SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
X Quarterly Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
or
Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For Quarter Ended March 31, 1996
Commission File Number 1-3034
NORTHERN STATES POWER COMPANY
(Exact name of registrant as specified in its charter)
Minnesota 41-0448030
(State of other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
414 Nicollet Mall, Minneapolis, Minnesota 55401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code
(612) 330-5500
None
Former name, former address and former fiscal year, if changed
since last report
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
_____ _____
Indicate the number of shares outstanding of each of the
issuer's classes of common stock, as of the latest practicable
date.
Class Outstanding at April 30, 1996
Common Stock, $2.50 par value 68,707,003 shares
Item 1. Financial Statements
<TABLE>
Northern States Power Company (Minnesota) and Subsidiaries
Consolidated Statements of Income (Unaudited)
<CAPTION>
Three Months Ended
March 31
1996 1995
(Thousands of dollars)
<S> <C> <C>
Utility operating revenues
Electric................................................. $512,943 $497,314
Gas...................................................... 205,766 163,853
Total.................................................. 718,709 661,167
Utility operating expenses
Fuel for electric generation............................. 76,092 83,338
Purchased and interchange power.......................... 62,209 51,733
Cost of gas purchased and transported.................... 133,525 99,415
Other operation.......................................... 83,961 78,994
Maintenance.............................................. 47,068 37,767
Administrative and general............................... 34,941 43,749
Conservation and energy management....................... 16,190 7,770
Depreciation and amortization............................ 74,651 71,831
Taxes: Property and general.............................. 60,129 62,279
Current income tax expense........................ 54,827 40,122
Deferred income tax expense....................... (11,954) (1,290)
Investment tax credit adjustments - net........... (2,207) (2,239)
Total.................................................. 629,432 573,469
Utility operating income.................................. 89,277 87,698
Other income (expense)
Equity in earnings of unconsolidated affiliates.......... 5,989 8,838
Allowance for funds used during construction - equity.... 2,580 1,338
Other income (deductions) - net.......................... (3,426) 2,025
Income taxes on non-regulated operations
and non-operating items................................. 4,029 (934)
Total .................................................. 9,172 11,267
Income before interest charges............................ 98,449 98,965
Interest charges
Interest on utility long-term debt....................... 25,021 25,266
Other utility interest and amortization.................. 4,999 5,117
Non-regulated interest and amortization.................. 4,065 2,285
Allowance for funds used during construction - debt...... (2,846) (1,893)
Total.................................................. 31,239 30,775
Net Income ............................................... 67,210 68,190
Preferred stock dividends ................................ 3,061 3,201
Earnings available for common stock....................... $64,149 $64,989
Average number of common and equivalent
shares outstanding (000's).............................. 68,308 67,004
Earnings per average common share......................... $0.94 $0.97
Common dividends declared per share....................... $0.675 $0.660
Statements of Retained Earnings (Unaudited)
Balance at beginning of period............................ $1,266,026 $1,183,191
Net income for period..................................... 67,210 68,190
Dividends declared:
Cumulative preferred stock............................... (3,061) (3,201)
Common stock............................................. (45,659) (44,198)
Balance at end of period.................................. $1,284,516 $1,203,982
The Notes to Financial Statements are an integral part of the Statements of Income
and Retained Earnings.
</TABLE>
<TABLE>
Northern States Power Company (Minnesota) and Subsidiaries
Consolidated Balance Sheets (Unaudited)
<CAPTION>
March 31, December 31,
1996 1995
(Thousands of dollars)
<S> <C> <C>
ASSETS
Utility Plant
Electric................................................ $6,608,730 $6,553,383
Gas..................................................... 712,259 710,035
Common.................................................. 312,511 299,585
Total............................................... 7,633,500 7,563,003
Accumulated provision for depreciation................ (3,414,077) (3,343,760)
Nuclear fuel............................................ 864,404 843,919
Accumulated provision for amortization................ (762,397) (752,821)
Net utility plant................................... 4,321,430 4,310,341
Current Assets
Cash and cash equivalents............................... 94,740 28,794
Short-term investments.................................. 224 149
Customer accounts receivable - net...................... 279,347 281,584
Unbilled utility revenues............................... 123,262 112,650
Other receivables....................................... 71,846 78,993
Fossil fuel inventories - at average cost............... 26,482 43,941
Materials and supplies inventories - at average cost.... 103,050 100,607
Special deposits - non-regulated projects............... 97,989 9,773
Prepayments and other................................... 40,738 47,972
Total current assets.................................. 837,678 704,463
Other Assets
Regulatory assets....................................... 365,265 374,212
Equity investments in non-regulated projects
and other investments.................................. 299,892 289,495
External decommissioning fund investments............... 214,437 203,625
Non-regulated property - net............................ 176,684 177,598
Long-term receivables................................... 67,848 83,065
Intangible and other assets............................. 97,980 85,786
Total other assets................................... 1,222,106 1,213,781
TOTAL ASSETS........................................ $6,381,214 $6,228,585
LIABILITIES AND EQUITY
Capitalization
Common stock equity:
Common stock and premium - authorized 160,000,000
shares of $2.50 par value, issued shares:
1996, 68,499,928; 1995, 68,175,934.................. $786,067 $769,534
Retained earnings..................................... 1,284,516 1,266,026
Leveraged common stock held by ESOP................... (9,033) (10,657)
Currency translation adjustments - net................ 4,717 2,488
Total common stock equity........................... 2,066,267 2,027,391
Cumulative preferred stock and premium - authorized
7,000,000 shares of $100 par value; outstanding
shares: 1996 and 1995, 2,400,000
without mandatory redemption.......................... 240,469 240,469
Long-term debt.......................................... 1,667,951 1,542,286
Total capitalization................................ 3,974,687 3,810,146
Current Liabilities
Long-term debt due within one year...................... 15,089 25,760
Other long-term debt potentially due within one year.... 141,600 141,600
Short-term debt - primarily commercial paper............ 169,077 216,194
Accounts payable........................................ 230,393 246,051
Taxes accrued........................................... 277,421 202,777
Interest accrued........................................ 33,984 31,806
Dividends payable on common and preferred stocks........ 48,721 48,875
Accrued payroll, vacation and other..................... 82,169 78,310
Total current liabilities........................... 998,454 991,373
Other Liabilities
Deferred income taxes................................... 818,216 841,153
Deferred investment tax credits......................... 159,196 161,513
Regulatory liabilities.................................. 245,083 242,787
Pension and other benefit obligations................... 120,610 115,797
Other long-term obligations and deferred income......... 64,968 65,816
Total other liabilities............................. 1,408,073 1,427,066
Commitments and Contingent Liabilities (See Note 4)
TOTAL LIABILITIES AND EQUITY...................... $6,381,214 $6,228,585
The Notes to Financial Statements are an integral part of the Balance Sheets.
</TABLE>
<TABLE>
Northern States Power Company (Minnesota) and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
<CAPTION>
Three Months Ended
March 31,
1996 1995
(Thousands of dollars)
<S> <C> <C>
Cash Flows from Operating Activities:
Net Income................................................. $67,210 $68,190
Adjustments to reconcile net income to cash from
operating activities:
Depreciation and amortization............................ 81,643 79,517
Nuclear fuel amortization................................ 9,576 12,817
Deferred income taxes.................................... (13,494) (780)
Deferred investment tax credits recognized............... (2,284) (2,349)
Allowance for funds used during construction - equity.... (2,580) (1,338)
Undistributed equity in earnings of unconsolidated
affiliate operations.................................... (4,761) (6,241)
Cash provided by changes in certain working
capital items........................................... 79,077 68,532
Conservation program expenditures - net of amortization.. (403) (3,953)
Cash provided by changes in other assets and liabilities. 4,821 17,483
Net cash provided by operating activities................... 218,805 231,878
Cash Flows from Investing Activities:
Capital expenditures ...................................... (98,571) (77,989)
Decrease in construction payables.......................... (5,485) (14,724)
Allowance for funds used during construction - equity...... 2,580 1,338
Purchase of short-term investments - net................... (75) (1,000)
Investment in external decommissioning fund................ (10,036) (6,981)
Equity investments in and deposits for non-regulated
projects and other........................................ (75,933) (7,096)
Net cash used for investing activities...................... (187,520) (106,452)
Cash Flows from Financing Activities:
Change in short-term debt - net issuances (repayments)..... (47,117) (80,791)
Proceeds from issuance of long-term debt - net............. 125,333 3,171
Loan to ESOP............................................... 0 (15,000)
Repayment of long-term debt, including reacquisition
premium................................................... (11,017) (5,656)
Proceeds from issuance of common stock - net............... 16,337 15,400
Dividends paid............................................. (48,875) (47,080)
Net cash provided by (used for) financing activities........ 34,661 (129,956)
Net increase (decrease) in cash and cash equivalents.......... 65,946 (4,530)
Cash and cash equivalents at beginning of period.............. 28,794 41,055
Cash and cash equivalents at end of period.................... $94,740 $36,525
The Notes to Financial Statements are an integral part of the Statements of Cash Flows.
</TABLE>
Northern States Power Company (Minnesota) and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In the opinion of management, the accompanying unaudited
financial statements contain all adjustments necessary to
present fairly the financial position of Northern States Power
Company (Minnesota) (the Company) and its subsidiaries
(collectively, NSP) as of March 31, 1996 and December 31, 1995,
the results of its operations for the three months ended March
31, 1996 and 1995, and its cash flows for the three months ended
March 31, 1996 and 1995. Due to the seasonality of NSP's
electric and gas sales, operating results on a quarterly basis
are not necessarily an appropriate base from which to project
annual results.
The accounting policies followed by NSP are set forth in
Note 1 to NSP's financial statements in NSP's Annual Report on
Form 10-K for the year ended December 31, 1995 (1995 Form 10-K).
The following notes should be read in conjunction with such
policies and other disclosures in the 1995 Form 10-K.
Certain reclassifications have been made to 1995 financial
information to conform with the 1996 presentation. These
reclassifications had no effect on net income or earnings per
share as previously reported.
1. Summary of Significant Accounting Policies
1996 Accounting Change - Wisconsin Gas Costs - While fixed
costs (demand charges) from gas suppliers and transporters are
incurred fairly evenly throughout the year, such costs are
recovered in customer rates on a per unit basis (using average
annual costs per unit), primarily in the winter heating season
when sales volumes are highest. Also, the energy price of gas
purchased (excluding demand charges) can vary from estimated
levels included in customer rates. As a result, gas costs for
both demand and energy charges are incurred throughout the year
at a different time than when such costs are recovered from
customers. The purchased gas adjustment (PGA) clause allows
customer rates to be adjusted periodically to ensure full
recovery of all gas costs incurred.
Effective Jan. 1, 1996, NSP's subsidiary, Northern States
Power Company, a Wisconsin corporation (the Wisconsin Company)
changed its method of accounting for the regulatory effects of
costs recovered through the PGA rate adjustment clause.
Previously, the Wisconsin Company expensed gas costs as
incurred. Beginning in 1996, the cost of gas expensed is
adjusted to equal the level of cost recovery in customer rates,
with such adjustments being reflected as regulatory deferrals on
the balance sheet. This accounting change results in a better
matching of revenues and expenses, and conforms to the cost
recognition method used by the Company.
This change affects the timing of expense recognition
within the year but will not change total annual gas expense for
1996 or any prior years. The effect of the change on first
quarter 1996 results was an increase in gas costs recognized and
a decrease in pretax operating income of approximately $6.5
million, and a decrease in net income of $3.9 million (six cents
per share). Consistent with accounting requirements, prior year
quarterly results have not been restated for this change. Had
the change been implemented as of Jan. 1, 1995, the effect of
the change on first quarter 1995 results would have been an
increase in gas costs and a decrease in pretax operating income
of $3.7 million, and a decrease in net income of $2.2 million
(three cents per share).
2. Proposed Business Combination
On April 28, 1995 NSP and Wisconsin Energy Corporation
(WEC) entered into an Agreement and Plan of Merger, which
provides for a strategic business combination involving NSP and
WEC in a "merger-of-equals" transaction to form Primergy
Corporation (Primergy). See further discussion of the proposed
business combination in the 1995 Form 10-K and Part II, Item 5-
Other Information of this report. On April 5, 1996, NSP and WEC
submitted the initial filing to the Securities and Exchange
Commission to facilitate registration of Primergy under the
Public Utility Holding Company Act of 1935, as amended. On
April 10, 1996, the Michigan Public Service Commission approved
the merger application, through a settlement agreement
containing terms consistent with the merger application. This
is the first of four states to act where approval of the merger
is required. The merger filings with each state included a
request for deferred accounting treatment and rate recovery of
costs incurred associated with the proposed merger. At March
31, 1996, $16.3 million of costs associated with the proposed
merger and incurred by NSP had been deferred as a component of
Intangible Assets and Other.
3. Business Developments
Non-regulated Acquisitions - On April 30, 1996, NSP's
wholly owned non-regulated subsidiary, NRG Energy, Inc. (NRG),
closed its acquisition of a 41.86-percent interest in O'Brien
Environmental Energy, Inc. (O'Brien) from bankruptcy. O'Brien
has been renamed NRG Generating (U.S.) Inc., and the former
shareholders of O'Brien own the remaining 58.14 percent of NRG
Generating, which will be publicly traded. As a result of the
purchase, approximately $107.3 million was made available to
O'Brien and its creditors by NRG consisting of the following:
(i) a $30.8 million equity investment by NRG for its 41.86
percent interest in O'Brien; (ii) a $7.5 million investment by
NEO Corporation, a wholly owned subsidiary of NRG, for all of
O'Brien's interest in certain biogas projects; and (iii) loans
totaling $69 million from NRG to O'Brien. Approximately $87
million of these investments in and loans to O'Brien were
reflected as Special Deposits - Non-regulated Projects in
current assets on the consolidated balance sheet at March 31,
1996. In connection with the closing on its O'Brien
acquisition, NRG was released from its $100 million letter of
credit obtained in January 1996 to secure its obligation to
complete its proposed investment in O'Brien. O'Brien has
interests in eight domestic operating power generation
facilities with aggregate capacity of approximately 230
megawatts, and in one 150-megawatt facility in the contract
stage of development.
4. Commitments and Contingent Liabilities
Nuclear Insurance - The circumstances set forth in Note 15
to NSP's financial statements contained in the 1995 Form 10-K
appropriately represent the current status of commitments and
contingent liabilities regarding public liability for claims
resulting from any nuclear incident.
Item 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATION
On April 28, 1995, the Company and WEC entered into an
Agreement and Plan of Merger which provides for a strategic
business combination involving the two companies in a "merger-
of-equals" transaction. Further information concerning this
agreement and proposed transaction and pro forma financial
information with respect thereto is included in the 1995 Form
10-K and Part II of this report. The following discussion and
analysis is based on the financial condition and operations of
NSP and does not reflect the potential effects of its
combination with WEC.
The following discussion and analysis contains forward-
looking statements. When used in this document, the words
"anticipate", "estimate", "expect", "objective" and similar
expressions are intended to identify forward-looking statements.
Such statements are subject to certain risks, uncertainties and
assumptions, including those that are described in Exhibit 99.01
to this report.
Results of Operations
Northern States Power Company's earnings per share for the
first quarter ended March 31, 1996, were $.94, down $.03 from
the $.97 earned for the same period a year ago.
In addition to items noted in the 1995 Form 10-K, the
historical and future trends of NSP's operating results have
been and are expected to be affected by the following factors:
Non-regulated Business Results - Quarterly results include
earnings contributions from non-regulated businesses of $0.04
per share in 1996 and $0.13 per share in 1995. The following
summarizes the earnings contributions of NSP's non-regulated
businesses:
3 Mos. Ended
3/31/96 3/31/95
NRG $0.04 $0.11
Eloigne Company 0.01 0.01
Cenerprise, Inc.
(Cenerprise) (0.03) 0.00
Other 0.02 0.01
Total $0.04 $0.13
Due to the nature of these non-regulated businesses, NSP
anticipates that the earnings from non-regulated operations will
experience more variability than regulated utility businesses.
As discussed below, NSP's non-regulated earnings in the three-
month period ended March 31, 1996 are experiencing such
variability.
NRG - NRG's first quarter earnings were down from a year
ago due to a combination of higher business development
expenses, which increased overall operating expenses, and
lower equity in earnings of projects. NRG experienced an
increased level of business development costs in late 1995
and early in 1996 as it pursued several significant
international and domestic projects. Until there is
substantial assurance that a project in development will
come to financial closure, such costs are expensed. Equity
in earnings of projects decreased in 1996, as lower equity
in earnings from the MIBRAG and Gladstone projects were
only partially offset by higher earnings from Schkopau.
Equity in earnings from MIBRAG decreased due to an expected
decline in heating briquette and coal sales, while
Gladstone incurred higher labor costs. Partially
offsetting these decreases, one unit of the Schkopau power
generation facility began commercial operation in March
1996, with the second unit scheduled to come on line later
in 1996.
Cenerprise - Cenerprise's first quarter earnings were down
due largely to unusually high gas costs incurred to meet
customer demand requirements, and to losses incurred from
gas trading activities. With the extremely cold weather
experienced throughout the U.S. in the first quarter of
1996, several of Cenerprise's gas suppliers and
transporters curtailed product availability. Other, more
expensive sources of spot gas supply were needed to meet
sales commitments to Cenerprise's customers. Cenerprise is
investigating legal action against suppliers who may not
have met their contractual obligations to supply gas.
Also, Cenerprise has curtailed its gas trading activities
and will trade only to support its end-use customer sales
in the future.
Estimated Impact of Weather on Regulated Earnings - NSP
estimates sales levels under normal weather conditions and
analyzes the approximate effect of variations from historical
average temperatures on actual sales levels. The following
summarizes the estimated impact of weather on actual utility
operating results (in relation to sales under normal weather
conditions):
Increase (Decrease)
Actual Actual Actual
1996 vs Normal 1995 vs Normal 1996 vs 1995
Earnings per
Share for
Quarter Ended
March 31 $0.09 ($0.06) $0.15
The estimated impact of weather on the first quarter of
1996 considers only the impacts of variations from average
temperatures, including the extremely cold temperatures in late
January and early February of 1996. Although such cold weather
in this period would be expected to result in increased energy
sales, an ice storm immediately preceding the cold weather
resulted in as many as 200,000 customers being temporarily out
of service, and bitterly cold temperatures resulted in some
customers shutting down or curtailing their operations. Because
these secondary weather impacts are not reliably quantifiable,
their expected effects (an offset to the energy sales increase
from cold weather) have not been included in the estimated
impact of weather on 1996 operating results.
Competition - On April 24, 1996, the Federal Energy
Regulatory Commission (FERC) issued two final rules regarding an
earlier proposal (called the "Mega-NOPR") for electric utilities
to offer open access transmission service to wholesale
transmission users. The ruling, which will take effect later
this year, requires utilities and other transmission users to
abide by the same terms and conditions in transmitting power and
is intended to promote competition. A new proposed rule,
Capacity Reservation Open Access Transmission Tariffs, was also
issued. While NSP is still reviewing the provisions of these
new rules and is unable at this time to precisely determine
their impact on future operations, NSP continues to be generally
supportive of the FERC's efforts to increase competition.
First Quarter 1996 Compared with First Quarter 1995
Utility Operating Results
Electric revenues for the first quarter 1996 compared with
the first quarter 1995 increased $15.6 million or 3.1%. Retail
revenues increased approximately $31.9 million or 7.0% largely
due to a 4.1% increase in retail electric sales. The increase
in retail electric sales is due to colder-than-normal weather
(as discussed above) and sales growth. In addition, retail
prices increased 2.8% primarily due to increased recovery of
deferred conservation and energy management costs and fuel
expense recovery (as discussed below). Wholesale revenues were
impacted by the effects of expected contract terminations for
seven municipal customers in July 1995, resulting in a $5.4
million decrease. Revenues from sales to other utilities
decreased by $11.0 million mainly due to decreases in sales
volume. This decrease in sales to other utilities reflects
higher retail sales requirements and less plant availability due
to more major planned outages in 1996 (as discussed below).
Gas revenues for the first quarter 1996 increased $41.9
million or 25.6% compared with the first quarter of 1995. Gas
revenues increased due to a 18.8% increase in gas sales volume
and a 6.3% average price increase. The sales volume increase is
due primarily to weather impacts (as discussed previously) and
firm sales growth. The price increase is mainly due to rate
adjustments for increased purchased gas costs resulting from
changes in natural gas market conditions.
Fuel for electric generation and Purchased and interchange
power combined for a net increase of $3.2 million or 2.4% for
the first quarter of 1996 compared with the first quarter of
1995. Purchased and interchange power increased $10.5 million
due primarily to higher cost of purchases, reflecting market
conditions and higher purchases due to less plant availability
(as discussed previously). The increased purchased power cost
was partially offset by lower fuel expense of $7.2 million
mainly due to less nuclear output in 1996 because of a planned
nuclear maintenance outage, and lower average fossil fuel cost
due to a new coal transportation contract in July 1995.
Cost of gas purchased and transported for first quarter
1996 compared with first quarter 1995 increased $34.1 million or
34.3% due to higher gas sendout and higher per unit cost of
purchased gas. The higher gas sendout reflects increased gas
sales, while the higher cost of purchased gas reflects changes
in market conditions and gas cost adjustments. (See
Note 1 to the Financial Statements for discussion of the
accounting change for Wisconsin gas costs to more accurately
match cost recovery in revenues.)
Other operation, Maintenance and Administrative and general
expenses together increased $5.5 million or 3.4% compared with
the first quarter 1995. The higher costs are largely due to the
timing of scheduled plant maintenance outages and an ice storm,
partially offset by lower administrative and general costs.
Planned maintenance outages occurred at two major plants in the
first quarter of 1996 compared with only one major plant in the
first quarter of 1995. Of the $14.3 million increase in Other
operation and Maintenance expenses, $9.5 million is due to
additional costs related to the timing of planned outages at
generating plants. Due to an ice storm in late January 1996, an
additional $2 million in maintenance costs were incurred to
bring customers back into service and to repair other damage to
NSP's transmission and distribution system.
Conservation and energy management increased $8.4 million
in the three-month period ended March 31, 1996 compared to the
same period in the prior year due to higher amortization levels
and concurrent rate recovery of deferred electric and gas
conservation and energy management program costs. These higher
amortization levels are consistent with new retail electric and
gas rate adjustment clauses in the Company's Minnesota
jurisdiction effective May 1, 1995, and Nov. 1, 1995,
respectively. Higher amortization levels reflect higher costs
incurred due to increased participation in NSP's conservation
and energy management programs.
Depreciation and amortization increased $2.8 million or
3.9% compared with the first quarter of 1995. The increase is
mainly due to increased plant in service between the two
periods.
Property and general taxes for the first quarter 1996
compared with the first quarter of 1995 decreased $2.2 million
or 3.5% due primarily to property tax adjustments for 1995 which
are payable in 1996.
Utility income taxes for first quarter 1996 compared with
first quarter 1995 increased $4.1 million primarily due to
higher pretax operating income (after interest charges) between
the two periods.
Other income (deductions) - net decreased mainly due to
non-regulated items discussed below.
Allowance for funds used during construction (AFC)
increased $2.2 million to $5.4 million in 1996 largely due to
returns allowed on higher conservation and energy management
expenditures.
Non-regulated Business Results
NSP's non-regulated operations include many diversified
businesses, such as independent power production, gas marketing,
industrial heating and cooling, and energy-related refuse-
derived fuel production. NSP also has investments in affordable
housing projects and several income-producing properties. The
following discusses NSP's diversified business results in the
aggregate.
Operating Revenues and Expenses - The net results of non-
regulated businesses are reported in Other Income (Deductions)-
Net on the Consolidated Statements of Income. Non-regulated
operating revenues increased $38.7 million in 1996, to $121.3
million, largely due to increased gas marketing sales by
Cenerprise. Non-regulated operating expenses increased $46.7
million in 1996 to $127.7 million due to higher gas costs
corresponding with Cenerprise gas sales and increased NRG
project development costs being expensed on potential projects
in 1996, as discussed previously.
Equity Income - NSP has a less-than-majority equity
interest in many non-regulated projects. Consequently, a
large portion of NSP's non-regulated earnings is reported as
Equity in Earnings of Unconsolidated Affiliates on the
Consolidated Statements of Income. Equity income decreased in
the first quarter of 1996 by $2.8 million primarily due to NRG
energy projects in Australia and Germany as discussed
previously, and to lower earnings from a domestic NRG
cogeneration project whose contracts were effectively terminated
in late February 1995.
Non-regulated interest and amortization increased $1.8
million to $4.1 million due to the issuance of $125 million of
long term debt by NRG in January 1996 and issuance of debt for
Eloigne Company projects.
Income Taxes - Income Taxes on Non-regulated Operations and
Non-operating Items reported on the Consolidated Statements of
Income includes income taxes related to non-regulated
businesses. Such income taxes for the first quarter of 1996
were a net benefit of $5.0 million, a $5.0 million decrease over
a net tax expense of $0 in the first quarter of 1995. The
decrease in 1996 is due mainly to lower income from NRG and
Cenerprise, as discussed previously, and to higher income tax
credits from Eloigne Company's affordable housing projects.
NSP's management intends to reinvest the earnings of
international operations indefinitely. Accordingly, U.S. income
taxes and foreign withholding taxes have not been provided on
the earnings of international projects.
Liquidity and Capital Resources
The Company had approximately $168 million in commercial
paper debt outstanding as of March 31, 1996. The Company plans
to keep credit lines of at least 85% of the highest anticipated
level of commercial paper borrowings. Commercial banks
currently provide credit lines of approximately $306 million to
the Company. These credit lines make short-term financing
available in the form of bank loans and support for commercial
paper sales. The Company has regulatory approval for up to $445
million in short-term borrowing levels.
Commercial banks currently provide credit lines of $17
million to wholly owned subsidiaries of the Company. However,
$5.4 million in letters of credit were outstanding, which
reduced the available credit lines at March 31, 1996.
Approximately $11.6 million of those credit lines remained
available at March 31, 1996.
In January 1996, stock options for the purchase of 263,039
shares were awarded under the Company's Executive Long-Term
Incentive Award Stock Plan (the Plan). These options are not
exercisable for approximately twelve months after the award
date. As of March 31, 1996, a total of 1,149,326 stock options
were outstanding, which were considered as potential common
stock equivalents for earnings per share purposes. During the
first three months of 1996, the Company has issued 103,348 new
shares of common stock under the Plan pursuant to the exercise
of options and awards granted in prior years. Under NSP's
Dividend Reinvestment and Stock Purchase Plan, the Company has
issued 161,025 shares of common stock during the first three
months of 1996. During 1996, the Company has issued an
additional 59,621 shares of new common stock to the Employee
Stock Ownership Plan for dividends on Company shares held.
On January 29, 1996, NRG issued $125 million of 7.625
percent unsecured Senior Notes maturing in 2006 to support
equity requirements for projects currently under way and in
development. The Senior Notes were assigned ratings of BBB- by
Standard & Poor's Rating Group and Baa3 by Moody's Investors
Services. See discussion of NRG's recent project developments
at Note 3 to the Financial Statements.
The Wisconsin Company registered $65 million of first
mortgage bonds with the Securities and Exchange Commission in
May 1996. Depending on capital market conditions, the Wisconsin
Company may issue all or a portion of this debt in 1996, for
purchase or redemption of one or more series of outstanding
first mortgage bonds and repayment of outstanding short-term
borrowings incurred in connection with the Wisconsin Company's
continuing construction program. The remainder of the proceeds
would be added to the general funds of the Wisconsin Company.
Part II. OTHER INFORMATION
Item 1. Legal Proceedings
As discussed in the Environmental Contingencies section of
Note 15 to the Company's financial statements in the 1995 Form
10-K, the Environmental Protection Agency or state environmental
agencies have designated the Company as a "potentially
responsible party" (PRP) at several waste disposal sites to
which the Company allegedly sent hazardous materials. In March
1996, the federal government filed suit in U.S. District Court
in Minneapolis seeking to collect at least $1.5 million that
federal agencies have spent investigating and cleaning up a
Brooklyn Park site. The Company is among a group of five
parties designated as a PRP in the suit. The Company has
recorded an estimate of its potential liability for the clean up
of this site.
In April 1996, the Company received a General Notice Letter
from the United States Environmental Protection Agency regarding
the Third Site Superfund Site in Zionsville, Indiana. The
letter alleges the Company is a PRP at the site. The Company is
among over 500 parties designated as a PRP. Management
anticipates that it is likely the Company will be considered de
minimis and qualify for a cash-out payment. The payment is not
expected to be material.
Item 4. Submission of Matters to a Vote of Security Holders
The Annual Meeting of Shareholders of the Company was held
on April 24, 1996, for the purpose of voting on the matters
listed below. Proxies for the meeting were solicited pursuant
to Section 14(a) of the Securities Exchange Act of 1934, as
amended, and there was no solicitation in opposition to
management's solicitations. All of management's nominees for
directors as listed in the proxy statement were elected. The
matters before the meeting and the voting results were as
follows:
1. A proposal to elect four directors to Class I to serve until
the 1999 Annual Meeting of Shareholders and until their
successors are elected and have qualified;
Election Shares
of Directors Voted For Withheld Authority
W. John Driscoll 58,930,004 1,902,677
Dale L. Haakenstad 58,892,682 1,939,999
John E. Pearson 58,918,233 1,914,448
James J. Howard 58,762,373 2,070,307
2. A proposal to elect a director to Class II to serve until
the 1997 Annual Meeting of Shareholders and until a
successor is elected and has qualified;
Election Shares
of Directors Voted For Withheld Authority
G. M. Pieschel 58,973,759 1,858,922
3. A proposal to ratify the appointment of Price Waterhouse LLP
as independent accountants for NSP for 1996;
Shares
Voted For Voted Against Voted Abstain
59,853,138 488,236 491,307
4. A "Shareholder Resolution on Public Image"
Shares
Voted For Voted Against Voted Abstain
4,901,693 44,931,572 2,674,868
The number of broker non-votes on the Shareholder Resolution
was 8,324,547.
Item 5. Other Information
MERGER AGREEMENT WITH WISCONSIN ENERGY CORPORATION
As previously reported in the Company's Current Report on
Form 8-K, dated April 28, 1995 and filed on May 3, 1995, and the
1995 Form 10-K, NSP; WEC; Northern Power Wisconsin Corp., a
wholly owned subsidiary of NSP (New NSP); and WEC Sub Corp., a
Wisconsin corporation and a wholly owned subsidiary of WEC (WEC
Sub) have entered into an Agreement and Plan of Merger (the
"Merger Agreement"), which provides for a strategic business
combination involving NSP and WEC in a "merger-of-equals"
transaction (the Merger Transaction). The Merger Transaction,
which was approved by the shareholders of the constituent
companies at meetings held on September 13, 1995, is expected to
close shortly after all of the conditions to the consummation of
the Merger Transaction, including obtaining applicable regu-
latory approvals, are met or waived. Although the goal of NSP
and WEC is to receive approvals from the regulatory authorities
by the end of 1996, some regulatory authorities have not
established a timetable for their decision. Therefore, it is
possible that the approvals necessary to consummate the merger
may not be obtainable until after 1996.
In the Merger Transaction, as the holding company of the
combined enterprise, Primergy will be registered under the
Public Utility Holding Company Act of 1935, as amended and will
be the parent company of the operations of both NSP (which, for
regulatory reasons, will reincorporate in Wisconsin) and of
WEC's present principal utility subsidiary, Wisconsin Electric
Power Company (WEPCO) which will be renamed "Wisconsin Energy
Company." It is anticipated that, following the Merger
Transaction, the Wisconsin Company will be merged into Wisconsin
Energy Company and that NSP's other subsidiaries will become
subsidiaries of Primergy.
As noted above, pursuant to the Merger Transaction, NSP
will reincorporate in Wisconsin for regulatory reasons. This
reincorporation will be accomplished by the merger of NSP into
New NSP, with New NSP being the surviving corporation and
succeeding to the business of NSP as an operating public
utility. Following such merger, WEC Sub will be merged with and
into New NSP, with New NSP being the surviving corporation and
becoming a subsidiary of Primergy. Both New NSP and WEC Sub
were created to effect the Merger Transaction and will not have
any significant operations, assets or liabilities prior to such
mergers. Under the proposed business combination, current
common stockholders of NSP would receive 1.626 shares of
Primergy common stock for each share of NSP common stock owned,
and current bondholders and preferred stockholders of NSP will
become investors in New NSP.
SUMMARIZED PRO FORMA FINANCIAL INFORMATION (UNAUDITED)
The following summary of unaudited pro forma financial
information reflects the adjustment of the historical
consolidated balance sheets and statements of income of NSP and
WEC to give effect to the Merger Transaction to form Primergy
and a new subsidiary structure. The unaudited pro forma balance
sheet information gives effect to the Merger Transaction as if
it had occurred on that date. The unaudited pro forma income
statement information gives effect to the Merger Transaction as
if it had occurred at the beginning of the period presented.
This pro forma information was prepared from the historical
consolidated financial statements of NSP and WEC on the basis of
accounting for the Merger Transaction as a pooling of interests
and should be read in conjunction with such historical
consolidated financial statements and related notes thereto of
NSP and WEC.
The allocation between NSP and WEC and their customers of
the estimated cost savings, resulting from the Merger
Transaction, net of the costs incurred to achieve such savings,
will be subject to regulatory review and approval. None of the
estimated cost savings, the costs to achieve such savings or the
transaction costs have been reflected in the summarized pro
forma financial information. A $143 million pro forma
adjustment has been made to conform the presentations of
noncurrent deferred income taxes in the summarized pro forma
combined balance sheet information as a net liability. The pro
forma combined earnings per common share reflect pro forma
adjustments to average common shares outstanding in accordance
with the stock conversion provisions of the Merger Agreement.
The following information is not necessarily indicative of
the financial position or operating results that would have
occurred had the Merger Transaction been consummated on the
date, or at the beginning of the periods, for which the Merger
Transaction is being given effect nor is it necessarily
indicative of future operating results or financial position.
The summarized Primergy pro forma financial information reflects
the combination of the historical financial statements of NSP
and WEC after giving effect to the Merger Transaction to form
Primergy. The summarized New NSP pro forma financial
information reflects the adjustment of the historical financial
statements of NSP to give effect to the Merger Transaction,
including the reincorporation of NSP in Wisconsin, the merger of
the Wisconsin Company into Wisconsin Energy Company, and the
transfer of ownership of all of the current NSP subsidiaries to
Primergy.
Pro Forma
PRIMERGY CORP: NSP WEC Combined
(in millions, except per share amounts)
As of March 31, 1996:
Utility Plant-Net $4,321 $2,907 $7,228
Current Assets 838 502 1,340
Other Assets 1,222 1,129 2,208
Total Assets $6,381 $4,538 $10,776
Common Stockholders'
Equity $2,066 $1,893 $3,959
Preferred Stockholders'
Equity 241 30 271
Long-Term Debt 1,668 1,356 3,024
Total Capitalization 3,975 3,279 7,254
Current Liabilities 998 400 1,398
Other Liabilities 1,408 859 2,124
Total Equity &
Liabilities $6,381 $4,538 $10,776
For the Three Months Ended
March 31, 1996:
Utility Operating Revenues $719 $495 $1,214
Utility Operating Income $89 $85 $174
Net Income, after Preferred
Dividend Requirements $64 $63 $127
Earnings per Common Share:
As reported $.94 $.57 --
NSP Equivalent Shares -- -- $.93
Primergy Shares -- -- $.57
Merger
Divestitures Pro Forma
NEW NSP: NSP Net New NSP
(in millions)
As of March 31, 1996:
Utility Plant-Net $4,321 ($695) $3,626
Current Assets 838 (295) 543
Other Assets 1,222 (527) 695
Total Assets $6,381 ($1,517) $4,864
Common Stockholder's
Equity $2,066 ($722) $1,344
Preferred Stockholder's
Equity 241 -- 241
Long-Term Debt 1,668 (482) 1,186
Total Capitalization 3,975 (1,204) 2,771
Current Liabilities 998 (134) 864
Other Liabilities 1,408 (179) 1,229
Total Equity &
Liabilities $6,381 ($1,517) $4,864
For the Three Months Ended
March 31, 1996:
Utility Operating Revenues $719 ($72) $647
Utility Operating Income $89 ($19) $70
Net Income, after Preferred
Dividend Requirements $64 ($15) $49
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
The following Exhibits are filed with this report:
10.01 Mid-continent Area Power Pool (MAPP) Agreement,
dated March 31, 1972, with amendments in 1994 and
1996, between the local power suppliers in the North
Central States area.
27.01 Financial Data Schedule for the three months ended
March 31, 1996.
99.01 Statement pursuant to Private Securities Litigation
Reform Act of 1995.
(b) Reports on Form 8-K
The following reports on Form 8-K were filed either during
the three months ended March 31, 1996, or between March 31, 1996
and the date of this report:
January 18, 1996 (Filed January 18, 1996) - Item 5. Other
Events. Release of 1995 financial results of NRG Energy,
Inc., a wholly owned subsidiary of the Company.
March 1, 1996 (Filed March 1, 1996)- Item 5. Other Events.
Disclosure of new reporting category for the Company's
electric commercial and industrial customers, and electric
and gas operating statistics for 1995.
April 16, 1996 (Filed April 18, 1996) - Item 5. Other
Events. Disclosure of suspension of negotiations with the
Mescalero Apache Tribe (the Tribe) by a consortium of
utilities, including the Company, for interim storage of
used nuclear fuel on the Tribe's reservation in New Mexico.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
NORTHERN STATES POWER COMPANY
(Registrant)
(Roger D. Sandeen)
Roger D. Sandeen
Vice President, Controller and
Chief Information Officer
(Edward J. McIntyre)
Edward J. McIntyre
Vice President and Chief
Financial Officer
Date: May 15, 1996
EXHIBIT INDEX
Method of Exhibit
Filing No. Description
DT 10.01 Mid-continent Area Power Pool
(MAPP) Agreement with
amendments
DT 27.01 Financial Data Schedule
DT 99.01 Statement pursuant to Private
Securities Litigation Reform
Act of 1995
DT = Filed electronically with this direct transmission.
MID-CONTINENT AREA POWER POOL AGREEMENT AS AMENDED EXHIBIT 10.01
MID-CONTINENT AREA POWER POOL AGREEMENT
PREAMBLE
THIS AGREEMENT, made and entered into as of the 31st day of
MARCH, 1972, by and between the signatories hereto, herein
referred to individually as a "Party" or collectively as
"Parties" and with the Parties further herein referred to as
"Participants" and "Associate Participants" as defined in
Article IV, as amended thereafter including additional
signatories since 1972.
WITNESSETH
0.01 WHEREAS the Parties are engaged in the electric
utility business; and
0.02 WHEREAS the systems of the Parties are interconnected
by transmission facilities and are operated in synchronism
pursuant to a number of power pooling interconnection
agreements; and
0.03 WHEREAS an extensive network of high voltage
transmission facilities has been developed by the
interconnection of such transmission facilities between the
systems of the Parties; and
0.04 WHEREAS the Parties desire to continue to participate
in a regional power pool coextensive with such interconnected
transmission facilities to further enhance the reliability and
other benefits of interconnected operations and to provide
further opportunities to coordinate the installation and
operation of generation and transmission facilities on the
respective systems of the Parties; and
0.05 WHEREAS all the present Parties that were signatory to
the Mid-Continent Area Reliability Coordination Agreement
(MARCA) are also Participants of the Mid-Continent Area Power
Pool; and
0.06 WHEREAS the Parties that are members of MARCA have
dissolved that Agreement and have included the necessary
functions from MARCA in the Mid-Continent Area Power Pool
Agreement;
NOW, THEREFORE, the Parties agree to enter into this
Agreement for the operation of the Mid-Continent Area Power
Pool, hereinafter call "MAPP," in accordance herewith.
ARTICLE I
OBJECTIVES
1.01 The objective of this Agreement is to provide reliable
and economical electric service to the customers of each of the
Parties consistent with reasonable utilization of natural
resources and effect on the environment. In order to accomplish
such purposes, the Parties shall endeavor to coordinate the
installation and operation of generation and transmission
facilities. However, each Party has the right and obligation,
regardless of size or type of organization, to own or otherwise
provide the facilities required to provide its electric service
requirements. Each and all of the provisions of this Agreement
are considered reasonably necessary in order to furnish a basis
for the Parties reaching an agreement to accomplish these
objectives.
ARTICLE II
TERM OF AGREEMENT
2.01 This Agreement shall become effective on the first of
the month next following sixty (60) days after acceptance for
filing of this Agreement by the Federal Energy Regulatory
Commission and shall not become effective if such acceptance is
not received within 180 days of the execution of this Agreement.
2.02 This Agreement and amendments thereto shall be of no
force or effect for a Participant which is a borrower from the
Rural Electrification Administration and which requires Rural
Electrification Administration approval thereof unless such
approval is obtained within 180 days of the date of execution
thereof by such borrower.
2.03 Any Participant may terminate its participation in
this Agreement by four years written notice to the other Parties
hereto. Any Associate Participant may terminate its
participation in this Agreement by ninety (90) days written
notice to the other Parties hereto.
2.04 In the event a Participant fails to perform its
obligations pursuant to this Agreement, the Management Committee
shall give written notice to such Participant specifying such
failure to perform and establishing such reasonable period as
such Participant shall have to fulfill its obligations pursuant
to this Agreement. In accordance with such notice, the
Management Committee shall review the performance of such
Participant and if the failure to perform its obligation is
continuing, the Management Committee may thereupon terminate
such Participant's participation. This provision shall not
limit the right of any other Participant to enforce the rights
and obligations established pursuant to this Agreement.
2.05 If any of the transmission facilities of a terminating
Participant are required for the continuing stability and
reliability of the interconnected systems of the remaining
Participants, such terminating Participant as to the affected
facilities shall continue to be subject to the requirements
relating to stability and reliability which are in effect at the
time of termination. This obligation shall continue only for as
long as the affected facilities continue to be interconnected,
directly or indirectly, with the system of any continuing
Participant, but for no longer a period than the remaining
Participants may reasonably and with due diligence require to
permit the establishment of alternative arrangements for
stability and reliability, but for no longer than four years
from the date of notice issued pursuant to Paragraph 2.03 or
from the date of termination by the Management Committee
pursuant to Paragraph 2.04.
2.06 Any Participant terminated as provided in Paragraph
2.04 shall continue to fulfill its obligations pursuant to any
power transaction under the Service Schedules until the
completion of such power transaction.
2.07 Any terminated or terminating Participant will
continue, or enter into, an agreement contemplated by Article XV
on such terms and conditions and for such annual payment as
shall be established between the Management Committee and the
Contractor. The annual payment shall be such share of the total
payment for services provided by the Contractor reasonably
related to the continuing obligation of the terminated or
terminating Participant and shall include for a period not
exceeding ten (10) years any unsatisfied portion of any payment
measured by investment in facilities or equipment committed by
such Contractor to provide services from the Coordination Center
when such commitment was made and the measure of payment
established between the Management Committee and the Contractor
prior to notice of default or termination.
ARTICLE III
DEFINITIONS
For the purposes of this Agreement and of the Service
Schedules which are a part hereof, the following definitions
shall apply:
3.01 Firm Energy shall mean energy intended to be supplied
at all times.
3.02 System Demand of a Party shall mean that number of
kilowatts which is equal to the kilowatt-hours required in any
clock hour, attributable to energy required by such Party during
such hour for supply of Firm Energy to the Party's consumers,
including system losses, and also including any transmission
losses occurring on other systems supplied by such party for
transmission of such Firm Energy, but excluding generating
station uses, excluding transmission losses supplied by another
system, and excluding Interruptible Load Replacement Energy as
provided for in Service Schedule "L."
3.03 Annual System Demand of a Party shall mean the highest
System Demand of such Party occurring during the 12-month period
ending with the current month.
3.04 Certified Interruptible Demand shall mean the quantity
of kilowatts which is equal to the kilowatt-hours in any clock
hour that can be removed from a Party's system under control of
the Party. Such quantities shall be certified by the Party to
the Engineering Committee for each month according to
requirements the Engineering Committee may establish.
3.05 Net Generating Capability of a Participant for any
month shall mean that amount of kilowatts, less station use,
that all the generating facilities of such Participant could
normally supply simultaneously to its system and the
interconnected systems of the Participants at the time of such
Participant's maximum System Demand for such month under such
conditions as may be established by the Engineering Committee.
The capability of the generating units of a Participant which
are temporarily out of service for maintenance or repair shall
be included in the Net Generating Capability of such
Participant.
3.06 Accredited Capability of a Participant for any month
shall mean (a) the Net Generating Capability of such
Participant, plus (b) the value in kilowatts assigned to such
Participant's purchases under Service Schedules "A," "B," "H,"
"I," "J," and "K," hereof, and to commitments for power from
electric suppliers under separate contracts now existing or
hereafter created, and minus (c) the value in kilowatts assigned
to any commitment of such Participant to deliver power to
another Participant under Service Schedules "A," "B," "H," "I,"
"J," and "K," hereof, or to any electric supplier or suppliers
pursuant to any valid order or under separate contract or
contracts now existing or hereafter created. The Accredited
Capability of such Participant will be determined and assigned
by the Engineering Committee in accordance with the provisions
of Paragraph 16.03 hereof.
3.07 Available Accredited Capability of a Participant shall
mean its Accredited Capability adjusted for generating capacity
out of service for maintenance or repair.
3.08 Reserve Capacity of a Participant for any month shall
mean the excess in kilowatts of each Participant's Accredited
Capability above such Participant's maximum System Demand for
such month.
3.09 Reserve Capacity Obligation of a Participant shall be
the capacity which that Participant is obligated to reserve and
use for the purpose of maintaining continuity of service.
3.10 Spinning Reserve shall mean the amount of unloaded
generating capability of a Participant connected to and
synchronized with the interconnected system of the Participants
and ready to take load. Spinning Reserve allocation to any
generator shall not exceed the amount of generation increase
that can be realized in ten (10) minutes.
3.11 Non-Spinning Reserve shall mean all unloaded
generating capability not meeting the Spinning Reserve criteria
(Paragraph 3.10) that can be made fully effective in ten (10)
minutes.
3.12 Operating Reserve shall mean the sum of Spinning and
Non-Spinning Reserve.
3.13 Operating Reserve Obligation shall mean that amount of
Spinning Reserve and Non-Spinning Reserve which a Participant is
obligated under the terms of this Agreement to provide for the
purpose of maintaining continuity of service.
3.14 Total Operating Reserve Obligation shall be that
amount of Spinning Reserve and Non-Spinning Reserve of the
Participants collectively required to maintain continuity of
service.
3.15 An Emergency Outage shall mean any unanticipated,
unscheduled outage of generating or transmission facilities;
however, such outage classification shall not exceed a period of
six hours.
3.16 A Scheduled Outage shall mean any outage of generating
or transmission facilities which is scheduled in advance for
maintenance and shall include the remainder of an Emergency
Outage which is rescheduled as a Scheduled Outage. Such
rescheduling shall be required within six hours of the
initiation of the Emergency Outage.
3.17 Participation Power shall mean power and associated
energy which is sold or purchased by Participants as provided
for in Service Schedule "A."
3.18 Seasonal Participation Power shall mean power and
associated energy which is sold or purchased by Participants as
provided for in Service Schedule "B."
3.19 System Participation Power shall mean power and
associated energy which is sold or purchased by Participants as
provided for in Service Schedule "K."
3.20 Peaking Power shall mean power and associated energy
which is sold or purchased by Participants as provided for in
Service Schedule "H."
3.21 Short Term Power shall mean power and associated
energy which is sold or purchased by the Participants and
intended to be available at all times during the period covered
by the commitment as provided for in Service Schedule "I."
3.22 Emergency Energy shall mean energy which is supplied
under Service Schedule "C" of this Agreement by any Participant
to any other Participant during and as required by an Emergency
Outage on such other Participant's system which is not supplied
under another provision of this Agreement.
3.23 Scheduled Outage Energy shall mean energy which is
supplied under Service Schedule "C" of this Agreement by any
Participant to any other Participant as a result of a Scheduled
Outage which is not supplied under another provision of this
Agreement.
3.24 Economy Energy shall mean energy which one Participant
may deliver under Service Schedule "E" to another Participant
for the purpose of replacing more expensive energy.
3.25 Interruptible Load Replacement Energy shall mean
energy which is supplied under Service Schedule "L" of this
Agreement by any Participant to another Participant for the
purpose of serving interruptible load.
3.26 Operational Control Energy shall mean energy which is
sold or purchased by the Participants to improve electric system
control and reliability as provided for in Service Schedule "G."
3.27 General Purpose Energy shall mean energy which is
supplied under Service Schedule "M" by any Participant to any
other Participant to enhance economic system operation.
3.28 Average Production Cost per kilowatt-hour of a
generating unit for a month shall be:
a. The total cost of all fuel consumed by the unit
in such month divided by the net kilowatt-hours
produced by the unit in such month, plus
b. An amount, established by the Operating
Committee after annual review, which shall
represent the average monthly production cost,
other than fuel, of the unit, plus
c. An amount, established by the Operating
Committee, which shall represent the cost per
kilowatt-hour of incremental losses on the
supplying Participant's system and on any other
system or systems of electric suppliers not
Participants hereto incurred in delivering power
and energy hereunder.
3.29 Incremental Cost of a supplying Participant to supply
energy to another Participant shall be:
a. The cost of the fuel, operating labor and
maintenance required to generate the energy
necessary to supply (1) the scheduled delivery
to the receiving Participant's system, plus (2)
the incremental losses incurred on the supplying
Participant's system, plus (3) the energy
supplied to any intervening system or systems as
compensation for losses.
b. The cost of starting and operating any
generating units which must be started as a
result of supplying such energy.
c. The supplying Participant's cost of purchased
energy if the purchase is made as a result of
supplying such energy. The incremental cost per
kilowatt-hour for any particular transaction
shall be the total of such costs divided by the
kilowatt-hours scheduled for delivery to the
receiving Participant either directly by the
supplying Participant or through an intervening
system or systems.
3.30 Decremental Cost of a receiving Participant for
avoiding the operation of generating facilities through the
purchase of energy from another Participant shall be:
a. The cost of the fuel, operating labor and
maintenance which such Participant avoided using
by means of such purchase.
b. The cost of starting and operating of a
generating unit or units which such Participant
avoided by means of such purchase.
The decremental cost per kilowatt-hour shall be the total
of such costs divided by the number of kilowatt-hours scheduled
for delivery to the receiving Participant either directly by the
supplying Participant or through an intervening system or
systems.
3.31 Latest Base Load Unit shall mean a single turbine
generator unit declared by the Participant to be either its most
recent wholly owned or leased and controlled capacity addition,
or its most recent wholly owned or leased and controlled share
of a jointly owned unit.
3.32 Transmission Service is the transfer of electricity by
a Participant over its transmission system for another
Participant, pursuant to Service Schedule "F."
3.33 Contractor shall be MAPPCOR, a Minnesota non-profit
corporation, or other such entity as may be selected by the
Management Committee pursuant to Paragraph 15.01 of this
Agreement.
3.34 Coordination Transactions are transactions between
electric utility systems for the purpose of achieving short-term
cost savings, providing assistance in emergency situations, or
coordinating operating procedures and maintenance schedules.
3.35 Control Area shall mean a system capable of regulating
its generation in order to maintain its interchange schedule
with other systems and contribute its frequency bias obligation
to the interconnected system. A system shall qualify as a
Control Area by meeting the criteria for control areas
established by the North American Electric Reliability Council
and by being recognized by the North American Electric
Reliability Council as a control area.
ARTICLE IV
PARTICIPANTS AND ASSOCIATE PARTICIPANTS
4.01 Any entity engaged in the electric utility business:
a. Which owns or leases and controls the operation
of one or more generating units, and which
regularly operates such unit or units to meet
all or part of its system load; and
b. Whose system is normally operated directly
interconnected with one or more Participants at
a voltage level and interconnection capacity so
as to enable it to meet its obligations under
this Agreement or enters into contractual
arrangements to have its system so
interconnected; and
c. Which operates or participates in the operation
of a twenty-four hour dispatch center with a
terminal on the MAPP communication network
connecting the Participants or enters into
contractual arrangements for such service; and
d. Which maintains during each month Accredited
Capability in an amount equal to or greater than
its maximum System Demand for such month plus
Participant's Reserve Capacity Obligation as
defined and determined pursuant to the terms of
this Agreement;
may become a Party to this Agreement as a Participant.
4.02 Electric utilities which meet the qualifications for
Participant membership as set forth in Paragraph 4.01 but elect
not to become a Participant and electric utilities which do not
meet the qualifications for Participant membership as set forth
in Paragraph 4.01 may execute this Agreement as Associate
Participants and participate herein as set forth for Associate
Participant.
ARTICLE V
PARTICIPATION IN NORTH-AMERICAN ELECTRIC
RELIABILITY COUNCIL (NERC)
5.01 The North-American Electric Reliability Council which
was incorporated on October 15, 1975, has nine member regions,
one of which is MARCA. Each region is responsible to appoint
two members to the NERC Board of Trustees and other
representatives to Engineering and Operating Committees and
working groups as established by the Board of Trustees. Since
MARCA has been terminated and MAPP has assumed the reliability
functions of MARCA, MAPP shall assume the previous MARCA
membership in NERC and will participate in NERC activities as
required to adequately represent the MAPP membership.
Representatives to the NERC Board of Trustees and other NERC
committees shall be appointed by the MAPP Management Committee.
Expenses of those representatives while representing MAPP at
NERC functions shall be reimbursed from funds provided by the
MAPP Coordination Center and allocation procedure.
ARTICLE VI
RELATION TO OTHER AGREEMENTS AND OBLIGATIONS
6.01 Each Party represents that there are no conditions in
such Party's existing agreements, including financing
agreements, which will preclude such Party from performance of
all obligations hereunder; and further, each Party agrees not
to enter into an agreement which will preclude performance
hereunder. The failure by any Party to get approval under any
financing agreement for entering into a contract, or amending or
terminating any existing agreement, shall not excuse performance
hereunder.
6.02 The execution of this Agreement shall not impair,
amend, or change any previous contracts or agreements and such
contracts and agreements shall continue, including all rates,
terms and conditions until the expiration of such contracts and
agreements.
ARTICLE VII
COMMITTEE ORGANIZATION
7.01 The committee organization under this Agreement shall
include a Management Committee, Executive Committee, Engineering
Committee, Operating Committee, Design Review Committee,
Environmental Committee, Area Relations Committee and such other
committees as may be established by the Management Committee
from time to time.
7.02 The expenses of each committee member shall be borne
by the represented Party.
7.03 Committee expenses, other than those described in
Paragraphs 5.01 and 7.02 shall be shared in a manner agreed to
by the affected Parties.
7.04 Minutes of all committee meetings shall be recorded
and copies thereof distributed in accordance with procedures
established by the Management Committee.
ARTICLE VIII
MANAGEMENT COMMITTEE
8.01 The Management Committee shall consist of one
representative selected by each Participant. Each Participant
shall designate the person who shall act as its representative
by written notice to the MAPP Secretary provided under Paragraph
8.04. By similar notice, a Participant may change its
representative on the Management Committee and also designate an
alternate representative to act in the absence of the designated
representative. Each Associate Participant may designate, by
written notice to the MAPP Secretary, a representative as a non-
voting member of the Management Committee.
8.02 The Management Committee shall administer this
Agreement to accomplish the objectives of MAPP.
8.03 The Management Committee shall hold an annual meeting
during the last month of the fiscal year at such time and place
as the Chairman shall designate and shall hold meetings at other
times at the call of the Chairman or upon call of three or more
Committee members. At least ten (10) days written notice shall
be given to each member of the Management Committee of any
meeting of such Committee. The notice shall state the time and
place of the meeting and shall include an agenda of the items to
be considered. Except by unanimous consent of those present, no
action shall be taken on any item other than those included on
the agenda.
8.04 The Management Committee, at its annual meeting, shall
elect three officers who shall serve until the next annual
meeting. They shall be a Chairman and a Vice Chairman elected
from the representatives of the Participants on the Committee,
also, a secretary, herein called "MAPP Secretary," who need not
be a member of the Committee. The Chairman shall not serve for
more than two consecutive terms.
8.05 The duties of the Management Committee include but
are not limited to the following:
a. Supervise the development of plans and
procedures that will result in attainment of the
objectives of this Agreement.
b. Specify the duties and authority, other than set
forth herein, of the Engineering Committee, the
Operating Committee, the Design Review
Committee, the Environmental Committee, the Area
Relations Committee and other committees which
may be established by the Management Committee.
c. Make such administrative arrangements as may be
required pertaining to matters which are
pertinent to this Agreement but which are not
specifically covered herein including the
establishment of a fiscal year.
d. Review and rule on appeals from Executive
Committee decisions filed pursuant to the
provisions of Paragraph 9.04.
e. Review and rule on appeals from Engineering and
Operating Committees as provided for in
Paragraphs 10.08 and 11.06 respectively.
f. Provide representation to the NERC Board of
Trustees and participate in its functions.
g. Review and approve an annual operating budget
for the MAPP Coordination Center and Committee
activities.
h. Establish the Reserve Capacity Obligation of
each Participant.
i. Establish total Operating Reserve Obligation and
formula for the Operating Reserve Obligation of
each Participant.
j. Review and approve recommendations of the Design
Review Committee.
8.06 Each Participant on the Management Committee shall be
entitled to the number of votes determined by the following
formula:
a. One vote for each 25 megawatts, or fraction
thereof, of Annual System Demand up to 300
megawatts.
b. One vote for each 50 megawatts, or fraction
thereof, of Annual System Demand from 301 to 600
megawatts.
c. One vote for each 100 megawatts, or fraction
thereof, of Annual System Demand over 600
megawatts.
A Participant's Annual System Demand shall be counted
only once in determining voting allocation.
8.07 A majority affirmative vote of the total authorized
votes is required to authorize any action, determination, or
recommendation of the Management Committee. Any such action,
determination, or recommendation of the Management Committee
shall be binding on the Parties thirty (30) days after the vote
thereon unless any Participant or Participants who vote against
such action, determination, or recommendation invoke the
arbitration provision set forth in Article XXX.
ARTICLE IX
EXECUTIVE COMMITTEE
9.01 The Executive Committee shall consist of not less than
nine voting members including the Chairman and Vice Chairman of
the Management Committee, a representative from the Western
Area Power Administration, a representative of the MAPP
Participant utility allocated the largest portion of the MAPP
Annual Budget and a representative from each of any other MAPP
Participant utilities allocated 20% or more of the MAPP Annual
Budget, plus additional voting members elected by and from the
Management Committee representatives. The other number of
voting members of the Executive Committee shall be elected by
and determined by the Management Committee. The Executive
Committee shall be representative of the membership; factors to
be considered are size and type of corporate organization and
geographic area covered. Any state or province in which at
least ten percent (10%) of the pool load is located shall be
represented by not less than one Participant representative on
the Executive Committee. The Chairman and Vice Chairman of the
Management Committee shall also be the Chairman and Vice
Chairman of the Executive Committee. The MAPP Secretary and a
representative of the Contractor under Article XV shall be non-
voting members of the Executive Committee.
9.02 Between meetings of the Management Committee, the
Executive Committee shall have the duties of the Management
Committee except those under Article XV and Paragraph 8.05 b, d,
e, f, g, h, i and j, subject to appeal pursuant to the
provisions of Paragraph 9.04.
9.03 The Executive Committee shall hold an annual meeting
within six months after the annual meeting of the Management
Committee at such time and place as the Chairman shall designate
and shall hold other meetings in accordance with a schedule
adopted by the Executive Committee or at the call of the
Chairman or upon call of two or more members of the Executive
Committee. At least ten (10) days written notice shall be given
to each member of the Executive Committee of any meeting of such
Committee.
9.04 An affirmative vote of two-thirds of the voting
representatives on the Executive Committee is required to
authorize any action, determination or recommendation of the
Executive Committee. Any action, determination or
recommendation adopted by the Executive Committee may be
appealed to the Management Committee by one or more of the
Participants; provided that, the sum of the Annual System
Demands of such appealing Participant or Participants for the
immediately preceding fiscal year is at least equal to one
percent (1%) of the sum of the Annual System Demand of all
Participants for such fiscal year. Such appeal shall be made by
filing a notice of appeal with the MAPP Secretary within thirty
(30) days after mailing of the written notice under Paragraph
9.05. The filing of a notice of appeal as aforesaid shall
suspend such action, determination or recommendation pending
action thereon by the Management Committee.
9.05 The MAPP Secretary shall send written notice to each
member of the Management Committee of any action taken by the
Executive Committee prior to the end of the fifth business day
following the meeting of the Executive Committee at which such
action was taken.
ARTICLE X
ENGINEERING COMMITTEE
10.01 The Engineering Committee shall consist of one
representative of each Participant designated by such
Participant's representative on the Management Committee by
written notice to the MAPP Secretary. By similar notice, a
Participant may change its Engineering Committee representative
and also designate an alternate Engineering Committee
representative to act in the absence of the designated
representative. Each Associate Participant may designate, by
written notice to the MAPP Secretary, a representative as a non-
voting member of the Engineering Committee.
10.02 The Engineering Committee, under the direction of
the Management Committee, shall administer the planning and
design reliability functions for the bulk power supply pursuant
to this Agreement.
10.03 The Engineering Committee shall hold an annual
meeting in the first quarter of each year and shall hold other
meetings at other times upon call of the Chairman or upon
request of three or more Participant members. At least ten (10)
days written notice shall be given to each member of the
Engineering Committee of any meeting of such Committee. The
notice shall state the time and place of the meeting and shall
include an agenda of items to be considered. Except by
unanimous consent of those present, no action shall be taken on
any item other than those included on the agenda.
10.04 The Engineering Committee, at its annual meeting,
shall elect two officers who shall serve until the next annual
meeting. They shall be a Chairman and Vice Chairman elected
from the representatives of the Participants on the Committee.
The Chairman shall not serve for more than two consecutive
terms. A person from the staff of the MAPP Coordination Center
shall serve as its Secretary and shall be a non-voting member.
10.05 The duties of the Engineering Committee shall
include, but shall not be limited to the following:
a. Establish and revise as necessary, design
reliability standards for the bulk power supply
of MAPP, and coordinate such standards with
regional power coordinating groups.
b. Conduct periodic overall system reliability
studies as required.
c. Recommend revisions to the Reserve Capacity
Obligation of the Participants as periodically
required, to the Management Committee.
d. Establish annually a plan for the ensuing ten
(10) years or longer period covering:
i. The size and type of the generating units
to be installed, and the voltage and
capacity of each transmission facility 115
Kv and above, where such facilities would
have a significant effect upon MAPP area
reliability,
ii. The location of such facilities,
iii. The time when such facilities are to be
placed in operation,
iv. The entity or entities installing such
facilities, and
v. The contracted purchases and sales by
Participants.
e. Review on a continuing basis, the load and
capability forecasts which take into account
conservation and load management plans of the
Parties as reported by the MAPP Coordination
Center and take the necessary action therewith
in accordance with Article XVI.
f. Coordinate the MAPP bulk power production and
transmission system development with adjoining
systems, pools and regional power coordinating
groups.
g. Establish and revise rules relating to the
effect of abnormal conditions on System Demand
and Reserve Capacity Obligation.
h. Establish and revise rules for the
determination of Accredited Capability of the
Participants.
i. Cause studies to be made as necessary for
administration of its duties hereunder.
j. Establish procedures for the use of Service
Schedules, including the use of Service Schedule
"F" for capacity transactions.
k. Review and recommend changes to the Service
Schedules to the Management Committee.
l. Recommend to the Management Committee,
representation to the NERC Engineering Committee
and participate in its functions.
m. Prepare and publish schedules of the
Transmission Service schedule charges, in
accordance with Service Schedule "F".
10.06 The Engineering Committee may establish
subcommittees and assign duties consistent with this Agreement
and policies of the Management Committee.
10.07 The Engineering Committee shall recommend to the
Management Committee, planning functions which should be
assigned to the MAPP Coordination Center to improve reliability
and economy. Such recommendations shall be provided to the
General Manager, MAPP Coordination Center to facilitate
preparation of budget recommendations.
10.08 Any action of the Engineering Committee shall be
taken only if seventy percent (70%) or more of the total
authorized votes, as provided in the formula in Paragraph 8.06,
are present at a meeting. Any action approved by at least
ninety percent (90%) of the total authorized votes present shall
become effective immediately. If less than a ninety percent
(90%) vote, any action receiving an affirmative vote of at least
two-thirds of the total authorized votes present shall become
effective after thirty (30) days unless it is appealed to the
Management Committee. Within five business days of any action
receiving less than ninety percent (90%) vote by the Engineering
Committee, the Committee Secretary shall give written notice
thereof to the members of the Engineering Committee. Notice of
any appeal therefrom shall be filed with the MAPP Secretary
within ten (10) days of mailing of said notice of action. The
submittal to the Management Committee shall include such
alternative proposals as any Participant may request.
ARTICLE XI
OPERATING COMMITTEE
11.01 The Operating Committee shall consist of one
representative of each Participant designated by such
Participant's representative on the Management Committee by
written notice to the MAPP Secretary. By similar notice, a
Participant may change its Operating Committee representative
and also designate an alternate representative to act in the
absence of the designated representative. Each Associate
Participant may designate, by written notice to the MAPP
Secretary, a representative as a non-voting member of the
Operating Committee.
11.02 The Operating Committee, under the direction of
the Management Committee, shall be responsible for establishing
such practices, rules and procedures as may be required to
coordinate the operations and pool energy accounting of the bulk
power generation and transmission facilities of the Parties
pursuant to this Agreement.
11.03 The Operating Committee shall hold an annual
meeting in the first quarter of each year and shall hold other
meetings at others times upon call of the Chairman or upon
request of three or more Participant members. At least ten (10)
days written notice shall be given to each member of the
Operating Committee of any meeting of such Committee. The
notice shall state the time and place of the meeting and shall
include an agenda of the items to be considered. Except by
unanimous consent of those present, no action shall be taken on
any item other than those included on the agenda.
11.04 The Operating Committee, at its annual meeting,
shall elect two officers who shall serve until the next annual
meeting. They shall be a Chairman and Vice Chairman elected
from the representatives of the Participants on the Committee.
The Chairman shall not serve for more than two consecutive
terms. A person from the staff of the MAPP Coordination Center
shall serve as its Secretary and shall be a non-voting member.
11.05 The duties of the Operating Committee shall
include, but shall not be limited to the following:
a. Coordinate the operation of the bulk power
generation and transmission facilities of the
Parties so as to effect optimum reliability and
economy of service.
b. Establish methods, standards, and procedures for
the determination of costs associated with
transactions hereunder.
c. Periodically review the Total Operating Reserve
Obligation and the formula for establishing the
Operating Reserve Obligation of a Participant
and make recommendations to the Management
Committee for revisions as required.
d. Collect and analyze operating data pertinent to
the interconnected operation of the systems of
the Participants and arrange for conducting such
transmission network studies as may be necessary
in the performance of its duties hereunder.
e. Review and approve the coordinated
maintenance schedules of the Participants as
provided by the MAPP Coordination Center to
assure at all times satisfying the Total
Operating Reserve Obligation.
f. Establish procedures for the use of the Service
Schedules, including the use of Service Schedule
"F" for energy transactions.
g. Review and recommend changes to the Service
Schedules to the Management Committee.
h. Determine and periodically review the procedures
to be followed by the Participants in restoring
the Total Operating Reserve Obligation in the
event of a large generator failure or other
comparable contingency.
i. Coordinate the periods and methods of reporting
scheduled and actual power and energy flows.
j. Establish methods and procedures for accounting
and billing of bulk power and energy
interchanges and Transmission Services
hereunder.
k. Establish operating reliability standards,
criteria and rules relating to protective
equipment, switching, voltage control, system
control performance, load shedding, emergency
and restoration procedures and the operation and
maintenance of generation and transmission
facilities of the Participants necessary to
assure the reliable operation of the MAPP
systems.
l. Establish procedures and practices for
coordinating the power pool operation activities
of MAPP with adjoining systems, pools and other
regional power coordination agencies.
m. Recommend to the Management Committee
representation to the NERC Operating Committee
and participate in its functions.
n. Recommend to the Management Committee the power
pool operating functions which should be
conducted at the MAPP Coordination Center to
improve reliability and economy. Such
recommendations shall be provided to the General
Manager, MAPP Coordination Center to facilitate
preparation of budget recommendations.
11.06 Any action of the Operating Committee shall be
taken only if seventy percent (70%) or more of the total
authorized votes, as provided in the formula in Paragraph 8.06,
are present at a meeting. Any action approved by at least
ninety percent (90%) of the total authorized votes present shall
become effective immediately. If less than a ninety percent
(90%) vote, any action receiving an affirmative vote of at least
two-thirds of the total authorized votes present shall become
effective after thirty (30) days unless it is appealed to the
Management Committee. Within five business days of any action
receiving less than ninety percent (90%) vote by the Operating
Committee, the Committee Secretary shall give written notice
thereof to the members of the Operating Committee. Notice of any
appeal therefrom shall be filed with the MAPP Secretary within
ten (10) days of mailing of said notice of action. The
submittal to the Management Committee shall include such
alternative proposals as any Participant may request.
ARTICLE XII
DESIGN REVIEW COMMITTEE
12.01 The Design Review Committee shall consist of
members representing various Participants appointed by the
Management Committee, one of whom shall be appointed Chairman by
the Management Committee. Members appointed should have
experience in system operation and analysis and be
representative of the geographic area covered. A person from
the staff of the MAPP Coordination Center shall serve as its
Secretary and shall be a non-voting member.
12.02 The Committee shall meet on call of its Chairman
as required to carry out its duties. Committee recommendations
to the Management Committee as well as other committee action
taken, shall be adopted by two-thirds vote of its members.
Minority recommendations may be submitted.
12.03 The Design Review Committee, with assistance of
the staff of the MAPP Coordination Center and in conjunction
with each Participant, shall review and evaluate such
Participant's planning for generation and transmission
facilities for conformance to reliability design standards
established by the Engineering Committee and report their
findings to the Management Committee. Any operating
restrictions necessary to make a Participant's planned
facilities operate within MAPP reliability design standards will
be subject to approval of the Design Review Committee.
12.04 To enable the Design Review Committee to carry
out its tasks, the Participants shall furnish such studies and
data as it shall reasonably request, including but not limited
to, technical studies of system performance, data on current and
projected loads, system equipment capabilities, capability
margins, spinning reserves, relay settings controlling major
facilities, communication facilities, recording facilities and
operating procedures.
ARTICLE XIIA
OPERATING REVIEW COMMITTEE
12A.01 An Operating Review committee is created which,
with assistance of the staff of the Contractor and in
conjunction with each Participant, shall review and evaluate
each Participant's operating studies, guides and practices for
compliance with operating reliability standards, criteria,
rules, methods, and procedures established by the Operating
Committee and report its findings to the Management Committee.
Any operating restrictions necessary to make a Participant's
facilities operate within MAPP systems operating standards
established by the Operating Committee will be subject to
approval by the Operating Review Committee.
12A.02 The Operating Review Committee shall be composed of
nine members; a Chair and Vice Chair appointed by the Management
committee and seven members appointed by the Chair with the
approval of the Management Committee. All members shall serve
for an indefinite term at the pleasure of the Management
Committee. The members of the Operating Review Committee shall
have electric system operating knowledge and experience and
shall be representative of the geographic area served by MAPP.
A staff member of the Contractor shall serve as Secretary of the
Operating Review Committee and shall be a non-voting member
thereof.
12A.03 The Operating Review Committee shall meet at the
call of the Chair as required to carry out its duties, or in
case of the disability of the Chair, at the call of the Vice
Chair. Recommendations of the Operating Review Committee to the
Management Committee and other actions taken shall be by the
affirmative vote of 2/3rds of all of the members. Minority
recommendations may be submitted to the Management Committee.
12A.04 In cases where the Operating Review Committee
determines from available information that a Participant has
failed to comply with established operating standards, it shall
notify the noncompliant Participant in writing. If the
noncompliant Participant does not, within three months after
receipt of the notice, propose a plan acceptable to the
Operating Review Committee to correct the failure, or fails to
comply with the correction plan, the Operating Review Committee
shall report such failure to the Management Committee.
ARTICLE XIII
ENVIRONMENTAL COMMITTEE
13.01 The Environmental Committee shall be appointed by
the Management Committee. In selection of such representatives,
consideration shall be given to geographic representation.
13.02 The Environmental Committee shall hold an annual
meeting in the first quarter of each year and shall hold other
meetings at other times upon call of the Chairman or upon
request of three or more Participant members. At least ten (10)
days written notice shall be given to each member of the
Environmental Committee of any meeting of such Committee. The
notice shall state the time and place of the meeting and shall
include an agenda of the items to be considered.
13.03 The Environmental Committee, at its annual
meeting, shall elect two officers who shall serve until the next
annual meeting. They shall be a Chairman and Vice Chairman
elected from the representatives of the Participants on the
Committee. The Chairman shall not serve for more than two
consecutive terms. A person from the staff of the MAPP
Coordination Center shall serve as its Secretary and shall be a
non-voting member.
13.04 Under the direction of the Management Committee,
the Environmental Committee shall keep abreast of national and
regional matters relating to air quality, water quality, land
use and other environmental factors. The Committee shall also
carry out other functions and activities as assigned or approved
by the Management Committee. Findings and recommendations shall
be reported to the Management Committee.
13.05 The Environmental Liaison Group shall consist of
one representative of each Participant designated by such
Participant's representative on the Management Committee by
written notice to the MAPP Secretary. The Liaison
representative shall serve as the liaison between the
Environmental Committee and each Participant for supplying
information and receiving reports. The Environmental Liaison
Group shall meet with the Environmental Committee as directed by
the Environmental Committee.
13.06 The Environmental Committee may establish
subcommittees and task forces and assign duties as necessary to
carry out its assigned functions.
ARTICLE XIV
AREA RELATIONS COMMITTEE
14.01 The Area Relations Committee shall consist of one
representative from each Participant designated by such
Participant's representative on the Management Committee by
written notice to the MAPP Secretary. By similar notice, a
Participant may change its representative or designate an
alternate to act in place of its representative.
14.02 The Area Relations Committee shall hold an annual
meeting in the first quarter of each year and shall hold other
meetings at other times upon call of the Chairman or upon
request of three or more Participant members. At least ten (10)
days written notice shall be given to each member of the Area
Relations Committee of any meeting of such Committee. The
notice shall state the time and place of the meeting and shall
include an agenda of the items to be considered. Except by
unanimous consent of those present, no action shall be taken on
any item other than those included on the agenda.
14.03 The Area Relations Committee, at its annual
meeting, shall elect two officers who shall serve until the next
annual meeting. They shall be a Chairman and Vice Chairman
elected from the representatives of the Participants on the
Committee. The Chairman shall not serve for more than two
consecutive terms. A person from the staff of the MAPP
Coordination Center shall serve as its Secretary and shall be a
non-voting member.
14.04 Under the direction of the Management Committee,
the Area Relations Committee shall be responsible for advising
the Parties on preparing progress reports, public presentations
and educational materials relating to activities of the Parties
pursuant to this Agreement and shall carry out other functions
and activities as assigned or approved by the Management
Committee.
14.05 The Committee shall meet as required on call of
the Committee Chairman or the Management Committee.
ARTICLE XV
MAPP COORDINATION CENTER
15.01 The Management Committee shall select a
Contractor which will agree to provide various information and
other services, as determined by the Management Committee, to
each of the Participants in order to enhance the attainment of
the goals of this Agreement.
15.02 Consistent with policy and guidelines provided by
the Management Committee, the Contractor shall be an
independent contractor with each of the Participants and will be
responsible for the establishment and operation of a MAPP
Coordination Center hereinafter called "Center." The Contractor
shall provide facilities, manpower, and administration necessary
for such operation.
15.03 Each Participant shall enter into an agreement
with the Contractor providing for services as provided in
Paragraph 15.01 under the terms and conditions and such annual
payment as may be established from time to time between the
Management Committee and the Contractor.
15.04 Each Party shall retain the sole responsibility
for the operation of its system and the utilization of the
information which may be provided from the Center.
15.05 Subject to a determination by the Management
Committee that such action can be taken without prejudicing the
Contractor's fulfillment of its obligations to the Participants
for services from the Coordination Center, the Contractor may
contract with electrical power suppliers which are not parties
to this Agreement for services from the Contractor or with
parties for other services under conditions approved by the
Management Committee.
15.06 In consideration of the services provided by the
Contractor inuring to the Associate Participants, the Associate
Participants shall make payment directly to the Contractor for
their share of the costs of providing such services which shall
be as follows or as subsequently established by the Management
Committee:
$200 for each fiscal year where the Annual
System Demand for the previous fiscal year
is 5,000 kilowatts or less plus $60 for
each 5,000 kilowatts or fraction thereof by
which such Annual System Demand exceeds
5,000 kilowatts, with a maximum of
$10,000.
15.07 The Contractor shall be responsible to maintain
a staff adequate to support the services required by the MAPP
Committees. Such services shall include but not be limited to
gathering of historical data, maintaining a data base for
planning and operating studies, maintaining official records of
the MAPP Committees, administering certain contracts with other
Parties or entities for studies, publishing reports and filing
such reports as required with regulatory bodies, continuously
monitoring the operation of the Pool and the MAPP communications
system, providing assistance in determining potential operating
problems, conducting studies as required, coordinating the
operations of the MAPP Region with adjoining coordinated regions
and others as appropriate, and carrying out projects of the MAPP
Committees as directed.
ARTICLE XVI
MAINTENANCE OF ADEQUATE CAPABILITY
16.01 Each Participant expects and is expected to
maintain utility responsibility for its own load and, as a part
of such responsibility, shall maintain during each month
Accredited Capability in an amount equal to or greater than its
maximum System Demand for such month plus such Participant's
Reserve Capacity Obligation, as set forth in Paragraph 16.02.
16.02 The Reserve Capacity Obligation of a Participant,
for any month, shall be equal to fifteen percent (ten percent
for a predominantly hydro system) of the Annual System Demand of
such Participant or as established by the Management Committee.
16.03 The Engineering Committee shall determine the
Accredited Capability for each Participant on the following
basis:
a. In respect to Net Generating Capability, the
Accredited Capability shall be determined in
accordance with Paragraph 3.07.
b. In respect to purchases and sales under Service
Schedules "A," "B," and "K," the Accredited
Capability shall include the amount for which
the Participant has contracted provided that
such transactions are in accordance with rules
and regulations established by the Engineering
Committee.
c. In respect to purchases and sales under Service
Schedules "H," "I," and "J," the Accredited
Capability shall include the amount for which
the Participant has contracted plus the
associated reserve capacity established from the
percentage determined by the Management
Committee subject to the provisions of Paragraph
2.02 of Service Schedule "I" provided that such
transactions are in accordance with rules and
regulations established by the Engineering
Committee.
d. In respect to commitments for power from or to
any electric power supplier, which are not under
the Service Schedules of this Agreement but are
under separate contracts now existing or
hereafter created, such commitments shall be
reflected in a Participant's Accredited
Capability provided that such transactions are
in accordance with rules and regulations
established by the Engineering Committee. Each
Participant shall submit, if requested, copies
of its contracts for such commitments to the
Engineering Committee for the purpose of such
determination.
Determinations of Accredited Capability shall be reviewed by
the Engineering Committee at least semi-annually and at any
other time upon the written request of any Participant and any
appropriate changes resulting from such review shall be made. In
order to secure consistency and continuity in determining
Accredited Capability, the Engineering Committee shall establish
rules and regulations as necessary These rules and regulations
shall reflect the following understanding:
i. Approval of transactions which are associated
with a coordinated system development, which may
include non-Participants, will be on the basis
of reliability considerations.
ii. Transactions for capability deficiencies which
are residual to subparagraph (i) normally will
be made with Pool Participants and Pool
surpluses normally will be dedicated to such
transactions.
iii. Transactions will not be compelled with a
Participant for power and energy from generating
capacity constructed by a Participant in excess
of capacity recommended by the Engineering
Committee.
16.04 The Engineering Committee shall continually
review the load and capability forecasts for the Participants.
If the forecast of a Participant indicates that, during any
month of the ensuing period, the length of period being
determined by the Engineering Committee, such Participant will
not meet its Reserve Capacity Obligation, such Participant shall
make arrangements to obtain additional Accredited Capability as
approved by the Engineering Committee so that during such month
it will have sufficient capacity to meet its Reserve Capacity
Obligation. In the event that during any month a Participant
did not meet its maximum System Demand plus its Reserve Capacity
Obligation, such Participant shall be required to obtain
additional Accredited Capability from the other Participants.
The amount of Accredited Capability required by the deficient
Participant and the source or sources will be determined by the
Engineering Committee. If Accredited Capability is not
available from Participants, the Engineering Committee may
recommend:
a. Purchase from non-Participants.
b. Other means of sharing Reserve Capacity to
effect equalization of reserves.
16.05 Nothing contained in this Agreement shall be
interpreted to require a Party to install facilities or to
restrict a Party's election of whether to install facilities or
purchase power to maintain its Accredited Capability.
ARTICLE XVII
INSTALLATION OF ADDITIONAL FACILITIES
17.01 It is the intent hereof to provide for an
equitable staggering of future investments in generating
capacity and other facilities in order to obtain maximum economy
and benefits from interconnected system operation. It is
understood that the generating units installed by the
Participants hereafter should be the most economical size and
type practicable, taking into consideration the size of the
installing Participants' systems, the loads of the Participants,
the anticipated growth of such loads, the transmission
facilities required to transmit the output thereof to such loads
or to supply such loads when the unit is not in service and the
ability of the systems of the Participants and their
interconnections with other interconnected systems to withstand
the instantaneous loss of such units without causing unstable
operation. It is also anticipated, that, in general, the amount
and type of additional generating capacity to be installed by
any Participant shall take into consideration the load and the
load growth of such Participant and that the installation of
specific generating units shall be rotated among the
Participants so as to accomplish this overall intent. Whenever
the recommendation of the Engineering Committee is that a
Participant construct and install any additional generating or
transmission facilities, such Participant shall not be deemed
committed to such construction or installation unless it has
elected to accept such recommendation by proper corporate action
reported by its representative on the Management Committee.
17.02 It is understood by the Parties that nothing in
the Agreement is intended to preclude a Participant from
constructing or utilizing generation and transmission facilities
other than those recommended by the Engineering Committee;
however, such facilities shall be subject to the established
reliability standards.
ARTICLE XVIII
MAINTENANCE OF ADEQUATE OPERATING RESERVE
18.01 Each Participant shall provide Spinning Reserve
and Non-Spinning Reserve in the proportions recommended by the
Operating Committee and established by the Management Committee,
equal to or greater than the Operating Reserve Obligation of the
Participant, as provided in Paragraph 18.02. As soon as
practicable after the occurrence of an incident which utilizes
Operating Reserve, each Participant shall restore its Operating
Reserve Obligation by following procedures determined by the
Operating Committee.
18.02 The Total Operating Reserve Obligation at any
time shall initially be an amount equal to 150 percent of the
capability of the largest generating unit in operation on the
interconnected systems of the Participants and shall be subject
to revision by the Management Committee. The Operating Reserve
Obligation of a Participant shall be that percentage of the
Total Operating Reserve Obligation determined by the Operating
Committee in accordance with formula based on the capability of
the largest generating unit of each Participant and the Annual
System Demand of such Participant. Initially one-third weight
shall be given to unit size and two-thirds weight to Annual
System Demand, such weighting shall be subject to revision by
the Management Committee.
18.03 The Operating Committee will establish procedures
for determining the Operating Reserve that is available on the
systems of the Participants at all times. Whenever a
Participant is unable to meet its Operating Reserve Obligation,
such Participant shall immediately advise all other Participants
and make arrangements to restore its Operating Reserve
Obligation.
ARTICLE XIX
SERVICES TO BE RENDERED
19.01 The various specific services to be rendered in
furtherance of the purposes of this Agreement are covered by
Service Schedules of the Agreement which are listed as follows:
"A" Participation Power Interchange Service
"B" Seasonal Participation Power Interchange Service
"C" Emergency and Scheduled Outage Interchange
Service
"D" Operating Reserve Interchange Service
"E" Economy Energy Interchange Service
"F" Transmission Services and Losses
"G" Operational Control Energy Interchange Service
"H" Peaking Power Interchange Service
"I" Short Term Power Interchange Service
"J" Firm Power
"K" System Participation Power
"L" Interruptible Load Replacement Energy Service
"M" General Purpose Energy Service
19.02 The Service Schedules are intended to facilitate
coordinated daily operation and the staggering of generation
additions in accordance with Paragraph 10.05 (d) and Article
XVII and shall not be used to provide power supply from a
generation source for a greater period than that consistent with
Article XVII.
19.03 The providing of Transmission Service under
Service Schedule "F" is based on each Participant providing an
equitable portion of the transmission facilities required to
accomplish the coordinated daily operation and coordinated
planning contemplated hereunder.
a. Participants meeting the following criteria will
be assumed to be providing an equitable share of
transmission:
i. Whose system is normally operated directly
interconnected with two or more
Participants systems.
ii. Which owns or controls transmission
facilities operated at 115 Kv or higher
forming an integral part of the regional
transmission network.
b. All other Participants may meet the
qualifications set forth in (a) through
contractual arrangements with a Participant
which does meet the qualifications and to which
it is interconnected. Participants shall
negotiate such arrangements in good faith and in
doing so shall be expected to permit a
Participant to qualify under this subsection by
making investment in facilities or by making
payments. The investment facilities or payments
shall be calculated to compensate the
Participant for the use of its facilities for
transactions under the Service Schedules. If
two Participants are unable to negotiate a
mutually satisfactory contracting arrangement
within a period of six months after written
notice has been received from the Participant
expressing a desire to enter into such a
contractual arrangement and the Participant
receiving such notice is a public utility within
the meaning of section 201 (e) of the Federal
Power Act, the Participant receiving such notice
shall, at the written request of the other
Participant, made at any time following the
expiration of six month period, file within
sixty (60) days thereafter a contractual
arrangement with the Federal Energy Regulatory
Commission in accordance with the provision of
section 205 of the Federal Power Act and the
Regulations thereunder.
ARTICLE XX
SERVICE OBLIGATIONS
20.01 It is recognized that the systems of the
Participants are now or may be interconnected with other
systems and that other agreements for interconnection, mutual
assistance, pooling, power supply and transmission service may
exist or may be entered into between Participants or between a
Participant and another system. It is understood that the
Participants intend to assist each other to the maximum extent
of their capabilities, but it is recognized that such agreements
may limit the capacities available to Participants under the
terms hereof.
20.02 Any Participant, upon request by any other
Participant, shall supply to such other Participant Emergency
Energy up to the full amount of its Available Accredited
Capability provided that such request conforms with the
provisions of Service Schedule "C."
20.03 Any Participant, upon request by any other
Participant, shall supply to such other Participant Scheduled
Outage Energy up to the full amount of its Accredited Capability
not required to maintain its Operating Reserve Obligation;
provided that the delivery thereof shall conform with the
provisions of Service Schedule "C" and provided further that, if
the requesting Participant is not using its Total Available
Accredited Capability, the Participant requested to supply
scheduled Outage Energy shall not be obligated to supply such
energy when in the sole judgment of such Participant, the supply
of such energy would cause a hardship.
20.04 Any Participant may procure through its
interconnection with other electric suppliers, Emergency Energy
or Scheduled Outage Energy in addition to that which can be
supplied by the Participants which may be available under
agreements covering such interconnections from a source or
sources which will result in the lowest cost to the receiving
Participant and shall arrange for the delivery of such Emergency
Energy or Scheduled Outage Energy to such receiving Participant;
provided that the delivery thereof can be made, in the sole
judgment of the Participant procuring such service, without
endangering its facilities or interfering with its obligations
to its customers, other Participants, or other electric
suppliers.
20.05 Any Participant whose transmission facilities are
required to provide Transmission Service for Emergency Energy
supplied to a receiving Participant shall transmit such energy
up to such amounts as will not, in the sole judgment of the
Participant providing the Transmission Service, endanger its
facilities or interfere with its obligations to its customers,
other Participants, or other electric suppliers.
20.06 Any Participant, upon request by any other
Participant, shall supply to such other Participant, Operating
Reserve up to the full amount of its Available Accredited
Capability not required to maintain its Operating Reserve
Obligation; provided that the delivery thereof shall conform
with the provisions of Service Schedule "D" and provided
further, however, that there shall be no obligation of a
Participant to supply Operating Reserve if the requesting
Participant is not making full use of its Available Accredited
Capability.
20.07 Any Participant, when called upon to do so by any
other Participant, may supply Economy Energy to such other
Participant provided such call conforms with the provisions of
Service Schedule "E."
20.08 Any Participant, when called upon to do so by any
other Participant, may supply Interruptible Load Replacement
Energy to such other Participant, provided such call conforms
with the provisions of Service Schedule "L."
20.09 Any Participant, when called upon to do so by any
other Participant, may supply General Purpose Energy to such
other Participant, provided such call conforms with the
provisions of Service Schedule "M."
20.10 Each Participant agrees that it will provide
Transmission Service in accordance with the provisions of
Section 19.03 and Service Schedule "F." The Participants shall
endeavor to make maximum use of facilities for Pool transactions
consistent with MAPP reliability standards. Nothing herein
shall be construed as obligating any of the Participants to
provide Transmission Service other than for Participants in
accordance with Section 19.03 and Service Schedule "F".
20.11 The service obligations set forth in this Article
are each subject to the limitations that the Participant on
which the request is made as therein stated shall not be
obligated to use Available Accredited Capability if it is at the
time being used to supply the requirements of its customers
including obligations now existing or hereafter created to other
Participants or to other electric suppliers. A Participant
shall not be obligated to deliver power and energy over its
transmission facilities if, in the sole judgment of said
Participant, such delivery will:
a. Endanger its facilities, or
b. Interfere with its obligations, now existing or
hereafter created, to its customers or to other
electric suppliers.
20.12 The Participant purchasing power and energy under
Service Schedules "A," "B," "H," "I," "J," "K," and "L" shall be
responsible for initiating scheduled deliveries thereunder and
the scheduled rate of delivery shall not exceed the amount being
purchased under the Schedule. In the scheduling of deliveries,
due consideration shall be given to the rate of change of
delivery and the continuity of delivery so as not to cause undue
hardship on the system of the supplying Participant.
ARTICLE XXI
SERVICE CONDITIONS
21.01 The systems of the Participants shall be operated
interconnected continuously under normal system conditions and
the Participants shall cooperate in keeping the frequency of the
interconnected systems of the Parties at 60 Hz as closely as is
practicable, in keeping the interchange of power and energy
between the systems of the Participants as closely as is
practicable to the scheduled amounts and in maintaining mutually
satisfactory voltage levels. Each Participant shall be
responsible for the reactive volt-ampere requirements of its
system. Reactive volt-amperes may be interchanged between
systems from time to time, subject to agreement between the
Participants involved, when benefit to one system may be gained
thereby without causing hardship to another system.
21.02 The systems of the Participants shall normally be
so maintained and operated as to minimize, in accordance with
good practice, the likelihood of a disturbance originating in
the system of one Participant causing impairment to the service
of the system of any other Participant or of any other system
with which the systems of the Participants are interconnected.
21.03 It is recognized that unintentional interchange
of power and energy between interconnected systems will occur
because of the impossibility of continuously controlling
generation to exactly equal the load. It also is recognized
that, due to the manner in which the systems of the Participants
are interconnected with each other and with other systems, a
portion of the power and energy scheduled for delivery between
any two of such interconnected systems may not flow directly
from the supplier thereof to the receiver thereof over the
intended route through the transmission systems of the
Participants, but may result in inadvertent flows through other
systems. Therefore, because of these conditions:
a. All intentional power and energy deliveries
between the system of one Participant and the
system of another Participant shall be scheduled
in advance.
b. It shall be the responsibility of each
Participant to maintain the net power and energy
flowing into and out of its system during each
hour so that deliveries are, as near as
practicable, equal to the net scheduled amount.
The difference between the net scheduled
deliveries and the actual net deliveries shall
be balanced out in kind in accordance with
principles and practices established by the
Operating Committee.
c. A Participant shall be entitled to compensation
for losses caused by the flow of power and
energy scheduled from or to another Participant.
Such compensation shall be in the form of an
equivalent amount of energy in accordance with
methods determined by the Operating Committee.
d. It is not the intent to grant any Participant
any right generally to use the system of any
other Participant as an intermediary in power
and energy transactions, nor shall consent by a
Participant to any power and energy flows
through its system in a particular case create
any rights for a Participant to continue such
flows; and, where such flows are objectionable
to a Participant experiencing such flows, the
Participants shall cooperate to prevent such
flows from occurring normally and to minimize
flows of this character.
ARTICLE XXII
METERING
22.01 All metering equipment required for recording the
deliveries of power and energy between the systems of each
Participant and the systems of the other Participants with which
it is interconnected shall be maintained by the Parties owning
such metering equipment in accordance with good practice and
accepted industry standards.
22.02 Should any such metering equipment at any time
fail to register or should the registration thereof be so
erratic as to be meaningless, the power and energy delivered
shall be determined from the best information available.
ARTICLE XXIII
RECORDS
23.01 In addition to meter records, the Participants
shall keep such log sheets and other records (determined by the
Operating Committee) as may be needed to afford a clear history
of the various movements of power and energy between the systems
of the Participants involved both in transactions hereunder and
in transactions between Participants hereto under other
agreements between such Participants and to effect such
differentiation as may be needed in connection with settlements
in respect to such transactions. The originals of all such
meter records and other records shall be open to inspection by
representatives of the Participants concerned and by the
Operating Committee.
23.02 Each Party shall furnish to the Operating
Committee appropriate data from meter registrations and from
other sources on such time basis as are determined by the
Operating Committee when such data is needed for settlements,
special tests, operating records or for other purposes
consistent with the objectives hereof. As promptly as
practicable after the end of each month, each Participant shall
render to the other Participants concerned, statements setting
forth appropriate data from meter registrations and other
sources in such detail and with such segregation as may be
needed for operating records and for settlements hereunder.
ARTICLE XXIV
BILLINGS AND PAYMENTS
24.01 For billing purposes, the amount of energy
delivered pursuant to this Agreement by a supplying Participant
to a receiving Participant, during any period, shall be the
amount scheduled for delivery.
24.02 Billing for any transaction involving generation
or transmission capacity pursuant to this Agreement, including
any Transmission Service charges pertaining to such transaction,
shall be based upon the amount of such capacity committed in
advance for delivery.
24.03 All bills for services supplied pursuant to this
Agreement shall be rendered monthly by the supplying Participant
to the purchasing Participant after the end of the period to
which such bills are applicable. Unless otherwise agreed upon
by the Operating Committee, such period shall be from 12:01 AM
on the first day of the month to 12:01 AM of the first day of
the succeeding month. Bills shall be due and payable within
fifteen days from the date such bills are rendered and payment
shall be made when due and without deduction. Bills shall be
deemed rendered on the postmark date if deposited in first class
mail with postage prepaid and shall be deemed rendered upon
receipt if another means of delivery is used. If the due date
of any bill falls on Saturday, Sunday or holiday observed by
either Party, the bill shall be due and payable on the next
following working day of both Parties. Interest shall accrue and
be compounded daily on any unpaid amount, from the date due
until the date upon which payment is made, using the lowest
daily prime rates published in the money rates section of the
Wall Street Journal for the applicable time period. Such daily
interest shall be computed on the basis of actual days and a 365
day calendar year.
24.04 Billing for Transmission Service shall be
rendered monthly in a manner to be determined by the Operating
Committee.
24.05 In the event a Participant desires to dispute all
or any part of the charges submitted by some other Participant,
it shall nevertheless pay the full amount of the charges when
due and give notification in writing within sixty (60) days from
the date of the statement stating the grounds on which the
charges are disputed and the amount in dispute. The complaining
Participant will not be entitled to any adjustment on account of
any disputed charges which are not brought to the attention of
the Participant rendering such charges within the time and in
the manner herein specified. If settlement of the dispute
results in a refund to the payer, interest shall accrue and be
compounded daily on the amount to be refunded from the date of
payment until the date upon which refund is made, using the
lowest daily prime rates published in the money rates section of
the Wall Street Journal for the applicable time period. Such
daily interest shall be computed on the basis of a 365 day year.
24.06 All billings under this Agreement shall be
determined and stated and all payments shall be made in the
currency of the United States of America. For all billings, the
rate to be used to convert from the currency of the United
States to that of Canada or from the currency of Canada to that
of the United States shall be the monthly average noon spot
exchange rate for the monthly billing period covered by such
billing provided by the Royal Bank of Canada, Winnipeg,
Manitoba.
ARTICLE XXV
TAXES
25.01 Any tax imposed upon the seller and levied upon
or measured by power or energy supplied by one Participant to
another Participant shall be added to the bill rendered by the
Participant supplying the power or energy.
ARTICLE XXVI
UNCONTROLLABLE FORCES
26.01 A Participant shall not be considered to be in
default in respect of any obligation hereunder if prevented from
fulfilling such obligation by reason of uncontrollable forces.
The term "uncontrollable forces" shall be deemed for the
purposes hereof to mean storm, flood, lightning, earthquake,
fire, explosion, failure of facilities not due to lack of proper
care or maintenance, civil disturbance, labor disturbance,
sabotage, war, national emergency, restraint by court or public
authority, or other causes beyond the control of the Participant
affected which such Participant could not reasonably have been
expected to avoid by exercise of due diligence and foresight and
by provision of reserves in accordance with the requirements of
this Agreement. Any Participant unable to fulfill any
obligation by reason of uncontrollable forces will exercise due
diligence to remove such disability with reasonable dispatch,
but such obligation shall not require the settlement of a labor
dispute except in the sole discretion of the Participant
experiencing such labor dispute.
ARTICLE XXVII
WAIVERS
27.01 Any waiver at any time by any Party of its rights
with respect to a default under this Agreement, or with respect
to any other matter arising in connection with this Agreement,
shall not be deemed a waiver with respect to any subsequent
default or other matter arising in connection herewith. Any
delay short of the statutory period of limitation in asserting
or enforcing any right shall not be deemed a waiver of such
right, except as provided in Paragraph 24.05 of this Agreement.
ARTICLE XXVIII
NOTICES
28.01 Any formal notice, demand or request required or
authorized by this Agreement shall be deemed properly given if
mailed, postage prepaid, to the Management Committee
representative of the Party concerned, at the address of such
Party shown on the signature pages hereof.
28.02 Any notice or request of a routine character in
connection with delivery of power and energy or in connection
with operation of facilities, shall be given in such manner as
the Operating Committee from time to time shall arrange.
ARTICLE XXIX
SUCCESSORS AND ASSIGNS
29.01 No Party shall assign this Agreement without the
consent, in writing, of the other Parties, except in connection
with the sale or merger of a substantial portion of its
properties including its high voltage transmission facilities.
29.02 The several provisions of this Agreement are not
intended to and shall not create rights of any character
whatsoever in favor of any persons, corporations, or
associations other than the Parties to this Agreement and the
obligations herein assumed are solely for the use and benefits
of the Parties to this Agreement.
ARTICLE XXX
ARBITRATION
30.01 Any controversy or claim arising out of or
relating to this Agreement or the breach thereof, or appeal from
action of the Management Committee under Paragraph 8.07 of this
Agreement, shall be settled by arbitration. Such arbitration
shall be conducted before a board of three arbitrators selected
by the American Arbitration Association and the arbitration
shall be conducted in accordance with the commercial arbitration
rules of the American Arbitration Association then in effect,
subject to the further qualification that the arbitrators named
under said rules shall be competent by virtue of education and
experience in the particular matter subject to arbitration.
30.02 The Party or Parties desiring arbitration shall
demand such arbitration by giving written notice to the other
Party or Parties involved. Such notice shall conform to the
procedures of the American Arbitration Association and shall
include a statement of the facts or circumstances causing the
controversy and the resolution, determination or relief sought
by the Party or Parties desiring arbitration.
30.03 Before the matter is presented to the board of
arbitrators a conference shall be held to attempt to resolve the
controversy or if that is not possible, to stipulate as many
facts as possible and to clarify and narrow the issues to be
submitted to arbitration.
30.04 The board of arbitrators shall have no
authority, power or jurisdiction to alter, amend, change,
modify, add to or subtract from any of the provisions of this
Agreement nor to consider any issues arising other than from the
language in and authority derived from this Agreement.
30.05 The decision or award of the arbitrators shall be
final and binding upon the Parties and the Parties shall do such
acts as the arbitration decision or award may require of them.
Judgment upon any award rendered by the arbitrators may be
entered in any court having jurisdiction and execution issued
thereon. This provision shall survive the termination of this
Agreement.
30.06 The Party or Parties demanding arbitration shall
pay the costs incurred in connection with the arbitration.
ARTICLE XXXI
CHOICE OF LAW
31.01 In order to promote the uniformity of the
interpretation of this Agreement, it is agreed that the laws of
the State of Minnesota shall control the obligations and
procedures established by this Agreement and the performance and
enforcement thereof.
ARTICLE XXXII
REGULATION
32.01 This Agreement is subject to the regulation of
any regulatory body having jurisdiction thereof.
ARTICLE XXXIII
AMENDMENTS
33.01 Any Participant may propose an amendment to this
Agreement by filing such proposed amendment with the Chairman of
the Management Committee who shall immediately forward copies
thereof to the Participants. Each Participant shall forward its
vote to the Chairman and said vote must be received by the
Chairman within sixty (60) days after the date of filing.
33.02 In voting on any amendment, each Participant
shall have the same number of votes as its representative would
have under Paragraph 8.06. If seventy-five percent (75%) or
more of the total authorized votes favor the amendment, such
amendment will become effective 120 days after filing with the
Chairman of the Management Committee but no amendment shall
affect transactions agreed upon in writing prior to the
effective date of such amendment. Abstentions shall be counted
as negative votes.
33.03 Notwithstanding Section 33.02 above, amendments that
are subject to the jurisdiction of the Federal Energy Regulatory
Commission (FERC) will become effective only upon acceptance
without change or condition by the FERC, or if accepted with
change or condition by the FERC, upon confirmation and approval
of such change or condition by an affirmative vote of seventy-
five percent (75%) or more of the total authorized votes of the
Management Committee, and unless otherwise provided, will become
effective the first day of the MAPP Season following acceptance
by the FERC, and if necessary, confirmation by the Management
Committee.
ARTICLE XXXIV
INTRA-CORPORATE RELATIONSHIPS
34.01 Northern States Power Company, a Minnesota
corporation, hereinafter called "NSP," as a Participant herein
shall include its subsidiary, Northern States Power Company, a
Wisconsin corporation. All interchanges of power and energy
between said companies and other Participants shall be
considered as transactions between such Participants and NSP.
34.02 Minnesota Power & Light Company, a Minnesota
corporation, hereinafter called "MP," as a Participant herein
shall include its subsidiary Superior Water, Light and Power
Company, a Wisconsin corporation. All interchanges of power and
energy between said companies and other Participants shall be
considered as transactions between such Participants and MP.
ARTICLE XXXV
PARTICIPATION BY THE WESTERN AREA POWER ADMINISTRATION
35.01 The Parties understand that participation in this
Agreement by THE UNITED STATES OF AMERICA, hereinafter called
the United States, is limited to application of this Agreement
to a specific electric system operated by the Western Area Power
Administration.
a. Application of this Agreement to the United
States is limited to a defined part of the
electric system operated by, and of the electric
power facilities and resources available to, the
EASTERN DIVISION, PICK-SLOAN MISSOURI BASIN
PROGRAM, or its successor administrative
entities.
b. Transactions between said Eastern Division of
the Pick-Sloan Missouri Basin Program and other
power systems of the United States shall be
considered to be internal, one-entity
transactions for the purposes of this Agreement.
35.02 The participation by the United States in this
Agreement is subject in all respects to acts of Congress and to
regulations of the Secretary of Energy established thereunder
and rate schedules promulgated by the Secretary of Energy or
delegatee. This reservation includes, but is not limited to:
a. The operation and administration of provisions
of law giving preference to certain classes of
customers in the sale of Federal power.
b. The final authority of Congress in all matters
relating to the installation, construction or
operation of facilities.
c. The statutory authority of the Secretary of
Energy to set rates for the sale of power by the
United States.
d. The statutory limitations upon the authority of
the Secretary of Energy to submit disputes
arising under this contract to arbitration.
35.03 Contingent Upon Appropriations: Notwithstanding
Article VI, where the operations of this Agreement extend beyond
the current fiscal year, participation by the United States is
contingent upon Congress making the necessary appropriation for
expenditures by the United States after such current year shall
have expired. In case such appropriation as may be necessary to
carry out obligations of the United States under this Agreement
is not made, the Parties release the United States from all
liability due to the failure of Congress to make such
appropriation.
35.04 Officials Not To Benefit: No member of or
Delegate to Congress or Resident Commissioner shall be admitted
to any share or part of this Agreement or to any benefit that
may arise herefrom, but this restriction shall not be construed
to extend to this Agreement if made with corporations or
companies for their general benefit.
35.05 Covenant Against Contingent Fees: The Parties
warrant that no person or selling agency has been employed or
retained to solicit or secure participation by the United States
in this Agreement upon an agreement or understanding for a
commission, percentage, brokerage or contingent fee, excepting
bona fide employees or bona fide established commercial or
selling agencies maintained by the Parties for the purpose of
securing business. For breach or violation of this warranty,
the United States shall have the right to annul its
participation in this Agreement without liability or, in its
discretion, to deduct from the contract price or consideration
due from the United States the full amount of such commission,
percentage, brokerage, or contingent fee.
35.06 Utility Responsibility: Any reference in this
Agreement to "utility responsibility" of a Participant shall
apply to the United States only to the extent, and in the sense,
that the United States has responsibility for satisfying its
obligations for power service as established by other contracts.
35.07 Membership in Other Groups: It is understood by
the Parties that the United States is at present a participant
in the Western Systems Coordinating Council (for a small part of
its western facilities and operations) and the Missouri Basin
Systems Groups (for certain planning coordination and joint
transmission activities) and the United States may in the future
participate in other similar coordination arrangements.
Participation of the United States is dependent on its
understanding that nothing in this Agreement would preclude such
other participation or commitment of resources thereto, but
rather that it remains the responsibility of each Participant to
insure that its obligations are not in conflict.
35.08 Rate Schedules: Rate Schedules for rates and
conditions of service by the United States shall be governed by
rate schedules promulgated by the Secretary of Energy or
delegatee:
a. The Service Schedules, except for Service
Schedule "F" Transmission Services and Losses,
shall not apply to the transactions of the
United States. Service Schedule "F" will apply
to transactions to which the United States is a
party and to transactions by other Participants
which utilize the transmission system of the
United States.
b. The United States will initiate discussion with
the other Participants as to the future
applicability of the Service Schedules to
transactions made by the United States.
35.09 Area Relations Committee: It is understood by the
Parties that Federal agencies are prohibited by law from
participating in or contributing to any activities influencing
legislation or involving lobbying. Participation of the United
States in this Agreement and especially as to participation in
the Area Relations Committee, shall be limited to activities
that are clearly legal for an agency of the United States.
35.10 Provisions Relative to Employment: The following
provisions governing employment under government contracts are
set forth in Article P of the "General Power Contract
Provisions" made a part of all current power contracts entered
into by the Western Area Power Administration. It is understood
by the Parties that these provisions shall be applicable
hereunder to transactions between the United States and other
Participants. For the purpose of this Paragraph 35.10, the term
"contract" shall mean this Agreement and the term "Contractor"
shall mean a Participant having transactions with the United
States.
a. During the performance of this contract, the
Contractor agrees as follows:
i. The Contractor will not discriminate
against any employee or applicant for
employment because of race, color,
religion, sex or national origin. The
Contractor will take affirmative action to
ensure that applicants are employed and
that employees are treated during
employment, without regard to their race,
color, religion, sex, or national origin.
Such action shall include, but not be
limited to, the following: employment,
upgrading, demotion or transfer,
recruitment or recruitment advertising,
layoff or termination, rates of pay or
other forms of compensation, and selection
for training, including apprenticeship.
The Contractor agrees to post in
conspicuous places, available to employees
and applicants for employment, notices to
be provided by the Contracting Officers
setting forth the provisions of this Equal
Opportunity clause.
ii. The Contractor will, in all solicitations
or advertisements for employees placed by
or on behalf of the Contractor, state that
all qualified applicants will receive
consideration for employment without regard
to race, color, religion, sex, or national
origin.
iii. The Contractor will send to each labor
union or representative of workers with
which he has a collective bargaining
agreement or other contract or
understanding, a notice, to be provided by
the agency Contracting Officer, advising
the labor union or workers' representative
of the Contractor's commitments under this
Equal Opportunity clause and shall post
copies of the notice in conspicuous places
available to employees and applicants for
employment.
iv. The Contractor will comply with all
provisions of Executive Order No. 11246 of
September 24, 1965, and the rules,
regulations and relevant orders of the
Secretary of Labor.
v. The Contractor will furnish all information
and reports required by Executive Order No.
11246 of September 24, 1965, and by the
rules, regulations and orders of the
Secretary of Labor or pursuant thereto and
will permit access to his books, records
and accounts by the contracting agency and
the Secretary of Labor for purposes of
investigation to ascertain compliance with
such rules, regulations and orders.
vi. In the event of the Contractor's
noncompliance with the Equal Opportunity
clause of this contract or with any of the
said rules, regulation or orders, this
contract may be canceled, terminated or
suspended, in whole or in part, and the
Contractor may be declared ineligible for
further Government contracts in accordance
with procedures authorized in Executive
Order No. 11246 of September 24, 1965, and
such other sanctions may be imposed and
remedies invoked as provided in Executive
Order No. 11246 of September 24, 1965, or
by rule, regulation or order of the
Secretary of Labor, or as otherwise
provided by law.
vii. The Contractor will include the provisions
of paragraphs (i) through (vii) in every
subcontract or purchase order unless
exempted by rules, regulations or orders of
the Secretary of Labor issued pursuant to
Section 204 of Executive Order No. 11246
of September 24, 1965, so that such
provisions will be binding upon each
subcontractor or vendor. The Contractor
will take such action with respect to any
subcontract or purchase as the contracting
agency may direct as a means of enforcing
such provisions, including sanctions or
noncompliance; provided however, that in
the event the Contractor becomes involved
in, or is threatened with, litigation with
a subcontractor or vendor as a result of
such direction by the contracting agency,
the Contractor may request the United
States to enter into such litigation to
protect the interests of the United States.
b. In the performance of any part of the work
contemplated by this contract, the Contractor
shall not employ any person undergoing sentence
of imprisonment at hard labor.
ARTICLE XXXVI
PARTICIPATION BY THE MANITOBA HYDRO
36.01 The generating and transmission systems of the
Manitoba Hydro and the City of Winnipeg Hydro Electric System
are interconnected and operated as a single system. Manitoba
Hydro provides any additional generating capacity required to
meet the combined needs of Manitoba Hydro and the City of
Winnipeg. For the purposes of this Agreement, System Demand and
Accredited Capability for Manitoba Hydro shall be determined for
the combined systems of Manitoba Hydro and the City of Winnipeg
Hydro Electric System.
36.02 The participation by Manitoba Hydro in this
Agreement is subject in all respects to legislation of the
Governments of Canada and Manitoba. This includes but is not
limited to: a. The final authority of the Government of Canada
in all matters relating to the export of electric power. b. The
final authority of the Government of Manitoba in all matters
relating to the installation or construction of facilities.
36.03 It is understood by the Parties that Manitoba
Hydro has entered into interconnection agreements with electric
utilities in other Provinces of Canada. Under the terms of
these agreements, Manitoba Hydro may not make commitments to
supply surplus electric power and energy or any other related
services to a utility based outside of Canada without first
giving utilities based in Canada the prior right to purchase
such surplus electric power, energy and other services on the
same terms and conditions and at an equivalent price.
36.04 The reliability characteristics of Manitoba
Hydro's generating facilities, which are predominantly
hydroelectric, shall be considered when establishing Manitoba
Hydro's Reserve Capacity Obligation.
36.05 It is an acknowledged condition to the
participation by Manitoba Hydro in this Agreement that:
a. Nothing in this Agreement shall alter or
diminish the rights of other Canadian electric
utilities to purchase surplus electric power,
energy, and services from Manitoba Hydro.
b. Nothing in this Agreement shall preclude
participation by Manitoba Hydro in any Canadian
electric power pool or the commitment of
resources thereto.
c. Manitoba Hydro's participation in the Area
Relations Committee shall be limited to
activities which are clearly nonpolitical
inasmuch as Manitoba Hydro does not have the
right to participate in or contribute to any
activity which is intended to influence
legislation.
d. Any provision governing employment or production
of goods and services enacted by the Congress of
the United States of America or enacted by any
other legislative body in the United States of
America shall not be applicable to any power or
other service provided by Manitoba Hydro to the
United States of America or to any other party
in the United States of America.
e. The authority of the Federal Energy Regulatory
Commission on matters pertaining to power
transactions between Manitoba Hydro and the
other Parties shall not be applicable to the
transmission or use of such power within Canada.
f. The provisions of Article XXX shall not apply to
any controversy, claim or dispute arising out of
or relating to this Agreement or the breach
thereof which involves Manitoba Hydro and any
such controversy, claim or dispute shall be
referred to the Chief Executive Officer of each
of the disputing parties to resolve.
g. Notwithstanding Article XXXI, the laws of the
Province of Manitoba, Canada, shall apply to any
transactions undertaken or services rendered in
Canada and the performance and enforcement
thereof.
Execution. Separate copies of this Agreement are executed
by the Parties with the understanding that, when each of the
Parties has executed a copy, its separately executed copy will
be joined together with all other similarly executed copies and
one conformed master copy of said agreement shall be prepared,
which shall bind all of the Parties to the same extent and
purpose as if all of said Parties had joined in the execution of
said master copy.
IN WITNESS WHEREOF, each of the Parties has caused this
Agreement to be executed by its duly authorized officer as of
the day and year of the membership shown below.
SIGNATORY PARTICIPANTS
(Date of Membership)
BASIN ELECTRIC POWER COOPERATIVE ARTHUR JONES
(August 14, 1975) President
CENTRAL IOWA POWER COOPERATIVE JOSEPH C. ARMBRECHT
(March 31, 1972) President
COOPERATIVE POWER ASSOCIATION ORVILLE J. LIPKE
(March 31, 1972) President
CORN BELT POWER COOPERATIVE WARREN C. SNELL
(March 31, 1972) President
DAIRYLAND POWER COOPERATIVE JOHN P. MADGETT
(March 31, 1972) General Manager
HEARTLAND CONSUMERS POWER DISTRICT WENDELL J. GARWOOD
(February 13, 1979) General Manager
HUTCHINSON UTILITIES COMMISSION Thomas B. Lyke
(February 25, 1991) Vice President
INTERSTATE POWER COMPANY GLENN J. LYSHOJ
(March 31, 1972) Vice President
IOWA ELECTRIC LIGHT AND POWER COMPANY DUANE ARNOLD
(March 31, 1972) Chairman of the Board
and President
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY C. J. MATH
(March 31, 1972) Vice President
IOWA POWER AND LIGHT COMPANY D. H. SWANSON
(March 31, 1972) President
IOWA PUBLIC SERVICE COMPANY F. W. GRIFFITH
(March 31, 1972) Chairman and President
IOWA SOUTHERN UTILITIES COMPANY R. F. BREWER
(March 31, 1972) President
LINCOLN ELECTRIC SYSTEM WALTER A. CANNEY
(December 1, 1977) Administrator
MINNESOTA POWER J. F. ROWE
(March 31, 1972) Executive Vice President
MINNKOTA POWER COOPERATIVE, INC. TED M. LEE
(March 31, 1972) President
MISSOURI BASIN MUNICIPAL POWER AGENCY RUSSELL DAU
(March 12, 1980) General Manager
MONTANA-DAKOTAS UTILITIES CO. DAVID M. HESKETT
(March 31, 1972) President
MUSCATINE POWER & WATER JAMES P. FULLER
(March 19, 1976) General Manager
NEBRASKA PUBLIC POWER DISTRICT DON E. SCHAUFELBERGER
(March 31, 1972) Deputy General Manager
NORTHERN STATES POWER COMPANY EDWARD C. SPETHMANN
(March 31, 1972) Vice President - Public
Affairs
NORTHWEST IOWA POWER COOPERATIVE CARL PAULSON
(November 26, 1979) Exec. Vice President and
General Manager
NORTHWESTERN PUBLIC SERVICE COMPANY A. D. SCHMIDT
(March 31, 1972) President
OMAHA PUBLIC POWER DISTRICT A. L. MONROE
(March 31, 1972) General Manager
OTTER TAIL POWER COMPANY DONALD F. VRASPIR
(December 27, 1979) Vice President
SOUTHERN MINNESOTA MUNICIPAL POWER PIERRE HEROUX
AGENCY
(November 1, 1982) Executive Director
UNITED POWER ASSOCIATION
(May 1, 1972)
THE UNITED STATES OF AMERICA H. E. ALDRICH
(March 31, 1972) Regional Director,
Region 6 U.S. Bureau
of Reclamation
SIGNATORY ASSOCIATE PARTICIPANTS
AMES MUNICIPAL ELECTRIC SYSTEM MERLIN C. HOVE
(January 5, 1983) Director
CEDAR FALLS, IOWA LEONARD J. KEEFE
(March 31, 1972) Cedar Falls Utilities
Board of Trustees
CUMBERLAND MUNICIPAL UTILITY CHARLES CHRISTENSEN
(December 30, 1982) Manager
DELANO, MINNESOTA LAURENCE RIEDER
(March 31, 1972) Mayor
FREMONT, NEBRASKA MILTON LAUNER
(January 9, 1980) Assistant General
Manager
GLENCOE, MINNESOTA DONALD A. NELSON
(March 31, 1972) Secretary
Light & Power Commission
GRAND ISLAND, NEBRASKA R. J. OLSON
(September 6, 1977) Director of Utility
Operation
HARLAN MUNICIPAL UTILITIES F. JAMES KALAL
(July 14, 1983) General Manager
MADELIA, MINNESOTA C. W. SEIBERT
(March 31, 1972) Commissioner
Public Utilities
Commission
MUNICIPAL ENERGY AGENCY OF NEBRASKA H. STEVE WACKER
(June 26, 1979) General Manager
NORTH IOWA MUNICIPAL ELECTRIC RONALD L. DEIBER
COOPERATIVE ASSOCIATION
(March 9, 1982) President
NORTHWESTERN WISCONSIN ELECTRIC CO. FRED E. DAHLBERG
(March 31, 1972) President
OWATONNA, MINNESOTA TY SINCOCK
(November 1, 1972) President
Municipal Public
Utilities
ROCHESTER, MINNESOTA R. JOHN MINER
(January 2, 1980) Director
SASKATCHEWAN POWER CORPORATION K. D. WELLMAN
(February 10, 1981) Corporate Legal Counsel
WISCONSIN PUBLIC POWER, INC. David Penn
(November 2, 1990) General Manager
MID-CONTINENT AREA POWER POOL
Service Schedule A
Participation Power Interchange Service
Section 1. Service to be Provided
1.01 This Schedule provides for the sale of Participation
Power by a Participant to any other Participant from a specific
generating unit or units. Participation Power shall mean power
and energy which is sold from a specific generating unit or
units on the basis that it is continuously available except when
such unit or units are temporarily out of service for
maintenance during which time the delivery of energy from other
sources shall be at the seller's option.
Section 2. Conditions of Service
2.01 This Schedule shall be available for the sale of
Participation Power for a period of six months or more.
2.02 Participation Power shall be supplied through
transmission facilities which have adequate capacity for
transmitting such power and energy, and Transmission Service
shall be arranged in accordance with the procedures established
under Service Schedule "F."
2.03 FERC-regulated Participants who enter into
transactions to sell power under this schedule shall file the
applicable agreement with the FERC as a rate schedule.
Section 3. Schedule of Rates
3.01 The rate and term for Participation Power under this
Service Schedule "A" shall be negotiated by the Participants
arranging the transaction.
3.02 In the event that service cannot be supplied on the
effective date of an Agreement to sell Participation Power under
this Service Schedule "A" due to a delayed in-service date of
the associated generating facilities, the demand charge to be
paid by the purchasing Participant shall not be effective until
the date such facilities are included as Accredited Capability.
3.03 The Transmission Service charge and losses provisions
of Service Schedule "F" shall also apply.<PAGE>
Service Schedule B
Seasonal Participation Power Interchange Service
Section 1. Service to be Provided
1.01 This Schedule provides for the sale of Seasonal
Participation Power by any Participant to any other Participant
from a specific generating unit. Seasonal Participation Power
shall mean power and energy which is sold from a base load unit
on the basis that it is continuously available except when such
unit is temporarily out of service for maintenance during which
time the delivery of energy from other sources shall be at the
seller's option.
Section 2. Conditions of Service
2.01 This Schedule shall be available for the sale of
Seasonal Participation Power for six consecutive months
beginning on May 1 or November 1 unless other dates are agreed
to by the Engineering Committee.
2.02 Seasonal Participation Power shall be supplied through
transmission facilities which have adequate capacity for
transmitting such power and energy, and Transmission Service
shall be arranged in accordance with the procedures established
under Service Schedule "F."
Section 3. Schedule of Rates
3.01 The receiving Participant shall pay to the supplying
Participant for Seasonal Participation Power furnished during
any month under this Schedule an amount determined from the
following schedule of rates:
Demand Charge:
For each megawatt or fraction thereof committed by the
supplier, a charge per month not more than P, where
P = A
___
12
where A = the value for the applicable year based on ten
(10) years of data representing the composite levelized
annual fixed charges per megawatt for the units of the
Participants which supplied, or are most likely to supply
capacity and energy under this Schedule.
For each FERC regulated Participant, the levelized annual
fixed carrying charge would be the sum of the return
requirement, depreciation, income tax, property tax and
administrative and general costs. The return requirement
shall be calculated in accordance with standard FERC
methods using debt costs, preferred stock cost and a
percentage rate of return on equity, weighted in accordance
with the Participant's capital ratios at the end of the
preceding calendar year. The percentage rate of return on
equity shall be the FERC benchmark rate of return on equity
percentage, which shall be filed annually with the FERC.
The income tax requirement which shall include deferred
taxes, shall be calculated in accordance with standard FERC
methods using federal and state tax rates in effect for the
current year. The administrative and general costs in
column b on line 167 of page 323 of the FERC Form 1 shall
be appropriately allocated to the electric production plant
and converted to a percentage of the electric production
plant investment. Appendix 1 describes the calculation of
the demand charge for this Service Schedule.
Participants not regulated by the FERC will file a
comparable, reasonable levelized annual carrying charge
with the MAPP Coordination Center for use in this
calculation.
Energy Charge:
a. For all energy supplied from the assigned
generating unit, a charge per kilowatt-hour of 110
percent of Average Production Cost for the month of
the assigned generating unit, for both the energy
delivered to the receiving Participant and the energy
supplied by the supplying Participant to any
intervening Participant or Participants as
compensation for losses.
b. For all energy supplied when the assigned
generating unit is temporarily out of service for
maintenance, a charge per kilowatt-hour of 110 percent
of Incremental Cost of supplying such energy, for both
the energy delivered to the receiving Participant and
the energy supplied by the supplying Participant to
any intervening Participant or Participants as
compensation for losses.
c. The percentage adder components contained in the
third-party purchase and resale provisions of this
rate schedule are hereby limited to recover no more
than:
i. The FERC Order 84 adder for each FERC-
regulated Participant. The FERC Order 84 adder
for each FERC-regulated Participant is shown on
Appendix 6 to this Agreement. FERC-regulated
Participants shall provide the FERC and the MAPP
Coordination Center with a revised Appendix 6
whenever a change to their Order 84 adder is
filed with the FERC.
ii. A value on file at the MAPP Center for
Participants not regulated by the FERC.
3.02 In the event that service cannot be supplied on the
effective date of an agreement to sell Seasonal Participation
Power under this Service Schedule "B" due to a delayed in-
service date of the associated generating facilities, the demand
charge to be paid by the purchasing Participant shall not be
effective until the date such facilities are included as
Accredited Capability.
3.03 The Transmission Service charge and losses provisions
of Service Schedule "F" shall also apply.
Service Schedule C
Emergency and Scheduled Outage Energy Interchange Service
Section 1. Service to be Provided
1.01 This Schedule provides for the supply of energy by any
Participant to any other Participant during Emergency Outages or
Scheduled Outages for maintenance of generating or transmission
facilities or both.
Section 2. Scheduling of Deliveries
2.01 Deliveries of Emergency Energy shall be scheduled as
soon as possible after the occurrence of an Emergency Outage in
accordance with principles and practices established by the
Operating Committee. Transmission Service for Emergency Energy
shall be available in accordance with the procedures established
under Service Schedule "F."
2.02 Scheduled Outage Energy may be scheduled from a
Participant not directly interconnected providing such energy is
available at a lower delivered cost than from a directly
interconnected Participant. Transmission Service for Scheduled
Outage Energy shall be available in accordance with the
procedures established under Service Schedule "F."
Section 3. Schedule of Rates
3.01 The receiving Participant shall pay to the supplying
Participant for Emergency Energy furnished during any month
under this Schedule the greater of 3.0 cents per kilowatt-hour
or 110 percent of the supplying Participant's Incremental Cost
of supplying such energy.
3.02 The receiving Participant shall compensate the
supplying Participant for Scheduled Outage Energy furnished
during any month under this Schedule in accordance with one of
the following subparagraphs:
a. The receiving Participant shall pay to the
supplying Participant for such Scheduled Outage Energy
an amount of whichever is the greater:
i. 110 percent of the Incremental Cost of
producing such energy, or
ii. 110 percent of the average cost of the
receiving Participant had it produced such
energy with the generating unit which is out of
service, which average cost shall include but
not be limited to fuel cost and operation and
maintenance cost;
provided that, if the receiving Participant is not using
its Total Available Accredited Capability, the supplying
Participant may require the receiving Participant to make
an additional payment for any financial loss that accrues
to the supplying Participant due to this transaction
replacing a sale to another party. For uniformity of
application, such additional payment should be calculated
assuming that the decremental cost of the other sale would
have been an amount equal to the cost of energy from oil-
fired generation determined in accordance with principles
and practices established by the Operating Committee as
follows:
The cost of oil-fired generation will be calculated using
the least-squares method based on a maximum of seven years'
data. For FERC regulated Participants, the data used will
be the sum of fuel, operation and maintenance costs divided
by net KWH (where net generation is sufficient to
demonstrate true operating costs) which is line 35 on page
402 and columns e, h, i and o on pages 410 and 411 of the
FERC Form 1. Participants not regulated by the FERC will
provide comparable data when cost data is requested for
filing at the MAPP Coordination Center.
b. The Participant supplying Scheduled Outage Energy
may, at its option, require the receiving Participant
to return such energy at such times and under such
conditions that the supplying Participant will not
experience a loss due to the transaction, or under
conditions mutually agreeable to both Participants.
3.03 The Transmission Service charge and losses provisions
of Service Schedule "F" shall also apply to Scheduled Outage
Energy transactions. The Transmission Service charge and losses
provisions of Service Schedule "F" shall not apply to Emergency
Energy transactions.
Service Schedule D
Operating Reserve Interchange Service
Section 1. Service to be Provided
1.01 A Participant may arrange for some other Participant
to supply part or all of its Operating Reserve requirement.
Section 2. Scheduling of Rates (See Note No. 1)
2.01 Except as otherwise agreed to by the Participants
concerned, a Participant supplying a portion or all of some
other Participant's Operating Reserve during any month shall be
paid by the purchasing Participant an amount of whichever is
greater of the following:
a. 110 percent of the incremental cost of supplying
such service, or
b. The incremental cost of supplying such service
plus one-half of the overall savings of such
transaction, where overall savings shall be equal to
the difference between the incremental cost of the
selling Participant and the decremental cost of the
purchasing Participant.
2.02 In the event there are repetitive transactions between
certain Participants involving similar incremental and
decremental costs, flat rates or an exchange arrangements may be
established for such transactions by the representatives of the
Participants concerned.
Note No. 1
Incremental and Decremental Cost for the purpose of this
schedule only, shall be determined as follows:
Incremental cost of the supplying Participant shall be
based on the costs incurred in starting and/or
operating any generating unit or units which must be
started as a result of supplying such service.
Decremental cost of the purchasing Participant shall
be based on the cost avoided by not starting and/or
operating any generator unit or units as a result of
receiving such service.
Service Schedule E
Economy Energy Interchange Service
Section 1. Service to be Provided
1.01 This Schedule provides for the supply of Economy
Energy by any Participant to any other Participant when it is
economical and practical to do so under the conditions set forth
hereinafter and in Paragraph 20.07 of the Agreement.
Section 2. Conditions of Service
2.01 It is the intent hereof that, insofar as is
practicable, Economy Energy from available sources having the
lowest Incremental Costs shall be used to displace generation
having the highest Decremental Costs and so on until such
transactions are no longer economical; provided that such
transactions are not scheduled in amounts which will overload
any transmission facility or endanger the operation of the
interconnected systems.
2.02 Transmission Service shall be available in accordance
with the procedures established under Service Schedule "F."
Section 3. Scheduling of Deliveries
3.01 Prior to beginning deliveries, the Participants
involved will agree on an hour-by-hour schedule of energy to be
delivered.
Section 4. Schedule of Rates
4.01 The overall savings of an Economy Energy transaction
shall be equal to the difference between the Incremental Cost of
the supplying Participant and the Decremental Cost of the
receiving Participant. If the transmission system of a non-
Participant is involved in an Economy Energy transaction, any
transmission fees and losses to be paid for the use of such
system shall be deducted from the overall savings in determining
the net savings of the transactions.
4.02 The receiving Participant shall pay the supplying
Participant for the Economy Energy supplied during each month,
an amount equal to the Incremental Cost of the energy so
supplied, plus one-half of the net savings of such transactions
which remain after deducting the amount paid by the receiving
Participant to any parties providing transmission service in
accordance with Paragraph 4.01 herein and with Service Schedule
"F."
4.03 The Transmission Service charge and losses provisions
of Service Schedule "F" shall also apply.
Service Schedule F
Transmission Services and Losses
Section 1. Service to be Provided
1.01 This Schedule provides for Transmission Service in
connection with Coordination Transactions scheduled between
Participants, or scheduled between a Participant and another
utility, in a non-Participant Control Area, with which the
Participant has a direct interconnection or has rights to
deliver or receive power and energy at such an interconnection.
1.02 This Service Schedule shall not be used for and will
not be applied to provide Transmission Service to deliver power
and energy from generation owned or leased by a Participant or
from which a Participant purchases power and energy pursuant to
life-of-unit contracts, to serve load which that Participant has
an obligation under law or contract to supply (including
preference customers in the case of the United States). This
Service Schedule shall also not be used for and will not be
applied to provide for Transmission Service to deliver power and
energy to an ultimate consumer.
1.03 Service Schedule "F" shall be applicable to
transactions, to which a Participant is a party, of four years
(eight full seasons) or less from the date notice of the
transaction is given to the MAPP Center in accordance with the
procedures established by the applicable committee.
Transmission Service under Service Schedule "F" may be used for
portions of longer term transactions, but only to the extent any
such portion occurs within four years (eight full seasons) of
the date notice of the transaction is given to the MAPP Center.
The eight full seasons are the eight consecutive seasons
immediately following notification of the MAPP Center of the
transaction, assuming notification is provided before the first
season. To the extent the transaction occurs during the first
season, the eight seasons shall consist of that season and the
following seven seasons.
Section 2. Conditions of Service
2.01 Transmission Service for transactions under Service
Schedules "A", "B", "H", "I", "J", and "K", and any other
capacity transactions, shall be arranged in accordance with
procedures established by the Engineering Committee.
Transmission Service for transactions under Service Schedules
"C", "E", "G", "L", and "M", and any other energy-only
transactions, shall be available in accordance with procedures
established by the Operating Committee. There shall be no
Transmission Service charge applicable to Emergency Energy
transactions under Service Schedule "C".
2.02 Nothing contained in this Service Schedule "F"
or in the procedures established by the appropriate committee
pursuant to Section 2.01 shall be interpreted to require a Party
to install or upgrade transmission facilities or to redispatch
its generation in order to enable Transmission Service to be
arranged or made available for prospective transactions.
2.03 Available transmission capacity for MAPP Service
Schedule "F" shall be determined on an integrated system basis
considering the combined transfer capability of all
Participants' transmission systems. If requests for
transmission capacity exceed the available transmission
capacity, the available transmission capacity will be allocated
under procedures established by the Engineering and Operating
Committees.
Section 3. Compensation
3.01 Each Participant who provides Transmission Service
utilizing transmission facilities of 115kV and higher, except
for Service Schedule C Emergency Energy transactions, shall be
entitled to compensation in accordance with the Transmission
Service charge formulae and methodology set forth in Appendix 7.
Participants whose 69kV transmission facilities meet the
criteria set forth in Appendix 7 for inclusion in such formulae
and methodology of the investments in and flows through such
facilities shall also be entitled to compensation in accordance
with Appendix 7.
3.02 The buyer shall pay for Transmission Service, unless
the buyer is a non-Participant, in which case the selling
Participant pays.
3.03 Whenever a Participant schedules the delivery of power
and energy pursuant to this Agreement, the amount of power and
energy to be furnished to the other Participants as compensation
for losses shall be determined in accordance with formulae
established by the Operating Committee.
Service Schedule G
Operational Control Energy Interchange Service
Section 1. Service to be Provided
1.01 This Schedule provides for the supply of Operational
Control Energy by any Participant to any other Participant to
improve electric system control and reliability.
1.02 This Schedule also provides for the supply of energy
by any Participant to any other Participant for resale to
another electric supplier, not signatory hereto, to enable such
other supplier to meet emergency conditions on its own system.
Section 2. Conditions of Service
2.01 Operational Control Energy shall not be used in lieu
of energy available under any other Service Schedule and shall
not be considered in the determination of a Participant's
Accredited Capability.
2.02 Transmission Service shall be available in accordance
with the procedures established under Service Schedule "F."
Section 3. Schedule of Rates
3.01 For all energy supplied under Paragraph 1.01 herein,
the receiving Participant shall pay to the supplying Participant
for Operational Control Energy, furnished during any month under
this Schedule, 110 percent of the Incremental Cost of the
supplying Participant when the transaction is initiated by the
receiving Participant for its benefit or ninety percent (90%) of
the Decremental Cost of the receiving Participant when the
transaction is initiated by the supplying Participant for its
benefit.
The percentage adder components contained in the third-
party purchase and resale provisions of this rate schedule
are hereby limited to recover no more than:
i. The FERC Order 84 adder for each FERC-regulated
Participant. The FERC Order 84 adder for each FERC-
regulated Participant is shown on Appendix 6 to this
Agreement. FERC-regulated Participants shall provide
the FERC and the MAPP Coordination Center with a
revised Appendix 6 whenever a change to their Order 84
adder is filed with the FERC.
ii. A value on file at the MAPP Center for
Participants not regulated by the FERC.
3.02 For all energy supplied during any month under
Paragraph 1.02, the receiving Participant shall pay to the
supplying Participant the rate in effect under Service Schedule
"C," Paragraph 3.01.
3.03 The Transmission Service charge and losses provisions
of Service Schedule "F" shall also apply.
Service Schedule H
Peaking Power Interchange Service
Section 1. Service to be Provided
1.01 This Schedule provides for the sale of Peaking Power
by any Participant to any other Participant. Peaking Power
shall mean power and associated energy intended to be available
at all times during the period covered by a commitment and which
is sold with anticipated low load factor use. Such power shall
include required reserve capacity.
Section 2. Conditions of Service
2.01 This Schedule shall be available for the sale of
Peaking Power for a period of six consecutive months beginning
on May 1 or November 1 unless other dates are agreed to by the
Engineering Committee.
2.02 Peaking Power shall be supplied through transmission
facilities which have adequate capacity for transmitting such
power and energy, and Transmission Service shall be arranged in
accordance with the procedures established under Service
Schedule "F."
2.03 The supplying Participant shall guarantee that Peaking
Power purchased hereunder shall be available to the receiving
Participant on at least a twenty percent (20%) monthly capacity
factor. The supplying Participant of such Peaking Power may
limit delivery of energy, above the guaranteed amount. The
capacity factor set forth herein shall be subject to change by
the Engineering Committee from time to time.
Section 3. Schedule of Rates
3.01 The receiving Participant shall pay to the supplying
Participant for Peaking Power furnished during any month under
this Schedule an amount determined from the following schedule
of rates:
Demand Charge:
For each megawatt or fraction thereof committed by the
supplying Participant, a charge per month not more than the
greater of:
i. Q, where
Q = B
___
12
where B = a value based on all Participant's current levelized
annual fixed charges per megawatt for their total peaking
generating capacity, or
ii. $2,000
For each FERC regulated Participant, the levelized annual
fixed carrying charge would be the sum of the return
requirement, depreciation, income tax, property tax and
administrative and general costs. The return requirement
shall be calculated in accordance with standard FERC
methods using debt costs, preferred stock cost and a
percentage rate of return on equity, weighted in accordance
with the Participant's capital ratios at the end of the
preceding calendar year. The percentage rate of return on
equity shall be the FERC benchmark rate of return on equity
percentage which shall be filed annually with the FERC.
The income tax requirement, which shall include deferred
taxes, shall be calculated in accordance with standard
FERC methods using federal and state tax rates in effect
for the current year. The administrative and general costs
in column b on line 167 of page 323 of the FERC Form 1
shall be appropriately allocated to the electric production
plant and converted to a percentage of the electric
production plant investment. Appendix 2 describes the
calculation of the demand charge for this Service Schedule.
Participants not regulated by the FERC will file a
comparable, reasonable levelized annual carrying charge
with the MAPP Coordination Center for use in this
calculation.
Energy Charge:
For all energy supplied hereunder, a charge per kilowatt-
hour of 110 percent of the Incremental Cost of producing or
purchasing such energy, whichever is less, for both the
energy delivered to the purchasing Participant and the
energy supplied by the supplying Participant to any
intervening Participant or Participants as compensation for
losses.
The percentage adder components contained in the third-
party purchase and resale provisions of this rate schedule
are hereby limited to recover no more than:
i. The FERC Order 84 adder for each FERC-regulated
Participant. The FERC Order 84 adder for each FERC-
regulated Participant is shown on Appendix 6 to this
Agreement. FERC-regulated Participants shall provide
the FERC and the MAPP Coordination Center with a
revised Appendix 6 whenever a change to their Order 84
adder is filed with the FERC.
ii. A value on file at the MAPP Coordination Center
for Participants not regulated by the FERC.
In the event it is desired by the Participants involved, an
exchange arrangement may be established by the
representatives of the Parties concerned. The supplying
Participant of Peaking Power may, at its option, require
the return of any energy delivered above the guaranteed
monthly capacity factor at such times and under such
conditions as agreed to by representatives of the
Participants concerned.
3.02 The Transmission Service charge and losses provisions
of Service Schedule "F" shall also apply.
Service Schedule I
Short Term Power Interchange Service
Section 1. Service to be Provided
1.01 This Schedule provides for the sale of Short Term
Power by any Participant to any other Participant. Short Term
Power shall mean power and associated energy intended to be
available at all times during the period covered by a
commitment. Such power shall include required reserve capacity.
Section 2. Conditions of Service
2.01 This Schedule shall be available for the sale of Short
Term Power for periods of seven or more consecutive days each.
2.02 Short Term Power shall be included in the Accredited
Capability of a Participant only under special conditions, such
as:
a. In an instance where a significant new industrial
customer load is imposed upon a Participant's system
at a time different from the purchase period for which
other schedules are applicable.
b. In an instance where a generator or transmission
line addition does not meet the scheduled in-service
date.
c. In an instance where it is being purchased for
resale to an electric supplier who is not a
Participant.
d. In an instance where a Participant's October
system demand is forecast to exceed the maximum system
demand of the previous five months.
2.03 Short Term Power shall be supplied through
transmission facilities which have adequate capacity for
transmitting such power and energy, and Transmission Service
shall be arranged in accordance with the procedures established
under Service Schedule "F."
Section 3. Schedule of Rates
3.01 The receiving Participant shall pay to the supplying
Participant for Short Term Power furnished during any month
under this Schedule an amount determined from the following
schedule of rates:
Demand Charge:
For each megawatt or fraction thereof committed by the
supplying Participant, a charge per day not more than the
greater of:
i. R, where
R = B
___
365
where B = a value based on all Participants' current
levelized annual fixed charges per megawatt for their
total peaking generating capacity, or
ii. $66
For each FERC regulated Participant, the levelized annual
fixed carrying charge would be the sum of the return
requirement, depreciation, income tax, property tax and
administrative and general costs. The return requirement
shall be calculated in accordance with standard FERC
methods using debt costs, preferred stock cost and a
percentage rate of return on equity, weighted in accordance
with the Participant's capital ratios at the end of the
preceding calendar year. The percentage rate of return on
equity shall be the FERC benchmark rate of return on equity
percentage, which shall be filed annually with the FERC.
The income tax requirement, which shall include deferred
taxes, shall be calculated in accordance with standard FERC
methods using federal and state tax rates in effect for the
current year. The administrative and general costs in
column b on line 167 of page 323 of the FERC Form 1 shall
be appropriately allocated to the electric production plant
and converted to a percentage of the electric production
plant investment. Appendix 3 describes the calculation of
the demand charge for this Service Schedule.
Participants not regulated by the FERC will file a
comparable, reasonable levelized annual carrying charge
with the MAPP Coordination Center for use in this
calculation.
Energy Charge:
For all energy supplied hereunder, a charge per kilowatt-
hour of 110 percent of the Incremental Cost of supplying
such energy, for both the energy delivered to the receiving
Participant and the energy supplied by the supplying
Participant to any intervening Participant or Participants
as compensation for losses. The percentage adder components
contained in the third-party purchase and resale provisions
of this rate schedule are hereby limited to recover no more
than:
i. The FERC Order 84 adder for each FERC-regulated
Participant. The FERC Order 84 adder for each FERC-
regulated Participant is shown on Appendix 6 to this
Agreement. FERC-regulated Participants shall provide
the FERC and the MAPP Coordination Center with a
revised Appendix 6 whenever a change to their Order 84
adder is filed with the FERC.
ii. A value on file at the MAPP Center for
Participants not regulated by the FERC.
3.02 The Transmission Service charge and losses provisions
of Service Schedule "F" shall also apply.
3.03 For any Short Term Capacity which the supplying
Participant procures from electric suppliers not signatory
hereto for delivery to the receiving Participant, the receiving
Participant shall pay to the supplying Participant the cost of
procuring such capacity and 110 percent of the cost of procuring
such energy, but not less than the rates specified herein, in
addition to compensation as set forth in Service Schedule "F."
Service Schedule J
Firm Power Interchange Service
Section 1. Service to be Provided
1.01 This Schedule provides for the sale of Firm Power by
any Participant to any other Participant. Firm Power shall mean
power and associated energy intended to be available at all
times during the period covered by a commitment. Such power
shall include required reserve capacity.
Section 2. Conditions of Service
2.01 Firm Power shall be supplied through transmission
facilities which have adequate capacity for transmitting such
power and energy, and Transmission Service shall be arranged in
accordance with the procedures established under Service
Schedule "F."
2.02 This Schedule shall be available for the sale of Firm
Power for a period of six months or longer.
2.03 FERC-regulated Participants who enter into
transactions to sell power under this schedule shall file the
applicable agreement with the FERC as a rate schedule.
Section 3. Schedule of Rates
3.01 The rate and term for Firm Power shall be negotiated
by the Participants to each transaction.
3.02 The Transmission Service charge and losses provisions
of Service Schedule "F" shall also apply.
Service Schedule K
System Participation Power Interchange Service
Section 1. Service to be Provided
1.01 This Schedule provides for the sale of System
Participation Power by any Participant to any other Participant
for a specified period for the purpose of obtaining a supply of
power which can be depended upon with the same degree of
assurance as that expected from the Purchaser's own generating
capacity, but which does not include reserve capacity.
Section 2. Conditions of Service
2.01 This Schedule shall be available for the sale of
System Participation Power for periods of seven or more
consecutive days.
2.02 System Participation Power is intended to be available
at all times during the period covered by the commitment;
provided, however, that in the event conditions arise during the
period covered by the commitment which in the sole judgment of
the supplying Participant would otherwise require curtailment of
firm power sales or service to its own customers, the supplying
Participant has the right to notify and require the receiving
Participant to reduce its take of such energy to any amount
specified and for any portion of the term of the commitment and
the receiving Participant shall promptly comply with the
decision of the supplying Participant.
2.03 System Participation Power shall be included in the
Accredited Capability of a Participant only under the following
conditions:
a. In an instance where it is being purchased for
resale to an electric supplier who is not a
Participant.
b. In an instance where a Participant purchases
power under this schedule for a period of six
consecutive months beginning May 1 or November 1 or
such other dates as are agreed to by the Management
Committee.
2.04 System Participation Power shall be supplied through
transmission facilities which have adequate capacity for
transmitting such power and energy, and Transmission Service
shall be arranged in accordance with the procedures established
under Service Schedule "F".
Section 3. Schedule of Rates
3.01 The receiving Participant shall pay to the supplying
Participant for System Participation Power furnished during any
period under this Schedule an amount determined from the
following schedule of rates:
Demand Charge:
For each megawatt or fraction thereof committed by the
supplying Participant, a charge per week of not more than
S, where
S = C
___
52
where C = a value based on all Participants' current
levelized annual fixed charges per megawatt for their total
thermal generating capacity excluding cogeneration,
provided however, that should delivery of System
Participation Power be curtailed by the supplying
Participant, the demand charge shall be reduced by one-
sixth per megawatt of curtailment for each day during which
there is a curtailment, but such reduction shall not exceed
the demand charge for the reservation period.
For each FERC regulated Participant, the levelized annual
fixed carrying charge would be the sum of the return
requirement, depreciation, income tax, property tax and
administrative and general costs. The return requirement
shall be calculated in accordance with standard FERC
methods using debt costs, preferred stock cost and a
percentage rate of return on equity, weighted in accordance
with the Participant's capital ratios at the end of the
preceding calendar year. The percentage rate of return on
equity shall be the FERC benchmark rate of return on equity
percentage, which shall be filed annually with the FERC.
The income tax requirement which shall include deferred
taxes, shall be calculated in accordance with standard FERC
methods using federal and state tax rates in effect for the
current year. The administrative and general costs in
column b on line 167 of page 323 of the FERC Form 1 shall
be appropriately allocated to the electric production plan
and converted to a percentage of the electric production
plant investment. Appendix 4 describes the calculation of
the demand charge for this Service Schedule.
Participants not regulated by the FERC will file a
comparable, reasonable levelized annual carrying charge
with the MAPP Coordination Center for use in this
calculation.
Energy Charge:
For all energy supplied hereunder, a charge per kilowatt-
hour of 110 percent of the Incremental Cost of supplying
such energy, for both the energy delivered to the receiving
Participant and the energy supplied by the supplying
Participant to any intervening Participant or Participants
as compensation for losses.
The percentage adder components contained in the third-
party purchase and resale provisions of this rate schedule
are hereby limited to recover no more than:
i. The FERC Order 84 adder for each FERC-regulated
Participant. The FERC Order 84 adder for each FERC-
regulated Participant is shown on Appendix 6 to this
Agreement. FERC-regulated Participants shall provide
the FERC and the MAPP Coordination Center with a
revised Appendix 6 whenever a change to their Order 84
adder is filed with the FERC.
ii. A value on file at the MAPP Coordination Center
for Participants not regulated by the FERC.
3.02 The Transmission Service charge and losses provisions
of Service Schedule "F" shall also apply.
3.03 For any System Participation Capacity which the
supplying Participant procures from electric suppliers not
signatory hereto for delivery to the receiving Participant, the
receiving Participant shall pay to the supplying Participant the
cost of procuring such capacity at cost and such associated
energy cost at 110 percent of the cost of procuring such energy,
in addition to wheeling and loss compensation as set forth in
Service Schedule "F."
Service Schedule L
Interruptible Load Replacement Energy Service
Section 1. Services to be Provided
1.01 This Schedule provides for the supply of Interruptible
Load Replacement Energy by any Participant to any other
Participant when it is economical and practical to do so under
the conditions set forth hereinafter and in Paragraph 20.08 of
this Agreement.
Section 2. Conditions of Service
2.01 It is the intent that Interruptible Load Replacement
Energy may be used by Participants to serve interruptible load
when that load would otherwise be interrupted.
a. In order to be eligible for Interruptible Load
Replacement Energy Service, the purchasing Participant
must report in advance monthly quantities of Certified
Interruptible Demand.
b. The rate of delivery of energy supplied under
this schedule in any hour shall not exceed the
purchasing Participant's Certified Interruptible
Demand.
c. Deliveries of energy may be received under this
schedule only when a Participant's maximum System
Demand would otherwise be greater than the
Participant's forecast System Demand for the current
season and shall not exceed that required to reduce
the System Demand to the forecast System Demand.
d. Interruptible Load Replacement Energy Service
shall not be scheduled in amounts which will overload
any transmission facilities or endanger the operation
of the interconnected systems of the Participants.
e. Interruptible Load Replacement Energy Service
transactions between Participants which are directly
interconnected shall normally take precedence over
transactions between Participants not directly
interconnected unless cost differential exceeds the
Operating Committee guidelines.
2.02 Transmission Service shall be available in accordance
with the procedures established under Service Schedule "F."
Section 3. Scheduling Deliveries
3.01 Prior to the scheduling of deliveries, the
Participants concerned, including the wheeling Participant or
Participants, if any, will agree on hour-by-hour amounts of
energy to be delivered.
Section 4. Schedule of Rates
4.01 The overall savings of an Interruptible Load
Replacement Energy Service transaction shall be equal to the
difference between the Incremental Cost of the supplying
Participant and the Displaced Cost of the receiving Participant
where Displaced Cost shall be determined as in Section 4.04
following. If the transmission facilities of a system not a
party hereto is involved in an Interruptible Load Replacement
Energy transaction, any transmission fees and losses to be paid
for the use of such facilities, shall be deducted from the
overall savings of the transactions in determining the net
savings of the transactions.
4.02 The receiving Participant shall pay the supplying
Participant for the energy supplied during each month an amount
equal to the Incremental Cost of the energy so supplied, plus
one-half of the overall savings of such transactions. However,
the amount paid by the receiving Participant shall not be less
than 110 percent of the supplying Participant's Incremental
Cost.
4.03 When the receiving Participant's Displaced Cost equals
or is lower than the supplying Participants Incremental Cost,
transactions may occur with the price being the minimum
specified in Paragraph 4.02.
4.04 The Displaced Cost per kilowatt-hour to be used under
this schedule shall be determined as the total revenues received
in the prior 12 months from retail customers whose load is
associated with the Interruptible Load Replacement Energy to be
purchased, divided by the kilowatt-hours of energy supplied
those customers over the same period. Participants that supply
wholesale loads which are associated with Interruptible Load
Replacement Energy to be purchased under this schedule shall
utilize the revenues received by the retail supplier(s) for the
energy supplied these customers in the computation of the
Displaced Cost.
Service Schedule M
General Purpose Energy Service
Section 1. Service to be Provided
1.01 This Schedule provides for the supply of General
Purpose Energy by any Participant to any other Participant to
enhance economic system operation.
Section 2. Conditions of Service
2.01 It is the intent hereof that, insofar as is
practicable, General Purpose Energy shall be used to improve the
overall economy of the systems involved in the transactions;
provided that such transactions are not scheduled in amounts
which will overload any transmission facility or endanger the
operation of the interconnected systems.
2.02 Transmission Service shall be available in accordance
with the procedures established under Service Schedule "F."
Section 3. Scheduling of Deliveries
3.01 Prior to beginning deliveries, the Participants
involved will agree on the terms of the transaction and on an
hour-by-hour schedule of energy to be delivered.
Section 4. Schedule of Rates
4.01 The receiving Participant shall pay the supplying
Participant for the General Purpose Energy supplied a charge of
up to 110 percent of the anticipated Incremental Cost of
supplying such energy, plus an additional charge per megawatt-
hour of up to S/96, where
S is the weekly demand charge for System Participation
Power Interchange Service as specified in Service Schedule
K, Section 3 and,
96 is the number of on-peak hours for a given week.
This additional charge shall not exceed S/6 multiplied by the
highest number of megawatt-hours delivered in any one hour
during that day, where
6 is the number of days in a week containing on-peak hours.
The total charge for each transaction shall not be less than 100
percent of the Incremental Cost of supplying the energy for the
transaction.
4.02 The Transmission Service charge and losses provisions
of Service Schedule "F" shall also apply.
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27.01
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated
Statements of Cash Flows and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> MAR-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,321,430
<OTHER-PROPERTY-AND-INVEST> 691,013
<TOTAL-CURRENT-ASSETS> 837,678
<TOTAL-DEFERRED-CHARGES> 365,265
<OTHER-ASSETS> 165,828
<TOTAL-ASSETS> 6,381,214
<COMMON> 171,250
<CAPITAL-SURPLUS-PAID-IN> 614,817
<RETAINED-EARNINGS> 1,284,516
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,066,267<F1>
0
240,469
<LONG-TERM-DEBT-NET> 1,667,951
<SHORT-TERM-NOTES> 577
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 168,500
<LONG-TERM-DEBT-CURRENT-PORT> 156,689
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,076,445<F1>
<TOT-CAPITALIZATION-AND-LIAB> 6,381,214
<GROSS-OPERATING-REVENUE> 718,709
<INCOME-TAX-EXPENSE> 36,637<F2>
<OTHER-OPERATING-EXPENSES> 588,766
<TOTAL-OPERATING-EXPENSES> 629,432
<OPERATING-INCOME-LOSS> 89,277
<OTHER-INCOME-NET> 5,143<F2>
<INCOME-BEFORE-INTEREST-EXPEN> 98,449
<TOTAL-INTEREST-EXPENSE> 31,239
<NET-INCOME> 67,210
3,061
<EARNINGS-AVAILABLE-FOR-COMM> 64,149
<COMMON-STOCK-DIVIDENDS> 45,660
<TOTAL-INTEREST-ON-BONDS> 27,271
<CASH-FLOW-OPERATIONS> 219,146
<EPS-PRIMARY> $0.94
<EPS-DILUTED> 0
<FN>
<F2>$4,029 thousand of non-operating income tax benefit is classified as
Income Tax Expense. The financial statement presentation includes this as
a component of Other Income (Expense).
<F1>$(4,316) thousand of Common Stockholders' Equity is classified as Other
Items-Capitalization and Liabilities. This represents the net of leveraged
common stock held by the Employee Stock Ownership Plan and the currency
translation adjustments.
</FN>
</TABLE>
EXHIBIT 99.01
Northern States Power Company Cautionary Factors
The Private Securities Litigation Reform Act of 1995
provides a new "safe harbor" for forward-looking statements to
encourage such disclosures without the threat of litigation
providing those statements are identified as forward-looking and
are accompanied by meaningful, cautionary statements identifying
important factors that could cause the actual results to differ
materially from those projected in the statement. Forward-
looking statements have been and will be made in written
documents and oral presentations of Northern States Power
Company (the Company). Such statements are based on
management's beliefs as well as assumptions made by and
information currently available to management. When used in the
Company's documents or oral presentations, the words
"anticipate", "estimate", "expect", "objective" and similar
expressions are intended to identify forward-looking statements.
In addition to any assumptions and other factors referred to
specifically in connection with such forward-looking statements,
factors that could cause the Company's actual results to differ
materially from those contemplated in any forward-looking
statements include, among others, the following:
- - Economic conditions including inflation rates and
monetary fluctuations;
- - Trade, monetary, fiscal, taxation, and environmental
policies of governments, agencies and similar
organizations in geographic areas where the Company has
a financial interest;
- - Customer business conditions including demand for their
products or services and supply of labor and materials
used in creating their products and services;
- - Financial or regulatory accounting principles or policies
imposed by the Financial Accounting Standards Board, the
Securities and Exchange Commission, the Federal Energy
Regulatory Commission and similar entities with
regulatory oversight;
- - Availability or cost of capital such as changes in:
interest rates; market perceptions of the utility
industry, the Company or any of its subsidiaries; or
security ratings;
- - Factors affecting utility and non-utility operations such
as unusual weather conditions; catastrophic weather-
related damage; unscheduled generation outages,
maintenance or repairs; unanticipated changes to fossil
fuel, nuclear fuel or gas supply costs or availability
due to higher demand, shortages, transportation
problems or other developments; nuclear or environmental
incidents; or electric transmission or gas pipeline system
constraints;
- - Employee workforce factors including loss or retirement
of key executives, collective bargaining agreements with
union employees, or work stoppages;
- - Increased competition in the utility industry, including:
industry restructuring initiatives; transmission system
operation and/or administration initiatives; recovery of
investments made under traditional regulation; nature of
competitors entering the industry; retail wheeling; a new
pricing structure; and former customers entering the
generation market;
- - Rate-setting policies or procedures of regulatory
entities, including environmental externalities;
- - Nuclear regulatory policies and procedures including
operating regulations and used nuclear fuel storage;
- - Social attitudes regarding the utility and power
industries;
- - Cost and other effects of legal and administrative
proceedings, settlements, investigations and claims;
- - Technological developments that result in competitive
disadvantages and create the potential for impairment of
existing assets;
- - Numerous matters associated with the proposed combination
of the Company and Wisconsin Energy Corporation to form
Primergy Corporation (Primergy), including:
- Regulatory authorities' decisions regarding business
combination issues including the approval of the business
combination as proposed, the rate structure of utility
operating companies after the merger, transmission system
operation and administration, or divestiture of gas
utility or non-regulated portions of the Company's
business;
- Qualification of the transaction as a pooling of
interests;
- Factors affecting the anticipated cost savings
including national and regional economic conditions,
national and regional competitive conditions,
inflation rates, weather conditions, financial market
conditions, and synergies resulting from the business
combination;
- Allocation of benefits of cost savings between
shareholders and customers, which will depend, among
other things, upon the results of regulatory
proceedings in various jurisdictions;
- Regulation of Primergy as a registered public utility
holding company and other different or additional
federal and state regulatory requirements or
restrictions to which Primergy and its subsidiaries
may be subject as a result of the business combination
(including conditions which may be imposed in
connection with obtaining the regulatory approvals
necessary to consummate the business combination, such
as the possible requirement to divest gas utility and
possibly certain non-regulated operations);
- Factors affecting dividend policy including results of
operations and financial condition of Primergy and its
subsidiaries and such other business considerations as
the Primergy Board of Directors considers relevant.
- - Factors associated with non-regulated investments
including conditions of final legal closing, foreign
government actions, foreign economic and currency risks,
political instability in foreign countries, partnership
actions, competition, operating risks, dependence on
certain suppliers and customers, domestic and foreign
environmental and energy regulations;
- - Most of the current project investments made by the
Company's subsidiary, NRG Energy, Inc. (NRG) consist of
minority interests, and a substantial portion of future
investments may take the form of minority interests,
which limits NRG's ability to control the development or
operation of the project;
- - Other business or investment considerations that may be
disclosed from time to time in the Company's Securities
and Exchange Commission filings or in other publicly
disseminated written documents.
The Company undertakes no obligation to publicly update or
revise any forward-looking statements, whether as a result of
new information, future events or otherwise.
