|
|
|
|
|
|
|
|
|
|
|
|
|
As filed with the Securities and Exchange Commission on February 2, 2000
File No. 70-9539
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
AMENDMENT NO. 2
TO
FORM U-1 APPLICATION-DECLARATION
UNDER
THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
|
New Century Energies, Inc. |
Northern States Power Company |
(Name of companies filing this statement and address of principal executive offices)
__________________________________________________________________
New Century Energies, Inc.
1225 Seventeenth Street
Denver, Colorado 80202
(Name of registered holding company parent of each applicant
or declarant)
|
Wayne H. Brunetti |
James J. Howard |
(Name and addresses of agents for service)
The Commission is requested to send copies of all notices, orders and communications in connection with this Application-Declaration to:
|
Paul J. Bonavia |
Gary R. Johnson |
|
Joanne C. Rutkowski |
Peter D. Clarke |
|
1 |
||
|
A. |
1 |
|
|
B. |
3 |
|
|
C. |
4 |
|
|
1. |
4 |
|
|
2. |
8 |
|
|
D. |
12 |
|
|
E. |
13 |
|
|
Item 2. |
14 |
|
|
Item 3. |
15 |
|
|
A. |
16 |
|
|
1. |
16 |
|
|
2. |
17 |
|
|
B. |
18 |
|
|
1. |
18 |
|
|
2. |
22 |
|
|
3. |
24 |
|
|
C. |
27 |
|
|
1. |
28 |
|
|
(a) |
28 |
|
|
(b) |
The
Merger will not
be detrimental to carrying out |
28 |
|
(i) |
30 |
|
|
(a) |
53 |
|
|
(b) |
56 |
|
|
(c) |
61 |
|
|
(d) |
64 |
|
|
(ii) |
68 |
|
|
(iii) |
73 |
|
|
(a) |
74 |
|
|
(b) |
77 |
|
|
(c) |
77 |
|
|
(iv) |
78 |
|
|
2. |
81 |
|
|
D. |
85 |
|
|
E. |
85 |
|
|
1. |
New Century Services, Inc.
(to be renamed Xcel |
85 |
|
2. |
Services, Goods, and Assets
Involving the Utility |
88 |
|
3. |
Non-Utility Sale of Goods
and Services to EWGs, |
90 |
|
4. |
91 |
|
|
5. |
91 |
|
|
F. |
91 |
|
|
Item 4. |
91 |
|
|
A. |
92 |
|
|
B. |
92 |
|
|
C. |
93 |
|
|
D. |
93 |
|
|
E. |
94 |
|
|
Item 5. |
94 |
|
|
Item 6. |
95 |
|
|
A. |
95 |
|
|
B. |
99 |
|
|
Item 7. |
100 |
New Century Energies, Inc. and Northern States Power Company hereby amend and restate in its entirety their Application-Declaration in File No. 70-9539 and file additional exhibits thereto.
Item 1. Description of Proposed TransactionThis Application-Declaration seeks approvals relating to the proposed combination (the "Merger") of New Century Energies, Inc., a Delaware corporation ("NCE"), and Northern States Power Company, a Minnesota corporation ("NSP"). Upon receipt of all necessary approvals, NCE will be merged with and into NSP, which will be renamed Xcel Energy Inc. ("Xcel"). Also as part of the Merger, NSP intends to transfer all of its existing electric and natural gas utility facilities and operations currently conducted directly by NSP at the parent company level to a newly formed, wholly-owned subsidiary (referred to herein as "New NSP"). Following the consummation of the Merger, Xcel will register with the Securities and Exchange Commission (the "Commission") as a holding company under the Public Utility Holding Company Act of 1935, as amended (the "1935 Act" or the "Act").[1]
The combination of NSP and NCE, two well-run, mid-sized, mid-continent energy companies, will result in a financially strong and competitive regional energy company. A key motivating factor for the proposed transaction is the shared vision by the senior managements of both NSP and NCE (the "Applicants") concerning the changes that are occurring in the utility industry and the actions needed to respond effectively to those changes. The Merger will produce substantial benefits to the public, consumers and investors and will meet all applicable standards of the Act. Among other things, the Applicants believe that the Merger offers significant strategic and financial benefits to each company and to their respective shareholders, as well as to their employees, customers and the communities in which they do business. These benefits include, among others:
In summary, Applicants believe the Merger will significantly improve their competitive positions and create an enhanced platform for growth for all segments of their businesses. Applicants estimate that efficiencies created by the Merger will generate cost savings of approximately $1.1 billion (net of costs to achieve) in the first ten years following the Merger. The expected Merger benefits are discussed in further detail in Item 3.C.2. below.
The shareholders of NCE and NSP approved the Merger on June 28, 1999, with more than 83% of the votes cast by the shareholders of each corporation voting in favor of the Merger. Various aspects of the Merger and the transactions relating thereto have been or will be submitted for review and/or approval by: (i) the Arizona Corporation Commission (the "Arizona Commission"), (ii) the Kansas Corporation Commission (the "Kansas Commission"), (iii) the Minnesota Public Utilities Commission (the "Minnesota Commission"), (iv) the New Mexico Public Regulation Commission (the "New Mexico Commission"), (v) the North Dakota Public Service Commission (the "North Dakota Commission"), (vi) the Public Utilities Commission of the State of Colorado (the "Colorado Commission"), (vii) the Public Utility Commission of Texas (the "Texas Commission"), (viii) the Wyoming Public Service Commission (the "Wyoming Commission"), (ix) the Federal Energy Regulatory Commission (the "FERC") and (x) the Nuclear Regulatory Commission (the "NRC"). Further, the Merger cannot proceed until the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act"), has expired or been terminated by the regulators. Approval will also be necessary from the Federal Communications Commission (the "FCC") in connection with various licenses. In addition, NSP possesses various franchises, permits and licenses granted by local and state authorities that NSP may need to assign, renew or replace as a result of the Merger. British regulatory approval may also be required in light of NCE's ownership interest in Yorkshire Electricity and NSP's indirect investments in the United Kingdom. The status of these approvals, including the recent unconditional approval of the Merger by FERC, [2] is explained in detail in Item 4 below. Apart from the approval of the Commission under the Act, the foregoing approvals are the only governmental approvals required for the Merger. In order to permit timely consummation of the Merger and the realization of the substantial benefits it is expected to produce, the Applicants request that the Commission's review of this Application-Declaration commence and proceed as expeditiously as practicable.
NCE and NSP have entered into an Agreement and Plan of Merger, dated as of March 24, 1999 (the "Merger Agreement"), which provides for a strategic business combination involving NCE and NSP in a "merger-of-equals" transaction. Pursuant to the Merger Agreement, NCE will merge with and into NSP. NSP, as the surviving corporation, will change its name to Xcel. Also, as part of the Merger, NSP is expected to transfer its existing utility operations that are being conducted directly by NSP at the parent company level to New NSP, which will be a wholly-owned subsidiary of Xcel.[3] Upon completion of the Merger, Xcel will have the following public-utility subsidiary companies: Southwestern Public Service Company, a New Mexico corporation ("SPS")[4] ; Public Service Company of Colorado, a Colorado corporation ("PSCo"); Cheyenne Light, Fuel and Power Company, a Wyoming corporation ("Cheyenne"); New NSP, a Minnesota corporation; and Northern States Power Company, a Wisconsin corporation ("NSP-W"). Black Mountain Gas Company ("BMG"), which currently operates in Arizona as a division of NSP, is also to become a public-utility subsidiary of Xcel.[5] New Century Services, Inc., the existing service company for the NCE system, will be the service company for the Xcel system under Section 13 of the Act, although it is expected to be renamed Xcel Energy Services Inc. In addition, Xcel will continue to own all of NSP's existing non-utility subsidiaries and will acquire all of the outstanding capital stock of the non-utility subsidiaries of NCE. See Exhibit E-12 for the resulting corporate structure of Xcel. [6]
A copy of the Merger Agreement is incorporated by reference as Exhibit B-1.
NCE is a registered public utility holding company formed in 1997 pursuant to Commission order. New Century Energies, Inc., Holding Co. Act Release No. 26748 (Aug. 1, 1997) (herein, the "1997 NCE Order"). NCE has three public-utility subsidiaries, PSCo, SPS and Cheyenne, which are referred to herein collectively as the "NCE Operating Companies." PSCo serves approximately 1.2 million electric customers and approximately 1.0 million gas customers in the state of Colorado. SPS serves approximately 385,000 electric customers in portions of the states of Texas, New Mexico, Oklahoma and Kansas. Cheyenne serves approximately 35,000 electric customers and 28,000 gas customers in and around Cheyenne, Wyoming. Maps of the electric and gas service areas of the NCE Operating Companies are filed as Exhibits E-4.1 and E-4.2.
PSCo's transmission facilities are located in Colorado. PSCo is a member of the Western Systems Coordinating Council ("WSCC"), an interstate network of transmission facilities that are owned by public entities and investor-owned utilities. WSCC is the regional reliability coordinating organization for member electric power systems in the entire western electric grid (the "Western Interconnect") of the United States. PSCo is also a member of the Western Systems Power Pool ("WSPP"), an economic power pool that operates an electronic bulletin board and acts as a clearinghouse for bulk power transactions among over 90 member utilities and marketers. The WSPP arrangement provides for short-term energy and capacity exchanges at market-based prices for most members and electronic bulletin board posting of available power and energy.
PSCo's transmission system is directly interconnected with Western Area Power Administration ("WAPA") in the WSCC. PSCo is also directly interconnected with Basin Electric Power Cooperative, PacifiCorp, Platte River Power Authority and Tri-State Generation and Transmission Cooperative. Nearby PSCo are the two high voltage direct current ("HVDC") interconnections between the WSCC and the eastern electrical grid (the "Eastern Interconnect"): 100 MW at Stegal (owned by Tri-State) and 200 MW at Sidney (owned by WAPA). For 1999, PSCo's peak load was 4,951 MW at a time when its net capability was 5,259 MW, including 1,856 MW of long-term purchase contracts. PSCo's 2000 projected peak load is 5,114 MW, and its net capability, including 2,019 MW of long-term purchase contracts, is 5,704 MW.
Cheyenne's transmission facilities are located in Wyoming. These facilities are very limited, consisting of two 115 kV transmission line segments that total 25.5 miles in length. The primary purpose of these transmission lines is to interconnect Cheyenne's distribution system with the WAPA transmission system to enable Cheyenne to purchase its power requirements from other parties to serve its retail load. At present, PacifiCorp is Cheyenne's full requirements supplier. Unlike PSCo and SPC, Cheyenne does not have any wholesale load. Like PSCo, Cheyenne is a member of the WSCC.
SPS's transmission system is located in parts of Texas, New Mexico, Oklahoma and Kansas. SPS is a member of the Southwest Power Pool ("SPP"), the regional reliability council for member electric power systems in an area that encompasses portions of the South, the Southwest, and the Great Plains. SPS is also a member of WSPP.
SPS's transmission system is interconnected with two SPP-member utilities, Public Service Company of Oklahoma (an operating company within the Central and South West system) and West Plains Energy-Kansas (a division of UtiliCorp United Inc.), which enables it to purchase or sell energy from power producers in the Eastern Interconnect. It is also interconnected with the WSCC via a 200 MW HVDC tie near Clovis, New Mexico (Public Service Company of New Mexico) and a 200 MW HVDC tie at Artesia, New Mexico (El Paso Electric Company and Texas-New Mexico Power Company), which allows SPS to purchase and sell energy from power producers in the Western Interconnect. For 1999, SPS's peak load was 3,946 MW at a time when its net capability was 4,647 MW, including 396 MW of long-term purchase contracts. SPS's 2000 projected peak load is 4,332 MW, and its net capability, including 670 MW of long-term purchase contracts, is 5,024 MW.
In connection with their 1997 merger, PSCo and SPS stated their intent to construct a new tie line to interconnect their combined electric systems within five years after the consummation of that merger. Following a joint planning process that involved input from over fifty participants, the final project was selected in August 1998. In early January 1999, after further evaluation, PSCo and SPS announced plans for the phased approach for the implementation of this project and the construction of additional transmission facilities to alleviate transmission constraints, increase reliability and provide energy supply alternatives in SPS's present service territory in anticipation of competition. This expansion is expected to be completed in a phased approach and will require various regulatory approvals. The first phase will involve construction of a 230-mile, 345 kV line from Amarillo, Texas to Holcomb, Kansas (the "Amarillo-Holcomb line") and is expected to be completed in the third quarter of 2001.[7] The second phase will consist of construction of a 100-mile, 345 kV line from Holcomb, Kansas to Lamar, Colorado and a HVDC facility that would interconnect the PSCo and SPS systems, as well as the WSCC and SPP regional transmission grids. This second phase is now scheduled for completion in 2004 and will establish the fifth HVDC interconnection between the Western Interconnect and Eastern Interconnect. [8] While not directly related to the interconnection of the PSCo and SPS systems, the third phase of this project will involve construction of an approximately 275-mile, 345 kV line from Amarillo, Texas to Oklahoma City, Oklahoma. The completion of this line is not expected before 2004. Further information on the utility assets and operations of the NCE Operating Companies is included in Annex A.
PSCo is subject to regulation as a public utility under the Colorado Public Utilities Law as to retail electric and gas rates and other matters by the Colorado Commission. As a public utility under the laws of the states of Texas, New Mexico, Kansas and Oklahoma, SPS is regulated as to retail electric and certain other matters by the Texas Commission, New Mexico Commission, Kansas Commission and Oklahoma Commission, respectively. Cheyenne is subject to regulation in connection with its electric and gas retail sales and other matters by the Wyoming Commission. The NCE Operating Companies are also subject to regulation by FERC pursuant to the Federal Power Act, as amended, with respect to the classification of accounts, rates for any wholesale sales of electricity,[9] the interstate transmission of electric power and energy, interconnection agreements, the licensing of certain hydro-electric facilities, acquisitions and sales of certain utility properties, and various other matters. In addition, PSCo and Cheyenne are subject to regulation by FERC under the Natural Gas Act of 1935, as amended ("NGA") with regard to certain transportation or sale of natural gas for resale.
NCE, directly or indirectly, owns all the outstanding common stock of the following non-utility subsidiary companies: New Century Services, the NCE system service company under Section 13 of the Act; WestGas InterState, Inc. ("WGI"), a natural gas company subject to FERC jurisdiction under the NGA; and NC Enterprises, Inc. ("NC Enterprises"), a holding company for NCE's foreign operations and most of its non-utility businesses. PSCo also holds various non-utility subsidiaries. These subsidiaries primarily operate in support of PSCo's operations. The non-utility operations of the NCE System have all been previously authorized under the 1935 Act or have been established by rule or pursuant to statutory exemption. A further description of the non-utility subsidiaries of NCE is set forth in Annex C.
New Century Services has entered into a separate service agreement with NCE and each of the NCE Operating Companies (the "Utility Service Agreement"). A copy of the form of the Utility Service Agreement as well as an appendix entitled "Description of Services and Determination of Charges for Services" is filed as Exhibit B-2. PSCo's service agreement has a section and attachment to reflect state merger commitments made at the time it sought Colorado Commission approval to merge with SPS. New NSP and NSP-W will also enter into the Service Agreement with New Century Services. New Century Services has also entered into separate service agreements (the "Non-Utility Service Agreements") with the non-utility subsidiary companies of NCE. It is contemplated that New Century Services will similarly enter into one or more separate service agreements with the direct and indirect non-utility subsidiaries of NSP. A copy of the form of Non-Utility Service Agreement as well as an appendix entitled "Description of Services and Determination of Charges for Services" is filed as Exhibit B-3. [10]
The NCE Common Stock is listed on the New York Stock Exchange, Inc. ("NYSE"). The authorized capital stock of NCE consists of 260,000,000 shares of NCE Common Stock and 20,000,000 shares of NCE preferred stock. As of the close of business on September 30, 1999, 115,533,704 shares of NCE Common Stock and no shares of NCE preferred stock were issued and outstanding.
Pertinent financial information regarding NCE's utility operations for the year ended December 31, 1998 may be summarized as follows ($ in millions):
|
Electric Utility Revenues |
Gas Utility Revenues |
|
|
SPS |
$951 |
-- |
|
PSCo |
1,636 |
$640 |
|
Cheyenne |
37 |
18 |
The consolidated assets of NCE, as of December 31, 1998, were approximately $7.7 billion, representing $4.6 billion in net electric utility property, plant and equipment ($1.7 billion for SPS, $2.8 billion for PSCo and $46 million for Cheyenne); $817 million in net gas utility property, plant and equipment ($792 million for PSCo and $24 million for Cheyenne); $500 million in non-utility subsidiary property, plant and equipment; and $1.8 billion in other corporate assets.
Pertinent financial information regarding NCE's utility operations for the twelve months ended September 30, 1999, may be summarized as follows ($ in millions):
|
Electric Utility Revenues |
Gas Utility Revenues |
|
|
SPS |
$717 |
-- |
|
PSCo |
$1,156 |
$477 |
|
Cheyenne |
$40 |
$19 |
The consolidated assets of NCE, as of September 30, 1999, were approximately $8.1 billion, representing $5.1 billion in net electric utility property, plant and equipment ($1.7 billion for SPS, $3.0 billion for PSCo and $42 million for Cheyenne); $808 million in net gas utility property, plant and equipment ($779 million for PSCo and $29 million for Cheyenne); $443 million in non-utility subsidiary property, plant and equipment; and $1.7 billion in other corporate assets.
NCE and the NCE Operating Companies are all financially strong companies. The Moody long-term debt ratings of SPS and PSCo are A3 and Aa2, respectively. More detailed information concerning NCE and its subsidiaries is contained in (i) NCE's Annual Report on Form 10-K for the year ended December 31, 1998, and its Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999, June 30, 1999, and September 30, 1999, which are incorporated by reference as Exhibits H-2, H-11, H-12 and H-20, respectively; (ii) PSCo's Annual Report on Form 10-K for the year ended December 31, 1998, and its Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999, June 30, 1999, and September 30, 1999, which are incorporated by reference as Exhibits H-5, H-17, H-18 and H-23, respectively; and (iii) SPS's Annual Report on Form 10-K for the year ended December 31, 1998 and its Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999, June 30, 1999, and September 30, 1999, which are incorporated by reference as Exhibits H-6, H-7, H-8 and H-24, respectively.
NSP, which was incorporated in 1909, is a public-utility company and a holding company exempt from registration pursuant to Commission order under Section 3(a)(2) of the Act. Northern States Power Company, Holding Co. Act Release No. 22334 (Dec. 23, 1981). NSP owns all of the outstanding common stock of NSP-W, a Wisconsin corporation, which is a public-utility company under the Act. Maps of the electric and gas service areas of NSP and NSP-W are filed as Exhibits E-3.1 and E-3.2.
NSP is engaged primarily in the generation, transmission and distribution of electricity throughout a 30,000 square mile service area in Minnesota, North Dakota and South Dakota. NSP also purchases, distributes and sells natural gas to retail customers and transports customer-owned gas in approximately 118 communities in Minnesota, North Dakota, South Dakota and Arizona. Of the more than 2.5 million people served by NSP, the majority are in the Minneapolis-St. Paul metropolitan area. In 1998, more than 73% of the electric retail revenue of NSP was derived from sales in the Minneapolis-St. Paul metropolitan area, and more than 64% of its retail gas revenue was derived from sales in the St. Paul metropolitan area. NSP provides both electric and gas utility service in Minnesota, North Dakota and South Dakota but only gas utility service in Arizona. NSP provides retail electric utility service to approximately 1,240,000 customers and gas utility service to approximately 385,000 customers.
NSP-W is engaged in the generation, transmission, and distribution of electricity to approximately 210,400 retail customers in an area of approximately 18,900 square miles in northwestern Wisconsin, to approximately 9,100 electric retail customers in an area of approximately 300 square miles in the western portion of the Upper Peninsula of Michigan and to 10 wholesale customers in the same general area. NSP-W purchases, distributes and sells natural gas to retail customers or transports customer-owned natural gas in the same service territory to approximately 78,000 customers in Wisconsin and 5,000 customers in Michigan. For the twelve months ended September 30, 1999, NSP-W provided approximately 14% of NSP's consolidated revenues.
The electric transmission system of NSP and NSP-W (the "NSP System") is located throughout the service territories that NSP and NSP-W serve in Minnesota, North Dakota, South Dakota, Michigan and Wisconsin. NSP and NSP-W are directly connected with each other through numerous transmission lines that they own, including one 345 kV transmission line, two 115 kV transmission lines and two 69 kV transmission lines.
NSP and NSP-W are members of the Mid-Continent Area Power Pool ("MAPP"), the regional reliability council for numerous electric providers in portions of the Midwest. The NSP System is interconnected with 19 other utility systems, including utilities in MAPP (Basin Electric Power Cooperative, Great River Energy, Otter Tail Power Co., WAPA, Southern Minnesota Municipal Power Agency, Interstate Energy Co., IES Utilities, MidAmerican Energy Co., Minnesota Power Co., Dairyland Power Cooperative and Manitoba Hydro-Electric Board at the United States/Canada border) and utilities in Mid-America Interconnected Network ("MAIN") (Ameren, Wisconsin Public Service Corporation, Wisconsin Electric Power Company and Wisconsin Power and Light). NSP also participates in two 345 kV lines that give it limited purpose contractual interconnections with six additional utilities. The "East 345 Line" runs between Minneapolis-St. Paul and St. Louis and includes as participants operating companies of Alliant Energy, Inc. (IES Utilities Inc. and Interstate Energy Company), Ameren (Union Electric) as well as MidAmerican Energy Company and NSP. The "West 345 Line" runs between Minneapolis-St. Paul and Kansas City and includes as participants Kansas City Power and Light, Interstate Energy Company, MidAmerican Energy Company, Omaha Public Power District and St. Joseph Light and Power.
The combined net generating capability (considering purchases and sales) of NSP and NSP-W is projected to be 8,411 MW in 2000, against a net demand of 7,171 MW.[11] Given MAPP's minimum reliability reserve margin requirement of 15 percent, NSP has 164 MW of uncommitted capacity in 2000. In 1998 and in 1999, NSP was a net purchaser of power, and it anticipates being a significant purchaser in future years. In the past, NSP relied increasingly on the short-term energy market to meet increased customer demand for energy. On June 28, 1999, NSP filed a request for proposals ("RFP") with the Minnesota Commission. In this request, NSP identified a need for a long-term capacity and energy to meet the increased requirements of customers beginning in 2003. The RFP identifies the need to have from 200 to 1200 additional MW of generation resources in service for 2003 or earlier. The range is intended to provide an opportunity to look at a wide variety of potential future conditions. The RFP permits both acceleration or delay of the in-service date. Further information on the utility assets and operations of NSP and NSP-W is included in Annex B.
Retail sales rates, services and other aspects of NSP's retail operations are subject to the jurisdiction of the Minnesota Commission, the North Dakota Commission, the South Dakota Commission and the Arizona Commission within their respective states. The Minnesota Commission also possesses regulatory authority over aspects of NSP's financial activities, including security issuances, property transfers when the asset value is in excess of $100,000, mergers with other utilities, and transactions between NSP and affiliates. In addition, the Minnesota Commission reviews and approves NSP's electric resource and gas supply capacity plans for meeting customers' future energy needs. NSP-W is subject to regulation of similar scope by the Wisconsin Commission and the Michigan Commission, except that the Michigan Commission does not regulate NSP-W's issuances of securities. In addition, a state commission generally must certify the need for new generating plants and transmission lines of designated capacities to be located within such state before they may be sited and built. Wholesale rates for electric energy sold in interstate commerce, the classification of accounts, the interstate transmission of electric power and energy, interconnection agreements, issuances of securities not regulated by state commissions, acquisitions and sales of certain utility properties and certain other activities of NSP and NSP-W (including the licensing of certain hydro-electric facilities) are subject to the jurisdiction of FERC. The operation and construction of NSP's Prairie Island and Monticello nuclear facilities are subject to regulation by the NRC. In addition, NSP and NSP-W are subject to FERC jurisdiction under the NGA with regards to sale of natural gas for resale.
NSP is also engaged, directly and through subsidiary companies, in non-utility businesses. NSP directly provides: (i) an appliance services program for its residential customers; (ii) construction of natural gas distribution systems for third parties (primarily end-users and municipal gas systems); (iii) sale and installation of power quality instruments, primarily to protect equipment of customers from electric surges; (iv) sale of steam to industrial customers in NSP's service territory and (v) installation and maintenance of street lighting for municipalities and other customers. In addition, NSP owns directly the interests of the following non-utility subsidiary companies: Viking Gas Transmission Company ("Viking"), an interstate natural gas pipeline subject to FERC jurisdiction under the NGA; NRG Energy, Inc. ("NRG"), a holding company for many of NSP's non-utility businesses, including significant investments in independent power projects and foreign operations; Energy Masters International, Inc. ("EMI"), an energy services company; Seren Innovations, Inc. ("Seren"), a company that provides cable, telephone and high-speed internet access system; Ultra Power Technologies, Inc. ("Ultra Power"), a company that markets power cable testing technology; Eloigne Company ("Eloigne"), an investor in projects that qualify for low-income housing tax credits; NSP Financing I, a special purpose business trust; First Midwest Auto Park, Inc. ("FMAP"), an owner of a parking garage; United Power and Land Company ("UP&L"), a real estate investment company; Reddy Kilowatt Corporation ("Reddy Kilowatt"), the owner of certain intellectual property rights; Natrogas, Inc., a provider of propane services; and Nuclear Management Company ("NMC"), a limited liability company that will provide services to the nuclear operations of its members. NSP owns 100% of all of the foregoing businesses, except that NSP owns 25% of the membership interests in NMC. A further description of the non-utility subsidiaries of NSP is set forth on Annex D hereto.
NSP-W owns directly all of the outstanding common stock of Clearwater Investments, Inc. ("Clearwater"), an investor in housing projects that qualify for low-income housing tax credits, and NSP Lands, Inc. ("NSP Lands"), a real estate investment company. NSP-W also owns 75.86% of Chippewa and Flambeau Improvement Company ("C&F"), a company that builds and operates dams and reservoirs for hydro-electric plants. A further description of the non-utility subsidiaries of NSP-W is also set forth on Annex D hereto.
NSP Common Stock is listed on the NYSE and the Chicago and Pacific Stock Exchanges. As of the close of business on September 30, 1999, there were 154,358,267 shares of NSP Common Stock and 1,050,000 shares of NSP cumulative preferred stock issued and outstanding. NSP-W does not have any preferred stock outstanding, and all of its common stock is owned by NSP. Copies of the Articles of Incorporation of NSP and NSP-W are incorporated by reference as Exhibit A-1 and Exhibit A-2.
Pertinent financial information regarding NSP's utility revenues for the year ended December 31, 1998, may be summarized as follows (before intercompany eliminations): [12]
($ in millions)
|
Electric |
Gas |
|
|
NSP |
$2,244 |
$366 |
|
NSP-W |
$ 325 |
$ 79 |
Consolidated assets of NSP and its subsidiaries as of December 31, 1998 were approximately $7.4 billion, consisting of $3.7 billion in net electric utility property, plant and equipment ($3.1 billion for NSP and $594 million for NSP-W); $439 million in net gas utility property, plant and equipment ($376 million for NSP and $63 million for NSP-W); $1.6 billion in non-utility subsidiary assets; and $1.7 billion in other corporate assets.
Pertinent financial information regarding NSP's utility revenues for the twelve months ended September 30, 1999, may be summarized as follows (before intercompany eliminations): [13]
($ in millions)
|
Electric |
Gas |
|
|
NSP |
$2,343 |
$360 |
|
NSP-W |
$ 335 |
$ 81 |
Consolidated assets of NSP and its subsidiaries as of September 30, 1999 were approximately $8.7 billion, consisting of $3.5 billion in net electric utility property, plant and equipment ($2.9 billion for NSP and $622 million for NSP-W); $459 million in net gas utility property, plant and equipment ($395 million for NSP and $64 million for NSP-W); $2.9 billion in non-utility subsidiary assets; and $1.7 billion in other corporate assets.
Like NCE, NSP is a financially strong company. The Moody long-term credit ratings of NSP and NSP-W are both Aa3. More detailed information concerning NSP and its subsidiaries is contained in (i) NSP's Annual Report on Form 10-K for the year ended December 31, 1998, and its Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999, June 30, 1999, and September 30, 1999, which are incorporated by reference as Exhibits H-1, H-9, H-10 and H-19, respectively; (ii) NSP-W's Annual Report on Form 10-K for the year ended December 31, 1998, and its Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999, June 30, 1999, and September 30, 1999, which are incorporated by reference as Exhibits H-3, H-13, H-14 and H-21, respectively; and (iii) NRG's Annual Report on Form 10-K for the year ended December 31, 1998, and its Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999, June 30, 1999, and September 30, 1999, which are incorporated by reference as Exhibits H-4 , H-15, H-16 and H-22, respectively.
The Merger Agreement provides for the merger of NCE with and into NSP pursuant to which: (a) each share of NCE Common Stock issued and outstanding immediately prior to the effective time of the Merger, together with any NCE Rights,[14] shall be converted into the right to receive 1.55 shares (the "Conversion Ratio") of duly authorized, validly issued, fully paid and nonassessable NSP Common Stock; (b) each issued and outstanding share of NSP Common Stock and each share of preferred stock of NSP issued and outstanding immediately prior to the effective time of the Merger shall remain outstanding; and (c) each share of NCE Common Stock, together with any NCE Rights, that is owned by NSP or any of its subsidiaries or held in the treasury of NCE will be canceled and shall cease to exist, and no consideration shall be delivered in exchange therefor. As noted previously, NSP will change its name to Xcel at or prior to the Merger. Based upon the capitalization of NCE and NSP on March 24, 1999 (the date the Merger Agreement was signed) and the Conversion Ratio, NCE shareholders would own 54 percent and NSP shareholders would own 46 percent of the common equity of Xcel if the Merger had been consummated as of such date.
Except as set forth below, if any holder of NCE Common Stock would be entitled to receive a number of shares of NSP Common Stock that includes a fraction, then in lieu of a fractional share, such holder will be entitled to receive a cash payment determined by multiplying the fractional share interest by the average of the last reported sales price, regular way, per share of NSP Common Stock on the NYSE Composite Tape for the ten business days prior to and including the last business day on which NSP Common Stock was traded on the NYSE, without any interest thereon. Fractional shares of NCE Common Stock held in accounts under the dividend reinvestment plans and employee benefit plans of NCE will be converted into the applicable number of shares (or fractional shares) of NSP Common Stock under corresponding plans of NSP, in accordance with the Conversion Ratio.
The Merger is subject to customary closing conditions, including the receipt of the requisite shareholder approvals of NCE and NSP and all necessary governmental approvals, including the approval of the Commission.
The Merger is designed to qualify as a tax-free reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended. NSP and NCE believe the Merger will be treated as a "pooling of interests" for accounting purposes.
The Merger Agreement contains certain covenants relating to the conduct of business by the parties pending the consummation of the Merger. Generally, the parties must carry on their businesses in the ordinary course consistent with past practice, may not increase common stock dividends beyond specified levels and may not issue capital stock except as specified. The Merger Agreement also contains restrictions on, among other things, charter and bylaw amendments, capital expenditures, acquisitions, dispositions, incurrence of indebtedness, certain increases in employee compensation and benefits, and affiliate Mergers.
The Merger Agreement provides that, after the effectiveness of the Merger, Xcel's principal corporate office will be located in Minneapolis, Minnesota. Xcel will also maintain significant operating offices in Denver, Colorado; Amarillo, Texas; and Eau Claire, Wisconsin. Xcel's board of directors (classified into three classes) will consist of an even number of up to 14 persons, half of whom will be designated by NSP and half of whom will be designated by NCE. Mr. James J. Howard, the current Chairman, Chief Executive Officer and President of NSP, will be entitled to serve as Chairman of the Board of Xcel until the first anniversary of the effectiveness of the Merger of NCE and NSP. Mr. Wayne H. Brunetti, the Chairman, Chief Executive Officer and President of NCE, will be entitled to serve as President and Chief Executive Officer of Xcel upon the effectiveness of the Merger, and thereafter will assume the position of Chairman when Mr. Howard ceases to be Chairman. The balance of the Xcel executive management is expected to consist of current executives of NCE and NSP as follows: Paul Bonavia (currently NCE General Counsel and President - International Business), Head of Energy Markets; Dick Kelly (currently NCE Executive Vice President and Chief Financial Officer), Head of Corporate Development and Strategy/Unregulated Subsidiaries; Gary Johnson (currently NSP Senior Vice President and General Counsel), General Counsel; Cyndi Lesher (currently NSP President - Gas Utility Operations), Chief Administrative Officer; James McIntyre (currently NSP Senior Vice President and Chief Financial Officer), Chief Financial Officer; Toni Petillo (currently NCE President - Retail Services), Head of Retail Operations; Larry Taylor (currently NSP President - Delivery Services), Head of Energy Delivery; and David Wilks (currently SPS President and Head of the Delivery Business Unit), Head of Energy Supply.
As explained more fully in Item 3.C.1(b), the gas operations of Xcel will constitute a single, integrated gas-utility system, and the electric operations (with the exception of Cheyenne, which the Commission has already found to be a permissible additional system) will similarly form a single, integrated electric-utility system. There will be significant savings and synergies as a result of these integrated operations. As noted previously and as described in Item 3.C.2 below, the benefits are estimated to exceed $1.1 billion over the next ten years.
Item 2. Fees, Commissions and Expenses
The fees, commissions and expenses to be paid or incurred, directly or indirectly, in connection with the Merger, including the solicitation of proxies, registration of securities of Xcel under the Securities Act of 1933, and other related matters, are estimated as follows:
| Commission filing fee for the Joint Registration Statement on Form S-4 | $1,145,707.50 |
| Accountants' fees | [15] |
| Legal fees and expenses relating to the Act | [15] |
| Other legal fees and expenses | [15] |
| Shareholder communication and proxy solicitation | [15] |
| NYSE listing fee | [15] |
| Exchanging, printing, and engraving of stock certificates | [15] |
| Investment bankers' fees and expenses | [15] |
| SG Barr Devlin | [15] |
| The Blackstone Group | [15] |
| Consulting fees related to the Merger | [15] |
| Expenses
related to integrating the operations of the merged company and miscellaneous |
[15] |
| TOTAL | [15] |
Item 3. Applicable Statutory Provisions
The following sections of the Act and the Commission's rules thereunder are or may be directly or indirectly applicable to the proposed Merger:
|
|
Transactions to which section or rule may be applicable: |
|
4, 5 |
Registration of Xcel as a holding company following consummation of the Merger. |
|
6(a), 7 |
Issuance of Xcel Common Stock in the Transaction in exchange for shares of NCE Common Stock; formation and capitalization of New NSP. |
|
9(a)(1), 10 |
Acquisition by Xcel of stock of New Century Services and of non-utility subsidiaries of NCE. |
|
9(a)(2), 10(a), (b), (c) and (f) |
Acquisition by Xcel of common stock of NCE and NCE Operating Companies; acquisition by Xcel of common stock of New NSP. |
|
8, 9(c)(3), 11(b), 21 |
Retention by Xcel of the retail gas utility operations of NSP, NSP-W, PSCo and Cheyenne; retention of other businesses of NSP and NCE and their direct and indirect subsidiaries. |
|
12(d) |
Sale by NCE of securities of NCE Operating Companies. |
|
13 |
Approval of the services to be provided by New Century Services to New NSP, NSP-W, BMG and Xcel in accordance with the Utility Service Agreement; approval of services to be provided thereunder by New Century Services to the direct and indirect non-utility subsidiaries of NSP in accordance with the Non-Utility Service Agreement; approval of the performance of certain services between Xcel system companies; and exemption from at-cost standards with respect to certain services between Xcel system companies. |
|
44 |
Sale by NCE of securities of NCE Operating Companies. |
|
Rules |
|
|
80-92 |
Affiliate transactions, generally. |
|
88 |
Expansion of the activities of New Century Services to the Xcel System. |
To the extent that other sections of the Act or the Commission's rules thereunder are deemed to be applicable to the Merger, such sections and rules should be considered to be set forth in this Item 3.
1. Introduction
The Commission must find that Section 10 of the Act is satisfied to approve the Merger. The Section 10 analysis is presented in detail below. The highlight of the analysis is whether the Merger will tend toward the economical and the efficient development of an integrated public utility system. Applicants believe that it will.
The future of the electric utility industry will be much different from its past. The utility market model, with generation functionally unbundled from transmission and distribution, is supplanting the vertically integrated monopoly model. Applicants recognize these changes and believe that the Merger forms an integrated public utility system positioned for competition in the utility industry of the future. Under FERC's recent Order No. 2000, described below, regional transmission organizations ("RTOs") will further the development of the market model because RTOs facilitate transmission access on a regional basis at non-pancaked rates, thereby promoting the growth of larger and more competitive regional wholesale power markets. More buyers and sellers participate in broader bulk power markets, and this increased competition will tend to produce lower prices for the benefit of consumers. The NSP companies and SPS are presently located to the north and south, respectively, of the Midwest Independent System Operator, Inc. ("MISO"), a FERC-approved independent system operator. As part of the Merger, they will join MISO, increasing its size and multiplying the consumer benefits that follow from regional integration of transmission systems and the corresponding increase in competition within bulk power markets. Moreover, PSCo and SPS continue to work toward the completion of a physical interconnection to link their systems, and PSCo, consistent with FERC policy, is working with its neighbors to establish an ISO in the Rocky Mountain/High Plains region, which would neighbor MISO.
The 1935 Act was intended, among other things, to prevent the evils that arise "when the growth and extension of holding companies bears no relation to the economy of management and operation or the integration and coordination of related operating properties . . ." [16] In contrast, the Xcel system is an example of growth that promotes economies and coordination of related operating properties within a single region in a manner consistent not only under the policies of the Act, but also with the policies of both FERC and with state regulatory initiatives. As discussed in detail below, the RTO integration model represents a reasoned evolution of the integration requirements under the 1935 Act, particularly when viewed as an extension of the past precedent of integration through a power pool. For these reasons, it is a model that should be encouraged by this Commission.
Section by Section Analysis
Section 9(a)(2) makes it unlawful, without approval of the Commission under Section 10, "for any person...to acquire, directly or indirectly, any security of any public-utility company, if such person is an affiliate...of such company and of any other public-utility or holding company, or will by virtue of such acquisition become such an affiliate." Under the definition set forth in Section 2(a)(11), an "affiliate" of a specified company means "any person that directly or indirectly owns, controls, or holds with power to vote, 5 per centum or more of the outstanding voting securities of such specified company," and "any company 5 per centum or more of whose outstanding voting securities are owned, controlled, or held with power to vote, directly or indirectly, by such specified company." As a result of the proposed Merger, Xcel will acquire all of the outstanding voting securities of the NCE Operating Companies. Also in connection with the Merger, Xcel will acquire all of the outstanding securities of New NSP. The Merger therefore requires prior Commission approval under the standards of Section 10.[17] In this regard, the relevant standards are set forth in Sections 10(b), 10(c) and 10(f) of the Act.
As set forth more fully below, the Merger complies with all of the applicable provisions of Section 10 of the Act and should be approved by the Commission. Thus:
the consideration to be paid in the Merger is fair and reasonable;
the Merger will not create detrimental interlocking relations or concentration of control;
the Merger will not result in an unduly complicated capital structure for the Xcel system;
the Merger is in the public interest and the interests of investors and consumers;
the Merger is consistent with Section 8 and not detrimental to carrying out the provisions of Section 11 of the Act;
the Merger tends toward the economical and efficient development of both integrated electric and gas systems; and
the Merger will comply with all applicable state laws.
Furthermore, the Merger also provides an opportunity for the Commission to follow certain of the interpretive recommendations made by the Division of Investment Management (the "Staff") in its report issued in June 1995 entitled "The Regulation of Public Utility Holding Companies" (the "1995 Report"), in particular the Staff's overall recommendation that the Commission act administratively to modernize and simplify holding company regulation and minimize regulatory overlap, while protecting the interests of consumers and investors.
Section 10(b) provides that, if the requirements of Section 10(f) are satisfied, the Commission shall approve an acquisition under Section 9(a) unless the Commission finds that:
(1) such acquisition will tend towards interlocking relations or the concentration of control of public-utility companies, of a kind or to an extent detrimental to the public interest or the interests of investors or consumers;
(2) in case of the acquisition of securities or utility assets, the consideration, including all fees, commissions, and other remuneration, to whomsoever paid, to be given, directly or indirectly, in connection with such acquisition is not reasonable or does not bear a fair relation to the sums invested in or the earning capacity of the utility assets to be acquired or the utility assets underlying the securities to be acquired; or
(3) such acquisition will unduly complicate the capital structure of the holding-company system of the applicant or will be detrimental to the public interest or the interests of investors or consumers or the proper functioning of such holding-company system.
The standards of Section 10(b)(1) are satisfied because the proposed Merger will not "tend towards interlocking relations or the concentration of control of public utility companies, of a kind or to an extent detrimental to the public interest or the interests of investors or consumers." By its nature, any merger results in new links between previously unrelated companies. The Commission has recognized that such interlocking relationships are permissible in the interest of efficiencies and economies. Northeast Utilities, Holding Co. Act Release No. 25221 (Dec. 21, 1990), as modified, Holding Co. Act Release No. 25273 (Mar. 15, 1991), aff'd sub nom. City of Holyoke v. SEC, 972 F.2d 358 (D.C. Cir. 1992) ("interlocking relationships are necessary to integrate [the two merging entities]"). The links that will be established as a result of the Merger are not the types of interlocking relationships targeted by Section 10(b)(1), which was primarily aimed at preventing business combinations unrelated to operating synergies. The Merger Agreement provides for the Board of Directors of Xcel to consist of up to 14 members, one-half designated by NSP and one-half designated by NCE. [18] In addition, a variety of contractual arrangements among the companies in the Xcel system will be established, including the following:
These arrangements, which work to integrate NSP and NCE into the Xcel system, will be in the public interest and the interest of investors and consumers. Forging such relationships is beneficial to the protected interests under the Act and, thus, is not prohibited by Section 10(b)(1). Moreover, because substantial benefits will accrue to the public, investors and consumers from the combination of NCE and NSP, whatever interlocking relationships may arise from the combination are not detrimental.
In applying Section 10(b)(1) to utility acquisitions, the Commission must further determine whether the acquisition will create "the type of structures and combinations at which the Act was specifically directed." Vermont Yankee Nuclear Power Corp., Holding Co. Act Release No. 15958 (Feb. 6, 1968). The NSP-NCE strategic alliance will not create a "huge, complex and irrational system" but, rather, will afford the opportunity to achieve economies of scale and efficiencies for the benefit of investors and consumers. See American Electric Power Company, Inc., Holding Co. Act Release No. 20633 (July 21, 1978) ("AEP"). As explained in the Joint Proxy Statement and Prospectus of NSP and NCE (the "Joint Proxy Statement") (a copy of which is included as Exhibit C-2), the primary objective of the Merger is to position the companies to participate in the growing and increasingly competitive energy markets. Specifically, the Merger will combine the strengths of the two companies, thus enabling them to offer customers a broader array of energy products and services more efficiently and cost-effectively than could either company acting alone, and at the same time create a larger and more diverse asset and customer base, with enhanced opportunities for operating efficiencies and risk diversification. Xcel will be a mid-size registered holding company, and its operations will not exceed the economies of scale of current electric generation and transmission technology or provide undue market power or control to Xcel in the region in which it will provide service.
While the combination of NCE and NSP will result in a larger utility system, it certainly will not be one that exceeds the economies of scale of current electric generation and transmission technology, on the one hand, and gas transportation technology on the other. If approved, the Xcel system will serve approximately 3.0 million electric customers and 1.5 million gas customers in twelve states. As of December 31, 1998, the combined consolidated assets of the Applicants totaled approximately $15.1 billion and, for the year ended December 31, 1998, combined operating revenues totaled approximately $6.4 billion. As of December 31, 1998, the combined owned summer generating capacity of the regulated utility operations of NSP, NSP-W, PSCo, SPS and Cheyenne totaled approximately 15,000 MW.
The following table shows the Xcel system's relative size as compared to other registered systems in terms of assets, operating revenues and customers[19]:
|
|
Total Assets |
Operating Revenues |
Electric Customers |
|
Southern |
$36,192 |
$11,403 |
3,794 |
|
AEP |
19,483 |
6,346 |
3,022 |
|
Entergy |
22,848 |
11,495 |
2,495 |
|
CSW |
13,744 |
5,482 |
1,752 |
|
GPU |
16,288 |
4,249 |
2,041 |
|
Xcel |
15,608 |
6,430 |
3,000 |
Moreover, the Commission has approved a number of acquisitions involving larger and similarly-sized operating utilities. See, e.g., Entergy Corporation Holding Co. Act Release No. 25952 (Dec. 17, 1993) (acquisition of Gulf States Utilities; combined assets at time of acquisition in excess of $22 billion); TUC Holding Company, Holding Co. Act Release No. 26749 (Aug. 1, 1997) (combination of Texas Utilities Company and ENSERCH Corporation; combined assets at time of acquisition of $24.0 billion); Houston Industries Incorporated, Holding Co. Act Release No. 26744 (July 24, 1997) (combination of Houston Industries Incorporated and NorAm Energy Corp., combined assets at time of acquisition of $16.0 billion); Northeast Utilities, supra (acquisition of Public Service Company of New Hampshire; combined assets at time of acquisition of approximately $9 billion); Centerior Energy Corp., Holding Co. Act Release No. 24073 (April 29, 1986) (combination of Cleveland Electric Illuminating and Toledo Edison; combined assets at time of acquisition of approximately $9.1 billion); AEP, supra (acquisition of Columbus and Southern Ohio Electric; combined assets at time of acquisition of close to $9 billion). Furthermore, at a time of consolidation in the industry, the combined assets of Xcel will be less than the combined assets of certain existing registered holding companies: AEP ($19.4 billion at December 31, 1998), Southern Company ($36.2 billion at December 31, 1998), Entergy Corporation ($22.8 billion at December 31, 1998) and GPU, Inc. ($16.3 billion at December 31, 1998).
The Commission has rejected a mechanical size analysis under Section 10(b)(1) in favor of assessing the size of the resulting system with reference to the economic efficiencies that can be achieved through the integration and coordination of utility operations. See, e.g., AEP, supra. The Commission in AEP noted that, although the framers of the Act were concerned about "the evils of bigness, they were also aware that the combination of isolated local utilities into an integrated system afforded opportunities for economies of scale, the elimination of duplicate facilities and activities, the sharing of production capacity and reserves and generally more efficient operations...[and] [t]hey wished to preserve these opportunities." Id . By virtue of the Merger, Xcel will be in a position to realize precisely these types of benefits. Among other things, the Merger is expected to yield labor cost savings, corporate and administrative and purchasing savings, cost of fuel and purchased gas savings. These expected economies and efficiencies from the combined utility operations are described in greater detail in Item 3.C.2., below.
Finally, Section 10(b)(1) also requires the Commission to consider possible anticompetitive effects of a proposed combination. As the Commission noted in Northeast Utilities, the "antitrust ramifications of an acquisition must be considered in light of the fact that public utilities are regulated monopolies and that federal and state administrative agencies regulate the rates charged to customers." In this case, NCE and NSP will soon file Notification and Report Forms with the Department of Justice and the Federal Trade Commission pursuant to the HSR Act describing the effects of the Merger on competition in the relevant market and it is a condition to the consummation of the Merger that the applicable waiting period under the HSR Act shall have expired or been terminated.
The competitive impact of the Merger was also extensively considered by FERC in unconditionally approving the Merger. In proceedings under Section 203 of the Federal Power Act involving utility mergers, FERC, under well-established policy, must evaluate the competitive effects of a proposed merger before deciding whether to approve the merger as "consistent with the public interest," the applicable standard of review. [20] Accordingly, as part of their merger application to FERC, Applicants submitted the testimony of Dr. Heironymus and Dr. Gilbert submitted in support of the FERC application (filed as Exhibits D-1.1 and D-1.2 hereto), Dr. Heironymus analyzed the horizontal effects of the Merger (i.e., those that result from combining the companies generating resources) and Dr. Gilbert analyzed the vertical effects (i.e., those that result from consolidating the companies' gas delivery and generation facilities). Based on those analyses, Applicants believe that there is no adverse impact on competition resulting from the consolidation of the pre-merger market shares of Applicants. While Applicants have acknowledged that their post-merger integration plans will affect their post-merger market shares, they explained to FERC that these occur as a result of joining an RTO and through exercise of rights under FERC Order No. 888 and that they do not reflect any overall anti-competitive effects of the Merger. [21]
The FERC Merger Order effectively validated Applicants' conclusion regarding the lack of competitive impacts. After considering various intervenor comments and protests, and performing its own extensive analysis of competitive effects, FERC concluded that the Merger was unlikely to have an adverse effect on competition (both horizontal and vertical analysis) and that there were no issues regarding the Merger that warranted a hearing. FERC thus summarily approved the Merger.
The analysis on which FERC based this conclusion relied heavily on the commitment of NSP and SPS to join MISO. "We find the Applicants' commitment to join the MISO alleviates any concern regarding the merger's impact on competition and is sufficient to support our approval of the merger. Our approval of the merger is based on Applicants' participation in the MISO."[22] FERC also concluded that it believed that the Merger did not raise vertical competitive issues. [23] The Commission has found, and the courts have agreed, that it may appropriately rely upon FERC with respect to such findings. See City of Holyoke v. SEC, supra at 363-64, quoting Wisconsin's Environmental Decade v. SEC, 882 F.2d 523, 527 (D.C. Cir. 1989). For these reasons, the Merger will not "tend toward interlocking relations or the concentration of control" of public utility companies, of a kind or to the extent detrimental to the public interest or the interests of investors or customers within the meaning of Section 10(b)(1).
Section 10(b)(2) precludes approval of an acquisition if the consideration to be paid in connection with the combination, including all fees, commissions and other remuneration, is "not reasonable or does not bear a fair relation to the sums invested in or the earning capacity of ... the utility assets underlying the securities to be acquired." The Commission has found "persuasive evidence" that the standards of Section 10(b)(2) are satisfied where, as here, the agreed consideration for an acquisition is the result of arm's-length negotiations between the managements of the companies involved, supported by opinions of financial advisors. See Southern Company, Holding Co. Act Release No. 24579 (Feb. 12, 1988).
First, the Merger is a pure stock-for-stock exchange that is to qualify for treatment as a pooling of interests. The Merger will therefore involve no "acquisition adjustment" or other write-up of the assets of NCE or NSP.
Second, as explained on pages 41 and 47 of the Joint Proxy Statement (EXHIBIT C-2 hereto), the historical price data, high and low, for NSP and NCE Common Stock provide support for the consideration of 1.55 shares of NSP Common Stock for each share of NCE Common Stock.
Third, the Conversion Ratio is the product of extensive and vigorous arm's-length negotiations between NCE and NSP. These negotiations were preceded by extensive due diligence, analysis and evaluation of the assets, liabilities and business prospects of each of the respective companies. This process is described in "Background of the Merger" at pages 30 to 35 of the Joint Proxy Statement. As recognized by the Commission in Ohio Power Co., Holding Co. Act Release No. 16753 (June 8, 1970), prices arrived at through arm's-length negotiations are particularly persuasive evidence that Section 10(b)(2) is satisfied.
Fourth, nationally-recognized investment bankers for NCE and NSP have reviewed extensive information concerning the companies, analyzed the Conversion Ratio employing a variety of valuation methodologies and opined that the Conversion Ratio is fair to the respective holders of NCE Common Stock and NSP Common Stock as of the date of the Merger Agreement and as of the date the Joint Proxy Statement was mailed to stockholders of NSP and NCE. The investment bankers' analyses and opinions are described in detail on pages 40 to 53 of the Joint Proxy Statement. The assistance of independent consultants in setting considerations has been recognized by the Commission as evidence that the requirements of Section 10(b)(2) have been met. Southern Company, supra; and SV Ventures, Inc., Holding Co. Act Release No. 24579 (Feb. 12, 1988).
Finally, the Merger was submitted to, and approved by, the affected public shareholders, i.e., the common shareholders of NCE and the common and preferred shareholders of NSP. Holders of approximately 93% of NCE's common stock represented at the meeting approved the Merger, and holders of approximately 83% of NSP's common and preferred stock represented at the meeting approved the Merger.
A further consideration under Section 10(b)(2) is the overall fees, commissions and expenses to be incurred in connection with the Merger. NCE and NSP believe that these items are reasonable and fair in light of the size and complexity of the Merger relative to other utility mergers and acquisitions, and the anticipated benefits of the Merger to the public, investors and consumers are consistent with recent precedent and meet the standards of Section 10(b)(2).
As set forth in Item 2 of this Application-Declaration, NSP and NCE together expect to incur a combined total of approximately $43.7 million in fees, commissions and expenses in connection with the Merger, including the financial advisory fees to SG Barr Devlin and The Blackstone Group. By contrast, AEP and Central and South West Corporation have represented that they expect to incur total transaction fees and regulatory processing fees of approximately $53 million in connection with their proposed Merger. The Cincinnati Gas and Electric Company and PSI Resources incurred $47.12 million in fees in connection with their reorganization as subsidiaries of CINergy; Northeast Utilities alone incurred $46.5 million in fees and expenses in connection with its acquisition of Public Service of New Hampshire; and Entergy alone incurred $38 million in fees in connection with its acquisition of Gulf States Utilities -- which amounts all were approved as reasonable by the Commission. CINergy, Holding Co. Act Release No. 26146 (Oct. 21, 1994); Northeast Utilities, Holding Co. Act Release No. 25548 (June 3, 1992); and Entergy Corp., Holding Co. Act Release No. 25952 (Dec. 17, 1993).
The Applicants believe that the estimated fees and expenses in this matter bear a fair relation to the value of their respective companies and the benefits to be achieved by the Merger, and further that the fees and expenses are fair and reasonable in light of the complexity of the Merger. See Northeast Utilities, supra (noting that fees and expenses must constitute normal costs and represent a minor part of the overall acquisition). Based on a $20.4375 price per share of NSP Common Stock, which was the closing price per share as reported on the NYSE-Composite Transaction of NSP Common Stock November 30, 1999, the Merger would be valued at approximately $4.0 billion. The total estimated fees and expenses of $43.7 million represent approximately 1.1% of the value of the consideration to be paid, and are consistent with (and are in fact lower than) percentages previously approved by the Commission. See, e.g., Entergy Corp., supra (fees and expenses represented approximately 1.7% of the value of the consideration paid to the shareholders of Gulf States Utilities); Northeast Utilities, supra (fees and expenses represented approximately 2% of the value of the assets to be acquired).
Section 10(b)(3) requires the Commission to determine whether the Merger will "unduly complicate the capital structure" or be "detrimental to the public interest or the interest of investors or consumers or the proper functioning" of the Xcel system.
The capital structure of Xcel will be substantially similar to capital structures approved by the Commission in other orders. See, e.g., Ameren Corporation, Holding Co. Act Release No. 26809 (Dec. 30, 1997); CINergy Corp; Holding Co. Act Release No. 26934 (Nov. 2, 1998); and Centerior Energy Corp., Holding Co. Act Release No. 24073 (April 29, 1986). Xcel's capital structure will also be similar to the capital structures of existing registered holding company systems. See, e.g., Ameren, supra; the 1997 NCE Order, supra; and American Electric Power, Holding Co. Act Release No. 21433 (Feb. 13, 1980). The shareholders of NCE will receive Xcel (i.e., NSP) Common Stock. Xcel will own 100% of the common stock of NSP-W, New NSP, BMG, SPS, PSCo and Cheyenne, and there will be no minority common stock interest in any of those companies. Each outstanding share of NSP preferred stock will remain outstanding without change as preferred stock of Xcel. The Commission has found previously that the existence of preferred stock under facts similar to those of the present case does not violate the standards of the Act. Illinois Power Company, Holding Co. Act Release No. 16574 (Jan. 2, 1970) (finding that "adequate safeguards were afforded by the dividend and liquidation preferences and other protective provisions that are applicable to such stock). See also, New Century Energies, Inc., Holding Co. Act Release No. 26751(Aug. 1, 1997) and The Columbia Gas System, Inc., Holding Co. Act Release No. 26361 (Aug. 25, 1995) (each authorizing preferred stock in a registered holding company).
The existing debt securities of NSP, NSP-W, SPS, PSCo and Cheyenne will likewise remain outstanding without change, except that, with the merger of NCE into NSP, the debt of NCE will become the debt of Xcel, and the existing debt of NSP will be transferred to New NSP. The only voting securities of Xcel that will be publicly held after the Merger will be NSP's existing Preferred Stock (which, as noted above, will become Preferred Stock of Xcel) and Xcel Common Stock. The outstanding NSP (i.e., Xcel) preferred stock will consist of 1.05 million shares, consisting of 6 series. Each share of such preferred stock is entitled to one vote per share on all matters presented to stockholders with the exception of $3.60 series consisting of 275,000 shares, which is entitled to three votes per share. [24]
Xcel will have the ability to issue, subject to the approval of the Commission, preferred stock, the terms of which may be set by Xcel's Board of Directors. See, e.g., Columbia Gas System, Inc., Holding Co. Act Release No. 26361 (Aug. 25, 1995) (approving restated charter, including preferred the terms of which, including voting rights, can be established by the board of directors). The only outstanding class of voting securities of Xcel's direct non-utility subsidiaries will be common stock and, in each case, all issued and outstanding shares of such common stock will be held by Xcel (other than as noted above for C&F, which is 75.86% owned, and NMC, which is 25% owned.)
Set forth below are summaries of the capital structures of NSP and NCE as of December 31, 1998, and the pro forma consolidated capital structure of Xcel (assuming the Merger occurred on December 31, 1998):
|
NSP and NCE Historical Capital Structures |
||||
|
|
|
|||
|
Common stock equity |
$2,481 |
47.3% |
$2,615 |
45.2% |
|
Preferred stock |
305 |
5.8 |
294 |
5.1 |
|
Long-term debt |
1,851 |
35.3 |
2,344 |
38.2 |
|
Short-term debt* |
609 |
11.6 |
524 |
11.5 |
|
Total |
$5,246 |
100.0% |
$5,777 |
100.0% |
_______________
* Includes current portion of long-term debt.
Xcel Pro Forma Consolidated Capital Structure
(dollars in millions) (unaudited)
|
Common stock equity |
$5,095 |
46.2% |
|
Preferred stock |
599 |
5.4 |
|
Long-term debt |
4,057 |
36.8 |
|
Short-term debt* |
1,272 |
11.5 |
|
Total |
$11,023 |
100.0% |
_______________
* Includes current portion of long-term debt.
Set forth below are summaries of the capital structures of NSP and NCE as of September 30, 1999, and the pro forma consolidated capital structure of Xcel (assuming the Merger occurred on September 30, 1999).
NSP and NCE Historical Structures
(dollars in millions)
|
NSP |
NCE |
|||
|
Common stock equity |
$2,548 |
39.5% |
$2,699 |
44.1% |
|
Preferred stock |
305 |
4.7 |
294 |
4.8 |
|
Long-term debt |
2,393 |
37.1 |
2,272 |
37.1 |
|
Short-term debt* |
1,206 |
18.7 |
855 |
14.0 |
|
Total |
$6,452 |
100.0% |
$6,120 |
100.0% |
_______________
* Includes current portion of long-term debt.
Xcel Pro Forma Consolidated Capital Structure
(dollars in millions) (unaudited)
|
Common stock equity |
$ 5,247 |
41.7% |
|
Preferred stock |
599 |
4.8 |
|
Long-term debt |
4,665 |
37.1 |
|
Short-term debt* |
2,061 |
16.4 |
|
Total |
$12,572 |
100.0% |
_______________
* Includes current portion of long-term debt.
Xcel's pro forma consolidated common equity to total capitalization ratio of 46.9% (41.7% as of September 30, 1999) comfortably exceeds the "traditionally acceptable 30% level." [25] Northeast Utilities, Holding Co. Act Release No. 25221 (Dec. 21, 1990). Accordingly, the proposed Merger will not unduly complicate the capital structure of the resulting holding company.
Section 10(b)(3) also requires the Commission to determine whether the proposed combination will be detrimental to the public interest, the interests of investors or consumers or the proper functioning of the combined Xcel system. The combination of NSP and NCE is entirely consistent with the proper functioning of a registered holding company system. NSP's and NCE's utility operations will be fully integrated. Further, the combination will result in substantial, otherwise unavailable, savings and benefits to the public and to consumers and investors of both companies, and the integration of NSP and NCE will improve the efficiency of their respective systems. The integration of NSP and NCE is described below in Item 3.C.1.(b) and the benefits and savings are described in Item 3.C.2.
Finally, as indicated previously, consummation of the Merger is conditional upon receipt of numerous state and federal regulatory approvals. These regulatory approvals will assure that the interests of retail customers and wholesale customers are adequately protected. FERC's recent approval further assures that there will be no significant effect to competition resulting from the Merger. Moreover, as noted by the Commission in approving Entergy's acquisition of Gulf States Utilities, "concerns with respect to investors' interests have been largely addressed by developments in the federal securities laws and the securities market themselves." Entergy Corp., Holding Co. Act Release No. 25952 (Dec. 17, 1993). Xcel, New NSP, NSP-W, PSCo, SPS and NRG will be reporting companies subject to the continuous disclosure requirements of the 1934 Act following the completion of the Merger. The various reports previously filed by NSP and NCE under the 1934 Act contain readily available information concerning the Merger. For these reasons, the Applicants believe that the Merger will be in the public interest and the interest of investors and consumers and will not be detrimental to the proper functioning of the resulting holding company system.
Section 10(c) of the Act provides that, notwithstanding the provisions of Section 10(b), the Commission shall not approve:
(1) an acquisition of securities or utility assets, or of any other interest, which is unlawful under the provisions of Section 8 or is detrimental to the carrying out of the provisions of Section 11; or
(2) the acquisition of securities or utility assets of a public utility or holding company unless the Commission finds that such acquisition will serve the public interest by tending towards the economical and the efficient development of an integrated public utility system.
(a) The Merger will be lawful under Section 8
Section 10(c)(1) first requires that the Merger be lawful under Section 8. That section was intended to prevent holding companies, by the use of separate subsidiaries, from circumventing state restrictions on common ownership of gas and electric operations. The Merger will not result in any new situations of common ownership of so-called "combination" systems within a given state. Post-Merger, New NSP, as successor to NSP, will continue to provide electric and gas utility services in Minnesota, North Dakota and South Dakota. NSP-W will provide electric and gas utility services in Wisconsin and Michigan; BMG will provide gas and propane service in Arizona; PSCo will provide gas and electric utility service in Colorado; and Cheyenne will provide gas and electric utility service in Wyoming. Since Minnesota, Michigan, Wisconsin, Wyoming, Colorado, South Dakota and North Dakota law all permit combination gas and electric utilities serving the same area, the Merger does not raise any issue under Section 8 or, accordingly, the first clause of Section 10(c)(1).
(b)
The
Merger will not be detrimental to carrying out the
provisions of
Section 11
Section 10(c)(1) also requires that the Merger not be "detrimental to the carrying out of the provisions of Section 11." Section 11(b)(1) directs the Commission generally to limit a registered holding company "to a single integrated public-utility system." In the 1997 NCE Order, the Commission found that the combined Colorado, New Mexico, Texas, Oklahoma and Kansas electric operations constituted a single, integrated electric utility system (the "Primary System"), [26] and that the Wyoming electric operations (the "Cheyenne Electric System") and the combined Wyoming and Colorado gas operations (the "Gas System") were each a permissible additional system under the A-B-C clauses of Section 11(b)(1). At issue is whether the further addition of NSP and NSP-W, each of which is a combination electric and gas utility, will result in a system that is "detrimental to the carrying out of the provisions of Section 11."
In the early years of its administration of the Act, the Commission construed Section 11(b)(1) to preclude significant geographic expansion by holding company systems. However, as the Commission has acknowledged, the Act "creates a system of pervasive and continuing economic regulation that must in some measure at least be fashioned from time to time to keep pace with changing economic and regulatory climates." [27] In recent decisions, the Commission has cited U.S. Supreme Court and Circuit Court of Appeals cases that recognize that an agency is not required to "establish rules of conduct to last forever," [28] but must "adapt [its] rules and policies to the demands of changing circumstances" [29] and to "treat experience not as a jailer but as a teacher." [30] Consequently, the Commission has attempted to "respond flexibly to the legislative, regulatory and technological changes that are transforming the structure and shape of the utility industry" as recommended in the Staff's 1995 Report. Indeed, with specific reference to the integration requirements of the Act, the 1995 Report explains:
The statute recognizes . . . that the application of the integration standards must be able to adjust in response to changes in "the state of the art." As discussed previously, the Division believes the SEC must respond realistically to the changes in the utility industry and interpret more flexibly each piece of the integration equation.[31]
Moreover, the ultimate determination has always been whether, on the facts of a given matter, the proposed transaction "will lead to a recurrence of the evils the Act was intended to address." [32] See also Sempra Energy, Holding Company Act Release No. 26971 (Feb. 1, 1999), in which the Commission acknowledged that "we have taken notice of developments that have occurred in the gas industry, and have interpreted the Act and analyzed proposed transactions in light of these changed and changing circumstances."[33]
As explained more fully below, the combination of the Primary System of NCE and the electric operations of NSP and NSP-W (the "NSP Electric System") will result in a single, integrated electric utility system (the "Xcel Electric System"). Integration will result from the combination of the following: (1) the Joint Operating Agreement, which will provide the framework for the coordinated operation and dispatch of the electric generating resources of the operating companies of Xcel; (2) participation in MISO by the NSP companies and SPS, which will involve the operational control by MISO of their transmission systems (and to some extent, their generating resources) and which will enable them, by using the MISO Tariff, to transact with each other and numerous other systems at single system transmission rates[34] ; and (3) a 100 MW firm transmission path from 2002 through 2004 between SPS and the NSP companies which will further facilitate transactions among the Xcel Operating Companies and by the Xcel Operating Companies on a joint basis with third parties. [35] The combination of the NCE Gas System and the NSP gas operations also will result in a single, integrated gas utility system (the "Xcel Gas System"). Consequently, the Commission should find that the Xcel Electric System will be the primary integrated public-utility system for purposes of Section 11(b)(1), and the Xcel Gas System and the Cheyenne Electric System are permissible systems under the A-B-C clauses of that section.[36]
(i) Integration of Electric Operations
The threshold question is whether the Primary System of NCE can be combined with the electric operations of NSP to form a single integrated public utility system. The term, as applied to electric utility companies, means:
a system consisting of one or more units of generating plants and/or transmission lines and/or distributing facilities, whose utility assets, whether owned by one or more electric utility companies, are physically interconnected or capable of physical interconnection and which under normal conditions may be economically operated as a single interconnected and coordinated system confined in its operations to a single area or region, in one or more States, not so large as to impair (considering the state of the art and the area or region affected) the advantages of localized management, efficient operation, and the effectiveness of regulation.
Section 2(a)(29)(A). As the definition suggests, and the Commission has observed, Section 11 is not intended to impose "rigid concepts" but rather creates a "flexible" standard designed "to accommodate changes in the electric utility industry." UNITIL Corp ., Holding Co. Act Release No. 25524 (April 24, 1992); see also Yankee Atomic Electric. Co., Holding Co. Act Release No. 13048 (Nov. 25, 1955) ("We think it is clear from the language of Section 2(a)(29)(A), which defines an integrated public utility system, that Congress did not intend to imposed [sic] rigid concepts with respect thereto.")(citations omitted). See also Madison Gas and Electric Company v. SEC, 168 F.3d. 1337 (D.C. Cir. 1999) ("section 10(c)(1) does not require that new acquisitions comply to the letter with section 11"). [37] Section 2(a)(29)(A) expressly directs the Commission to consider the "state of the art" in analyzing the integration requirement. As indicated above, the Commission is not constrained by its past decisions interpreting the integration standards based on what was then the "state of the art." See AEP, supra (noting that the state of the art -- technological advances in generation and transmission, unavailable thirty years prior -- served to distinguish a prior case and justified "large systems spanning several states").
The concept of an integrated public utility system has evolved in light of the dramatic changes in the law, technology and structure of the industry since the passage of the 1935 Act over 60 years ago. Since the enactment of the Act, the "state of the art" has changed enormously, so as to include within the scope of integrated operations a broader range of utility contractual relationships and activities. A review of these changes seems appropriate in view of the Commission's stated goal of interpreting the Act to reflect and accommodate changes in the industry.
Historically, electric utilities have been single corporate entities engaged in three vertically-integrated businesses: (i) generation of electricity (i.e., the ownership and operation of power plants that produce electricity); (ii) transmission of electricity (i.e., the ownership and operation of the high voltage facilities that transport electric energy in bulk from one point to another, generally from a utility's generating units to its distribution facilities); and (iii) distribution of electricity (the ownership and operation of the lower voltage facilities that deliver electric energy from the transmission system to most end users). Until recently, electric utilities operated as regulated monopolies "predicated on the concept that a central source of power supplied by efficient, low-cost utility generation, transmission, and distribution was a natural monopoly."[38] These utilities generally built generating facilities in the proximity of their customers, and transmission was treated essentially "as an incidental service." [39]
In the decades following the enactment of the Act, the transmission sector of the electric utility industry significantly expanded. The total miles of high voltage (230 kV and above) transmission lines tripled in the 1950s and tripled again in the 1960s.[40] Utilities had originally constructed transmission facilities to transmit power from their own plants to their customers. Subsequent to the enactment of the 1935 Act, utilities increasingly developed interconnections with their neighboring utilities to obtain and provide assistance in emergency situations, to improve reliability, and to reduce the costs of power supply through long-term capacity transactions and economy transactions with their neighbors. [41] Technological advances in transmission have also occurred, making it possible to transmit electric power economically over long distances at higher voltages. In today's world, "improved transmission and monitoring technologies have increased the feasible geographic bounds for supply choice; a geographic radius of 1,000 miles or more is currently considered reasonable for choosing among supply options." [42]
Interconnections have proven so beneficial that every utility in the continental United States is interconnected with one of three Interconnects: the Eastern Interconnect, which encompasses utilities in the eastern United States and Canada from the Atlantic Ocean to the High Plains; the Western Interconnect, which encompasses utilities from the High Plains/Rocky Mountain region to the Pacific Ocean; and ERCOT, which encompasses most of the State of Texas. FERC has described the present state of the transmission sector of the electric utility industry as follows:
The transmission facilities of any one utility in a region are part of a larger, integrated transmission system. From an electric engineering perspective, each of the three interconnections in the United States (the Eastern, Western and ERCOT) operates as a single "machine."
Regional Transmission Organizations, Notice of Proposed Rulemaking, IV FERC Stats. & Regs. ¶ 32,541 (1999) ("RTO NOPR") at 33,697. See also, Regional Transmission Organizations, 89 FERC ¶ 61,285, Order No. 2000 (1999) ("Order No. 2000") at FERC Mimeo. p. 32. [43]
The generation sector of the electric utility industry is also very different than it was in 1935. Concern over the nation's energy future, in conjunction with other factors, led to the first significant legislative development at the federal level affecting the electric utility industry since the enactment of the Act and the FPA: the enactment of the Public Utility Regulatory Policies Act of 1978 ("PURPA"). PURPA requires utilities to purchase the output of qualifying facilities ("QFs") at avoided cost rates established by state commissions. [44] An effect of PURPA was to begin to separate generation from the transmission and distribution functions of utility operations, or to put it another way, to broaden the scope of integrated electric operations to include purchases from third parties as well as a utility's own production of electricity. Consistent with the intent of PURPA, in some states significant QF resources were added in lieu of utility generation.[45]
Following the enactment of PURPA and the development of the QF industry, independent power producers ("IPPs") emerged as another type of generation supplier. IPPs operate without a franchised service territory or an established customer base and seek to sell the output of their generating facilities in the wholesale market, typically to a single utility. With many traditional utilities wary of investing in new generation for a variety of reasons, IPPs in some instances found a ready market. IPPs were further spurred by the great latitude that FERC afforded them in rate setting. In fact, FERC initially developed its market-based rate standards in the context of IPPs.[46] However, the development of IPPs was formerly inhibited by their lack of access to essential transmission facilities to reach a broader customer base, as well as ownership restrictions effectively created by the integration requirements of the Act. Recognizing these obstacles and desiring to promote greater development of wholesale power markets generally, Congress passed the Energy Policy Act of 1992 ("EPACT").[47] EPACT amended the FPA to permit any entity selling power at wholesale to request FERC to order a transmission-owning utility to provide transmission services.[48] EPACT also created a new exemption under Section 32 of the 1935 Act for exempt wholesale generators ("EWGs"). The EWG exemption ensures that the 1935 Act's integration requirements will not thwart the development of IPPs participating in the wholesale market, an implicit acknowledgment that the economic operation of a utility system depends on contractual relationships as well as facilities ownership.
Since EPACT, the competitive electric supply wholesale market has developed rapidly. This progress has been facilitated by FERC's willingness to permit the sale of electric capacity and energy at market-based rates. This change in regulatory policy applies not only to IPPs, but to power marketers (many of which are affiliated with utilities) - a relatively new class of wholesale market participant that purchases and sells power produced by third parties, not from their own resources. This new policy also applies to utilities directly, who have increasingly focused on their own wholesale marketing efforts. It is now the rare utility that does not have either market-based rate authority or an active wholesale power marketing affiliate.[49]
Notwithstanding these initiatives, FERC concluded that due to the lack of third-party transmission access, and preferential access that utilities accorded to their own marketing efforts, unequal transmission access continued to impede the development of fully competitive bulk power markets that FERC sought to promote.[50] On that basis, within three years of the enactment of EPACT, FERC commenced the so-called "Mega-NOPR" proceeding, Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities. [51] This notice of proposed rulemaking culminated approximately a year later with FERC's issuance of Order No. 888.[52]
Order No. 888 requires all transmission owners to (1) offer comparable open-access transmission service for wholesale transactions under a tariff of general applicability on file at FERC [53] and (2) take transmission service for their own wholesale sales under their open-access tariff. Order No. 888 was intended to facilitate third-party utilization of the transmission grid as the vehicle for developing a competitive wholesale bulk power market. Under Order No. 888, a utility must wheel power for third parties upon their request, on either a firm or a non-firm basis. [54] If the transmitting utility does not have sufficient transmission capacity to transmit on a firm basis, it must either offer to expand its transmission system to accommodate the request, or, if appropriate, to redispatch generation to relieve constraints and thereby make transmission capacity available. In the interim, a utility must offer transmission on a non-firm basis to the requesting entity. [55]
Prior to Order No. 888, electric utilities typically needed to construct direct interconnections to facilitate capacity and energy transfers. Now, as a matter of right under Order No. 888, two utilities can contractually arrange for interconnection: by contract, they can acquire either a firm or a non-firm transmission path that would allow power transfers between their separate systems.
Moreover, Order No. 888's companion order, Order No. 889, [56] requires public utilities to functionally separate their transmission and reliability functions from their wholesale power marketing functions. In this connection, Order No. 889 required public utilities to develop and maintain an Open Access Same-Time Information System ("OASIS") to give transmission users the same access to transmission information that the wholesale merchant function of a utility enjoys. The fundamental purpose of an OASIS is to ensure that transmission customers have access to transmission information, through electronic means, that will enable them to obtain open-access transmission service on a basis comparable to a transmitting utility's own use of its system. [57] Generally stated, a utility's wholesale merchant function is limited to receiving from a utility's transmission and reliability function only such transmission information that is posted on an OASIS, and is thereby publicly available on a simultaneous basis to third-party transmission customers. Thus, while FERC in Order Nos. 888 and 889 did not require actual corporate divestiture or legal separation of generation and transmission functions within utilities, on an operational basis there has been a de facto separation of these functions in response to these orders.
The comparable transmission service and functional unbundling that FERC has required in Order Nos. 888 and 889 initially may appear to contradict the integrated operation of electric systems required under Section 11. Taken together, the two orders require utilities to deprive themselves of any benefit associated with the consolidation of ownership of transmission and generation facilities. Instead, under the concepts supporting Order Nos. 888 and 889, such benefits are created by the competitive marketplace that results from open access. As FERC stated in Order No. 888, "[i]ncreasingly, customers are demanding the benefits of competition in the growing electric commodity market." FERC estimated quantitative benefits of its rule of $3.8-$5.4 billion a year, in addition to expected non-quantifiable benefits such as better use of existing assets and institutions, new market mechanisms, technical innovation and less rate distortion. According to FERC, the continuing competitive changes in the industry and the prospect of these benefits to customers made it imperative that FERC ensure nondiscriminatory transmission access through Order Nos. 888 and 889. [58] Thus, FERC has recognized that the economic operation of utility systems can be achieved, and indeed is perhaps best achieved, through contractual relationships in a competitive marketplace, and not simply through ownership of facilities.
EPACT, Order Nos. 888 and 889, and other FERC policies and initiatives have had a tremendous impact on the development of competitive bulk power markets. Utilities have increased their own in-house wholesale marketing efforts and the number of entities with whom they trade. To illustrate by example, PSCo's non-requirements wholesales sales (including short-term firm and economy sales) have increased from 306,920 MWh in 1993 to 7,873,800 MWh in 1998. Moreover, whereas PSCo's past wholesale marketing efforts were largely limited to economy energy sales made by its dispatchers in the former Inland Power Pool, New Century Services now has a marketing group that makes sales on behalf of PSCo throughout the entire western region. Similarly, NSP's revenues from sales for resale have increased by 55% from 1996 to 1998. While trades were typically made within MAPP and MAIN in the past, NSP has found it economical to trade in markets such as Ohio and Florida.
Moreover, power marketers are an increasingly important presence in the industry. The top ten power marketers sold in excess of 1 billion MWh in 1998. These entities typically arbitrage remaining price differentials by buying in one market and selling in another. The effect is to minimize margins to be gained in these interregional sales and therefore to drive electric supply market prices closer to a regional-wide marginal (or incremental) cost. As prices move to marginal cost, rate differentials arising from historical embedded cost will begin to disappear. [59] IPPs also are becoming a more significant sector of the electric utility industry. Nationwide, plans to build new plants have exploded. In the Northeast Power Coordinating Counsel region alone, an additional 30,000 MWs has been announced, almost all of it from IPPs.[60] Similar plant additions have been announced by IPPs and EWGs in the mid-continent area as well. These significant plant additions lessen the impact of historical embedded utility-specific price differentials by changing the cost structure of the industry as a whole.
Notwithstanding these developments in the wholesale power market, FERC has recognized that impediments remain to the achievement of fully competitive markets. Specifically, FERC has identified two important transmission-related problems with the current structure of the industry: (1) engineering and economic inefficiencies inherent in the current operation and expansion of the transmission grid and (2) continuing opportunities for transmission owners to discriminate in the operation of their transmission facilities in favor of their own or affiliated power marketing activities. Thus, whereas FERC in the past only encouraged utilities to join and place their transmission systems under the operational control of ISOs,[61] FERC in the RTO NOPR requested industry comment on a proposal that each public utility that owns, operates, or controls transmission facilities make certain filings with respect to forming and participating in an RTO - i.e., a properly constituted ISO or transmission company ("Transco"). Subsequently on December 20, 1999, FERC issued Order No. 2000, its final rule on RTOs. Order No. 2000 sets out FERC's expectation that all transmission owners will join RTOs on a voluntary basis. To that end, FERC announced a timetable for every jurisdictional utility to either join in an RTO filing, or, alternatively, to submit a filing describing its efforts to join in an RTO, the reasons for not participating in an RTO proposal and any obstacles to participation, and its plans for further work toward participation. This timetable is aggressive, requiring that utilities not already participating in a FERC-approved RTO make such initial filing by October 15, 2000. Public utilities that have already transferred control of their facilities to a FERC-approved RTO must file with FERC by January 15, 2001, a statement explaining, among other things, how such RTO has the characteristics and performs the minimum functions identified by FERC in the final rule. [62] FERC also announced institution of a collaborative process whereby FERC expects public and non-public utilities, in coordination with state officials, FERC staff, and all affected interest groups to work actively towards the voluntary development of RTOs. Although adopting a voluntary approach towards RTO formation, FERC stressed that Order No. 2000 does not preclude it from requiring RTO participation through the exercise of its authority under the Federal Power Act to remedy undue discrimination. The final rule adopted by FERC in Order No. 2000 is substantially similar to the proposed rule.
FERC has thus given utilities new impetus to join RTOs, including ISOs. Order No. 2000 makes clear that the form of an RTO is not critical so long as the RTO has certain minimum characteristics and functions. Minimum characteristics include (i) independence from market participants (generally, any entity that, either directly or through an affiliate, sells or brokers electric energy, or provides transmission or ancillary services to the RTO); (ii) sufficient scope and regional configuration (that is, sufficient to permit the RTO to maintain reliability, effectively perform its required functions, and support efficient and non-discriminatory power markets); (iii) operational authority (that is, over all transmission facilities under its control); and (iv) short-term reliability (that is, exclusive authority for maintaining the short-term reliability of the transmission grid that the RTO operates). In addition, an RTO must provide the following functions at a minimum: (i) tariff administration and design; (ii) congestion management; (iii) parallel path flow management; (iv) supplier of last resort for ancillary services; (v) OASIS site administration and the determination of total transmission capability and available transmission capacity; (vi) market monitoring; (vii) system planning and expansion; and (viii) interregional coordination. [63] These minimum characteristics and functions are intended to have the effect of turning the nation's transmission facilities into independently owned and operated "common carriers" that offer comparable service to all would-be users.
Several factors led to FERC's issuance of Order No. 2000 at this time. First, FERC has identified what can be broadly characterized as operational inefficiencies in the current provision of transmission services. Due to the changes in the structure of the electric utility industry, the transmission grids in the three interconnects - the Eastern Interconnect, the Western Interconnect and ERCOT - are being used more extensively and in different ways that they ever had been in the past. [64] This increased usage, which has put a strain on all systems, has further called into question the reliance on the "contract path" model of arranging transmission services whereby an entity requiring transmission service between two utilities - e.g., Utilities A and B - could arrange it by putting together a "path" among intervening systems - e.g., Utilities C and D - even where power flows primarily over another system - e.g., Utility E. In the past, there was generally enough slack in the grid to allow for these arrangements. Now, however, with transmission systems operating closer to capacity during many periods, FERC has recognized the need to have transmission arrangements evaluated and made in a larger, regional context. FERC expects that properly configured RTOs, through control over a larger, regional grid, will:
As FERC summarized in Order No. 2000, "[r]egional institutions can address the operational and reliability issues now confronting the industry, and eliminate any residual discrimination in transmission services that can occur when the operation of the transmission system remains in the control of the vertically integrated utility." [69]
FERC expects that RTOs will promote economic efficiency as well as operational efficiency. A significant barrier to equalizing the trading price of a more distant utility with a nearby utility is the cost of transmission, which is hampered by the "pancaking" of rates under the current transmission pricing scheme. Simply stated, if a transaction requires movement of power across the transmission system of multiple, non-affiliated public utilities:
[the] transmission customer pays separate, additive access charges every time its contract path crosses the boundary of a transmission owner. By raising the cost of transmission, pancaking reduces the size of geographic power markets. This, in turn, can result in concentrated electricity markets. Balkanization of electricity markets hurts electricity consumers, in general, by forcing them to pay higher prices than they would in a larger, more competitive, bulk power market. [70]
As such, wholesale generators or customers seeking to buy competitively priced generation in more distant markets must pay transmission costs that may exceed the benefits of the transaction.
Among other benefits, an RTO price structure eliminates rate pancaking, allowing power on the most distant edges of an ISO to be transmitted at market price with no additional cost for transmission than would exist for a nearby transaction or even the generation-to-end-user within a utility's own service area. FERC has explained this benefit:
The Commission has long recognized that transmission pricing reform is most effectively accomplished on a regional basis. An RTO would have the geographic scope needed to eliminate pancaked transmission rates within its region. This would broaden the generation market and could result in more potential suppliers and less concentrated generation markets, thereby fostering more competitive markets and lower prices to consumers. [71]
Because RTOs will offer service to customers on a system-wide basis under a single FERC-approved tariff, customers will have available ""one stop shopping" for regional transmission service . . . resulting in simpler and more efficient procedures for transmission users to transmit power over greater distances."[72]
Due to these and other developments at the federal level, the landscape of the electric industry is changing rapidly. Wholesale power markets have developed from a balkanized, utility-specific, cost-based structure to a more competitive market-based structure. [73] Transmission services will increasingly be managed or provided through large regional entities rather than individual utilities. The effect of these developments on SEC merger policy is both direct and profound. The emergence of RTOs, at the direction of FERC, will further facilitate wholesale competition, moving the industry further from the vertically-integrated utility model under which utilities relied substantially on their own resources to serve their loads. Because NSP and NCE can, by joining the same RTO, obtain energy from distant markets at prices equivalent to or better than nearby markets in which they do business, direct physical interconnection is no longer necessary for the utilities to transact with, or act in unison with, one another to achieve operational efficiency. For example, in situations where two non-contiguous utilities in the same RTO wish to transact with each other, they can arrange necessary transmission services using an RTO's non-pancaked tariff. Moreover, using this tariff, two non-contiguous utilities in the same RTO may reach common suppliers or hubs to both sell and purchase electricity collectively. The net effect of these regulatory and market changes is to require a re-evaluation of the meaning of integration in light of the present structure of the electric utility industry and regulatory environment, which have changed dramatically since the passage of the Act. [74] The Commission already has recognized many of these changes in its decisions in UNITIL Corp., Holding Co. Act Release No. 25524 (April 24, 1992) and Conectiv, Inc., Holding Co. Act Release No. 26832 (February 25, 1998). As will be demonstrated, Applicants joint membership in the same ISO/RTO is entirely consistent with past precedent and meets the integration requirements of the Act.
Regulatory changes at the state level have paralleled those at the federal level and have been equally dramatic. Concurrent with or subsequent to their implementation of PURPA, states began developing integrated resource planning requirements that mandate that utilities focus on both supply-side and demand-side resources and that require local utilities competitively bid their resource requirements to obtain the lowest cost resources possible. Under these resource procurement requirements, utilities must purchase power from third parties (rather than provide for their own generation) if to do so would result in lower costs to consumers. Typically, special evaluation procedures apply to assure the fairness of the bidding process where a utility desires to pursue a self-build option or where an affiliate desires to submit a proposal. The bidding process has also become the manner in which QF suppliers are chosen for avoided cost sales. For example, the Colorado Commission has adopted integrated resource planning rules that require that utilities in Colorado conduct a competitive resource procurement process for all additions of capacity to their systems, except in very narrow circumstances, e.g., capacity and/or energy from the generation facilities of other utilities or from non-utility generators pursuant to agreements for less than one year term or for less than ten megawatts of capacity. In the event that a Colorado utility wishes to pursue a self-build option of greater than 10 MW, it must submit a proposal in the competitive process. SPS and NSP are likewise subject to competitive procurement procedures.[75] Thus, the state regulators have recognized that the economic operation of a utility system must include the benefits of integration through the marketplace and not just the effects of vertically-integrated ownership structure.
Moreover, virtually every state, either at the legislative level or the state regulatory commission level, has implemented or is actively considering retail competition. One consequence of such actions has been the divestiture by utilities of large amounts of generating assets to relieve stranded costs or in response to a state mandate. Since August 1997, approximately 50,000 MW of generating capacity have been sold (or are under contract to be sold) by utilities, and an additional 30,000 MW is currently for sale. In total, this represents more than 10 percent of U.S. generating capacity.[76] The combination of state restructuring efforts and federal unbundling of transmission from generation makes it clear that utilities will not be encouraged to achieve saving from mergers through the combination of generating facilities. The lowest cost supply of power will be achieved in the market, and consumers will directly access that market.
The two states in which SPS principally operates, Texas and New Mexico, vividly illustrate the trend towards retail electric competition. Both Texas and New Mexico in 1999 enacted restructuring legislation requiring that historically integrated utilities, including SPS, unbundle their transmission and distribution operations from their energy supply operations (including the generation function) through corporate reorganizations or divestitures of assets to facilitate retail competition in those states.
To elaborate, New Mexico SB-428, which was recently enacted, will require the corporate separation of SPS's generation operations and its transmission and distribution operations in New Mexico. Texas SB-7, which was recently enacted, will require the corporate separation of SPS's generation, retail marketing, and transmission and distribution operations in Texas. Moreover, SB-7 requires Texas utilities to sell at auction, at least sixty days before customer choice is to begin in Texas, entitlements to at least fifteen percent of their jurisdictional installed capacity, and further limits the amount of installed generating capacity that a generating company in Texas, including those formed through the corporate separation of existing integrated utilities, may own.
Both New Mexico SB-428 and Texas SB-7 require utilities to submit compliance or "transition" plans for state commission approval. In New Mexico, SPS must file its transition plan by March 1, 2000, for New Mexico Commission approval by December 1, 2000. In Texas, SPS on January 10, 2000 filed its plan to separate its retail, generation, and transmission and distribution businesses. By December 1, 2000, SPS must file its transition to competition plan. Moreover, in its order setting the Merger for hearing, the Texas Commission requested that SPS file supplemental direct testimony addressing the structural and operational changes that SPS would make to comply with SB-7. While SPS is continuing to develop its separation and transition plans more fully, it has proposed to the Texas Commission that it would take the following steps in compliance with SB-7. First, SPS (or the generating company that is established through the corporate separation of SPS's activities) would divest approximately 200 MW of generation capacity by the beginning of 2002. Subsequently, SPS would take various long-term actions to achieve an allowable level of generation, namely (1) to refrain from building or acquiring additional generation capacity within its service territory, (2) to investigate the construction of additional transmission capacity to increase transmission import capacity to the Texas Panhandle, wherein SPS operates, and (3) to divest itself or dispose of by other means sufficient generation capacity to meet the applicable generation ownership limitations.[77]
To summarize, the ongoing corporate restructuring of the U.S. utility industry reflects the effects of emerging FERC policy on transmission (including Order Nos. 888 and 889 requiring open-access transmission on comparable terms and the functional unbundling of the transmission and wholesale merchant functions), the formation of ISOs and Order No. 2000. It is also the product of many recent state laws mandating competitive resource procurement and retail electric competition, and the functional separation (and in some states, divestiture) of generation from transmission and distribution operations. Layered on these changes are both rapid developments in technology and the emergence and growth of the power marketing and energy trading businesses, both of which facilitate efficient and competitive low-cost electric markets. Perhaps most notable among all of these changes is the recent evolution of ISOs/RTOs. These entities facilitate trading regions with no economic constraints on transmission access and with the ability to manage and plan for new transmission on a regional basis to help alleviate transmission constraints, thereby providing entities with both the requisite physical and economic means to integrate their systems. The cumulative effect of these regulatory, technological and economic changes has dramatically altered the "state of the art" that Congress directed the Commission to consider more than sixty years ago.
* * * * *
It is against this backdrop of rapid change in the electric utility industry and the regulatory framework that Applicants have developed a plan to integrate the NCE and NSP systems. There are three primary components to this plan. First, the NSP companies and SPS will join the same ISO, namely MISO. MISO will effectively result in the coordination of their transmission systems, and to a lesser extent their generating resources as well. Moreover, the availability of transmission service under the MISO Tariff will facilitate transactions between SPS, the NSP companies, and even PSCo, and those companies collective efforts to access wholesale markets. Second, Applicants have nearly completed the process of arranging a 100 MW south to north firm transmission path from 2002 through 2004 between SPS and the NSP. This contract path will further integrate the Xcel operating companies by permitting cost savings from power transfers between NSP and SPS initially and later between NSP and PSCo. Third, the Xcel operating companies will be parties to the Joint Operating Agreement, which FERC has already approved in the FERC Merger Order. The Joint Operating Agreement provides the basis for the coordination of the Xcel operating companies generating resources, and sets out the contractual framework for them to transact with each other and to transact with third parties on a joint basis. MISO, the contract path and the Joint Operating Agreement are explained below, followed by a showing how the Xcel Electric System will be an integrated electric utility system within the meaning of Section 2(a)(29)(A).
MISO
MISO is a voluntary non-profit corporation and, as FERC has recognized, MISO is unique in that it "began through a consensual process and was not driven by a pre-existing institution." [78] The other ISOs were either the result of state restructuring initiatives (ERCOT and the California ISOs) or grew out of existing tight power pools (PJM, New England, and New York ISOs). MISO's participants include various transmission-owning electric utilities ("Transmission Owners") located in the Midwest. The initial Transmission Owners currently are Ameren Corporation (which includes Central Illinois Public Service Company and Union Electric Company), Central Illinois Light Company, Cinergy Corporation (which includes PSI Energy, Inc., Cincinnati Gas & Electric Company and Union Light, Heat and Power Company), Commonwealth Edison Company, Hoosier Energy Rural Electric Cooperative, Illinova Corp., LG&E Energy Corp. (which includes Louisville Gas and Electric Company and Kentucky Utilities Company), Southern Illinois Power Cooperative, Southern Indiana Gas & Electric Company, Wabash Valley Power Association and Wisconsin Electric Power Company. MISO is expected to commence operations in mid-2001.
As presently constituted (excluding the NSP companies and SPS), MISO will have a service territory that includes portions of Illinois, Indiana, Kentucky, Michigan, Missouri, Ohio and Wisconsin and two regional reliability councils (East Central Area Reliability Coordination Agreement ("ECAR") and Mid-American Interconnected Network ("MAIN")). MISO will control 45,000 miles of transmission facilities which represent approximately $6.5 billion in capital investments, and approximately 70,000 MW of generation assets will be located within the MISO region. With the addition of the NSP companies and SPS, MISO's transmission facilities will expand significantly to include portions of Minnesota, North Dakota, South Dakota, Texas, New Mexico, Oklahoma and Kansas, and generation assets in the MISO region will exceed 80,000 MW. Also, Alliant Corporation, on behalf of Wisconsin Power & Light Company, Interstate Power Company, IES Utilities, Inc. and South Beloit, Water, Gas and Electric Company, is seeking FERC approval to become a participant in MISO. Moreover, both the MidContinent Area Power Pool (i.e., MAPP) and Southwest Power Pool (i.e., SPP) recently signed a Memorandum of Understanding to consolidate functions with MISO making it more likely that the members of each organization would participate in the MISO. The addition of most MAPP and SPP members as MISO participants would increase the generation assets within MISO to well over 100,000 MW and cause the MISO region to encompass a large part of the Mid-Continent area of the United States.
On September 16, 1998, FERC conditionally approved the formation of MISO by authorizing the transfer of jurisdictional facilities from the Transmission Owners to MISO, and accepting the MISO Tariff and MISO Agreement for filing.[79] In its Order evaluating MISO under its eleven principles for ISOs and approving the formation of MISO, FERC stated:
The participating transmission owners (Transmission Owners) will transfer to the Midwest ISO functional control over all network transmission facilities above 100 kV and all network transformers whose two highest voltages exceed 100 kV (Transmission System). The Midwest ISO will be authorized to provide non-discriminatory open access transmission service over the Transmission System, to receive and distribute transmission revenues, and to be responsible for regional system security. The Transmission Owners will retain ownership of their transmission facilities, and will physically operate and maintain these facilities, subject to the Midwest ISOs direction. Under the Midwest ISO Agreement, the Transmission Owners who are currently control area operators will continue to operate their control areas for local generation control and economic dispatch purposes. However, the Transmission Owners will follow the directives of the ISO for redispatching generation, curtailing load, and providing reactive supply, voltage control or other ancillary services.[80]
The MISO Tariff will, as its name suggests, be administered by MISO. The MISO Tariff provides for transmission service using non-pancaked zonal rates for a six-year transition period ("Transition Period") after the commencement of operations. During the Transition Period, each control area will operate as a separate "zone" for determining transmission rates. Transmission customers will pay a single rate based on the zone in which the load is located. Transmission customers sending power through or exporting power from MISO will pay a single rate based on the average cost of transmission facilities of all Transmission Owners. Moreover, pricing for point-to-point transmission service from another control area into MISO ("drive-in" service) or service within MISO ("drive-within" service) will be based on the zonal rates described above. After the Transition Period, MISO will attempt to formulate a single, grid-wide rate for transmission service. [81]
The MISO Bylaws also include criteria for regional transmission planning decisions. The planning function is the responsibility of the MISO Planning Staff, which will engage in a collaborative process with owners, users and other interested parties such as state regulators. The Planning Staff is charged with developing cost-effective plans to resolve transmission constraints that would otherwise preclude requested transmission service and to create the MISO Plan by integrating, evaluating and modifying the transmission plans developed by each Transmission Owner. The ability to look at transmission upgrades over a larger region and to recommend "non-owner" solutions should provide a more efficient transmission planning process.
While MISO will have functional control over the Transmission System of the Transmission Owners, some generation control functions (such as scheduling, economic dispatch and load balancing) will continue to be performed by the existing control area operations within MISO. Nevertheless, MISO will have significant control over the generation of the Transmission Owners.[82] As stated by the Transmission Owners of MISO in their application to FERC, MISO will possess authority over generation to the extent "generation affects transmission." [83] In particular, MISO will solve transmission congestion through curtailments, generation redispatch and (as a last resort) load shedding. MISO will use redispatch to prevent the curtailment of scheduled firm and network transmission service and the costs of redispatch will be shared among all load including bundled native load on a pro rata basis rather than directly assigned to specific transmission customers.[84] MISO members that own generation will be required to offer redispatch service pursuant to cost-based rates on file with FERC, and MISO will select the least-cost option for redispatch. When requests for new firm service cannot be accommodated under current operating conditions, MISO will facilitate transmission capacity reassignment (by posting bids electronically on a real-time basis) and transmission capacity expansion by generation redispatch (by identifying generators that could relieve the constraint by increasing or decreasing their output). [85] When a system emergency arises, however, MISO will take whatever actions are necessary to maintain the reliability of the Transmission System, including curtailments. [86]
MISO also will develop all necessary operating procedures and have authority over the security coordinator functions of the Transmission Owners, such as approving transmission requests, implementing curtailment of transmission or requiring redispatch of generation with transmission. MISO's duties will include calculating available transmission capability and maintaining OASIS information. MISO will monitor real-time data to determine whether any control areas are experiencing generation capacity deficiencies. MISO also will control transmission maintenance. Integration of generation will occur at the MISO level through the methods outlined above and through coordinating the maintenance (outage schedules) of generating units to assure that they minimize the impact on transmission capability. Thus, entities participating in the MISO will interconnect and integrate their systems in a joint effort to promote regional deployment of certain operating functions, security and redispatch functions and scheduling functions so as to enhance efficiencies across this broad regional market.
In joining MISO, New NSP, NSP-W and SPS will transfer control of their respective transmission systems to MISO and become subject to the MISO Tariff and Bylaws. Thus, like the tight power pool arrangements that formed the basis for findings of integration by the Commission in UNITIL and Conectiv, the transmission facilities of these entities will be under common management and control along with those of other MISO members. In an environment where transmission and generation are unbundled, it is the Applicants' view that there is no greater integrating action than to turn over the operation and coordination functions of the merged company's key transmission assets to a single management entity. Transmission will be centrally coordinated so as to maximize transmission capacity. Further, transmission constraints will be alleviated through regional redispatch of generation so that the system can operate at maximum efficiency. Transmission upgrades will be planned on a regional basis to assure the most economic means of relieving constraints over the long-run are achieved. The greater the transmission capacity, the greater the ability the NSP companies and the NCE Operating Companies will have to obtain low cost sources of generation throughout the MISO region and to arrange for power transfers from one another. Finally, removal of rate pancaking throughout the MISO region will remove economic barriers in reaching more distant sources of generation supply. Thus, the efficiency of centralized transmission management and pricing will directly create greater purchasing efficiencies in obtaining power for Xcel's customers. [87]
The impact of joining MISO on Applicants' combined operations is best demonstrated by way of an example. Currently, NSP buys power from the market to meet its customers' energy needs. A key limiting factor in all purchases is the need to arrange for and the associated cost of transmission. It is common for NSP to arrange a purchase from the Cinergy hub, which is a liquid market that permits critical hedging against volatile price swings. However, because of transmission cost differentials, NSP typically finds nearby power more economical by the time delivery is expected. NSP then sells its position in Cinergy and buys from neighboring markets at a higher energy price but a lower overall price (energy plus pancaked transmission). Under MISO, NSP will be able to keep and to take delivery from Cinergy, as there will be no incremental transmission cost that makes it uneconomical. With SPS in the same RTO, the purchase could be made jointly and dispatched to the entity whose load requirements indicate a need for the energy. Again, there would be no transmission price differential, and the power could flow freely to either NSP or SPS. In this way, both operating companies achieve economies associated with access to low-cost power as well as efficiencies in the economic use of this power supply. Without common MISO membership, pancaked transmission rates would create differences in the ultimate purchase decision that would make such coordinated arrangements more difficult and less efficient. Moreover, MISO membership will permit the necessary transmission arrangements to be made with MISO as the sole transmission provider.
Accordingly, when the NSP companies and SPS become members of MISO, they will be able to transmit power between their two systems at nonpancaked rates - specifically, at an incremental cost which is the same per unit cost involved in shipping power within their respective systems. [88] Since all market participants in MISO can similarly move power at no additional cost of transport, the MISO Tariff makes choice of power supply across a broad region economically feasible for the Applicants. As this occurs, Applicants' integration of generation will be efficiently accomplished in the marketplace, through the ability to access potentially 100,000 MW of generating capacity rather than merely seeking opportunities to exchange power with one another. When the NSP companies and SPS believe such opportunities exist, they will successfully lower their total energy costs to customers through their joint participation in energy markets. Moreover, the establishment of a Midwest power exchange ("Midwest PX"), that would complement the operation of the MISO, is currently being evaluated. If the Midwest PX is established, generation would be sold into the power exchange and purchased from the exchange, with the ISO providing the regional scope for this trading activity. The movement from cost-based power pools (like those that existed in UNITIL and Conectiv) to power exchanges, which will have a large number of participants, are expected to facilitate lower costs to consumers.
As referenced in Applicants' FERC application and the FERC Merger Order,[89] upon joining MISO, Xcel's northern zone, consisting of New NSP and NSP-W, will be physically interconnected with its southern zone, consisting of SPS, through the MISO transmission system, [90] and, if necessary, a firm transmission contract path between SPS and Ameren (a MISO member). Thus, the operation of transmission assets, the transmission planning process and the generation assets of all three of these Xcel operating companies will be subject to the regional management of a single transmission organization.
As noted above, Applicants anticipate that MISO will have attracted additional members by the time it becomes fully operational, which will permit SPS to be directly interconnected with MISO through intervening utilities. For example, if SPP becomes part of MISO as planned, there would be a contiguous MISO transmission region between SPS and NSP. However, in the event that SPS does not become directly interconnected with another MISO member, SPS intends to obtain a firm, 200 MW bi-directional transmission path from the point at which its system interconnects with PSO to the point at which PSO interconnects with Ameren and MISO. This path is referred to herein as the "MISO Interconnection." [91] SPS has requested this path from the SPP under its open-access transmission tariff. In November 1999, SPS executed a contract with SPP for the south-to-north portion, and facilities studies are underway for the north-to-south portion.
Absent anticipated changes that result in a direct interconnection between SPS and another MISO member, Applicants will implement their plans and agreements already executed for the MISO Interconnection. In the event that Applicants need to establish the MISO Interconnection, they will attempt to enter into arrangements with PSO or the SPP to facilitate third-party use. Specifically, they will attempt to make arrangements so that the interconnection path will be treated as part of SPS's system, and therefore subject to MISO's control. Transmission customers would then be able to arrange service over the path through MISO.
The Contract Path
For at least three years following consummation of the Merger, NCE and NSP will interconnect their systems through a firm contract for a 100 MW unidirectional path from SPS to NSP (through SPP and Ameren), to flow 100 MW from a point of receipt located at SPS's Tolk generating station to a point of delivery at NSP-M's Sherbourne County generation station (the "Northbound Path").
Certain of the same upgrades required with respect to the MISO Interconnection would be required with respect to the Northbound Path. The upgrades will be made by SPP pursuant to transmission requests submitted to it by SPS.
The Applicants initially proposed that the Northbound Path be a 200 MW firm path, as compared to 100 MW firm path, as 200 MW could be physically moved between the two systems on a firm basis and would result in additional savings. However, preliminary analysis of this scenario indicated that the loss in available capacity in the NSP destination market was likely significant enough to cause a potential screen failure under FERC's guidelines related to market power, which could have resulted in NSP being required to divest a portion of its generation assets. Because NSP is currently acquiring additional generation resources, divestiture would be inconsistent with its growing need for energy and capacity to serve its customers. Thus, the Applicants chose to have the Northbound Path be a 100 MW firm path from SPS to NSP, which does not result in the same concern. [92] The 100 MW Northbound Path will serve to reduce the operating costs by allowing for firm power transfers from SPS to NSP, creating projected savings of $24 million over the next ten years. NSP has entered into an agreement with Ameren for part of the path (from Ameren to NSP), and SPS is in the process of completing the southern portion through the SPP, where facilities studies have recently been completed, and execution of the service agreement is near. SPS's merchant function has also reserved the necessary capacity for the transaction from the SPS transmission business.
The Joint Operating Agreement
The Joint Operating Agreement will integrate the generating resources of NSP, NSP-W, PSCo and SPS (individually, an "Operating Company" and collectively, the "Operating Companies"). More specifically, the Joint Operating Agreement sets out the framework for the coordinated planning, operations, and maintenance of generation resources (both owned and purchased), and coordinated wholesale marketing activities of the Operating Companies.[93] It also provides for the allocation of associated costs and benefits.
An Operating Committee will have overall responsibility for administering the Joint Operating Agreement. The Operating Committee will be comprised of a representative of each of the Operating Companies and New Century Services, which will act as the agent for the Operating Companies.
In accordance with the terms of the Joint Operating Agreement, New Century Services will undertake a number of activities involving the coordination of the generating resources of the Operating Companies, including the following:
(a) evaluating and making recommendations concerning additions of generating facilities or capacity to be owned by, or under long-term contract, to an Operating Company ("Generation Resources") in order to meet the load requirements of the Operating Companies;
(b) coordinating the planning and design of Generating Resources to be installed or acquired by the Operating Companies;
(c) coordinating the operation and maintenance of Operating Companies Generating Resources;
(d) coordinating the economic dispatch of Generating Resources for the Operating Companies;
(e) conducting system purchases and sales and off-system marketing on behalf of the Operating Companies;
(f) developing all bills and billing information among the Operating Companies under the Joint Operating Agreement;
(g) acquiring and coordinate the provision of transmission and ancillary services from affiliated and non-affiliate transmission providers for use with respect to transactions by or among Operating Companies;
(h) operating and maintain a central generating control center to achieve these purposes, and such additional generation control centers as the Operating Companies may require; and
(i) reassigning transmission services obtained for wholesale merchant purposes on behalf of any Operating Company.
Section 7.2 of the Joint Operating Agreement provides for the coordinated operation of each of the Operating Companies' resources. While preserving the pre-Merger dispatch priorities applicable to each company's resources to allay any possible state regulatory concern regarding cost-shifts among the Operating Companies, this section further provides that "the Control Areas will be dispatched on a coordinated basis in real time to minimize total generation costs for the Operating Companies, subject to the availability of Firm Transmission Entitlements or other transmission arrangements linking the Operating Companies' Control Areas or other transmission services."
The Joint Operating Agreement also contains service schedules providing for actual power transactions among the Operating Companies or by the Operating Companies acting jointly with non-affiliated third parties. Specifically, Service Schedule A provides for the sale of capacity and associated energy sales by one Operating Company to another. Service Schedule B provides for energy-only sales by one Operating Company to another. Service Schedule C provides for system sales and purchases, and off-system marketing (i.e., not involving the generating resources of the Operating Companies) with non-affiliated third parties. Service Schedule D provides for the allocation of costs and revenues associated with any firm transmission paths that the Operating Companies may obtain to link their systems.
Applicants submitted the Joint Operating Agreement to FERC concurrently with their application to merge. FERC in the FERC Merger Order accepted the Joint Operating Agreement for filing without modification, only conditional on the consummation of the Merger. FERC has jurisdiction over the actual power transactions set out in the Joint Operating Agreement. The costs for various non-power transaction activities (e.g., for joint planning) will likely be incurred at the service company level and allocated in accordance with the SEC-jurisdictional service agreements.
* * * * *
As previously discussed, joint membership and participation in MISO is one of the primary means by which NCE and NSP will integrate their system operations. As MISO moves to eliminate utility-specific cost disparities through a large regional trading market, an economically efficient electric supply will be available to any market participant. This elimination of traditional cost-based prices will allow the benefits of integration to occur through the market and contractual arrangements, rather than through the ownership of facilities and joint dispatch of operations. NSP and NCE intend to integrate operations in the most economic manner possible, consistent with state and FERC regulatory requirements, to take full advantage of the opportunities available to produce power at a lower cost for the benefit of its customers and shareholders.
The foregoing discussion was intended to provide background and overview of how NSP and NCE will be integrated through MISO, through a contract path and through the Joint Operating Agreement. Each of the four integration standards of Section 2(a)(29)(A) is discussed specifically below.
(a) Interconnection
The first requirement for an integrated electric utility system is that the electric generation and/or transmission and/or distribution facilities comprising the system be "physically interconnected or capable of physical interconnection." Historically, the Commission has focused on physical interconnection through facilities that the parties owned or, by contract, controlled.[94] As early as 1978, however, the Commission indicated that joint participation in a power pool could be the basis for a finding of integration.[95] To date, the Commission has found interconnection through memberships in "tight" power pools and ISOs. [96] These findings are consistent with the recommendation of the 1995 Study that the Commission "adopt a more flexible interpretation of the geographic and physical integration standards, with more emphasis on whether an acquisition will be economical and subject to effective regulation."
The 1995 Report further recommended that the Commission should increasingly rely on an acquisition's demonstrated economies and efficiencies, rather than upon physical interconnection, to meet the integration standard. The Report noted that the 1935 Act provides the necessary flexibility and that the application of the integration standards must be able to adjust in response to changes in the state of the art. The Report concluded that it would be a logical extension of prior orders for the Commission to find that wheeling and other forms of sharing power (such as reliability councils and proposed regional transmission groups) also qualify as interconnection. This recommendation is particularly significant in view of the recent RTO Order, which will cause the development of regional transmission grids that will bring even more distant utilities closer together.
As explained above, the NSP Electric System and the Primary System of NCE will be "physically interconnected or capable of physical interconnection" through membership in MISO and by means of the Northbound Path.
The Northbound Path, in and of itself, satisfies the physical interconnection requirement of Section 2(a)(29)(A). The Commission in the past "has reasonably construed this requirement to be satisfied in cases... 'on the basis of contractual rights to use a third-party's transmission lines. . .'"" Madison Gas and Electric Company v SEC, supra at 1340. See also Centerior, supra (The physical interconnection requirements of [Section 2(a)(29)(A)] are met if the two service areas are connected by power transmission lines that the companies have the right to use whenever needed."). Dicta in a series of Commission decisions states that contract rights cannot be relied on to integrate two "distant" systems. See, e.g., WPL Holdings, Inc., Holding Co. Act Release No. 26856 (April 14, 1998), citing UNITIL Corp., supra; Northeast Utilities, Holding Co. Act Release No. 25273 (March 15, 1991); Centerior Energy Corp., supra. In the Applicants' view, it would be incorrect to interpret these statements to mean that a firm contract path might not meet the "physical interconnection" requirement because of its length. In both UNITIL and Northeast Utilities, the Commission explained that the reason a contract path might not "integrate" two distant utilities was due to the "single area or region" requirement of Section 2(a) (29)(A). UNITIL, supra at n.30; Northeast Utilities, supra at n.75. The Commission did not hold in any of these cases that the length of a firm contract path was relevant in determining whether the "physically interconnected or capable of physical interconnection" requirement of Section 2(a)(29)(A) was met. Such a holding would be contrary to the literal language of Section 2(a)(29)(A), and would ignore both the technological and commercial developments in the industry that have occurred since the enactment of the Act.
NSP and NCE also will be "physically interconnected or capable of physical interconnection" through their common membership in MISO. Commission precedent supports a finding of interconnection through an ISO such as MISO.[97] In 1992, the Commission approved the merger of UNITIL Corporation with Fitchburg Gas and Electric Light Company, based on their common membership in NEPOOL,[98] a regional power pool that was the basis for a FERC approved ISO and associated power exchange. [99] UNITIL and Fitchburg were not connected through transmission lines that they owned. Rather, as the Commission noted in its order:
Access to and use of the regional transmission network, which is owned by the larger New England utilities, is provided by the NEPOOL Agreement and by transmission rate schedules and contracts filed with the Federal Energy Regulatory Commission.
In this matter, the Companies are indirectly interconnected through NEPOOL-designated transmission facilities ("PTF") and other nonaffiliate transmission facilities pursuant to the NEPOOL Agreement and other separate agreements with nonaffiliate companies. The Commission has previously found a system to be "capable of physical interconnection" on the basis of contractual rights to use a third-party's transmission lines.
This matter differs from prior orders in that there will be no particular line through which transfers of power will be made among the Companies. Instead, power will be delivered through a nonaffiliate system and a transmission charge will be paid to the owner of the facilities. On the facts of this matter, the Commission is satisfied that the Companies' contractual arrangements for transmission service establish that the UNITIL electric system will satisfy the physical interconnection requirement of the Act.
With respect to the "other separate agreements with nonaffiliate companies" described above, the Commission by footnote explained that Fitchburg obtained primary transmission service from New England Power Company ("NEPCO") under the NEPOOL Agreement and through NEPCO's FERC Tariff Number 3, which provided for non-firm service. The Commission went on to note that Fitchburg was eligible to use NEPCO's FERC Tariff No. 4[100] should Fitchburg and UNITIL Power conduct more power sales or swaps. In 1998, based on UNITIL, the Commission found that Delmarva Power & Light Company and Atlantic Energy, Inc. met the physical interconnection requirements of Section 2(a)(29)(A) through their common membership in PJM Interconnection, LLC ("PJM"), which was a regional power pool and the first FERC-approved, operational ISO. [101] Conectiv, Inc., Holding Co. Act Release No. 26832 (February 25, 1998).
The facts of this case similarly establish physical interconnection under the UNITIL precedent and its progeny. Access by NSP and SPS to the regional transmission network of MISO will be provided by the MISO Agreement and MISO Tariff, which have been filed with FERC. Also, like UNITIL Power and Fitchburg, NSP and SPS will have "other separate agreements with nonaffiliate companies" - namely; the firm Northbound Path for 100 MW, and the nonfirm arrangements that Applicants may arrange as described below under "Coordination." In particular, MAPP has an open-access transmission tariff, Schedule F, that may provide an alternative path for transactions between SPS and the NSP companies. Moreover, in the present case and like UNITIL, "power will be delivered through a nonaffiliate system" (i.e., MISO) and "a transmission charge will be paid to the owner of the facilities". As noted above, MISO will have functional control over the transmission systems of NSP, NSP-W, SPS and other members of the MISO. As was the case in UNITIL, the NSP companies and SPS will be able to readily obtain transmission services at non-pancaked rates to exchange energy with each other or to access the market collectively as either a buyer or a seller. For these reasons, Applicants believe that the Xcel Electric System will be "physically interconnected or capable of physical interconnection."
As shown by Exhibit E-13, the powers and responsibilities of MISO over the transmission assets of members of MISO will be virtually identical to those today of NEPOOL and PJM over the transmission assets of their respective members. Applicants note that MISO differs from NEPOOL in UNITIL and from PJM in Conectiv in that NEPOOL and PJM were both "tight" power pools at the time of the Commission's decisions, in that the generation assets of all members of NEPOOL and PJM were centrally dispatched and controlled. Applicants acknowledge the relevance of generation control for purposes of evaluating whether the system is operated as "a single interconnected and coordinated system" under Section 2(a)(29)(A), but do not believe it is relevant as to whether the system is "physically interconnected or capable of physical interconnection."[102]
(b) Coordination
Historically, the Commission has interpreted the requirement that an integrated electric system be economically operated under normal conditions as a single interconnected and coordinated system, "to refer to the physical operation of utility assets as a system in which, among other things, the generation and/or flow of current within the system may be centrally controlled and allocated as need or economy directs." See, e.g., Conectiv, supra, citing The North American Company, Holding Co. Act Release No. 3466 (April 14, 1942), aff'd, 133 F.2d 148 (2d Cir. 1943), aff'd on constitutional issues, 327 U.S. 686 (1946). The Commission has noted that, through this standard, Congress "intended that the utility properties be so connected and operated that there is coordination among all parts, and that those parts bear an integral operating relationship to one another." Id., (citations omitted). Applicants submit that the coordination requirement is satisfied through such measures as coordinated generation operations; coordinated transmission through common participation and membership in an ISO; coordinated marketing efforts, both as a buyer and seller of electricity; the integration of administrative and general services and programs; and gas/electric convergence type measures, which will lead to lower costs for gas as a fuel for the generation of electricity.
This is not a matter of first impression. Nearly a decade ago, the Commission found, and the courts agreed, that the coordination requirement could be satisfied even if power never flowed between two parts of the system. Environmental Action, Inc. v. SEC, 895 F.2d 1255 (9th Cir. 1990). Environmental Action involved the acquisition by a holding company of an interest in an electric generating plant ("GenCo"). The intervenors argued that the acquisition did not satisfy the standards of the 1935 Act because, among other things, the system's existing electric utility company ("UtilCo") had represented that it might purchase up to twenty percent of GenCo's capacity if, and only if, the price of such power was competitive in the market. The Court of Appeals noted that the GenCo might not purchase any of GenCo's output but, nonetheless, concluded that the Commission had correctly found that UtilCo and GenCo could be operated as part of a coordinated system, within the meaning of the Act. Id. at 1264-65, citing Electric Energy, Inc., Holding Co. Act Release No., 13871 (Nov. 28, 1958) (the companies sponsoring the construction of a generating plant only pledged to buy any surplus energy remaining after the plant had supplied the needs of the major purchaser, a nonaffiliated government agency). More recently, the Commission found similar types of coordinated operational and administrative functions to constitute "de facto" integration. Sierra Pacific Resources , Holding Co. Act Release No. 27054 (1999). Moreover, the coordination of administrative functions and joint marketing activities were crucial factors in the Commission's determination that the coordination requirement was satisfied in Sempra and NIPSCO.
Moreover, in applying the integration standard, the Commission looks beyond simply the coordination of the generation and transmission within a system to the coordination of other activities. See, e.g., General Public Utilities Corp., Holding Co. Act Release No. 13116 (Mar. 2, 1956) (integration is accomplished through power dispatching by a central load dispatcher as well as through coordination of maintenance and construction requirements); Middle South Utilities, Inc., Holding Co. Act Release No. 11782 (Mar. 20, 1953), petition to reopen denied , Holding Co. Act Release No. 12978 (Sept. 13, 1955), rev'd sub nom. Louisiana Public Service Comm'n v. SEC, 235 F.2d 167 (5th Cir. 1956), rev'd, 353 U.S. 368 (1957), reh'g denied, 354 U.S. 928 (1957) (integration is accomplished through an operating committee which coordinates not only the scheduling of generation and system dispatch, but also makes and keeps records and necessary reports, coordinates construction programs and provides for all other interrelated operations involved in the coordination of generation and transmission); North American Company, Holding Co. Act Release No. 10320 (Dec. 28, 1950) (economic integration is demonstrated by the exchange of power, the coordination of future power demand, the sharing of extensive experience with regard to engineering and other operating problems, and the furnishing of financial aid to the company being acquired). See also NIPSCO, supra (functional merger of Bay States and NIPSCO gas supply department through NIPSCO Services, "a service company subsidiary of NIPSCO that provides financial, accounting, tax, purchasing, natural gas portfolio management, and other administrative services to associate companies.")
Applicants will satisfy the coordination requirement in several ways.
First, as has already been discussed in great detail, the transmission systems of the NSP companies and SPS will be operated as a single interconnected and coordinated system through joint membership and participation in MISO. Among other things, MISO will develop all operating procedures and schedules, approve all transmission requests and direct the operation of the transmission grid for all MISO participants. MISO also will control maintenance and planning of all of the transmission facilities within the MISO system. This degree of coordination and integration of transmission assets is comparable to that presented to, and accepted by, the Commission in UNITIL and Conectiv, supra. [103] Moreover, the availability of transmission under MISO will provide the means to coordinate operations and engage in the joint marketing efforts that are described below.
Second, in light of the developments that have occurred in the electric utility industry and the regulatory framework that applies to it, which have been detailed above, the coordination of utilities can occur through the market and contractual arrangements. The Joint Operating Agreement will provide the contractual operating framework for the Xcel Operating Companies to coordinate and transact with each other.
Under the agreement, the generating systems of the Xcel Electric System will be operated as a single interconnected and coordinated system. Specifically, New Century Services, as agent for the Operating Companies, will coordinate the planning, operation and maintenance of generating capacity resources and the dispatch of electricity throughout the combined system of NSP and NCE. This will be accomplished through a central generation control center that, through a common software system, will direct the dispatch of the entire Xcel Electric System. Under this arrangement, the system dispatcher will dispatch the generation units of the Xcel Operating Companies and those plants under long-term contract to which the companies effectively dispatch generation, as needed to meet native load and will arrange for economy energy sales (provided for in Schedule B of the Joint Operating Agreement) between Operating Companies where such sales will lower the operating costs of the purchasing Operating Company. To allay any concerns that state commissions and FERC may have, such intra-system sales will not be made if the purchasing Operating Company has a better purchase opportunity, or the selling Operating Company has a better sales opportunity. Schedule A of the Joint Operating Agreement likewise provides for short-term capacity and associated energy sales between Xcel Operating Companies, subject to the same limitations. The Joint Operating Agreement also provides for joint generation planning and the common procurement of resources, although again the agreement addresses potential state concerns by making explicit that any resource additions will comply with applicable state procurement requirements. Additionally, the Joint Operating Agreement also vests the agent, New Century Services, with the responsibility of arranging joint sales and purchases of electricity, as described below, and makes provision for the allocation of associated costs and revenues. [104]The Joint Operating Agreement, with its protections, also will benefit customers as more and more power is purchased from the market. Currently, both NSP and PSCo are capacity short and will have opportunities to coordinate contracting of purchases to meet the energy needs of their customers. The Joint Operating Agreement will allow joint procurement to take advantage of weather and economic diversity as well as scheduling of plant outages.
Third, the Xcel Operating Companies will coordinate through joint marketing efforts, both as a buyer and seller. System dispatchers will continually monitor the generation needs and capacity of the NSP and NCE systems. This will include the NSP companies, SPS and PSCo. The Xcel Operating Companies already have the ability to reach common suppliers, purchasers, and trading hubs in various combinations. The rapidly evolving wholesale power markets surrounding the energy industry will allow NSP and NCE to operate their generation assets as a single system by buying and selling power to decrease the overall production costs of the two systems. The diversity of weather, time, fuel supply and localized economic conditions will create opportunities to allocate resources more efficiently. This can be accomplished without the need to actually move power from the NSP system or NCE system to the other company's system. Power can be delivered to and from the systems by third parties using their transmission systems. These marketing efforts will be greatly facilitated by the common participation of the NSP companies and SPS in MISO. For example, NSP and NCE will be able to use their diversity to buy and sell in common MISO markets such as Ameren to optimize their use of this market, acting, in effect, like their own trading hub. The 100 MW Northbound Path will further facilitate the ability of the entities to coordinate their systems by assuring the ability to move power even when there are transmission constraints.
MISO, however, is not the only means for NSP and NCE to engage in these efforts: the NSP companies, SPS and PSCo presently trade in other common markets, which can be accessed post-merger. For example, the NSP companies and NCE Operating Companies both hold capacity contracts with Basin Electric Cooperative. In 1998, NCE purchased 200MW of capacity from the Laramie River Station. PSCo recently added an additional 136 MW. NSP contracted for 65 MW of seasonal capacity from Basin as well as entering into an ongoing energy only agreement which allows NSP to purchase system energy from Basin. Because Laramie River Station is located at the intersection of the Eastern and Western Interconnections, it is equipped to sell power in both directions. In the future, joint purchases could be made and dispatched to the operating companies that would provide the greater benefit. Weather diversity would make these purchases more economically efficient as changes in daily and hourly load forecasts can be accommodated by joint purchasing and coordinated dispatch. In addition to Basin, both PSCo and NSP have made significant purchases from WAPA in the past. In 1997, NSP purchased 252,332 MWh from WAPA. During this same time period, the NCE Operating Companies purchased 559,121 MWh from WAPA. Given WAPA's location on the border of the Eastern and Western Interconnects, it will serve as a market for coordinated trading activities. This ability to diversify supply over a broader region with diverse weather and time zones is how companies can best achieve the benefits of economic integration in a market-based commodity like electricity. The NSP companies and NCE Operating Companies also anticipate making use of the burgeoning power markets and their associated volatility to maximize efficiency and coordination on their systems.
Again, the Joint Operating Agreement provides the framework for these types of activities. Pursuant to Schedule C (System Sales and Purchases, and Off-System Marketing), New Century Services as the Agent will have responsibility to engage in wholesale sales and purchases on behalf of the Xcel Operating Companies on an individual company and collective basis. The coordination of these activities under the Joint Operating Agreement is expected to result in savings for the Xcel Operating Companies and their customers.[105]
Fourth, the generation assets of NSP and SPS (or the SPS generating company formed in compliance with Texas and New Mexico restructuring legislation) also will be coordinated through MISO. As discussed previously, MISO will possess authority over generation to the extent "generation affects transmission." In particular, MISO will solve transmission congestion through load shedding, curtailments and generation redispatch. MISO will use redispatch to prevent the curtailment of scheduled firm and network transmission. [106] MISO members which own generation will be required to offer redispatch service pursuant to cost-based rates on file with FERC, and MISO will select the least-cost option for redispatch. When requests for new firm service cannot be accommodated absent mitigation, MISO will facilitate transmission capacity reassignment (by posting bids electronically on a real-time basis) and generation redispatch (by identifying generators that could relieve the constraint by increasing or decreasing their output). [107] When a system emergency arises, however, MISO will take whatever actions are necessary to maintain the reliability of the transmission system including load shedding or curtailments.[108] Integration of generation also will occur at the MISO level through coordinating maintenance (outage schedules) of generating units of the transmission owners to assure that they minimize the impact on transmission capability. Thus, the generating assets of NSP and SPS will be coordinated and integrated by MISO as needed to facilitate transmission access by the members of MISO.
Fifth, as explained further below, the Xcel Operating Companies will be able to achieve efficiencies in the management of their natural gas portfolios. Because PSCo, SPS, and NSP use natural gas to generate electricity, these efficiencies are expected to translate to lower cost for gas as a fuel for electric production, which will benefit electric customers.
Sixth, the combined system in this matter will be coordinated in a variety of ways beyond simply the coordination of the generation and transmission within the system. Among other things, virtually all administrative and general services will be performed for the Xcel System by New Century Services. In addition, the accounting functions of the combined system will be prepared and consolidated through the use of a single system. Xcel will have a single accounting organization which will be managed by a single team in one or more locations. The coordination and integration of the combined system is expected to be further achieved through the coordination and integration of information system networks; customer service; procurement organizations; organizational structures for power generation, energy delivery and customer relations; and support services.
As indicated by the language under Section 2(a)(29)(A) that the coordinated system be "economically operated," the Commission further analyzes whether the coordinated operation of the system results in economies and efficiencies. The question whether a combined system will be economically operated under Section 10(c)(2) and Section 2(a)(29)(A) was recently addressed by the Court of Appeals in Madison Gas and Electric Company v. SEC, 168 F.3d 1337 (D.C. Cir. 1999). In that case, the court determined that in analyzing whether a system will be economically coordinated, the focus must be on whether the acquisition "as a whole" will "tend toward efficiency and economy." Id. at 1341. The Merger will clearly meet this standard. As explained in Item 3.C.2. below, NSP and NCE estimate that the net savings from the Merger will exceed $1.1 billion over 10 years.
In short, all aspects of the combined system will be centrally and efficiently planned and operated. As with other merger applications approved by the Commission, the combined system will be capable of being economically operated as a single interconnected and coordinated system as demonstrated by the variety of means through which its operations will be coordinated and the efficiencies and economies expected to be realized by the proposed transaction.
As required by Section 2(a)(29)(A), the operations of the Xcel Electric System will be confined to a "single area or region in one or more States." While the terms "area" and "region" are not defined in the 1935 Act, the "single area or region" requirement does not mandate that a system's operations be confined to a small geographic area or a single state. [109] The Commission has specifically found that the combining systems need not be contiguous in order for the requirement to be met.[110] Rather, the Commission has found that the single area or region test should be applied flexibly when doing so does not undercut the policies of the 1935 Act against ""scatteration" -- [that is,] the ownership of widely dispersed utility properties which do not lend themselves to efficient operation and effective state regulation." NIPSCO, supra (applying single area or region requirement with respect to gas utility system); accord, Sempra, supra. [111]
Moreover, the Staff has recommended that the Commission "interpret the "single area or region" requirement flexibly, recognizing technological advances, consistent with the purposes and provisions of the Act" and that the Commission place "more emphasis on whether an acquisition will be economical." 1995 Report at 66, 69. The Staff has recognized that "recent institutional, legal and technological changes . . . have reduced the relative importance of . . . geographical limitations by permitting greater control, coordination and efficiencies" and "have expanded the means for achieving the interconnection and economic operation and coordination of utilities with non-contiguous service territories." 1995 Report at 69. It has also recognized that the concept of "geographic integration" has been affected by "technological advances on the ability to transmit electric energy economically over longer distances, and other developments in the industry, such as brokers and marketers." Id. Such advances and developments are breaking down traditional boundaries and concepts of regions. The Commission has confirmed its support for the Staff's Report, citing, in particular, the Staff's recommendation that the Commission "continue to interpret the "single area or region" requirement of [the 1935 Act] to take into account technological advances." NIPSCO, supra; accord, Sempra, supra.
The Applicants believe that the Xcel Electric system will satisfy "single area or region" requirement. The Xcel Operating Companies all have their electric operations in the Mid-Continent area of the United States in states that adjoin - Michigan, Wisconsin, Minnesota, North Dakota, South Dakota, Wyoming, Colorado, New Mexico, Texas, Oklahoma and Kansas. Three of the primary Xcel Operating Companies (SPS, NSP and New NSP) will be part of MISO, which will be tasked with operating the regional grid, and the other primary system, PSCo, will be directly interconnected upon completion of NCE's commitments in the 1997 NCE Order. An RTO, such as MISO, effectively defines a region from both an operational and economic standpoint. To reiterate, FERC is promoting RTOs due to operational and economic inefficiencies that presently exist. Generally, from an operational perspective, RTOs will place transmission services in a larger regional market, which is necessary to achieve short-term and long-term reliability, including the authority to direct transmission maintenance schedules and to redispatch generation to ensure the integrity and operation efficiency of the electric grid. The RTO will also ensure proper evaluation of ATC, proper transmission congestion management and proper management of loop flows. By virtue of common membership in MISO, the electric operations of the NSP companies and SPS will be part of the same region.
Likewise, RTOs create an economic region due to the pancaking of transmission rates and the burden to transmission customers of having to arrange service from multiple providers that would otherwise exist. The result is that RTOs will likely become the primary trading region for RTO members. FERC has recognized the key of RTOs in establishing a trading region among utilities:
The Commission has long recognized that transmission pricing reform is most effectively accomplished on a regional basis. An RTO would have the geographic scope needed to eliminate pancaked transmission rates within its region. This would broaden the generation market. . . thereby fostering more competitive markets and lower prices.[112]
MISO is organized to be extremely effective in achieving this objective. Quite simply, joint membership in MISO makes all of its members, at the most, one-wheel away.[113] That is, the elimination of pancaked transmission rates throughout the MISO region will create a broad wholesale market readily accessible to all members.
Thus, through a common RTO, the NSP companies and SPS will be in the same operational and economic region. These regions created by RTOs are larger than those in the electrical regions of the past for a variety of reasons. First, as previously discussed the technological advances and additions to the transmission network that have occurred since 1935 now permit trading to occur over 1000 mile distances. Second, as explained in detail previously, a large region is necessary to address the inefficiencies and inequities that FERC is seeking to remedy through RTOs.
Moreover, although PSCo will not be in the same RTO as SPS and the NSP companies, it nonetheless should be considered to be in the same economic region, in light of the historic pattern of trading with Basin Cooperative and WAPA as described above. Upon the completion of Phase II of the tie line, trades into MAPP by PSCo will be further facilitated, and, more importantly, because the interconnection will place PSCo on the border of MISO, PSCo will be able to directly access the MISO region, including NSP, at non-pancaked rates.
The conclusion that the Xcel Electric System will constitute a single area or region is further supported by the logic of the Commission's definition of "region" used for purposes of its size analysis under Section 10(b)(1). In Entergy, supra, the Commission adopted the applicants' definition of the relevant region for purposes of Section 10(b)(1) to include themselves and those electric utilities directly interconnected with either or both, which, at the time, were their most accessible markets. This region consisting of utilities within "one-wheel" of the merging utilities made sense in light of the barrier that rate pancaking presented in trying to access more distant markets. In today's increasingly competitive world, NSP and NCE do not operate as isolated companies, and their geographic region should be analyzed in terms of their most accessible market, which will be MISO. With the elimination of rate pancaking and with central control of their transmission assets in MISO, the Xcel Electric system will primarily compete within and access the MISO market and will be within "one wheel" of each other under the MISO Tariff. At the time PSCo interconnects its system with SPS, it will be one-wheel away from both SPS and NSP thereby satisfying the test set forth in Entergy.
The Commission's recent decision in Sempra Energy is also relevant for a commodity business such as the evolving electricity industry. In that decision, the SEC approved Sempra's acquisition of a 90 percent interest in Frontier Energy LLC of North Carolina and considered the combined system to be an integrated system under the Act. [114] In that decision the SEC affirmed the existence of a national natural gas commodity market. The SEC pointed out that, when the Act was drafted in the 1930s, the common source requirement meant the same source at the city gate. Now, however, with the changing gas market, it means obtaining gas from the same supply basins. Thus, even though the two systems in Sempra were 3,000 miles apart, the SEC said that its decision did not undercut the Act because the acquisition did not raise the concerns that prompted its enactment.
The logic of this decision is directly applicable to electric mergers because the electric industry is in rapid transition to becoming both a commodity market and an extended retail consumer services industry. As demonstrated above, there are numerous instances where NCE and NSP purchase and sell commodity energy in the same market. These instances will increase with continued growth in wholesale electric power market competition. In Sempra, the SEC concluded that because Sempra and the North Carolina distribution company it was acquiring purchased some natural gas from the same supply basin, they were integrated utilities for Section 11 purposes under the Act. Extending the logic of Sempra to the evolving electricity markets, the systems of NSP and NCE are in a "single area or region" because they purchase and sell energy into the same regional and national commodity markets.
Moreover, although the physical distance between the NSP companies and the NCE Operating Companies are greater than the Commission has approved in the past, Applicants do not believe that they contravene the policy of the Act against "scatteration" - the ownership of widely dispersed utility properties that do not lend themselves to efficient operation. As stated in Sempra, supra, "The Act is directed against the growth and extension of holding companies [that] bear no relation to economy of management and operation or the integration and coordination of related operating properties". As demonstrated above, the Primary System of NCE and the electric operations of NSP and NSP-W will be economically operated as a single interconnected and coordinated system. As demonstrated below, the combined system will not have a adverse effect upon localized management, efficient operation or effective regulation.
Finally, Applicants retained the Pacific Economics Group to determine whether the service territories of NSP and NCE constitute a single region under traditional economic theories. The report of the Pacific Economies Group, filed as EXHIBIT K-1, demonstrates that the companies operate in a single, unified economic region. Pacific Economics Group used a gravity model to demonstrate a high degree of economic interaction in the region including NSP and NCE's service territories. Finally, Pacific Economics further found that the geographic Elzinga-Hogarty market analysis underscores this result, clearly identifying that the companies operate within a distinct economic region. For all of these reasons, the Applicants believe that the Xcel Electric System will be confined to a single area or region, within the meaning of the Act. [115]
(d) Size
The final clause of Section 2(a)(29)(A) requires the Commission to look to the size of the combined system (considering the state of the art and the area or region affected) and its effect upon localized management, efficient operation and the effectiveness of regulation. In the instant matter, these standards are easily met. The size of the Xcel Electric System will not impair the advantages of localized management, efficient operation or the effectiveness of regulation. Instead, the Merger will actually increase the efficiency of operations.
Localized Management -- The Commission has found that an acquisition does not impair the advantages of localized management where the new holding company's "management [would be] drawn from the present management" (Centerior, supra), or where the acquired company's management would remain substantially intact (AEP, supra). The Commission has noted that the distance of corporate headquarters from local management was a "less important factor in determining what is in the public interest" given the "present-day ease of communication and transportation." AEP, supra. The Commission also evaluates localized management in terms of whether a merged system will be "responsive to local needs." AEP, supra.
The management of Xcel will be drawn primarily from the existing management of NSP and NCE and their subsidiaries. NSP will continue to maintain its corporate headquarters in Minneapolis and will maintain the management structure of its combined subsidiary companies (including the electric operating and other subsidiary companies of NCE) essentially intact. The electric utility subsidiaries will continue to operate through the regional offices with local service personnel and line crews available to respond to customers needs. Xcel will preserve the well-established delegations of authority -- currently in place at NSP and NCE -- which permit the local, district and regional management teams to budget for, operate and maintain the electric distribution system, to procure materials and supplies and to schedule work forces in order to continue to provide the high quality of service which the customers of NSP and NCE have enjoyed in the past. In short, the management structures of NSP and NCE, which are responsive to local needs, will be left essentially intact after the Merger. Accordingly, the advantages of localized management will not be impaired.
Efficient Operation -- As discussed above in the analysis of Section 10(b)(1), the size of Xcel will not impede efficient operation; rather, the Merger will result in significant economies and efficiencies as described in Item 3.C.2 below. Operations (as described in Item 1.E.) are more efficiently performed on a centralized basis because of economies of scale, standardized operating and maintenance practices and closer coordination of system-wide matters.
Effective Regulation -- The Merger will not impair the effectiveness of regulation at either the state or federal level. The utility subsidiaries of NCE will continue to be regulated by the state commissions of Colorado, Texas, Wyoming, Oklahoma, New Mexico and Kansas with respect to retail rates, service and related matters. The electric utility subsidiaries of NSP will continue to be regulated by the state commissions of Minnesota, North Dakota, South Dakota, Michigan and Wisconsin with respect to retail rates, service and related matters.[116] On the federal level, Xcel will be fully regulated as a registered holding company. The electric utility subsidiaries of Xcel will continue to be regulated by FERC with respect to interstate electric sales for resale, transmission services and other matters, by the NRC with respect to the operation of nuclear facilities, and by the FCC with respect to certain communications licenses. The jurisdiction of other federal regulators is similarly not affected.
Moreover, the Merger Agreement requires approvals from most of the regulatory authorities having jurisdiction over the Xcel Operating Companies as a condition to the consummation of the Merger. Applicants are working closely with such regulators (both state and federal) to obtain the required approvals (as described below in Item 4). Presumably, if the Merger results in an impairment of regulatory authority, the state commissions will not approve it.[117]
Also, the FERC Merger Order addressed the potential impact of the Merger on regulation. The FERC stated:
As explained in the Policy Statement, the Commission's primary concern with the effect on regulation of a proposed merger involves possible changes in the Commission's jurisdiction when a registered holding company is formed, thus invoking the jurisdiction of the Securities and Exchange Commission (SEC). We are also concerned with the effect on state regulation where a state does not have the authority to act on a merger. . . With respect to state regulation, Applicants note that the transaction will be reviewed by the state public utility commissions of Minnesota, North Dakota, Arizona, New Mexico, Colorado, Wyoming and Texas and will not impair regulation in any of these state jurisdictions. In addition, Applicants state that although the public utility commissions of Kansas, Wisconsin, Michigan, Oklahoma, and South Dakota do not have direct authority to approve the merger transaction, each state commission has authority to protect retail customers from the effects of the merger. Applicants maintain that their operating companies will continue to be subject to state regulation after the transaction in each of these jurisdictions. Intervenors, including the public utility commissions of the states of Wisconsin, South Dakota, North Dakota, and Minnesota, raise no issues of adverse impact on regulation.
Accordingly, in light of the facts and commitments stated above, we are satisfied that the proposed merger will not have an adverse effect on regulation.[118]
Summary
The cumulative effect of the regulatory, technological and economic changes discussed above have significantly changed what is now the "state of the art" in the electric industry. The Commission must respond to these changes realistically in a manner that furthers the national and local energy policies that have developed.
A rigid reading of the integration requirement was undoubtedly appropriate at a time when ownership or control of the intervening lines was the only way that a utility could move power from its generation assets to its distribution systems. The need for this type of firm physical interconnection has been reduced, if not eliminated, as the distribution systems now routinely contract for power with nonaffiliates and move the purchased commodity power over independently operated or owned transmission lines -- or eliminate the requirement for physical movement of power from the generator to the utility system through use of market swaps, power displacement or other similar techniques. Indeed, a narrow reading of the integration standard could force merging parties to a "Hobson's choice," by requiring unnecessary interconnections that could cause a merger to fail to satisfy FERC's standards for approval.
Xcel's participation in MISO integrates the Xcel Electric System while significantly increasing the geographic scope of MISO in furtherance of FERC policy. A primary factor in NSP's and SPS's decision to join MISO was to enable the electric operations of the two companies to be integrated in today's electric market. The development of ISOs and other RTOs is critical to ensuring the reliability and adequacy of the interstate transmission grid. As FERC explained in Order No. 2000:
Regional institutions can address the operational and reliability issues now confronting the industry, and eliminate any residual discrimination in transmission services that can occur when the operation of the transmission system remains in the control of a vertically integrated utility. Appropriate regional transmission institutions could: (1) improve efficiencies in transmission grid management; (2) improve grid reliability; (3) remove remaining opportunities for discriminatory transmission practices; (4) improve market performance; and (5) facilitate lighter handed regulation. Thus, we believe that appropriate RTOs could successfully address the existing impediments to efficient grid operation and competition and could consequently benefit consumers through lower electricity rates resulting from a wider choice of services and service providers. In addition, substantial cost savings are likely to result from the formation of RTOs. [119]
The Commission has found, and the courts have agreed, that in circumstances in which the expertise in operating issues is lodged with another regulator, it is appropriate to "watchfully defer" to the work of that regulator.[120] Applicants urge the SEC to apply the doctrine of watchful deference to FERC's stated objective to improve the competitiveness of the electric industry through large RTOs. [121]
The need for the SEC to accommodate the views of FERC in this matter cannot be overstated. Congress enacted the 1935 Act and the FPA as two parts of the same legislation. The legislative history makes clear that the purpose of Section 11 of the 1935 act "is simply to provide a mechanism to create conditions under which effective Federal and State regulation will be possible."[122] The FERC's administration of the FPA has evolved as that agency has sought to develop fully competitive wholesale markets consistent with the changing technology. These facts compel the conclusion that administration of the 1935 Act must also evolve if the 1935 Act is to continue to create conditions under which "effective Federal and State regulation" is possible.
In the 1995 Report, the Division recommended that the Commission focus on whether the resulting system will be subject to effective regulation. The Study emphasized that "open access under FERC Order No. 636, wholesale wheeling under the Energy Policy Act [and FERC Order No. 888] and the development of an increasingly competitive and interconnected market for wholesale power have expanded the means for achieving the interconnection and the economic operation and coordination of utilities with non-contiguous service territories." The Study further expressed concern that the Act "not serve as an artificial barrier where other energy regulators have determined that an acquisition will benefit utility consumers." Accordingly, the Study concluded that "[w]hen considering any proposed acquisition, the SEC should consider whether the resulting system will impair the effectiveness of regulation. Where the affected state and local regulators concur, the SEC should interpret the integration standard flexibly to permit non-traditional systems if the standards of the Act are otherwise met." (Emphasis added.) Under this approach, if the affected States approve a proposed transaction (a condition precedent to the instant Merger), the "effectiveness of regulation" standard would be met.
In summary, the Applicants believe that the Merger will result in an integrated electric system under the current "state of the art" in the electric industry. The NCE and NSP systems will be physically interconnected through both the 100 Mw Northbound Path and common membership in MISO. Either is sufficient to meet the physically interconnected standard. The two systems will be economically operated as a single interconnected and coordinated system primarily through the Joint Operating Agreement, MISO and New Century Services. The two systems will be in the same region created by MISO. Finally, the Merger will not impair localized management, efficient operation or effective regulation. The Merger also will benefit investors, consumers and the public interest and will not give rise to the evils against which the Act is addressed. Accordingly, for the reasons set forth above, the Commission should find that the Xcel Electric System comprises a single, integrated electric-utility system within the meaning of the Act.
(ii) Retention of Combined Gas System
Because the Commission has interpreted the term "integrated public-utility system" to mean a system that is either gas or electric, but not both, it is necessary to qualify the combined gas operations of NSP and NCE (the "Xcel Gas System") under the "A-B-C" clauses of Section 11(b)(1). Under those provisions, a registered holding company can own "one or more" additional integrated systems if certain conditions are met. Specifically, the Commission must find that (A) the additional system "cannot be operated as an independent system without the loss of substantial economies which can be secured by the retention of control by such holding company of such system," (B) the additional system is located in one state or adjoining states, and (C) the combination of systems under the control of a single holding company is not so large . . . as to impair the advantages of localized management, efficient operation, or the effectiveness of regulation."
As shown below, the Xcel Gas System will constitute a single, integrated public utility system. Section 2(a)(29)(B) defines an "integrated public utility system" as applied to gas utility companies as:
a system consisting of one or more gas utility companies which are so located and related that substantial economies may be effectuated by being operated as a single coordinated system confined in its operation to a single area or region, in one or more States, not so large as to impair (considering the state of the art and the area or region affected) the advantages of localized management, efficient operation, and the effectiveness of regulation: Provided, that gas utility companies deriving natural gas from a common source of supply may be deemed to be included in a single area or region.
The combined gas operations of NSP and NCE satisfy this definition.
First, both the Commission's precedent and current technological realities indicate that the Xcel Gas System will operate as a coordinated system confined in its operation to a single area or region because it will derive natural gas from common sources of supply, and utilize common transportation and storage facilities. The gas utility operations of NSP and NCE will operate in a single area or region, as those operations are in the adjoining states of Michigan, Wisconsin, Minnesota, North Dakota, South Dakota, Wyoming, Colorado and Arizona. The Commission has not traditionally required that the pipeline facilities of an integrated gas system be physically interconnected. See, Penzoil Company, Holding Co. Act Release No. 15963 (Feb. 7, 1968) (finding an integrated gas utility system where some gas utility properties were not connected with the rest of the system, but with the facilities of an unaffiliated transmission company from which the system purchased all natural gas supplied to those properties, but not each other). See also, American Natural Gas Company, Holding Co. Act Release No. 15620 n.5 (Dec. 12, 1966) ("It is clear the integrated or coordinated operations of a gas system under the Act may exist in the absence of such interconnection"). Instead, the Commission has looked to such issues as from whom the distribution companies within the system receive much, although not all, of their gas supply. See, e.g., Philadelphia Company and Standard Power and Light Company, Holding Co. Act Release No. 8242 (June 1, 1948) ("most of the gas used by these companies in their operations is obtained from common sources of supply"); Consolidated Natural Gas Company, Holding Co. Act Release No. 25040 (Feb. 14, 1990) (finding integrated system where each company derived natural gas from two transmission companies, although one such company also received gas from other sources); Sempra Energy, Holding Co. Act Release No. 26971 (Feb. 1, 1999) (finding an integrated system where each utility would derive "a significant amount" of gas from two basins and noting that gas can now be obtained by more flexible and efficient means, due to the development of market centers, hubs and pooling points). The Commission also has considered obtaining gas from a common pipeline, North American Company, Public Holding Co. Act Release No. 11530 (finding Panhandle Eastern pipeline to be a common source of supply): NIPSCO Industries, Holding Co. Act Release No. 26975 (Feb. 10, 1999) (finding an integrated system where the applicants had contracted capacity on only one common long-haul pipeline and ten of sixteen individual interstate pipelines on which the applicants' systems had contract capacity intersected at and formed industry-recognized trading hubs), as well as from different pipelines when the gas originates from the same gas field in determining a common source of supply. See, Central Power Company and Northwestern Public Service Company, Holding Co. Act Release No. 2471 (Jan. 6, 1941), in which the Commission declared an integrated system to exist where two entities purchase from different pipeline companies since "both pipelines run out of the Otis field, side by side, and are interconnected at various points in their transmission system; and that they are within two miles of each other at Kearney." See also, MCN Corporation, Holding Co. Act Release No. 26576 (Sept. 17, 1996) (finding an integrated system where one gas utility would receive 70-90% of its gas supply from the same basin from which two affiliates received 46% and 55% of their supply). Since the time of most of these decisions, the state of the art in the industry has developed to allow efficient operation of systems whose gas supplies derive from many sources.
The NSP and NCE gas operations today purchase gas from multiple basins and transport gas on multiple pipelines in order to enhance supply competition and provide increased reliability. However, NSP and NCE purchase significant quantities of natural gas from common supply basins as shown below. Approximately 75% of the 324.7 Bcf of natural gas purchased during 1998 were from common supply sources. The majority of these supplies were delivered off of the Northern Natural Gas Company ("NNG") and Colorado Interstate Gas Company ("CIG") pipeline systems to NSP and NCE, respectively. The pipeline systems of NNG and CIG are directly connected in two locations in the Mid Continent supply basin (i.e., the Hugoton and Anadarko supply basins). Together NCE and NSP hold over 1.5 Bcf of daily capacity and receive peak day deliveries in excess of 1.7 Bcf from the NNG and CIG pipeline systems. NSP and NCE purchase gas from the following major supply basins:
|
NATURAL GAS |
NCE |
NSP |
NCE & NSP |
|
|
Mid Continent |
33.7 |
27.7 |
61.4 |
18.9 |
|
Permian |
58.5 |
5.3 |
63.9 |
19.7 |
|
Rocky Mountain |
118.7 |
1.7 |
120.5 |
37.1 |
|
San Juan |
2.9 |
- |
2.9 |
0.9 |
|
Denver-Julesburg |
13.8 |
- |
13.7 |
4.2 |
|
Alberta |
- |
41.9 |
41.9 |
12.9 |
|
Other |
- |
20.4 |
20.4 |
6.3 |
|
Total |
227.6 |
97.0 |
324.7 |
100.0 |
In addition to the above, NCE and NSP own or have contracted for significant underground gas storage and own local gas peak shaving capacity at numerous locations throughout Colorado, Minnesota, Texas and other Midwestern states. The vast majority of this storage and peak shaving capacity is directly linked or accessible to the NNG and CIG pipeline systems. As a result, these operationally flexible assets have the ability to further integrate the common sources of supply for NCE and NSP. Access to the various storage facilities and pipelines forms a grid upon which the companies can source supply to take advantage of relative shifts in market conditions among the various producing basins.
The concept of a "common source of supply" is susceptible to a different understanding today than in 1935, when the "single area or region" was generally defined in terms of the pipeline delivery points (i.e., the city gate), where system LDCs purchased their gas. Sempra Energy, Holding Co. Act Release No. 26971 (Feb. 1, 1999). In Sempra, the Commission recognized "that the relevant inquiry today is whether the system LDCs purchase substantial quantities of gas produced in the same supply basins, and whether that gas is "deliverable" - in other words, whether there is sufficient transportation capacity available in the marketplace to assure delivery on an economical and reliable basis." See also NIPSCO Industries, Inc., Holding Co. Act Release No. 26975 (February 10, 1999) (NIPSCO Industries' acquisition of Bay State Gas Company, in which case the Commission held that "[a]lthough the intervening territory between the NIPSCO Operating Companies is significant, we do not believe that the distance contravenes the policy of the Act against scatteration -- the ownership of widely dispersed utility properties which do not lend themselves to efficient operation and effective state regulation").
In NIPSCO Industries' acquisition of Bay State Gas Company, the Commission recognized that the "state of the art" in the gas industry continues to evolve and change, primarily as a result of decontrol of wellhead prices, the continuing development of an integrated national gas transportation network, the emergence of marketers and brokers, and the "unbundling" of the commodity and transportation functions of the interstate pipelines in response to various FERC initiatives, in particular Order 636,[123] which has dramatically altered the way in which local gas distribution companies purchase and ship their required gas supplies. NIPSCO, supra.
The Commission has also considered and recognized that another important development affecting the "state of the art" in the natural gas industry has been the creation of a national network of trading hubs and market centers. The development of trading hubs and market centers was a natural outgrowth of FERC Order 436 and 636, which, as indicated, required interstate pipelines to separate, or "unbundle," the commodity and transportation and storage functions of the interstate pipelines.
In this regard, it is significant to note that, 6 of the 12 individual interstate pipelines (long-haul and regional) on which the NCE and NSP companies have contracted capacity intersect at and form industry recognized trading hubs. These include:
|
Name of Hub |
Location |
Intersecting Pipelines |
|
MidContinent Market Center |
Greensburg, Kansas |
ANR Pipeline Co. |
|
Chalk Bluffs |
near Cheyenne, Wyoming |
Colorado Interstate Gas Co. |
|
Buffalo Wallow |
near Amarillo, Texas |
ANR Pipeline Co. |
Trading hubs (including all of those listed above) essentially function as physical transfer points between intersecting pipelines, where shippers (i.e., buyers and sellers) and traders can sell, exchange or trade gas or pipeline capacity or redirect deliveries to a different pipeline. Further, various types of unbundled services are typically available at trading hubs, such as parking, loaning, and wheeling of gas and, in some instances, title transfer.[124] Because of the role played today by market hubs and market centers, coordination of the operations of two non-contiguous gas companies is no longer dependent solely upon having contractual capacity on the same interstate pipelines, so long as the two companies both have access to one or more common trading hubs.
Importantly, trading hubs now allow gas distribution companies operating in a much larger area or region of the country to realize operating economies and efficiencies from coordinated operations that were once thought to be achievable only by contiguous or nearly contiguous gas companies supplied by the same interstate pipelines. In fact, as discussed below, the opportunities to achieve operating economies may be even greater where the two companies seeking to combine have significantly different load profiles (e.g., non-coincident seasonal peaks, a substantially different customer mix, etc.) or where, as in this case, the two companies are located in two different major gas market centers, experience non-coincident peak demands, and are served (to a degree) from common supply basins.
Because NSP and NCE share access through their respective pipeline transporters to several industry-recognized market and supply-area hubs, they will have the ability to physically coordinate and manage their portfolios of gas supply, transportation, storage and peak shaving. Each of the hubs or market centers is served by a significant number of competing pipeline transporters, further expanding the potential supply options available to the merged company. In addition, as customers of hub services, NSP and NCE are among an even larger number of other customers of such services such as natural gas marketers, local distribution companies, and other wholesale customers.
For example, the ANR and NNG pipelines, which transport gas to NSP, and the KN and Williams pipelines, which transport gas to NCE, all intersect at the MidContinent Market Center hub located at Greensburg, Kansas. At the MidContinent Market Center hub, NSP can arrange and consummate direct physical purchases and trades of gas and/or transportation capacity with NCE or with any other shipper having access to the MidContinent Market Center hub. NSP and NCE also have access to the Waha Permian Basin hub near Odessa, Texas via contracted capacity on the NNG and El Paso pipelines. The Waha Permian Basin hub is a recognized center for western natural gas index price futures trading in the U.S. Through four interstate and six intrastate pipeline interconnections, market participants such as NSP and NCE can physically support, if necessary and if permitted by state regulatory bodies, the utilization of financial derivatives as a means of managing price volatility.
Moreover, through its contracted capacity on the CIG and KN pipelines, NCE would have access to the storage capacity held by NSP on NNG and ANR. Such access will enhance Xcel's ability to manage price volatility. These facilities would also provide NSP and NCE with an important gas balancing capability, which will allow them to manage fluctuating weather-related load profiles of each other's system.
Finally, NSP and NCE would have direct access to the Chicago market center hub, which is expected to become an increasingly important source of gas for all eastern U.S. markets.
In the current natural gas industry, limitations on the deliverability of gas in most areas of the country have disappeared. Under Section 2(a)(29)(B), these "state of the art" changes in the industry are directly relevant to the issue of the appropriate size of the "area or region" in which an "integrated" gas system may operate.
(iii) Coordinated Operations of Combined Gas Properties
NSP and NCE currently manage similar physical properties and contractual assets (gas supply, pipeline transportation, and storage contracts of varying types and duration). Each company maintains a professional staff that performs essential portfolio management functions. In NSP's case, these functions are performed by a group that currently consists of 9 individuals and provides gas portfolio management services. The NCE gas supply department currently consists of 8 individuals.
After the Merger, there will be a formal relationship between the two gas supply departments which will enable them to integrate the overall planning and management of the two companies' respective portfolios of physical and contractual assets. This formal relationship will be through New Century Services, which will provide various administrative and operational services to the existing gas operations of NSP and NCE, and through a Gas Supply Coordinated Dispatch Agreement and a Joint Operating Agreement analogous to the Joint Operating Agreement between the electric operating company subsidiaries.
Finally, the system will not be so large as to impair the advantages of localized management or the effectiveness of regulation. Localized management will be preserved. It is expected that the centralized functions of the NSP-NCE gas system will be managed from one location, and the local functions will continue to be handled from several regional offices. Management will, accordingly, remain close to the gas operations, thereby preserving the advantages of local management. And, from a regulatory standpoint, there will be no impairment of regulatory effectiveness. The same state regulators currently overseeing these gas operations will continue to have jurisdiction after the proposed transaction is completed. Those same state regulators are already regulating multi-jurisdictional gas or combination gas/electric utilities.
For all of these reasons, we believe that the NSP-NCE gas operations will satisfy the integration requirements of Section 2(a)(29)(B).
Prior to the 1997 NCE Order, the Commission interpreted Clause A to require, in effect, a showing that the additional system could not survive on a stand-alone basis. Id., citing New England Electric System, Holding Co. Act Release No. 15035 (Mar. 19, 1964), rev'd, 346 F.2d 399 (1st Cir. 1966), rev'd and remanded, 384 U.S. 176 (1965), on remand, 376 F.2d 107 (1st Cir. 1967), rev'd, 390 U.S. 207 (1968). In its 1995 Report, the SEC Staff noted that, in a competitive utility environment, any loss of economies threatens a utility's competitive position and even a "small" loss of economies could render a utility vulnerable to significant erosion of its competitive position. Adopting this line of reasoning, the Commission, in its order approving the merger of PSCo and SPS, found that "[t]he gas and electric industries are converging, and, in these circumstances, separation of gas and electric businesses may cause the separated entities to be weaker competitors than they would be together. This factor adds to the quantifiable loss of economies caused by increased costs." 1997 NCE Order, supra. See also WPL Holdings, supra .
Applicants believe that in light of this precedent and the changing structure of the industry, where utilities are no longer either gas companies or electric companies, but are commonly energy companies, lost opportunities could constitute lost economies for the purpose of the application of the (A)-(B)-(C) clauses. This proceeding, however, does not require that the Commission agree with this interpretation, since Applicants can demonstrate loss of economies under a more traditional analysis. Historically, the Commission has given consideration to four ratios, which measure the projected loss of economies as a percentage of: (1) total utility operating revenues; (2) total utility expense or "operating revenue deductions"; (3) gross utility income; and (4) net utility operating income. Although the Commission has declined to draw a bright-line numerical test under Section 11(b)(1)(A), it has indicated that cost increases resulting in a 6.78% loss of operating revenues, a 9.72% increase in operating revenue deductions, a 25.44% loss of gross gas income and a 42.46% loss of net income would afford an "impressive basis for finding a loss of substantial economies." Engineers Public Service Co., Holding Co. Act Release No. 1632 (Sept. 16, 1942).
Direct Loss of Economies. NSP and NCE have each prepared separate studies of their respective gas utility operations that analyze the lost economies that their gas utility operations would suffer upon divestiture when compared to their retention pursuant to the Merger. These studies are attached to this Application as Exhibit J-1 and Exhibit J-2 (the "Gas Studies"). As set forth in the Gas Studies, if the gas operations of NSP and NCE were operated on a stand-alone basis, lost economies from the need to replicate services, the loss of economies of scale, the costs of reorganization, and other factors would be immediate and substantial. In the absence of rate relief, those lost economies would substantially injure the shareholders of NSP and NCE upon the divestiture of those gas operations. As the studies further show, if rate relief were granted with respect to the lost economies, then consumers would bear those substantial costs over what they would have to pay if the properties were retained as contemplated by the Merger.
As set forth in the Gas Studies, divestiture of the gas operations of PSCo, Cheyenne, NSP and NSP-W into stand-alone companies would result in lost economies of $25,807,000 for NSP, $7,629,000 for NSP-W, $55,862,000 for PSCo, and $1,417,000 for Cheyenne. The table below shows the 1998 gas operating revenues, gas operating revenue deductions, gas gross income and gas net income of NSP, NSP-W, PSCo and Cheyenne.
|
|
|
000s |
|
|
|
NSP |
$360,567 |
$330,578 |
$29,989 |
$23,432 |
|
NSP-W |
$78,800 |
$73,510 |
$5,290 |
$3,691 |
|
PSCo |
$682,289 |
$585,557 |
$96,732 |
$73,321 |
|
Cheyenne |
$20,995 |
$18,574 |
$2,421 |
$1,856 |
On a percentage basis, the lost economies amount to 76.19% of 1998 gas net income for PSCo, 76.35% for Cheyenne, 110.14% of gas net income for NSP and 206.69% of gas net income for NSP-W -- far in excess of the loss of net income in UNITIL, where the Commission allowed the retention of gas utility operations, and the 30% loss in New England Electric System that the Commission has described as the highest loss of net income in any past divestiture order.[125] As a percentage of 1998 gas operating revenues, these lost economies described in the Gas Studies amount to 8.19% for PSCo, 6.75% for Cheyenne, 7.16% for NSP and 9.68% for NSP-W--losses substantially higher than the losses in any past divestiture order. [126] As a percentage of 1998 expenses or operating revenue deductions, the lost economies described in the Gas Studies would amount to 9.54% for PSCo, 7.63% for Cheyenne, 7.81% for NSP, and 10.38% for NSP-W, higher than the losses in any past divestiture order and, in Entergy Corporation, Holding Co. Act Release No. 25952 (Dec. 17, 1993), another case in which the Commission authorized the retention of gas operations. As a percentage of 1998 gross income, the lost economies described in the Gas Studies amount to 57.75% for PSCo, 58.53% for Cheyenne, 86.05% for NSP and 144.22% for NSP-W, far in excess of the highest loss of gross income in any divestiture order.
In order to recover these estimated lost economies, PSCo would need to increase rate revenue by $57,738,000 or 8.53%, Cheyenne would need to increase revenue by $1,615,000 or 7.69%, NSP would need to increase revenues by $26,723,000 or 7.41% and NSP-W would need to increase rate revenue by $7,812,000 or 9.91%. These increases in rate revenues would have a direct and immediate negative impact on the rates charged to customers for gas services. In addition, the customers of NCE and NSP gas businesses who are also customers of their respective electric utility businesses will experience a doubling of their postage costs to pay separate bills. The total estimated increase in such postage costs is $3.96 per customer per year or $6,026,733 in the aggregate ($1,523,000 for NSP gas customers, $326,000 for NSP-W gas customers, $4,065,000 for PSCo gas customers, and $113,000 for Cheyenne gas customers.)
It is the intention of the Applicants that their separate gas properties be integrated and operated as a single economic system in conjunction with Applicants' electric system in order to better provide competitive comprehensive energy services to Applicant's customers. Because today the properties of NSP and NCE are operated as separate entities and Section 11(b)(1)(A), (B) and (C) appear to require an analysis of "[e]ach such additional system," the Gas Studies described above looked at divestiture of four separate gas systems, preserving their present status of being separate from one another, which produced annual lost economies that are estimated to be $90.7 million per annum. [127]
These lost economies are substantial in an industry in which there are already many companies competing with Applicants for the provision of comprehensive energy services in Applicants' service territories and, where there is not yet competition, lost economies may well result in increased retail rates. Competition between energy suppliers can only benefit consumers. Increasingly, the competitors are themselves suppliers of comprehensive energy services just like NCE, NSP, TUC Holding Company and Reliant Energy Inc.
Divestiture of the NSP and NCE gas properties either into one company or into separate companies would also result in the loss to consumers of the cost-saving benefits of the economies offered by the "energy services" approach of NSP and NCE to the utility business. While the losses cannot now be fully quantified, they are substantial. At the center of the energy services company concept is the idea that providing gas and electric services and products is only the start of the utility's job. In addition, the utility must provide enhanced service to the consumer by providing an entire package of both energy products and services. In this area, NSP's and NCE's efforts are part of a trend by utilities to organize themselves as energy service companies; that is, as providers of a total package of energy services rather than merely suppliers of gas and electric products. The goal of an energy service company is to retain its current customers and obtain new customers in an increasingly competitive environment by meeting customers' needs better than the competition. An energy service company can provide the customer with a low cost energy (i.e., gas, electricity or conservation) option without inefficient subsidies. This trend towards, and the need for, convergence of the former separate electric utility function and gas utility function into one energy service company was recently recognized by the Commission in Consolidated Natural Gas Company, Holding Co. Act Release No. 26512 (April 30, 1996) (hereinafter, the "CNG Order"), where the Commission stated: "It appears that the restructuring of the electric industry now underway will dramatically affect all United States energy markets as a result of the growing interdependence of natural gas transmission and electric generation, and the interchangeability of different forms of energy, particularly gas and electricity." See also UNITIL Corp., Holding Co. Act Release No. 26527 (May 31, 1996); SEI Holdings, Inc., Holding Co. Act Release No. 26581 (Sept. 26, 1996); and Dominion Resources, Inc, Holding Co. Act Release No. 27113 (Dec. 15, 1999).
As the Commission recognized in WPL Holdings, TUC Holdings and the 1997 NCE Order, there are significant economies and competitive advantages inherent in a combined gas and electric utility as contrasted to a utility offering only electricity or gas. Besides the loss of these inherent economies, other substantial economies would be lost by the separation of the electric systems from the gas systems. These lost economies would include decreased efficiencies from separate meter reading, meter testing and billing operations, as well as decreased efficiencies in customer service operations, savings in facilities maintenance and emergency work coordination, and other administrative operations. A final consideration, also raised by the Commission in the 1997 NCE Order, is that the gas and electric properties of NCE and NSP have long been under common control, and approval of the Merger will not alter the status quo with respect to these operations.
Accordingly, it is Applicants' view that the standards of Clause A are satisfied in light of the increased expenses and the potential loss of competitive advantages that could result from separation from the gas system. Against this background, Applicants believe that the Commission should find the standards of Clause A satisfied with respect to the gas systems of NCE, NSP and NSP-W.
(b) Same state or adjoining states
The proposed Merger does not raise any issue under Section 11(b)(1)(B) of the Act. The Commission has paraphrased Clause B as follows: "All of such additional systems are located in a state in which the single integrated public utility system operates, or in states adjoining such a state, or in a foreign country contiguous thereto." Engineers Public Service Company, Holding Co. Act Release No. 2897 (July 23, 1941), rev'd on other grounds, 138 F.2d 936 (D.C. Cir. 1943), vacated as moot, 332 U.S. 788 (1947). The Xcel Gas System is located in the same states as the Xcel Electric System, plus Arizona, and Arizona adjoins Colorado, a state in which the Xcel Electric System operates. Thus, the requirement that each additional system is located in one state or adjoining states is satisfied.
(c) Size
Further, retention of the combined gas operations of NCE and NSP as an additional integrated system raises no issue under Section 11(b)(1)(c) of the Act. The combination of the systems under the control of a single holding company will not be "not so large . . . as to impair the advantages of localized management, efficient operation, or the effectiveness of regulation." As the Commission has recognized elsewhere, the determinative consideration is not size alone or size in an absolute sense, either big or small, but size in relation to its effect, if any, on localized management, efficient operation and effective regulation. From these perspectives, it is clear that the continued combination of the gas operations under Xcel is not too large.
Even after the combination, the gas utility operations of New NSP, NSP-W, BMG, PSCo and Cheyenne, with some 1.5 million gas customers combined in seven states, will be smaller than Reliant Energy (the parent of Minnegasco) which, through subsidiaries, has 2,700,000 gas customers, 630,000 of which are in Minnesota. This company is among NSP's and NCE's primary natural gas competitors in the region. Based on data through December 31, 1998, and giving effect to the Merger, the combined gas assets will represent only 8.6% of the total assets of Xcel, whereas the electric assets will represent 51.6%; operating revenues for the gas operations will be 16.5% of total Xcel's revenues as compared with 74.1% for the electric operations; and customers of the gas operations will constitute 33.3% of all Xcel's customers, while electric operations will represent 67.6%. With respect to localized management, this issue is discussed for the Merger as a whole under Item 3.C.1.(b)(i)(a) below. Applied solely to the gas operations, the current NSP, NSP-W, BMG, PSCo and Cheyenne gas systems enhance localized management within the larger corporate structure and will continue to do so after the Merger is completed.
After the Merger, certain centralized gas functions of Xcel will be managed by New Century Services from a centralized location, and the local functions will continue to be handled from regional offices. No reduction in customer service or support crews is expected. Management will therefore remain geographically close to the gas operations, thereby preserving the advantages of localized management. From the standpoint of regulatory effectiveness, NSP already operates a combined gas and electric utility in Minnesota, North Dakota and South Dakota, as does NSP-W in Wisconsin and Michigan, PSCo in Colorado and Cheyenne in Wyoming. In addition, several other gas utilities in the region serve customers in several states. Thus, the regulatory agencies in the seven states are currently regulating multi-jurisdictional gas utilities and will be able to effectively regulate the gas utility operations of Xcel after the Merger. In addition, the historical joint gas and electric utility operations of NSP have never raised regulatory concerns in Minnesota and North Dakota, and NSP has requested the Minnesota and North Dakota regulatory authorities to make findings that the retention of the existing gas system of NSP would not impair their ability to regulate these systems effectively. [128] With respect to efficient operation, as described below, as part of the Xcel system, the gas operations of New NSP, NSP-W, PSCo and Cheyenne are expected to reduce purchased gas costs by $77.4 million from 2001 to 2010, which will be flowed through to customers via lower rates in accordance with state commission approved purchased gas adjustment clauses. Far from impairing the advantages of efficient operation, the combination of the gas operations under Xcel will facilitate and enhance the efficiency of gas operations.
As in the 1997 NCE Order and WPL Holdings, the proposed combination of NCE and NSP offers Applicants a means to compete more effectively in the emerging energy services business. Further, as discussed above, the Merger will give rise to none of the abuses, such as ownership of scattered utilities properties, inefficient operations, lack of local management or evasion of state regulation, that section 11(b)(1) and the Act generally were intended to prohibit.
(iv) Retention of Other Businesses
In the 1997 NCE Order, the Commission approved the retention by NCE of certain non-utility businesses of PSCo and SPS, as well as their direct and indirect subsidiary companies. Annex C sets forth those non-utility businesses. In addition Annex C lists and describes those non-utility businesses commenced by NCE following that merger. All such businesses have been established pursuant to a Commission order or an applicable exception. As noted previously, the non-utility businesses of NSP were listed and described on Annex D. At issue in this transaction, is whether Xcel may retain the non-utility businesses of NSP and the new non-utility businesses of NCE.
The non-utility interests of NSP are fully retainable. As a result of the Merger, the non-utility businesses and interests of NSP and NCE described in Item 1.C. above will become businesses and interests of Xcel. Corporate charts showing the subsidiaries, including non-utility subsidiaries of NSP and NCE, are filed as Exhibits E-10 and E-11. A corporate chart showing the projected arrangement of these subsidiaries under Xcel is filed as Exhibit E-12. [129]
Standard for retention: Section 11(b)(1) permits a registered holding company to retain "such other businesses as are reasonably incidental, or economically necessary or appropriate, to the operations of [an] integrated public utility system." The Commission has historically interpreted this provision to require an operating or "functional" relationship between the non-utility activity and the system's core non-utility business. See, e.g. Michigan Consolidated Gas Co., Holding Co. Act Release No. 16763 (June 22, 1970), aff'd, 444 F.2d 913 (D.C. Cir. 1971); United Light and Railways Co., Holding Co. Act Release No. 12317 (Jan. 22, 1954); CSW Credit, Inc., Holding Co. Act Release No. 25995 (March 2, 1994); and Jersey Central Power and Light Co. , Holding Co. Act Release No. 24348 (March 18, 1987). The Commission retreated from this historical position and "has sought to respond to developments in the industry by expanding its concept of a functional relationship."[130] This shift culminated in the adoption of Rule 58. The Commission added "that various considerations, including developments in the industry, the Commission's familiarity with the particular non-utility activities at issue, the absence of significant risks inherent in the particular venture, the specific protections provided for consumers and the absence of objections by the relevant state regulators, made it unnecessary to adhere rigidly to the types of administrative measures" used in the past. Id. Furthermore, in the 1995 Report, the SEC Staff recommended that the Commission replace the use of bright-line limitations with a more flexible standard that would take into account the risks inherent in the particular venture and the specific protections provided for consumers.[131] As set forth more fully in Annexes C, D and E, the non-utility business interests that Xcel will hold directly or indirectly all meet the Commission's standards for retention.
In the past, the Commission has approved the acquisition or retention of non-utility businesses in a merger between two companies, one of which was an independent public utility company not subject to the 1935 Act and the other was an exempt holding company. See 1997 NCE Order, supra. As noted above, Annex C sets forth the non-utility business of PSCo and SPS approved for retention. Applicants submit that the statutory requirements for ownership of NCE's new non-utility businesses and NSP's non-utility businesses are satisfied, as detailed in Annexes C and D hereto.
In approving NCE's retention of other businesses, the Commission also excluded such businesses from the limitation upon investment in energy-related companies under Rule 58, noting that the restrictions of Section 11(b)(1) are applicable to registered holding companies and not to exempt holding companies. Rule 58 provides in section (a)(1)(ii) that investments in non-utility activities that are exempt under Rule 58 cannot exceed 15% of the consolidated capitalization of the registered holding company. In its statement supporting the adoption of the Rule, the Commission stated:
The Commission believes that all amounts that have actually been invested in energy-related companies pursuant to commission order prior to the date of effectiveness of the Rule should be excluded from the calculation of aggregate investment under Rule 58. The Commission also believes it is appropriate to exclude from the calculation all investments made prior to that date pursuant to available exemptions.
Holding Co. Act Release No. 26667 at 50-51. Because NSP was not yet a registered holding company, none of the investments in non-utility activities that are described in Annex D hereto were pursuant to Commission order. However, since the non-utility investments of NSP, as an exempt holding company, were exempt under the Act, investments made by it prior to the effective date of Rule 58 which will continue as part of Xcel after consummation of the merger, should not count in the calculation of the 15% maximum. See 1997 NCE Order, supra (Commission order granting exclusion of non-utility energy-related investments of SPS, an independent utility, and PSCo an exempt holding company, from calculations of the 15% maximum investment allowed under Rule 58).
Besides the non-utility businesses of NSP subsidiaries that are described in Annex B, NSP is directly engaged at the parent company level in the following non-utility businesses: (i) an appliance services program for its residential customers, (ii) construction of natural gas distribution systems for third parties (primarily end-users and municipal gas systems), (iii) sale and installation of power quality instruments primarily to protect equipment of customers from electric surges, (iv) sale of steam to industrial customers in NSP's service territory and (v) installation and maintenance of street lighting for municipalities and other customers. New NSP intends to continue to engage in these businesses.
The following chart shows the reasons based on Commission orders or rules that retention of such businesses should be permitted:
Business Description Authority
|
Appliance services program |
Mississippi Power and Light |
|
Sale and installation of power quality instruments |
New Century Energies, Inc., |
|
Construction of natural gas distribution systems for third
parties; installation and maintenance of street lighting |
National Fuel Gas Company, |
|
Sale of steam |
New Century Energies, Inc., |
Similarly, PSCo, prior to the merger with SPS into NCE, also was directly engaged in various non-utility businesses, namely: (i) thermal energy; (ii) the commercialization of electro-technologies; (iii) electric and gas vehicle products and services; and (iv) the sale and servicing of electric and gas appliances. The Commission in the 1997 NCE Order authorized the retention of these businesses. From its experience in marketing these services, NCE is aware that there are certain advantages of having a utility be able to offer these types of services directly to customers, as opposed to through an affiliate. Based on this experience, Applicants request the following authorization: where either PSCo or the NSP companies are directly engaged in a line of business, the retention of which the Commission either in the 1997 NCE Order or in its order in this proceeding has authorized, the other Xcel Operating Companies should likewise be authorized to engage in that business, subject to any limitations or requirements imposed by state law or state commission order or rule.
In addition, the Commission in the 1997 NCE Order authorized SPS, PSCo, and other associate companies of NCE to lease office or other space to other associate companies (with such leases to be in accordance with Rules 87, 90 and 91) or to third parties. Applicants request that the Commission extend this authority to apply to the Xcel system and NSP and its direct and indirect subsidiaries.
Because the Merger is expected to result in substantial cost savings and synergies, it will tend toward the economical and efficient development of an integrated public utility system, thereby serving the public interest, as required by Section 10(c)(2) of the Act.
The Merger will produce economies and efficiencies more than sufficient to satisfy the standards of Section 10(c)(2) of the Act. Although some of the anticipated economies and efficiencies will be fully realizable only in the longer term, they are properly considered in determining whether the standards of Section 10(c)(2) have been met. See AEP, supra. Some potential benefits cannot be precisely estimated, nevertheless they too are entitled to be considered. "[S]pecific dollar forecasts of future savings are not necessarily required; a demonstrated potential for economies will suffice even when these are not precisely quantifiable." Centerior, supra.
NSP and NCE have estimated the nominal dollar value of synergies from the Merger to be approximately $1.1 billion (net costs to achieve) over the 10-year period from 2001-2010. The Merger is expected to yield several types of presently quantifiable benefits and savings, which are identified by area below: (1) corporate and operations support; (2) corporate and administration programs; (3) nonfuel purchasing economies; and (4) production savings, including savings for fuel procurement, production dispatch and natural gas supply. The total amount of savings currently estimated in each of these categories, on a nominal dollar basis is summarized in the table below:
Merger Synergies in Nominal Dollars
|
|
|
|
|
|
|
Corporate and Administrative Programs |
$344.4 million |
|
Non-Fuel Purchasing Economies |
$203.7 million |
|
Production Savings (Electric and Gas) |
$95.9 million |
|
Total Savings |
$1,334.7 million |
|
Less: Costs to Achieve ($105.8 million of transition costs and $43.7 million of transaction costs) |
($149.5 million) |
|
Pre-merger Initiatives |
($92.9 million) |
|
Net Savings |
$1,092.3 million |
These expected savings will meet or exceed the anticipated savings in a number of recent acquisitions approved by the Commission. [132] See, e.g., NIPSCO Industries, Inc., Holding Co. Act Release No. 26975 (Feb. 10, 1999) (expected savings of $57.45 million over ten years); Sempra Energy , Holding Co. Act Release No. 26890 (June 26, 1998) (expected savings of $1.2 billion over ten years); BL Holding Corp., Holding Co. Act Release No. 26875 (May 15, 1998) (expected savings of $1.1 billion over ten years); LG&E Energy Corp., Holding Co. Act Release No. 26866 (April 20, 1998) (expected savings of $687.3 million over ten years); WPL Holdings, Holding Co. Act Release No. 26856 (April 14, 1998) (expected savings of $680 million over ten years); Conectiv, Holding Co. Act Release No. 26856 (Feb. 25, 1998) (expected savings of $500 million over ten years); Ameren Corporation, supra (expected savings of $686 million over ten years); 1997 NCE Order, supra (expected savings of $770 million over ten years); TUC Holding Company, supra (expected savings of $505 million over ten years); Northeast Utilities, supra (expected savings of $837 million over eleven years); Entergy Corporation , Holding Co. Act Release No. 25952 (Dec. 17, 1993) (expected savings of $1.67 billion over ten years); Northeast Utilities, Holding Co. Act Release No. 25221 (Dec. 21, 1990) (expected savings of $837 million over eleven years); Kansas Power and Light Co., Holding Co. Act Release No. 25465 (Feb. 5, 1992) (expected savings of $140 million over five years); IE Industries, Holding Co. Act Release No. 25325 (June 3, 1991) (expected savings of $91 million over ten years); Midwest Resources, Holding Co. Act Release No. 25159 (Sept. 26, 1990) (expected savings of $25 million over five years); CINergy Corp., Holding Co. Act Release No. 26146 (Oct. 21, 1994) (expected savings of approximately $1.5 billion over ten years). These savings categories are described in greater detail below.
Corporate and Operations Support: NCE and NSP estimate that a net reduction in labor costs of approximately $691 million over ten years can be achieved as a result of the Merger through elimination of approximately 780 full time equivalent duplicative positions (including 105 contract workers) in certain corporate, administrative and technical support functions.
Corporate and Administrative Programs: NSP and NCE estimate a reduction in nonlabor corporate and administrative programs and expenses through the consolidation of overlapping or duplicative programs and expenses of $344 million over ten years. Specific areas in which savings are expected to occur include information systems, professional services, demand-side management administration, benefits administration, insurance, regulatory expenses, advertising and shareholder services.
Nonfuel Purchasing Economies: NSP and NCE estimate savings of $203.7 million through the combined procurement of material and supplies, inventory reduction from standardization, and limited sharing of parts and components and from economies of scale from the aggregation of related work activities and increased purchasing power over service providers.
Production Savings: NSP and NCE estimate production savings of approximately $96 million over a ten-year period. Two main components make up total production savings: efficiencies in procurement of fossil fuel and efficiencies in procurement and management of natural gas supply. The Applicants estimate fossil fuel savings of $18.5 million, stemming from an increase in coal procurement and coal transportation volumes and greater leverage during contract negotiations. NSP and NCE estimate natural gas supply savings of approximately $77.4 million, based on gas transport and storage capacity reductions, gas reserve margin reductions, field transportation reductions and capacity release savings through the contemplated Gas Supply Coordinated Dispatch Agreement.
The foregoing amounts do not include an additional $24 million in operating efficiencies that the Applicants expect to achieve over ten years as a result of the integration of the NSP and NCE electric generation systems through the 100 MW firm path from SPS to NSP. Through the use of this contract path, the Applicants estimate approximately $31 million in production cost savings and an additional $10 million in benefits resulting from increased opportunity sales. The firm path would also provide a secure source of additional low-cost supply to NSP during NSP's peak periods, protecting NSP from some predicted energy price volatility. These expected benefits are offset by anticipated transmission costs, resulting in an expected net benefit of $24 million over the ten-year period. As noted before, in their application to FERC, Applicants reserved the right to forego this firm path in the event that FERC believed that competitive concerns related to the path raised material issues of fact that would require a hearing. For this reason, these additional $24 million of savings have not been included in the $1.1 billion of savings presented in the chart above. Because the FERC Merger Order did not require that Applicants forego this path, these additional savings should also be achievable.
Additional Expected Benefits: In addition to the benefits described above, there are other benefits which, while presently difficult to quantify, are nonetheless substantial. These other benefits include maintenance of competitive rates, expanded management resources, more diverse service territory and continued community involvement.
Maintenance of Competitive Rates: A combined NSP/NCE will be able to meet the challenges of the increasingly competitive environment in the utility industry more effectively than either NCE or NSP standing alone. The Merger will create the opportunity for strategic, financial and operational benefits for customers in the form of lower rates over the long term and for shareholders in the form of greater financial strength and financial flexibility. NCE and NSP have proposed in filings with the various state regulatory commissions that regulate their retail sales of electricity various mechanisms to share in contemplated benefits, including a three- to five-year rate freeze. The rate freezes are subject to certain exceptions regarding matters beyond the NSP's or NCE's control. Further, ratepayers will receive 100% of the benefit of reductions in Xcel's fuel costs, except that customers of PSCo will receive 50% of such benefit.
Expanded Management Resources: A combined NCE and NSP entity will be able to draw on a larger and more diverse mid- and senior-level management pool to lead the new company forward in an increasingly competitive environment for the delivery of energy, and should be better able to attract and retain the most qualified employees. The employees of Xcel should also benefit from new opportunities in the expanded organization.
More Diverse Service Territory: The combined service territories of NSP and NCE will be larger and more diverse than either of the service territories of NSP or NCE as independent entities. This increased geographical diversity will mitigate the risk of changes in economic, competitive or climatic conditions in any given sector of the combined service territory.
Community Involvement: Xcel will continue to play a strong role in the economic development efforts of the communities NSP and NCE now serve. The philanthropic and volunteer programs currently maintained by the two companies will be continued.
Section 10(f) provides that:
The Commission shall not approve any acquisition as to which an application is made under this section unless it appears to the satisfaction of the Commission that such State laws as may apply in respect of such acquisition have been complied with, except where the Commission finds that compliance with such State laws would be detrimental to the carrying out of the provisions of section 11.
As described below under Item 4. "Regulatory Approvals," and as evidenced by the filings before the Minnesota Commission, the North Dakota Commission, the Colorado Commission, the Arizona Commission, the New Mexico Commission, the Texas Commission, and the Wyoming Commission, NSP and NCE intend to comply with all applicable state laws related to the proposed Merger.
The Xcel system companies will engage in a variety of affiliate transactions for the provision of goods, services, and construction. Certain of these transactions are elaborated upon below. In some instances, the Applicants simply request extension of the authorizations granted in the 1997 NCE Order, with respect to the NCE system, to the Xcel system. The provision of goods, services and construction by Xcel system companies to other Xcel system companies will be carried out in accordance with the requirements and provisions of Rules 87, 90 and 91 unless otherwise authorized by the Commission by order or by rule. [133]
1. New Century Services, Inc. (to be renamed Xcel Energy Services Inc.)
Rule 88(b) provides that "[a] finding by the Commission that a subsidiary company of a registered holding company. . .is so organized and conducted, or to be so conducted, as to meet the requirements of Section 13(b) of the Act with respect to reasonable assurance of efficient and economical performance of services or construction or sale of goods for the benefit of associate companies, at cost fairly and equitably allocated among them (or as permitted by [Rule] 90), will be made only pursuant to a declaration filed with the Commission on Form U-13-1, as specified in the instructions for that form, by such company or the persons proposing to organize it." Notwithstanding the foregoing language, the Commission in the 1997 NCE Order made findings under Section 13(b) based on information set forth in an Application-Declaration on Form U-1, without requiring the formal filing of a Form U-13-1. In this Application-Declaration, Applicants are submitting substantially the application information as would have been submitted in a Form U-13-1. Moreover, in this application, Applicants are not requesting authorization to establish a new service company, but rather are requesting that the Commission authorize an existing, Commission-approved service company, New Century Services, to extend its activities to NSP and its direct and indirect subsidiaries following the consummation of the Merger and the formation of the Xcel system.
Accordingly, it is submitted that it is appropriate to find that New Century Services will be so organized and shall be so conducted as to meet the requirements of Section 13(b), and that the filing of a Form U-13-1 is unnecessary, or, alternatively, that this Application-Declaration should be deemed to constitute a filing on Form U-13-1 for purposes of Rule 88.
New Century Services will be the service company subsidiary for the Xcel system. Applicants accordingly request that the prior authorizations and exemptions from the 1997 Order and the subsequent order in 1999 [134] (the "1999 Order") remain in effect and be expanded to include NSP and its subsidiaries. Specifically, New Century Services will provide Xcel, New NSP, NSP-W, BMG, PSCo, SPS, and Cheyenne, pursuant to the Utility Service Agreement, and the non-utility subsidiaries of the NSP/NCE system pursuant to the Non-Utility Service Agreement, with one or more of the following: administrative, management and support services, including services relating to support of electric and gas plant operations (i.e., energy supply management of the bulk power and natural gas supply, procurement of fuels, dispatch of generating units, coordination of electric and natural gas distribution systems, maintenance, construction and engineering work); customer bills, and related matters; materials management; facilities; real estate; rights of way; human resources; finance; accounting; internal auditing; information systems; corporate planning and research; public affairs; corporate communications; legal; environmental matters; and executive services. In accordance with the Service Agreement, services provided by New Century Services will be directly assigned, distributed or allocated by activity, project, program, work order or other appropriate basis. To accomplish this, employees of New Century Services will record their labor and expenses to bill the appropriate subsidiary company. Costs of New Century Services will be accumulated in accounts of the service company and be directly assigned, distributed, or allocated to the appropriate client company in accordance with the guidelines set forth in the Utility Service Agreement and the Non-Utility Service Agreement and the procedures in the "Procedures Manual" included but not incorporated with ExhibitS B-2 and B-3. At present, Applicants as part of the merger integration process are currently evaluating the forms of service agreement and the allocation methodologies to determine whether they should be revised to reflect the introduction of New NSP, NSP-W, or any of NSP's present subsidiaries as recipients of services. While Applicants do not expect that the forms of service agreements or allocation methodologies will be revised in any substantial manner, it is likely that some revisions nonetheless will be made, particularly to the allocation methodologies. After completion of this evaluation process, which will likely involve discussions with the state commissions that regulate the NCE Operating Companies and the NSP companies, Applicants will file (if necessary) the revised forms of service agreements or the allocation methodologies by amendment to this application. There will be an internal audit group which, among other things, will audit the assignment of service company charges to client companies. It is anticipated that New Century Services will be staffed primarily by existing personnel and by transferring personnel from the current employee rosters of NSP and its subsidiaries. New Century Services's accounting and cost allocation methods and procedures are structured so as to comply with the Commission's standards for service companies in registered holding company systems and were approved by the Commission in the 1997 NCE Order.
It is expected that New Century Services will conduct substantial operations in Minneapolis and St. Paul, Minnesota; Eau Claire, Wisconsin; Denver, Colorado; and Amarillo, Texas, where the headquarters of NSP, NSP-W, PSCo and SPS are located. Merger transition teams are presently considering where specific operations of the combined company will be headquartered.
As compensation for services, both the Utility and Non-Utility Service Agreements provide that "each Client Company shall pay to Service Company [i.e., New Century Services] the cost to Service Company of rendering such services for or on its behalf." Where more than one company is involved in or has received benefits from a service performed, the Service Agreement will provide that the "methods of assigning, distributing, or allocating Service Company costs to each Client Company, as well as to other associate companies, are set forth in Appendix A. . . . Such methods of assignment, distribution or allocation of costs may be modified or changed by Service Company without the necessity of an amendment to this Service Agreement provided that in such instance, all services rendered hereunder shall be at actual cost thereof, fairly and equitably assigned, distributed or allocated, all in accordance with the requirements of the [Public Utility Holding Company] Act and any orders thereunder." Thus, charges for all services provided by New Century Services to affiliated utility companies will be as determined under Rules 90 and 91 of the Act.
The Non-Utility Service Agreement contains provisions similar to those of the Service Agreement, except as set forth in detail below in this Item 3.E.3. The Non-Utility Service Agreement also will permit charges for certain services to be at fair market value to the extent authorized by the 1997 NCE Order, or hereafter by the Commission. Thus, except for the prior exemptions in the 1997 NCE Order and the requested exceptions discussed below, services provided by New Century Services to non-utility affiliates pursuant to the Non-Utility Service Agreement will also be charged as determined under Rules 90 and 91 of the Act. For further information regarding the accounting and cost assignment procedures of New Century Services, reference is made to EXHIBITS B-2 and B-3 hereto.[135]
Moreover, the Utility and Non-Utility Service Agreements provide that no change in the organization of New Century Services, the type and character of the companies to be serviced, the methods of allocating costs to associate companies, or in the scope or character of the services to be rendered subject to Section 13 of the Act, or any rule, regulation or order thereunder, shall be made unless and until New Century Services shall first have given the Commission written notice of the proposed change not less than 60 days prior to the proposed effectiveness of any such change. If, upon the receipt of any such notice, the Commission shall notify New Century Services within the 60-day period that a question exists as to whether the proposed change is consistent with the provisions of Section 13 of the Act, or of any rule, regulation or order thereunder, then the proposed change shall not become effective unless and until New Century Services shall have filed with the Commission an appropriate declaration regarding such proposed change and the Commission shall have permitted such declaration to become effective.
Applicants believe that the Utility Service Agreement and the Non-Utility Service Agreement are structured so as to comply with Section 13 of the Act and the Commission's rules and regulations thereunder.
2. Services, Goods, and Assets Involving the Utility Operating Companies
PSCo, SPS, Cheyenne, New NSP, NSP-W and BMG may provide to one another and other associate companies services incidental to their utility businesses, including but not limited to, power plant maintenance overhauls, power plant and storm outage emergency repairs, and services of personnel with specialized expertise related to the operation of the utility (i.e. , services by an industrial lighting specialist or waste disposal specialist). These services will be provided in accordance with Rules 87, 90 and 91. Moreover, in accordance with Rules 87, 90 and 91, certain goods may be provided through a leasing arrangement or otherwise by one utility operating company to one or more associate companies, and certain assets may be used by one utility operating company for the benefit of one or more other associate companies.
In addition to the foregoing, NSP and NSP-W are currently providing services to, or receiving services from, affiliates in accordance with agreements approved by the Minnesota Commission and/or the Wisconsin Commission. Each of these contracts (including the parties) is described in Annex E. To the extent necessary, Applicants request waiver from the Commission's "at cost" standards with respect to these transactions.
To elaborate on these contracts, under Minnesota law:
no contract or arrangement, including any general or continuing arrangement, providing for the furnishing of management, supervisory, construction, engineering, accounting, legal, financial or similar services and no contract or arrangement for the purchase, sale, lease or exchange of any property, right or thing, or for the furnishing of any service, property, right or thing, other than those above enumerated, made or entered into after January 1, 1975, between a public utility and any affiliated interest...is valid or effective unless and until the contract or arrangement has received the written approval of the [Minnesota Public Utilities] commission. [136]
An "affiliated interest" includes every subsidiary of a public utility. Furthermore the statute provides that "the [Minnesota Public Utilities] Commission shall approve the contract or arrangement. . . only if it shall clearly appear and be established upon investigation that it is reasonable and consistent with the public interest. . .," with the utility bearing the burden of proving that it is in the public interest. [137]
Also, under a policy statement issued in Docket No. E,G-999/CI-90-1008 (1994), the Minnesota Commission had adopted extensive guidelines on the allocation of costs for transactions with nonregulated affiliates. The Policy Statement docket initially arose from an investigation of nonregulated utility appliance sales and service programs. However, the Minnesota Commission later expanded the scope of the docket, and the Policy Statement also applies to all utility arrangements with regulated and nonregulated affiliates.[138] The Policy Statement provides that costs should be assigned between the utility and non-regulated function using the following four step hierarchy:
1. Tariffed rates shall be used to value tariffed services provided to the non-regulated activity.
2. Costs shall be directly assigned to either regulated or non-regulated activities whenever possible.
3. Costs which cannot be directly assigned are common costs which shall be grouped into cost categories. Each cost category shall be allocated based on direct analysis of the origin of costs wherever possible. If direct analysis is not possible, common costs shall be allocated based upon an indirect cost-causative linkage to another cost category or group of cost categories for which direct assignment or allocation is available.
4. When neither direct nor indirect measures of cost causation can be found, the cost category shall be allocated based upon a general allocator computed by the ratio of all expenses directly assigned or attributed to regulated and non-regulated activities, excluding the cost of fuel, gas, purchased power and the cost of goods sold.
Under this hierarchy, costs are allocated to non-regulated or regulated affiliates on a "fully allocated cost" basis, in order to prevent any subsidy of non-utility operations by the regulated utility operations and its customers. The Wisconsin Commission, in contrast, uses a higher-of-cost-or-market test where utilities provide services to affiliates.
The contracts listed in Annex E between associate companies are considered contracts between a public utility and an affiliated interest under Minnesota and Wisconsin law. However, for each contract, the Minnesota Commission (and in some cases the Wisconsin Commission) has determined that the contract is reasonable and in the public interest. The Commission's principal concern under Section 13 of the Act is to protect utility companies in a holding company system from abusive cross-subsidization transactions between associate companies. Since the Minnesota Commission or the Wisconsin Commission has found that all the aforementioned contracts are reasonable and in the public interest, cross-subsidization issues do not arise under these agreements, and each should be permitted to continue. Also, the contracts listed in Annex E under Natural Gas and Gas Related Services are exempt from the at cost standards of the Act under Rule 81.
3. Non-Utility Sale of Goods and Services to EWGs, FUCOs, and QFs
In its 1997 Order and subsequently in the 1999 Order, the Commission granted an exemption under Section 13(b) of the Act from the at-cost requirements of Section 13 and Rules 90 and 91 thereunder in connection with the provision of goods and services, including operation and maintenance services, at fair market prices, by New Century Services and certain non-utility subsidiaries of NCE to associate qualifying facilities ("QFs"), exempt wholesale generators ("EWGs") and foreign utility companies ("FUCOs") provided certain conditions were met. In the 1999 Order, the Commission has reserved jurisdiction over the issue whether it should similarly grant an exemption with respect to transactions involving exempt telecommunication companies under Section 34 of the Act, Rule 58 companies, or other non-utility subsidiaries that do not derive any part of their income from sales of goods, services or other property to the NCE Operating Companies. Applicants request that this authorization be extended to the Xcel system and, in particular, to certain non-utility subsidiaries of Xcel following completion of the Merger (the "Exempt Companies"). This authorization would extend to at least one existing contract among NSP subsidiaries.[139]
In addition, Applicants further request that the Commission, if necessary, grant a waiver of the "at cost" rules with respect to certain arrangements that the NSP companies have with affiliated QFs, which would not be subject to the blanket authorization requested above due to the failure to satisfy certain criteria. Specifically, Applicants request an exception with respect to Landfill Power and Minnesota Methane which, as explained in Annex E, are affiliates of NSP that own portions of QF facilities that sell power to NSP pursuant to PURPA contracts approved by the MPUC. The price of power under these contracts is based on NSP's avoided costs; they are not set with reference to Landfill Power and Minnesota Methane's cost of service. The exception being requested by Applicant is that the Commission permit the Exempt Companies to provide services or goods to Landfill Power and Minnesota Methane without compliance with the at-cost standards. The power purchase contracts of Landfill Power and Minnesota Methane with NSP set out fixed rates and do not contain any provisions that would affect the price NSP pays for power as a result of the price charged by the Exempt Companies in providing services or goods to Landfill Power or Minnesota Methane.
Applicants further request a waiver of the at-cost rules with respect to the services to be rendered by NMC, a Wisconsin limited liability company. NMC was formed in February 1999 by three unaffiliated companies which own (or whose affiliates own) nuclear power plant units located in Wisconsin and Minnesota for the purpose of consolidating into one service organization the specialized nuclear power plant personnel and resources of such companies. By order dated October 26, 1999 (Holding Co. Act Release No. 27096), Alliant Energy Corporation was authorized to acquire a 25% membership interest in NMC, and IES Utilities, Inc., a subsidiary of Alliant Energy, was authorized to enter into a services agreement (the "NMC Services Agreement") and related employee lease agreement (the "NMC Employee Lease Agreement"). Alliant Energy has also filed a request for approval of a Nuclear Power Plant Operating Services Agreement (the "Operating Services Agreement") with NMC (Post-Effective Amendment No. 1, File No. 70-9513, filed on November 24, 1999). Applicants seek permission for New NSP Utility to engage in business with NMC under the same terms as have been approved for Alliant Energy with respect to the NMC Services Agreement and the NMC Employee Lease Agreement and under the terms that Alliant Energy is currently seeking approval for with respect to the Operating Services Agreement.
4. UE
In the 1997 NCE Order, the Commission authorized UE to perform engineering, development, design, construction, and other related services to companies within the NCE system, including the NCE Operating Companies. Applicants request that this authority be extended to enable UE to provide such services to all associate companies within the Xcel system.
5. Other Existing Transactions
PSCo and SPS in File No. 70-8787 requested waivers of the at-cost standard with respect to various specific transactions. The Commission granted such waivers in the 1997 NCE Order. To the extent necessary, Applicants request that these waivers be extended following the Merger to such transactions that are still ongoing.
The Applicants request authority to organize a new utility subsidiary, New NSP, under the laws of Minnesota and to take the following actions in connection with the organization and capitalization of New NSP: New NSP proposes to assume the debt of NSP existing at the time of the Merger (approximately $1.8 billion) and issue shares of its capital stock to Xcel. The equity component will be derived by subtracting the total debt being assumed by New NSP from the total assets being transferred to New NSP. The result of the foregoing is that the overall equity/debt ratio New NSP will be approximately 50%, which is similar to that of NSP prior to consummation of the Merger. Applicants also request authority for Xcel to acquire the capital stock of New NSP and for NSP to transfer its debt to New NSP.
Item 4. Regulatory Approvals
Set forth below is a summary of the regulatory approvals that Applicants have obtained or expect to obtain in connection with the Merger. It is a condition to the consummation of the Merger that final orders approving the Merger be obtained from the Commission under the Act and from the various federal and state commissions described below on terms and conditions which would not have, or would not be reasonably likely to have, a material adverse effect on the business, assets, financial condition or results of operations of NCE and its subsidiaries taken as a whole, or on NSP and its subsidiaries taken as a whole.
A. Antitrust
The HSR Act and the rules and regulations thereunder prohibit certain transactions (including the Merger) until certain information has been submitted to the Antitrust Division of the Department of Justice ("DOJ") and Federal Trade Commission ("FTC") and the specified HSR Act waiting period requirements have been satisfied. NSP and NCE expect to make the initial filings under the HSR Act in January 2000.>
The expiration or earlier termination of the HSR Act waiting period does not preclude the DOJ or the FTC from challenging the Merger on antitrust grounds. Applicants believe that the Merger will not violate Federal antitrust laws. If the Merger is not consummated within twelve months after the expiration or earlier termination of the initial HSR Act waiting period, NSP and NCE will be required to submit new information to the DOJ and the FTC, and a new HSR Act waiting period would begin and have to expire or be terminated before the Merger could be consummated.
Section 203 of the Federal Power Act provides that no public utility shall sell or otherwise dispose of its jurisdictional facilities or directly or indirectly merge or consolidate such facilities with those of any other person or acquire any security of any other public utility, without first having obtained authorization from FERC. Under Section 203 of the Federal Power Act, FERC will approve a merger if it finds that merger "consistent with the public interest." In reviewing a merger, FERC generally evaluates: (i) whether the merger will adversely affect competition, (ii) whether the merger will adversely affect rates, and (iii) whether the merger will impair the effectiveness of regulation. On July 30, 1999, NSP and NCE filed a combined application with FERC requesting FERC to approve the Merger under Section 203 of the Federal Power Act. In connection with this Application, NSP and NCE also filed a joint Open Access Transmission Tariff to be effective upon completion of the Merger and Joint Operating Agreement and proposed Statement of Policy and Code of Conduct applicable to certain wholesale merchant function operations and various subsidiaries under Section 205 of the Federal Power Act, to become effective upon consummation of the Merger. As explained previously, on January 12, 2000, FERC issued its order approving the Merger under Section 203 of the Federal Power Act. As part of its order, the FERC also accepted the Joint Operating Agreement for filing without modification, the proposed Statement of Policy and Code of Conduct without modification and the Joint Open Access Transmission Tariff for filing, subject to a pending separate proceeding regarding SPS's rates. In addition, Applicants separately filed under 18 C.F.R. Part 37 proposed revised Standards of Conduct for NSP, PSCo, Cheyenne and SPS to be effective during the pendency of and after the proposed Merger. NSP will also need to obtain FERC's authorization under Part I of the Federal Power Act to transfer hydro-electric licenses held by it to New NSP, and may need to obtain FERC's authorization under Section 205 of the Federal Power Act to amend existing wholesale contracts to have New NSP assume NSP's responsibilities.
NSP holds NRC operating licenses in connection with its ownership and operation of the Prairie Island and Monticello nuclear generating facilities. The operating licenses authorize NSP to own and operate the facilities. PSCo holds NRC licenses in connection with its ownership of the Fort St. Vrain Nuclear Electric Generating Station. The Fort St. Vrain facility ceased operations on August 29, 1989 and is in the process of being decommissioned in accordance with the terms of orders issued by the NRC. The Atomic Energy Act provides that a license or any rights thereunder may not be transferred or in any manner disposed of, directly or indirectly, to any person through transfer of control unless the NRC finds that such transfer is in accordance with the Atomic Energy Act and consents to the transfer. Pursuant to the Atomic Energy Act, NSP has applied for approval from the NRC to reflect the fact that after the merger, New NSP will own and operate the Prairie Island and Monticello facilities and will become the operating company subsidiary of such facilities.
D. State Public Utility Regulation
NSP is currently subject to the jurisdiction of the Minnesota Commission, the North Dakota Commission, the South Dakota Commission and the Arizona Commission. NSP-W is subject to the jurisdiction of the Wisconsin Commission and the Michigan Commission. BMG is subject to the jurisdiction of the Arizona Commission. PSCo is subject to the jurisdiction of the Colorado Commission. Cheyenne is subject to the jurisdiction of the Wyoming Commission. SPS is subject to the jurisdiction of the New Mexico Commission, the Texas Commission, the Kansas Commission and the Oklahoma Commission. NSP and NCE have filed applications for approval of the Merger, including (where necessary) the issuance of securities, with the Minnesota Commission, the North Dakota Commission, the Arizona Commission, the Colorado Commission, the New Mexico Commission and the Wyoming Commission. Approval of the Merger is not required in Texas. However, unless the Texas Commission determines that the Merger is in the public interest, the Texas Commission may take its findings into account in future rate making proceedings. Thus, NSP and NCE also filed with the Texas Commission for a determination that the Merger is in the public interest. Approval of the Merger is not required in South Dakota, Wisconsin, Michigan, Kansas or Oklahoma. However, certain notice or similar filings may be filed in such states. The status of certain state filings is as follows:
On December 20, 1999, the Arizona Commission staff recommended approval without a hearing.
On September 20, 1999, the Kansas Commission issued an order approving an agreement among the Kansas Commission staff, SPS, and NSP setting forth various commitments relating to the Merger, including an annual rate credit. No further approval of the Kansas Commission is expected or required in connection with the Merger.
On December 21, 1999, the Oklahoma Commission approving a stipulation which incorporated a regulatory plan relating to the Merger. The Oklahoma Commission found the proposed regulatory plan to be fair, just and reasonable, and in the best interests of SPS's retail customers in Oklahoma. No further approval of the Oklahoma Commission is expected or required in connection with the Merger.
E. Other
The NSP and NCE Systems possess municipal franchises and environmental permits and licenses that they may need to assign or replace as a result of the Merger. NSP and NCE do not anticipate any difficulties obtaining such assignments, renewals and replacements. In addition, British regulatory approval may also be required in light of NCE's ownership interest in Yorkshire Electricity and NSP's indirect investments in the United Kingdom.
Except as set forth above, no other state or local regulatory body or agency and no other Federal commission or agency has jurisdiction over the transactions proposed herein.
Finally, pursuant to Rule 24 under the Act, the Applicants represent that the transactions proposed in this filing shall be carried out in accordance with the terms and conditions of, and for the purposes stated in, the declaration-application no later than December 31, 2004.
Item 5. Procedure
The Commission is respectfully requested to publish, not later than January 31, 2000, the requisite notice under Rule 23 with respect to the filing of this Application-Declaration, such notice to specify a date not later than February 28, 2000, by which comments must have been entered and a date on or after February 29, 2000, as the date when an order of the Commission granting and permitting this Application-Declaration to become effective may be entered by the Commission.
It is submitted that a recommended decision by a hearing or other responsible officer of the Commission is not needed for approval of the proposed Merger. The SEC Staff may assist in the preparation of the Commission's decision. There should be no waiting period between the issuance of the Commission's order and the date on which it is to become effective.
Item 6. Exhibits and Financial Statements
A. Exhibits
|
Exhibit Number |
|
|
|
A-1 |
Restated Articles of Incorporation of NSP (filed as EXHIBIT 3.01 to Form 10-Q of NSP for the quarter ended June 30, 1998, File No. 1-3034, and incorporated herein by reference) |
|
|
A-2 |
|
Restated Articles of Incorporation of NSP-W (filed as EXHIBIT 3.01 to Form 10-K of NSP-W for the year ended December 31, 1987, File No. 10-3140, and incorporated herein by reference) |
|
A-3 |
|
Restated Articles of Incorporation of NCE dated December 8, 1995 (filed as EXHIBIT 3(a) to Registration Statement No. 333-64951 on Form S-4, File No. 1-12927, and incorporated herein by reference) |
|
A-4 |
Amended and Restated Articles of Incorporation of PSCo dated July 10, 1998 (filed as EXHIBIT 3(a)1 to Form 10-K of PSCo for the year ended December 31, 1998, File No. 1-3280). |
|
|
A-5 |
Amended and Restated Articles of Incorporation of SPS (filed as EXHIBIT 3(a)2 to Form 10-K of SPS for the year ended December 31, 1997, File No. 1-3789). |
|
|
A-6 |
Certificate of Incorporation of NRG (filed as EXHIBIT 3.1 to Registration Statement on Form S-1 (as amended), File No. 333-33397). |
|
|
B-1 |
Agreement and Plan of Merger (Merger Agreement) (filed as Appendix A to Exhibit C-1, and incorporated herein by reference) |
|
|
B-2*** |
Form of Service Agreement between New Century Services and utility affiliates (an appendix entitled "Description of Services and Determination of Charges for Services" is attached but not forming a part thereof.) |
|
|
B-3*** |
Form of Service Agreement between New Century Services and non-utility affiliates (an appendix entitled "Description of Services and Determination of Charges for Services" is attached but not forming a part thereof) | |
| C-1 | Registration Statement of NSP on Form S-4 (as amended) (filed as Registration Statement No. 333-73989 and incorporated herein by reference) | |
| C-2 | Joint Proxy Statement and Prospectus of NSP and NCE (included in EXHIBIT C-1) | |
| D-1.1** | P | Original testimony of Heironymus to FERC |
| D-1.2** | P | Application of NSP and NCE before FERC |
| D-1.3*** | P | Order of FERC approving the Merger |
| D-1.4** | P | Original testimony of Gilbert to FERC |
__________
** Filed with Amendment No. 1
*** Filed with this Amendment
|
D-2.1** |
P |
Application of NSP before the Minnesota Commission |
| D-2.2**** | P | Order of the Minnesota Commission approving the Merger |
| D-3.1** | P | Application of NSP before the North Dakota Commission |
| D-3.2**** | P | Order of the North Dakota Commission approving the Merger |
| D-4.1** | P | Application of NSP before the Arizona Commission |
| D-4.2**** | P | Order of the Arizona Commission approving the Merger |
| D-5.1** | P | Application of NCE before the Colorado Commission |
| D-5.2**** | P | Order of the Colorado Commission approving the Merger |
| D-6.1** | P | Application of NCE before the New Mexico Commission |
| D-6.2**** | P | Order of the New Mexico Commission approving the Merger |
| D-7.1** | P | Application of NCE before the Wyoming Commission |
| D-7.2**** | P | Order of the Wyoming Commission approving the Merger |
| D-8.1** | P | Application of NCE before the Texas Commission |
| D-8.2**** | P | Order of the Texas Commission finding that the Merger is in the public interest |
| D-9**** | P | Order of the NRC finding that the transfer of certain operating licenses in connection with the Merger is in compliance with The Atomic Energy Act and consenting to such transfers |
| E-1** | P | Map of service areas of NSP, NSP-W, PSCo, SPS and Cheyenne |
| E-2** | P | Map showing interconnections of NSP, NSP-W PSCo, SPS and Cheyenne (see Exhibit E-1) |
| E-3.1** | P | Map of NSP electric and gas service areas |
| E-3.2** | P | Map of NSP-W electric and gas service areas |
| E-3.3** | P | Map of NSP and NSP-W transmission systems |
| E-4.1** | P | Map of PSCo electric and gas service areas (including Cheyenne electric and gas service areas) |
| E-4.2** | P | Map of SPS electric service areas (see Exhibit E-4.3) |
| E-4.3** | P | Map of PSCo and SPS transmission systems (including Cheyenne transmission system) |
| E-10** | P | NSP corporate chart |
| E-11** | P | NCE corporate chart |
| E-12***** | P | Combined Company corporate chart |
| E-13*** | Chart comparing MISO, NEPOOL and PJM | |
| F-1.1**** | Preliminary opinion of counsel to NSP | |
| F-1.2**** | Past-tense opinion of counsel to NSP | |
| F-2.1**** | Preliminary opinion of counsel to NCE | |
| F-2.1**** | Past-tense opinion of counsel to NCE | |
| G-1 | Opinion of SG Barr Devlin (filed as Annex B to Registration Statement No. 333-76989 on Form S-4 and incorporated herein by reference) | |
| G-2 | Opinion of The Blackstone Group L.P. (filed as Annex C to Registration Statement No. 333-76989 on Form S-4 and incorporated herein by reference) |
__________
**** To be filed by Amendment
***** Previously filed; revised and filed again
herewith
| H-1 | Annual Report of NSP on Form 10-K for the year ended December 31, 1998 (File No. 1-3034 and incorporated herein by reference) | |
| H-2 | Annual Report of NCE on Form 10-K for the year ended December 31, 1998 (File No. 1-23927 and incorporated herein by reference) | |
| H-3 | Annual Report of NSP-W on Form 10-K for the year ended December 31, 1998 (File No. 10-3140 and incorporated herein by reference) | |
| H-4 | Annual Report of NRG on Form 10-K for the year ended December 31, 1998 (File No. 333-33397 and incorporated herein by reference) | |
| H-5 | Annual Report of PSCo on Form 10-K for the year ended December 31, 1998 (File No. 1-3780 and incorporated herein by reference) | |
| H-6 | Annual Report of SPS on Form 10-K for the year ended December 31, 1998 (File No. 1-3789 and incorporated herein by reference) | |
| H-7 | Quarterly Report of SPS on Form 10-Q for the quarter ended March 31, 1999 (File No. 1-3789 and incorporated herein by reference) | |
| H-8 | Quarterly Report of SPS on Form 10-Q for the quarter ended June 30, 1999 (File No. 1-3789 and incorporated herein by reference) | |
| H-9 | Quarterly Report of NSP on Form 10-Q for the quarter ended March 31, 1999 (File No. 1-3034 and incorporated herein by reference) | |
| H-10 | Quarterly Report of NSP on Form 10-Q for the quarter ended June 30, 1999 (File No. 1-3034 and incorporated herein by reference) | |
| H-11 | Quarterly Report of NCE on Form 10-Q for the quarter ended March 31, 1999 (File No. 1-12927 and incorporated herein by reference) | |
| H-12 | Quarterly Report of NCE on Form 10-Q for the quarter ended June 30, 1999 (File No. 1-12927 and incorporated herein by reference) | |
| H-13 | Quarterly Report of NSP-W on Form 10-Q for the quarter ended March 31, 1999 (File No. 10-3140 and incorporated herein by reference) | |
| H-14 | Quarterly Report of NSP-W on Form 10-Q for the quarter ended June 30, 1999 (File No. 10-3140 and incorporated herein by reference) | |
| H-15 | Quarterly Report of NRG on Form 10-Q for the quarter ended March 31, 1999 (File No. 333-33397 and incorporated herein by reference) | |
| H-16 | Quarterly Report of NRG on Form 10-Q for the quarter ended June 30, 1999 (File No. 333-33397 and incorporated herein by reference) | |
| H-17 | Quarterly Report of PSCo on Form 10-Q for the quarter ended March 31, 1999 (File No. 1-3280 and incorporated herein by reference) | |
| H-18 | Quarterly Report of PSCo on Form 10-Q for the quarter ended June 30, 1999 (File No. 1-3280 and incorporated herein by reference) | |
| H-19 | Quarterly Report of NSP on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-3034 and incorporated herein by reference) | |
| H-20 | Quarterly Report of NCE on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12927 and incorporated herein by reference) | |
| H-21 | Quarterly Report of NSP-W on Form 10-Q for the quarter ended September 30, 1999 (File No. 10-3140 and incorporated herein by reference) | |
| H-22 | Quarterly Report of NRG on Form 10-Q for the quarter ended September 30, 1999 (File No. 333-33397 and incorporated herein by reference) |
| H-23 | Quarterly Report of PSCo on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-3280 and incorporated herein by reference) | |
| H-24 | Quarterly Report of SPS on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-3789 and incorporated herein by reference) | |
| I-1***** | Notice of the Transaction | |
| J-1***** | NSP and NSP-W Analysis of the Economic Impact of a Divestiture of the Gas Operations of NSP and NSP-W | |
| J-2*** | NCE Analysis of the Economic Impact of a Divestiture of NCE's Gas Operations | |
| J-3**** | Joint Analysis of the Economic Impact of a Divestiture of the Gas Operations of NCE, NSP and NSP-W | |
| K-1*** | Report of Pacific Economies Group |
__________
*
Filed with the
original Application-Declaration
*** Filed with this Amendment
**** To be filed by Amendment
***** Previously filed; revised and filed again herewith
| FS-1 | Unaudited Pro Forma Combined Condensed Consolidated Balance Sheet at March 31, 1999 (included in Form 10-Q for the quarter ended March 31, 1999 of NSP (Exhibit H-9 hereto) at p. 55) |
| FS-2 | Unaudited Pro Forma Condensed Consolidated Statements of Income for the three month periods ended March 31, 1999 and March 31, 1998 and for each of the three years in the period ended December 31, 1998 (included in Form 10-Q for the quarter ended March 31, 1999 of NSP (Exhibit H-9 hereto) at p. 53) |
| FS-3 | NSP Consolidated Balance Sheet as of December 31, 1998 see Annual Report of NSP on Form 10-K for the year ended December 31, 1998 (Exhibit H-1 hereto), at p. 41) |
| FS-4 | NSP Consolidated Statements of Income for its last three fiscal years (see Annual Report of NSP on Form 10-K for the year ended December 31, 1998 (Exhibit H-1 hereto), at p. 39) |
| FS-5 | NCE Consolidated Balance Sheet as of December 31, 1998 (see Annual Report of NCE on Form 10-K for the year ended December 31, 1998 (Exhibit H-2 hereto), at p. 45) |
| FS-6 | NCE Consolidated Statements of Income for its last three fiscal years (see Annual Report of NCE on Form 10-K for the year ended December 31, 1998 (Exhibit H-2 hereto), at p. 47) |
| FS-7 | NSP-W Consolidated Balance Sheet as of December 31, 1998 (see Annual Report of NSP-W on Form 10-K for the year ended December 31, 1998 (Exhibit H-3 hereto), at p. 22) |
| FS-8 | NSP-W Consolidated Statements of Income for its last three fiscal years (see Annual Report of NSP-W on Form 10-K for the year ended December 31, 1998 (Exhibit H-3) hereto), at p. 20) |
| FS-9 | NRG Consolidated Balance Sheet as of December 31, 1998 (see Annual Report of NRG on Form 10-K for the year ended December 31, 1998 (Exhibit H-4 hereto), at p. 25) |
| FS-10 | NRG Consolidated Statements of Income for it last three fiscal years (see Annual Report of NRG on Form 10-K for the year ended December 31, 1998 (Exhibit H-4 hereto), at p. 23) |
| FS-11 | PSCo Consolidated Balance Sheet as of December 31, 1998 (see Annual Report of PSCo on Form 10-K for the year ended December 31, 1998 (Exhibit H-5 hereto), at p. 57) |
| FS-12 | PSCo Consolidated Statements of Income for its last three fiscal years (an Annual Report of PSCo on Form 10-K for the year ended December 31, 1998 (Exhibit H-5), at p. 60) |
| FS-13 | SPS Consolidated Balance Sheet as of December 31, 1998 (see Annual Report of SPS on Form 10-K for the year ended December 31, 1998 (Exhibit H-6 hereto), at p. 69) |
| FS-14 | SPS Consolidated Statements of Income for its last three fiscal years (see Annual Report of SPS on Form 10-K for the year ended December 31, 1998 (Exhibit H-6 hereto), at p. 72) |
Item 7. Information as to Environmental Effects
The Merger neither involves "major federal actions" nor "significantly [affects] the quality of the human environment" as those terms are used in Section (2)(C) of the National Environmental Policy Act, 42 U.S.C. Sec. 4332. The only federal actions related to the Merger pertain to the Commission's declaration of the effectiveness of the Joint Registration Statement, the approvals and actions described under Item 4 and Commission approval of this Application-Declaration. Consummation of the Merger will not result in changes in the operations of NSP, NSP-W or NCE that would have any impact on the environment. No federal agency is preparing an environmental impact statement with respect to this matter.
SIGNATURE
Pursuant to the requirements of the Public Utility Holding Company Act of 1935, each of the undersigned companies has duly caused this Application-Declaration to be signed on its behalf by the undersigned thereunto duly authorized.
|
New Century Energies, Inc. |
Northern States Power Company |
| By:/s/ Richard C. Kelly> | By:/s/ E. J. McIntyre |
| Richard C. Kelly | E. J. McIntyre |
|
Executive Vice President and |
Vice President and |
|
Chief Financial Officer |
Chief Financial Officer |
Date: February 2, 2000
[1]Prior to completion of the Merger, NSP and NCE expect to file one or more additional applications-declarations under the Act with respect to ongoing activities (including financing activities) and other matters pertaining to Xcel after the Merger.
[2]Northern States Power Company, et al., 90 FERC ¶ 61,020 (2000) (herein, the "FERC Merger Order").
[3]The Merger Agreement provides that NSP shall not be obligated to undertake the above restructuring if it would cause a NSP Material Adverse Effect as defined in that document, and, if a NSP Material Adverse Effect would result, the parties must negotiate in good faith an alternative to the restructuring.
[4]As noted below, SPS is required to restructure to comply with restructuring legislation enacted in Texas and New Mexico. However, it is expected that such restructuring will take place subsequent to the Commission's action on this application. Any necessary authorizations of the Commission to implement the SPS restructuring will be requested at the appropriate time in a separate application.
[5] Presently pending before the Commission is NSP's application for approval to transfer the assets and operations of BMG to a subsidiary of NSP (File No. 70-09337). NSP's intent is to accomplish the transfer of such assets promptly upon receipt of the necessary regulatory approvals. If these approvals are obtained prior to consummation of the Merger, BMG will be Xcel's sixth public-utility subsidiary company.
[6]In the event that a different corporate structure is adopted, Applicants will file a revised version of EXHIBIT E-12 by amendment. Moreover, to give the Xcel system maximum flexibility to reorganize its non-utility operations in the future and to eliminate unnecessary burden on the Commission, Applicants intend through a separate application to make a request for blanket authority to reorganize Xcel's non-utility subsidiaries and to establish new intermediate holding companies, similar to what the Commission has authorized for other registered systems. See Columbia Energy Group, Holding Co. Act Release No. 27099 (Nov. 5, 1999).
[7]In the 1997 NCE Order, the Commission noted that: "In the event that New Century Energies at any time determines not to construct the tie, or the tie is not substantially completed within five years of the date of consummation of the [PSCo/SPS] merger, New Century Energies will file a post-effective amendment concerning the measures it will take to ensure that the requirements of section 2(a)(29)(A) are satisfied." The Applicants believe that completion of first phase (the Amarillo Holcomb line) will result in substantial completion of the tie line.
[8]In April 1999, SPS submitted an application to the Kansas Commission requesting a siting permit in Kansas for construction of both the Amarillo-Holcomb line and the Holcomb-Lamar line. Kansas is the state where the longest portion of the two lines will be constructed. SPS has completed the detailed routing and environmental assessment of the proposed location of the lines. Public conferences have been held in Colorado, Kansas, Oklahoma and Texas to present information to affected landowners and receive their input. Hearings on the Kansas application were held in June 1999 and, on July 16, 1999, the Hearing Examiner in the proceeding recommended to the Kansas Commission that the location of the lines was reasonable. The Hearing Examiner recommended approval of the requested Siting Permit, KCC Docket No. 99-SWPE-764-MIS. The Kansas Commission recently affirmed the Hearing Examiner's order. In the Matter of the Application of Southwestern Public Service Company for a Siting Permit, Docket No. 99‑SWPE‑764‑MIS (KCC July 19, 1999).
[9]As noted above, Cheyenne currently makes no wholesale sales of electricity.
[10]As part of the merger integration process, Applicants are in the process of reviewing the forms of service agreement. It is therefore possible that Applicants may propose to revise them in the future. In that event, Applicants will submit the revised forms of agreement by amendment in this proceeding.
[11]The electric production and transmission costs of NSP and NSP-W are shared by them. The cost-sharing arrangement between the companies is referred to as the Interchange Agreement. It is a FERC-regulated agreement and has been accepted by the Wisconsin Commission and the Minnesota Commission for determination of costs recoverable by NSP-W and NSP in rate cases.
[12]In this table, Electric Utility revenues are the revenues derived by NSP and NSP-W from each company's operations as an "electric utility company" as defined in Section 2(a)(3) under the Act, and Gas Utility revenues are the revenues derived by NSP and NSP-W from each company's operations as a "gas utility company" under Section 2(a)(4) of the Act. These amounts do not conform to NSP's consolidated financial statements, as the consolidated financial statements reflect eliminations of intercompany revenues among NSP and its consolidated subsidiaries, and NSP reports, in its consolidated financial statements: (i) the revenues of its wholly-owned regulated natural gas interstate pipeline (Viking) as part of Gas Utility revenues, (ii) the revenues of its other consolidated subsidiaries as part of "Other Income (Deductions)," and (iii) the results of the operations of its non-consolidated subsidiaries under "Equity in Earnings of Unconsolidated Affiliates."
[13]Id .
[14]Each NCE Right entitles the registered holder to purchase from NCE one one-hundredth of a share of Series A Junior Participating Preferred Stock. The NCE Rights were distributed as a dividend on each outstanding share of NCE Common Stock as part of NCE's shareholder rights plan which was approved by the Commission in New Century Energies, Holding Co. Act Release No. 26751 (Aug. 1, 1997).
[15]To be filed by amendment.
[16] Section 1(b)(4).
[17] Similarly, to the extent that NCE could be deemed to sell utility securities or assets, it would require approval under Section 12.
[18]The Applicants acknowledge the requirements of Section 17(c) of the Act and Rule 70 thereunder with respect to limitations upon directors and officers of registered holding companies and subsidiary companies thereof having affiliations with commercial banking institutions and investment bankers and undertake that, upon completion of the Merger, they will be in compliance with the applicable provisions thereof.
[19]U.S. Securities and Exchange Commission, Financial and Corporate Report, Holding Companies Registered under the Public Utility Holding Company Act of 1935 as of July 1, 1999 (data provided is as of December 31, 1998); Northern States Power Company 1998 Annual Report; NCE 1998 Annual Report.
[20]16 U.S.C. §824b(a). The factors that FERC focuses on in making this public interest determination are set out in its Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement, Order No. 592, 61 Fed. Reg. 68,595 (1996), reconsideration denied, Order No. 592-A, 62 Fed. Reg. 33,341 (1997).
[21]While Applicants have committed to certain market mitigation in the NSP destination market, this was done to allay any potential concerns about the impact of the Merger on competition.
[22]FERC Merger Order, slip op. at 23 (emphasis added).
[23]Id. at 21.
[24]This Application only requests authorization to retain such preferred stock. Any proposed issuance of additional preferred stock will be addressed in a separate application.
[25]Under section 7(d)(1) of the Act, the Commission generally has required a registered holding company system and its public-utility subsidiaries to maintain a 65/30 debt/common equity ratio, the balance generally being preferred equity. Such debt/equity capitalization requirement was included in rule 52, as originally adopted, as applied to securities issued by public-utility subsidiaries, but was eliminated in 1992.
[26]The Commission's decision was predicated on the completion of the tie line between the SPS and PSCo systems or on the parties' otherwise satisfying the requirements of section 10(c)(1). The status of the tie line has been discussed above.
[27] Union Electric Co., Holding Co. Act Release No. 18368, n. 52 (1974), quoted in Consolidated Natural Gas Co., Holding Co. Act Release No. 26512 (April 30, 1996) (authorizing international joint venture to engage in energy marketing activities); Eastern Utilities Associates, Holding Co. Act Release No. 26232 (Feb. 15, 1995) (removing restrictions on energy management activities); and Southern Co., Holding Co. Act Release No. 25639 (Sept. 23, 1992) (approving acquisition of foreign public-utility subsidiary company).
[28]Rust v. Sullivan, 500 U.S. 173 (1991); American Trucking Assns., Inc. v. Atchison, T.&S.F.R. Co., 387 U.S. 397 (1967); Shawmut Assn. v. SEC, 146 F.2d, 791 (1st Cir. 1945); Sempra Energy, Holding Company Act Release No. 27095 (Oct. 25, 1999).
[29] NIPSCO Industries, Inc., Holding Co. Act Release No. 26975 (Feb. 10, 1999) [hereinafter "NIPSCO"], citing Rust v. Sullivan at 186-187. Accord, Sempra Energy, Holding Co. Act Release No. 26971 n.23 (Feb. 1, 1999) (interpreting the integration standards of the 1935 Act in light of developments in the gas industry).
[30] NIPSCO, supra, citing Shawmut Assn. v. SEC at 796-97.
[31] 1995 Report at 71.
[32] Union Electric, supra.
[33] Cf. Sempra Energy, Holding Company Act Release No. 27095 (Oct. 25, 1999) ("The application notes that the concept of a 'common source of supply' is susceptible of a different understanding today than in 1935.").
[34] In the FERC Merger Order, the FERC stated "Upon joining MISO following consummation of the merger, Xcel Energy's northern zone, consisting of New NSP Utility and NSP-W, will be physically interconnected with its southern zone, consisting of SPS, through the transmission system of MISO."
[35] PSCo will be interconnected with the combined SPS and NSP company systems upon the completion of its announced tie-line with SPS.
[36]The Applicants further believe that the Commission could find (i) that the Xcel Gas System is the primary integrated system and that the NCE Primary System, the Cheyenne Electric System and the NSP Electric Operations are retainable additional systems, or (ii) that the Xcel Gas and Electric Systems together constitute a single integrated public utility system within the meaning of Section 11(b)(1) of the Act, and the Cheyenne Electric System is a retainable additional system. The Applicants reserve the right to supplement this Application-Declaration to develop these arguments fully in the event that the Commission or the Staff reject the argument that the Xcel Electric System will be the primary integrated public-utility system for purposes of Section 11(b)(1), and the Xcel Gas System and the Cheyenne Electric System are permissible systems under the A-B-C clauses of that section.
[37]The Commission interprets the 1935 Act and its integration standards "in light of . . . changed and changing circumstances." Sempra Energy, Holding Co. Act Release No. 26971 (Feb. 1, 1999) (interpreting the integration standards of the 1935 Act in light of developments in the gas industry). Accord, NIPSCO.
[38]Energy Information Administration, Department of Energy, The Changing Structure of the Electric Power Industry: An Update at 5.
[39]See Comments by Commissioner Curtis L. Hebert, New Orleans, LA ISO Conf., F.E.R.C. Docket No. PL 98‑5‑000, Tr. at 2 (June 1, 1998); 1995 SEC Staff Report on the Regulation of Public Utility Holding Companies at 59. See also Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Notice of Proposed Rulemaking, FERC Stats. & Regs., Proposed Regulations, ¶ 32,514 (1995) ("Mega-NOPR"), wherein FERC described the electric industry in 1935, the year of enactment of both the Act and the Federal Power Act, which was a companion piece of legislation to the Act, as follows:
The Federal Power Act was enacted in an age of mostly self-sufficient, vertically integrated electric utilities, in which generation, transmission, and distribution facilities were owned by a single entity and sold as part of a bundled service (delivered electric energy) to wholesale and retail customers. Most electric utilities built their own power plants and transmission systems, entered into interconnection and coordination arrangements with neighboring utilities, and entered into long-term contracts to make wholesale requirements sales (bundled sales of generation and transmission) to municipal, cooperative, and other investor-owned utilities (IOUs) connected to each utility's transmission system. Each system covered limited service areas. This structure of separate systems arose naturally due primarily to the cost and technological limitations on the distance over which electricity could be transmitted.
Mega-NOPR at 33,059.
[40] There were 2,974 miles of high voltage transmission in 1940, 8,174 miles in 1950, 22,379 miles in 1960, and 65,370 miles in 1970. Peter Fox-Penner, Electric Utility Restructuring, A Guide to the Competitive Era (1997) at 130.
[41] See William J. Baumol & J. Gregory Sidak, Transmission Pricing and Stranded Costs in the Electric Power Industry (1995) at 13.
[42] Technological advances have occurred with respect to the "size" of transmission lines (345 kV to 765 kV lines) which have allowed for the transfer of large amounts of power over great distances. Technological advances have also occurred with respect to the "type" of transmission lines. High-voltage direct current ("HVDC") technology provides the ability to transmit bulk power over longer distances with less energy loss and normally with a smaller investment than with alternating current ("AC") transmission lines. This technology provides an economical way to interconnect separated AC power grids and enables power transfers to occur between these systems, thus improving economies and reliability. The application of phase shifting transformers, series compensation, and flexible alternating current transmission system ("FACTS") technology has also provided the ability to improve and control the transfer of power and energy across expansive transmission networks. New flexible alternating FACTS technology can increase the capacity of existing transmission lines by approximately 20 to 40 percent. Electricity: Innovation and Competition, Hearing Before the Subcomm. of Energy and Power of the House Comm. on Commerce, 105th Cong. 38 (1997) (statement of Robert B. Schainker, Manager, Substations, Transmissions and Substation Business Area Power Delivery Group, Electric Power Research Institute). Such technology "help[s] electric utilities operate their bulk power networks closer to their inherent thermal limits, while maintaining and/or improving network security and reliability. Id. Advances in telecommunications and computer technology have improved the ability to economically dispatch power systems and control power flow across such systems. Improvements in telecommunication technology and the growth in coverage area of telecommunications systems have allowed for the quick and reliable transfer of data necessary to control and dispatch from a single location generation that can be scattered over large geographic areas. The improvements provided by fast and reliable telecommunication networks allow for the control and economic dispatch of power systems that extend over large geographic areas, providing system operators an almost real time ability to monitor and control the power system. Significant improvements in transmission and resource planning have also occurred since 1935. There are several software packages available today that enable the system planner to model the operation of most of the equipment used on a power system. Studies can be performed that not only evaluate power transfer capabilities, but also allow the system planner to add different types of equipment to determine their impact on increasing power transfer capabilities. Development of such software has enabled the system planner to determine what equipment functions best as well as where and when it should be installed. Further technological advances can be expected in the future as "power engineers" explore the potential for computers to optimize the efficiency and reliability of the North American power network. Leslie Lamarre, The Digital Revolution, EPRI Journal, (Jan./Feb. 1998).
[43] FERC has noted that "the entire Eastern interconnection is, as the name indicates, interconnected." North American Electric Reliability Council, 87 FERC ¶ 61,161 (1999).
[44] PURPA Section 210. 16 U.S.C. § 824a-3.
[45] PSCo, which has installed capacity of more than 3,000 MW, purchases over 600 MW of capacity and associated energy from QFs pursuant to long-term agreements.
[46]See , e.g., Commonwealth Atlantic Limited Partnership, 51 F.E.R.C. ¶ 61,368 (1990).
[47]Pub. L. No. 102-486, 106 Stat. 2776 (1992).
[48] PURPA also included a provision that allowed the Commission to order wheeling for power generated by a third party under certain narrowly-defined circumstances. However, FERC quickly interpreted this already limited authority very conservatively. See Southeastern Power Administration v. Kentucky Utilities Co., 20 F.E.R.C. ¶ 61,204 (1983) (holding that the Commission could not order wheeling if the wheeling order would result in a disturbance of existing market patterns, and holding that Section 211 of the FPA, as added by PURPA, was not designed to remedy a utility's anticompetitive conduct). EPACT amended sections 211 and 212 of the FPA to expand the Commission's authority to order wheeling upon application. 16 U.S.C. §§ 824j, 824k.
[49] The NSP companies, PSCo and SPS all have been granted market rate authority and participate actively in wholesale markets. The NCE system also has a wholesale power marketer, e prime.
[50] One commentator has described this unequal transmission access as follows:
For more than 100 years, electric companies operated as separate, regulated monopolies producing, transmitting and distribution electricity to their own customers or native load. The utilities were virtual islands unto themselves with no competition and minimal risk. To help ensure a reliable supply of electricity when generators were down for maintenance or during period of peak demand for electricity and other shortages, neighboring utilities installed connections between their individual transmission systems or control areas. Power could now flow from one neighboring utility to another. As these connections expanded, they eventually formed a complex "grid" of transmission systems or control areas capable of transmitting electricity across must longer distances. Utilities also faced another challenge, wholesale competition. Suddenly your neighboring utilities could buy electricity at potentially lower prices from another, more distant supplier. That meant lost business and lost income from your company. One way to reduce this threat was to set the price for access to your company's transmission system so high that it discouraged other utilities from wheeling power across your territory. The result was that distant power suppliers often found it difficult if not physically impossible to wheel their electricity to your neighbors. You could also thwart competition by withholding information about transmission pricing and availability, or the hours when your system had sufficient capacity to handle the additional flow of electricity.
Nelson, Kenneth C., "The New World of Power Marketing," Management Quarterly, v. 40, pages 13-42 (Spring 1999).
[51] 70 FERC ¶ 61,357 (1995).
[52] Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Service by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, FERC Stats. and Regs., Regulations Preambles, ¶ 31,036 (1996) ("Order No. 888"), order on rehearing, FERC Stats. & Regs., Regulations Preambles, ¶ 31,048 (1997) ("Order 888-A"), order on rehearing, 81 FERC ¶ 61,248 (1997) ("Order 888-B"), order on rehearing, 82 FERC ¶ 61,046 (1998) ("Order 888-C").
[53]FERC has explained what it means by comparability:
an open access tariff that is not unduly discriminatory or anticompetitive should offer third parties access on the same or comparable basis, and under the same or comparable terms and conditions, as the transmission provider's uses of its system.
67 FERC at 61,490.
[54] "Wheeling" is the provision of transportation by a hub operator from one system to another system.
[55] Moreover, FERC in Order No. 888 required tight power pools (or their individual members) both to file open-access transmission tariffs and to file revised pooling agreements by December 31, 1996. With respect to the latter requirement, FERC required that the reformulated power pooling agreements establish, among other things, open, non-discriminatory membership provisions, that would allow any bulk power market participant to join a power pool, irrespective of its type, affiliations with other entities, or geographic location. In Order No. 888, FERC expressly noted that the reformation of tight power pools could be achieved through the establishment of an ISO to supplant the tight power pool. As a result of this encouragement and FERC's requirements, the three primary tight power pools - Pennsylvania-New Jersey-Maryland Interconnection ("PJM"), New York Power Pool ("NYPP"), and New England Power Pool ("NEPOOL") - have restructured into ISOs, and have significantly modified their operations.
[56] Open Access Same-Time Information System (formerly Real-Time Information Network) and Standards of Conduct, Order No. 889, [1991-1996 Transfer Binder] F.E.R.C. Stats. & Regs., Regs. Preambles ¶ 31,035, at 31,585 (1996), order on reh'g, Order No. 889-A, III F.E.R.C. Stats. & Regs., Regs. Preambles ¶ 61,253 (1997).
[57]The information to be posted on an OASIS includes the following: transmission capability that is available on both a firm and nonfirm (i.e., interruptible) basis; descriptive information regarding specific transmission requests and transactions including the point of receipt and delivery on the transmitting utility's system, the term of service, the level (i.e., number of MWs) and quality (i.e., firm or nonfirm) of service, and whether the service is provided for the benefit of a transmitting utility's associated wholesale merchant function or to an affiliate; whether any transmission services have been offered at a discounted rate; and notices regarding transmission curtailments or interruptions.See 18 C.F.R. § 37.6.
[58]Order No. 888.
[59]One commentator has recently described the ramifications of the more competitive wholesale markets resulting from the enactment of EPACT and the issuance of Order Nos. 888 and 889 as follows:
What resulted is a highly competitive and sophisticated 24-hour power market . . .
Next we examine what happens in "real-time" . . . . Economic power schedulers, working in the front office, monitor the utility's entire real-time system, making sure that the planners have accurately matched the power supply assets with the hourly demand or native load. Economic power schedulers also make sure that the planners have utilized the least expensive power supply assets. Schedulers may also make adjustments to the power plan in order to maximize the goals of reducing costs, providing customers with the lowest possible wholesale prices. To make these adjustments, economic power schedulers rely on available power supply assets and the hourly or "spot" market. Unexpected changes in the weather, mechanical problems at the generating station and congestion on the transmission grid are only a few of the factors that can result in deviations from the planner's schedule. Let's assume the scheduler needs an additional 10 MW of power for two hours, one hour from now. He or she, depending on the level of sophistication of the company, may consult a data screen that displays the real-time spot-market price and the incremental cost of generation or the cost of producing the additional or next 10 MW of electricity.
If the incremental cost of generation is less than the market price, the power scheduler may ask the generating plant to increase production or start a peaking unit. If the price of power from pre-existing contracts is less than the spot market price or generation, the scheduler may draw upon the amount of electricity stipulated in the contract. But if the spot market price is less than the incremental cost of generation or contract power, the scheduler may notify the traders in the "front office." They immediately go to the spot market and begin the buying process.
The economic power scheduler may also find that the utility is "long" on power or has excess capacity for several hours. The traders may now begin the selling process. Trading in the spot market has the same requirements as day-ahead, weekly and monthly trading except that it happens at a much faster pace. Spot market trading averages less than 20 minutes for securing a buyer or seller scheduling transmission or obtaining an NERC tag, applying competitive intelligence and price and credit risk management, confirming the trade and notifying billing, finance and accounting in the "back office."
Nelson, Kenneth C., "The New World of Power Marketing," Management Quarterly, v. 40, pp. 13-32 (Spring 1999).
[60]Order No. 2000 at 13.
[61] Although FERC Order No. 888 did not require the formation of ISOs, it did encourage their formation and set out the minimal characteristics that an ISO should have. As set out in Order No. 888, these characteristics are as follows: (i) an ISO's governance should be structured in a fair and non-discriminatory manner; (ii) an ISO and its employees should have no financial interest in the economic performance of any power market participant, an ISO should adopt and enforce strict conflict of interest standards; (iii) an ISO should provide open access to the transmission system and all services under its control at non-pancaked rates pursuant to a single, unbundled, grid-wide tariff that applies to all eligible users in a non-discriminatory manner; (iv) an ISO should have the primary responsibility in ensuring short-term reliability of grid operations, its role in this responsibility should be well-defined and comply with applicable standards set by the North American Electric Reliability Council and the regional reliability council; (v) an ISO should have control over the operation of interconnected transmission facilities within its region; (vi) an ISO should identify constraints on the system and be able to take operational actions to relieve those constraints within the trading rules established by the governing body, these rules should promote efficient trading; (vii) the ISO should have appropriate incentives for efficient management and administration and should procure the services needed for such management and administration in an open competitive market; (viii) an ISO's transmission and ancillary services pricing policies should promote the efficient use of and investment in generation, transmission, and consumption, an ISO or a regional transmission group of which the ISO is a member should conduct such studies as may be necessary to identify operational problems or appropriate expansions; (ix) an ISO should make transmission system information publicly available on a timely basis via an electronic information network consistent with FERC's requirements; (x) an ISO should develop mechanisms to coordinate with neighboring control areas and (xi) an ISO should establish an alternative dispute resolution process to resolve disputes in the first instance. FERC's principles were intended to ensure that ISOs will have operational control over participating members' transmission systems and operate such systems in a non-discriminatory manner for the benefit of all market participants.
[62]FERC justified the aggressive timetable on the basis that "given the urgent needs of electricity markets as discussed elsewhere in our Final Rule, we have an obligation to promote RTO operation at the earliest feasible date." Order No. 2000 at 670.
[63]FERC added the interregional coordination function in Order No. 2000 in order to assure that "seams" issues between RTOs (or between RTOs and areas where there is not yet an RTO) are adequately addressed. As FERC stated in Order No. 2000, "[c]oordination of activities among regions is a significant element in maintaining a reliable bulk transmission system and for the development of competitive markets." Order No. 2000 at 494.
[64]FERC stated in Order No. 2000 that it is "concerned that the traditional approaches to operating the grid are showing signs of strain. Order No. 2000 at 16. FERC also quoted the North American Electric Reliability Council's ("NERC") statement that "the adequacy of the bulk transmission system has been challenged to support the movement of power in unprecedented amounts and in unexpected directions." Order No. 2000 at 16. FERC further observed in Order No. 2000 that the successes of its own policies have caused these stresses to the transmission grid:
The availability of tariffs and information about the transmission system has fostered a rapid growth in dependence on wholesale markets for acquisition of generation resources. . . . Power resources are now acquired over increasingly large regional areas, and interregional transfers of electricity have increased. The very success of Order Nos. 888 and 889, and the initiative of some utilities that have pursued voluntary restructuring beyond the minimum open access requirements, have placed new stresses on regional transmission systems - stresses that call for regional solutions.
Order No. 2000 at 13-14. See also Order No. 2000 at 1-2.
[65]As FERC explained in the RTO NOPR:
The scheduling of power by multiple utilities over a regional grid can lead to unexpected overloads on constrained facilities. This can be a serious barrier to competitive power trading because some power sale transactions may be have to be curtailed. With a regional scope, an RTO would be better able to mange congestion. An RTO would be in a better position to prevent congestion or control it through application of appropriate region wide congestion pricing to ration use of the grid if necessary. An RTO would also more readily identify schedules that could lead to congestion, and relieve congestion through regional redispatch authority.
RTO NOPR at 33,716.
[66]The FERC explained this in the RTO NOPR:
Conditions on all parts of the regional grid affect ATC on individual utility systems. Factors such as load estimates, generation and transmission outages, generation dispatch orders and transactions on individual systems can affect the determination of ATC. An individual utility may not have complete or timely information regarding such factors and may apply assumptions and criteria in its ATC estimates that are different from those of neighboring transmission operators, leading to wide variations in ATC values for the same transmission path. . . .
An RTO would produce better ATC estimates because it would have access to complete regional usage information, would have current information because the RTO will be the security coordinator as well as the OASIS site administrator, and would calculate ATC values on a consistent region-wide basis using a regional flow model.
RTO NOPR at 33,716.
[67]RTO NOPR at 33,717.
[68]"One advantage of an RTO that is helpful in planning is that it will be able to see the 'big picture.' Planning and expansion of grid facilities will no longer be done on a piecemeal basis." RTO NOPR at 33,717.
>[69] Order No. 2000 at 3. See also Order No. 2000 at 62-63, at which FERC noted, "There is substantial agreement among commenters that most of the engineering and economic obstacles identified by the NOPR arise from the current industry structure and can be rectified through development of regional transmission entities."
[70]RTO NOPR at 33,703.
[71]RTO NOPR at 33,716 (footnote omitted).
[72]RTO NOPR at 33,717.
[73] Indeed, FERC in Order No. 888 invoked the widely-differing cost of utility-generated electricity across the major regions of the country as evidence of the need for reform. Order No. 888 at 31,651-52.
[74]See also Order No. 2000 at 516 ("A main reason that an RTO can expand the marketplace for generation to a large region is that an RTO can implement non-pancaked rates for each transaction. A wider area served by a single rate means more generation is economically available to any customer which means greater competition for energy.")
[75]As stated previously under Item 1.C.2., NSP recently submitted a request for bids for up to 1,200 MW of capacity.
[76]Order No. 2000 at 14.
[77]As noted previously, Applicants do not in this application request the necessary authorizations to implement SPS's compliance plan. Any necessary authorizations of the Commission to implement the SPS compliance plan will be requested at the appropriate time in a separate application.
[78]RTO NOPR at 33,693.
[79] Midwest Independent Transmission System Operator, Inc., 84 FERC ¶ 61,231 ("MISO Order"), reconsidered and clarified, 85 FERC ¶ 61,250 ("MISO Clarification"), order on rehg, 85 FERC ¶ 61,372 (1998) ("MISO Rehearing Order"). In accordance with Order No. 2000, those utilities participating in MISO, individually or jointly with other entities, must submit a filing with FERC by January 15, 2001 explaining how MISO has the characteristics and performs the functions of RTOs as set out in the final RTO rule. See Order No. 2000 at 708.
[80]See the MISO Orders.
[81] Bundled retail load is excluded from service under the MISO Tariff during the Transition Period.
[82]In Order No. 2000 at 277 n.397, FERC noted:
As we have stated before, the dividing line "between transmission control and generation control is not always clear because both sets of functions are ultimately required for reliable operation of the overall system." Midwest ISO, 84 FERC at 62,151. The idea that the entity that controls the transmission system must have some degree of control over some generation seems to be generally recognized.
See also Order No. 2000 at 318 ("In order to maintain the reliability of the transmission system, the entity that controls transmission must also have some control over some generation") and at 422 ("All generators or other facilities that provide ancillary services must be subject to direct or indirect operational control by the RTO").
[83]See ER98-1438-000, Applicants Response at 3.
[84]MISO Order at 62,162.
[85]Id .
[86]Id .
[87]As noted previously, this result was recognized by FERC in its Order No. 2000 at 516, where FERC stated: "A main reason that an RTO can expand the marketplace for generation to a large region is that an RTO can implement non-pancaked rates for each transaction. A wider area served by a single rate means more generation is economically available to any customer which means greater competition for energy."
[88]There are gaps in the contiguous borders of MISO; however, any charges incurred for flows across those borders would produce a relative small cost differential when compared with a traditional rate pancake across multiple service territories; as a consequence, the transactions will still be economically feasible. In fact, there is currently an intervening utility between SPS and MISO. As explained below, SPS intends to obtain a contract path across the intervening utility service area so that it is interconnected directly with MISO, although the need for this path may be obviated in the event that the presently contemplated combination of MISO and SPP reaches fruition.
[89]FERC Merger Order at 5.
[90]The NSP companies have agreed to join MISO irrespective of the consummation of the Merger. SPS's commitment to join MISO is contingent upon the consummation of the Merger.
[91] Applicants engaged Dr. Ricardo Austria of Power Technologies, Inc. ("PTI") to aid in analyzing potential impediments to their interconnection plans. Based on his analysis, Applicants anticipate that PSO does not presently have sufficient capacity to grant the full request of 200 MW for the MISO Interconnection. Specifically, the 200 MW reservation would have an adverse impact on a "flowgate" located in eastern Oklahoma. However, Dr. Austria's analysis shows that ATC at the affected flowgate can be upgraded to accommodate the full request if a transmission reinforcement consisting of a 25-mile 345 kV line is constructed from Pecan Creek to Riverside ("Pecan Line"). Dr. Austria also determined that obtaining 200 MW of ATC on the west-bound portion of the path during winter months would require redispatch of the Western Resources and Sunflower systems.
[92]Also, the Northbound Path (like virtually every firm contract path) has some market concentrating effects as a result of the loop-flows, as well as market de-concentrating effects. For this reason, Applicants initially supported the Northbound Path as a separate option from MISO in their filing for FERC approval of the Merger. If FERC had not approved the Northbound Path without a hearing, the Applicants would have requested FERC and the SEC to approve the Merger without the Northbound Path. The issue is now moot as the FERC unconditionally approved the Merger without a hearing.
[93] Cheyenne is not a part to the Joint Operating Agreement as it does not operate any generation assets or make any wholesale sales. Thus, Cheyenne has no owned generation resources subject to integration as a result of the Merger.
[94]See , e.g., Northeast Utilities, Holding Co. Act Release No. 25221 (Dec. 21, 1990) ("Northeast Utilities") at n.85, supplemented, Holding Co. Act Release No. 25273 (Mar. 15, 1991), aff'd sub nom. City of Holyoke v. SEC., 972 F.2d 358 (1992) (Northeast had the right to use a Vermont Electric line for ten years, with automatic two-year extensions, subject to termination upon two years notice, in order to provide power to a Northeast affiliate.); Centerior Energy Corp., Holding Co. Act Release No. 24073 (1986) (Cleveland Electric Illuminating Company and Toledo Edison Company were connected by a line owned by Ohio Edison. All three were members of the Central Area Power Coordination Group ("CAPCO"). The line connecting Cleveland Electric, Ohio Edison and Toledo was a CAPCO line with segments owned by each of the three named utilities.); Cities Service Power & Light. Co., 14 S.E.C. 28, 53 n.44 (1943) (two companies in the same holding company system were found to be interconnected where energy was transmitted between two separated parts of the system over a transmission line owned by the United States Bureau of Reclamation, under an arrangement which afforded the system the privilege of using the line).
[95] See AEP, supra ("The pooling issue is one aspect of the major debate, . . . as to what should be the future structure of the electric utility industry. We will not undertake to resolve these issues since they are beyond our mandate in this case and because they are within the province of the Congress and the Department of Energy.").
[96See , e.g., UNITIL Corp., supra (interconnection through NEPOOL), and Conectiv, Inc., Holding Co. Act Release No. 26382 (Feb. 25, 1998) (interconnection through PJM, Inc.). See also Yankee Atomic Elec. Co., 36 S.E.C. 552, 565 (1955); Connecticut Yankee Atomic Power Co., 41 S.E.C. 705, 710 (1963) (authorizing various New England companies to acquire interests in a commonly-owned nuclear power company and finding the interconnection requirement met because the New England transmission grid already interconnected the companies).
[97]Such findings would also appear consistent with Applicants' position in their FERC application and the following statement in the FERC Merger Order: "Upon joining MISO following consummation of the merger, Xcel Energy's northern zone, consisting of New NSP Utility and NSP-W, will be physically interconnected with its southern zone, consisting of SPS, through the transmission system of MISO."
[98]New England Power Pool, 79 FERC ¶ 61,374 (1997); New England Power Pool, 83 FERC ¶ 61,045 (1998).
[99]MISO differs from how NEPOOL was initially structured as a tight power pool in that NEPOOL provided for centralized dispatch, within a single routed area, of the generating assets of the NEPOOL members. However, as explained below, this difference is not relevant to whether two entities are "physically interconnected or capable of physical interconnection."
[100] Under FERC Tariff No. 4, Fitchburg would receive firm transmission service. Amendment No. 11 to Form U-1 of UNITIL Corporation, File No. 70-7628, at 55.
[101] Pennsylvania - New Jersey - Maryland Interconnection, 81 FERC ¶ 61,257 (1998).
[102]The relationship between physical interconnection and coordinated system is examined in The North American Co., 11 S.E.C. 194, at 241-42 (1942). The only physical interconnection between four small service areas and a North American subsidiary, Illinois Iowa Power Co., was through facilities operated by Central Illinois Public Service Co., a nonaffiliated company. The small properties were held to be physically interconnected with the subsidiary but not part of a coordinated system because most or all of the power for sale in these service areas was purchased from Central Illinois and there was no central control: "Thus, even though we find physical interconnection exists or may be effected, evidence is necessary that in fact the isolated territories are or can be so operated in conjunction with the remainder of the system that central control is available for the renting of power." Moreover, as previously noted, NEPOOL and PJM have restructured into ISOs. Indeed, both organizations have established or are in the process of establishing associated power exchanges.
[103] See also MISO Order, supra at n.162 and n.169.
[104]This philosophy is consistent with the treatment of affiliate transactions involving non-power goods and services, which are subject to the Commissions' jurisdiction under Section 13 of the Act. See, e.g. , Rule 88(a) (service companies required to be so organized as to be able to provide services, construction, or goods "at a reasonable saving over the cost of comparable services or construction performed or goods sold by independent persons").
[105]The Joint Operating Agreement (Schedule D) also vests New Century Services as the Agent under the Joint Operating Agreement with the authority to acquire the necessary transmission services for wholesale marketing activities with non-affiliates and the system transactions described above.
[106]MISO Order at 62,162.
[107] Id.
[108] Id.
[109]In considering size, the Commission has consistently found that utility systems spanning multiple states satisfy the single area or region requirement of the 1935 Act. For example, the Entergy system covers portions of four states (Entergy, supra), the Southern system provides electric service to customers in portions of four states (Southern Co., Holding Co. Act Release No. 24579 (Feb. 12, 1988)), and the principal integrated system of NCE covers portions of five states (with all of its electric operations serving customers in six states) (1997 NCE Order, supra ). As early as 1945, the Commission found that the operations of American Electric Power in seven states were confined to a single region or area. American Gas and Electric Co., Holding Co. Act Release No. 6333 (Dec. 26, 1945).
[110] See, e.g., Conectiv, supra; cf. 1997 NCE Order, supra (integration test was met where entities planned to build a 300 mile transmission line to interconnect the systems which operated in noncontiguous territories).
[111]In Gaz Metropolitain, Inc., the Commission agreed that a single area or region could include areas across international borders. Holding Co. Act Release No. 26170 (Nov. 23, 1994).
[112]RTO NOPR, FERC Stats & Regs at 33,716. See also Order No. 2000 at 516, where FERC stated: "A main reason that an RTO can expand the marketplace for generation to a large region is that an RTO can implement non-pancaked rates for each transaction. A wider area served by a single rate means more generation is economically available to any customer which means greater competition for energy."
[113]In fact, under the MISO bylaws it may be possible for NSP and SPS to be part of a single zone in which case there would be no incremental cost of transmission (or no wheel) for exchanges of power between them.
[114] Sempra Energy, Holding Co. Act Release No. 26890 (June 26, 1998).
[115]As explained below, the Xcel Gas System, which spans the same geographic expanse, is itself an integrated public utility system which by definition is confined "to a single area or region."
[116]The NSP and NCE management structures are designed to facilitate communications with state regulators. Each company has established State offices which have responsibility for regulatory, environmental, and corporate communications and have other external relations purposes. These state offices provide a single point of contact with each of the state regulatory and environmental offices and have the responsibility for handling all regulatory contacts, including making regulatory filings and answering customer inquiries to the regulatory commissions. It is expected that these offices will be left essentially intact after the Merger.
[117]In fact, a key aspect of the merger applications is to explain why no such impairment of regulatory authority occurs.
[118]FERC Merger Order at 26.
[119] Order No. 2000 at 3-4.
[120] Northeast Utilities, Holding Co. Act Release No. 25273 (March 15, 1991), aff'd sub nom. City of Holyoke v. SEC, 972 F.2d 358 (1992). See also Wisconsin's Environmental Decade v. SEC, 882 F.2d 523 (D.C. Cir. 1989) ("we are not prepared to say that the Commission abdicates its duty in an exemption determination by deciding to rely, watchfully, on the course of state regulation").
[121]"We conclude that a large scope is important for an RTO to effectively perform its required functions and to support efficient and nondiscriminatory power markets." Order No. 2000 at 257.
[122]Sen. Rep. No. 621, 74th Cong., 1st Sess. (1935).
[123] See 1995 Report, pp. 29-31.
[124] "Parking" is essentially a short-term interruptible storage service. "Loaning" is a service by which a party with gas will provide the gas to another party with a specific date for the return of such gas at either that location or another location under mutually agreeable terms and conditions (in effect, the inverse of parking). "Wheeling" is the provision of transportation by a hub operator from one system to another system. Finally, "title transfer" services allow parties to exchange title to gas that is already within a pipeline system for gas at different points on the same pipeline system or for gas that is on another pipeline system, without the requirement of physical movement. Title transfer in itself allows the shippers to minimize transportation costs.
[125] See UNITIL Corp., supra ("The Commission has required divestment where the anticipated loss of income of the stand-alone company was approximately 30%..." or "29.9% of net income before taxes"), citing SEC v. New England Electric System, 390 U.S. 207, 214 n.11 (1968).
[126]The highest loss of operating revenues in any case ordering divestiture is commonly said to be 6.58%. See, e.g., UNITIL Corp., supra ("[o]f cases in which the Commission has required divestment, the highest estimated loss of operating revenues of a stand-alone company was 6.58%...").
[127]NSP and NCE are in the process of preparing an additional study which will show the impact of the divestiture of their gas operations if divestiture were to occur following their integration into one multi-state gas operation.
[128]In approving the merger of PSCo and SPS into NCE, the Colorado Commission similarly supported the retention by PSCo of its gas operations, and the Wyoming Commission similarly supported the retention by Cheyenne of its gas operations.
[129]As noted before, as part of the merger integration process, Applicants are currently trying to determine the optimal corporate structure for Xcel. The structure reflected in EXHIBIT E-12 is thus tentative. In the event that Applicants decide to revise the proposed structure, they will file it by amendment.
[130] Exemption of Acquisition by Registered Public-utility Holding Companies of Securities of Non-utility Companies Engaged in Certain Energy-related and Gas-related Activities, Holding Co. Act Release No. 26667 (Feb. 14, 1997) ("Rule 58 Release").
[131]1995 Report at 81-87, 91-92.
[132] Further, the Applicants anticipate an additional $24 million in operating efficiencies due to the integration plans. Because of contingencies in the Applicants' FERC filing, these additional savings are not reflected in this estimate. Should FERC approve the integration plan, the additional savings will be passed on to customers via a fuel clause adjustment.
[133]As stated previously, the electric production and transmission costs of NSP and NSP-W are shared by them in accordance with the Interchange Agreement, which is a FERC-regulated agreement that has also been accepted by the Wisconsin Commission and the Minnesota Commission for determination of costs recoverable in rates by NSP-W and NSP in rate cases.
[134] New Century Energies, Inc., Holding Co. Act Release No. 27000 (April 7, 1999).
[135] NSP's agreement with a subsidiary, NMC, states that services provided to NMC or received from NMC be at the higher of cost or market, or lower the cost or market, respectively. However, that agreement also deems market to equal cost and thus is consistent with SEC requirements.
[136] § 216B.48, subdivision 3 (Supp. 1993).
[137] Id.
[138]In MPUC Docket No. G002/M-94-831, the MPUC again expanded the scope of the Policy Statement, indicating it would be applied to assign costs between NSP utility operations and regulated affiliates (such as Viking).
[139]NRG provides management and administrative services to Cogeneration Corporation of America, which services are described in Annex D under the caption "Subsidiaries of NRG." These services are to be provided at cost and such contract was approved by the Bankruptcy Court as part of the reorganization. None of the entities to be acquired by NRG in this transaction, or to which NRG will be providing such services, will be a "public-utility company" under the Act.
Annex A
FURTHER DESCRIPTION OF UTILITY ASSETS
AND OPERATIONS OF NCE
1. PSCo ELECTRIC GENERATION PROPERTY
The PSCo electric generating stations expected to be available at the time of the anticipated 1999 net firm system peak demand during the summer season are as follows:
|
Name of Station and Location |
Installed Gross Capacity (MW) |
Net Dependable Capacity (MW) at Time of Anticipated 1999 Net Firm System Peak Demand* |
Major Fuel Source |
|
Steam: |
|||
|
Arapahoe - |
262.00 |
246.00 |
Coal |
|
Cameo - near |
77.00 |
72.70 |
Coal |
|
Cherokee - |
779.00 |
717 |
Coal |
|
Comanche - Near |
725.00 |
660 |
Coal |
|
Craig - near Craig, |
87.00(a) |
83.20 |
Coal |
|
Hayden - near |
259.00(b) |
237.00 |
Coal |
|
Pawnee - near |
547.00 |
495.00 |
Coal |
|
Valmont - near |
188.00 |
178.00 |
Coal |
|
Zuni - Denver, Co. |
115.00 |
107.00 |
Gas/Oil |
|
Total (Steam) |
3,022.00 |
2,812.00 |
|
|
Other: |
|||
|
Fort St. Vrain |
243.00 |
217.00 |
Gas |
|
Combustion |
209.00 |
171.00 |
Gas |
|
Hydro (14 units- |
53.00 |
37.00(d) |
Hydro |
|
Cabin Creek |
324.00(e) |
162.00 |
Hydro |
|
Total (Steam and |
3,852.00 |
3,408.00 |
Notes to Table:
* A measure of the unit capability planned to be available at the time of the system peak load net of seasonal reductions in unit capability due to weather, stream flow, fuel availability and station horsepower, including requirements for air and water quality control equipment.
(a) The gross maximum capability of Craig Units No. 1 and No. 2 is 894 Megawatts ("MW"), of which PSCo has a 9.72% undivided ownership interest.
(b) The gross maximum capability of Hayden Units No. 1 and No. 2 is 202.01 MW and 285.96 MW, respectively, of which PSCo has a 75.5% and 37.4% undivided ownership interest, respectively.
(c) Includes one station (two units) not owned by PSCo but operated under contract.
(d) Seasonal Hydro Plant net dependable capabilities are based upon average water conditions and limitations for each particular season. The individual plant seasonal capabilities are sometimes limited by less than design water flow.
(e) Capability at maximum load.
Fort St. Vrain, PSCo's only nuclear plant, ceased operations on August 29, 1989, and on March 22, 1996, the physical decommissioning of the station was completed. The initial phase of the repowered gas-fired, combined-cycle steam electric generating station began commercial operations on May 1, 1996. Phase 2 began operations in May 1999.
2. SPS ELECTRIC GENERATION PROPERTY[140]
The SPS electric generating stations expected to be available at the time of the anticipated 1999 net firm system peak demand during the summer season are as follows:
|
Name of Station and Location |
Installed Gross Capacity (MW) |
Net Dependable Capacity (MW) at Time of Anticipated 1999 Net Firm System Peak Demand* |
Major Fuel source |
|
Steam: |
|
|
|
|
Tolk - near Muleshoe, TX |
1,130.00 |
1,080.00 |
Coal |
|
Jones - near Lubbock, TX |
512.00 |
486.00 |
Gas |
|
Plant X - near Earth, TX |
463.00 |
442.00 |
Gas |
|
Nichols - near Amarillo, TX |
479.00 |
457.00 |
Gas |
|
Cunningham - near Hobbs, NM |
281.00 |
267.00 |
Gas |
|
Maddox - near Hobbs, NM |
123.00 |
118.00 |
Gas |
|
CZ-2 - near Pampa, TX |
26.00 |
26.00 |
Purch. steam |
|
Moore County - near Sunray, TX |
51.00 |
48.00 |
Gas |
|
Total (Steam) |
4,202.00 |
3,990.00 |
|
|
|
|
|
|
|
CZ-1 - near Pampa, TX |
13.00 |
13.00 |
|
|
Maddox - near Hobbs, NM |
76.00 |
66.00 |
Gas |
|
Riverview - near Borger, TX |
25.00 |
25.00 |
Gas |
|
Cunningham - near Hobbs, NM |
245.00 |
244.00 |
Gas |
|
Diesel Engine (1 unit) Tucumcari, NM |
15.00 |
0.00 |
Diesel |
|
Total (Steam and Gas Turbine) |
4,592.00 |
4,354.00 |
Notes to Table:
* Purchased Power Contracts: The NCE Operating Companies have contractual arrangements with regional utilities as well as QFs and EWGs to meet the energy needs of their customers. The NCE Operating Companies have capacity contracts in the following amounts at the time of the anticipated 1999 net firm system peak demand:
|
NCE Operating Company |
MW |
|
PSCo |
1,768 |
|
SPS |
508 |
|
Cheyenne |
152 |
|
Total |
2,428 |
3. NCE ELECTRIC TRANSMISSION AND DISTRIBUTION PROPERTIES
PSCo: On December 31, 1998, PSCo's transmission system consisted of approximately 112 circuit miles of 345 kilovolt ("kV") overhead lines; 1,936 circuit miles of 230 kV overhead lines; 15 circuit miles of 230 kV underground lines; 65 circuit miles of 138 kV overhead lines; 1,002 circuit miles of 115 kV overhead lines; 22 circuit miles of 115 kV underground lines; 330 circuit miles of 69 kV overhead lines; 137 circuit miles of 44 kV overhead lines; and 1 circuit mile of 44 kV underground lines. PSCo jointly owns with another utility approximately 342 circuit miles of 345 kV overhead lines and 359 miles of 230 kV overhead lines, of which PSCo's share is 112 miles and 147 miles, respectively, which shares are included in the amounts listed above.
SPS: On December 31, 1998, SPS's transmission system consisted of approximately 319 circuit miles of 345 kV overhead lines; 1,598 circuit miles of 230 kV overhead lines; 2,579 circuit miles of 115 kV overhead lines; 1,768 circuit miles of 69 kV overhead lines; 1 circuit mile of 115 kV underground line; and 5 circuit miles of 69 kV underground lines.
Cheyenne : Cheyenne's transmission facilities are located in Wyoming. These facilities are very limited, consisting of two 115kV transmission line segments that total 25.5 miles in length. The primary purpose of these transmission lines is to deliver power that Cheyenne purchases from its full requirements supplier, PacifiCorp. Power is wheeled from WAPA's transmission system, with which Cheyenne intersects, to Cheyenne's distribution substation for ultimate distribution to Cheyenne's retail customers. Like PSCo, Cheyenne is a member of the WSCC.
The distribution system of NCE's electric utility subsidiary companies consists of both overhead lines and underground distribution systems. PSCo owns approximately 210 substations (30 of which are jointly-owned) having an aggregate transformer capacity of 19,390,000 kVa, of which, 4,141,000 kVa is step-up transformer capacity at generating stations. SPS owns approximately 316 substations having an aggregate transformer capacity of 20,531,310 kVa, of which 5,951,000 kVa is step-up transformer capacity.
4. NCE ENERGY SALES
For the year ended December 31, 1998, PSCo, SPS and Cheyenne sold the following amounts of electric energy (at retail or wholesale) and distributed the following amounts of natural or manufactured gas at retail:
|
Year ended |
|
|
PSCo Kwh of electric energy sold (including amounts delivered in interchange) |
|
|
Million ("MDth") of gas distributed at retail (including natural and manufactured gas) |
|
|
|
|
|
|
|
|
MMBTU of gas distributed at retail (including natural and manufactured gas) |
|
5. NCE GAS PROPERTY
The gas property of PSCo at December 31, 1998, consisted of approximately 16,048 miles of distribution mains ranging in size from 0.50 to 30 inches and related equipment. The Denver distribution system consisted of 9,093 miles of mains. Pressures in the system are varied to meet load requirements and individual house regulators are installed on each customer's premises to provide uniform flow of gas to appliances. PSCo also owns and operates four gas storage facilities.
__________________________
[140]No information is presented for Cheyenne as it does not own any generating facilities. [140]No information is presented for Cheyenne as it does not own any generating facilities. [140]No information is presented for Cheyenne as it does not own any generating facilities. [140] No information is presented for Cheyenne as it does not own any generating facilities.
Annex B
FURTHER DESCRIPTION OF UTILITY ASSETS
AND OPERATIONS OF NSP
1. NSP ELECTRIC GENERATING FACILITIES
As of December 31, 1998, NSP and NSP-W had a total net generating capability of 7,186 MW and NSP had a total summer net generating capacity of 6,338 MW available primarily from the following units:
Sherburne County ("Sherco"): NSP owns two coal-fired generating units at its Sherco station in Minnesota with a combined net capability of 1,433 MW. NSP owns a 59% undivided interest in the third unit at the station ("Sherco 3"), of which NSP's share of the net capability of this unit is 514 MW.
Prairie Island: NSP owns two nuclear generating units at its Prairie Island station in Minnesota with a combined net capability of 1,039 MW.
Monticello: NSP owns one nuclear generating unit at its Monticello station in Minnesota with a net capability of 578 MW.
King: NSP owns one coal-fired generating unit at its King station in Minnesota with a net capability of 571 MW.
Black Dog: NSP owns four coal-fired generating units at its Black Dog station in Minnesota with a combined net capability of 462 MW.
High Bridge: NSP owns two coal-fired generating units at its High Bridge station in Minnesota with a combined net capability of 267 MW.
Riverside: NSP owns two coal-fired generating units at its Riverside station in Minnesota with a combined net capability of 380 MW.
Anson: NSP owns two oil/gas-fired combustion turbine electric generating units at its Angus Anson station in Sioux Falls, South Dakota, with an aggregate net generating capability of 232 MW.
Inver Hills: NSP owns five oil/gas-fired combustion turbine electric generating units at its Inver Hills station located in Inver Grove Heights, Minnesota, with an aggregate net generating capability of 343 MW.
NSP also owns numerous smaller generating units fueled with coal, natural gas, oil or waste, wind and one hydro-electric generating facility, with an aggregate net capability of 519 MW.
As of December 31, 1998, NSP-W had a total net summer generating capability of 848 MW from the following units:
Bay Front: NSP-W owns three steam electric generating units at its Bay Front station in Ashland, Wisconsin that are fueled with coal, wood and gas, with a combined net capability of 73 MW.
French Island: NSP-W owns two steam electric generating units, fueled with wood and refuse derived fuel, and two oil-fired combustion turbine generating units at its French Island generating station in LaCrosse, Wisconsin with a combined net capability of 171 MW.
Flambeau: NSP-W owns a gas/oil-fired combustion turbine electric generating unit at its Flambeau station in Park Falls, Wisconsin with a summer net generating capability of 12 MW.
Wheaton: NSP-W owns six oil-fired combustion turbine electric generating units at its Wheaton station in Eau Claire, Wisconsin with a combined net capability of 342 MW.
Hydro Plants: NSP-W also owns and operates 19 hydro-electric generating stations throughout northwestern Wisconsin with an aggregate net capability of 250 MW.
NSP-W presently relies primarily on NSP for base load generation and purchases of power to meet the needs of NSP-W's customers. The electric operations of NSP and NSP-W are fully integrated and all generating units are centrally dispatched by NSP. The electric production and transmission costs of NSP and NSP-W are shared by the companies under an agreement which is called the "Agreement to Coordinate Planning and Operation and Interchange Power and Energy Between Northern States Power Company (Minnesota) and Northern States Power Company (Wisconsin)" (the "Interchange Agreement"). The Interchange Agreement was approved by FERC in Docket No. ER84-690-000, dated August 21, 1985. For the year ended December 31, 1998, the combined energy (Kwh) sales of NSP and NSP-W were produced 46% by coal-fired generation, 25% by nuclear generation, 27% by purchase and interchange and 2% from NSP's hydroelectric and other generation. The 1998 electric system peak load for NSP and NSP-W was 7,639 MW and occurred on July 14, 1998, exclusive of off-system sales. The 1999 electric system peak load for NSP and NSP-W was 7,990 MW and occurred on July 29, 1999, exclusive of off-system sales. For the year ended December 31, 1998, the fuel resources for NSP's and NSP-W's generation-based Kwh was 60% obtained from coal-fired generation, approximately 35% from nuclear generation, and approximately 5% from other fuels.
2. NSP Electric Transmission and Other Facilities
As of December 31, 1998, NSP's electric transmission system included 265 circuit miles of 500 kV line, 751 circuit miles of 345 kV line, 287 circuit miles of 230 kV line, 59 circuit miles of 161 kV line, 1,276 circuit miles of 115 kV line and 1,775 circuit miles of transmission line under 115 kV. The bulk of NSP's high voltage transmission system is located in the State of Minnesota. As of December 31, 1998, NSP's transmission substations had a combined capacity of approximately 27,665 thousand KVA and the distribution substations totaled approximately 13,260 thousand KVA. Manitoba Hydro-Electric Board, Minnesota Power Company and NSP completed the construction of a 500 kV transmission interconnection between Winnipeg, Manitoba, Canada, and the Minneapolis-St. Paul, Minnesota, area in May 1980. NSP has a contract with Manitoba Hydro-Electric Board for 500 MW of firm power utilizing this transmission line. In addition, the Company is interconnected with Manitoba Hydro at the U.S./Canada border through a 230 kV transmission line completed in 1970.
As of December 31, 1998, NSP-W's electric transmission system included 165 circuit miles of 345 kV line, 280 circuit miles of 161 kV line, 448 circuit miles of 115 kV line and 1,496 circuit miles of transmission line under 115 kV. As of December 31, 1998 NSP-W's transmission substations had a combined capacity of approximately 4,404 thousand KVA and the distribution substations totaled approximately 2,036 thousand KVA.
Other assets owned by NSP and NSP-W include electric distribution systems located throughout its service area, and property, plant and equipment owned or leased supporting their electric and gas utility functions. NSP and NSP-W also own or lease other physical properties, including real property, and other facilities necessary to conduct their operations.
3. NSP Energy Sales
For the year ended December 31, 1998, NSP and NSP-W sold the following amounts of electric energy (at retail or wholesale):
|
Year ended |
|
|
NSP |
|
|
NSP-W |
|
4. Gas Facilities
NSP provides natural gas service at retail in the St. Paul metropolitan area and portions of southeast, northwest and central Minnesota, as well as eastern North Dakota, and in Arizona through its BMG division. [141] NSP-W provides natural gas service in western and central Wisconsin as well as Ironwood in Michigan's Upper Peninsula. Both NSP and NSP-W are directly connected to various interstate pipelines and have separate contractual supply portfolios for transportation through pipelines and with suppliers of natural gas. The gas delivery operations of NSP, NSP-W and Viking are managed out of St. Paul, Minnesota, pursuant to a Supervisory Control and Data Acquisition Agreements among NSP, NSP-W and Viking (NSP's wholly-owned interstate pipeline subsidiary). Under these agreements, NSP manages the pressures of the various pipelines owned by these companies and the inflow and outflow of natural gas from these pipelines. These agreements were approved by the Minnesota Commission in Docket No. G002/AI-94-831, and the NSP/NSP-W agreement was approved by the Wisconsin Commission in Docket No. 4220-AU-117.
The gas properties of NSP include 7,989 miles of natural gas distribution and transmission mains, 50 miles of propane vapor distribution mains, the Westcott LNG plant with a storage capacity of 2.1 Bcf equivalent and five propane-air plants with a storage capacity of 1.4 Bcf equivalent to help meet the peak requirements of its firm residential, commercial and industrial customers. NSP-W's gas properties include approximately 1,724 miles of natural gas distribution mains, the Eau Claire and LaCrosse LNG plants, having a storage capacity of 0.4 Bcf equivalent, and one propane-air plant, with storage capacity of 0.02 Bcf equivalent. The gas properties of BMG include 250 miles of natural gas distribution mains and approximately 50 miles of propane vapor distribution mains.
NSP and NSP-W are authorized to make certain sales of natural gas for resale under blanket authority granted by FERC under 18 CFR 284.402.
For the year ended December 31, 1998, NSP, NSP-W and BMG distributed the following amounts of natural or manufactured gas at retail:
|
Year-ended |
|
|
NSP |
|
|
NSP-W |
|
________________________
[141]As noted above, a "spin down" of NSP's gas utility assets to a subsidiary (also called BMG) is pending Commission approval. The Minnesota Commission and the North Dakota Commission approved this transaction in April 1999; the Arizona Commission approved it in September 1999. Upon Commission approval, BMG would operate as a subsidiary of NSP until the Merger and would be utility operating company subsidiary of Xcel after the Merger. [141]As noted above, a "spin down" of NSP's gas utility assets to a subsidiary (also called BMG) is pending Commission approval. The Minnesota Commission and the North Dakota Commission approved this transaction in April 1999; the Arizona Commission approved it in September 1999. Upon Commission approval, BMG would operate as a subsidiary of NSP until the Merger and would be utility operating company subsidiary of Xcel after the Merger. [141]As noted above, a "spin down" of NSP's gas utility assets to a subsidiary (also called BMG) is pending Commission approval. The Minnesota Commission and the North Dakota Commission approved this transaction in April 1999; the Arizona Commission approved it in September 1999. Upon Commission approval, BMG would operate as a subsidiary of NSP until the Merger and would be utility operating company subsidiary of Xcel after the Merger. [141]As noted above, a "spin down" of NSP's gas utility assets to a subsidiary (also called BMG) is pending Commission approval. The Minnesota Commission and the North Dakota Commission approved this transaction in April 1999; the Arizona Commission approved it in September 1999. Upon Commission approval, BMG would operate as a subsidiary of NSP until the Merger and would be utility operating company subsidiary of Xcel after the Merger. [141] As noted above, a "spin down" of NSP's gas utility assets to a subsidiary (also called BMG) is pending Commission approval. The Minnesota Commission and the North Dakota Commission approved this transaction in April 1999; the Arizona Commission approved it in September 1999. Upon Commission approval, BMG would operate as a subsidiary of NSP until the Merger and would be utility operating company subsidiary of Xcel after the Merger.ANNEX C
NON-UTILITY SUBSIDIARIES OF NCE
|
|
|
|
Type of |
|
|
DIRECT NON-UTILITY SUBSIDIARIES OF NCE |
||||
|
WestGas InterState, Inc. |
Corporation |
CO |
Gas pipeline company |
1997 Order |
|
NC Enterprises, Inc. |
Corporation |
DE |
Non-utility holding company |
1997 Order |
|
NON-UTILITY SUBSIDIARIES OF PUBLIC SERVICE COMPANY OF COLORADO |
||||
|
1480 Welton, Inc. |
Corporation |
CO |
Utility real estate |
1997 Order |
|
P.S.R. Investments, Inc. |
Corporation |
CO |
Employee life insurance |
1997 Order |
|
PS Colorado Credit Corporation |
Corporation |
CO |
Financing/factoring company |
1997 Order |
|
Green and Clear Lakes Company |
Corporation |
NY |
Hydroelectric water storage |
1997 Order |
|
Fuel Resources Development Co. |
Corporation [143] |
CO |
Natural gas exploration |
1997 Order |
|
Baugh Lateral Ditch Company |
Corporation |
CO |
Ditch company |
1997 Order |
|
The Beeman Irrigating Ditch and Milling Company |
Corporation |
CO |
Ditch company |
1997 Order |
|
Consolidated Extension Canal Company |
Corporation |
CO |
Ditch company |
1997 Order |
|
East Boulder Ditch Company |
Corporation |
CO |
Ditch company |
1997 Order |
|
Enterprise Irrigating Ditch Company |
Corporation |
CO |
Ditch company |
1997 Order |
|
Fisher Ditch Company |
Corporation |
CO |
Ditch company |
1997 Order |
|
Hillcrest Ditch and Reservoir Company |
Corporation |
CO |
Ditch company |
1997 Order |
|
Jones and Donnelly Ditch Company |
Corporation |
CO |
Ditch company |
1997 Order |
|
Las Animas Consolidated Canal Company |
Corporation |
CO |
Ditch company |
1997 Order |
|
United Water Company |
Corporation |
CO |
Ditch company |
1997 Order |
|
NON-UTILITY SUBSIDIARIES OF NC ENTERPRISES |
||||
|
NC Enterprises, Inc. |
Corporation |
DE |
Non-utility holding company |
1997 Order |
|
ep3, L.L.C. |
Limited liability company |
DE |
Foreign EWG and FUCO development |
1997 Order |
|
New Century International, Inc. |
Corporation |
DE |
FUCO/EWG holding company |
1997 Order |
|
Jersey Isle |
EWG |
§ 32 |
|
|
Corporation |
EWG |
§ 32 |
|
|
Corporation |
EWG |
§ 32 |
|
|
Corporation |
UK |
FUCO holding company |
1997 Order |
|
Corporation |
UK |
FUCO holding company |
1997 Order |
|
Corporation |
UK |
§ 3(b) subsidiary; expected FUCO |
1997 Order |
|
Corporation |
UK |
Expected FUCO |
1997 Order |
|
NCE Communications, Inc. [144] |
Corporation |
DE |
ETC |
1997 Order |
|
Natural Fuels Corporation |
Corporation |
CO |
Commercialization of compressed natural gas |
1997 Order |
|
Limited liability company |
WY |
Commercialization of compressed natural gas |
1997 Order |
|
Limited partnership |
CO |
Commercialization of compressed natural gas |
1997 Order |
|
Limited liability company |
WY |
Commercialization of compressed natural gas |
1997 Order |
|
Utility Engineering Corporation |
Corporation |
TX |
Engineering services and construction management |
1997 Order |
|
Corporation |
TX |
IPP & cogeneration development; railcar services; water rights; other non-utility investments |
1997 Order |
|
Limited liability company |
DE |
Expected EWG |
§ 32 |
|
Limited liability company |
DE |
Expected EWG |
§ 32 |
|
Corporation |
TX |
IPP & cogeneration operation and maintenance services |
1997 Order |
|
Corporation |
NV |
Ownership of water rights, QF, and EWG |
1997 Order |
|
Limited partnership |
DE |
QF ownership |
1997 Order |
|
Corporation |
DE |
1997 Order |
|
|
Limited partnership |
DE |
EWG ownership |
1997 Order |
|
Limited partnership |
TX |
QF ownership and ownership of water rights |
1997 Order |
|
Limited partnership |
DE |
QF ownership |
1997 Order |
|
Corporation |
DE |
EWG holding company |
1997 Order |
|
Limited partnership |
DE |
EWG |
1997 Order |
|
Corporation |
DE |
EWG holding company |
1997 Order |
|
Limited partnership |
DE |
EWG ownership |
1997 Order |
|
Corporation |
DE |
QF holding company |
1997 Order |
|
Limited partnership |
DE |
QF ownership |
1997 Order |
|
Corporation |
DE |
QF holding company |
1997 Order |
|
Limited partnership |
DE |
QF ownership |
1997 Order |
|
Corporation |
TX |
QF holding company |
1997 Order |
|
Limited partnership |
DE |
QF ownership |
1997 Order |
|
Corporation |
TX |
QF holding company |
1997 Order |
|
Limited partnership |
DE |
QF ownership |
1997 Order |
|
Limited Partnership |
DE |
QF ownership - Inactive |
1997 Order |
|
Limited partnership |
DE |
QF ownership - Inactive |
1997 Order |
|
Limited partnership |
DE |
QF ownership |
1997 Order |
|
Limited liability company |
DE |
Steam generation |
1997 Order |
|
Limited partnership |
TX |
QF ownership and ownership of water rights |
1997 Order |
|
Corporation |
DE |
EWG holding company |
1997 Order |
|
Limited partnership |
DE |
EWG |
1997 Order |
|
Corporation |
DE |
EWG holding company |
1997 Order |
|
Limited liability company |
DE |
EWG and FUCO development and ownership |
1997 Order |
|
Limited liability company |
DE |
EWG and FUCO development and ownership |
1997 Order |
|
Corporation |
TX |
Cooling tower maintenance and resource recovery |
1997 Order |
|
Corporation |
TX |
Human resource services |
1997 Order |
|
Limited liability company |
TX |
Environmental consulting services |
1997 Order |
|
The Planergy Group, Inc. |
Corporation |
TX |
Energy-related company |
Rule 58 |
|
Corporation |
DE |
Energy-related company |
Rule 58 |
|
Corporation |
DE |
Energy-related company |
Rule 58 |
|
Corporation |
CA |
Energy-related company |
Rule 58 |
|
Corporation |
CA |
Energy-related company |
Rule 58 |
|
Corporation |
DE |
Energy-related company |
Rule 58 |
|
Corporation |
DE |
Energy-related company |
Rule 58 |
|
Corporation |
DE |
Energy-related company |
Rule 58 |
|
Corporation |
DE |
Energy-related company |
Rule 58 |
|
Corporation |
NY |
Energy-related company |
Rule 58 |
|
Corporation |
TX |
Energy-related company |
Rule 58 |
|
Corporation |
Canada |
Energy-related company |
Rule 58 |
|
Corporation |
TX |
Energy-related company |
Rule 58 |
|
Corporation |
NC |
Energy-related company |
Rule 58 |
|
Corporation |
Energy-related company |
Rule 58 |
|
|
Corporation |
DE |
Energy-related company |
Rule 58 |
|
New Century O&M Services, Inc. |
Corporation |
CO |
Ownership, operation & maintenance of military base assets |
HCAR No. 27048 |
|
New Century Centrus, Inc. |
Corporation |
CO |
ETC |
§ 34 |
|
Limited partnership |
IN |
ETC |
§ 34 |
|
New Century-Cadence, Inc. |
Corporation |
CO |
Energy-related company |
Rule 58 |
|
Limited liability company |
DE |
Energy-related company |
Rule 58 |
|
e prime, inc. |
Corporation |
CO |
Energy services; IPP, cogeneration, and ETC ownership |
1997 Order |
|
Corporation |
FL |
Energy-related company |
Rule 58 |
|
Corporation |
GA |
Energy-related company |
Rule 58 |
|
Corporation |
CO |
Meter reading network (possible ETC) |
1997 Order |
|
Corporation |
CO |
Energy marketing |
1997 Order |
|
Limited partnership |
DE |
(Inactive) |
1997 Order |
|
Corporation |
TX |
Natural gas pipeline |
1997 Order |
|
Corporation |
TX |
Energy marketing |
1997 Order |
|
Limited liability company |
CO |
QF ownership |
1997 Order |
|
Corporation |
DE |
Natural gas storage |
1997 Order |
|
Limited partnership |
CO |
Natural gas storage |
1997 Order |
|
Corporation |
DE |
(Inactive) |
1997 Order (§ 32) |
|
Corporation |
DE |
(Inactive) |
1997 Order (§ 32) |
|
Corporation |
UK |
(Inactive) |
1997 Order (§ 32) |
_______________________________________
[142]"1997 Order" refers to New Century Energies, Inc., Holding Co. Act Release No. 26748 (1997), wherein the Commission approved the creation of the NCE system through the merger of Public Service Company of Colorado and Southwestern Public Service Company, including the retention of their non-utility businesses. [142]"1997 Order" refers to New Century Energies, Inc., Holding Co. Act Release No. 26748 (1997), wherein the Commission approved the creation of the NCE system through the merger of Public Service Company of Colorado and Southwestern Public Service Company, including the retention of their non-utility businesses. [142]"1997 Order" refers to New Century Energies, Inc., Holding Co. Act Release No. 26748 (1997), wherein the Commission approved the creation of the NCE system through the merger of Public Service Company of Colorado and Southwestern Public Service Company, including the retention of their non-utility businesses. [142]"1997 Order" refers to New Century Energies, Inc., Holding Co. Act Release No. 26748 (1997), wherein the Commission approved the creation of the NCE system through the merger of Public Service Company of Colorado and Southwestern Public Service Company, including the retention of their non-utility businesses. [142] "1997 Order" refers to New Century Energies, Inc., Holding Co. Act Release No. 26748 (1997), wherein the Commission approved the creation of the NCE system through the merger of Public Service Company of Colorado and Southwestern Public Service Company, including the retention of their non-utility businesses.[143]In dissolution under Colorado law.
[144] Formerly e prime Telecom, Inc., a subsidiary of e prime, inc.
Annex D
NSP NON-UTILITY BUSINESSES
The vast majority of NSP's non-utility business are EWGs, FUCOs or QFs and therefore would be exempt from the Act. A registered holding company may acquire and hold an interest in an EWG and a FUCO without the need to apply for or receive approval from the Commission. §§ 32 and 33 of the Act. (The Commission retains jurisdiction over certain related transactions with prior entities.) The Commission has also authorized the formation and financing of a number of non-utility subsidiaries of registered holding companies in order to invest in and hold securities of QFs, FUCOs, and EWGs. See, e.g., The Southern Company, Holding Co. Act Release No. 26212 (Dec. 30, 1994); Entergy Corp., Holding Co. Act Release No. 26322 (June 30, 1995); Northeast Utilities, Holding Co. Act Release No. 25977 (Jan. 24, 1994) (authorizing Charter Oak Energy and COE Development Corporation): Central and South West Corp., Holding Co. Act Release No. 26156 (Nov. 3, 1994) (authorizing CSW to form, acquire, finance and own securities of FUCOs); Central and South West Corporation, Holding Co. Act Release No. 26155 (Nov. 2, 1994) (authorizing investment in joint venture which will construct, own and operate QFs and EWGs). Moreover, Rule 58 lists the ownership of QFs as an energy-related activity under Rule 58(b)(1)(viii). A registered holding company may acquire "energy-related companies meeting the Rule 58 safe harbor conditions without the need for Commission approval. 17 C.F.R. § 250.58 (1999); Exemption of Acquisition by Registered Public-Utility Holding Companies of Non-Utility Companies Engaged in Certain Energy-Related Activities, Holding Co. Act Release No. 26667 (Feb. 14, 1997).
In addition, under Rule 58, an energy-related company is a company that derives or will derive substantially all of its revenues (exclusive of revenues from temporary investments) from one of the twelve businesses described in the Rule and from such other activities and investments as the Commission may approve under Section 10. Of the remainder, almost all of NSP's and certain of NCE's non-utility businesses that are not EWGs or FUCOs would be energy-related companies under the Commission's Rule 58 or prior Commission precedent.
The non-utility subsidiary companies are further described below.
I. Subsidiaries of NSP
|
|
Location of Incorporation |
|
|
|
NSP Financing I |
Delaware |
Special purpose business trust |
Prior Commission Precedent[145] |
|
Viking Gas Transmission |
Delaware |
Natural Gas Company (interstate transportation) |
Rule 58 (b)(2) |
|
Energy Masters |
Minnesota |
Energy services company |
Rule 58(b)(1)(i) |
|
Eloigne Company |
Minnesota |
Investments in affordable housing projects which qualify for low income housing tax credits |
Prior commission precedent[146] |
|
First Midwest Auto |
Minnesota |
Owns and operates parking garage next to NSP HQs |
Prior commission precedent[147] |
|
United Power & Land |
Minnesota |
Holds land adjacent to certain NSP operations, rents office space to NSP |
Prior commission precedent[148] |
|
Nuclear Management |
Wisconsin |
Provides services to the nuclear operations of its members |
Rule 58(b)(1)(i) |
|
Reddy Kilowatt |
Montana |
Owns certain intellectual property rights |
Prior Commission Precedent[149] |
|
Seren Innovations, Inc. |
Minnesota |
Provides cable, telephone and high-speed internet access system |
The Telecom-munications Act |
|
Ultra Power Technologies, |
Minnesota |
Markets power cable testing technology |
Rule 58(b)(1)(vii) |
|
NRG Energy, Inc. |
Delaware |
Develops, organizes, owns and operates non-regulated energy-related businesses |
§§ 32 and 33 and |
II. Subsidiaries of NSP-W
|
|
Location of Incorporation |
|
|
|
Clearwater Investments, Inc. |
Wisconsin |
Investment in affordable housing projects which qualify for low income housing tax credits under federal tax law |
Prior Commission precedent[150] |
|
NSP Lands |
Wisconsin |
Sells excess lands adjacent to certain NSP operations |
Prior Commission precedent[151] |
|
Chippewa & Flambeau |
Wisconsin |
Builds and operates dams and reservoirs |
Prior Commission precedent[152] |
III. Subsidiaries of NRG
|
|
Location of Incorporation |
|
|
|
Arthur Kill Power LLC |
Delaware |
Entity holding title to Arthur Kill generating station in New York |
EWG (Holding Company) |
|
Astoria Gas Turbine Power |
Delaware |
Entity holding title to Astoria turbines in New York |
EWG (Holding Company) |
|
Bioconversion Partners, L.P. |
California |
Supplies biomass fuel in California |
QF |
|
Brimsdown Power Limited |
England |
Project company for peaking unit associated with Enfield Energy Centre Limited in England |
EWG |
|
Cabrillo Power I LLC |
Delaware |
Owns and operates Encina electric generation station in San Diego, California |
EWG |
|
Cabrillo Power II LLC |
Delaware |
Entity holding title to 17 SDG&E combustion turbines in San Diego, California |
EWG (Holding Company) |
|
Cadillac Renewable Energy |
Delaware |
Owns Cadillac wood-fired power plant in Michigan |
QF |
|
Camas Power Boiler Limited |
Oregon |
Owns waste-wood-fired steam boiler in Camas paper mill in Washington, L.P. |
QF |
|
Camas Power Boiler, Inc. |
Oregon |
General partner in Camas Boiler Limited Partners |
QF |
|
Carolina Energy, Limited |
Delaware |
Holds remaining non-generating assets of the Carolina Energy transfer station and waste-to-energy facility in North Carolina |
QF |
|
Carquinez Strait Preservation |
California |
Non-profit corporation which provides monetary support to the communities surrounding the Crockett cogeneration facility in California |
Prior Commission precedent[153] |
|
Cobee Development LLC |
Delaware |
Provides international business development services in Latin America for Compania Boliviana de Energia Electrica S.A. |
EWG (Development Office) |
|
Cobee Holdings Inc. |
Delaware |
Domestic holding company for Tosli Investments B.V. |
EWG |
|
Cogeneration Corporation of |
Delaware |
Develops, owns and operates cogeneration facilities in U.S. |
Rule 58(b)(1)(viii) |
|
Collinsville Operations Pty |
Australia |
Operates Collinsville coal-fired power plant in Australia |
EWG |
|
Collinsville Power Joint |
(Unincorporated) |
Owns Collinsville coal-fired power plant in Australia |
EWG |
|
Compania Electrica Central |
Bolivia |
Owner of generation assets for project in Bolivia |
EWG |
|
Compania Boliviana de |
Canada (Nova Scotia) |
Owns 15 operating power plants primarily hydroelectric, in Bolivia |
EWG |
|
Connecticut Jet Power LLC |
Delaware |
Own and/or operate a portion of the generation assets acquired from Connecticut Light and Power ("CL&P assets") |
EWG |
|
Coniti Holding B.V. |
Netherlands |
International holding company |
Inactive |
|
Crockett Cogeneration, a |
California |
Owns Crockett cogeneration facility in California |
QF |
|
Curtis/Palmer Hydroelectric |
New York |
Owns Curtis/Palmer hydroelectric power plant in New York |
QF |
|
Cypress Energy Partners, |
Delaware |
Holds land purchase option for proposed coal-fired power plant in Florida |
EWG |
|
Devon Power LLC |
Delaware |
Own and/or operate portion of CL&P assets |
EWG |
|
Dunkirk Power LLC |
Delaware |
Entity holding title to Dunkirk Power Station in New York |
EWG |
|
ECK Generating, s.r.o. |
Czech Republic |
Expansion project for approximately 300 MW coal-fired power plant under construction in Kladno facility |
FUCO |
|
El Segundo Power, LLC |
Delaware |
Owns El Segundo gas fired power plant in California |
EWG |
|
Elk River Resource Recovery, |
Minnesota |
Proposed owner of Elk River waste processing facility in Minnesota |
Inactive |
|
Energeticke Centrum Kladno, |
Czech Republic |
Owns and operates a coal-fired power plant in Kladno, Czech Republic |
FUCO |
|
Energy Developments |
Australia (Queensland) |
Develops, owns and operates power generation and waste-to-energy projects in Australia, New Zealand, Asia and England |
FUCO (Development Company) |
|
Energy Investors Funds, L.P. |
Delaware |
Domestic investment company which holds limited partner interests in Crockett, Curtis/Palmer, Windpower 87 and Windpower 88 projects; also a funding vehicle for numerous other unrelated projects in the U.S. |
QF (Holding Company) |
|
Energy National, Inc. |
Utah |
Domestic holding company which holds limited partner interests in Crockett, Curtis/Palmer, Maine Energy Recovery Company, Penobscot Energy Recovery Company, PowerSmith, Windpower 87, Windpower 88 projects; general partner in Penobscot Energy Recovery Co. |
QF (Holding Company) |
|
Enfield Energy Centre |
England |
Owns Enfield gas fired power plant in England |
EWG |
|
Enfield Holdings B.V. |
Netherlands |
International holding company for Enfield Energy Centre Limited projects in England |
EWG |
|
Enfield Operations, L.L.C. |
England |
Operates Enfield Energy gas-fired power plant in England |
EWG |
|
Enfield Operations (UK) |
England |
Holds employees for Enfield Operations, L.L.C. |
EWG |
|
ENI Chester, Limited |
Oregon |
Was limited partner in wood burning project in Maine |
Inactive |
|
ENI Crockett Limited |
Oregon |
Limited partner in Crockett Cogeneration, A California Limited Partnership |
QF |
|
ENI Curtis Falls, Limited |
Oregon |
Limited partner in Curtis/Palmer Hydroelectric Company |
QF |
|
Enifund, Inc. |
Utah |
Holds property (house at Crockett cogeneration facility) and provides consulting services to Maine Energy Recovery Company |
Rule 58(b)(1)(viii) |
|
Enigen, Inc. |
Utah |
General Partner in The PowerSmith Cogeneration Project, Limited Partnership |
QF |
|
ESOCO Crockett, Inc. |
Oregon |
Operates Crockett cogeneration facility in California |
QF |
|
ESOCO Fayetteville, Inc. |
Oregon |
Proposed operator of Fayetteville waste-to-energy facility in North Carolina |
Inactive |
|
ESOCO Molokai, Inc. |
Utah |
Proposed operator of Molokai biomass fueled power plant in Hawaii |
Inactive |
|
ESOCO Orrington, Inc. |
Utah |
Operates Penobscot Energy Recovery Company in Maine |
Rule 58(b)(1)(viii) |
|
ESOCO Soledad, Inc. |
Utah |
Proposed operator of Soledad wood burning power plant in California |
Inactive |
|
ESOCO Wilson, Inc. |
Oregon |
Proposed operator of Carolina Energy waste-to-energy facility and transfer station in North Carolina |
Inactive |
|
ESOCO, Inc. |
Utah |
Domestic holding company for individual Esoco O&M companies |
QF |
|
Four Hills, LLC |
Delaware |
Landfill gas collection system for Nashua project in New Hampshire |
Rule 58(b)(1)(vi) |
|
Gladstone Power Station |
(Unincorporated) |
Owns a 1,680MW coal-fired power generation facility in Australia |
EWG |
|
Graystone Corporation |
Minnesota |
General Partner in Louisiana Energy Services, L.P. |
EWG |
|
Gunwale B.V. |
Netherlands |
International holding company |
Inactive |
|
Huntley Power LLC |
Delaware |
Entity holding title to the Huntley Power station in New York |
EWG |
|
Interenergy Limited |
Ireland |
Inactive - proposed provider of electric marketing services in eastern and central Europe |
Inactive |
|
Inversiones Bulo Bulo S.A. |
Bolivia |
Holding company for power project in Bolivia |
EWG |
|
Jackson Valley Energy |
California |
Owns and operates waste lignite/cogeneration plant and lignite mining and reclamation operation in California |
QF [Rule 58(b)(1)(x)] |
|
Kanel Kangal Elektrik |
Turkey |
Will own Kangal lignite fired power plant in Turkey |
EWG |
|
Kiksis B.V. |
Netherlands |
Inactive - international holding company - hold for Estonia project |
Inactive |
|
Killingholme Generation |
United Kingdom |
Project company for Killingholme Power Station |
Inactive |
|
Kingston Cogeneration |
Canada |
Owns Kingston cogeneration facility in Ontario, Canada |
EWG |
|
Kissimee Power Partners, |
Delaware |
Limited Partner in Cypress Energy Partners, Limited Partnership |
EWG |
|
Kladno Power (No. 1) B.V. |
Netherlands |
International holding company for Energeticke Centrum Kladno, s.r.o. |
FUCO |
|
Kladno Power (No. 2) B.V. |
Netherlands |
International holding company for Matra Powerplant Holding B.V., in Czech Republic |
FUCO |
|
Kraftwerk Schkopau GbR |
Germany |
Owns 960MW coal-fired power plan in Schkopau, Germany |
EWG |
|
Kraftwerk Schkopau |
Germany |
Operates in Germany Schkopau facility |
EWG |
|
Lakefield Junction LLC |
Delaware |
Owns peaking plant to be constructed in Minnesota |
EWG |
|
Lakefield Junction LLP |
Delaware |
Formed to develop the proposed independent power project currently planned for Martin County (Lakefield Junction) |
EWG |
|
Lambique Beheer B.V. |
Netherlands |
International holding company for MIBRAG B.V. and Mitteldeutsche Braunkohlengesellschaft mbH in Germany |
EWG |
|
Landfill Power LLC |
Wyoming |
Owns and operates Flying Cloud landfill gas fueled power generation facility in Eden Prairie, Minnesota |
QF |
|
Le Paz Incorporated |
Minnesota |
Limited partner in Louisiana Energy Services, L.P. |
Rule 58(b)(1)(vii) |
|
LFG Partners, LLC |
Delaware |
Landfill gas collection system for Yaworski project in Connecticut |
Inactive |
|
Long Beach Generation LLC |
Delaware |
Owns Long Beach gas-fired power plant in California |
EWG |
|
Long Island Cogeneration, |
New York |
Holds contracts for Long Island cogeneration facility in New York which was never constructed |
Inactive |
|
Louisiana Energy Services, |
Delaware |
Owns uranium enrichment facility under development in Louisiana |
Rule 58(b)(1)(vii) |
|
Louisiana Generating LLC |
Delaware |
Formed for the purpose of owning Cajun non-nuclear generating assets in Louisiana (including gas and coal-fired generation) |
EWG |
|
Loy Yang Power |
Australia (Victoria) |
Operates Loy Yang coal-fired power plant in Australia |
EWG |
|
Loy Yang Power Partners |
Australia |
Owns Loy Yang coal-fired plant in Australia |
EWG |
|
Loy Yang Power Projects Pty |
Australia (Victoria) |
Provides technical services to Loy Yang coal fired power plant in Australia |
EWG |
|
Maine Energy Recovery |
Maine |
Owns Waste-to-Energy facility in Biddeford, Maine |
QF and |
|
Matra Powerplant Holding |
Netherlands |
International holding company for ECK Generating, s.r.o. in Czech Republic |
FUCO |
|
MIBRAG B.V. |
Netherlands |
Owns 99% of MIBRAG GmbH coal mines and coal-fired power plants in Germany |
EWG |
|
Mid-Continent Power |
Delaware |
Owns Mid-Contingent Power Company cogeneration facility in Oklahoma |
QF |
|
Middletown Power LLC |
Delaware |
Own and/or operate portion of CL&P assets |
EWG |
|
Minnesota Methane Holdings |
Delaware |
Domestic holding company |
Inactive |
|
Minnesota Methane II LLC |
Delaware |
Owns and operates original 3 NEO/Ziegler landfill gas projects (Edward Kraemer in Burnsville, MN; Flying Cloud in Eden Prairie, MN and Nashua in New Hampshire) |
QF and |
|
Minnesota Methane LLC |
Wyoming |
Owns and operates 18 landfill gas projects in the U.S. financed by Lyon Credit |
QF and |
|
Minnesota Waste Processing |
Delaware |
Owns municipal solid waste processing facility and transfer station in Minnesota |
Rule 58(b)(1)(ii) |
|
Mitteldeutsche |
Germany |
Operates coal mining, power generation and associated operations near Leipzig, Germany |
EWG |
|
MM Albany Energy LLC |
Delaware |
Landfill gas fueled power generation for project in New York |
QF and |
|
MM Biogas Power LLC |
Delaware |
Domestic holding company - owns 100% interest in landfill gas fueled power generation projects not being financed |
QF and |
|
MM Burnsville Energy LLC |
Delaware |
Landfill gas fueled power generation for Edward Kraemer landfill in Minnesota |
QF and |
|
MM Corona Energy LLC |
Delaware |
Landfill gas fueled power generation for O'Brien projects in California |
QF and |
|
MM Cuyahoga Energy LLC |
Delaware |
Landfill gas fueled power generation for project in Cleveland, Ohio |
QF and |
|
MM Erie Power LLC |
Delaware |
Landfill gas fueled power generation for project in Denver, Colorado |
QF [Rule 58(b)(1)(vi)] |
|
MM Ft. Smith Energy LLC |
Delaware |
Will sell landfill gas to other companies in Arkansas - not a GENCO |
QF and |
|
MM Hackensack Energy LLC |
Delaware |
Landfill gas fueled power generation for HMDC/Balefill/Kingsland O'Brien project in Lyndhurst, New Jersey |
QF and |
|
MM Hartford Energy LLC |
Delaware |
Landfill gas fueled power generation for project in Connecticut |
QF and |
|
MM Lopez Energy LLC |
Delaware |
Landfill gas fueled power generation for Lopez Canyon project in Los Angeles, California |
QF and |
|
MM Lowell Energy LLC |
Delaware |
Landfill gas fueled power generation for project in Massachusetts |
QF and |
|
MM Martinez Energy LLC |
Delaware |
Landfill gas fueled power generation for project in California |
QF [Rule 58(b)(1)(vi)] |
|
MM Nashville Energy LLC |
Delaware |
Landfill gas fueled power generation for project in Tennessee |
QF and |
|
MM Northern Tier Energy |
Delaware |
Landfill gas fueled power generation for project in Pennsylvania |
QF and |
|
MM Phoenix Energy LLC |
Delaware |
Landfill gas fueled power generation for project in Arizona |
QF and |
|
MM Prima Deshecha Energy |
Delaware |
Landfill gas fueled power generation for project in Orange County, California |
QF and |
|
MM Prince William Energy |
Delaware |
Landfill gas fueled power generation for project in Virginia |
QF and |
|
MM Riverside LLC |
Delaware |
Landfill gas fueled power generation for project in California |
QF and |
|
MM San Diego LLC |
Delaware |
Landfill gas fueled power generation for Miramar project in California |
QF and |
|
MM SKB Energy LLC |
Delaware |
Landfill gas fueled power generation for project in Pennsylvania |
QF and |
|
MM Spokane Energy LLC |
Delaware |
Landfill gas fueled power generation for project in Washington |
QF and |
|
MM Tacoma LLC |
Delaware |
Landfill gas fueled power generation for project in Washington |
QF and |
|
MM Tajiguas Energy |
Delaware |
Landfill gas fueled power generation for project in Santa Barbara, California |
QF and |
|
MM Taunton Energy LLC |
Delaware |
Landfill gas fueled power generation for project in Massachusetts |
QF and |
|
MM Tomoka Farms Energy |
Delaware |
Landfill gas fueled power generation for Volusia project in Florida |
QF and |
|
MM Tulare Energy LLC |
Delaware |
Landfill gas fueled power generation for Visalia project in California |
QF and |
|
MM West Covina LLC |
Delaware |
Landfill gas fueled power generation for BKK project in California |
QF and |
|
MM Woodville Energy LLC |
Delaware |
Landfill gas fueled power generation for project in California |
QF and |
|
MM Yolo Power LLC |
Delaware |
Landfill gas fueled power generation for project in California |
QF and |
|
MMSB Transco Holdings |
Delaware |
Transport landfill gas for resale |
QF and |
|
Montville Power LLC |
Delaware |
Own and/or operate a portion of the CL&P assets |
EWG |
|
Mt. Poso Cogeneration |
California |
Owns Mt. Poso cogeneration facility in California |
QF |
|
NEO Albany, L.L.C. |
Delaware |
Landfill gas collection system for project in New York |
QF and |
|
NEO Burnsville, LLC |
Delaware |
Landfill gas collection system for Edward Kraemer landfill in Minnesota |
QF and |
|
NEO Corona LLC |
Delaware |
Landfill gas collection system for O'Brien project in California |
QF and |
|
NEO Corporation |
Minnesota |
Develops, owns and operates landfill gas, hydroelectric and small cogeneration projects in the U.S. |
QF and |
|
NEO Cuyahoga, LLC |
Delaware |
Landfill gas collection system for project in Cleveland, Ohio |
QF and |
|
NEO Erie LLC |
Delaware |
Landfill gas collection system for project in Denver, Colorado |
QF [Rule 58(b)(1)(iv)] |
|
NEO Edgeboro, LLC |
Delaware |
Landfill gas collection system for O'Brien project in New Jersey |
QF and |
|
NEO Findlay, LLC |
Delaware |
Landfill gas collection system for project in Pennsylvania |
Inactive |
|
NEO Fitchburg LLC |
Delaware |
Landfill gas collection system for project in Massachusetts |
QF and |
|
NEO Ft. Smith LLC |
Delaware |
Landfill gas collection system for project in Arkansas |
QF and |
|
NEO Hackensack, LLC |
Delaware |
Landfill gas collection system for HMDC/Balefill/Kingsland O'Brien projects in Lyndhurst, New Jersey |
QF and |
|
NEO Hartford, LLC |
Delaware |
Landfill gas collection system for project in Connecticut |
QF and |
|
NEO Landfill Gas Holdings |
Delaware |
Domestic holding company - provides O&M services for landfill gas projects |
QF and |
|
NEO Landfill Gas Inc. |
Delaware |
Domestic holding company - holds 99% interest in landfill gas collection system projects financed by Lyon Credit |
QF and |
|
NEO Lopez Canyon LLC |
Delaware |
Landfill gas collection system for project in Los Angeles, California |
QF and |
|
NEO Lowell LLC |
Delaware |
Landfill gas collection system for project in Massachusetts |
QF and |
|
NEO Martinez LLC |
Delaware |
Landfill gas collection system for project in California |
QF |
|
NEO MESI LLC |
Delaware |
Produce and sell synthetic fuel (coal briquettes) in Kentucky |
QF [Rule 58(b)(1)(vi)] |
|
NEO Nashville LLC |
Delaware |
Landfill gas collection system for project in Tennessee |
QF and |
|
NEO Northern Tier LLC |
Delaware |
Landfill gas collection system for project in Pennsylvania |
QF and |
|
NEO Phoenix LLC |
Delaware |
Landfill gas collection system for project in Arizona |
QF and |
|
NEO Prima Deshecha LLC |
Delaware |
Landfill gas collection system for project in Orange County, California |
QF and |
|
NEO Prince William, LLC |
Delaware |
Landfill gas collection system for project in Virginia |
QF and |
|
NEO Riverside LLC |
Delaware |
Landfill gas collection system for project in California |
QF and |
|
NEO San Bernardino LLC |
Delaware |
Landfill gas collection system for project in California |
QF and |
|
NEO San Diego LLC |
Delaware |
Landfill gas collection system for Miramar project in California |
QF and |
|
NEO SKB LLC |
Delaware |
Landfill gas collection system for project in Pennsylvania |
QF and |
|
NEO Spokane LLC |
Delaware |
Landfill gas collection system for project in Washington |
QF and |
|
NEO Tacoma, L.L.C. |
Delaware |
Landfill gas collection system for project in Washington |
QF and |
|
NEO Tajiguas LLC |
Delaware |
Landfill gas collection system for project in Santa Barbara, California |
QF and |
|
NEO Taunton LLC |
Delaware |
Landfill gas collection system for project in Massachusetts |
QF and |
|
NEO Tomoka Farms LLC |
Delaware |
Landfill gas collection system for Volusia project in Florida |
QF and |
|
NEO Tulare LLC |
Delaware |
Landfill gas collection system for Visalia project in California |
QF and |
|
NEO West Covina LLC |
Delaware |
Landfill gas collection system for BKK project in California |
QF and |
|
NEO Woodville LLC |
Delaware |
Landfill gas collection for project in California |
QF and |
|
NEO Yolo LLC |
Delaware |
Landfill gas collection system for project in California |
QF and |
|
New Roads Generating, LLC |
Delaware |
Alternative domestic holding company for Cajun non-nuclear generating assets in Louisiana (including gas and coal-fired generation) |
Inactive |
|
North American Thermal |
Ohio |
Develops district heating and cooling projects in the U.S.; general partner in Pittsburgh Thermal, Limited Partnership and San Francisco Thermal, Limited Partnership |
QF and |
|
Northbrook Acquisition Corp. |
Delaware |
Domestic holding company in STS Hydropower Ltd. |
QF |
|
Northbrook Carolina Hydro, |
Delaware |
Owns and operates hydroelectric power plants in North Carolina and South Carolina |
QF |
|
Northbrook Energy, L.L.C. |
Delaware |
Develops hydroelectric power projects in the U.S. |
QF |
|
Northeast Generation Holding |
Delaware |
To hold 50% interest in NRG Northeast Generating LLC |
EWG |
|
Norwalk Power LLC |
Delaware |
Own and/or operate a portion of the CL&P assets |
EWG |
|
NR (Gibraltar) |
Gibraltar |
Company utilized during the Enfield transactions in England |
Inactive |
|
NRG Affiliate Services Inc. |
Delaware |
Sponsor and hold the contracts and 401k plans for CL&P, Somerset and other entities. |
Prior Commission precedent[154] |
|
NRG Artesia Operations Inc. |
Delaware |
Proposed operator for Artesia cogeneration facility in California |
QF |
|
NRG Arthur Kill Operations |
Delaware |
Special purpose operating company to provide O&M services contract to Arthur Kill Power LLC |
EWG |
|
NRG Asia-Pacific, Ltd. |
Delaware |
Provides international business development services in Australia and the Pacific Rim region |
EWG |
|
NRG Astoria Gas Turbine |
Delaware |
Special purpose operating company to provide O&M services contract to Astoria Gas Turbine Power LLC |
EWG |
|
NRG Cabrillo I Inc. |
Delaware |
Special purpose company to add layer of liability protection between operating asset and NRG |
EWG |
|
NRG Cabrillo I LLC |
Delaware |
Special purpose company to add layer of liability protection between operating asset and NRG |
EWG |
|
NRG Cabrillo II Inc. |
Delaware |
Special purpose company to add layer of liability protection between operating asset and NRG |
EWG |
|
NRG Cabrillo II LLC |
Delaware |
Special purpose company to add layer of liability of protection between operating asset and NRG |
EWG |
|
NRG Cabrillo Power |
Delaware |
Special purpose operating company to provide O&M services contract to Cabrillo Power I LLC and Cabrillo Power II LLC |
EWG |
|
NRG Cadillac Inc. |
Delaware |
Domestic holding company in Cadillac Renewable Energy LLC |
QF and |
|
NRG Cadillac Operations Inc. |
Delaware |
Proposed operator for Cadillac wood fired power plant in Michigan |
QF and |
|
NRG Caymans-C |
Cayman Islands |
Holding company for interests in Scudder Latin American Power I-C |
EWG |
|
NRG Caymans Company |
Cayman Islands |
Holding company for Croatia Power structure (Inactive) |
EWG |
|
NRG Caymans-P |
Cayman Islands |
Holding company for interests in Scudder Latin American |
EWG |
|
NRG Central Generating LLC |
Delaware |
Special purpose holding company entity to facility central pool financing (Inactive) |
EWG |
|
NRG Central U.S. LLC |
Delaware |
To hold 50% interest in NRG Central Generating LLC (Inactive) |
EWG |
|
NRG Collinsville Operating |
Australia |
International holding company in Collinsville Operations Pty Ltd. |
EWG |
|
NRG Connecticut Affiliate |
Delaware |
House the payroll for the four Connecticut operations, sponsor the Pension, 401(k), Welfare plans, etc. |
Prior Commission precedent[155] |
|
NRG Connecticut Generating |
Delaware |
Sole Member of Devon Power LLC, Norwalk Power LLC, Middletown Power LLC, Montville Powe LLC and Connecticut Jet Power LLC |
EWG |
|
NRG del Coronado Inc. |
Delaware |
General partner in RSD Power Partners, L.P. |
QF |
|
NRG Development Company |
Delaware |
Entity created to limit development exposure on generation projects where NRG Energy, Inc. is pursuing the transaction with certain types of partners |
EWG |
|
NRG Devon Operations Inc. |
Delaware |
Special purpose operating company to provide O&M services contract to Devon Power LLC |
Prior Commission precedent[156] |
|
NRG Dunkirk Operations Inc. |
Delaware |
Special purpose operating company to provide O&M services contract to Dunkirk Power LLC |
EWG |
|
NRG Eastern LLC |
Delaware |
To hold 50% interest in NRG Northeast Generating LLC |
EWG |
|
NRG El Segundo Inc. |
Delaware |
Domestic holding company in El Segundo Power, LLC |
EWG |
|
NRG El Segundo Operations |
Delaware |
Proposed operator for El Segundo gas-fired power plant in California |
EWG |
|
NRG Energeticky Provoz, |
Czech Republic |
Operates coal-fired power plants in Kladno, Czech Republic |
FUCO |
|
NRG Energy Center, Inc. |
Minnesota |
Owns and operates Minneapolis Energy Center district heating and cooling system in Minnesota |
QF and |
|
NRG Energy Center Grand |
Delaware |
Owns assets in connection with a contract to provide steam at the Grand Forks Air Force Base |
Rule 58(b)(1)(vii) |
|
NRG Energy Center |
Delaware |
Owns and operates the district heating and cooling system serving customers in the downtown Minneapolis area. |
Rule 58(b)(1)(vii) |
|
NRG Energy Center |
Delaware |
Eventually will own and operate the Pittsburgh Thermal district heating and cooling plant which currently serves approx 25 customers in the Pittsburgh area. |
Rule 58(b)(1)(vii) |
|
NRG Energy Center Rock |
Delaware |
Owns assets in connection with the sale of steam of Rock-Tenn Corporation in St. Paul. |
Rule 58(b)(1)(vii) |
|
NRG Energy Center San |
Delaware |
Eventually will own and operate San Diego power and cooling, a chilled plant serving downtown San Diego area. |
Rule 58(b)(1)(vii) |
|
NRG Energy Center San |
Delaware |
Eventually will own and operate the San Francisco Thermal district heating and cooling plant which currently serves customers in the San Francisco area. |
Rule 58(b)(1)(vii) |
|
NRG Energy Center Washco |
Delaware |
Owns assets in connection with the sale of steam to Anderson Corporation and the State of Minnesota Correctional Facility |
Rule 58(b)(1)(vii) |
|
NRG Energy CZ, s.r.o. |
Czech Republic |
Provides international business development services in the Czech Republic and Europe |
FUCO |
|
NRG Energy Development |
Germany |
Provides international business development services in Germany and Europe |
Prior Commission precedent[157] |
|
NRG Energy Jackson Valley |
California |
General partner in Jackson Valley Energy Partners, L.P. |
QF |
|
NRG Energy Jackson |
California |
Limited partner in (i) Jackson Valley Energy Partners, L.P., (ii) San Joaquin Valley Energy Partners I, L.P., (iii) San Joaquin Valley Energy Partners IV, L.P. and (iv) Bioconversion Partners, L.P. |
QF |
|
NRG Energy Ltd. |
England and Wales |
Provides international business development services in the U.K. and Europe |
Prior Commission precedent[158] |
|
NRG Energy PL Sp. z o.o. |
Warsaw, Poland |
Provides international business development services in Poland |
Prior Commission precedent[159] |
|
NRG Gladstone Operating |
Australia |
Operates coal-fired Gladstone power plant in Australia |
EWG |
|
NRG Gladstone |
Australia |
Holds pension assets for employees of Gladstone coal-fired power plant in Australia |
EWG |
|
NRG Huntley Operations Inc. |
Delaware |
Special purpose operating company to provide O&M services contract to Huntley Power LLC |
EWG |
|
NRG International II Inc. |
Delaware |
Domestic holding company |
EWG/FUCO Holding Company |
|
NRG International, Inc. |
Delaware |
Domestic holding company |
EWG/FUCO Holding Company |
|
NRG International Services |
Delaware |
Holds service agreements with expatriates and international consultants |
EWG/FUCO Holding Company |
|
NRG International |
Delaware |
Entity created to limit development exposure on generation projects where NRG Energy, Inc. is pursuing the transaction with certain types of partners on international transactions |
EWG |
|
NRG Lakefield Inc. |
Delaware |
Special purpose entity to hold NRG's 50% member interest in Lakefield Junction LLC |
EWG |
|
NRG Latin America Inc. |
Delaware |
Provides international business development services in Latin America |
Prior Commission precedent[160] |
|
NRG Long Beach Inc. |
Delaware |
Domestic holding company in Long Beach Generation LLC |
EWG |
|
NRG Long Beach Operations |
Delaware |
Proposed operator for Long Beach gas-fired power plant in California |
EWG |
|
NRG Mextrans Inc. |
Delaware |
This entity will develop a transmission line from Palo Verde power station through Arizona, into Mexico and back up into California, per a Presidential Permit. |
EWG |
|
NRG Middletown Operations |
Delaware |
Special purpose operating company to provide O&M services contract to Middletown Power LLC |
EWG |
|
NRG Montville Operations |
Delaware |
Special purpose operating company to provide O&M services contract to Montville Power LLC |
EWG |
|
NRG Morris Operations Inc. |
Delaware |
Proposed operator for Millennium cogeneration facility in Illinois |
QF |
|
NRG Northeast Affiliate |
Delaware |
Manage payroll and benefits for Huntley and Dunkirk (approximately 330 employees) |
Prior Commission precedent[161] |
|
NRG Northeast Generating |
Delaware |
Special purpose holding company entity to facilitate east coast pool financing |
EWG |
|
NRG Northeast Power |
Delaware |
Power marketing and fuel procurement |
Rule 58(b)(1)(v) |
|
NRG Norwalk Harbor |
Delaware |
Special purpose operating company to provide O&M services contract to Norwalk Harbor LLC |
Prior Commission precedent[162] |
|
NRG Oklahoma Operations |
Delaware |
Proposed operator for Mid-Continent Power Company cogeneration facility in Oklahoma |
QF |
|
NRG Operating Services, Inc. |
Delaware |
Currently provides O&M services for Artesia, Cadillac, Collinsville, Gladstone and Minneapolis Energy Center projects |
Prior Commission precedent[163] |
|
NRG Oswego Harbor Power |
Delaware |
Special purpose operating company to provide O&M services contract to Oswego Power LLC |
Prior Commission precedent[164] |
|
NRG PacGen Inc. |
Delaware |
Domestic holding company which acquired 100% of the stock of Pacific Generation Company |
EWG (Holding Company) |
|
NRG Pittsburgh Thermal Inc. |
Delaware |
Limited Partner in Pittsburgh Thermal, Limited Partnership |
QF |
|
NRG Power Marketing Inc. |
Delaware |
Holds power marketing license |
Rule 58(b)(1)(v) |
|
NRG Rocky Road LLC |
Delaware |
Special purpose LLC formed to hold the 50% membership interest in Rocky Road LLC |
EWG |
|
NRG San Diego Inc. |
Delaware |
Limited Partner in RSD Power Partners, L.P. |
QF |
|
NRG San Francisco Thermal |
Delaware |
Special purpose entity to hold NRG's limited partnership ownership in SFTLP |
QF |
|
NRG Services Corporation |
Delaware |
Provides payroll and benefits services through service agreements with individual O&M companies |
Prior Commission precedent[165] |
|
NRG Sunnyside Operations |
Delaware |
General Partner in Sunnyside Operations Associated L.P. |
QF |
|
NRG Sunnyside Operations |
Delaware |
Limited Partner in Sunnyside Operations Associates L.P. |
Rule 58(b)(1)(viii) |
|
NRG Thermal Corporation |
Delaware |
The sole member of all the llcs under the new thermal restructuring |
Rule 58(b)(1)(vii) |
|
NRG Thermal Operating |
Delaware |
At this time has no assets or operations. |
Inactive |
|
NRG Victoria I Pty Ltd. |
Australia |
International holding company in NRG Victoria II Pty Ltd. and NRG Victoria III Pty Ltd. In Australia |
FUCO |
|
NRG Victoria II Pty Ltd. |
Australia |
International holding company in NRG Victoria III Pty Ltd. In Australia |
FUCO |
|
NRG Victoria III Pty Ltd. |
Australia |
International holding company for Energy Developments Limited |
FUCO |
|
NRG West Coast Inc. |
Delaware |
To act as holding company for West coast limited liability companies |
EWG (Holding Company) |
|
NRG Western Affiliate |
Delaware |
Handle payroll type issues for the Western Region operating companies |
Prior Commission precedent[166] |
|
NRGenerating Holdings |
Switzerland |
Swiss holding company |
EWG |
|
NRGenerating Holdings |
Netherlands |
International holding company in Collinsville Power Joint Venture |
EWG |
|
NRGenerating Holdings |
Netherlands |
International holding company registered to do business in Australia |
Inactive |
|
NRGenerating Holdings |
Netherlands |
International holding company in Loy Yang Power Partners, Loy Yang Power Management Pty Ltd. and Loy Yang Power Projects Pty Ltd. |
EWG |
|
NRGenerating Holdings |
Netherlands |
International holding company in NRG Energeticky Provoz, s.r.o. |
FUCO |
|
NRGenerating Holdings |
Netherlands |
International holding company registered to do business in Australia |
Inactive |
|
NRGenerating Holdings |
Netherlands |
International holding company for West Java O&M company in formation in Indonesia |
Inactive |
|
NRGenerating Holdings |
Netherlands |
International holding company for West Java O&M company in formation in Indonesia |
Inactive |
|
NRGenerating Holdings |
Netherlands |
International holding company in Kanel Kangal Elektrik Limited Sirketi |
EWG |
|
NRGenerating Holdings |
Netherlands |
International holding company for Langage Park Project in England |
EWG |
|
NRGenerating Holdings |
Netherlands |
International holding company |
Inactive |
|
NRGenerating Holdings |
Netherlands |
International holding company |
Inactive |
|
NRGenerating Holdings |
Netherlands |
International holding company |
Inactive |
|
NRGenerating Holdings |
Netherlands |
International holding company |
Inactive |
|
NRGenerating Holdings |
Netherlands |
International holding company |
Inactive |
|
NRGenerating Holdings |
Netherlands |
International holding company |
Inactive |
|
NRGenerating International |
Netherlands |
International holding company |
Inactive |
|
NRGenerating Rupali B.V. |
Netherlands |
International holding company for Rupali oil fired power plant bid in Pakistan |
Inactive |
|
O Brien Biogas (Mazzaro), |
Delaware |
Landfill gas collection system for project in Pennsylvania |
QF and |
|
O Brien Biogas IV LLC |
Delaware |
Landfill gas fueled power generation for Edgeboro project in New Jersey |
QF and |
|
O Brien California Cogen |
California |
Owns Artesia cogeneration facility in California |
QF |
|
O Brien Cogeneration, Inc. II |
Delaware |
General Partner in O'Brien California Cogen Limited |
QF |
|
O Brien Standby Power |
Delaware |
Landfill gas fueled power generation for SKB project in Pennsylvania |
QF |
|
Okeechobee Power I, Inc. |
Delaware |
General partner in Cypress |
QF |
|
Okeechobee Power II, Inc. |
Delaware |
General partner in Kissimee Power Partners, Limited Partnership |
QF |
|
Okeechobee Power III, Inc. |
Delaware |
Limited Partner in Kissimee Power Partners, Limited Partnership |
QF |
|
ONSITE Energy, Inc. |
Oregon |
Domestic holding company for ONSITE Soledad, Inc. and ONSITE Marianas Corporation; also indirectly holds general partner interest in Mt. Poso project and limited partner interest in Turners Falls project |
QF |
|
ONSITE Funding Corporation |
Oregon |
Provides funding to various ONSITE projects |
Inactive |
|
ONSITE Limited Partnership |
Oregon |
Owned cogeneration facilities for bakery in Los Angeles and dairy in Michigan |
Inactive |
|
ONSITE Marianas |
Commonwealth of the Northern Marianas Islands |
Owned and operated Marianas solar energy plant in the Commonwealth of Northern Mariana Islands in Pacific Ocean |
Inactive |
|
ONSITE Soledad, Inc. |
Oregon |
Owned and operated Soledad wood burning power plant in California |
Inactive |
|
ONSITE/Haines Limited |
Oregon |
Owned wood burning power plant in Alaska |
Inactive |
|
ONSITE/Molokai, Limited |
Oregon |
Owned and operated biomass fueled Molokai power plant in Hawaii |
Inactive |
|
ONSITE/US Power Limited |
Oregon |
Owned Crossroads cogeneration facility in New Jersey |
Inactive |
|
Orrington Waste, Ltd. Limited |
Oregon |
Provides waste disposal services to municipalities to be delivered to waste disposal operators in Maine, including Penobscot Energy Recovery Company |
QF and |
|
Oswego Harbor Power LLC |
Delaware |
Formed for the purpose of acquiring, operating and owning the electric generating plant in Oswego, New York |
EWG |
|
P.T. Dayalistrik Pratama |
Indonesia |
Will own and construct West Java coal-fired power plant in Indonesia |
Inactive |
|
Pacific Crockett Energy, Inc. |
Utah |
General Partner in Crockett Cogeneration, A California Limited Partnership |
QF |
|
Pacific Crockett Holdings, |
Oregon |
Domestic holding company for Pacific Crockett Energy, Inc. |
QF |
|
Pacific Generation Company |
Oregon |
Domestic holding company acquired by NRG (formerly a wholly owned subsidiary of PacifiCorp Holdings, Inc. which developed, built, owned, operated and managed energy production facilities); also a limited partner in Camas Power Boiler Limited Partnership |
QF |
|
Pacific Generation |
Oregon |
Provided domestic business development services |
Inactive |
|
Pacific Generation Holdings |
Oregon |
Domestic holdings company for Pacific Generation Funding and Pacific Recycling Energy; holds limited partner interests in Carolina Energy, Limited Partnership and Project Finance Fund III; and indirectly holds general partner interest in Kingston Cogeneration Limited Partnership |
QF and |
|
Pacific Generation Resources |
Oregon |
Domestic holding company which holds limited partner interest in Long Island Cogeneration, L.P.; holds limited and general partner interests in Curtis/Palmer, Windpower 87 and Windpower 88 projects; general partner in ENI Chester, Limited Partnership |
Rule 58(b)(1)(vi); Rule 58(b)(1)(viii) |
|
Pacific Kingston Energy, Inc. |
Canada |
General Partner in Kingston Cogeneration Limited Partnership |
EWG |
|
Pacific Orrington Energy, Inc. |
Oregon |
Holds general and limited partner interests in Orrington Waste, Ltd., Limited Partnership |
QF |
|
Pacific Recycling Energy, Inc. |
Oregon |
Provided business development services for waste-to-energy projects |
Inactive |
|
Pacific-Mt. Poso Corporation |
Oregon |
General Partner in Mt. Poso Cogeneration Company, A California Limited Partnership |
QF |
|
Penobscot Energy Recovery |
Maine |
Owns waste-to-energy facility in Orrington, Maine |
QF and |
|
Pittsburgh Thermal, Limited |
Delaware |
Provides district heating and cooling services in Pittsburgh |
QF and |
|
Power Operations, Inc. |
Delaware |
Provides O&M services for Artesia, Cadillac, Newark and Parlin projects |
QF |
|
Project Finance Fund III, L.P. |
Delaware |
Funding vehicle for various (primarily) international operating projects |
QF |
|
Pyro-Pacific Operating |
California |
Operates Mt. Poso cogeneration facility in California |
QF |
|
RSD Power Partners, L.P. |
Delaware |
Owns and operates a power and cooling plant in California |
QF |
|
Saale Energie GmbH |
Germany |
International holding company for Kraftwerk Schkopau Betriebsgesellschaft mbH, Kraftwerk Schkopau GbR and Saale Energie Services GmbH (Germany) |
EWG |
|
Saale Energie Services GmbH |
Germany |
Provides consulting services to MIBRAG |
EWG |
|
Sachsen Holding B.V. |
Netherlands |
International holding company for P.T. Dayalistrik Pratama |
Inactive |
|
San Bernardino Landfill Gas |
Delaware |
Partnership holding interest in QF landfill project |
QF |
|
San Francisco Thermal, |
Delaware |
Provides district heating and cooling services in California |
QF |
|
San Joaquin Valley Energy I, |
California |
General Partner in San Joaquin Valley Energy Partners I, L.P. |
QF |
|
San Joaquin Valley |
California |
General partner in San Joaquin Valley Energy Partners IV, L.P. and Bioconversion Partners, L.P. |
QF |
|
San Joaquin Valley Energy |
California |
Owns and operates three biomass waste-fuel power plants (Chowchilla II, El Nido and Madera) in California |
QF |
|
San Joaquin Valley Energy |
California |
Holds remaining non-operating assets of biomass waste-fuel power plant (Chowchilla I) in California |
QF |
|
Scoria Incorporated |
Minnesota |
Holds license for synthetic coal technology |
QF and |
|
Scudder Latin American |
Cayman Islands, British West Indies |
Investment company which owns (primarily passive) investments in Latin American power projects |
EWG |
|
Scudder Latin American |
Cayman Islands, British West Indies |
Investment company which owns (primarily passive) investments in Latin American power projects |
EWG |
|
Scudder Latin American |
Cayman Islands, British West Indies |
Investment company which owns (primarily passive) investments in Latin American power projects - phase II |
EWG |
|
Scudder Latin American |
Cayman Islands, British West Indies |
Investment company which owns (primarily passive) investments in Latin American power projects - phase II |
EWG |
|
Scudder Latin American |
Cayman Islands, British West Indies |
Investment company which owns (primarily passive) investments in Latin American power projects - phase II |
EWG |
|
Scudder Latin American |
Cayman Islands, British West Indies |
Investment company which owns (primarily passive) investments in Latin American power projects - phase II |
EWG |
|
Somerset Operations Inc. |
Delaware |
Proposed operator for Somerset coal fired power plant in Massachusetts |
EWG |
|
Somerset Power LLC |
Delaware |
Acquire, operate and own the electric generating plant in Somerset, Massachusetts |
EWG |
|
STS Hydropower Ltd. |
Michigan |
Owns and operates hydroelectric projects in California, Colorado, Michigan, Virginia and Washington |
QF |
|
STS Turbine & Development, |
Delaware |
Provides turbine design and project development services |
QF and |
|
Suncook Energy LLC |
Delaware |
Landfill gas fueled power generation for Nashua project in New Hampshire |
QF and |
|
Sunnyside Cogeneration |
Utah |
Owns waste coal power plant in Utah |
QF and |
|
Sunnyside Operations |
Delaware |
Operates waste coal power plant in Utah |
QF and |
|
Sunshine State Power (No. 2) |
Netherlands |
International holding company which holds a 17.5% undivided interest in Gladstone Power Station Joint Venture |
EWG |
|
Sunshine State Power B.V. |
Netherlands |
International holding company which holds a 20% undivided interest in Gladstone Power Station Joint Venture |
EWG |
|
Tacoma Energy Recovery |
Delaware |
Operate and manage power plant for City of Tacoma |
QF |
|
The PowerSmith |
Delaware |
Owns PowerSmith cogeneration facility in Oklahoma |
QF [Rule 58(b)(1)(viii)] |
|
Tosli (Gibraltar) B.V. |
Netherlands |
Company formed to assist with Cobee tender offer |
EWG |
|
Tosli Acquisition B.V. |
Netherlands |
Company formed to assist with Cobee tender offer |
EWG |
|
Tosli Investments N.V. |
Netherlands |
International holding company for Compania Boliviana de Energia Electrica S.A. in Latin America |
EWG |
|
Turners Falls Limited |
Massachusetts |
Owns Turners Falls cogeneration facility in Massachusetts |
QF |
|
Wainstones Power Limited |
England and Wales |
Will build, own and operate 800MW combined cycle gas turbine power plant on greenfield site at Langage England (f/k/a Plymouth Energy Centre) |
EWG |
|
WCP (Generation) Holdings |
Delaware |
Jointly owned entity between the owners and West Coast Power LLC |
EWG |
|
West Coast Power LLC |
Delaware |
West coast holding company entity designed to facilitate west coast asset pool financing |
EWG |
IV. Subsidiaries of Eloigne Company
|
|
Location of Incorporation |
|
|
|
Safe Haven Homes LLC |
Delaware |
Affordable housing primarily within the Company's service area |
Prior Commission precedent[167] |
|
Lauring Green Ltd. Ptsp. |
Minnesota |
|
Same |
|
Bemidji Townhouse Ltd. Ptsp. |
Minnesota |
|
Same |
|
Central Towers Limited |
Minnesota |
|
Same |
|
Driftwood Partners Ltd. Ptsp. |
Minnesota |
|
Same |
|
Colfax Prairie Homes Limited |
Wisconsin |
|
Same |
|
Cottage Court Ltd. Ptsp. |
Minnesota |
|
Same |
|
Ctg. Homesteads Hillcrest |
Minnesota |
|
Same |
|
Cottages of Spring Lake Park |
Minnesota |
|
Same |
|
Cottages of Vadnais Heights |
Minnesota |
|
Same |
|
Ctg. Homesteads of Willow |
Minnesota |
|
Same |
|
Albany Countryside |
Minnesota |
|
Same |
|
RWIC Credit Fund Ltd. Ptsp. |
Minnesota |
|
Same |
|
Marvin Gardens Ltd. Ptsp. |
Minnesota |
|
Same |
|
Crown Ridge Apartments Ltd. |
Minnesota |
|
Same |
|
Sioux Falls Housing Equity |
South Dakota |
|
Same |
|
East Creek Limited |
Minnesota |
|
Same |
|
Edenvale Family Housing |
Minnesota |
|
Same |
|
Granite Hill Ltd. Ptsp. |
Minnesota |
|
Same |
|
Groveland Terrace |
Minnesota |
|
Same |
|
Plover Limited Liability Co. |
Wisconsin |
|
Same |
|
Jefferson Heights Townhomes |
Minnesota |
|
Same |
|
Lakeville Court Ltd. Ptsp. |
Minnesota |
|
Same |
|
Majestic View Apartments, |
South Dakota |
|
Same |
|
Marsh Run Ltd. Ptsp. |
Minnesota |
|
Same |
|
Oakdale Leased Housing Ltd. |
Minnesota |
|
Same |
|
Wyoming Limited Partnership |
Minnesota |
|
Same |
|
J&D 14-93 Ltd. Ptsp. |
Minnesota |
|
Same |
|
Park Rapids Housing Limited |
Minnesota |
|
Same |
|
MDI Ltd. Ptsp. #44 |
Minnesota |
|
Same |
|
Sioux Falls Partners Ltd. Ptsp. |
South Dakota |
|
Same |
|
806 N. Hazel Ltd. Ptsp. |
Minnesota |
|
Same |
|
Links Lane, A Ltd. Ptsp. |
Minnesota |
|
Same |
|
Polynesian Village 1994 Ltd. |
Minnesota |
|
Same |
|
Sioux River Ltd. Ptsp. |
South Dakota |
|
Same |
|
Stradford Flats Ltd. Ptsp. |
Minnesota |
|
Same |
|
Brooklyn Ctr. Leased Housing |
Minnesota |
|
Same |
|
Fairview Ridge Ltd. Ptsp. |
Minnesota |
|
Same |
|
Tower Terrace Ltd. Ptsp. |
Minnesota |
|
Same |
|
R & W Partners Ltd. Ptsp. |
Minnesota |
|
Same |
|
Mahtomedi Woodland |
Minnesota |
|
Same |
|
Woodland Village |
Minnesota |
|
Same |
V. Subsidiaries of Energy Masters International, Inc.
|
|
Location of Incorporation |
|
|
|
Energy Solutions International |
Minnesota |
|
Rule 58(b)(1)(i) |
____________________________
[145]New Century Energies, Inc., Holding Co. Act Release No. 26748 (Aug. 1, 1997) (approving retention of Southwestern Public Service Capital I, as special purpose trust of SPS). [145]New Century Energies, Inc., Holding Co. Act Release No. 26748 (Aug. 1, 1997) (approving retention of Southwestern Public Service Capital I, as special purpose trust of SPS). [145] New Century Energies, Inc., Holding Co. Act Release No. 26748 (Aug. 1, 1997) (approving retention of Southwestern Public Service Capital I, as special purpose trust of SPS). New Century Energies, Inc., Holding Co. Act Release No. 26748 (Aug. 1, 1997) (approving retention of Southwestern Public Service Capital I, as special purpose trust of SPS). [145] New Century Energies, Inc., Holding Co. Act Release No. 26748 (Aug. 1, 1997) (approving retention of Southwestern Public Service Capital I, as special purpose trust of SPS).[146]WPL Holdings, Inc. , Holding Co. Act Release No. 26856 (April 14, 1998).
[147]American Electric Power Service Co., Holding Co. Act Release No. 19981 (April 12, 1977).
[148]UNITIL Corporation , Holding Co. Act Release No. 25524 (April 24, 1992).
[149]New Century Energies, Inc., supra (approving the activity of selling or entering into "royalty arrangements with regard to intellectual property owned or developed" by PSC).
[150]WPL Holdings, Inc., Holding Co. Act Release No. 26856 (April 14, 1998).
[151]UNITIL Corporation , supra.
[152]New Century Energies, Inc., supra; UNITIL Corp., Holding Co. Act Release No. 25524 (April 24, 1992); and Commonwealth & Southern Corp., Holding Co. Act Release No. 7615 (Aug. 2, 1947).
[153]WPL Holdings, Inc. , supra.
[154]Entergy Corporation , Holding Co., Act Release No. 26322 (June 30, 1995).
[155]Id.
[156]Id.
[157]CINergy Corporation, Holding Co. Act Release No. 26376 (September 21, 1995).
[158]Id.
[159]Id.
[160]Id.
[161]Id.
[162]Id.
[163]Entergy Corporation , supra.
[164]Id.
[165]Id.
[166]Id.
[167]WPL Holdings, Inc. , Holding Co. Act Release No. 26856 (April 14, 1998) (approving retention of a non-utility subsidiary engaged in the "development, ownership, and sales of, and asset management services in connection with, affordable multi-family housing properties").
Annex E
AFFILIATE CONTRACTS
SALE OF ELECTRICITY
Minnesota Methane sells power from its QF facility in Burnsville, Minnesota to NSP pursuant to a power purchase agreement approved by the MPUC in Docket No. E002/AI-94-378. Similarly, Landfill Power sells power to NSP from its QF facilities in Eden Prairie, Minnesota and Inver Grove Heights, Minnesota pursuant to power purchase agreements approved by the MPUC in Docket Nos. E002/AI-95-371 and E002/AI-95-570, respectively. NSP entered into these contracts in accordance with PURPA.
SALE OF FUEL FOR ELECTRIC GENERATION
Washco sells wood by-product purchased from Andersen Corporation to NSP for use as fuel in generating facilities. The price for the wood by-product equals the average cost per MMBtu of solid fuel delivered to a NSP generating plant during the calendar year. This contract was approved by the MPUC in Docket No. E002/M-86-775.
NSP purchases RDF from the Newport facility. This contract was approved by the MPUC in Docket No. E002/AI-93-821.
GENERATION FUEL PROCESSING SERVICES
NRG operates a municipal solid waste transfer station and Minnesota Waste Processing's RDF storage facility on land leased from NSP adjacent to NSP's Wilmarth steam generating facility. The RDF storage facility collects and distributes municipal solid waste and stores RDF for distribution to generating facilities. This contract was approved by the MPUC in Docket No. E002/AI-94-950. NRG also operates the Newport RDF facility, the Elk River RDF facility and the Becker ash landfill on behalf of NSP. This contract and subsequent contract amendments were approved by the MPUC in Docket Nos. E002/AI-93-770 and E002/AI-95-171. A contract formalizing the arrangement where the above RDF facilities owned by NSP and operated and maintained by NRG was approved by the MPUC in Docket No. E-002/AI-96-966.
URANIUM FUEL ENRICHMENT SERVICES
Louisiana Energy Services (LES) is a joint venture which operates a nuclear enrichment facility in Louisiana. NSP's wholly owned subsidiary, NRG Energy, Inc. ("NRG"), owns 100% of Graystone Corporation (Graystone), an investor in uranium enrichment services. Graystone is a general partner in the LES venture, and also owns LePaz Inc., which is a limited partner in LES. Together, Graystone and LePaz own 6.74% of LES.
Under the terms of the contract, LES supplies 30% of NSP's enrichment services needs for the period October 1, 1995 through September 30, 2005. The remainder of NSP's enrichment services needs are purchased on the spot market. This contract was approved by the MPUC in Docket No. E002/AI-92-1164.
SALE OF NATURAL GAS SUPPLY AND RELATED SERVICES
Under an umbrella gas agreement, NSP may purchase interruptible spot gas supplies from EMI, make sales to EMI and release to EMI its firm unutilized transportation rights on both unaffiliated gas pipelines and on Viking. This contract was approved by the MPUC in Docket No. G002/AI-98-071. The MPUC order allows NSP to purchase gas supplies from EMI only when NSP receives at least three bids (two from non-affiliates) and EMI offers the lowest bid. Recovery of the gas supply cost from retail ratepayers is also subject to MPUC audit and potential disallowance if the contracting principles are not followed.
NSP-W has a similar agreement with EMI to release pipeline capacity or to purchase pipeline capacity from one another pursuant to rules and filed tariff provisions approved by FERC. The agreement was approved in PSCW Docket No. 4220-AU-118.
However, EMI transferred its gas supply merchant function to NSP Energy Marketing in February 1999, and NSP and NSP-W have no current transactions with EMI under the umbrella affiliate agreements.
SALE OF NATURAL GAS TRANSPORTATION AND RELATED SERVICES
Under FERC rules, Viking must provide transportation service on a non-discriminatory basis to all eligible shippers of natural gas pursuant to a tariff on file with FERC, [168] including standard form contracts. Viking currently provides firm transportation ("FT"), interruptible transportation ("IT") and authorized overrun transportation ("AOT") services for NSP and NSP-W pursuant to several transportation contracts.[169] Viking also previously provided certain transportation services for EMI. [170] In addition, FERC has adopted rules - called Order Nos. 497 and 566 - (18 CFR §§ 161 and 275) governing the relationship between Viking and its affiliated LDCs (e.g., NSP or NSP-W) and gas marketing affiliates (e.g., EMI). The rules prohibit any service preference to affiliated marketers and impose operational restrictions on affiliated LDCs.
Viking also contracts to construct certain natural gas pipeline facilities for non-affiliates and affiliates (such as a town border station ("TBS") or lateral lines) pursuant to a standard form Reimbursement Agreement which requires the contracting customer to pay the installed cost of the new facility either up-front or by contracting for incremental transportation services for a period of time, all as required by Viking's FERC Gas Tariff. The facilities constructed are subject to FERC "blanket certificate" construction jurisdiction under the Natural Gas Act and 18 CFR Part 157. NSP and NSP-W have entered into Reimbursement Agreements with Viking to facilitate reliable gas service to existing and new customers. [171] Viking has entered into similar Reimbursement Agreements with several other non-affiliated shippers. [172]
NSP Generation, a business unit of NSP and a regulated jurisdictional utility within Minnesota, owns and operates two 105 MW natural gas fired combustion turbines at the Angus Anson Generation Site at Sioux Falls, South Dakota. NSP Generation and NSP Gas, another business unit of NSP and a regulated jurisdictional utility within Minnesota, entered into an arrangement for NSP Gas to provide natural gas supply management services for gas fuel delivered to the two turbines. Under the terms of the arrangement, NSP Gas provides services (supply management services, daily nominations, scheduling, and imbalance reconciliation) and NSP Generation pays a fee. Under the 1993 amendments of Minn. Stat 216B.48, the MPUC found that, for this docket only, this contract qualifies as an affiliated interest agreement because NSP's gas business and NSP's electric business are separate public utilities, even if they are within the same legal entity. Future transactions between business units will be evaluated on a case by case basis. This contract was approved by the MPUC in Docket No. E002/AI-94-729.
SALE OF STEAM
NSP sells steam to NRG for its Wascho operations for resale to Andersen Corporation and to a Minnesota correctional facility. This contract was approved by the MPUC in Docket No. E002/M-86-775.
NRG purchases steam for its Waldorf (now RockTenn Corp.) process steam operation from NSP's High Bridge power generation facility. This contract was approved by the MPUC in Docket No. E002/CI-82-523.
NSP sells steam and electricity from its Sherco Generating Plant to Liberty Paper, Inc. ("LPI"). NSP supplies steam to satisfy LPI's thermal energy needs and provides LPI with about eight megawatts of electricity under tariffed rates. NSP treated the construction and continues to treat the operation of the steam supply system as a non-regulated venture and, as such, segregates the plant investment from utility rate base and records operating and maintenance expenses and revenue in non-utility operating accounts. This contract was approved by the MPUC in Docket No. E002/M-93-1253.
GAS SUPERVISORY CONTROL AND DATA ACQUISITION AND DISPATCHING SERVICES
NSP supplies NSP-W and Viking with supervisory control and data acquisition ("SCADA") services for their gas businesses pursuant to separate contracts with Viking and NSP-W. NSP also supplies NSP-W gas dispatching and other services. Both contracts were approved by the MPUC in Docket No. G002/AI-94-831, and the contract between NSP and NSP-W was approved by the PSCW in Docket No. 4220-AU-117. A SCADA system electronically communicates gas flow, gas pressure, and gas equipment set point data for the delivery system and records the data in a computerized data storage system for monitoring and control purposes. Gas dispatching includes monitoring and controlling the flow, pressures and operating conditions of a natural gas delivery system through the use of a SCADA system. The agreements enable NSP, NSP-W and Viking to share the costs of a single system rather than each owning and operating a SCADA system. The three companies are each allocated and billed a share of the actual costs incurred by NSP on a monthly basis based on the number of metering points monitored for each company.
CABLE TESTING SERVICES
Ultra Power Technologies, Inc. ("Ultra Power") is a wholly-owned subsidiary of NSP which has acquired from Instrument Manufacturing Corporation all rights to a technology for detecting problems and defects in underground cables from an above ground position. Ultra Power markets and delivers these services to utilities throughout the United States and Canada. NSP procures services from Ultra Power on a regular basis under terms which are equivalent to terms offered to other customers. This affiliated interest was approved by the MPUC in Docket No. E002/AI-97-1677.
NUCLEAR MANAGEMENT COMPANY SERVICES
NSP and Nuclear Management Company, LLC ("NMC"), an affiliate of NSP, are parties to a service agreement and an employee lease. NMC was formed in February 1999 by: WEC Nuclear Corporation, an affiliate of Wisconsin Energy Corporation; WPS Nuclear Corporation, an affiliate of Wisconsin Public Service Resources, Corporation; and NSP. Alliant Energy Resources, Inc. also entered into an agreement with the NMC owners to become a member upon approval of the Commission.
The services agreement assures that resources provided by NSP to NMC are charged at NSP's fully allocated cost and that when NSP pays NMC for services it will pay the fully allocated cost of NMC-directed utility employees charging time to NSP plus portions of NMC overhead costs. The employee lease agreement outlines the terms and conditions under which NSP will make its employees available to the NMC, that they will remain employees of NSP, and that NSP retains overall direction and control of its employees. This service agreement and employee lease were approved by the MPUC in Docket No. E-002/AI-99-618.
NSP separately filed for approval of a Nuclear Power Plant Operating Services Agreement to transfer operations of its plants (but not ownership) to the NMC. This filing is pending approval before the MPUC.
MANAGEMENT OR LEASING OF LAND OR OTHER FACILITIES
NSP manages the Renaissance Square Office Building for United Power & Land ("UP&L"). NSP provides this service in exchange for two percent (2%) of the building's gross annual rents. This contract was approved by the MPUC in Docket No. E002/AI-94-1188.
UP&L leases office space on floors two through eleven of the Renaissance Square office building to NSP. This contract was approved by the MPUC in Docket No. E002/AI-90-845. UP&L also leases office space on the first floor and in the basement of the Renaissance Square office building to NSP. This contract was approved by the MPUC in Docket No. E002/AI-94-1056.
First Midwest Auto Park ("FMAP") leases 14,000 square feet of unimproved storage area to NSP in the first and second floors of the parking garage adjacent to NSP's headquarters. This contract was approved by the MPUC in Docket No. E002/AI-94-1043. FMAP also leases 92 parking spaces in the parking facility to NSP. This contract was approved by the MPUC in Docket No. E002/AI-94-1042.
Seren Innovations, Inc. ("Seren"), a wholly-owned subsidiary of NSP, entered into a lease agreement with NSP which allows Seren to attach cable or similar telecommunications facilities to NSP's distribution poles, conduits, ducts and other properties. The lease is effective February 20, 1998 through December 31, 2018, and is applicable in Minnesota, South Dakota and North Dakota. This contract was approved by the MPUC in Docket No. E002/AI-98-377. Under the federal Telecommunications Act of 1996, NSP is obligated to provide access to its poles, etc., to telecommunications providers. NSP has entered into similar facility access lease agreements with several non-affiliated telecommunications providers.
INTELLECTUAL PROPERTY
Reddy Kilowatt Corporation ("RKC") is a wholly-owned subsidiary of NSP which owns and licenses use of the Reddy KilowattR and Reddy FlameTM trademarks ("Trademarks"). On October 1, 1999, NSP and RKC entered into a Trademark License Agreement allowing NSP to use the Trademarks for an annual fee. The MPUC approved the agreement effective October 1, 1999, in Docket No. G,E-002/AI-99-1418.
CORPORATE ADMINISTRATIVE SERVICES AND OTHER
As a parent holding company exempt from registration with the Commission, NSP has entered into Administrative Services Agreements and Tax Sharing Agreements with its various subsidiaries. An Administrative Services Agreement ("ASA") provides a contractual mechanism whereby NSP provides corporate services to (or sometimes receives services from) the affiliate and charges (or is charged) on a fully-allocated cost basis consistent with the MPUC's fully-allocated costing policy adopted in Docket No. G,E-999/CI-90-1008 (order dated December 1994). A Tax Sharing Agreement ("TSA") provides a contractual means for NSP and the affiliate to share the benefits of the consolidated NSP corporate tax return. The charges from NSP to the affiliate and payments by NSP to the affiliate are reported to the MPUC annually in financial reports filed pursuant to Minn. Rule 7825.4900.
The MPUC has reviewed and approved the various ASA and TSA agreements in a series of orders issued since 1992:
Docket No.
E002/AI-92-148 (NRG Energy, Inc.);
Docket No. G002/AI-93-1235 (Viking
Gas Transmission Company);
Docket No. E002/AI-94-41 (Energy
Masters International, Inc.
f/k/a Cenergy, Inc.);
Docket No. E002/AI-94-1041 (First
Midwest Auto Park, Inc.);
Docket No. E002/AI-94-934 (Eloigne
Company);
Docket No. E002/AI-97-1677 (Ultra
Power Technologies, Inc.);
Docket No. E002/AI-97-300 (Seren
Innovations, Inc.);
Docket No. E,G002/AI-98-1513
(Northern States Power
Company-Wisconsin);
Docket No. G002/PA-99-46 (Black
Mountain Gas Company);
Docket No. G,E002/AI-99-1418 (Reddy
Kilowatt Corp.); and
Docket No. G002/PA-99-1268 (Natrogas,
Inc. and North American
Energy, Inc.)
The ASA and TSA between NSP and NSP-W were also approved by the Wisconsin Commission in PSCW Docket Nos. 4420-AU-117 and 4220-AU-121. The ASA and TSA between NSP and Black Mountain Gas were also approved by the Arizona Commission in ACC Docket Nos. G-03493A-99-0054 and G-0307A-99-0054 (Decision 61914, August 1999).
Upon effectuation of the Merger, the Administrative Service Agreements would be terminated and replaced by utility or non-utility service agreements between Service Company and the respective affiliate, using Commission cost allocation procedures. Upon effectuation of the Merger, the Tax Sharing Agreements would also be terminated or assigned, and the allocation of taxes between Xcel and its utility operating companies and other affiliates would be determined by Commission cost allocation procedures.
___________________________
[168]Viking's current rates effective January 1, 1999 were established on a cost of service basis and were approved by FERC by order dated May 12, 1999. Viking Gas Transmission Co., 87 FERC ¶ 61,167 (1999). Viking Gas Transmission Co Viking Gas Transmission Co Viking Gas Transmission Co Viking Gas Transmission Co[169]The contracts between NSP and Viking were reviewed in the following dockets: FERC Dockets ST92-1412, ST94-5658 and ST94-5659 and MPUC Dockets G002/AI-93-1235, G002/AI-94-738 and G002/AI-93-1235. In addition, NSP's firm transportation contract quantities with Viking (and non-affiliated pipelines) are reviewed annually by the MPUC under Minn. Rule 7825.2910, Subp. B. The contracts between Viking and NSP-W were reviewed in the following dockets: FERC Dockets ST92-2273, ST94-5660, ST95-2361 and ST94-5661. Since FERC has primary jurisdiction over these agreements, NSP-W is not required to seek Wisconsin Commission approval.
[170]These services for EMI were approved by FERC in Docket numbers ST94-4797 and ST95-0784.
[171]The Viking blanket certificate filings for facilities constructed for NSP were reviewed in FERC Docket Nos. CP95-308-000, CP96-39-000, and CP97-676-000. The Viking blanket certificate filing for facilities constructed for NSP-W was approved in Docket No. CP97-619-000. The various Viking Reimbursement Agreements with NSP were also reviewed by the MPUC in Docket Nos. G002/AI-94-698, G002/AI-95-239, G002/AI-96-817, G002/AI-97-1222, G002/AI-98-1296 and G002/AI-99-830.
[172]E.g., FERC Docket No. CP95-323-000 (Reliant Energy Minnegasco, Inc.); Docket No. CP95-539-000 (City of Randall, MN); CP97-21-000 (RDO Foods); Docket No. CP98-625-000 (Wisconsin Gas Company); and Docket No. CP98-626-000 (Wisconsin Gas Company).
EXHIBIT B-2
FORM OF UTILITY SERVICE AGREEMENT [ALSO APPLICABLE TO AFFILIATES THAT SUPPORT UTILITY OPERATIONS]
SERVICE AGREEMENT
This Service Agreement is made and entered into this ____ day of ____________, 1997, by and between ________ ("Client Company") and New Century Services, Inc. [new name] ("Service Company").
WITNESSETH
WHEREAS, the Securities and Exchange Commission ("SEC") has approved and authorized as meeting the requirements of Section 13(b) of the Public Utility Holding Company Act of 1935 ("Act") the organization and conduct of the business of Service Company, in accordance herewith, as a wholly-owned subsidiary service company of New Century Energies, Inc. ("NCE"); and
WHEREAS, Client Company is a utility operating company subsidiary of NCE and an affiliate of Service Company; and [alternatively: Client Company is an affiliate of Service Company that provides support services for the utility operations of the utility operating companies within the NCE system; and]
WHEREAS, Service Company and Client Company have entered into this Service Agreement whereby Service Company agrees to provide and Client Company agrees to accept and pay for various services as provided herein at cost, with cost determined in accordance with applicable rules and regulations under the Act, which require Service Company to fairly and equitably allocate costs among all associate companies to which it renders services, including Client Company.
NOW THEREFORE, in consideration of the premises and the mutual agreements herein contained, the parties to this Service Agreement covenant and agree as follows:
ARTICLE I - SERVICES
Section 1.1 Service Company shall furnish to Client Company, as requested by Client Company, upon the terms and conditions hereinafter set forth, such of the services described in Attachment A hereto, at such times, for such periods and in such manner as Client Company may from time to time request and that Service Company concludes it is able to perform. Service Company shall also provide Client Company with such special services, in addition to those services described in Attachment A hereto, as may be requested by Client Company and that Service Company concludes it is able to perform. In supplying such services, Service Company may arrange, where it deems appropriate, for the services of such experts, consultants, advisers, and other persons with necessary qualifications as are required for or pertinent to the provision of such services.
Section 1.2 Client Company shall take from Service Company such of the services described in Section 1.1, and such additional general or special services, whether or not now contemplated, as are requested from time to time by Client Company and that Service Company concludes it is able to perform.
Section 1.3 The services described herein or contemplated to be performed hereunder shall be directly assigned, distributed or allocated by activity, project, program, work order or other appropriate basis. Client Company shall have the right from time to time to amend, alter or rescind any activity, project, program or work order provided that (i) any such amendment or alteration that results in a material change in the scope of the services to be performed or equipment to be provided is agreed to by Service Company, (ii) the cost for the services covered by the activity, project, program or work order shall include any expense incurred by Service Company as a direct result of such amendment, alteration or rescission of the activity, project, program or work order, and (iii) no amendment, alteration or rescission of an activity, project, program or work order shall release Client Company from liability for all costs already incurred by or contracted for by Service Company pursuant to the activity, project, program or work order, regardless of whether the services associated with such costs have been completed.
Section 1.4 Service Company shall use its best efforts to maintain a staff trained and experienced in the design, construction, operation, maintenance, and management of public utility properties.
ARTICLE II - COMPENSATION
Section 2.1 As compensation for the services to be rendered hereunder, Client Company shall pay to Service Company all costs which reasonably can be identified and related to particular services performed by Service Company for or on its behalf. The methods for assigning or allocating Service Company costs to Client Company, as well as to other associate companies, are set forth in Attachment A.
Section 2.2 The methods of assignment, distribution or allocation of costs described in Attachment A shall be subject to review annually, or more frequently if appropriate. Such methods of assignment, distribution or allocation of costs may be modified or changed by Service Company; provided, however, that no changes will be made to the methods of assignment, distribution, or allocation set forth herein or in Attachment A hereto unless first authorized by the SEC in accordance with the procedures specified in Section 2.3. Service Company shall advise Client Company from time to time of such changes.
Section 2.3 No change in the organization of NC Services, the type and character of the companies to be serviced, the methods of allocating costs to associate companies, or in the scope or character of the services to be rendered subject to Section 13 of the Act, or any rule, regulation or order thereunder, shall be made unless and until NC Services shall first have given the SEC written notice of the proposed change not less than 60 days prior to the proposed effectiveness of any such change. If, upon the receipt of any such notice, the SEC shall notify NC Services within the 60-day period that a question exists as to whether the proposed change is consistent with the provisions of Section 13 of the Act, or of any rule, regulation or order thereunder, then the proposed change shall not become effective unless and until NC Services shall have filed with the SEC an appropriate declaration regarding such proposed change and the SEC shall have permitted such declaration to become effective.
Section 2.4 Service Company shall render a monthly statement to Client Company that shall reflect the billing information necessary to identify the costs charged for that month. By the twentieth (20th) day of each month, Client Company shall remit to Service Company all charges billed to it.
Section 2.5 It is the intent of this Service Agreement that the payment for services rendered by Service Company to Client Company under this Service Agreement shall cover all the costs of its doing business (less the costs of services provided to affiliated companies not a party to this Service Agreement and to other non-affiliated companies, and credits for any miscellaneous items), including, but not limited to, salaries and wages, office supplies and expenses, outside services employed, property insurance, injuries and damages, employee pensions and benefits, miscellaneous general expenses, rents, maintenance of structures and equipment, depreciation and amortization, compensation for use of capital as permitted by Rule 91 of the SEC's regulations under the Act.
ARTICLE III - TERM
Section 3.1 This Service Agreement shall become effective subject to the receipt of required regulatory approval, and shall continue in force until terminated by Service Company or Client Company, upon not less than one year's prior written notice to the other party. This Service Agreement shall also be subject to termination or modification at any time, without notice, if and to the extent performance under this Service Agreement may conflict with the Act or with any rule, regulation or order of the SEC adopted before or after the date of this Service Agreement.
ARTICLE IV - LIMITATION OF LIABILITY AND INDEMNIFICATION
Section 4.1 In performing the services hereunder, Service Company will exercise due care to assure that the services are performed in an appropriate manner, meet the standards and specifications set forth in any applicable request for service and comply with the applicable standards of law and regulation. However, failure to meet these obligations shall in no event subject Service Company to any claims by or liabilities to Client Company other than to reperform the services and be reimbursed at cost for such reperformance. Service Company makes no other warranty with respect to its performance of the services, and Client Company agrees to accept such services without further warranty of any nature.
Section 4.2 To the fullest extent allowed by law, Client Company shall and does hereby indemnify and agree to save harmless and defend Service Company, its agents and employees from liabilities, taxes, losses, obligations, claims, damages, penalties, causes of action, suits, costs and expenses or judgments of any nature, on account of, or resulting from the performance and prosecution of any services performed on behalf of Client Company pursuant to this Agreement, whether or not the same results or allegedly results from the claimed or actual negligence or breach of warranty of , or willful conduct by, Service Company or any of its employees, agents, clients, or contractors or its or their subcontractors or any combination thereof.
ARTICLE V - MISCELLANEOUS
Section 5.1 All accounts and records of Service Company shall be kept in accordance with the General Rules and Regulations promulgated by the SEC pursuant to the Act, in particular, the uniform System of Accounts for Mutual Service Companies and Subsidiary Service Companies in effect from and after the date hereof.
Section 5.2 New direct or indirect non-utility subsidiaries of NCE, which may come into existence after the effective date of this Service Agreement, may become additional client companies of Service Company and subject to a service agreement with Service Company. The parties hereto shall make such changes in the scope and character of the services to be rendered and the method of assigning, distributing or allocating costs of such services as specified in Attachment A, subject to the requirements of Section 2.3, as may become necessary to achieve a fair and equitable assignment, distribution, or allocation of Service Company costs among all associate companies including the new subsidiaries.
Section 5.3 Service Company shall permit Client Company access to its accounts and records, including the basis and computation of allocations.
IN WITNESS WHEREOF, the parties hereto have caused this Service Agreement to be executed as of the date and year first above written.
NEW CENTURY SERVICES, INC.
BY:_______________________________
&nbs
Name:
&nbs
Title:
& [COMPANY]
&nb
BY:_______________________________
&nbs
Name:
&nbs
Title:
Attachment A
DESCRIPTION OF SERVICES TO BE PROVIDED BY NEW CENTURY
SERVICES, INC. AND DETERMINATION OF CHARGES FOR SUCH
SERVICES TO THE OPERATING COMPANIES AND AFFILIATES
Description of Services Provided
A description of the services provided by NCS is detailed below. Identifiable costs will be directly assigned or distributed to the Operating Companies or affiliates. For costs which are for services of a general nature that cannot be directly assigned or distributed, the method of allocation is described below for each service provided.
a) Electric Commodity Services - Business Development.
Description - Provides administrative support services and business development opportunities to the Operating Companies electric generation stations.
Methods of Allocation - The Support of Plant Operations will be allocated to the Operating Companies based on the Electric kWh Generation Ratio.
b) Energy Supply Management and Bulk Power Transport
Description - Supervises and coordinates the electric transmission system control operations and dispatching for the Operating Companies.
Methods of Allocation - The Energy Supply Management and Bulk Power Transport services will be allocated to the Operating Companies based on the kWh Sales Ratio.
c) Purchased Power and Electric Trading
Description - Purchases power and provides electric trading services to the Operating Companies electric generation systems.
Method of Allocation - The Purchased Power and Electric Trading services will be allocated to the Operating Companies based on the Electric kWh Purchased Power Ratio.
d) Transmission, Substation Construction, Maintenance & Operations
Description - Provides management services to the Operating Companies transmission and substation construction, maintenance and operations areas.
Method of Allocation - Transmission, Substation Construction, Maintenance and Operations management services will be allocated to the Operating Companies based on the Transmission and Substation Construction Expenditures Ratios.
e) Transportation.
Description - Oversees the Operating Companies' Fleet Services Group.
Method of Allocation - Transportation will be allocated to the Operating Companies as well as other affected affiliates of NCS based on the Employees Ratio.
f) Supply Chain.
Description - Provides services in connection with the procurement of materials including the management of materials and supplies inventories.
Method of Allocation - Materials management will be allocated to the Operating Companies based on an average of the Revenue Ratio and the Total Construction Expenditures Ratio.
g) Facilities and Real Estate.
Description - Operates and maintains office buildings and service centers. Procures real estate and administers real estate leases. Administers contracts to provide security, housekeeping and maintenance services for such facilities. Procures office furniture and equipment
Method of Allocation - Facilities and Real Estate services will be allocated to the Operating Companies as well as affected affiliates based on the Square Footage Ratio.
h) Accounting.
Description - Maintains the books and records of New Century Energies, Inc. and its affected affiliates, prepares financial and statistical reports, prepares tax filings and supervises compliance with the applicable laws and regulations. Supports the accounting systems.
Method of Allocation - Accounting services will be allocated to the Operating Companies and affected affiliates based on an average of the Revenue Ratio, the Total Construction Expenditures Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc. Accounting system support services will be allocated based on the Accounting Transactions Ratio.
i) Payment and Reporting.
Description - Processes payments to vendors of New Century Energies, Inc. and its affected, affiliates, and prepares statistical reports.
Method of Allocation - Payment and reporting activities will be allocated to the Operating Companies and affected affiliates based on the Payment Transaction Ratio.
j) Finance and Treasury.
Description - Coordinates activities related to securities issuance, including maintaining relationships with financial institutions, cash management, investing activities and monitoring the capital markets. Performs financial and economic analysis.
Method of Allocation - Finance and Treasury activities will be allocated to the Operating Companies and affected affiliates based on an average of the Revenue Ratio, the Total Construction Expenditures Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
k) Rates and Regulation.
Description - Determines the Operating Companies' revenue requirements and rates for electric and gas customers. Coordinates the regulatory compliance requirements and maintains relationships with the regulatory bodies.
Method of Allocation - Rates and Regulation services will be allocated to the Operating Companies based an the Revenue Ratio.
l) Legal.
Description - Provides legal services related to labor and employment law, litigation, contracts, rates and regulation, environmental matters, real estate and other legal matters.
Method of Allocation - Legal services will be allocated to the Operating Companies and affected affiliates based on an average of the Payroll Ratio, the Revenue Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
m) Internal Audit.
Description - Reviews internal controls and procedures to ensure assets are safeguarded and transactions are properly authorized and recorded. Evaluates contract risks.
Methods of Allocation - Internal Auditing services will be allocated to the Operating Companies and affected affiliates based on the average of the Revenue Ratio, the Total Construction Expenditures Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
n) Corporate Communications.
Description - Prepares and disseminates information to employees, customers, government agencies, communities and the media.
Methods of Allocation - Corporate Communications services will be allocated to the Operating Companies and affected affiliates based on the Revenue Ratio, the Employee Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
o) Environmental.
Description - Establishes policies and procedures for compliance with environmental laws and regulations. Researches emerging environmental issues and monitors compliance with environmental requirements. Oversees environmental clean up projects.
Method of Allocation - Environmental services will be allocated to the Operating Companies and affected affiliates based on the Revenue Ratio.
p) Resource Acquisition and Analysis.
Description - Procures coal, natural gas and oil for the Operating Companies generation facilities. Ensures compliance with price and quality provisions of fuel contracts and arranges for transportation of fuel to the desired location. Purchases power and performs electric and gas trading services.
Method of Allocation - Resource Acquisition and Analysis services will be allocated to the Operating Companies based on the Electric kWh Generation Ratio or the Purchased Power Ratio, whichever is appropriate.
q) Corporate Planning.
Description - Facilitates preparation of strategic plans, monitors trends and evaluates business opportunities. Facilitates process improvements. Prepares budgets and financial forecasts.
Method of Allocation - Strategic Planning services will be allocated to the Operating Companies and affected affiliates based on the average of the Revenue Ratio, the Total Assets Ratio and Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
r) Investor Relations.
Description - Provides communications to investors and the financial community. Coordinates the transfer agent and shareholder record keeping functions.
Method of Allocation - Investor Relations services will be allocated to the Operating Companies and affected affiliates based on the average of the Revenue Ratio, the Total Assets Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
s) Human Resources.
Description - Establishes and administers policies and supervises compliance with legal requirements in the areas of employment, compensation, benefits and employee health, welfare and safety. Processes payroll and employee benefit payments. Coordinates contract negotiation and relations with labor unions.
Method of Allocation - Human Resources services will be allocated to the Operating Companies and affected affiliates based on the Payroll Ratio.
t) Customer Services.
Description - Performs customer billing, handles customer inquiries and complaints and provides related customer information services.
Method of Allocation - Customer Services will be allocated based on the Customers Ratio.
u) Information Systems.
Description - Administers the contract for various communications and electronic data processing services. Such services provided under the contract include, but are not limited to, development and support of mainframe computer software applications, procurement and support of personal computers, operation of a data center and installation and operation of a communications system.
Method of Allocation - Information Systems will be allocated based an the Information Systems direct charges.
v) Marketing Services.
Description - Provides marketing services including market load research and new product development for Operating Companies and affiliates.
Method of Allocation - Marketing services will be allocated based on the total Residential, Business, and Large Commercial and Industrial kWh sales ratio.
w) Wholesale and Bulk Power Sales.
Description - Provides sales and to support to electric wholesale customers of the Operating Companies.
Method of Allocation - Wholesale Sales will be allocated based on the Electric Wholesale Sales Ratio.
x) Residential and Business Sales.
Description - Provides sales and support to electric residential and business customers of the Operating Companies.
Method of Allocation - Residential and Business Sales will be allocated based on the Residential and Commercial Sales Ratio.
y) Custom Account Sales.
Description - Provides sales services to large commercial and industrial customers of the Operating Companies.
Method of Allocation - Custom Account Sales will be allocated based on the Large Commercial and Industrial Sales Ratio.
z) Strategic and Key Account Sales.
Description - Provides sales and support services to niche markets of the Operating Companies.
Method of Allocation - Strategic Account Sales will be allocated based on the total of the Large Commercial and Industrial and the Public Authority Sales Ratios. Key Account Sales will be allocated based on the Large Commercial and Industrial Sales Ratio.
aa) Community and Economic Development
Description - Provides community support and economic development services to the service territories of the Operating Companies.
Method of Allocation - Community and Economic Development services will be allocated based on the Total kWh Sales Ratio.
bb) Gas Marketing, Control, Planning and Supply.
Description - Provides marketing services to gas transport customers. Coordinates the planning and support for Gas operations of Public Service Company of Colorado, Cheyenne Light, Fuel and Power and WestGas Interstate Company including coordinating the operation of the gas system and well as the purchase of gas for the Operating Companies distribution business from third parties.
Method of Allocation - Gas Marketing, Control, Planning and Supply services will be allocated based on the Gas Throughput Ratio.
cc) Design n Engineering.
Description - Designs and monitors construction of electric transmission and distribution lines and substations.
Method of Allocation - Design Engineering services will be allocated based on the Transmission Construction Expenditures Ratio, the Distribution Construction Ratio, or a ratio based on the sum of the Transmission and Distribution Construction Expenditures whichever is appropriate.
dd) Substation Engineering and Support.
Description - Provides management support services to the Substation Engineering and Support organizations of the Operating Companies.
Method of Allocation - Substation Engineering and Support services will be allocated based on the Substation Construction Expenditures Ratio.
ee) Transmission Engineering and Right of Way Services.
Description - Provides management support services to the Transmission Engineering and Right of Way organizations of the Operating Companies.
Method of Allocation - Transmission Engineering and Right of Way services will be allocated based an the Transmission Construction Expenditures Ratio.
ff) Distribution Support Services.
Description - Provides planning, benchmarking, activity tracking and budget support services to the Construction and Operations and Maintenance Organization.
Method of Allocation - Distribution Support Services will be allocated based on the Total Customers Ratio.
gg) Aviation Services.
Description - Provides aviation and travel services to employees.
Method of Allocation - Aviation Services will be allocated to the appropriate Operating Companies and affiliates based on the Aviation Department's actual direct charges. (This method will allocate costs only to those companies who actually use aviation services).
hh) Governmental Affairs.
Description - Lobbies government officials and monitors, reviews and researches governmental legislation.
Method of Allocation - Governmental Affairs will be allocated based on the average of the Revenue Ratio, the Employee Ratio, and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
ii) Production Services.
Description - Provides performance, chemical and water testing and analysis, technical, and analytical services to the Operating Companies generation facilities.
Method of Allocation - Production Services will be allocated based on the kWh Generation Ratio.
jj) Executives.
Description - Provides executive management and general administrative services.
Method of Allocation - Executive Management Services will be allocated based on the average of the Revenue Ratio, the Total Assets Ratio and the Total Common Equity Ratio, with 20 percent of Common Equity assigned to New Century Energies, Inc.
Allocation Ratios
The following ratios will be utilized as outlined above.
Sales Ratio - Based on firm kilowatt-hour electric sales (and/or the equivalent cubic feet of natural gas sales based on a Btu content, where applicable), excluding inter-system sales, for the immediate preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or and affiliate and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Residential Sales Ratio - Based on firm kilowatt-hour electric sales to residential customers for the immediate preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affiliate and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Business Sales Ratio - Based on firm kilowatt-hour electric sales to business customers that purchase less than 250 kilowatts for the immediate preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affiliate and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Large Commercial & Industrial Sales Ratio - Based on firm kilowatt-hour electric sales to large commercial and industrial customers that purchase greater than 250 kilowatts for the immediate preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affiliate and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Electric Peak Load Ratio - Based on the sum of the monthly electric maximum system demands for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company and the denominator of which is for all Operating Companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Customers Ratio - Based on the sum of total electric customers (and/or gas customers, or residential, business and large commercial and industrial customers where applicable) at the end of each month for the immediately proceeding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Employees Ratio - Based on the sum of the number of employees at the end of each month for the immediately preceding twelve calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Construction Expenditures Ratio - Based on construction or capital expenditures , net of reimbursements, for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Transmission Construction Expenditures Ratio - Based on transmission construction or capital expenditures , net of reimbursements, for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Distribution Construction Expenditures Ratio - Based on distribution construction or capital expenditures, net of reimbursements, for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Substation Construction Expenditures Ratio - Based on substation construction or capital expenditures, net of reimbursements, for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc. - Based on the sum of the common equity at the end of each month for the immediately preceding twelve calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Revenue Ratio - Based on the sum of the revenue at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Wholesale Revenue Ratio - Based on the sum of the electric wholesale revenue at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Industrial Revenue Ratio - Based on the sum of the electric industrial revenue at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Payroll Ratio - Based on the sum of the payroll at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Electric kWh Generation - Based on the sum of electric kWh generated during each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company and the denominator of which is for all Operating Companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Electric kWh Purchased Power Ratio - Based on the sum of electric kWh purchased power during each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company and the denominator of which is for all Operating Companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Total Assets Ratio - Based an the total assets at year end for the preceding year, the numerator of which is for an Operating Company or affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Cost of Gas Sold - Based on the sum of the cost of gas sold at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Gas Throughput Ratio - Based on the sum of the gas throughput MCF's at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Gas Transport MCF - Based on the sum of transported gas MCF's at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required. due to significant changes.
Payment Transaction Ratio - Based on the sum of the number of payment transactions processed during each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Accounting Transactions Ratio - Based on the sum of the number of accounting transactions processed during each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies.
EXHIBIT B-3
FORM OF NON-UTILITY SERVICE AGREEMENT
SERVICE AGREEMENT
This Service Agreement is made and entered into this____ day of ____________, 1997, by and between ________ ("Client Company") and New Century Services, Inc. [new name] ("Service Company").
WITNESSETH
WHEREAS, the Securities and Exchange Commission ("SEC") has approved and authorized as meeting the requirements of Section 13(b) of the Public Utility Holding Company Act of 1935 ("Act") the organization and conduct of the business of Service Company, in accordance herewith, as a wholly-owned subsidiary service company of New Century Energies, Inc. ("NCE"); and
WHEREAS, Client Company is an associate company in the NCE system and an affiliate of Service Company that provides goods, construction, and services to non-affiliated entities on a non-regulated basis; and
WHEREAS, Service Company and Client Company have entered into this Service Agreement whereby Service Company agrees to provide and Client Company agrees to accept and pay for various services as provided herein at no less than cost, with cost determined in accordance with applicable rules and regulations under the Act, which require Service Company to fairly and equitably allocate costs among all associate companies to which it renders services, including Client Company.
NOW THEREFORE, in consideration of the premises and the mutual agreements herein contained, the parties to this Service Agreement covenant and agree as follows:
ARTICLE I - SERVICES
Section 1.1 Service Company shall furnish to client Company, as requested by Client Company, upon the terms and conditions hereinafter set forth, such of the services described in Attachment A hereto, at such times, for such periods and in such manner as Client Company may from time to time request and that Service Company concludes it is able to perform. Service Company shall also provide Client Company with such special services, in addition to those services described in Attachment A hereto, as may be requested by Client Company and that Service Company concludes it is able to perform. In supplying such services, Service Company may arrange, where it deems appropriate, for the services of such experts, consultants, advisers, and other persons with necessary qualifications as are required for or pertinent to the provision of such services.
Section 1.2 Client Company shall take from Service Company such of the services described in Section 1.1, and such additional general or special services, whether or not now contemplated, as are requested from time to time by Client Company and that Service Company concludes it is able to perform.
Section 1.3 The services described herein or contemplated to be performed hereunder shall be directly assigned, distributed or allocated by activity, project, program, work order or other appropriate basis. Client Company shall have the right from time to time to amend, alter or rescind any activity, project, program or work order provided that (i) any such amendment or alteration that results in a material change in the scope of the services to be performed or equipment to be provided is agreed to by Service Company, (ii) the cost for the services covered by the activity, project, program or work order shall include any expense incurred by Service Company as a direct result of such amendment, alteration or rescission of the activity, project, program or work order, and (iii) no amendment, alteration or rescission of an activity, project, program or work order shall release Client Company from liability for all costs already incurred by or contracted for by Service Company pursuant to the activity, project, program or work order, regardless of whether the services associated with such costs have been completed
Section 1.4 Service Company shall use its best efforts to maintain a staff trained and experienced in providing the services described herein or contemplated to be performed hereunder.
ARTICLE II - COMPENSATION
Section 2.1 As compensation for the services to be rendered hereunder, Client Company shall pay to Service Company charges for services that are to be no less than cost (except as may otherwise be permitted by the SEC), insofar as costs can reasonably be identified and related by Service Company to its performance of particular services for or on behalf of Client Company. The methods for assigning or allocating Service Company costs to Client Company, as well as to other associate companies, are set forth in Attachment A.
Section 2.2 The methods of assignment, distribution or allocation of costs described in Attachment A shall be subject to review annually, or more frequently if appropriate. Such methods of assignment, distribution or allocation of costs may be modified or changed by Service Company; provided, however, that no changes will be made to the methods of assignment, distribution, or allocation set forth herein or in Attachment A hereto unless first authorized by the SEC in accordance with the procedures specified in Section 2.3. Service Company shall advise Client Company from time to time of such changes.
Section 2.3 No change in the organization of NC Services, the type and character of the companies to be serviced, the methods of allocating costs to associate companies, or in the scope or character of the services to be rendered subject to Section 13 of the Act, or any rule, regulation, or order thereunder, shall be made unless and until NC Services shall first have given the SEC written notice of the proposed change not less than 60 days prior to the proposed effectiveness of any such change. If, upon the receipt of any such notice, the SEC shall notify NC Services within the 60-day period that a question exists as to whether the proposed change is consistent with the provisions of Section 13 of the Act, or of any rule, regulation, or order thereunder, then the proposed change shall not become effective unless and until NC Services shall have filed with the SEC an appropriate declaration regarding such proposed change and the SEC shall have permitted such declaration to become effective.
Section 2.4 Service Company shall render a monthly statement to Client Company that shall reflect the billing information necessary to identify the costs charged for that month. By the twentieth (20th) day of each month, Client Company shall remit to Service Company all charges billed to it.
Section 2.5 It is the intent of this Service Agreement that the payment for services rendered by Service Company to Client Company under this Service Agreement shall cover all the costs of its doing business (less the costs of services provided to affiliated companies not a party to this Service Agreement and to other non-affiliated companies, and credits for any miscellaneous items), including, but not limited to, salaries and wages, office supplies and expenses, outside services employed, property insurance, injuries and damages, employee pensions and benefits, miscellaneous general expenses, rents, maintenance of structures and equipment, depreciation and amortization, profit and compensation for use of capital as permitted by Rule 91 of the SEC's regulations under the Act.
ARTICLE III - TERM
Section 3.1 This Service Agreement shall become effective subject to the receipt of required regulatory approval, and shall continue in force until terminated by Service Company or Client Company, upon not less than one year's prior written notice to the other party. This Service Agreement shall also be subject to termination or modification at any time, without notice, if and to the extent performance under this Service Agreement may conflict with the Act or with any rule, regulation or order of the SEC adopted before or after the date of this Service Agreement.
ARTICLE IV - LIMITATION OF LIABILITY AND INDEMNIFICATION
Section 4.1 In performing the services hereunder, Service Company will exercise due care to assure that the services are performed in an appropriate manner, meet the standards and specifications set forth in any applicable request for service and comply with the applicable standards of law and regulation. However, failure to meet these obligations shall in no event subject Service Company to any claims by or liabilities to Client Company other than to reperform the services and be reimbursed at cost for such reperformance. Service Company makes no other warranty with respect to its performance of the services, and Client Company agrees to accept such services without further warranty of any nature.
Section 4.2 To the fullest extent allowed by law, Client Company shall and does hereby indemnify and agree to save harmless and defend Service Company, its agents and employees from liabilities, taxes, losses, obligations, claims, damages, penalties, causes of action, suits, costs and expenses or judgments of any nature, on account of, or resulting from the performance and prosecution of any services performed on behalf of Client Company pursuant to this Agreement, whether or not the same results or allegedly results from the claimed or actual negligence or breach of warranty of , or willful conduct by, Service Company or any of its employees, agents, clients, or contractors or its or their subcontractors or any combination thereof.
ARTICLE V - MISCELLANEOUS
Section 5.1 All accounts and records of Service Company shall be kept in accordance with the General Rules and Regulations promulgated by the SEC pursuant to the Act, in particular, the uniform System of Accounts for Mutual Service Companies and Subsidiary Service Companies in effect from and after the date hereof.
Section 5.2 New direct or indirect non-utility subsidiaries of NCE, which may come into existence after the effective date of this Service Agreement, may become additional client companies of Service Company and subject to a service agreement with Service Company. The parties hereto shall make such changes in the scope and character of the services to be rendered and the method of assigning, distributing or allocating costs of such services as specified in Attachment A, subject to the requirements of Section 2.3, as may become necessary to achieve a fair and equitable assignment, distribution, or allocation of Service Company costs among all associate companies including the new subsidiaries.
Section 5.3 Service Company shall permit Client Company access to its accounts and records, including the basis and computation of allocations.
IN WITNESS WHEREOF, the parties hereto have caused this Service Agreement to be executed as of the date and year first above written.
NEW CENTURY SERVICES, INC.
By:_______________________________________
Name: Wayne H. Brunetti
Title: Vice Chairman, President, and
Chief Executive Officer
[COMPANY]
By:_______________________________________
Name:
Title:
Attachment A
DESCRIPTION OF SERVICES TO BE PROVIDED BY NEW CENTURY
SERVICES, INC. AND DETERMINATION OF CHARGES FOR SUCH
SERVICES TO THE OPERATING COMPANIES AND AFFILIATES
Description of Services Provided
A description of the services provided by NCS is detailed below. Identifiable costs will be directly assigned or distributed to the Operating Companies or affiliates. For costs which are for services of a general nature that cannot be directly assigned or distributed, the method of allocation is described below for each service provided.
a) Electric Commodity Services - Business Development.
Description - Provides administrative support services and business development opportunities to the Operating Companies electric generation stations.
Methods of Allocation - The Support of Plant Operations will be allocated to the Operating Companies based on the Electric kWh Generation Ratio.
b) Energy Supply Management and Bulk Power Transport
Description - Supervises and coordinates the electric transmission system control operations and dispatching for the Operating Companies.
Methods of Allocation - The Energy Supply Management and Bulk Power Transport services will be allocated to the Operating Companies based on the kWh Sales Ratio.
c) Purchased Power and Electric Trading
Description - Purchases power and provides electric trading services to the Operating Companies electric generation systems.
Method of Allocation - The Purchased Power and Electric Trading services will be allocated to the Operating Companies based on the Electric kWh Purchased Power Ratio.
d) Transmission, Substation Construction, Maintenance & Operations
Description - Provides management services to the Operating Companies transmission and substation construction, maintenance and operations areas.
Method of Allocation - Transmission, Substation Construction, Maintenance and Operations management services will be allocated to the Operating Companies based on the Transmission and Substation Construction Expenditures Ratios.
e) Transportation.
Description - Oversees the Operating Companies' Fleet Services Group.
Method of Allocation - Transportation will be allocated to the Operating Companies as well as other affected affiliates of NCS based on the Employees Ratio.
f) Supply Chain.
Description - Provides services in connection with the procurement of materials including the management of materials and supplies inventories.
Method of Allocation - Materials management will be allocated to the Operating Companies based on an average of the Revenue Ratio and the Total Construction Expenditures Ratio.
g) Facilities and Real Estate.
Description - Operates and maintains office buildings and service centers. Procures real estate and administers real estate leases. Administers contracts to provide security, housekeeping and maintenance services for such facilities. Procures office furniture and equipment
Method of Allocation - Facilities and Real Estate services will be allocated to the Operating Companies as well as affected affiliates based on the Square Footage Ratio.
h) Accounting.
Description - Maintains the books and records of New Century Energies, Inc. and its affected affiliates, prepares financial and statistical reports, prepares tax filings and supervises compliance with the applicable laws and regulations. Supports the accounting systems.
Method of Allocation - Accounting services will be allocated to the Operating Companies and affected affiliates based on an average of the Revenue Ratio, the Total Construction Expenditures Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc. Accounting system support services will be allocated based on the Accounting Transactions Ratio.
i) Payment and Reporting.
Description - Processes payments to vendors of New Century Energies, Inc. and its affected, affiliates, and prepares statistical reports.
Method of Allocation - Payment and reporting activities will be allocated to the Operating Companies and affected affiliates based on the Payment Transaction Ratio.
j) Finance and Treasury.
Description - Coordinates activities related to securities issuance, including maintaining relationships with financial institutions, cash management, investing activities and monitoring the capital markets. Performs financial and economic analysis.
Method of Allocation - Finance and Treasury activities will be allocated to the Operating Companies and affected affiliates based on an average of the Revenue Ratio, the Total Construction Expenditures Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
k) Rates and Regulation.
Description - Determines the Operating Companies' revenue requirements and rates for electric and gas customers. Coordinates the regulatory compliance requirements and maintains relationships with the regulatory bodies.
Method of Allocation - Rates and Regulation services will be allocated to the Operating Companies based an the Revenue Ratio.
l) Legal.
Description - Provides legal services related to labor and employment law, litigation, contracts, rates and regulation, environmental matters, real estate and other legal matters.
Method of Allocation - Legal services will be allocated to the Operating Companies and affected affiliates based on an average of the Payroll Ratio, the Revenue Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
m) Internal Audit.
Description - Reviews internal controls and procedures to ensure assets are safeguarded and transactions are properly authorized and recorded. Evaluates contract risks.
Methods of Allocation - Internal Auditing services will be allocated to the Operating Companies and affected affiliates based on the average of the Revenue Ratio, the Total Construction Expenditures Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
n) Corporate Communications.
Description - Prepares and disseminates information to employees, customers, government agencies, communities and the media.
Methods of Allocation - Corporate Communications services will be allocated to the Operating Companies and affected affiliates based on the Revenue Ratio, the Employee Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
o) Environmental.
Description - Establishes policies and procedures for compliance with environmental laws and regulations. Researches emerging environmental issues and monitors compliance with environmental requirements. Oversees environmental clean up projects.
Method of Allocation - Environmental services will be allocated to the Operating Companies and affected affiliates based on the Revenue Ratio.
p) Resource Acquisition and Analysis.
Description - Procures coal, natural gas and oil for the Operating Companies generation facilities. Ensures compliance with price and quality provisions of fuel contracts and arranges for transportation of fuel to the desired location. Purchases power and performs electric and gas trading services.
Method of Allocation - Resource Acquisition and Analysis services will be allocated to the Operating Companies based on the Electric kWh Generation Ratio or the Purchased Power Ratio, whichever is appropriate.
q) Corporate Planning.
Description - Facilitates preparation of strategic plans, monitors trends and evaluates business opportunities. Facilitates process improvements. Prepares budgets and financial forecasts.
Method of Allocation - Strategic Planning services will be allocated to the Operating Companies and affected affiliates based on the average of the Revenue Ratio, the Total Assets Ratio and Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
r) Investor Relations.
Description - Provides communications to investors and the financial community. Coordinates the transfer agent and shareholder record keeping functions.
Method of Allocation - Investor Relations services will be allocated to the Operating Companies and affected affiliates based on the average of the Revenue Ratio, the Total Assets Ratio and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
s) Human Resources.
Description - Establishes and administers policies and supervises compliance with legal requirements in the areas of employment, compensation, benefits and employee health, welfare and safety. Processes payroll and employee benefit payments. Coordinates contract negotiation and relations with labor unions.
Method of Allocation - Human Resources services will be allocated to the Operating Companies and affected affiliates based on the Payroll Ratio.
t) Customer Services.
Description - Performs customer billing, handles customer inquiries and complaints and provides related customer information services.
Method of Allocation - Customer Services will be allocated based on the Customers Ratio.
u) Information Systems.
Description - Administers the contract for various communications and electronic data processing services. Such services provided under the contract include, but are not limited to, development and support of mainframe computer software applications, procurement and support of personal computers, operation of a data center and installation and operation of a communications system.
Method of Allocation - Information Systems will be allocated based an the Information Systems direct charges.
v) Marketing Services.
Description - Provides marketing services including market load research and new product development for Operating Companies and affiliates.
Method of Allocation - Marketing services will be allocated based on the total Residential, Business, and Large Commercial and Industrial kWh sales ratio.
w) Wholesale and Bulk Power Sales.
Description - Provides sales and to support to electric wholesale customers of the Operating Companies.
Method of Allocation - Wholesale Sales will be allocated based on the Electric Wholesale Sales Ratio.
x) Residential and Business Sales.
Description - Provides sales and support to electric residential and business customers of the Operating Companies.
Method of Allocation - Residential and Business Sales will be allocated based on the Residential and Commercial Sales Ratio.
y) Custom Account Sales.
Description - Provides sales services to large commercial and industrial customers of the Operating Companies.
Method of Allocation - Custom Account Sales will be allocated based on the Large Commercial and Industrial Sales Ratio.
z) Strategic and Key Account Sales.
Description - Provides sales and support services to niche markets of the Operating Companies.
Method of Allocation - Strategic Account Sales will be allocated based on the total of the Large Commercial and Industrial and the Public Authority Sales Ratios. Key Account Sales will be allocated based on the Large Commercial and Industrial Sales Ratio.
aa) Community and Economic Development
Description - Provides community support and economic development services to the service territories of the Operating Companies.
Method of Allocation - Community and Economic Development services will be allocated based on the Total kWh Sales Ratio.
bb) Gas Marketing, Control, Planning and Supply.
Description - Provides marketing services to gas transport customers. Coordinates the planning and support for Gas operations of Public Service Company of Colorado, Cheyenne Light, Fuel and Power and WestGas Interstate Company including coordinating the operation of the gas system and well as the purchase of gas for the Operating Companies distribution business from third parties.
Method of Allocation - Gas Marketing, Control, Planning and Supply services will be allocated based on the Gas Throughput Ratio.
cc) Design n Engineering.
Description - Designs and monitors construction of electric transmission and distribution lines and substations.
Method of Allocation - Design Engineering services will be allocated based on the Transmission Construction Expenditures Ratio, the Distribution Construction Ratio, or a ratio based on the sum of the Transmission and Distribution Construction Expenditures whichever is appropriate.
dd) Substation Engineering and Support.
Description - Provides management support services to the Substation Engineering and Support organizations of the Operating Companies.
Method of Allocation - Substation Engineering and Support services will be allocated based on the Substation Construction Expenditures Ratio.
ee) Transmission Engineering and Right of Way Services.
Description - Provides management support services to the Transmission Engineering and Right of Way organizations of the Operating Companies.
Method of Allocation - Transmission Engineering and Right of Way services will be allocated based an the Transmission Construction Expenditures Ratio.
ff) Distribution Support Services.
Description - Provides planning, benchmarking, activity tracking and budget support services to the Construction and Operations and Maintenance Organization.
Method of Allocation - Distribution Support Services will be allocated based on the Total Customers Ratio.
gg) Aviation Services.
Description - Provides aviation and travel services to employees.
Method of Allocation - Aviation Services will be allocated to the appropriate Operating Companies and affiliates based on the Aviation Department's actual direct charges. (This method will allocate costs only to those companies who actually use aviation services).
hh) Governmental Affairs.
Description - Lobbies government officials and monitors, reviews and researches governmental legislation.
Method of Allocation - Governmental Affairs will be allocated based on the average of the Revenue Ratio, the Employee Ratio, and the Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc.
ii) Production Services.
Description - Provides performance, chemical and water testing and analysis, technical, and analytical services to the Operating Companies generation facilities.
Method of Allocation - Production Services will be allocated based on the kWh Generation Ratio.
jj) Executives.
Description - Provides executive management and general administrative services.
Method of Allocation - Executive Management Services will be allocated based on the average of the Revenue Ratio, the Total Assets Ratio and the Total Common Equity Ratio, with 20 percent of Common Equity assigned to New Century Energies, Inc.
Allocation Ratios
The following ratios will be utilized as outlined above.
Sales Ratio - Based on firm kilowatt-hour electric sales (and/or the equivalent cubic feet of natural gas sales based on a Btu content, where applicable), excluding inter-system sales, for the immediate preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or and affiliate and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Residential Sales Ratio - Based on firm kilowatt-hour electric sales to residential customers for the immediate preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affiliate and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Business Sales Ratio - Based on firm kilowatt-hour electric sales to business customers that purchase less than 250 kilowatts for the immediate preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affiliate and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Large Commercial & Industrial Sales Ratio - Based on firm kilowatt-hour electric sales to large commercial and industrial customers that purchase greater than 250 kilowatts for the immediate preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affiliate and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Electric Peak Load Ratio - Based on the sum of the monthly electric maximum system demands for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company and the denominator of which is for all Operating Companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Customers Ratio - Based on the sum of total electric customers (and/or gas customers, or residential, business and large commercial and industrial customers where applicable) at the end of each month for the immediately proceeding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Employees Ratio - Based on the sum of the number of employees at the end of each month for the immediately preceding twelve calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Construction Expenditures Ratio - Based on construction or capital expenditures , net of reimbursements, for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Transmission Construction Expenditures Ratio - Based on transmission construction or capital expenditures , net of reimbursements, for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Distribution Construction Expenditures Ratio - Based on distribution construction or capital expenditures, net of reimbursements, for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Substation Construction Expenditures Ratio - Based on substation construction or capital expenditures, net of reimbursements, for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to a significant change.
Total Common Equity Ratio, with 20 Percent of Common Equity assigned to New Century Energies, Inc. - Based on the sum of the common equity at the end of each month for the immediately preceding twelve calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Revenue Ratio - Based on the sum of the revenue at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Wholesale Revenue Ratio - Based on the sum of the electric wholesale revenue at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Industrial Revenue Ratio - Based on the sum of the electric industrial revenue at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Payroll Ratio - Based on the sum of the payroll at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Electric kWh Generation - Based on the sum of electric kWh generated during each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company and the denominator of which is for all Operating Companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Electric kWh Purchased Power Ratio - Based on the sum of electric kWh purchased power during each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company and the denominator of which is for all Operating Companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Total Assets Ratio - Based an the total assets at year end for the preceding year, the numerator of which is for an Operating Company or affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Cost of Gas Sold - Based on the sum of the cost of gas sold at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Gas Throughput Ratio - Based on the sum of the gas throughput MCF's at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Gas Transport MCF - Based on the sum of transported gas MCF's at the end of each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required. due to significant changes.
Payment Transaction Ratio - Based on the sum of the number of payment transactions processed during each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies. This ratio will be determined annually, or at such time as may be required due to significant changes.
Accounting Transactions Ratio - Based on the sum of the number of accounting transactions processed during each month for the immediately preceding twelve consecutive calendar months, the numerator of which is for an Operating Company or an affected affiliate company and the denominator of which is for all Operating Companies and affected affiliate companies.
EXHIBIT E-13
COMPARISON OF INDEPENDENT SYSTEM OPERATORS
|
Characteristics |
Midwest ISO |
PJM |
New England ISO |
|
Size |
45,000 miles of transmission lines 15 million ultimate customers 566 million MWh sales to ultimate customers 78,000 MW of generating capacity Covers all or parts of 11 Mid-Western and Mid-Atlantic States: IL, IN, KY, MD, MI, MO, OH, PA, VA, WV and WI [173] |
15,000 miles of transmission lines 9.5 million ultimate customers 308 million MWh sales to ultimate consumers 56,000 MW of generating capacity Covers all or part of 6 Mid-Atlantic States: DE, DC, MD, NJ, PA and VA |
13,000 miles of transmission lines 6.5 million ultimate customers 216 million MWh sales to ultimate consumers 27,000 MW of generating capacity Covers all or part of 6 New England States: CT, ME, MA, NH, RI and VT |
|
Region-Wide Open-Access Transmission Tariff |
MISO will administer a region-wide open access transmission tariff and provide non-discriminatory transmission service at non-pancaked rates. A single-system average transmission rate will be completely phased in over 6 years. In the interim, transmission customers will pay zonal rates based on where the load is located (10+ zones). |
PJM administers a region-wide open access transmission tariff and provides non-discriminatory transmission service at non-pancaked rates. A single-system average transmission rate will be completely phased in over 5 years. In the interim, transmission customers will pay zonal rates based on the location of the load (10 zones). |
NE ISO administers a region-wide open access transmission tariff and provides non-discriminatory transmission service at non-pancaked rates. A single-system average transmission rate will be completely phased in over 10 years. In the interim, transmission customers will pay zonal rates based on the location of the load (9 zones). |
|
Control Area Operator |
MISO will have functional control over all network transmission facilities and generation facilities to the extent generation affects transmission. The transmission owners will follow the directives of MISO for redispatching generation, curtailing load and providing ancillary services. [174] |
PJM has operational control over all network transmission facilities and generation functions. |
NE ISO has operational control over all network transmission and generation functions. |
|
Power Exchange |
The establishment of a Midwest power exchange is currently being evaluated by MISO. In the interim, power transactions will be accomplished through bilateral contracts, such as the Joint Operating Agreement between NSP and NCE. |
PJM administers competitive wholesale bid-based markets for capacity, energy and certain ancillary services. FERC lifted the cost-based caps imposed on prices for energy bid into the PJM power exchange. Bilateral contracts can also be used to procure these services. |
NE ISO administers competitive wholesale bid-based markets for capacity, energy and certain ancillary services. Bilateral contracts can also be used to procure these services.[175] |
|
Ensuring Reliability as Security Coordinator |
MISO is a NERC Security Coordinator that will monitor real-time data on the transmission system to determine generation capacity deficiencies and take any action necessary to preserve system reliability consistent with NERC standards. |
PJM is a NERC Security Coordinator that monitors real-time data on the transmission system to determine generation capacity deficiencies and takes any action necessary to preserve system reliability consistent with NERC standards. |
NE ISO is a NERC Security Coordinator that monitors real-time data on the transmission system to determine generation capacity deficiencies and takes any action necessary to preserve system reliability consistent with NERC standards. |
|
Relief of Transmission Constraints |
MISO will have the authority to relieve transmission constraints through curtailment, generation redispatch and load shedding. [176] |
PJM has the authority to relieve transmission constraints through curtailment, generation redispatch and load shedding. |
NE ISO has the authority to relieve transmission constraints through curtailment, generation redispatch and load shedding. |
|
Scheduling Transmission Services |
MISO will process transmission service requests, schedule all transmission service on the ISO-controlled grid and calculate the system's Available Transmission Capacity. |
PJM forecasts, schedules and coordinates transmission requests to meet load requirements and calculates the system's Available Transmission Capacity. |
NE ISO processes transmission service requests, schedules all transmission service on the ISO-controlled grid and calculates the system's Available Transmission Capacity. |
|
Coordination of Transmission and Generation Maintenance |
MISO will have final approval over all planned maintenance of transmission facilities and will coordinate generation maintenance (outage schedules) in order to minimize the impact on transmission capability. |
PJM coordinates and approves or rejects planned maintenance of transmission and generation facilities. |
NE ISO oversees the scheduling of maintenance for transmission and generation facilities. |
|
Transmission Planning and Expansion |
MISO will integrate, evaluate and modify the transmission plans developed by each transmission owner. MISO will review the planning and interconnections standards of its transmission owners and will have authority to direct transmission owners to construct new transmission facilities as required. |
PJM develops a grid-wide transmission plan that assesses transmission capability and proposes transmission constraint relief as required. |
NE ISO can conduct, or has conducted, transmission facility studies and direct transmission owners to construct new transmission facilities as required. |
|
Ensuring Availability of Ancillary Services |
MISO directs the transmission owners to provide ancillary services. The transmission owners are required to offer six ancillary services. Transmission customers may elect to purchase ancillary services through MISO or from third party providers. |
PJM provides ancillary services by assigning the costs to the transmission customer. Ancillary service bids can be accepted outside the PJM control area. FERC approved market-based rate authority for two ancillary services bid into the PJM Power Exchange. |
Ancillary services must be taken from NEPOOL through the NE ISO or be made available through it. FERC granted NEPOOL's request for market-based rate authority for four ancillary services. |
|
Open-Access Same-Time Information System |
MISO will administer and maintain an OASIS for the regional transmission system. |
PJM administers and maintains an OASIS for its wholesale electricity market. |
NE ISO administers and maintains the NEPOOL OASIS. |
__________________________________
[173]These numbers exclude the NSP companies which have recently executed the MISO Agreement and SPS which has pledged to join MISO upon consummation of the merger. These numbers also exclude the Southwest Power Pool and the Mid-Continent Area Power Pool which are currently considering participation in MISO.[174]Unlike PJM and NE ISO, MISO will not be a NERC-certified control area operator because some generation control functions (i.e., scheduling, economic dispatch and load balancing) will continue to be performed by existing control area operators within MISO. However, MISO will, as noted in the table, have control over generation to the extent needed to assure reliable operation of the transmission grid. Section 7.2 of the Joint Operating Agreement provides that NSP, PSCo and SPS will dispatch their generation resources on a coordinated basis in real-time to minimize their total generation costs. Consequently, through the Joint Operating Agreement, NSP, PSCO and SPS will effectively achieve the benefits of economic dispatch to the maximum extent possible subject, of course, to transmission availability and to each company's obligations to minimize costs to its native load customers.
[175]Prior to the establishment of a power exchange by PJM and NE ISO, the generating units were dispatched based upon each unit's incremental cost of production rather than prices bid by each generator wishing to sell into the power exchange as is currently employed by PJM and NE ISO power exchanges.
[176]The methods that will be employed by MISO to accomplish generation redispatch are different from the methods employed by PJM and NE ISO. MISO will require generators to offer redispatch with MISO selecting the least-cost option and the resulting congestion costs will be shared by all system users on a pro rata basis. PJM and NE ISO, on the other hand, use locational-based marginal pricing and the sale of fixed transmission rights to alleviate congestion costs and each transmission customer pays the incremental costs associated with the redispatch necessary to accommodate their transaction.
EXHIBIT I-1
SECURITIES AND EXCHANGE COMMISSION
(Release No. 35- )
Filing under the Public Utility Holding Company Act of 1935
January 31, 2000
New Century Energies and Northern States Power (70-9539)
Notice is hereby given that the following filing has been made with the Commission pursuant to provisions of the Act and rules promulgated under the Act. All interested persons are referred to the application-declaration for complete statements of the proposed transactions summarized below. The application-declaration and any amendments are available for public inspection through the Commission's Office of Public Reference.
Interested persons wishing to comment or request a hearing on the application-declaration should submit their views in writing by ___________, 2000 to the Secretary, Securities and Exchange Commission, Washington, D.C. 20549, and serve a copy of the relevant application-declaration at the addresses specified below. Proof of service (by affidavit or, in case of an attorney at law, by certificate) should be filed with the request. Any request for hearing should identify specifically the issues of fact or law that are disputed. A person who so requests will be notified of any hearing, if ordered, and will receive a copy of any notice or order issued in the matter. After __________, 2000, the application-declaration, as filed or as amended, may be granted and/or permitted to become effective.
New Century Energies, Inc. ("NCE"), 1225 Seventeenth Street, Denver, Colorado 80202, a registered holding company, and Northern States Power Company ("NSP"), 414 Nicollet Mall, Minneapolis, Minnesota 55401, a holding company exempt from registration (collectively, "Applicants"), have filed a joint application-declaration under Sections 4; 5; 6(a); 7; 9(a)(1); 10; 9(a)(2); 10(a), (b), (c) and (f); 8; 9(c)(3); 11(b); 21; 12(d); 13; and 13(b)(1) and rules 44, 80-92 and 88 under the Act.
Summary of Proposal
As described in more detail below, Applicants propose: (1) to merge NCE with and into NSP, which will be renamed Xcel Energy Inc. ("Xcel"), through the issuance of Xcel Common Stock in exchange for NCE Common Stock; (2) to transfer all of NSP's existing electric and gas utility operations to a newly formed, wholly owned subsidiary ("New NSP") and to form and capitalize New NSP; (3) to register Xcel as a holding company following consummation of the merger; (4) to have Xcel retain the retail gas utility operations of NSP, of NSP's subsidiary Northern States Power, a Wisconsin corporation ("NSP-W"), and of NCE's subsidiaries Public Service Company of Colorado, a Colorado corporation ("PSCo"), and Cheyenne Light, Fuel and Power Company, a Wyoming corporation ("Cheyenne"); (5) to retain the other businesses of NSP and NCE and their direct and indirect subsidiaries; and (6) to have NCE's service company subsidiary, New Century Services, Inc., (to be renamed Xcel Energy Services Inc.) render services to Xcel's utility and non utility subsidiaries.
NCE and Subsidiaries
NCE, a Delaware corporation, was incorporated under the laws of the State of Delaware in 1997. NCE is a registered public utility holding company formed pursuant to Commission order. NCE owns all the outstanding shares of stock of three U.S. public-utility operating subsidiaries, PSCo, Cheyenne, and Southwestern Public Service Company, a New Mexico corporation ("SPS"). PSCo serves approximately 1.2 million electric customers and approximately 1.0 million gas customers in the state of Colorado. SPS serves approximately 385,000 electric customers in portions of the states of Texas, New Mexico, Oklahoma and Kansas. Cheyenne serves approximately 35,000 electric customers and 28,000 gas customers in Cheyenne, Wyoming.
NCE, directly or indirectly, owns all the outstanding common stock of the following non-utility subsidiary companies: New Century Services, the NCE system service company under Section 13 of the Act; WestGas InterState, Inc. ("WGI"), a natural gas company subject to FERC jurisdiction under the NGA; and NC Enterprises, Inc. ("NC Enterprises"), a holding company for NCE's non-utility businesses and foreign operations. PSCo also holds various non-utility subsidiaries. These subsidiaries primarily operate in support to PSCo's operations. The non-utility operations of NCE have all been previously authorized under the 1935 Act or have been established by rule or pursuant to statutory exemption.
NCE and its subsidiaries are subject to regulation by the Commission under the Act. PSCo is subject to regulation as a public utility under the Colorado Public Utilities Law as to retail electric and gas rates and other matters by the Colorado Commission. As a public utility under the laws of the states of Texas, New Mexico, Kansas and Oklahoma, SPS is regulated as to retail electric and certain other matters by the Texas Commission, New Mexico Commission, Kansas Commission and Oklahoma Commission, respectively. Cheyenne is subject to regulation in connection with its electric and gas retail sales and other matters by the Wyoming Commission. SPS, PSCo and Cheyenne are also subject to regulation by FERC pursuant to the Federal Power Act, as amended, with respect to the classification of accounts, rates for any wholesale sales of electricity, the interstate transmission of electric power and energy, interconnection agreements, the licensing of hydro-electric facilities, and acquisitions and sales of certain utility properties. In addition, PSCo and Cheyenne are subject to regulation by FERC under the Natural Gas Act of 1935, as amended ("NGA") with regards to certain transportation or sale of natural gas for resale.
New Century Services has entered into service agreements with NCE, SPS, PSCo and Cheyenne (the "Utility Service Agreements"). New NSP and NSP-W will also enter into service agreements comparable to the Utility Service Agreement with New Century Services. New Century Services has also entered into separate service agreements with the non-utility subsidiary companies of NCE. It is contemplated that New Century Services will similarly enter into one or more separate service agreements with the direct and indirect non-utility subsidiaries of NSP.
NCE Common Stock is listed on the New York Stock Exchange, Inc. ("NYSE"). As of the close of business on September 30, 1999, 115,533,704 shares of NCE Common Stock and no shares of NCE preferred stock were issued and outstanding. Consolidated assets of NCE, as of December 31, 1998, were approximately $7.7 billion, representing $4.6 billion in net electric utility property, plant and equipment ($1.7 billion for SPS, $2.8 billion for PSCo and $46 million for Cheyenne); $817 million in net gas utility property, plant and equipment ($792 million for PSCo and $24 million for Cheyenne); $500 million in non-utility subsidiary property, plant and equipment; and $1.8 billion in other corporate assets.
NSP and its Subsidiaries
NSP, which was incorporated in Minnesota in 1909, is a public-utility company and a holding company exempt from registration pursuant to Commission order under Section 3(a)(2) of the Act. NSP owns all of the outstanding common stock of NSP-W, which is a public-utility company under the Act.
NSP is engaged primarily in the generation, transmission and distribution of electricity throughout a 30,000 square mile service area in Minnesota, North Dakota and South Dakota. NSP also purchases, distributes and sells natural gas to retail customers and transports customer-owned gas in approximately 118 communities within this area and in Arizona. Of the more than 2.5 million people served by NSP, the majority are in the Minneapolis-St. Paul metropolitan area. NSP provides both electric and gas utility service in Minnesota, North Dakota and South Dakota, but only gas utility service in Arizona. As of December 31, 1998, NSP provided retail electric utility service to approximately 1,240,000 customers and gas utility service to approximately 385,000 customers.
NSP-W is engaged in the generation, transmission, and distribution of electricity to approximately 210,400 retail customers in an area of approximately 18,900 square miles in northwestern Wisconsin, to approximately 9,100 electric retail customers in an area of approximately 300 square miles in the western portion of the Upper Peninsula of Michigan and to 10 wholesale customers in the same general area. NSP-W purchases, distributes and sells natural gas to retail customers or transports customer-owned natural gas in the same service territory to approximately 78,000 customers in Wisconsin and 5,000 customers in Michigan. In 1998, NSP-W provided approximately 13% of NSP's consolidated revenues.
The electric transmission system of NSP and NSP-W is located throughout the service territories that NSP and NSP-W serve in Minnesota, North Dakota, South Dakota, Michigan and Wisconsin. NSP and NSP-W are directly connected with each other through numerous transmission lines that they own, including one 345 kV transmission line, two 115 kV transmission lines and two 69 kV transmission lines.
Retail sales rates, services and other aspects of NSP's retail operations are subject to the jurisdiction of the Minnesota Commission, the North Dakota Commission and the South Dakota Commission within their respective states. The Minnesota Commission also possesses regulatory authority over aspects of NSP's financial activities, including security issuances, property transfers when the asset value is in excess of $100,000, mergers with other utilities, and transactions between NSP and affiliates. In addition, the Minnesota Commission reviews and approves NSP's electric resource and gas supply capacity plans for meeting customers' future energy needs. NSP-W is subject to regulation of similar scope by the Wisconsin Commission and the Michigan Commission, except that the Michigan Commission does not regulate NSP-W's issuances of securities. In addition, a state commission generally must certify the need for new generating plants and transmission lines of designated capacities to be located within such state before they may be sited and built. Wholesale rates for electric energy sold in interstate commerce, the classification of accounts, the interstate transmission of electric power and energy, interconnection agreements, issuances of securities not regulated by state commissions, acquisitions and sales of certain utility properties and certain other activities of NSP and NSP-W (including the licensing of its hydro-electric facilities) are subject to the jurisdiction of FERC. The operation and construction of NSP's Prairie Island and Monticello nuclear facilities are subject to regulation by the NRC. In addition, NSP and NSP-W are subject to FERC jurisdiction under the NGA and 18 C.F.R. § 284.402 with regards to the sale of natural gas for resale.
NSP is also engaged, directly and through subsidiary companies, in non-utility businesses. NSP directly provides: (i) an appliance services program for its residential customers, (ii) construction of natural gas distribution systems for third parties (primarily end-users and municipal gas systems), (iii) sale and installation of power quality instruments primarily to protect equipment of customers from electric surges, (iv) sale of steam to industrial customers in NSP's service territory, and (v) installation and maintenance of street lighting for municipalities and other customers. In addition, NSP owns directly the interests of the following non-utility subsidiary companies: NSP Financing I, a special purpose business trust; Viking Gas Transmission Company ("Viking"), an interstate natural gas pipeline subject to FERC jurisdiction under the NGA; Eloigne Company ("Eloigne"), an investor in projects that qualify for low-income housing tax credits; Energy Masters International, Inc. ("EMI"), an energy services company; Seren Innovations, Inc. ("Seren"), a company that provides cable, telephone and high-speed internet access system; Ultra Power Technologies, Inc. ("Ultra Power"), a company that markets power cable testing technology; First Midwest Auto Park, Inc. ("FMAP"), an owner of a parking garage; United Power and Land Company ("UP&L"), a real estate investment company; NRG Energy, Inc. ("NRG"), a holding company for many of NSP's non-utility businesses and foreign operations; Reddy Kilowatt Corporation ("Reddy Kilowatt"), the owner of certain intellectual property rights; Natrogas, Inc., a provider of propane services; and Nuclear Management Company ("NMC"), a limited liability company that will provide services to the nuclear operations of its members. NSP owns 100% of all of the foregoing businesses, except that NSP owns 25% of the membership interests in NMC.
NSP-W owns directly all of the outstanding common stock of Clearwater Investments, Inc. ("Clearwater"), an investor in housing projects that qualify for low-income housing tax credits, and NSP Lands, Inc. ("NSP Lands"), a real estate investor. NSP-W also owns 75.86% of Chippewa and Flambeau Improvement Company ("C&F"), a company that builds and operates dams and reservoirs.
NSP Common Stock is listed on the NYSE and the Chicago and Pacific Stock Exchanges. As of the close of business on September 30, 1999, there were 154,358,267 shares of NSP Common Stock and 1,050,000 shares of NSP cumulative preferred stock issued and outstanding. NSP's principal executive office is located at 414 Nicollet Mall, Minneapolis, Minnesota 55401. NSP-W does not have any preferred stock outstanding, and all of its common stock is owned by NSP. Consolidated assets of NSP and its subsidiaries as of December 31, 1998 were approximately $7.4 billion, consisting of $3.7 billion in net electric utility property, plant and equipment ($3.1 billion for NSP and $594 million for NSP-W); $439 million in net gas utility property, plant and equipment ($376 million for NSP and $63 million for NSP-W); and $1.6 billion in non-utility subsidiary assets, and $1.7 billion in other corporate assets.
The Proposed Merger
An Agreement and Plan of Merger, dated as of March 24, 1999 (the "Merger Agreement") among NSP and NCE provides for the merger of NCE with and into NSP pursuant to which: (a) each share of NCE Common Stock issued and outstanding immediately prior to the effective time of the Merger, together with any NCE Rights,[177] shall be converted into the right to receive 1.55 shares (the "Conversion Ratio") of duly authorized, validly issued, fully paid and nonassessable NSP Common Stock; (b) each issued and outstanding share of NSP Common Stock and each share of preferred stock of NSP issued and outstanding immediately prior to the effective time of the Merger shall remain outstanding and (c) each share of NCE Common Stock, together with any NCE Rights, that is owned by NSP or any of its subsidiaries or held in the treasury of NCE will be canceled and shall cease to exist, and no consideration shall be delivered in exchange therefor. As noted previously, NSP will change its name to Xcel at or prior to the Merger. Based upon the capitalization of NCE and NSP on March 24, 1999 (the date the Merger Agreement was signed) and the Conversion Ratio, NCE shareholders would own 54 percent and NSP shareholders would own 46 percent of the common equity of Xcel if the Merger had been consummated as of such date.
Except as set forth below, if any holder of NCE Common Stock would be entitled to receive a number of shares of NSP Common Stock that includes a fraction, then in lieu of a fractional share, such holder will be entitled to receive a cash payment determined by multiplying the fractional share interest by the average of the last reported sales price, regular way, per share of NSP Common Stock on the NYSE Composite Tape for the ten business days prior to and including the last business day on which NSP Common Stock was traded on the NYSE, without any interest thereon. Fractional shares of NCE Common Stock held in accounts under the dividend reinvestment plans and employee benefit plans of NCE will be converted into the applicable number of shares (or fractional shares) of NSP Common Stock under corresponding plans of NSP, in accordance with the Conversion Ratio.
Applicants request authority for Xcel to acquire and NCE to sell the stock of NCE, SPS, PSCo, Cheyenne, New Century Services and the non-utility subsidiaries of NCE. Applicants also request authority for Xcel to issue its common stock in exchange for shares of NCE common stock, as well as to form and capitalize New NSP. Applicants also seek an exemption from at-cost standards with respect to certain services between Xcel system companies and seek to retain all of their existing businesses.
The Merger Agreement provides that, after the effectiveness of the Merger, Xcel's principal corporate office will be located in Minneapolis, Minnesota. Xcel will also maintain significant operating offices in Denver, Colorado; Amarillo, Texas; and Eau Claire, Wisconsin. Xcel's board of directors (classified into three classes) will consist of an even number of up to 14 persons, half of whom will be designated by NSP and half of whom will be designated by NCE. Mr. James J. Howard, the current Chairman, Chief Executive Officer and President of NSP, will be entitled to serve as Chairman of the Board of Xcel until the first anniversary of the effectiveness of the Merger of NCE and NSP. Mr. Wayne H. Brunetti, the Chairman, Chief Executive Officer and President of NCE, will be entitled to serve as President and Chief Executive Officer of Xcel upon the effectiveness of the Merger, and thereafter will assume the position of Chairman when Mr. Howard ceases to be Chairman. The balance of the Xcel executive management is expected to consist of current executives of NCE and NSP as follows: Paul Bonavia (currently NCE General Counsel and President - International Busines), Head of Energy Markets; Dick Kelly (currently NCE Executive Vice President and Chief Financial Officer), Head of Corporate Development and Strategy/Unregulated Subsidiaries; Gary Johnson (currently NSP Senior Vice President and General Counsel), General Counsel; Cyndi Lesher (currently NSP President - Gas Operations), Chief Administrative Officer; James McIntyre (currently NSP Senior Vice President and Chief Financial Officer), Chief Financial Officer; Toni Petillo (currently NCE President - Retail Services), Head of Retail Operations; Larry Taylor (currently NSP President-Delivery Services), Head of Energy Delivery; and David Wilks (currently NCE President-Delivery Services), Head of Energy Supply.
For the Commission, by the Division of Investment Management, pursuant to delegated authority.
______________________________
[177] Each NCE Right entitles the registered holder to purchase from NCE one one-hundredth of a share of Series A Junior Participating Preferred Stock. The NCE Rights were distributed as a dividend on each outstanding share of NCE Common Stock as part of NCE's shareholder rights plan. [177] [177] [177] [177]Exhibit J-1
NORTHERN STATES POWER COMPANY (MINNESOTA)
NORTHERN STATES POWER COMPANY (WISCONSIN)
ANALYSIS OF THE ECONOMIC IMPACT
OF A DIVESTITURE OF THE GAS OPERATIONS OF
NSP AND ITS NSP-W SUBSIDIARY
This study was undertaken by the management and staff of Northern States Power Company, a Minnesota corporation ("NSP"), and its wholly-owned subsidiary Northern States Power Company, a Wisconsin corporation ("NSP-W"). The objective of the study is to quantify the economic impact on shareholders and customers of divesting NSP of its natural gas utility assets and business in the States of Minnesota, North Dakota, South Dakota and Arizona; and divesting NSP-W of its natural gas utility assets and business in the States of Wisconsin and Michigan.
In addition, NSP and New Century Energies, Inc. ("NCE") have prepared a separate analysis (Exhibit J-3) to quantify the economic impact on shareholders and customers of instead divesting the retail natural gas operations of NSP and NCE into a stand-alone gas holding company subject to the Act, with the retail gas operations of NSP, NSP-W and NCE each becoming a subsidiary of the new natural gas holding company.
January 31, 2000
TABLE OF CONTENTS
|
I. |
EXECUTIVE SUMMARY |
1 |
|
II. |
CONCLUSIONS |
3 |
|
III. |
SPIN-OFF ASSUMPTIONS |
6 |
|
IV. |
GENERAL STUDY ASSUMPTIONS |
8 |
|
V. |
GAS COMPANY OF MINNESOTA ANALYSIS |
9 |
|
VI. |
GAS COMPANY OF WISCONSIN ANALYSIS |
17 |
|
VII. |
OTHER CUSTOMER IMPACTS |
28 |
|
VIII. |
BILL COMPARISON OF GAS COMPANY OF MINNESOTA AND GAS COMPANY OF WISCONSIN TO OTHER UTILITIES |
29 |
|
IX. |
EFFECT ON REMAINING ELECTRIC COMPANIES |
30 |
APPENDICES
|
APPENDIX A. |
COMPARISON OF NSP AND NSP-W TO REGIONAL GAS UTILITIES |
|
APPENDIX B. |
NEW GAS COMPANY OF MINNESOTA ORGANIZATION CHART |
|
APPENDIX C. |
BASE CASE - NSP |
|
APPENDIX D. |
NEW GAS COMPANY OF WISCONSIN ORGANIZATION CHART |
|
APPENDIX E. |
BASE CASE - NSP - W |
I. EXECUTIVE SUMMARY
Northern States Power Company, a Minnesota corporation ("NSP") management and staff have undertaken this Analysis of the Economic Impact of a Divestiture of the Gas Operations of NSP and its Wholly-Owned Subsidiary Northern States Power Company, a Wisconsin corporation ("NSP-W") ("Study"). The purpose of the Study is to quantify the economic impact on NSP shareholders and its customers of spinning off NSP's and NSP-W's natural gas assets and businesses. NSP is currently an exempt holding company under the Public Utility Holding Company Act of 1935 ("PUHCA") providing electric and natural gas service in a major portion of the States of Minnesota, North Dakota, and South Dakota, with a small natural gas operation in Arizona called Black Mountain Gas ("BMG"). NSP-W is a wholly-owned subsidiary of NSP providing electric and natural gas service in and around Eau Claire, Wisconsin, portions of northwestern Wisconsin and portions of the Upper Peninsula of Michigan.
The Study quantifies the economic impacts of operating the following two entities as independent, stand-alone companies if they were disaggregated from NSP's combined utility businesses:
The Study evaluates the increased costs of "lost economies" associated with divestiture of these businesses from two perspectives - shareholders and customers. The effect on shareholders is the direct result of the increased costs or lost economies resulting from a spin-off or divestiture, absent regulatory rate relief to recoup these lost economies. The effect on customers assumes recovery of these lost economies through rate increases, and is divided into two parts. The potential effects on customers have first been evaluated in terms of increased revenue requirements and rates, and second in terms of the impact of other quantifiable and nonquantifiable costs.
The projected impacts on the shareholders of the lost economies resulting from the spin-off of NSP's gas business (including BMG) into Gas Company of Minnesota and the spin-off of NSP-'s gas business into Gas Company of Wisconsin, assuming no rate adjustments to recover the lost economies and associated income taxes, are shown in Table I-1.
|
TABLE I-1 ANNUAL SHAREHOLDER IMPACT OF LOST ECONOMIES |
||
|
LOST ECONOMIES AS A PERCENT OF: |
GAS COMPANY OF MINNESOTA |
GAS COMPANY OF WISCONSIN |
|
Total Gas Operating Revenue |
7.16% |
9.68% |
|
Total Gas Operating Rev. Deductions |
7.81% |
10.38% |
|
Gross Gas Income |
86.05% |
144.22% |
|
Net Gas Income |
110.14% |
206.69% |
In Table I-1, Total Gas Operating Revenue is the sum of rate and other revenue for the 12 months ending December 31, 1998 (Base Case). [179] Total Gas Operating Revenue Deductions includes all operation and maintenance expenses, administrative and general expenses, depreciation and all taxes, except income taxes. Gross Gas Income is the difference between Total Gas Operating Revenue and Total Gas Operating Revenue Deductions. Net Gas Income is Gross Gas Income minus Income Taxes.
Alternatively, and assuming that each organization is allowed to increase its rate revenue to recover these lost economies and attendant income taxes through rate increases, the projected impact on NSP's and NSP-W's gas customers is shown in Table I-2.
|
TABLE I-2 ANNUAL GAS CUSTOMER IMPACT OF LOST ECONOMIES |
||
|
RATE REVENUE:
|
GAS COMPANY OF |
GAS COMPANY OF |
|
Pre Spin-off |
$360,567,000 |
$78,800,000 |
|
Post Spin-off |
$387,290,000 |
$86,612,000 |
|
Increase |
$26,723,000 |
$7,812,000 |
|
Percent Increase |
7.41% |
9.91% |
In addition to the foregoing impacts, the following table sets forth the impact on the remaining electric utility operations comprised of NSP's and NSP-W's current electric businesses. This impact is primarily due to the expense of additional employees required to perform the multitude of functions accomplished by employees who currently work for both the electric and gas businesses and assumes that rate recovery of the lost economies and attendant income taxes is allowed by the appropriate regulatory agencies.
|
TABLE I-3 ANNUAL ELECTRIC CUSTOMER IMPACT OF LOST ECONOMIES |
||
|
RATE REVENUE:
|
NSP REMAINING |
NSP-W REMAINING |
|
Pre Spin-off |
$2,200,000,000 |
$325,000,000 |
|
Post Spin-off |
$2,219,900,000 |
$329,690,000 |
|
Increase |
$19,900,000 |
$4,690,000 |
|
Percent Increase |
0.90% |
1.44% |
If, on the other hand, the foregoing organizations were not spun-off from NSP and NSP-W, the NSP/NCE merger was implemented as proposed, and assuming a rate decrease to pass on the potential merger benefits, the impact on gas customers is shown in Table I-4.
|
TABLE I-4 ANNUAL GAS CUSTOMER IMPACT OF POTENTIAL |
||
|
RATE REVENUE |
NSP GAS |
NSP-W GAS |
|
Pre Merger |
$360,567,000 |
$ 78,800,000 |
|
Post Merger |
355,562,000 |
77,853,000 |
|
Decrease |
5,005,000 |
947,000 |
|
Percent Decrease |
1.39% |
1.20% |
Finally, both NSP's and NSP-W's gas customers would incur increased personal costs such as postage on a separate envelope and additional check costs to mail payments to two utilities rather than one. This does not include additional customer confusion resulting from doing business with two utilities rather than one. The increased postage expense alone of $3.96 per customer per year for all customers is shown in Table I-5.
|
TABLE I-5 OTHER ANNUAL CUSTOMER IMPACTS |
|
|
NSP POSTAGE
|
NSP-W POSTAGE |
|
$1,523,000 |
$326,000 |
II. CONCLUSIONS
A. Impact on Gas Operations
The spin-off of NSP's and NSP-W's current gas businesses into two stand-alone companies is estimated to result in a substantial increase in costs and therefore a substantial decrease in earnings to NSP shareholders absent rate relief to recoup these increased costs. Without an increase in rates, the immediate negative effect on shareholders' earnings would be substantial. For example, the earnings contribution relating to NSP's and NSP-W's gas businesses would be decreased by approximately 110 percent and 207 percent, respectively, as shown in Table I-1. Such a decline would make ownership of shares in these stand-alone companies unattractive.
However, rate recovery of these cost increases to retail gas customers in Minnesota, North Dakota, South Dakota, Arizona, Wisconsin and Michigan would result in a significant increase in the level of costs borne by these customers with no attendant increase in the level or quality of service. The rate increases required to provide the level of revenue needed to cover costs to operate Gas Company of Minnesota and Gas Company of Wisconsin would be significant, amounting to approximately $35 million, as shown in Table I-2. Such rate increases would make the new gas companies less competitive at a time when competition in the energy industry is rapidly increasing due to Federal Energy Regulatory Commission ("FERC") Order No. 636 and other FERC and state regulatory restructuring initiatives such as the current trend toward retail service unbundling.
The potential physical bypass of Local Distribution Companies ("LDCs") is becoming a reality that LDCs must face daily, along with the commensurate possibility of a decreasing customer base, resultant rate increases, and potential stranded costs. Certain NSP and NSP-W customers have already bypassed their LDC distribution system, and other customers have used the threat of physical bypass to negotiate service agreements at substantial discounts.[180] The FERC has sanctioned the bypass of LDC systems by interstate pipelines in recent years in the interest of increasing competition. In addition, natural gas service continues to compete with alternative fuels. Cost increases to the gas utility operations from divestiture might increase the bypass risk.
The focus on competition is also beginning to require the unbundling of LDC services. This trend is occurring as state commissions, LDCs and their customers call for a change in the way LDCs provide services. While the objectives of these groups are not always consistent, the result will likely be the same - increased competition. LDCs already face fierce price competition, and must remain competitive to avoid shareholder losses and a reduced customer base. As a result of the increased costs discussed herein, bundled or unbundled services may become uncompetitive as the rate increases needed to recover these cost increases could potentially result in rates that few customers would pay when compared to other competitive options they may have.
A graphic comparison of typical residential and commercial gas bills in Minnesota, North Dakota, Wisconsin and Michigan, illustrating the loss of each new Gas Company's relative position resulting from a spin-off, as compared to other regional utilities, is contained in Table VII-1. By comparison, retention of the NSP and NSP-W gas businesses by Xcel Energy Inc. ("Xcel") would allow rate reductions to gas customers, as noted in Table I-4.
B. Impact on Electric Operations
In addition, FERC Order Nos. 888, [181] 889 and 2000, and state retail restructuring initiatives are expected to increase competition in the electric industry. If divestiture of the gas operations were required, the lost economies estimated for NSP's and NSP-W's remaining electric companies would also have an adverse impact on their ability to successfully compete in the restructured electric industry. A forced divestiture as a result of the proposed merged company would result in the remaining electric utility operating companies of New NSP being less cost competitive than they would be as part of a merged company.
C. Other Impacts
As opposed to the negative results of the economic impact, two positive conclusions were noted.
However, it should be noted that these same conditions (continued local management and state regulatory jurisdiction) would exist if the gas businesses remain with the new merged entity.
D. Divestiture Would Not Tend
Toward the Economical and Efficient Development of an
Integrated Public Utility
System
As previously discussed in the Executive Summary, there is a combination of approximately $35 million in gas revenue increases needed for the New Gas Companies, shown in Table I-2, and an additional $25 million in electric revenue increases as a result of lost utility operating economies, including income taxes, that will impact the remaining NSP and NSP-W electric companies, and potentially their customers shown in Table I-3. Therefore, the total revenue increases that would be required is approximately $60 million annually. This compares to rate decreases of $6 million annually if the NSP/NCE merger is approved and Xcel is allowed to retain its gas utility operations. Thus, the total differential is more than $66 million annually.
Based on the foregoing conclusions, NSP believes that spinning off the gas businesses would adversely impact NSP's shareholders and both electric and gas customers. By comparison, the combination of the gas operations under Xcel will facilitate and enhance the efficiency of gas operations. Therefore, NSP recommends that it is in the best interest of its shareholders and customers that Xcel retain the existing NSP and NSP-W gas utility assets and businesses.
III. SPIN-OFF ASSUMPTIONS
The Study assumes that two segments of NSP's current business can, in fact, be spun-off into stand-alone companies. These two potential stand-alone businesses are currently part of the combined companies as described below:
Within Minnesota, North Dakota and South Dakota, NSP is primarily a combination electric and gas utility, engaged in the generation, purchase, transmission, distribution and sale of electricity, and in the purchase, transmission, distribution, sale and transportation of natural gas. NSP presently provides gas-only service in Arizona through its Black Mountain Gas division.
NSP's gas business includes an extensive distribution system serving numerous communities throughout Minnesota, North Dakota and Arizona. NSP's gas system serves over 385,000 residential, commercial, industrial, and transportation customers. Total annual gas revenues are approximately $361 million. Annual gas deliveries are nearly 87 billion cubic feet (Bcf). The Study assumes the retail gas operations of NSP are spun-off into a stand-alone gas company: New Gas Company of Minnesota. [183]
NSP's electric business, which includes generation, transmission, and distribution facilities located statewide, provides service to nearly 1.2 million customers throughout a large portion of Minnesota, North Dakota and South Dakota. Total annual electric revenues are approximately $2.2 billion and annual sales are nearly 3.7 million megawatt hours (Mwh).
NSP's wholly-owned subsidiary, NSP-W, operates a combination electric and gas business in Wisconsin and the Upper Peninsula of Michigan. NSP-W is engaged in the generation, transmission, distribution and sale of electricity, and in the purchase, distribution, sale and transportation of natural gas.
The NSP-W gas distribution system serves over 82,000 customers. Total annual gas revenues are approximately $79 million. Annual gas deliveries are nearly 18 billion cubic feet (Bcf). The Study assumes that the gas portion of NSP-W is spun-off into a stand-alone gas company: New Gas Company of Wisconsin.
The NSP-W electric system consists of generation, transmission and distribution facilities and serves over 220,000 customers. Total annual electric revenues are approximately $325 million and annual sales are approximately 6 million megawatt hours (Mwh).
The Study assumes that it would be possible to spin-off NSP's gas business and its NSP-W's gas business from their respective combined gas and electric businesses for the following reasons:
In addition, the Study analyzes the Gas Company of Minnesota and Gas Company of Wisconsin organizations as two stand-alone companies rather than one combined-gas-company for the following reasons:
IV. GENERAL STUDY ASSUMPTIONS
The assumptions, information and data utilized in the analyses undertaken in this Study are based on the energy industry expertise and experience possessed by the management and staff of NSP and NSP-W. Employees with experience in all major facets of the operations of NSP and NSP-W were consulted and provided input. The Study's aggregate conclusions are the result of many independent inputs and analyses from highly qualified individuals throughout the companies.
The Base Cases for the Study were developed using actual sales, revenues, costs, and rates of return from the 1998 gas utility operations of NSP and NSP-W.
NSP made an extensive analysis of the major cost components that may be associated with a divestiture. As a result of discussions with numerous personnel at NSP and NSP-W, the major cost components associated with a divestiture were identified, quantified, and included in the Study results. A more exhaustive analysis would probably produce additional costs and diseconomies from divestiture of NSP and NSP-W gas operations. Thus the Study results are likely to be at the low end of the actual divestiture costs based on these assumptions.
The remainder of this section discusses the major assumptions that were employed in developing the Study.
V. GAS COMPANY OF MINNESOTA ANALYSIS
A detailed study was undertaken to analyze the potential impact on both the shareholders and customers of NSP if it were ordered to divest its Minnesota, North Dakota, South Dakota and Arizona gas utility operations. In order to accomplish that study, the management of NSP provided estimates of the staffing levels of a Gas Company of Minnesota, as well as any other operational and administrative changes that would have to be made in order to maintain the same level and quality of service to its gas customers after a spin-off of the gas business.
A. Specific Assumptions
In addition to the General Study Assumptions cited earlier, the following specific assumptions have been incorporated into the analysis of the spin-off of the gas operations of NSP into Gas Company of Minnesota.
1. Labor Assumptions
a. The NSP organization as of December 31, 1998, was used as the template for developing the Gas Company of Minnesota organization structure.
b. Where practical, some management positions were combined, eliminated or replaced with non-management positions. Some further consolidation of management positions may be possible, particularly within the staff organizations. However, the overall span of control (the ratio of non-management employees to management employees) for Gas Company of Minnesota is greater than the span of control in the NSP organization. As of December 31, 1998, NSP had 548 management and 4,673 non-management employees, yielding a span of control of 8.5 employees per manager. Gas Company of Minnesota would have 71 management and 848 non-management employees, resulting in a span of control of 12.0 (i.e., fewer managers per non-management employees than the NSP organization). This higher span of control is due to the following:
1) Management employees required in the operations areas, but with a higher non-management employee count due to the elimination of electric and corporate resources that are currently providing both electric and gas services; and,
2) The number of management personnel required in the staff organization, but with some increases in non-management staff size due to the elimination of support for electric and corporate functions that were currently providing both electric and gas services.
c. To provide an equivalent quality of customer service, an analysis was made of the Customer Service Area to determine the number of employees required for Gas Company of Minnesota. The staffing levels required in the Gas Company of Minnesota compared to the current combined company for the following functional areas of Customer Service are as follows:
Meter Reading 57 Additional (29% over current levels)
Customer Service 59 Additional (37% over current levels)
Billing/Statements 17 Additional (31% over current levels)
Payment Processing 17 Additional (37% over current levels)These functions are accomplished by a relatively small number of personnel and a spin-off of gas responsibilities would not significantly affect the number of employees required to accomplish electric only functions.
d. The Customer Service cost for Gas Company of Minnesota was based on the current cost of providing customer service (meter reading, customer service, billing and payment processing) for both electric and gas customers. This amount was multiplied by the number of current gas customers as of December 31, 1998. The staffing levels were based on an employee per customer ratio. This ratio was applied to the gas customers to determine the required staff size per Customer Service function.
e. Executive salaries were based on composite industry service data from Mercer, American Gas Association (AGA), Towers Perrin, Edison Electric Institute (EEI), and Wyatt.
f. All non-executive salaries were based on the current compensation levels for the functional areas.
g. Pensions and benefits were estimated as a percent of the labor cost. Currently, pension and benefits are approximately 30 percent above the base cost of labor. Therefore, after the base cost of labor was determined, an additional 30 percent was added to include pension and benefit costs.
2. Operations & Maintenance and Administrative & General Assumptions:
a. Annual facility costs relating to the additional employees and building needs for the trucks, trailers and backhoes required to operate the stand-alone companies have been incorporated into the Study.
b. Separate arrangements would be made for external auditing of the books and accounts of Gas Company of Minnesota.
c. Executive and administrative support from NSP would cease upon any divestiture, and these functions have been provided for in the Gas Company of Minnesota organizational structure.
d. Separate gas bills would be provided to customers of Gas Company of Minnesota. Specific shared activities such as locating and customer support were examined and included in the analysis.
e. The Customer Service center needed for a Gas Company of Minnesota will be leased at an annual cost of $625,000.
3. Capital Expenditure and Cost Assumptions:
a. With the exception of Information Technology computer hardware to handle the various accounting and operating systems, estimated at $3.0 million, and facilities costs related to work stations, estimated at $1.6 million. The study assumes no additional capital expenditures would be made by Gas Company of Minnesota as a direct consequence of spinning off the gas facilities from NSP. This, of course, does not include planned capital expenditures to be made in the normal course of business in order to maintain existing levels of service and provide service to new customers.
b. In the event NSP is required to divest its gas operations, and assuming the assets are spun-off into a new stand-alone corporation, the requirements of the existing indentures would result in the need to recapitalize at market rates in effect at the time of the spin-off. Additionally, costs associated with the issuance of securities would be incurred and ultimately included in the Gas Company of Minnesota cost of service.
The current capital structure of NSP was used for the purpose of analyzing capital costs for Gas Company of Minnesota. This structure is equal to the capital structure approved by the MPUC in NSP's most recent gas rate proceeding, Docket No. G002/GR-97-1606. As of December 31, 1998, NSP's gas rate base was capitalized as follows:
Ratio
Cost
Composite Cost
Long/Short Term Debt
48.99%
6.90%
3.37%
Preferred Stock
5.15%
4.79%
0.25%
Common Equity
45.86%
11.40%
5.23%
Total
100.00%
8.85%
This Study assumes that Gas Company of Minnesota would have access to capital at a cost similar to that of NSP. The difference expected from the rates listed above would result from an increased equity ratio. The Study assumes that gas utilities have an equity ratio about 300 basis points higher than electric utilities. NSP's electric utility business encompasses about 90% of the combined rate base. The study assumes the capital structure is really a function of the electric business and therefore a capital structure for an electric only NSP would be the same as the current combined capital structure. The cost of debt was not changed because the marginal cost of debt for a double-A utility was assumed to be about the same as the embedded rate.
The cost of common equity is 11.4 percent which was accepted by the MPUC in Docket No G002/GR-97-1606. Common equity would require the sale of new securities, as new stock certificates would be issued to future shareholders of Gas Company of Minnesota. Gas Company of Minnesota would capitalize through an initial public offering (IPO) of 20% of the equity value and spinning off 80% to existing NSP shareholders, and debt issuance in the above reference capital structure ratios at an aggregated cost of $5.2 million. Annual cost over 30 years would be $173,000. This cost would be charged as a transition cost to be recovered over 30 years.
4. Transition Cost Assumptions. In addition to the increased amount of equity discussed above, the new Gas Company of Minnesota and Gas Company of Wisconsin would incur transition costs associated with the new separate gas utilities being formed. Gas franchises would be assigned to the new gas companies by providing notice to the cities at minimal or zero cost.
5. Foregone Merger Savings. The Xcel Energy merger filing includes anticipated merger savings for the gas utilities. The Study assumed these savings would be lost as a result of divestiture. The levelized annual impact is $5.0 million.
B. Organization of Gas Company of Minnesota
The functional organization chart of Gas Company of Minnesota is contained in Appendix B.
Design of Gas Company of Minnesota Organization - The NSP organization at December 31, 1998, was used as the pattern for developing the Gas Company of Minnesota organization structure. In order to develop the new structure for the standalone company, management was contacted for input regarding staffing levels.
Board of Directors - The Board of Directors is assumed to consist of twelve directors based on the size and scope of Gas Company of Minnesota.
Chief Executive Officer (CEO) - The CEO reports to the Board of Directors and is responsible for overseeing the entire Company. The CEO oversees 8 direct-report executives (Chief Operating Officer; Chief Financial Officer, Customer Service Vice President; Human Resources Vice President, Chief Information Officer, Government Affairs Vice President, and General Counsel) and is responsible for Audit Services. The Executive Organization totals 19 employees, and is composed of 8 executives, 1 manager, 2 non-management personnel, and 8 executive assistants.
Chief Operating Officer (COO) - The COO reports directly to the CEO and is responsible for the overall operating activities of the Company. The COO oversees the work of three directors (Operations); Gas Supply; and Gas Control and Engineering. The organization managed by the COO totals 468 employees, and is composed of 30 managers, and 438 non-management personnel.
Director, Gas Control and Engineering - The Director of Gas Control and Engineering is responsible for measurement system design (pipelines, storage reservoirs, and compressors), LNG and propane plants, and gas system control coordination. Control and Engineering totals 55 employees, composed of 3 management and 52 non-management personnel.
Director, Gas Supply - The Director of Gas Supply and Federal Regulatory Affairs is responsible for acquiring interstate gas transportation and storage capacity, forecasting gas requirements, making gas purchases and contract administration (supply accounting, bill payment, etc.) Gas Supply totals 12 employees, composed of 3 management and 9 non-management personnel.
Director, Operations - The Director of Operations is responsible for all major distribution functions such as safety, environmental training, regional management, pipeline construction, and distribution system support services. Operations totals 401 employees, composed of 22 management and 379 non-management personnel.
Chief Financial Officer (CFO) - The CFO reports directly to the CEO and is responsible for rates and regulatory relations, investor relations, risk management, finance, treasury, and accounting functions. The CFO oversees the work of 6 managers (Rates & Regulatory Relations, Investor Relations, Treasury, Risk Management, Corporate Strategy, and the Controller.) The organization managed by the CFO totals 63 employees, and is composed of 10 management and 53 non-management personnel.
Vice President, Customer Support - The Vice President, Customer Support reports directly to the CEO and is responsible for the day-to-day interface with customers, customer accounts, meter reading, credit, billing and customer information service. The Vice President is also responsible for marketing, sales, market research, conservation programs, program development and evaluation. Two non-regulated positions also report to the Customer Support Vice President. Natural Gas Services provides engineering, operational and technical support to communities that want natural gas but are outside NSP's service territory. Advantage Service is a non-regulated appliance service business. Customer Support totals 269 employees and is composed of 10 management and 259 non-management personnel.
General Counsel - The General Counsel reports directly to the CEO and oversees the Legal Affairs and the Corporate Secretary functions. The General Counsel is responsible for environmental compliance, SEC compliance, litigation, regulatory affairs, labor and benefit legal matters, contracts and corporate governance. The organization managed by the General Counsel totals 6 employees, and is composed of 2 management and 4 non-management personnel.
Vice President, Human Resources - The Vice President, Human Resources, reports directly to the CEO and oversees company staffing, compensation, training, benefits, health services, employee services and security. The organization managed by the Human Resources Vice President totals 17 employees, and is composed of 3 management and 14 non-management personnel.
Chief Information Officer (CIO) - The CIO reports directly to the CEO and is responsible for all the information technology requirements. The CIO oversees the work of 5 managers (Application Support, Infrastructure, Data Network, Director, Recovery and User Support). The organization managed by the CIO totals 55 employees, and is comprised of 5 management and 50 non-management personnel.
Vice President, Government Affairs - The Vice President, Government Affairs, reports directly to the CEO and is responsible for all corporate communications, state, federal and public affairs and environmental monitoring. The organization managed by the Government Affairs Vice President totals 22 employees, and is composed of 4 management and 18 non-management personnel.
C. Annual Cost Increases
Based upon the foregoing general and specific assumptions, and the staffing requirements of the organizational structure, the following increased annual costs have been developed for Gas Company of Minnesota:
1. Customer Support $12,382,000
2. Chief Operating Officer $ 3,465,000
3. Chief Financial Officer $ 3,244,000
4. Chief Information Officer $ 1,833,000
5. Public Affairs $ 1,326,000
6. Chief Executive Officer, Audit Services $ 818,000
7. Human Resources $ 735,000
8. Board of Directors Fees $ 341,000
9. General Counsel $ 230,000Total $24,374,000
D. Capitalization Cost Increases
Using the allowed cost of equity as discussed earlier, and recasting the cost of capitalizing the gas assets using NSP's existing capital structure as a proxy for Gas Company of Minnesota results in the following:
Ratio
Cost
Composite Cost
Long/Short Term Debt
45.99%
6.88%
3.17%
Preferred Stock
5.15%
4.79%
0.24%
Common Equity
48.86%
11.40%
5.57%
Total
100.00%
8.98%
The actual interest rates and preferred stock yields in effect at the time of divestiture could be substantially higher or lower than the forecasts employed here.
Applying the foregoing capital cost to Gas Company of Minnesota results in the following increased annual capital costs:
Capitalization Cost $1,260,000
E. Transition Cost Increases
The following is a summary of the principal transition costs that will be incurred as a result of a spin-off of the gas business of NSP and their annual costs:
IPO and Debt Issuance Cost $173,000
F. Total Lost Economies
Summarizing the foregoing increased annual costs, capital costs, foregone merger savings, and amortized transition costs which were developed in the Base Case Study yields the following total lost economies before the effect of income taxes:
Total Lost Economies: $25,807,000
G. Income Taxes
Recovery of the foregoing lost economies in a general rate proceeding would also require an increase to recover income taxes associated with the lost economies. The following is a summary of the revenue effect of income taxes:
Total Income Taxes: $916,000
H. Foregone Merger Savings
The following is a summary of the foregone merger savings lost if the spin-off occurs:
Foregone Merger Savings $5,005,000
I. Base Case - 12 Months Ended December 31, 1998
The following is a summary of the key components of the Base Case (the definition of each item is the same as in the Executive Summary):
1. Total Gas Operating Revenue $360,567,000
2. Total Gas Operating Revenue Deductions $330,578,000
3. Gross Gas Income $ 29,989,000
4. Net Gas Income $ 23,432,000
J. Comparison of the Total Lost Economies of Gas Company of Minnesota to the Base Case
The Total Lost Economies, before the effect of income taxes, as a percent of the key components of the Base Case are:
1. Percent of Total Gas Operating Revenue 7.16%
2. Percent of Total Gas Operating Revenue Deductions 7.81%
3 Percent of Gross Gas Income 86.05%
4. Percent of Net Gas Income 110.14%
K. Comparison of Rates of Return on Rate Base
The following is a comparison of the rates of return on rate base for the gas operations before and after an assumed spin-off:
1. Rate of Return - Base Case 6.42%
2. Pro Forma Rate of Return after Spin-off 2.11%
3. Required Rate of Return based on Gas Company 8.98%
of Minnesota Cost of Capital
VI. GAS COMPANY OF WISCONSIN ANALYSIS
As was the case with NSP, a detailed study was undertaken to analyze the potential impact on both the shareholders and customers of NSP-W if it were ordered to divest its gas business.
In order to accomplish that study, the management of NSP-W provided estimates of the staffing levels of a Gas Company of Wisconsin, as well as any other operational and administrative changes that would have to be made in order to maintain the same level and quality of service to its gas customers after a spin-off of the gas properties.
A. Specific Assumptions
In addition to the General Study Assumptions cited earlier, the following specific assumptions have been incorporated into the analysis of the spin-off of the gas operations of NSP-W into a Gas Company of Wisconsin.
1. Labor Assumptions:
a. As was the case with Gas Company of Minnesota, the NSP-W organization at December 31, 1998, was used as the template for developing the Gas Company of Wisconsin organization structure.
b. Where practical, some management positions were combined, eliminated or replaced with non-management positions. Some further consolidation of management positions may be possible, particularly within the staff organizations. However, the overall span of control (the ratio of non-management employees to management employees) for Gas Company of Wisconsin is greater than the span of control in the NSP-W organization. As of December 31, 1998, NSP-W had 120 management and 743 non-management employees, yielding a span of control of 6.2 employees per manager. Gas Company of Wisconsin has 18 management and 129 non-management employees, resulting in a span of control of 7.2 (i.e., fewer managers per non management employee than the organization).
c. To provide an equivalent quality of customer service an analysis was made of the Customer Service Area to determine the number of employees required for Gas Company of Wisconsin. The staffing levels in the Gas Company of Wisconsin requires 44 employees, approximately 14% of the combined company customer service level.
d. The Customer Service cost for Gas Company of Wisconsin was based on the current cost of providing customer service from the Gas Company of Minnesota Study (meter reading, customer service, billing and payment processing) for both electric and gas customers. This amount was multiplied by the number of current gas customers as of December 31, 1998. The staffing levels were based on an employee per customer ratio. This ratio was applied to the gas customers to determine the required staff size per Customer Service function.
e. Executive salaries are based on national survey data. Since the size of the organization is smaller than Gas Company of Minnesota, the executive salaries are assumed to be less for Gas Company of Wisconsin.
f. All non-executive salaries are based on current average compensation for the appropriate job level.
g. After the base cost of labor was determined, an additional 30 percent was added to determine pension and benefit costs. This percent is based on NSP-W's approximate current percentage in order to keep benefits similar for Gas Company of Wisconsin.
2. Operation & Maintenance and Administrative & General Assumptions:
a. In addition to the General Study Assumptions cited earlier, it is assumed that certain minor administrative functions now performed by employees of NSP and billed to NSP-W would be performed by Gas Company of Wisconsin. For example, audit services and investor relations functions are currently being performed by NSP, and if divestiture of NSP-W's gas operations were ordered, Gas Company of Wisconsin would perform those functions.
b. Annual facility costs relating to the additional employees and building needs for trucks, trailers and backhoes required to operate the Gas Company of Wisconsin have been incorporated into the Study.
c. Separate arrangements would be made for external auditing of the books and accounts of Gas Company of Wisconsin.
d. In like manner, legal assistance, billing and record-keeping assistance would be required, and it is assumed that Gas Company of Wisconsin would be able to acquire these services for substantially the same fees as it is now incurring.
e. Executive and administrative support from NSP-W would cease upon any divestiture, and these functions have been provided for in the Gas Company of Wisconsin organizational structure.
f. Separate gas bills would be provided the customers of Gas Company of Wisconsin.
3. Capital Expenditure and Cost Assumptions:
a. The study assumes no additional capital expenditures would be made by Gas Company of Wisconsin as a direct consequence of spinning off the gas facilities from NSP-W. This, of course, does not include planned capital expenditures to be made in the normal course of business in order to maintain existing levels of service and provide service to new customers.
b. In the event NSP-W is required to divest its gas operations, and assuming the assets are spun-off into a new stand-alone corporation, the requirements of the existing indentures would result in the need to recapitalize at market rates in effect at the time of the spin-off. Additionally, costs associated with the issuance of securities would be incurred and ultimately included in the Gas Company of Wisconsin cost of service.
The current capital structure of NSP-W was used for the purpose of analyzing capital costs for Gas Company of Wisconsin. This structure is equal to the capital structure approved by the PSCW in NSP-W's Docket No. 4220-UR-110. As of September 15, 1998, NSP-W's gas rate base was capitalized as follows:
Ratio
Cost
Composite
Long/Short Term Debt
45.00%
7.08%
3.28%
Common Equity
55.00%
11.90%
6.55%
Total:
100.00%
9.73%
This Study assumes that Gas Company of Wisconsin would have access to capital at a cost similar to that of NSP-W. The difference expected from the rates listed above would result from an increased equity ratio. The study assumes that gas utilities have an equity ratio about 300 basis points higher than electric utilities. NSP-W's electric business encompasses about 90% of the combined rate base, the study assumes that the capital structure is really a function of the electric business and therefore a capital structure for an electric only NSP-W would be the same as the current combined capital structure. The cost of debt was not changed because the marginal cost of debt for a double-A utility should be about the same as the embedded rate.
The cost of common equity is 11.90 percent which was established by the PSCW on September 15, 1998, in NSP-W's Docket No. 4220-UR-110. Common equity would require the sale of new securities, as new stock certificates would be issued to future shareholders of Gas Company of Wisconsin. Gas Company of Wisconsin would capitalize through an initial public offering (IPO) of 20% of the equity value and spinning off 80% to existing NSP shareholders, and debt issuance in the above reference capital structure ratios at an aggregated cost of $1.0 million. Annual cost over 30 years would be $34,000. This cost would be charged as a transition cost to be recovered over 30 years.
4. Transition Cost Assumptions. Transition costs for Gas Company of Wisconsin have been previously discussed, and would be amortized over the appropriate life of the asset.
5. Foregone Merger Savings. The NSP/NCE merger filing includes anticipated merger savings for the gas utilities. The Study assumed these savings would be lost as a result of divestiture. The levelized annual impact is $1.0 million.
B. Organization of Gas Company of Wisconsin
The functional organization chart of Gas Company of Wisconsin is contained in Appendix C.
Design of Gas Company of Wisconsin Organization - The NSP-W organization at December 31, 1998, was used as the pattern for developing the Gas Company of Wisconsin organization structure. In order to develop the new structure for the stand-alone company, management was contacted for input regarding staffing levels.
Board of Directors - The Board of Directors is assumed to consist of 6 directors based on the size and scope of Gas Company of Wisconsin.
Chief Executive Officer (CEO) - The CEO reports to the Board of Directors and is responsible for overseeing the entire Company. The CEO oversees 7 direct-report executives (Chief Operating Officer, Chief Financial Officer, Customer Service Vice President; Human Resources Vice President, Chief Information Officer, Government Affairs Vice President, and General Counsel) and is responsible for Audit Services. The Executive Organization totals 11 employees, and is composed of 8 executives, 1 manager, and 2 executive assistants.
Chief Operating Officer (COO) - The COO reports directly to the CEO and is responsible for the overall operating activities of the Company. The COO oversees the work of two directors (Operations; and Gas Supply, Control and Engineering). The organization managed by the COO totals 57 employees, and is composed of 4 managers, and 53 non-management personnel.
Director, Gas Supply Control and Engineering - The Director of Gas Supply, Control, and Engineering, is responsible for measurement, acquiring interstate gas transportation capacity, forecasting gas requirements, making gas purchases, system design (pipelines, storage reservoirs, and compressors), gas system control coordination. The organization totals 11 employees, composed of 2 management and 9 non-management personnel.
Director, Operations - The Director of Operations is responsible for all major distribution functions such as safety, environmental training, regional management, pipeline construction, distribution system support services, facilities, warehousing, and purchasing. Support totals 48 employees, composed of 2 management and 46 non-management personnel.
Chief Financial Officer (CFO) - The CFO reports directly to the CEO and is responsible for regulatory relations, finance, investor relations, risk management, treasury, and accounting functions. The CFO oversees the work of three managers (Treasury, Investor Relations, and the Controller.) The organization managed by the CFO totals 16 employees, and is composed of 3 managers and 13 non-management personnel.
Vice President, Customer Support - The Vice President, Customer Support, reports directly to the CEO and is responsible for the day-to-day interface with customers, customer accounts, meter reading, credit, billing and customer information service. The Vice President is also responsible for marketing, sales, market research, conservation programs, program development and evaluation. Customer Support totals 47 employees and is composed of 3 management and 44 non-management personnel.
General Counsel - The General Counsel reports directly to the CEO and oversees legal affairs and corporate secretary functions. The General Counsel is responsible for SEC compliance, litigation, regulatory affairs, labor and benefit legal matters, contracts and corporate governance. The organization managed by the General Counsel totals 2 employees, and is composed of 2 non-management personnel.
Vice President, Human Resources - The Vice President, Human Resources, reports directly to the CEO and oversees company staffing, compensation, training, benefits, health services, employee services and security. The organization managed by the Human Resources Vice President totals 3 employees, and is composed of 3 non-management personnel.
Chief Information Officer (CIO) - The CIO reports directly to the CEO and is responsible for all the information technology requirements. The CIO oversees the work of Application Support; Infrastructure; Data Network; Director, Recovery and User Support. The organization managed by the CIO totals 9 employees, and is comprised of 1 management and 8 non-management personnel.
Government Affairs Vice President - The Government Affairs Vice President reports directly to the CEO and is responsible for all corporate communications, state, federal and public affairs and environmental monitoring. The organization managed by the Government Affairs Vice President totals 2 employees, and is comprised of 2 non-management personnel.
C. Annual Cost Increases
Based upon the foregoing general and specific assumptions, and the staffing requirements of the organizational structure, the following increased annual costs have been developed for Gas Company of Wisconsin:
1.
Chief Information Officer
$2,443,000
2.
Customer Support
$2,018,000
3.
Chief Financial Officer
$1,319,000
4.
Chief Executive Officer, Audit Services
575,000
5.
Public Affairs
$ 393,000
6.
General Counsel
$ 190,000
7.
Board of Directors Fees
$ 202,000
8.
Human Resources
$ 163,000
9.
Chief Operating Officer
$ 40,000
Total
$7,343,000
D. Capitalization Cost Increases
Using the capital structure, allowed cost of equity and debt costs for Gas Company of Wisconsin discussed earlier, the resulting weighted composite cost of capital for the stand alone gas company would be:
Ratio Cost Composite Cost
Long/Short Term Debt 42.00% 7.06% 2.97%
Common Equity 58.00% 11.90% 6.90%
Total 100.00% 9.87%
The actual interest rates in effect at the time of divestiture could be substantially higher or lower than the forecasts employed here.
Applying the foregoing capital cost to Gas Company of Wisconsin results in the following increased capital costs:
Capitalization Costs $252,000
E. Transition Cost Increases
The following is a summary of the principal transition costs that will be incurred as a result of a spin-off of the gas business of NSP-W and their annual Costs:
IPO and Debt Issuance Costs $34,000
F. Total Lost Economies
Summarizing the foregoing increased annual costs, capital costs, and amortized transition costs as developed in the Base Case Study, yields the following total lost economies before the effect of income taxes:
Total Lost Economies: $7,629,000
G. Income Taxes
Recovery of the foregoing lost economies in a general rate proceeding would also require an increase to recover income taxes associated with the lost economies. The following is a summary of the revenue effect of income taxes:
Total Income Taxes : $183,000
H. Foregone Merger Savings
The following is a summary of the foregone merger savings lost if the spin-off occurs:
Foregone Merger Savings $ 947,000
I. Base Case - 12 Months Ended December 31, 1998
The following is a summary of the key components of the Base Case (the definition of each item is the same as in the Executive Summary):
1. Total Gas Operating Revenue $78,800,000
2. Total Gas Operating Revenue Deductions $73,510,000
3. Gross Gas Income $ 5,290,000
4. Net Gas Income $ 3,691,000
J. Comparison of the Lost Economies of Gas Company of Wisconsin to the Base Case
The Total Lost Economies, before the effect of income taxes as a percent of the key components of the Base Case are:
1. Percent of Total Gas Operating Revenue 9.68%
2. Percent of Total Gas Operating Revenue Deductions 10.38%
3. Percent of Gross Gas Income 144.22%
4. Percent of Net Gas Income 206.69%
K. Comparison of Rates of Return on Rate Base
The following is a comparison of the rates of return on rate base for the gas operations before and after an assumed spin-off.
| Rate of Return - Base Case | 5.22% |
| Pro Forma Rate of Return after Spin-off | (1.36%) |
| Required Rate of Return based on Gas Company | 9.87% |
|
of Wisconsin Cost of Capital |
VII. OTHER CUSTOMER IMPACTS
A. Quantifiable Postage Costs
Combination customers who currently pay their monthly NSP or NSP-W electric and gas bill with one check and one stamp will be required to use two separate checks and two separate stamps in paying the remaining electric company and the two new gas companies. For the gas and electric customers of the existing NSP and NSP-W companies, the doubling of postage cost alone, not counting check costs, will result in a total annual out-of-pocket cost increase to customers of approximately $1.9 million annually. These annual postage costs are broken downs as follows:
Postage Costs
Gas Company of Minnesota Customers $1,523,000
Gas Company of Wisconsin Customers $ 326,000
Total $1,849,000
B. Non-Quantifiable
In addition to the quantifiable increased costs or lost economies which have been evaluated and included in the Study, there are other non-quantifiable costs which have not been included. The reason for not attempting to quantify these costs is that a meaningful estimate of these costs is beyond the scope of NSP's present analysis. However these costs do exist, and the following are a few examples of these non-quantifiable costs.
VIII. BILL COMPARISON OF GAS COMPANY OF
MINNESOTA AND GAS COMPANY
OF WISCONSIN TO OTHER UTILITIES
The following is a comparison of average monthly bills for various utilities with which NSP MN and NSP Wisconsin compete. The average bills are based on American Gas Association's Bill Comparison Report for the quarter ending March 31, 1998.
|
Table VIII - 1 |
||
|
Average Monthly Bill |
||
|
Name of Utility |
Residential |
Commercial |
|
Montana Dakota - ND |
$47.01 |
$208.00 |
|
Utilicorp United - MN |
$50.00 |
$227.00 |
|
NSP - MN |
$51.92 |
$228.00 |
|
Minnegasco |
$52.07 |
$235.00 |
|
New Gas Company of MN |
$56.61 |
$248.00 |
|
NSP - WI |
$64.08 |
$268.00 |
|
New Gas Company of WI |
$71.40 |
$298.87 |
IX. EFFECT ON REMAINING ELECTRIC COMPANIES
A. NSP
As a result of any divestiture, the remaining New NSP Utility electric utility operations would experience increased costs in addition to those experienced by Gas Company of Minnesota. These total increased costs of $19.9 million annually are largely the result of increased labor costs associated with the additional personnel required to replace those who currently work in both gas and electric operations and additional postage costs incurred since electric billings would no longer share postage with the gas billings. The total of these additional costs equates to approximately 0.9 percent of NSP electric rate revenues.
A summary of the increased annual costs applicable to New NSP is as follows:
1. Customer Service $ 7,294,000
2. Chief Information Officer $ 6,520,000
3. Chief Financial Officer $ 1,692,000
4. Human Resources $ 1,420,000
5. Chief Executive Officer, Audit Services $1,098,000
6. Government Affairs $ 780,000
7. Chief Operating Officer $ 553,000
8. General Counsel $ 414,000
9. Board of Directors Fees $ 101,000
Total $19,872,000
B. NSP-W
Similarly, the remaining NSP-W electric utility operations would experience additional costs due to labor and postage. The additional labor is due to replacing those personnel who currently work in both gas and electric operations and additional postage costs incurred since electric billings would no longer share postage with the gas billings. The total of these additional costs is $4.7 million annually, which is approximately 1.4 percent of NSP-W electric rate revenues.
A summary of the increased annual costs applicable to NSP-W is as follows:
1. Customer Service $2,108,000
2. Chief Operating Officer $ 810,000
3. Chief Information Officer $ 717,000
4. Chief Financial Officer $ 488,000
5. Human Resources $ 252,000
6. Chief Executive Officer (Includes BOD Fees) $173,000
7. General Counsel $ 131,000
8. Government Affairs $ 11,000
Total $4,690,000
APPENDIX A
|
Comparison of NSP and NSP-W to Regional Gas Utilities |
||||||
|
Name of Utility |
State |
1998 Gas Sales Mmcf |
Number of Customers |
Operating Revenues |
Operating Revenues |
Operating Income |
|
NSP and NSP-W
|
MN, ND, SD, WI, MI |
85,181 |
474,763 |
$412,199 |
$4.83 |
$17,321 |
|
Reliant Energy Minnegasco |
MN |
126,400 |
668,544 |
$567,190 |
$4.49 |
NA |
|
Utilicorp United |
MN, NE, IA, CO, MO |
109,511 |
851,589 |
$622,400 |
$5.68 |
NA |
|
MidAmerican Energy Company |
IA, SD |
93,825 |
611,765 |
$536,306 |
$5.72 |
$29,473 |
|
Wisconsin Gas Company |
WI |
114,500 |
528,963 |
$428,562 |
$3.74 |
$33,854 |
|
Wisconsin Electric Power Company |
WI |
48,846 |
388,478 |
$295,848 |
$6.06 |
$19,180 |
|
Montana Dakota Utilities |
ND, SD, MT |
29,749 |
206,077 |
$154,146 |
$5.18 |
$8,028 |
|
Alliant Energy (WP&L, Interstate, IES) |
WI, IL, IA, MN, |
61,253
|
387,000 |
$295,590 |
$4.83 |
$16,027 |
|
Wisconsin Public Service Company |
WI, MI |
34,251 |
223,776 |
$165,111 |
$4.82 |
$12,500 |
Source: Pipeline and Gas Journal, November 1999; NSP Annual Report[186]
APPENDIX B
NEW GAS COMPANY OF MINNESOTA ORGANIZATION CHART
|
Board of Directors |
||||||
|
CEO |
||||||
|
||||||
|
COO |
VP Customer Support |
CFO |
CIO |
VP Human Resources |
General Counsel |
VP Gov't Affairs |
|
Operations MN |
Sales/Mktg |
Controller |
Law |
Communications |
||
|
Operations |
Comm/Econ |
Treasurer |
Corp. Secretary |
Gov't Affairs |
||
|
Procurement |
CBO |
Risk Management |
Environmental |
|||
|
Gas Supply |
Investor Relations |
|||||
|
Plant/Engineering |
Corp. Strategy |
|||||
|
Facilities |
Regulatory |
|||||
The organization chart in this Appendix shows the organization down to the functional level only. As a result, details on individual employee positions are not included.
APPENDIX C
BASE CASE - NSP
(Dollars in 000's)
|
Operating Revenue |
$ 360,567 |
|||
|
Operating Revenue Deductions |
||||
|
Operating & Maintenance Expense |
287,837 |
|||
|
Depreciation & Amortization |
21,100 |
|||
|
Taxes Other Than Income |
21,641 |
|||
|
Total Operating Revenue Deductions |
330,578 |
|||
|
Gross Operating Income |
29,989 |
|||
|
Income Taxes |
6,557 |
|||
|
Net Operating Income |
23,432 |
|||
|
Rate Base |
364,797 |
|||
|
Rate of Return on Rate Base |
6.42% |
|||
APPENDIX D
NEW GAS COMPANY OF WISCONSIN ORGANIZATION CHART
|
Board of Directors |
||||||
|
CEO |
||||||
|
||||||
|
COO |
VP Customer Support |
CFO |
CIO |
VP Human Resources |
General Counsel |
VP Gov't Affairs |
|
Operations |
Sales/Mktg |
Controller |
Law |
Communications |
||
|
Gas Supply |
Comm/Econ |
Treasurer |
Corp. Secretary |
Gov't Affairs |
||
|
Engineering/Plant |
CBO |
Risk Mgmnt |
Environmental |
|||
|
Facilities |
Investor Relations |
|||||
|
Procurement |
Corp. Strategy |
|||||
|
Regulatory |
||||||
The organization chart in this Appendix shows the organization down to the functional level only. As a result, details on individual employee positions are not included.
APPENDIX E
BASE CASE - NSP-W
(Dollars in 000's)
|
Operating Revenue |
$ 78,800 |
|||
|
Operating Revenue Deductions |
||||
|
Operating & Maintenance Expense |
66,275 |
|||
|
Depreciation & Amortization |
5,672 |
|||
|
Taxes Other Than Income |
1,563 |
|||
|
Total Operating Revenue Deductions |
73,510 |
|||
|
Gross Operating Income |
5,290 |
|||
|
Income Taxes |
1,599 |
|||
|
Net Operating Income |
3,691 |
|||
|
Rate Base |
70,682 |
|||
|
Rate of Return on Rate Base |
5.22% |
|||
___________________________
[178]NSP is presently seeking authorization to "spin down" its Black Mountain Gas ("BMG") gas distribution operation into a new wholly-owned subsidiary of NSP, also called BMG for purposes of the Study. The Minnesota Commission, North Dakota Commission and Arizona Commission have all approved the transaction. Commission approval is pending in File No. 70-09337. This Study assumes BMG is a subsidiary of NSP, and is operationally integrated with NSP as described in the NSP U-1 filing in File No. 70-09337. [178] [178] [178] [178][179]All dollar amounts contained in the study are expressed in 1998 dollars.
[180] Viking Gas Transmission Company, "Notice of Request Under Blanket Authorization," FERC Docket No. CP97-21-000 (October 17, 1996) (request for authorization to construct physical bypass of NSP gas system to serve RDO Foods in Grand Forks County, North Dakota).
[181]Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Service by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order N. 888, FERC Stats. and Regs. (Regulations Preambles, 1991-1996) ¶ 31,036 (1996); order on rehearing, Order 888-A III FERC Stats & Regs. (Regulations Preambles) ¶ 31,048 (1997); order on rehearing, Order No. 888-B, 81 FERC ¶ 61,248 (1997); order on rehearing, Order No. 888-C, 82 FERC ¶ 61,046 (1998), appeals pending in D.C. Cir. Case Nos. 97-1715.
[182]In addition, as described in File No. 70-09337, BMG would continue to be managed locally in Cave Creek, Arizona. [182] [182] [182] [182] [182][183]The Study assumes the interstate gas pipeline subsidiary of NSP -- Viking Gas Transmission Company -- remains a subsidiary of Xcel.
[184] Indeed, a significant portion of the NSP electric service area in Minnesota is served by Reliant Energy Minnegasco, a gas-only LDC subsidiary of Reliant Energy (formerly Houston Industries). Also, a significant portion of NSP's South Dakota electric service area near Sioux Falls is served by the gas utility division of Mid-American Energy, Inc.
[185]As discussed in the Application/Declaration on Form U-1 of NSP and NCE, to which this study is an exhibit, the NSP and NSP-W gas systems together constitute an "integrated public utility system" within the meaning of Section 2(a) (29) of the Public Utility Holding Company Act of 1935.
[186]
NSP operating income data includes Viking Gas
Transmission Co. operating income. Other NSP and NSP-W values reflect retail
gas operations only.
EXHIBIT J-2 PUBLIC SERVICE COMPANY OF COLORADO CHEYENNE LIGHT, FUEL AND POWER COMPANY ANALYSIS OF THE ECONOMIC IMPACT
OF A DIVESTITURE OF THE GAS OPERATIONS OF
NEW CENTURY ENERGIES, INC.
In addition, NCE and Northern States Power Company (NSP) are preparing a separate analysis where the retail natural gas operations are instead divested into a stand-alone gas holding company subject to the Act, with the retail gas operations of NSP, NSP - Wisconsin, and NCE.
January 31, 2000
TABLE OF CONTENTS
&nbs ; PAGE
|
I. |
EXECUTIVE SUMMARY |
1 |
|
II. |
CONCLUSIONS |
3 |
|
III. |
SPIN-OFF ASSUMPTIONS |
6 |
|
IV. |
GENERAL STUDY ASSUMPTIONS |
7 |
|
V. |
NEWGASCO-COLO ANALYSIS |
9 |
|
VI. |
NEWGASCO-WYO ANALYSIS |
17 |
|
VII. |
OTHER CUSTOMER IMPACTS |
23 |
|
VIII. |
BILL COMPARISON OF NEWGASCO-COLO |
|
|
25 |
||
|
IX. |
EFFECT ON REMAINING ELECTRIC COMPANIES |
26 |
APPENDICES
A. COMPARISON OF
PSCO AND CHEYENNE GAS TO
REGIONAL GAS UTILITIES
B. NEWGASCO-COLO ORGANIZATIONAL CHART
C. BASE CASE STUDY-COLO
D. NEWGASCO-WYO ORGANIZATIONAL CHART
E. BASE CASE STUDY-WYO
I. EXECUTIVE SUMMARY
New Century Services, Inc. (NCS) has undertaken this "Analysis of the Economic Impact of a Divestiture of the Gas Operations of New Century Energies, Inc." (Study) on behalf of NCE in order to quantify the economic impact on NCE shareholders and its customers of spinning off its Colorado natural gas assets and business owned by Public Service Company of Colorado (PSCo) and its Wyoming natural gas assets and business owned by Cheyenne Light, Fuel and Power Company (Cheyenne). NCE is currently a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). PSCo currently provides electric and natural gas service in a major portion of the State of Colorado. Cheyenne currently provides electric and natural gas service in and around Cheyenne, Wyoming. Both PSCo and Cheyenne are first-tier utility operating company subsidiaries of NCE.
The Study quantifies the economic impacts of operating the following two entities as independent, stand-alone companies if they were disaggregated from NCE's combined businesses:
The Colorado portion of PSCo's gas business spun-off into a new organization called, for the purpose of this Study, NewGasCo-Colo; and
Cheyenne's gas business spun-off into a new organization called, for the purpose of this Study, NewGasCo-Wyo.
The Study evaluates the increased costs or "lost economies" associated with divestiture of these businesses from two perspectives -- shareholders and customers. The effect on shareholders is the direct result of the increased costs or lost economies resulting from a spin-off or divestiture, absent regulatory rate relief to recoup these lost economies. The effect on customers assumes recovery of these lost economies through rate increases, and is divided into two parts. The potential effects on customers have first been evaluated in terms of increased revenue requirements and rates, and second in terms of the impact of other quantifiable and non-quantifiable costs.
The projected impacts on the shareholders of the lost economies resulting from the spin-off of PSCo's gas business into NewGasCo-Colo and the spin-off of Cheyenne's gas business into NewGasCo-Wyo, assuming no rate adjustments to recover the lost economies and associated incomes taxes, are shown in Table I-1.
|
TABLE I-1 ANNUAL SHAREHOLDER IMPACT OF LOST ECONOMIES |
||
|
LOST ECONOMIES AS A PERCENT OF: |
NEWGASCO-COLO |
NEWGASCO-WYO |
|
Total Gas Operating Revenue |
8.19% |
6.75% |
|
Total Gas Operating Revenue Deductions |
9.54% |
7.63% |
|
Gross Gas Income |
57.75% |
58.53% |
|
Net Gas Income |
76.19% |
76.35% |
In Table I-1, Total Gas Operating Revenue is the sum of rate and other revenue for the 12 months ending December 31, 1998 (Base Case). [1] Total Gas Operating Revenue Deductions includes all operation and maintenance expenses, administrative and general expenses, depreciation and all taxes, except income taxes. Gross Gas Income is the difference between Total Gas Operating Revenue and Total Gas Operating Revenue Deductions. Net Gas Income is Gross Gas Income minus Income Taxes.
Alternatively, and assuming that each organization is allowed to increase its rate revenue to recover these lost economies and attendant income taxes through rate increases, the projected impact on PSCo's and Cheyenne's customers is shown in Table I-2.
|
TABLE I-2 ANNUAL GAS CUSTOMER IMPACT OF LOST ECONOMIES |
||
|
RATE REVENUE |
NEWGASCO-COLO |
NEWGASCO-WYO |
|
Pre Spin-off |
$677,141,000 |
$ 20,988,000 |
|
Post Spin-off |
$ 734,879,000 |
$ 22,603,000 |
|
Increase |
$ 57,738,000 |
$ 1,615,000 |
|
Percent Increase |
8.53% |
7.69% |
In addition to the foregoing impacts, the following table sets forth the impact on the remaining electric companies (comprised of PSCo's and Cheyenne's current electric businesses). This impact is primarily due to the expense of additional employees required to perform the multitude of functions accomplished by employees who currently work for both the electric and gas businesses and assumes that rate recovery of the lost economies and attendant income taxes is allowed by the appropriate regulatory agencies.
|
TABLE I-3 ANNUAL ELECTRIC CUSTOMER IMPACT OF LOST ECONOMIES |
||
|
RATE REVENUE |
PSCO REMAINING ELECTRIC |
CHEYENNE REMAINING ELECTRIC |
|
Pre Spin-off |
$ 1,248,058,000 |
$ 43,169,000 |
|
Post Spin-off |
$ 1,332,751,000 |
$ 44,333,000 |
|
Increase |
$ 84,693,000 |
$ 1,164,000 |
|
Percent Increase |
6.79% |
2.70% |
If, on the other hand, the foregoing organizations were not spun-off from PSCo and Cheyenne, the NSP/NCE merger was implemented as proposed, and assuming a rate decrease to pass on the potential merger benefits, the impact on gas customers is shown in Table I-4.
|
TABLE I-4 ANNUAL GAS CUSTOMER IMPACT OF POTENTIAL |
||
|
RATE REVENUE |
PSCO GAS |
CHEYENNE GAS |
|
Pre Merger |
$ 677,141,000 |
$ 20,988,000 |
|
Post Merger |
662,695,000 |
20,650,000 |
|
Decrease |
14,446,000 |
338,000 |
|
Percent Decrease |
2.13% |
1.61% |
Finally, both PSCo's and Cheyenne's gas customers would incur increased personal costs, such as postage on a separate envelope, and additional check costs to mail payments to two utilities rather than one. This does not include additional customer confusion resulting from doing business with two utilities rather than one. The increased postage expense alone of $3.96 per customer per year for all customers is shown in Table 1-5.
|
TABLE I-5 OTHER ANNUAL CUSTOMER IMPACTS |
|
|
PSCO POSTAGE |
CHEYENNE POSTAGE |
|
$ 4,065,000 |
$ 113,000 |
II. CONCLUSIONS
A. Impact on Gas Operations
The spin-off of PSCo's and Cheyenne's current gas businesses into two stand-alone companies is estimated to result in a substantial increase in costs and therefore a substantial decrease in earnings to NCE's shareholders absent rate relief to recoup these increased costs. Without an increase in rates, the immediate negative effect on shareholders earnings would be substantial. For example, the earnings contribution relating to both PSCo's and Cheyenne's gas business would be decreased by approximately 76 percent as shown in Table I-1. Such a decline would make ownership of shares in these stand-alone companies unattractive.
The recovery of these cost increases through rates charged to customers in Colorado and Wyoming would result in a significant increase in the level of cost borne by these customers with no attendant increase in the level or quality of service. The rate increases required to provide the level of revenue needed to cover costs to operate the NewGasCos (NewGasCo-Colo and NewGasCo-Wyo) will be significant, amounting to approximately $ 59.3 million, as shown in Table I-2. Such rate increases would make the NewGasCos less competitive at a time when competition in the energy industry is rapidly increasing due to Federal Energy Regulatory Commission (FERC) Order No. 636 and other FERC and state regulatory initiatives such as the current trend toward retail service unbundling. A comparison of typical residential and commercial gas bills in Colorado and Cheyenne, Wyoming, illustrating the loss of each NewGasCo's relative position as compared to other utilities resulting from a spin-off, is contained in Table VIII-1, page 25.
The potential by-pass of Local Distribution Companies (LDCs) is becoming a reality that LDCs must face daily, along with the commensurate possibility of a decreasing customer base, resultant rate increases, and potential stranded costs. The FERC has sanctioned the bypass of LDC systems by interstate pipelines in recent years in the interest of competition. [2] In addition, natural gas service continues to compete with alternative fuels.
The focus on competition is beginning to require the unbundling of LDC services. This trend is occurring as state commissions, LDCs, and their customers, call for a change in the way LDCs do business. While the objectives of these groups are not always consistent, the result will likely be the same -- increased competition. LDCs already face fierce price competition, and must remain competitive to avoid shareholder losses and a reduced customer base. As a result of the increased costs discussed herein, bundled or unbundled services may become uncompetitive as the pass through of these increases could potentially result in rates that few customers would pay when compared to other competitive options they may have.
B. Impact on Electric Operations
In addition, the FERC's Order No. 888 [3]rulemaking requiring wholesale electric open access nondiscriminatory transmission services by public utilities and state retail wheeling initiatives are expected to increase competition in the electric industry. The lost economies estimated for PSCo's and Cheyenne's remaining electric companies, if divestiture of gas operations were required, would also have an adverse impact on their ability to successfully compete in the electric industry. A forced divestiture as a result of the proposed merged company would result in the remaining companies being less competitive than they would be as part of a merged company.
C. Other Impacts
As opposed to the negative results of the economic impact, two positive conclusions were noted.
First, it is expected that after divestiture, the two segments of PSCo's business analyzed in this Study would continue to be managed locally, as they currently are. PSCo's gas business would continue to be managed from and based in Denver and from the other local/regional parts of Colorado where management is currently based. Cheyenne's gas business would continue to be locally based in the City of Cheyenne, Wyoming. Therefore, the benefits and costs of localized management would continue to be realized.
Second, it is expected that after divestiture, the Colorado Public Utilities Commission (CPUC) and the Wyoming Public Service Commission (WPSC) would continue to have and exercise the same jurisdictional authority over the regulated businesses as they do today. PSCo's gas business would continue to be regulated primarily by the CPUC, and Cheyenne's gas business would continue to be regulated primarily by the WPSC. Therefore, the state commissions will continue as the primary agencies responsible for the regulation of the LDCs. [4]
However, it should be noted that these same conditions (continued local management and state regulatory jurisdiction) would exist if the gas businesses were to remain with the new merged entity, Xcel Energy Inc. ("Xcel").
D.
Divestiture Would Not Tend Toward The
Economic and Efficient Development of an
Integrated Public
Utility System
As previously discussed in the Executive Summary, there is a combination of approximately $59.3 million in annual revenue increases needed for the NewGasCos, shown in Table I-2, and an additional $85.9 million in annual revenue increases as a result of lost economies, including income taxes, that would impact the remaining PSCo and Cheyenne electric companies, and potentially their customers shown in Table I-3. Therefore, the total rate increases that would be required is approximately $145.2 million a year. This compares to potential rate decreases of $14.8 million relating to merger savings if the NCE/NSP merger is approved and Xcel is allowed to retain its gas utility operations. Thus, the total differential is more than $160.0 million.
Based on the foregoing conclusions, spinning off the gas businesses would adversely impact NCE's shareholders and both electric and gas customers through higher costs and thus higher rates, and would tend toward uneconomical and inefficient public utility systems. By contrast, allowing Xcel to retain the PSCo and Cheyenne gas assets and businesses would tend toward the economical and efficient development of an integrated public utility system.
III. SPIN-OFF ASSUMPTIONS
The Study assumes that two segments of NCE's current business can, in fact, be spun-off into stand-alone companies. These two potential stand-alone businesses are currently part of the combined companies as described below:[5]
Within Colorado, NCE's wholly owned first-tier subsidiary, PSCo, is primarily a combination electric and gas utility, engaged in the generation, purchase, transmission, distribution and sale of electricity, and in the purchase, transmission, distribution, sale and transportation of natural gas.
PSCo's Colorado gas business includes an extensive transmission and distribution system serving numerous communities throughout Colorado. PSCo's gas system serves over 1 million residential, commercial, industrial, and transportation customers. Total annual gas revenues are approximately $680 million. Annual gas deliveries are nearly 213 million dekatherms (Dth). The Study assumes that the Colorado gas portion of PSCo is spun-off into a stand-alone gas company-- NewGasCo-Colo.
PSCo's Colorado electric business, which includes generation, transmission, and distribution facilities located statewide, provides service to nearly 1.2 million customers throughout a large portion of Colorado. Total annual electric revenues are approximately $1.6 billion and annual sales are nearly 30.5 million megawatt hours (Mwh).
NCE's wholly-owned first-tier subsidiary, Cheyenne, operates a combination electric and gas utility in the City of Cheyenne, Wyoming and in a significant portion of Laramie County, Wyoming. Cheyenne is engaged in the purchase, transmission, distribution and sale of electricity, and in the purchase, distribution, sale and transportation of natural gas.
The Cheyenne gas distribution system serves over 28,500 customers. Total annual gas revenues are approximately $21 million. Annual gas deliveries are nearly 18 million Dth. The Study assumes that the gas portion of Cheyenne is spun-off into a stand-alone gas company--NewGasCo-Wyo.
The Cheyenne electric system consists of electric transmission and distribution facilities and serves over 35,400 customers. Total annual electric revenues are approximately $37.1 million and annual sales are approximately 848,000 Mwh.
The Study assumes that it would be possible to spin-off NCE's Colorado gas business and its Cheyenne gas business from their respective combined gas and electric businesses for the following reasons:
The electric and gas systems are physically separate;
A large number of personnel who are directly involved in the day-to-day operations of the electric and gas physical plant ("systems") are dedicated electric-only or gas-only;
The regulatory treatment of the respective electric and gas revenue requirements and tariff filings is, for the most part, handled separately; and,
In other parts of the country, stand-alone electric and gas companies routinely share overlapping service territories.
In addition, the Study analyzes the NewGasCo-Colo and NewGasCo-Wyo organizations as two stand-alone companies rather than one combined-gas company for the following reasons:
Cheyenne is a wholly-owned first-tier subsidiary of NCE with separate management and its own Board of Directors;
PSCo's Colorado gas business and Cheyenne's gas business are currently regulated by different state commissions. PSCo's is regulated by the CPUC, while Cheyenne's is regulated by the WPSC;[6]
The PSCo and Cheyenne gas systems can be operated independently;[7] and,
A significant number of personnel who oversee and maintain the operation of the two systems are employees of PSCo-only or Cheyenne-only.
IV. GENERAL STUDY ASSUMPTIONS
The assumptions, information and data utilized in the analyses undertaken in this Study are based on the energy industry expertise and experience possessed by the management and staff of NCS, PSCo and Cheyenne. Employees with experience in all major facets of the gas operations of PSCo and Cheyenne were consulted and provided input. The Study's aggregate conclusions are the result of many independent inputs and analyses from highly qualified individuals throughout the companies. Further, the Base Cases for the Study are founded upon sales, revenues, costs, and rates of return from rate of return studies recently filed with the CPUC and WPSC.
NCS did not conduct an exhaustive analysis of every cost component that may be associated with a divestiture. As a result of discussions with numerous personnel at PSCo and Cheyenne, the major cost components associated with a divestiture were identified, quantified, and included in the Study results. Thus, the Study results are likely to be at the low end of the actual divestiture costs.
The remainder of this section discusses the major assumptions that were employed in developing the Study.
V. NEWGASCO-COLO ANALYSIS
A detailed study was undertaken to analyze the potential impact on both the shareholders and customers of NCE if it were ordered to divest its Colorado gas business. In order to accomplish that study, the management of NCS and PSCo provided estimates of the staffing levels of a NewGasCo-Colo, as well as any other operational and administrative changes that would have to be made in order to maintain the same level and quality of service to its gas customers after a spin-off of the gas business.
A. Specific Assumptions
In addition to the General Study Assumptions cited earlier, the following specific assumptions have been incorporated into the analysis of the spin-off of the gas operations of PSCo into a NewGasCo-Colo.
1. Labor Assumptions
a. The PSCo organization as of September 30, 1995, was used as the template for developing the NewGasCo-Colo organization structure. Appropriate labor cost and other adjustments have been made to this structure to update the study to December, 1998 levels.
b. Where practical, some management positions were combined, eliminated or replaced with non-management positions. Some further consolidation of management positions may be possible, particularly within the staff organizations. However, the overall span of control (the ratio of non-management employees to management employees) for NewGasCo-Colo is smaller than the span of control in the PSCo organization. As of December 1, 1998, PSCo had 223 management and 2,706 non-management employees, yielding a span of control of 12.1 employees per manager. NewGasCo-Colo has 185 management and 1,784 non-management employees, resulting in a span of control of 9.6 (i.e., more managers per non-management employee than the organization). This smaller span of control is due to the following:
1) A duplicate executive organization due to the need of having a separate set of executives for the new organization;
2) Management employees required in the geographic areas, but with a lower non-management employee count due to the elimination of electric responsibilities; and,
3) The number of management personnel required in the staff organizations possessing technical expertise and background with some decrease in non-management staff size due to the elimination of support for electric functions.
c. To provide an equivalent quality of customer service, an analysis was made of the NCS organization to determine the number of employees required for the customer service area of NewGasCo-Colo. The staffing percentages required in the NewGasCo-Colo compared to the current combined company for the following functional areas of the NCS organization are as follows:
Credit
100 percent
Personal Account Representatives
100 percent
Billing
100 percent
Remittance
100 percent
Collection
75 percent
Call Center
86 percent
A 100 percent factor, for example, would result in a doubling of the number of existing employees, as the electric business would also require the same number of employees as the spun-off gas organization to accomplish the same function. These functions are accomplished by a relatively small number of NCS personnel and a spin-off of gas responsibilities would not materially affect the number of employees required to accomplish electric-only functions.
d. In order to determine the number of meter readers, the original NewGasCo-Colo organizational structure were adjusted to account for the reduction in the number of meter readers needed due to the introduction of Automatic Meter Reading since the previous study was completed.
e. Executive salaries were based on national survey data.[8]
f. All non-executive salaries are based on current NCS and PSCo average compensation for the appropriate job level.
g. Pensions and benefits are estimated as a percent of the labor cost. Currently, pension and benefits average an additional cost of approximately 37.6 percent above the base cost of labor. Therefore, after the base cost of labor was determined, an additional 37.6 percent was added to include pension and benefit costs.
h. The cost of overtime varies depending upon the time of year, work load, and job classifications. The overtime cost assumptions utilized are comparable with the percent of overtime cost currently experienced by NCS and PSCo. [9]
2. Operation and Maintenance and Administrative and General Assumptions:
a. Annual facility costs relating to the additional employees required to operate the stand-alone companies have been incorporated into the Study.
b. Separate arrangements will be made for external auditing of the books and accounts of NewGasCo-Colo.
c. Executive and administrative support from NCS and PSCo would cease upon any divestiture, and these functions have been provided for in the NewGasCo-Colo organizational structure.
d. Separate gas bills will be provided the customers of NewGasCo-Colo.
3. Capital Expenditure and Cost Assumptions
a. With the exception of a new Call Center which would need to be constructed in order to handle customer orders and bill inquiries, estimated at $22.3 million, no additional capital expenditures will be made by NewGasCo-Colo as a direct consequence of spinning off the gas facilities from NCE. This, of course, does not include planned capital expenditures to be made in the normal course of business in order to maintain existing levels of service and provide service to new customers.
b. In the event NCE were required to divest its PSCo gas operations, and assuming the assets were spun-off into a new stand-alone corporation, the requirements of the existing indentures would result in the need to recapitalize at market rates in effect at the time of the spin-off. Additionally, costs associated with the issuance of securities would be incurred and ultimately included in the NewGasCo-Colo cost of service.
The current capital structure of NCE is used for the purpose of analyzing capital costs for NewGasCo-Colo. This structure is approximately equal to the capital structure approved by the CPUC in PSCo's most recent rate proceeding, Docket No. 98S-518G. As of December 31, 1998, PSCo's gas rate base was capitalized as follows:
Ratio Cost Composite Cost
Long Term Debt
48.36% 7.47%
3.61%
Common Equity
51.64% 11.25%
5.81%
Total:
100.00%
9.42%
This Study assumes that NewGasCo-Colo would have access to capital at a cost similar to that of NCE. The difference expected from the rates listed above would result from an increased equity ratio. [10] The Study assumes that gas utilities have an equity ratio about 300 basis points higher than a combination electric and gas utility due to the higher risk inherent in the gas business. Historically, rating agencies have expected a slightly higher equity component in the capital structure for natural gas utilities in recognition of their greater weather and sales risk.
The existing debt financing supporting PSCo's assets is primarily thirty-year utility bonds rated BBB+ at an average imbedded rate of 7.47 percent. The cost of debt has not been changed because the marginal cost of debt for a BBB plus company was assumed to be about the same as the embedded rate listed above. An additional cost of $250,000 would be incurred in executing a new indenture.
The cost of common equity is 11.25 percent which was established by the CPUC on May 20, 1999 in PSCo's most recent rate proceeding, Docket No. 98S-518G. A divestiture of the gas business and formation of a new corporation, would not require new certificates, except for those shareholders who request them. In that event, the certificates would be issued to those shareholders at cost.
4. Transition Cost Assumptions --Transition costs, such as the renegotiation of gas-only franchises with the numerous cities and towns in which PSCo provides service, as well as upfront costs related to the creation of new indenture agreements, would be incurred and amortized over the appropriate life of the asset.[11]
B. Organization of NewGasCo-Colo
The functional organization charts of NewGasCo-Colo are contained in Appendix B.
Design of NewGasCo-Colo Organization--The PSCo organization at September 30, 1995, was used as the pattern for developing the NewGasCo-Colo organizational structure. In order to develop the new structure for the stand-alone company, management personnel were contacted for input regarding staffing levels.
Board of Directors --The Board of Directors is assumed to consist of nine directors based on the size and scope of NewGasCo-Colo.
Chief Executive Officer(CEO) -- The CEO reports to the Board of Directors and is responsible for overseeing the entire Company. The CEO oversees three direct-report executives (Chief Operating Officer; Chief Financial Officer; and General Counsel) and is responsible for Corporate Communications and Audit Services. The Executive Organization totals 23 employees, and is composed of 8 executives, 2 managers, and 13 non-management personnel.
Chief Operating Officer (COO)--The COO reports directly to the CEO and is responsible for the overall operating activities of the Company. The COO oversees the work of three executives (Marketing Planning and Supply; Engineering and Technical Support; and Operations and Customer Service), and in addition directs the Managers of Business Processes and Information Technology and a secretary. The organization managed by the COO totals 1,767 employees, and is composed of 146 managers, and 1,621 non-management personnel.
Vice President, Marketing, Planning and Supply--The Vice President (VP) of Marketing, Planning and Supply is responsible for residential marketing, wholesale marketing, sales to large commercial and industrial customers, market research, measurement, program development and evaluation, business support, the natural gas vehicle program, acquiring interstate gas transportation, forecasting gas requirements, making sales gas purchases, and gas system control coordination. Marketing, Planning and Supply totals 129 employees, composed of 16 management and 113 non-management personnel.
Vice President, Engineering and Technical Support--The VP of Engineering and Technical Support is responsible for all major engineering functions such as system design (pipelines, storage reservoirs, and compressors), safety, environmental training, purchasing, contracts, material management, transportation, and facilities maintenance. Engineering and Technical Support totals 252 employees, composed of 27 management and 225 non-management personnel.
Vice President, Operations and Customer Service--The VP of Operations and Customer Service is responsible for the day-to-day interface with customers, customer accounts, regional management, pipeline construction, distribution system support services, meter reading, credit and billing, and customer information service. Operations and Customer Service is the largest department, totaling 1,363 employees, composed of 99 management and 1,264 non-management personnel.
Manager, Business Processes--The Manager of Business Processes is responsible for reviewing and recommending improvements to on-going business practices and procedures. Business Processes totals four employees and is composed of one management and three non-management personnel.
Manager, Information Technology--The Manager of Information Technology is responsible for asset management, technology management, and business planning. Information Technology totals 18 employees, and is composed of three management and 15 non-management personnel. The day-to-day operations, maintenance, software development, and equipment refresh functions will continue to be under contract with a third-party information technology provider.
Chief Financial Officer (CFO)--The CFO reports directly to the CEO and is responsible for rate, regulatory, finance, treasury, and accounting functions. The CFO oversees the work of four managers (Rates and Regulation; Investor Relations; Treasury; and the Controller/Corporate Secretary). The organization managed by the CFO totals 113 employees, and is composed of 18 management and 95 non-management personnel.
General Counsel--The General Counsel reports directly to the CEO and oversees the Associate Legal Counsel, the Governmental Affairs Group, and the Unit Manager of Risk Management. The General Counsel is responsible for governmental affairs, legal services, and liability risk management, and, through the VP of Human Resources, oversees company staffing, compensation, training, benefits, health services, and employee relations. The organization managed by the General Counsel totals 66 employees, and is composed of 11 management and 55 non-management personnel.
C. Annual Cost Increases
Based upon the foregoing general and specific assumptions, and the staffing requirements of the organizational structure, the following increased annual costs have been developed for NewGasCo-Colo:
1. Labor Costs
$ 30,198,000
2. Pension and Benefits
14,067,000
3. Facility Costs
2,633,000
4. Postage Expense
2,000,000
5. Board of Director's Fees
216,000
6. Reporting Costs
199,000
7. Payroll Taxes
1,861,000
8. Call Center Depreciation
491,000
9. Capitalized Labor Depreciation
126,000
Total:
$ 51,791,000
D. Capital Cost Increases
Using the allowed cost of equity as discussed earlier, and recasting the cost of capitalizing the gas assets using NCE's existing capital structure as a proxy for NewGasCo-Colo results in the following:
Ratio Cost Composite Cost
Long Term Debt 45.36% 7.47% 3.39%
Common Equity 54.64% 11. 25% 6.15%
Total: 100.00% 9.54%
The actual interest rates in effect at the time of divestiture could be substantially higher or lower than the forecasts employed here.[12]
Applying the foregoing capital cost to NewGasCo-Colo results in the following increased annual capital costs:
1. Increased Borrowing Cost
$ 934,000
2. Capital Expenditure
2,077,000
3. Capitalized Labor
747,000
4. Capitalized Transition
205,000
Total:
$ 3,963,000
E. Transition Cost Increases
The following is a summary of the principal transition costs that will be incurred as a result of a spin-off of the gas business of PSCo and their annual costs:
Annual
Asset Cost Increase
1. Renegotiation of Franchises
$ 2,001,000 $ 100,000
2. New Indenture
250,000
8,000
Total:
$ 2,251,000 $ 108,000
F. Total Lost Economies
Summarizing the foregoing increased annual costs, capital costs, and amortized transition costs, which were developed in the Base Case Study yields the following total lost economies before the effect of income taxes:
Total Lost Economies: $ 55,862,000
G. Income Taxes
Recovery of the foregoing lost economies in a general rate proceeding would also require an increase to recover income taxes associated with the lost economies. The following is a summary of the revenue effect of income taxes:
Total Income Taxes: $ 1,876,000
H. Foregone Merger Savings
The following is a summary of the annual foregone merger savings lost if the spin-off occurs:
Total: $ 14,446,000
I. Base Case - 12 Months Ended December 31, 1998
The following is a summary of the key components of the Base Case (the definition of each item is the same as in the Executive Summary):
1. Total Gas Operating Revenue
$ 682,289,000
2. Total
Gas Operating Revenue Deductions
$ 585,557,000
3. Gross
Gas Income
$ 96,732,000
4. Net Gas
Income
$ 73,321,000
J. Comparison of the Total Lost Economies of NewGasCo-Colo to the Base Case
The Total Lost Economies, before the effect of income taxes, as a percent of the key components of the Base Case are:
1. Percent of Total Gas Operating Revenue
8.19%
2. Percent of
Total Gas Operating Revenue Deductions
9.54%
3. Percent
of Gross Gas Income
57.75%
4. Percent of
Net Gas Income
76.19%
K. Comparison of Rates of Return on Rate Base
The following is a comparison of the rates of return on rate base for the gas operations before and after an assumed spin-off:
1. Pro Forma Rate of Return - Existing
7.09%
2. Pro Forma Rate of Return - Base Case
9.42%
3. Pro Forma Rate of Return after Spin-off
5.10%
4. Required Rate of Return based on NewGasCo-Colo
Cost of Capital
9.54%
VI. NEWGASCO-WYO ANALYSIS
As was the case with PSCo, a detailed study was undertaken to analyze the potential impact on both the shareholders of NCE and the customers of Cheyenne if it were ordered to divest the gas business.
In order to accomplish that study, the management of NCS and Cheyenne provided estimates of the staffing levels of a NewGasCo-Wyo, as well as any other operational and administrative changes that would have to be made in order to maintain the same level and quality of service to its gas customers after a spin-off of the gas properties.
A. Specific Assumptions
In addition to the General Study Assumptions cited earlier, the following specific assumptions have been incorporated into the analysis of the spin-off of the gas operations of Cheyenne into a NewGasCo-Wyo.
1. Labor Assumptions:
a. As was the case with NewGasCo-Colo, the Cheyenne organization at September 30, 1995, was used as the template for developing the NewGasCo-Wyo organization structure.
b. In order to maintain the same quality of service after the divestiture as before, a detailed analysis of the staffing requirements for NewGasCo-Wyo was made by Cheyenne management and NCS Human Resources personnel. The following is a summary of their analysis of the staffing requirements for NewGasCo-Wyo:
A total of 57 employees would be required to operate NewGasCo-Wyo. Thirty-two employees of Cheyenne would be transferred to the new organization. The employees transferred include one manager and 31 non-management employees. An additional 25 employees would have to be hired in order for NewGasCo-Wyo to provide the same level of service as before the divestiture. These additional employees would include: one President, two managers and 22 non-management employees.
c. Executive salaries are based on national survey data. Since the size of the organization is smaller than NewGasCo-Colo, the executive salaries are less for NewGasCo-Wyo.[13]
d. All non-executive salaries are based on current NCS and Cheyenne average compensation for the appropriate job level.
e. After the base cost of labor was determined, an additional 37.6 percent was added to determine pension and benefit costs. This percent is based on PSCo's approximate current percentage in order to keep benefits similar for NewGasCo-Wyo.
f. The cost of overtime varies depending upon the time of year, work load, and job classifications. The overtime cost assumptions utilized are comparable with the percent of overtime cost currently experienced for PSCo.[14]
2. Operation & Maintenance and Administrative and General Assumptions:
a. In addition to the General Study Assumptions cited earlier, it is assumed that certain minor administrative functions now performed by employees of NCS and PSCo and billed to Cheyenne will be contracted out on an as-needed basis; and further, it is assumed that the cost to NewGasCo-Wyo would be substantially the same after a divestiture as before. For example, the short- and long-term financing for Cheyenne is currently being accomplished by employees of the Long-term Finance Department of NCS, and if divestiture of Cheyenne's gas operations were ordered, and such financing were required, arrangements would have to be made with another organization possessing the same or similar financial expertise.
b. Annual facility costs relating to the additional employees required to operate NewGasCo-Wyo have been incorporated into the Study.
c. Separate arrangements will be made for external auditing of the books and accounts of NewGasCo-Wyo.
d. In like manner, legal assistance, billing and record-keeping assistance would be contracted out, and it is assumed that NewGasCo-Wyo would be able to acquire these services for substantially the same fees as it is currently paying NCS.
e. Operations support provided by NCS and PSCo, such as controlling the operation of the gas distribution system, would have to be transferred to NewGasCo-Wyo. However, it is assumed that this support could be accomplished for the same cost as currently incurred by NewGasCo-Wyo.
f. Executive and administrative support from NCE and NCS would cease upon any divestiture, and these functions have been provided for in the NewGasCo-Wyo organizational structure.
g. Separate gas bills will be provided the customers of NewGasCo-Wyo.
3. Capital Expenditure and Cost Assumptions
a. No additional capital expenditures will be made by NewGasCo-Wyo. as a direct consequence of spinning off the gas facilities from Cheyenne. This, of course, does not include planned capital expenditures to be made in the normal course of business in order to maintain existing levels of service and provide service to new customers.
b. Financing costs for Cheyenne would similarly be affected by a required spin-off of their gas operations as was PSCo. The current capital structure of Cheyenne is used for the purpose of analyzing capital costs for NewGasCo-Wyo. This structure is approximately equal to the capital structure approved by the WPSC in the most recent rate proceeding, Docket No. 30005-GR-97-51. As of December 31, 1998 Cheyenne's gas rate base was capitalized as follows:
Ratio Cost Composite Cost
Long Term Debt
56.85% 5.47%
3.11%
Common Equity
43.15% 11.71%
5.05%
Total:
100.00%
8.16%
Recapitalizing NewGasCo-Wyo would involve issuing new long-term debt at marginal rates. Cheyenne debt is currently rated BBB. The Study assumes the marginal rate for debt for NewGasCo-Wyo is the same as the current imbedded rate for PSCo, namely 7.47%. This is a very conservative estimate, since NewGasCo-Wyo has a much lower common equity ratio in its capital structure which would likely lower its bond rating below BBB. The capital structure ratio has also been adjusted by shifting 300 basis point from long term debt to common equity in order to recognize the increased risk in a stand alone gas company.
The cost of common equity is 11.71 percent which was established by the WPSC in Cheyenne's most recent gas rate proceeding, Docket No. 30005-GR-97-51. Common equity would not require the sale of new securities; however, new stock certificates would be issued to current shareholders of NCE. As in the case of PSCo, a new indenture would be required at an estimated cost of $250,000. This cost would be included in transition costs to be recovered over 30 years.
4. Transition Cost Assumptions--Transition costs, such as the renegotiation of gas-only franchises with the City of Cheyenne, and the Towns of Burns and Pine Bluffs would be amortized over the appropriate life of the asset. [15]
B. Organization of NewGasCo-Wyo
The functional organization chart of NewGasCo-Wyo is contained in Appendix D. The new structure is composed of a seven-member Board of Directors, a President, and four managers. The organization managed by the President totals 56 employees and is composed of four managers and 52 non-management personnel.
The Manager of Operations will have the day-to-day responsibility for all new gas construction, including the installation of mains and services to new customers, as well as the installation of the meters and associated equipment for such service. In addition, this manager will have the responsibility for maintaining all gas facilities as well as inspecting the facilities on a routine basis. Operations totals 25 employees, composed of one manager and 24 non-management employees.
The Manager of Operations Support will be in charge of the engineering and mapping functions, in addition to the purchasing and storing of the various equipment, materials, and supplies required for the operation of NewGasCo-Wyo. This manager will also supervise the trouble dispatch team and be responsible for the maintenance of NewGasCo-Wyo's vehicles. Operations Support totals 14 employees, composed of one manager and 13 non-management employees.
The Manager of Customer Service will be responsible for marketing, meter reading, billing, and collection functions, in addition to the acquisition of natural gas, and the accounting and reporting required by the various state and federal agencies. Clerical support will also be this manager's responsibility. Customer Service includes 12 employees in addition to the manager.
The Manager of Rates and Regulations will be responsible for all regulatory activities, including the development and filing of periodic rate cases with the WPSC and all regulatory reporting requirements. This department will have three employees in addition to the manager.
C. Annual Cost Increases
Based upon the foregoing general and specific assumptions, and the staffing requirements of the organizational structure, the following increased annual costs have been developed for NewGasCo-Wyo:
1. Labor Costs
$423,000
2. Pension and Benefits
242,000
3. Facility Costs
134,000
4. Auditing Costs - External Auditor
10,000
5. Postage Expense
44,000
6. Board of Director's Fees
84,000
7. Reporting Costs
99,000
8. Payroll Taxes
26,000
9. Capitalized Labor Depreciation
6,000
Total:
$ 1,068,000
D. Capital Cost Increases
Using allowed cost of equity, as discussed earlier, and increased debt costs for NewGasCo-Wyo discussed earlier, the resulting weighted composite cost of capital for the stand-alone gas company would be:
Ratio Cost Composite Cost
Long Term Debt 53.85% 7.47% 4.02%
Common Equity 46.15% 11.71% 5.40%
Total: 100.00% 9.42%
Applying the foregoing capital cost to NewGasCo-Wyo results in the following increased capital costs: [16]
1. Increased Borrowing Cost
$ 287,000
2. Capitalized Labor
23,000
3. Capitalized Transition
28,000
Total:
$ 338,000
E. Transition Cost Increases
The following is a summary of the principal transition costs that will be incurred as a result of a spin-off of the gas business of Cheyenne and their annual costs:
&nbs
;
Annual
Asset
Cost Increase
1. Renegotiation of Franchises $ 60,000
$ 3,000
2. New Indenture
250,000
8,000
Total:
$ 310,000
$ 11,000
F. Total Lost Economies
Summarizing the foregoing increased annual costs, capital costs, and amortized transition costs, as developed in the Base Case Study, yields the following total lost economies before the effect of income and franchise taxes:
Total Lost Economies: $ 1,417,000
G. Income and Franchise Taxes
Recovery of the foregoing lost economies in a general rate proceeding would also require an increase to recover income and franchise taxes associated with the lost economies. The following is a summary of the revenue effect of income and franchise taxes:
Total Income and Franchise Taxes: $ 198,000
H. Foregone Merger Savings
The following is a summary of the annual foregone merger savings lost if the spin-off occurs
Total: $ 338,000
I. Base Case - 12 Months Ended December 31, 1998
The following is a summary of the key components of the Base Case (the definition of each item is the same as in the Executive Summary):
1. Total Gas Operating Revenue
$ 20,995,000
2. Total Gas Operating Revenue Deductions
$ 18,574,000
3. Gross Gas Income
$ 2,421,000
4. Net Gas Income
$ 1,856,000
J. Comparison of the Lost Economies of NewGasCo-Wyo to the Base Case
The Total Lost Economies, before the effect of income and franchise taxes, as a percent of the key components of the Base Case are:
1. Percent of Total Gas Operating Revenue
6.75%
2. Percent of Total Gas Operating Revenue Deductions
7.63%
3. Percent of Gross Gas Income
58.53%
4. Percent of Net Gas Income
76.35%
K. Comparison of Rates of Return on Rate Base
The following is a comparison of the rates of return on rate base for the gas operations before and after an assumed spin-off:
1. Pro Forma Rate of Return - Existing 4.73%
2. Pro Forma Rate of Return - Base Case 8.16%
3. Pro Forma Rate of Return after spin-off 4.96%
4. Required Rate of Return based on NewGasCo-Wyo
Cost of Capital 9.42%
VII. OTHER CUSTOMER IMPACTS
A. Quantifiable Postage Costs
Customers who currently pay their monthly bill with one check and one stamp will be required to use two separate checks and two separate stamps in paying the remaining electric company and the NewGasCo. For the gas and electric customers of the existing PSCo and Cheyenne companies, the doubling of postage cost alone, not counting check and envelope costs, will result in a total annual out-of-pocket cost increase to customers of over $4.1 million annually. These annual postage costs are broken down as follows:
&nbs ; Postage Costs
NewGasCo-Colo Customers
$ 4,065,000
NewGasCo-Wyo Customers
$ 113,000
Total:
$ 4,178,000
B. Non-quantifiable
In addition to the quantifiable increased costs or lost economies which have been evaluated and included in the Study, there are other non-quantifiable costs which have not been included. The reason for not attempting to quantify these costs is that a meaningful estimate of these costs is beyond the scope of the present analysis. However these costs do exist, and the following are a few examples of these non-quantifiable costs.
The cost of additional regulation for both the CPUC and WPSC. The staffs of these agencies would undoubtedly experience additional duties and responsibilities as a result of dealing with an additional utility.
The cost to customers as a result of doing business with two utilities instead of one, including additional telephone calls for service questions or bill inquiries.
The cost to customers of providing access to meters and other facilities for two utilities.
rather than one, for installation or maintenance of electric and gas service facilities.
VIII. MONTHLY BILL COMPARISON OF
NEWGASCO-COLO AND
NEWGASCO-WYO
TO OTHER UTILITIES
The following is a comparison of average monthly bills for various utilities with which PSCo and Cheyenne compete. The average bills are based on American Gas Association's Bill Comparison Report for the quarter ending March 31, 1998.
|
TABLE VIII-1 BILL COMPARISON OF NEWGASCO-COLO |
|||
|
AVERAGE |
|||
|
NAME OF UTILITY |
RESIDENTIAL |
COMMERCIAL |
|
|
CHEYENNE (WY) |
$42.43 |
$183.00 |
|
|
NEWGASCO-WYO |
$45.69 |
$197.07 |
|
|
CITY OF COLORADO SPRINGS (CO) |
$46.10 |
$219.00 |
|
|
PNM GAS SERVICES (NM) |
$46.34 |
$196.00 |
|
|
MONTANA-DAKOTA UTILITIES (WY) |
$49.87 |
$220.00 |
|
|
CITIZENS UTILITIES (CO) |
$50.96 |
$233.00 |
|
|
GREELEY GAS COMPANY (CO) |
$51.78 |
$232.00 |
|
|
PSCO (CO) |
$51.78 |
$235.00 |
|
|
NEWGASCO-COLO |
$56.20 |
$255.05 |
|
|
UTILICORP (CO) |
$58.00 |
$273.00 |
|
|
QUESTAR (WY) |
$61.31 |
$266.00 |
|
IX. EFFECT ON REMAINING ELECTRIC COMPANIES
A. PSCO
As a result of any divestiture, the remaining NewElectricCo-Colo would experience increased costs in addition to those experienced by NewGasCo-Colo. These increased costs, as outlined earlier, are largely the result of increased labor costs associated with the additional personnel required to replace those who currently work in both gas and electric operations. Additional postage costs would also be incurred since electric billings would no longer share postage with the gas billings. The total of these additional costs is $84.7 million, which equates to approximately 6.7 percent of electric rate revenues.
A summary of the increased annual costs, capital costs, and amortized transition costs applicable to NewElectricCo-Colo is as follows:
1. Labor Costs
$ 49,447,000
2. Pensions and Benefits
22,698,000
3. Facility Costs
2,633,000
4. Postage Expense
2,000,000
5. Reporting Costs
199,000
6. Payroll Taxes
3,055,000
7. Capitalized Labor Depreciation
326,000
8. Increased Borrowing Cost
3,138,000
9. Capitalized Labor
1,197.000
Total:
$ 84,693,000
B. Cheyenne
Similarly, the remaining NewElectricCo-Wyo would experience additional costs due to labor and postage. The additional labor is due to replacing those personnel who currently work in both gas and electric operations. The total of these additional costs is $1.2 million, which is approximately 2.7 percent of electric rate revenues.
A summary of the increased annual costs, capital costs, and amortized transition costs applicable to NewElectricCo-Wyo is as follows:
1. Labor Costs
$ 352,000
2. Pensions and Benefits
200,000
3. Facility Costs
16,000
4. Postage Expense
44,000
5. Payroll Taxes
21,000
6. Capitalized Labor Depreciation
5,000
7. Increased Borrowing Cost
494,000
8. Capitalized Labor
32,000
Total:
$ 1,164,000
APPENDIX A
COMPARISON OF
PSCO AND CHEYENNE GAS TO REGIONAL GAS UTILITIES
|
1998 FINANCIAL |
||||||
|
NAME OF UTILITY |
|
NUMBER OF CUSTOMERS |
|
|
|
|
|
Public Service |
CO |
1,026,418 |
124,397 |
$640,064 |
$5.15 |
$57,047 |
|
Mountain Fuel |
UT, WY |
663,392 |
90,400 |
$476,823 |
$5.27 |
$44,456 |
|
Public Service Co. of |
NM |
418,973 |
51,756 |
$255,975 |
$4.95 |
$19,695 |
|
|
KS, NE, CO, WY |
224,677 |
47,873 |
$207,915 |
$4.34 |
$13,851 |
|
Montana-Dakota |
MT, ND, SD |
206,077 |
29,749 |
$154,146 |
$5.18 |
$8,028 |
|
Montana Power |
MT |
147,994 |
19,664 |
$107,779 |
$5.48 |
$15,019 |
|
Cheyenne Light, Fuel and Power Company |
WY |
28,092 |
5,328 |
$14,853 |
$2.79 |
$1,214 |
Source: Pipeline & Gas Journal, November 1999
APPENDIX B
NEWGASCO-COLO ORGANIZATIONAL CHART
The organizational charts in this appendix show the organization down to the functional level only. As a result, details on individual employee positions are not included.
|
|
|||||
|
Chief Executive Officer
|
|||||
|
- Business Processes |
Chief Financial Officer
- Manager, Rates & Regulation - Controller & - Corporate Secretary - Unit Manager, Investor Relations - Manager, Treasury |
General Counsel
- Assoc. Legal Counsel - Governmental - Affairs - Unit Manager, Risk Management - Vice President, Human Resources |
|||
|
Gas Marketing, Planning & Supply - Manager, Marketing & Sales - Manager, Business Support - Manager, Gas Planning & Supply - Unit Manager, Program Development |
Engineering & Technical Support - Manager, Engineering - Manager, Safety, Environment & Training - Manager, Purchasing & Contracts - Manager, ROW & Administration - Manager, Transportation - Manager, Material Management - Manager, Facilities & Real Estate |
Operations & Customer Service - Manager, Distribution Support Services - Manager, Support Services - Manager, Denver Metro Region - Manager, West Region - Manager, East Region - Manager, North Region - Manager, Customer Accounts |
Information Technology |
||
|
VP Marketing, - Executive Assistant - Secretary
|
|||
|
Manager, - Com & Res Sales - Industrial Sales - Wholesale Marketing - Technical Customer Support |
Manager, - Prog. Evaluation - Billing & Measurement - Market Research |
Manager, - Gas Control & Transportation - Gas Supply & Planning |
Unit Manager, - Program Development - Program Management |
|
VP - Executive Assistant - Secretary |
||||||
|
Manager, - Metro Engineering - Measurement & Control Engineering - Corrosion Prevention - Reservoir Engineering - Standards & Technology - Pipeline Engineering - Process Engineering & Design |
Manager, - Technical Training - Security - Public Safety - Safety Compliance - Emergency Planning - Environmental Services
|
Manager, - Purchasing - Contracts |
Manager, - Land Use - Right of Way - Administrative Services |
Manager, - Fleet Services - Compliance - Vehicle Maintenance - New Unit Modifications |
Manager, - Stores - Material Accounting - Dispatch |
Manager - Real Estate - Facilities & Real Estate Planning - Facilities Business Services - Facilities Operations Services |
|
Operations & Customer Service - Executive Assistant - Secretary |
||||||
|
Manager, - Emergency Response & Special Services - Facilities Location - Dispatch - Meter Shop - Operations Support |
Manager, - Administrative Services - Planning & Budget - Facility Inf. Sys. & Mapping - Data Analysis & Maintenance |
Manager, |
Manager, |
Manager, |
Manager, |
Manager, - Remittance Processing - Mailing & Order Entry - Customer Support Meter Reading - Personal Accounts - Service Investigation - Field Collection - Phone Collection - Final Accounts - Billing - Customer Information/ Phone Center - Order Readers |
|
New Construction Operations & Maintenance |
||||||
|
- Executive Assistant - Secretary |
|||
|
Manager, - Rates & Regulations Policy - Rate Administration - Revenue Requirements |
Controller & - Internal Accounting - Accounting Info Sys. - Tax Services - Corporate Accounting - Accounts Payable - Records Retention |
Unit Manager, |
Manager, - Trust Asset Management - Capital & Cash Management - Corporate Planning & Financial Analysis |
|
|
|||
|
- Executive Legal Secretary |
|||
|
Assoc. Legal Counsel |
Government Affairs |
Unit Manager, - Fire Prev/Loss Control - Claims Investigation |
Vice President, - Staffing & Development - Employee Relations - Compensation, Benefits & Health Services |
APPENDIX C
BASE CASE STUDY-COLO
|
Line No. |
Item |
Amount |
|
1 |
Operating Revenues: |
|
|
2 |
||
|
3 |
Rate Revenue |
677,141,000 |
|
4 |
Other Gas Revenue |
5,148,000 |
|
5 |
||
|
6 |
Total Operating Revenue |
682,289,000 |
|
7 |
||
|
8 |
Operating Revenue Deductions: |
|
|
9 |
||
|
10 |
Operation & Maintenance Expense |
524,108,000 |
|
11 |
Depreciation & Amortization Expense |
41,116,000 |
|
12 |
Taxes Other than Income |
20,333,000 |
|
13 |
||
|
14 |
Total Operating Revenue Deductions |
585,557,000 |
|
15 |
||
|
16 |
Gross Gas Income |
96,732,000 |
|
17 |
||
|
18 |
Income Taxes |
23,411,000 |
|
19 |
||
|
20 |
Net Gas Income |
73,321,000 |
|
21 |
||
|
22 |
Rate Base |
778,361,000 |
|
23 |
||
|
24 |
Rate of Return on Rate Base |
9.42% |
APPENDIX D
NEWGASCO-WYO ORGANIZATIONAL CHART
The organizational chart in this appendix shows the organization down to the functional level only. As a result, details on individual employee positions are not included.
|
Board of Directors 7 |
|||
|
President |
|||
|
Manager - Construction & Maintenance |
Manager - Engineering - Mapping - Purchasing - Trouble Dispatch - Stores - Vehicle Maintenance |
Manager - Accounting - Customer Service - Collections - Meter Reading - Billing - Gas Purchasing - Clerical Support |
Manager - Rates & Regulations Policy - Rate Administration - Revenue Requirements |
APPENDIX E
BASE CASE STUDY-WYO
|
Line No. |
Item |
Amount |
|
1 |
Operating Revenues: |
|
|
2 |
||
|
3 |
Rate Revenue |
20,988,000 |
|
4 |
Other Gas Revenue |
7,000 |
|
5 |
||
|
6 |
Total Operating Revenue |
20,995,000 |
|
7 |
||
|
8 |
Operating Revenue Deductions: |
|
|
9 |
||
|
10 |
Operation & Maintenance Expense |
17,088,000 |
|
11 |
Depreciation & Amortization Expense |
921,000 |
|
12 |
Taxes Other than Income |
565,000 |
|
13 |
||
|
14 |
Total Operating Revenue Deductions |
18,574,000 |
|
15 |
||
|
16 |
Gross Gas Income |
2,421,000 |
|
17 |
||
|
18 |
Income Taxes |
565,000 |
|
19 |
||
|
20 |
Net Gas Income |
1,856,000 |
|
21 |
||
|
22 |
Rate Base |
22,753,000 |
|
23 |
||
|
24 |
Rate of Return on Rate Base |
8.16% |
____________________________
The dollar amounts contained in the Study are expressed in 1998 dollars. See KN Wattenberg Transmission LLC's ("KNW") - Front Runner Pipeline application in FERC Docket No. CP98-49-000 for a pipeline that would compete with PSCo's existing pipeline. Also, see FERC Docket No. CP97-256, authorizing KNW to build a 6 mile pipeline lateral bypassing the City of Ft. Morgan's municipal gas system. Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Service by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order N. 888, FERC Stats. and Regs. (Regulations Preambles, 1991-1996) ¶ 31,036 (1996), order on rehearing, Order 888-A III FERC Stats & Regs. (Regulations Preambles) ¶ 31,048 (1997), order on rehearing, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on rehearing, Order No. 888-C, 82 FERC ¶ 61,046 (1998), appeals pending in D.C. Cir. Case Nos. 97-1715. For a comparison of PSCo's and Cheyenne's gas operations relative to other utilities based on 1998 data, see Appendix A. For a comparison of PSCo's and Cheyenne's gas operations relative to other utilities based on 1998 data, see Appendix A. Both PSCo and Cheyenne are regulated to a minor extent by the FERC under the provisions of limited jurisdiction certificates pursuant to Section 7(c) of the Natural Gas Act of 1938. As discussed in the Application/Declaration on Form U-1 of New Century Energies to which this Study is an exhibit, the PSCo and Cheyenne gas systems together constitute an "integrated public utility system" within the meaning of Section 2 (a) (29) of the Public Utility Holding Company Act of 1935. Neither an Employee Incentive Plan (EIP), nor a Management Incentive Plan has been included when determining the NewGasCo-Colo cost of labor. Note, however, that it is estimated that a plan similar to the present PSCo plan could result in the following additional annual costs:
EIP per employee at target $1000 per year
Middle
Management at Target 20 percent of base
salaries
Unit
Managers at Target 15 percent of base salaries
EIP per employee at target $1000 per year
Exhibit K-1
FORGING A REGIONAL ENERGY COMPANY
By
Charles J. Cicchetti, Ph.D.
Pacific Economics Group
for
Northern States Power Company
and
New Century Energies, Inc.
24 January 2000
NCE and NSP: Forging a Regional Energy Company
Part I. Introduction
The pending merger between New Century Energies, Inc. (NCE) and Northern States Power Company (NSP) will form a new regional energy company that must be approved by the Securities Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 as amended (PUHCA). To obtain SEC approval under PUHCA, a merger must demonstrate, among other things, that the resulting company's utility operations would constitute an integrated utility system. Historically, as applied to electric utilities, the SEC has set four specific standards to meet this integration requirement:
1. the utility system's assets must be
2. under normal conditions, the utility assets may be economically operated as a single interconnected and coordinated system;
3. the system must be confined in its operation to a single area or region; and,
4. the system must not be so large as to impair (considering the state of the art and the region or area affected) the advantage of localized management, efficient operation and regulatory effectiveness. [188]
The analysis shows that the proposed merger between NCE and NSP will meet the third standard. To provide context for this analysis, Part II provides background on the merging companies. A gravity model analysis is presented in Part III to demonstrate that the merger satisfies the "single area or region" standard. Gravity model analysis is well-established in international trade and regional economics. The gravity model quantifies the economic ties between the two merging companies' service territories, along with the region surrounding them.
Part IV buttresses the results of the gravity model analyses using techniques of antitrust geographic market definition to define the economic region that the company will operate within. This analysis is not intended to identify markets from an antitrust perspective. Rather, it draws upon those techniques used in antitrust analysis to identify broad economic regions. This analysis provides even clearer evidence that NCE and NSP do, and would, continue to operate in a unified economic region.
Part V reviews and summarizes the conclusions.
Part II. Merger Background
NCE and NSP are both mid-size combination electric and gas utility companies, generally serving the economic region that includes the Great Plains and upper Midwest region of the U.S. NCE is a utility holding company registered under PUHCA. NCE has three wholly-owned public-utility company subsidiaries. One of the public-utility companies, Southwestern Public Service (SPS) is solely an electric utility company, providing electric utility service to customers in New Mexico, Texas, Oklahoma and Kansas. The second utility affiliate, Public Service Company of Colorado (PSCo) is both an electric utility company and a gas utility company, providing electric and gas utility service in Colorado. The third utility affiliate, Cheyenne Light, Fuel and Power Company (Cheyenne) provides gas and electric service in Wyoming. In its order approving the formation of NCE, the SEC found that the combined Colorado, New Mexico, Texas, Oklahoma and Kansas electric operations constituted a single, integrated electric utility system and that the Wyoming electric operations and the combined Wyoming and Colorado gas operations were each permissible as an additional system under the ABC clauses of Section 11(b)(1) of PUHCA.
NSP is a public utility company and an exempt holding company (not registered) that primarily provides gas and electric utility service to customers in Minnesota, North Dakota, and South Dakota. Through its wholly-owned utility subsidiary Northern States Power Company - Wisconsin (NSP-Wisconsin), NSP also provides gas and electric service to customers in Wisconsin and Michigan.
Currently, the proposed merger would be a merger of equals, forming a new company to be called Xcel Energy, Inc. NCE will merge into NSP, and NSP (either immediately before or after the merger) will drop its existing electric and gas utility business into a new subsidiary. The transaction is expected to be structured as a tax-free, stock for stock exchange, with NCE shareholders receiving shares of NSP. The companies also expect that the transaction will be treated as a pooling of interests for accounting and tax purposes. The resulting corporate structure will be a registered holding company, incorporated in Minnesota, with the following five first-tier public utility subsidiaries:
1) SPS;
2) PSCo;
3) Cheyenne;
4) A new subsidiary containing NSP's existing electric and gas utility operations in Minnesota, North Dakota and South Dakota; and
5) NSP-Wisconsin.
Part III: Gravity Models Demonstrate That The Companies Operate in a Single Economic Region
NSP's and NCE's service territories and their respective retail customers are several hundred miles apart. Nonetheless, for the reasons discussed below, these two companies operate in a single economic region.
In general economic terms, these two merging service territories have evident and quantifiable similarities. This is shown by an analysis using gravity models from regional and international trade economics. This analysis illustrates that, in economic terms, the two companies already participate in a single economic region or market area. The gravity model measures the economic "pull" between geographically separate franchises and locations as a function of the economic size or "mass" of each and the distance between them. Thus, this method quantifies the economic connection and ties between geographically separated economic entities, such as metropolitan areas and states.
A. Gravity Model Background
Gravity models were developed by regional economists about 40 years ago. They use the analogy of gravitational potential in physics to model the economic pull between two economic or population centers. The gravitational pull between two planets is a function of their mass and the squared distance between them. Economic gravity models are based on the theory that the economic pull between entities, two cities or states, for example, is a function of their economic "mass" and the squared distance between them. This mass is usually population combined with income. The degree to which a city or state economically interacts with another city or state is related to the economic "gravitational pull" between them. [189] Cities with very large economic "mass", such as New York or Los Angeles, have significant economic interaction with very distant cities. More important, cities within a confined area or economic market may have such strong pull that an identifiable economic region is formed and defined.
In the gravity models basic form, the economic interaction between two regions is directly proportional to the interaction of the economic "mass" of the two regions, and inversely proportional to the distance squared. A typical functional form of the gravity model for regions i and j is as follows:[190]
Fij = GIi1Ij 2 Pi3Pj4 Dij5euij (1)
where Fij is the potential flow of some economic activity from region i to region j, G is a gravitational constant, Ij is income (or some other measure of j's economic size), Pj is the population of j, Dij is the distance (or distance squared) between i and j, and uij is a random error term that reflects the flows not explained in the model. The gravitational constant represents the degree of gravitational pull between regions i and j, given the economic characteristics of each. Various regression coefficients, or terms, capture the influence of each of the economic characteristics and the distance between the regions. The values of the gravitational constant and regression coefficients can be estimated using least squares regression techniques.
Gravity models are used to explain migration, commuting patterns, international trade, interregional trade, and travel. Economists, geographers, demographers, and sociologists all use gravity models to explain and analyze various interregional (or international) flows. The gravity model's theoretical and empirical soundness in explaining international trade flows is well-established.[191] For trade flow applications of the gravity model, a log-linear functional form is nearly universally applied.[192]
B. A Gravity Model of Total Commodity Flows
This empirical analysis estimates the potential economic interaction or pull between the sub-regions served by NSP and NCE, and examines whether these specific markets are part of a larger single economic region.
Using the estimated potential to attract, it is possible to estimate the flows within and out of a combined region that includes the two companies' service territories. This analysis shows that the combined utilities form and are part of a very specific economic market and region. This quantified result is not particularly surprising. Recent business consolidations and marketing plans of Norwest Bank and U.S. West strongly suggest that these large banking and telecommunications companies also find this regional alignment to be a distinct economic market or region.
The gravity concept and regression analysis can be used to determine the percent of commodity shipments going "to or from" the various economic entities from within the geographic area as compared to entities from outside. A relatively self-contained geographic area is one in which relatively more commodities are generated within the economic region. Specifically, the greater the percent of goods (tons or dollar valued) that are produced, shipped and used locally means that the geographic area is a relatively self-contained and identifiable, comprehensive economic market or region.
1. Data Used and Structure of the Analysis
The gravity analyses use the total tons of commodity shipments and the dollar value of those commodity shipments as the two primary measures of total economic interaction. The 1993 Commodity Flow Survey conducted by the Department of Transportation and the Bureau of the Census provides data on the total value (in dollars) and volume (in tons) of commodity shipments between states (including intra-state flows).[193] As these data were only available at the state level, the model was estimated at the state level. However, the results are used to estimate potential interaction at the level of Metropolitan Statistical Areas (MSAs), the Census Bureau's designation for urban areas. The 1993 data for the economic variables of income and population at both the state and MSA levels are from the Bureau of Economic Analysis' Regional Economic Information System.[194]
The econometric models used in this analysis adopt the basic functional form for gravity models, with 1993 total commodity flows, in tons and in dollar value, respectively, as the economic flow or dependent variable. The explanatory or independent variables are: total personal income, population, and total employment, which measure the specific economic "mass" of the regions; and distance measured as the great circle, or curvature, distance between the longitude and latitude of each state's population center.[195]
Equation (2) represents the basic model used:
Fij = GF[IiIjPiPjEiEj] / Dij (2)
where Fij is the value of total commodity flow from state i to state j (in either dollars or tons), G is the gravity constant, I is the total personal income in state i or j, P is total population in state i or j, E is total employment in state i or state j, and dij is the great circle distance between the MSA population centers of state i and state j.
Transforming the equation into logarithmic form and rearranging terms permit the use of least squares linear regression techniques for the logarithmic form of these variables. The basic regression equation is:
ln(Fij) = ln(G) + ln(Ii)+ln(Ij)] + ln(Pi)+ln(Pj)] + ln(Ei)+ln(Ej)] - ln(dij)]. (3)
The various income, population and employment variables yield estimates of the total effect of the combined economic factors for various state pairings. Note however, that the flows are not constrained to be equal for each direction: Fij is not necessarily equal to Fji.
A separate regression is specified for intra-state flows, because these are deemed to follow a similar pattern, but are likely to have different parameters. For each state, the intra-state flows typically represent the largest share of total flows, however the measured distance is effectively zero for these flows; therefore a gravity formulation does not work particularly well. Using a simple log-linear cross sectional regression for intrastate flows works relatively well.[196] Therefore, for intrastate flows the model we use is:
ln(Fii) = +ln(Ii) + ln(Pi) + ln(Ei). (4)
Some further modifications to the basic model provide an improved estimate of the regional economic flows. The U.S. has no trade barriers within its borders and any given state has some degree of economic interaction with the majority of other states. The degree of interaction is likely to be different for far distant points than for closer ones, with the incremental effect of distance declining. Competition and substitution cause this result. To account for these facts, further modifications to the model distinguish "near" from "far" by replacing the distance variable with a dummy variable which equals 1 for distances over 800 miles, and 0 otherwise. The specific quantifiable incremental effect of distance is therefore estimated only for points less than 800 miles apart, with distances beyond combined into a dummy variable, as represented in equation 5.
ln(Fij) = ln(G) + ln(Ii)+ln(Ij)] + ln(Pi)+ln(Pj)] +
ln(Ei)+ln(Ej)] - ln(dij)*NEARDUM] - FARDUM. (5)
where NEARDUM = 1 if distance is 800 miles or less (0 otherwise), and FARDUM = 1 if distance is greater than 800 miles.
The statistical fit of the data is shown by the R2 value, which represents the proportion of variation in the data explained by the regression relative to the total variation in the data. The interstate gravity model based on tons shipped produces R2 values of about 0.63, meaning that about 63 percent of the variation in total commodity flows between i and j is explained by the regression model. The interstate gravity model based on the dollar value of the commodities shipped produces R2 values of about 0.83. These R2 values are somewhat high for a cross-sectional (one time period) regression analysis and indicate a fairly tight fit. The regression method also yields estimated values for the coefficients ( ). These are statistically different from zero with a higher degree of confidence. Attached as Exhibit 1 are the interstate and intrastate regressions based on the dollar value of the commodities shipped. Attached as Exhibit 2 are the interstate and intrastate regressions based on the tons of commodities shipped.
C. Determining an Economic Region
An economic market or region is defined by how much activity is concentrated within the boundaries of the region. Accordingly, an economic market is defined when most goods used in a geographic area come from within, relatively little flows out from within the area, and/or relatively little flows in from outside the area. Three definitions of potential economic regions were examined using the econometric analysis of the gravity models.[197] These various economic market definitions were: (1) a market defined as including all the major urban centers in the service area of the two merging electric utilities; (2) a rectangular area defined by the extreme coordinates of the combined utilities' existing service territories; and, (3) a circular region defined by an axis running through the two major cities served (Minneapolis and Denver) and including both service territories in their entirety.
The Census Bureau defines the major urban centers as Metropolitan Statistical Areas (MSAs). This definition corresponds to the data used in the econometric analysis. However, it is economically too narrow because rural areas and small communities would be arbitrarily excluded. Regardless, this narrow definition estimates that ninety (90) percent of all the tons shipped "to and from" the MSAs in this geographic market came from within such a market. The dollar value of these same goods from within this market definition exceed three-fifths of all the commodities shipped in this "urban" market.
The second definition is the rectangular market,[198] which adds the rural and small communities to the service territories. In addition, some geographic origins and destinations not served by the combined electric utilities are added. While adding more origins increases the percentage from "within," these "additions" can often increase the deliveries outside because these economic centers generally ship to external destinations, which tends to reduce the calculated "within" market percentage.
Increasing the size of the market by including rural areas and adding areas not served by the combined utilities' franchise territory, results in a small net increase in the "within" market percentages. Specifically, slightly more than ninety (90) percent of the tons shipped would be "within" this region, and about two-thirds of the dollar value of the goods shipped would fall in this geographic market.
The rectangular market is bigger than the urban market and the percentage of "within" especially in dollar terms is higher. Nevertheless, the greater size also tends to mean a greater volume of economic interaction by the new urban areas added by the rectangular definition with urban areas outside the market. Accordingly, sensitivity analyses were performed taking out the effect of Chicago, as well as Chicago and the Texas MSAs not included in the franchise territory of the merging electric utilities. These sensitivity analyses demonstrated that the "net" effect from removing these large urban areas did not affect the conclusion that more than 90 percent of the goods shipped and two-thirds of their dollar value would still be from "within" these small economic markets.
A third geographic market is defined as a circular area. This definition mitigates the arbitrary exclusions caused by the various rectangular definitions that exclude some reasonable spillover economic activity with markets that are contiguous to the existing franchise territories. The circular market was defined by selecting an axis between the two principal cities, Minneapolis and Denver, as following on the diameter, and extending the circle to include the more extreme points of the existing franchise territory. This particular distance was consistent with the econometric variable definitions, which yielded better statistical explanations of the relationships in the gravity model estimation. Further, by expanding the circular market definition to more than an 800-mile radius would pick-up Canadian MSAs, which were not in the database used in the regression analysis. The circular market definition includes ninety-four (94) percent of the goods shipped and seventy-seven (77) percent of the dollar value of these goods from within this region.
The circular region is both larger and includes the entire franchise territory and, therefore, is superior to the urban market definition. The circular model also avoids the more arbitrary exclusion of adjacent spillover interaction that occurred with the rectangular market definitions.
All the definitions analyzed yield relatively very high "within" percentage commodity shipped estimates. The 800-mile radius circular market definition is the most comprehensive and this market definition is used in the remainder of the analysis. However, the high "within" results of the different analyses demonstrate that the Applicants are in the same economic region.
Part IV. Antitrust Geographic Market
Definition Technique Shows that the Utilities Operate
in a
Single Economic Region
The economic techniques for defining geographic markets in antitrust economics provide the conceptual underpinnings of this analysis, which are used to determine the boundaries of a region in terms of economic activity. However, this analysis, while it uses traditional antitrust techniques, is not performed to identify potential market power issues. Rather, this analysis was performed to identify the economic region in which the companies operate. This is a purpose distinct from and unrelated to the companies' market shares. Identifying the relevant geographic market is one of two key elements in antitrust analysis, the other being to identify the relevant product market. For antitrust purposes, the relevant geographic market for a particular product is the area in which a hypothetical profit-maximizing monopolist could impose a "small but significant and non-transitory price increase."[199] The heart of the concept of relevant geographic market is that it is the smallest area that contains all or virtually all of the suppliers from whom consumers could reasonably choose to buy.
Though this analysis does not specifically address the question of the relevant geographic market for NSP and NCE, the logic of defining relevant geographic markets provides a useful way to test whether the companies operate in a single economic region. Specifically, if the total tons of or value of commodity shipments within (to and from) a proposed unified region is consistent with defining a geographic market according to antitrust methods, the region so defined can reasonably be considered a single market, or economic region.
There are several approaches to defining geographic markets in the antitrust literature. They fall generally into three categories: shipments tests,[200] price tests,[201] and estimating residual demand.[202] The shipments and price tests are based upon fundamental economic principles of what constitutes a market. The assumption behind the shipments test is that the area in which actual trades occur can define a market's boundaries. The shipments test uses data on total shipments of a product to characterize the region in which the product is traded.
The price test methodology extends this theory somewhat to define a market as an area in which prices of the same goods differ only by transportation costs, regardless of whether shipments between distant locations actually occur.[203] There are several variations on the price test, but all require data on prices over time.
The residual demand faced by a particular set of producers is the total demand minus the supply provided by other producers. The residual demand estimation method is intended to identify (a market according to the potential market power a producer or group of producers could exert (acting collusively) within that market.) The shipment test and price test methods in particular are widely used in antitrust analysis. They are so widely used, in part, because the data they require is widely available for most products and industries. Another reason for their popularity is their straightforward derivation from basic economic theory. It is generally agreed that these tests identify economic markets. There is, however, some dispute about the effectiveness of these tests in identifying antitrust markets, which are generally smaller than economic markets. Since this analysis of regulated firms is not concerned with the antitrust market, and is not focused on a particular product or industry, the drawbacks of these tests are not of concern in this analysis.
The specifics of the shipments test are described further below. It was chosen for this analysis because it is the best, and really the only appropriate method to use to characterize a broader economic market in which many products are shipped and traded.[204] Because this analysis is not limited to a single product or industry, no data on specific prices is available, so the other tests are infeasible. Though it is more commonly used for a particular product, the theory behind the shipments test extends to characterizing trade in general.
In their seminal 1973 paper, Kenneth Elzinga and Thomas Hogarty proposed the shipments framework for defining relevant geographic markets in antitrust analysis.[205] The heart of their framework is the concept of Little In from Outside (LIFO) and Little Out from Inside (LOFI). They argue that the boundaries of a relevant geographic market exist at the point where little of the product in question comes in from outside the boundaries tested, and little of the product is sent out from inside the boundaries. A true geographic market boundary is likely to exist where both conditions are true.
Both ratios are developed from raw production, consumption and shipping data. The LIFO ratio describes the percentage of goods flowing in from outside. The LIFO statistic provides insight on the options available to consumers - in particular their tendency to transact with suppliers within and without a defined geographic region. Similarly the LOFI statistic highlights the geographic breadth of the customer base that producers can and do supply. The LOFI describes the percentage shipped out of market. The information in the LIFO and LOFI statistics can also be captured in the supplement, which is designated as 1-LIFO, which describes the percentage of goods flowing wholly within (to and from) the proposed relevant market.
The Elzinga-Hogarty supplement ratio calculation consists simply of adding up the predicted commodity flows to or from all MSAs within the region, and taking the ratio of all flows strictly within the region (to and from MSAs inside the region) to the total of all flows to or from MSAs inside the region. The model assumes that an economic region is achieved where the model estimates a ratio that predicts that approximately 75 percent or more of the goods or services are produced and consumed inside the defined boundaries and less than 25 percent outside the geographic area.
Using the most comprehensive market definition, i.e., the circular region encompassing the majority of NCE's and NSP's service territories, the predicted Elzinga-Hogarty ratio for the model based on tons shipped is 94 percent, and for the model based on the dollar value of the commodity shipped is 77 percent. This suggests that NSP and NCE operate within a single economic region. The 94 percent ratio based on tons shipped should be interpreted as meaning that only about 6 percent of the commodity shipments going to or from MSAs within the NSP/NCE region are going to or coming from outside the region (excluding California and New York shipments). Similarly, about 23 percent of the dollar value is going to or coming from outside the region. Thus, the circular market definition using the dollar value of the commodities shipped satisfies the Elzinga-Hogarty 25 percent benchmark. Also, the circular market definition using the tons of commodities shipped substantially satisfies this criteria with only 6 percent of goods going to or coming from outside the region.[206] Thus, the Elzinga-Hogarty ratio derived from the gravity model predictions presents clear and straightforward evidence that NSP and NCE operate in a single economic region or market.
Part V. Conclusion
The gravity model demonstrates a high degree of economic interaction in the region including NSP and NCE's service territories. The geographic Elzinga-Hogarty market analysis underscores this result, clearly identifying that the companies operate within a distinct economic region. This analysis demonstrates that NSP and NCE operate within a single economic region.
Exhibit 1
SST Spool File: reg10f.log
Mon Jun 07 14:29:36 1999load file[gravstate]
rem Regression of Interstate Flows
rem Dependent Variable: Value of Commodity Shipments
rem Independent Variables: Employment, Population, Personal Income, Distance
reg dep[lvalue] ind[ (1) (l_oempl+l_dempl) (l_opop+l_dpop) (l_oprin+l_dprin) \
(l_dist*(distance<=800)) (distance>800)] pred[predflow] coef[b]
********* ORDINARY LEAST SQUARES ESTIMATION *********
Dependent Variable: lvalue
|
Independent |
Estimated |
Standard |
t- |
|
Variable |
Coefficient |
Error |
Statistic |
|
(1) |
-16.66115 |
0.71788 |
-23.20876 |
|
(l_oempl |
1.03499 |
0.13936 |
7.42685 |
|
(l_opop+ |
0.84066 |
0.11842 |
7.09876 |
|
(l_oprin |
-0.69489 |
0.10289 |
-6.75350 |
|
(l_dist* |
-1.09066 |
5.43420e-002 |
-20.07030 |
|
(distanc |
-8.01396 |
0.33266 |
-24.09071 |
Number of Observations
2125
R-squared
0.82891
Corrected R-squared
0.82851
Sum of Squared Residuals
1.26293e+003
Standard Error of the Regression
0.77201
Durbin-Watson Statistic
1.67631
Mean of Dependent Variable
6.00990
Exhibit 1
rem Regression of Intrastate Flows
rem Dependent Variable: Value of Commodity Shipments Within Each State
rem Independent Variables: Employment, Population, Personal Income
reg dep[lvalue] ind[(1) l_oempl l_opop l_oprin] pred[predintu] \
if[origfips==destfips] coef[isb]
********* ORDINARY LEAST SQUARES ESTIMATION *********
Dependent Variable: lvalue
|
Independent |
Estimated |
Standard |
t- |
|
Variable |
Coefficient |
Error |
Statistic |
|
(1) |
-5.91449 |
0.87703 |
-6.74377 |
|
l_oempl |
1.86106 |
0.54958 |
3.38633 |
|
l_opop |
0.65545 |
0.47477 |
1.38058 |
|
l_oprin |
-1.15118 |
0.29098 |
-3.95615 |
Number of Observations
48
R-squared
0.96739
Corrected R-squared
0.96517
Sum of Squared Residuals
2.51513
Standard Error of the Regression
0.23909
Durbin-Watson Statistic
2.47270
Mean of Dependent Variable
10.08156
Exhibit 2
SST Spool File: reg9_wt.log
Wed Jun 16 13:22:32 1999load file[gravstate]
rem Regression of Interstate Flows
rem TONS as Dependent, Ind: Employment, Population, Real prin, Distance
reg dep[lweight] ind[ (1) (l_oempl+l_dempl) (l_opop+l_dpop) (l_oprin+l_dprin) \
(l_dist*(distance<=800)) (distance>800)] pred[predflow] coef[b]
********* ORDINARY LEAST SQUARES ESTIMATION *********
Dependent Variable: lweight
|
Independent |
Estimated |
Standard |
t- |
|
(1) |
1.15854 |
1.24041 |
0.93399 |
|
(l_oempl |
1.35769 |
0.25553 |
5.31332 |
|
(l_opop+ |
2.43902 |
0.21669 |
11.25567 |
|
(l_oprin |
-2.69856 |
0.17741 |
-15.21101 |
|
(l_dist* |
-1.61221 |
9.24900e-002 |
-17.43121 |
|
(distanc |
-11.88982 |
0.56647 |
-20.98927 |
|
Number of Observations |
1949 |
|
R-squared |
0.63219 |
|
Corrected R-squared |
0.63124 |
|
Sum of Squared Residuals |
3.19578e+003 |
|
Standard Error of the Regression |
1.28248 |
|
Durbin-Watson Statistic |
1.40446 |
|
Mean of Dependent Variable |
5.46339 |
Exhibit 2
load file[gravstate]
rem Regression of Intrastate Flows
rem TONS as Dependent, Ind: Employment, Population, Real prin, Distance
reg dep[lweight] ind[(1) l_oempl l_opop l_oprin] pred[predintu] \
if[origfips==destfips] coef[isb]
********* ORDINARY LEAST SQUARES ESTIMATION *********
Dependent Variable: lweight
|
Independent |
Estimated |
Standard |
t- |
|
Variable |
Coefficient |
Error |
Statistic |
|
(1) |
3.43875 |
1.62976 |
2.10998 |
|
l_oempl |
1.30150 |
1.02410 |
1.27087 |
|
l_opop |
2.41038 |
0.88015 |
2.73859 |
|
l_oprin |
-2.61620 |
0.55404 |
-4.72205 |
Number of Observations
47
R-squared
0.83503
Corrected R-squared
0.82352
Sum of Squared Residuals
8.43284
Standard Error of the Regression
0.44285
Durbin-Watson Statistic
1.57897
Mean of Dependent Variable
11.35612
_______________________________________
[188]See Environmental Action, Inc. v. SEC, 895 F.2d 1255, 1263 (9th Cir. 1990) (citing In the Matter of Electric Energy, Inc. Holding Company Release No. 1387`, 38 S.E.C. 658, 668 (Nov. 28, 1958)). See Environmental Action, Inc. v. SEC, 895 F.2d 1255, 1263 (9th Cir. 1990) (citing In the Matter of Electric Energy, Inc. Holding Company Release No. 1387`, 38 S.E.C. 658, 668 (Nov. 28, 1958)). See Environmental Action, Inc. v. SEC, 895 F.2d 1255, 1263 (9th Cir. 1990) (citing In the Matter of Electric Energy, Inc. Holding Company Release No. 1387`, 38 S.E.C. 658, 668 (Nov. 28, 1958)). See Environmental Action, Inc. v. SEC, 895 F.2d 1255, 1263 (9th Cir. 1990) (citing In the Matter of Electric Energy, Inc. Holding Company Release No. 1387`, 38 S.E.C. 658, 668 (Nov. 28, 1958)). See Environmental Action, Inc. v. SEC, 895 F.2d 1255, 1263 (9th Cir. 1990) (citing In the Matter of Electric Energy, Inc. Holding Company Release No. 1387`, 38 S.E.C. 658, 668 (Nov. 28, 1958)).[189]See Walter Izard and David Bramhall, "Gravity, Potential and Spatial Interaction Models," Chapter 11 in Methods of Regional Analysis: An Introduction to Regional Science (Cambridge, Mass.: MIT Press, 1960) for the definitive discussion of the gravity model method.
[190]Marcos Sanso, Rogelop Cuairan, and Fernando Sanz. "Bilateral Trade Flows, the Gravity Equation, and Functional Form," The Review of Economics and Statistics 75(2): 267, May 1993.
[191]Most often cited theoretical justification for the gravity model is James E. Anderson, "A Theoretical Foundation for the Gravity Equation," American Economic Review 69: 106-116, 1979. For examples of applications in international trade see Marcos Sanso, Rogelio Cuairan, and Fernando Sanz. "Bilateral Trade Flows, the Gravity Equation, and Functional Form," Review of Economics and Statistics 75(2): 266-75, May 1993; Spiros Bougheas, Panicos O. Demetriades, and Edgar L.W. Morgenroth, "Infrastructure, Transport Costs and Trade," Journal of International Economics 47: 169-189, 1999; and Bruno Larue and Joshua Mutunga, "The Gravity Equation, Market Size, and Black Market Exchange Rates," International Economic Journal 7(2): 61-75, Summer 1993.
[192]Sanso et al suspected the popularity of the log-linear form more mathematically convenient than definitively correct. Using a more general Box Cox transformation of the gravity model they test the validity of the log-linear functional form. They find that the more general transformation produces a slightly better statistical fit for international trade models, but acknowledge that the improvement and the difference in model results is so small as to be easily considered trivial.
[193]Bureau of the Census. 1993 Commodity Flow Survey, Sponsored by the U.S. Department of Transportation, December 1996, CD-CFS-93-1.
[194]Bureau of Economic Analysis. Regional Economic Information System. Data also published in The Survey of Current Business. URL: http://fisher.lib.Virginia.EDU/reis.
[195]Great circle distance is the equivalent of
straight-line distance, accounting for the curvature of the earth. It
can be estimated from latitude and longitude coordinates using the
calculation
dlon = long2 - long1
dlat = lat2 - lat1
a = (sin(dlat/2))2 + cos(lat1) * cos(lat2) * (sin(dlon/2))2
c = 2 * arcsin(minimum(1,sqrt(a)))
d = R * c
where R is the radius of the earth in miles and d is the
great circle distance in miles. See Bureau of the Census, Geographic Information
Systems Frequently Asked Questions.
[196]Some researchers have
specified gravity models for "zero" distances by calculating a
small but finite and non-zero distance for flows with the "same"
origin and destination. The precision of the data used in this analysis does
not support such a technique, nor does the purpose of the analysis require
it. See John Q. Stewart, "Demographic Gravitation: Evidence and
Applications," Sociometry vol. 11, February and May 1948; John
Q. Stewart and William Warntz, "Macrogeography and Social
Science," Geographical Review vol. 48, April 1958; Gerald A.P.
Carrothers, "Forecasting the Population of Open Areas, doctoral
dissertation, Massachusetts Institute of Technology, Cambridge,
Massachusetts, 1959. All cited in Walter Isard, Methods of Regional
Analysis: an Introduction to Regional Science (Cambridge, Massachusetts:
MIT Press, 1960).
[197]California and New York were excluded from all
calculations because these states constitute the major international import
and export ports for the nation.
[198]The rectangular area is defined by the extreme
coordinates of the combined utilities' existing service territories. These
are: Northern limit - Berthhold, ND 48:18:54N, 101:44:07W, Southern limit
- Jal, NM 32:06:49N, 103:11:22W; Eastern limit - McMillan, MI 46:20:20N,
85:41:14N; Western limit - Fruita, CO 39:09:23N, 108:43:38W. Source:
Company produced service territory maps and descriptions for NCE and NSP.
[199]Federal Trade Commission. 1992 Horizontal Merger
Guidelines. URL: http://www.ftc.gov/bc/docs/horizmer.htm.
[200]See Kenneth G. Elzinga and Thomas F. Hogarty,
"The Problem of Geographic Market Delineation in Antimerger
Suits," The Antitrust Bulletin 18: 45-81, 1973. Ronald Shrieves'
methodology is sometimes called a shipments test, but actually combines
shipments and price data to characterize similarity between producing
regions. His methodology is specifically designed for industries where the
location of production is distant from the consuming locations, for
exogenous reasons, such as coal mining. Ronald E. Shrieves, "Geographic
Market Areas and Market Structure in the Bituminous Coal Industry," The
Antitrust Bulletin 23(3): 589-625, Fall 1978.
[201]See Ira Horowitz. "Market Definition in
Antitrust Analysis: A Regression-Based Approach," Southern Economic
Journal 48(1): 1-16; George Stigler and Robert Sherwin, "The Extent
of the Market," Journal of Law and Economics 28(3): 555-85,
October 1983.
[202]See David Scheffman and Pablo T. Spiller,
"Geographic Market Definition Under the U.S. Department of Justice
Guidelines," Journal of Law and Economics 30: 123-47, April
1987.
[203]See Alfred Marshall, Principles of Economics,
Book 5, (London: MacMillan Publishing, 1920) p. 324, George Stigler, The
Theory of Price (New York: MacMillan Publishing, 1966), p.85; cited in David
Scheffman and Pablo Spiller, "Geographic Market Definition Under the
U.S. Department of Justice Merger Guidelines," The Journal of Law
and Economics 30: 123-147, April 1987.
[204]That is, without resorting to a data-intensive and
quite unnecessary model of the local economies of this region.
[205]Kenneth G. Elzinga and Thomas F. Hogarty. "The
Problem of Geographic Market Delineation in Antimerger Suits," The
Antitrust Bulletin 18: 45-81, 1973.
[206]Elzinga and Hogarty point out, however, that the 25
percent (or 75 percent for the supplemental ratios) benchmark is a suggested
level, but can be adjusted. The appropriate benchmark should be decided
based on a judgment of the quality of the data and its accuracy in
representing the product or industry being analyzed. Elzinga and Hogarty,
pp. 74-75.
|
|