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<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 1994
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
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Commission File Number 1-4393
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PUGET SOUND POWER & LIGHT COMPANY
(Exact name of registrant as specified in its charter)
Washington 91-0374630
(State or other (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
411 - 108th Avenue N.E., Bellevue, Washington 98004-5515
(Address of principal executive offices)
(206) 454-6363
(Registrant's telephone number, including area code)
Exhibit Index on Page 61
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<PAGE>
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which listed
Common Stock, without par value,
$10 stated value N. Y. S. E.
Preference Share Purchase Rights N. Y. S. E.
7-7/8% Series Preferred Stock
(Cumulative $25 Par Value) N. Y. S. E.
Adjustable Rate Cumulative Preferred
Stock, Series B ($25 Par Value) N. Y. S. E.
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
Preferred Stock (Cumulative; $100 Par Value)
Preferred Stock (Cumulative; $25 Par Value)
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 by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /X/
The aggregate market value of the voting stock held by non-affiliates of the
registrant at December 31, 1994 was approximately $1,278,978,607.
The number of shares of the registrant's common stock outstanding at January
31, 1995 was 63,640,861.
Documents Incorporated by Reference
The Company's definitive proxy statement for its annual meeting of
shareholders on May 9, 1995, is incorporated by reference in Part III hereof.
<PAGE>
INDEX
Item Page
No. No.
Part I
1. Business................................................. 1
The Company.............................................. 1
Regulation and Rates..................................... 2
Power Resources.......................................... 3
Construction Financing................................... 9
Environment.............................................. 9
Operating Statistics.....................................12
Executive Officers.......................................14
2. Properties...............................................16
3. Legal Proceedings........................................16
4. Submission of Matters to a Vote of Security Holders......16
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................16
6. Selected Financial Data..................................17
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations............18
8. Financial Statements and Supplementary Data..............27
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure...................27
Part III
(Incorporated by reference from the Company's
definitive proxy statement issued in connection
with the 1994 Annual Meeting of Shareholders)
10. Directors and Executive Officers of the Registrant
11. Executive Compensation
12. Security Ownership of Certain Beneficial
Owners and Management
13. Certain Relationships and Related Transactions
Part IV
14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K......................................27
Signatures...............................................28
Exhibit Index............................................61
<PAGE>
DEFINITIONS
A.C. Alternating Current
AFUCE Allowance for Funds Used to Conserve Energy
AFUDC Allowance for Funds Used During Construction
BPA Bonneville Power Administration
CAAA Clean Air Act Amendments
Chelan Public Utility District No. 1 of
Chelan County, Washington
EPA Environmental Protection Agency
FERC Federal Energy Regulatory Commission
KW Kilowatts
KWH Kilowatt Hours
MW Megawatts (one MW equals one thousand KW)
MWH Megawatt Hours
Montana Power The Montana Power Company
NMFS National Marine Fisheries Service
NWPPC Northwest Power Planning Council
PRAM Periodic Rate Adjustment Mechanism
PRP Potentially Responsible Party
PUDs Washington Public Utility Districts
Washington Commission Washington Utilities and Transportation Commission
WPPSS Washington Public Power Supply System
<PAGE>
PART I
ITEM 1. BUSINESS
THE COMPANY
The Company is an investor-owned public utility incorporated in the
State of Washington furnishing electric service in a territory covering
approximately 4,500 square miles, principally in the Puget Sound region of
Washington State. The population of the Company's service area is over 1.8
million. In December 1994, the Company had approximately 823,100 total
customers, consisting of 731,700 residential, 86,200 commercial, 3,900
industrial and 1,300 other customers. For the year 1994, the Company added
approximately 18,500 customers, an annual growth rate of 2.3%. Growth in
total kilowatt-hour sales increased 9.0% in 1994 over 1993, due to increased
sales to other utilities and continuing growth in the number of customers in
1994.
During 1994, the Company's billed revenues were derived 47% from
residential customers, 33% from commercial customers, 14% from industrial
customers and 6% from sales to other utilities and others. During this
period, the largest single customer accounted for 3.3% of the Company's
operating revenues. The average number of kilowatt-hours billed per
residential customer served by the Company in 1994 was 12,319 kilowatt-
hours. At December 31, 1994, the peak power resources of the Company were
approximately 5,400,000 KW. The Company's historical peak load of
approximately 4,615,000 KW occurred on December 21, 1990.
The Company is affected by various seasonal weather patterns throughout
the year and, therefore, operating revenues and associated expenses are not
generated evenly during the year. Variations in energy usage by consumers
do occur from season to season and from month to month within a season,
primarily as a result of weather conditions. The Company normally
experiences its highest energy sales in the first and fourth quarters of the
year. Sales to other utilities also vary by quarters and years depending
principally upon water conditions for the generation of surplus hydro-
electric power, customer usage and the energy requirements of other
utilities. With the implementation of the Periodic Rate Adjustment
Mechanism ("PRAM") in October 1991, earnings are no longer significantly
influenced, up or down, by sales of surplus electricity to other utilities
or by variations in normal seasonal weather or hydro conditions. (See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Rate Matters")
The electric utility industry in general is facing a more competitive
environment, particularly in wholesale generation and industrial customer
markets, with the prospect of changes in utility regulation which could
accelerate competitive pressures. The National Energy Policy Act of 1992
has intensified competition in the wholesale electric generation market by
easing restrictions on producers of wholesale power and by authorizing the
Federal Energy Regulatory Commission ("FERC") to mandate access by wholesale
power producers to electric transmission systems owned by others. The
potential for increased competition at the retail level through mandated
retail wheeling has also been the subject of legislative and administrative
agency interest in a number of states including the state of Washington.
1
Retail wheeling is the term for regulatory changes that would allow
competing electric suppliers access to transmission and distribution lines
owned by others to distribute power to any industrial, commercial or
residential customer, regardless of service territory boundaries. In April
1994, utility regulators in California proposed a plan to open competition
in the sale of electricity at the retail level, suggesting that both
industrial and residential customers be allowed to shop freely for
electricity among competing suppliers. Recommendations by the utility
regulators to the California legislature are expected by the end of 1995.
In December 1994, the Washington Utilities and Transportation Commission
(the "Washington Commission")issued a notice of inquiry seeking comments
from utility companies, ratepayers and other interested parties on costs and
benefits of retail competition and on creating a new regulatory structure to
better accommodate the electric utility industry as it evolves towards
retail competition. Any substantial changes in utility regulation in
Washington state, such as mandating retail wheeling, would require
legislative action. The major credit rating agencies have expressed the
view that competitive developments are likely to increase business risks in
the electric utility industry, with resulting pressures on utility credit
quality and investor returns. The Company and other electric utilities now
face an increasing prospect of competition for customers and resources from
other investor-owned utilities, government agencies, independent power
producers, exempt wholesale power producers, industrial customers developing
cogeneration and other power resources, and suppliers of natural gas and
other fuels.
The Company seeks to build on the strengths of its efficient electric
distribution and transmission system to become a leading provider of energy
and related services to homes and businesses in the Pacific Northwest. To
prepare for a more competitive business environment, the Company has
committed itself to being a low cost supplier of electricity. The Company
has taken steps to reduce costs, including work force reductions, facility
consolidations and reductions in capital budgets. The Company has also
conducted joint customer service operations with Washington Natural Gas
Company to lower costs of serving customers of both utilities. The Company
intends to pursue opportunities for improved operating efficiencies and
productivity, including possible restructuring of its power supply resources
and contracts. The Company is also actively pursuing opportunities to
become a provider of new high value services such as wireless automated
meter reading and billing, to utility customers and other utilities.
During the period from January 1, 1990 through December 31, 1994, the
Company made gross utility plant additions of $834 million and retirements
of $105 million. Gross electric utility plant at December 31, 1994 was
approximately $3.3 billion which consisted of 46% distribution, 27%
generation, 15% transmission and 12% general plant and other.
The Company had 2,221 full-time equivalent employees on December 31,
1994, down from 2,775 at the end of 1992. This represents a workforce
reduction of 20% over the last two years.
REGULATION AND RATES
The Company is subject to the regulatory authority of (1) the
2
Washington Commission as to rates, accounting, the issuance of securities
and certain other matters, and (2) the FERC in the transmission of electric
energy in interstate commerce, the sale of electric energy at wholesale for
resale, accounting and certain other matters. The Washington Commission
consists of three Commissioners, each appointed for a six-year term by the
Governor of the State of Washington. (See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Rate Matters.")
POWER RESOURCES
During 1994, the Company's total energy production was supplied 30% by
its own resources, 25% through long-term contracts with several of the
Washington Public Utility Districts ("PUDs") that own hydroelectric projects
on the Columbia River, 44% from other firm purchases and 1% from non-firm
purchases.
<PAGE>
The following table shows the Company's resources at December 31, 1994,
and energy production during the year:
Peak Power Resources at
December 31, 1994 1994 Energy Production
----------------------- ----------------------
Kilowatts % Kilowatt-Hours %
--------- ----- -------------- -----
(Thousands)
Purchased Resources:
Columbia River
PUD Contracts (Hydro) 1,469,591 27.2 5,841,169 25.2
Other Hydro(a) 699,325 13.0 3,711,797 16.0
Thermal(a) 1,446,914 26.8 6,627,304 28.6
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Total Purchased 3,615,830 67.0 16,180,270 69.8
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Company-owned Resources:
Hydro 309,950 5.7 1,284,384 5.5
Coal 771,900 14.3 5,527,600 23.8
Natural gas/oil 702,350 13.0 199,949 0.9
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Total Company-owned 1,784,200 33.0 7,011,933 30.2
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Total Capability 5,400,030 100.0 23,192,203 100.0
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(a) Power received from other utilities is classified between hydro and
thermal based on the character of the utility system used to supply the
power or, if the power is supplied from a particular resource, the character
of that resource.
Company Owned Resources
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The Company and other utilities are joint owners of four mine-mouth,
coal-fired, steam-electric generating units at Colstrip, Montana,
3
approximately 100 miles east of Billings. The Company owns a 50% interest
(330,000 KW) in Units 1 and 2 and a 25% interest (350,000 KW) in Units 3 and
4.
The owners of the Colstrip Units purchase coal for the units from
Western Energy Company, an affiliate of Montana Power - one of the joint
owners, under the terms of long-term coal supply agreements, with escalation
provisions to cover actual mining cost increases and inflationary factors.
These contracts are expected to satisfy the majority of the requirements for
the units over their anticipated useful life.
A contract price reopener for both the base price and adjustment
provisions of the Colstrip 1 and 2 Coal Supply Agreement became effective
July 30, 1991. A dispute exists between the buyers, including the Company,
and the seller on this reopener. This dispute was arbitrated in January of
1995 and a decision on the arbitration is expected in the first quarter of
1995. The outcome is not expected to have a material adverse impact on the
financial condition, results of operations or liquidity of the Company.
There are several issues pending between the buyers, including the
Company and the seller, under the Colstrip 3 and 4 Coal Supply Agreement.
On February 23, 1995, the buyers, other than Montana Power, gave
Western Energy Company and Montana Power written notice of their intent to
submit a number of these issues to arbitration.
The Company owns a 7% interest (91,900 KW) in a coal-fired, steam-
electric generating plant near Centralia, Washington, with a net capability
of 1,313,000 KW. In 1991, the Company and other owners of the Centralia
Project renegotiated a long-term coal supply agreement with Pacific Power &
Light Company.
The Company also has the following plants with an aggregate net
generating capability of 1,012,300 KW: Upper Baker River hydro project
(103,000 KW) constructed in 1959; Lower Baker River hydro project (71,400
KW) reconstructed in 1968; White River hydro plant (63,400 KW) constructed
in 1912 with installation of the last unit in 1924; Snoqualmie Falls hydro
plant (44,000 KW), half the capability of which was installed during the
period 1898 to 1910 and half in 1957; two smaller hydro plants, Electron
(26,400 KW) and Nooksack Falls (1,750 KW), constructed during the period
1904 to 1929; a standby internal combustion unit (2,750 KW) installed in
1969; two oil-fired combustion turbine units (28,500 KW and 67,500 KW)
installed in 1972 and 1974, respectively; four combustion turbine units
(89,100 KW each) installed during 1981; and two combustion turbine units
(123,600 KW each) installed during 1984.
The Company's combustion turbines installed in 1981 and 1984 may be
fueled with natural gas or distillate oil. The Company has not entered into
contracts which assure a future long-term supply or price of fuel for the
Company's combustion turbines, and the future availability and prices of
fuel for the Company's combustion turbines are not assured.
The Company has applied to the FERC for an initial license for its
existing and operating White River project and authorization to install an
additional 14,000 KW generating unit. The initial license for the
4
Snoqualmie Falls project expired in December 1993, and the Company is
continuing the FERC application process to relicense the project. The
Company has also applied for a license to expand its 1,750 KW Nooksack Falls
project which is currently an unlicensed facility.
Columbia River Projects
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The purchase of power from the Columbia River projects is generally on
a "cost of service" basis under which the Company pays a proportionate share
of the annual debt service and operating and maintenance costs of each
project in direct ratio to the amount of power annually allocated to it.
Such payments are not contingent upon the projects being operable. These
projects are financed through substantially level debt service payments, and
their annual costs should not vary significantly over the term of the
contracts unless additional financing is required to meet the costs of major
maintenance, repairs or replacements or license requirements. The average
cost of power purchased from these projects is approximately 12.1 mills per
KWH.
As of December 31, 1994, the Company was entitled to purchase portions
of the power output of the PUDs' projects as set forth in Note 16 to the
Consolidated Financial Statements.
The Company has contracted to purchase a share of the output of the
original units of the Rock Island Project that equals 61.4% through June 30,
1995, decreases gradually to 50% of the output until July 1, 1999, and
remains unchanged thereafter for the duration of the contract. The Company
has contracted to purchase the entire output of the additional Rock Island
units for the duration of the contract, except that the Company's share of
output of the additional units may be reduced not in excess of 10% per year
beginning July 1, 2000, to a minimum of 50% upon the exercise of rights of
withdrawal by Chelan for use in its local service area. The Company has
contracted to purchase a share of the output of the Rocky Reach Project that
remains unchanged for the duration of the contract. Under terms of a
withdrawal of power settlement, the Company's share of the output of the
Wells Project is currently 34.8% and is expected to decrease to 33.6% by
September 1, 1995. However, the Company's share of the output can be
reduced to 31.3% at any time upon the exercise of withdrawal rights by
Douglas County PUD. The Company has contracted to purchase a share of the
output of the Priest Rapids and Wanapum projects that remains unchanged for
the duration of the contracts.
The eleven turbines at Rocky Reach are in the process of being
replaced. Turbine replacement is planned for all ten units at Wanapum.
Also, as a result of FERC settlements, it is anticipated that installation
of fish bypasses will be required at Rocky Reach, Rock Island, Priest
Rapids and Wanapum Dams. These and other multi-year capital projects are
expected to result in increases in annual power costs as they progress. The
Company expects the increases in power costs, due to debt service for
capital expenditures, to average 2.5% to 3.0% annually for the next five
years.
In 1964, the Company and fifteen other utilities and agencies in the
5
Pacific Northwest entered into a long-term coordination agreement extending
until June 30, 2003 (the "Coordination Agreement"). This agreement provides
for the coordinated operation of substantially all of the hydroelectric
power plants and reservoirs in the Pacific Northwest. A 1995 biological
opinion from the National Marine Fisheries Service ("NMFS"), if implemented
in its present form, could reduce the benefits provided by the Coordination
Agreement.
Certain utilities in the northwest United States and Canada are
obtaining the benefits of over 1,000,000 KW of additional power as a result
of the ratification of a treaty between the United States and Canada under
which Canada is providing approximately 15,500,000 acre-feet of storage on
the upper Columbia River. As a result of this storage, the Company obtains
firm power based upon its percentage entitlement under its Columbia River
contracts, currently approximately 106,300 KW. In addition, the Company has
contracted to purchase 17.5% of Canada's share of the power resulting from
such storage (111,524 KW capacity and 49,993 KW average energy in the 1994-
95 contract year, April 1 to March 31, which amounts decrease gradually
until expiration of the contract in 2003). The Company has also contracted
to purchase from the Bonneville Power Administration ("BPA") supplemental
capacity in amounts that decrease gradually until expiration of the contract
in 2003. The amount of supplemental capacity currently purchased is
approximately 38,032 KW.
Late in 1994, the United States (through the BPA) and Canada signed a
Memorandum of Understanding regarding the disposition of the Canadian share
of benefits ("Entitlement") from 1998 to 2024. For a payment of $180
million the United States will purchase a portion of the Entitlement
capacity. BPA and Canadian negotiators are working on a definitive
agreement. Concurrently, BPA negotiators and representatives of
participants in the five Mid Columbia projects from which the Company
purchases power are developing associated agreements which will define the
amount of payment, if any, and the amounts of power which each project, and
in turn each purchaser including the Company, will contribute to the
delivery of the Entitlement to Canada.
See "ENVIRONMENT - Federal Endangered Species Act" for discussion of
the fishery enhancement plan related to these projects.
Contracts and Agreements with Other Utilities
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On September 17, 1985, the Company and BPA entered into a settlement
agreement settling the Company's claims against BPA resulting from BPA's
action in halting construction on Washington Public Power Supply System
("WPPSS") Nuclear Project No. 3 in which the Company has a five percent
interest. The settlement includes a Settlement Exchange Agreement
("Bonneville Exchange Power Contract") under which the Company is receiving
from BPA for a period of approximately 30.5 years, beginning January 1,
1987, a certain amount of electric power determined by a formula and
depending on the equivalent annual availability factors of several surrogate
nuclear plants. The power is received during the months of November through
April. Under the contract, the Company is guaranteed to receive not less
than 191,667 MWH in each contract year until the Company has received total
6
deliveries of 5,833,333 MWH. BPA may request energy at times not needed by
the Company during the months of September through June of each contract
year. The payment to the Company for such energy would be based on the
actual costs to produce such energy up to the operating and maintenance
costs of the Company's oil and natural gas fired combustion turbines.
On April 4, 1988, the Company executed a 15-year contract for the
purchase of firm energy supply from Washington Water Power Company. This
agreement calls for the delivery of 100 MW of capacity and 657,000 MWH of
energy from the Washington Water Power system annually (75 annual average
MW). Minimum and maximum delivery rates are prescribed. Under this
agreement, the energy is to be priced at Washington Water Power's average
generation and transmission cost.
On October 27, 1988, the Company executed a 15-year contract for the
purchase of firm power and energy from Pacific Power & Light Company. Under
the terms of the agreement, the Company receives 120 average MW of energy
and 200 MW of peak capacity.
On November 23, 1988, the Company executed an agreement to purchase
surplus firm power from BPA. Under the agreement, the Company receives 150
average MW of energy and 300 MW of peak capacity from BPA between October 1
and March 31 of each contract year. The contract extends for 20 years,
ending in 2008. The sale will convert to a power-for-power exchange on June
30, 2001, or earlier, if BPA provides the Company with a five-year notice
that it no longer has surplus energy available to support the power sale.
On October 1, 1989, the Company signed a contract with Montana Power
under which Montana Power provides, from its share of Colstrip Unit 4, to
the Company 71 average MW of energy (94 MW of peak capacity) over a 21-year
period. On February 27, 1995, the Company delivered to Montana Power notice
of termination of the contract based on Montana Power's failure to arrange
for firm contractual transmission rights for such energy as required by the
contract. On February 28, 1995, Montana Power filed a lawsuit in a Montana
State Court and obtained a temporary restraining order regarding the
termination. The Company has filed a notice of removal of the Montana State
Court action to the Federal District Court in Montana. On March 7, 1995,
the Company filed a lawsuit in the United Stated District Court for the
Western District of Washington in response to Montana Power's failure to
terminate the contract as required and for failure to reimburse the Company
for approximately $39 million in power costs, which are due upon termination
under contract provisions.
On December 11, 1989, the Company executed a conservation transfer
agreement with Snohomish County PUD. Snohomish County PUD, together with
Mason and Lewis County PUDs, will install conservation measures in their
service areas. The agreement calls for the Company to receive the power
saved over the expected 20-year life of the measures. The agreement calls
for BPA to deliver the conservation power to the Company from March 1, 1990
through June 30, 2001, and for Snohomish County PUD to deliver the conser-
vation power for the remaining term of the agreement. Power deliveries
gradually increase over the first five years of the agreement, roughly
matching the installation of the conservation measures, and will reach six
average MW of energy in the fifth year. Under the agreement, deliveries of
7
conservation power will then remain at six average MW of energy throughout
the term of the agreement.
The Company executed an exchange agreement with Pacific Gas & Electric
Company which became effective on January 1, 1992. Under the agreement, 300
MW of capacity together with 413,000 MWH of energy are exchanged every year
on a unit for unit basis. No payments are made under this agreement.
Pacific Gas & Electric Company is a summer peaking utility and will provide
power during the months of November through February. The Company is a
winter peaking utility and will provide power during the months of June
through September. By giving proper notice, either party may terminate the
contract for various reasons.
Contracts and Agreements with Non-Utilities
- -------------------------------------------
The Company has contracted to purchase the output from a number of non-
utility generating resources. The Company currently has available 648 MW of
capacity from natural gas fired cogeneration, 40.9 MW from small hydro
generation and 28 MW from municipal solid waste and others. Payments by the
Company to owners of these non-utility generating resources are subject to
the delivery of power. (See Note 16 to the Consolidated Financial
Statements)
Energy Conservation
- -------------------
The Company offers programs designed to help new and existing customers
conserve electric energy. In addition to providing energy audits and
analyses, the Company may provide grants and rebates to encourage the
installation of energy conservation measures in customer facilities. Energy
conservation measures installed in 1994 are expected to result in annualized
savings of approximately 189,400 MWH.
The Company's energy conservation expenditures are accumulated,
included in rate base and amortized to expense over a ten year period at the
direction of the Washington Commission. The Company's total unamortized
conservation balance, at December 31, 1994, was $241 million. The amount
included in rate base by the Washington Commission in its September 1994
PRAM order, based on expenditures through April 30, 1994, was $229 million.
Conservation investments made from May 1, 1994 to December 31, 1994 are
expected to be included in rates beginning October 1, 1995. The Washington
Commission has authorized the Company to accrue, as non-cash income, the
carrying costs on energy conservation expenditures until such investments
are reflected in rates. (See "Management's Discussion and Analysis of
Financial Condition and Results of Operations.")
The energy conservation grants the Company makes to its customers to
invest in energy efficiency improvements to their homes and businesses do
not produce collateral which the Company can use to finance those grants.
In principle, therefore, energy conservation has been financed by the
Company entirely through the use of equity capital. To remedy this
situation, the State of Washington enacted a new law effective June 9, 1994.
This new law provides, if certain conditions are met, that a utility would
8
be able to issue securities backed by a statutory requirement that rate
revenues be provided to repay those securities. The law provides the
Company, with the Washington Commission's approval, with an avenue to
refinance its existing investment in energy conservation and to finance new
conservation investment in a more cost-effective manner.
On February 16, 1995, the Company filed an application with the
Washington Commission for approval to issue securities for the purpose of
selling to a trust energy conservation investments currently included in
customer rates.
CONSTRUCTION FINANCING
The Company estimates its construction expenditures, which include
energy conservation expenditures and exclude Allowance for Funds Used During
Construction ("AFUDC") and Allowance for Funds Used to Conserve Energy
("AFUCE"), for 1995 and 1996 to be $154.9 million and $198.1 million,
respectively. The Company expects to fund an average of 72% of its
estimated construction expenditures (excluding AFUDC and AFUCE) in 1995 and
1996 from cash from operations (net of dividends, AFUDC and AFUCE), and to
fund the balance through the sale of securities. (See "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
for a discussion of the Company's construction program.) The Company's
ability to finance its future construction program is dependent upon market
conditions and maintaining a level of earnings sufficient to permit the sale
of additional securities. In determining the type and amount of future
financings, the Company may be limited by restrictions contained in its
Mortgage Indenture, Articles of Incorporation and certain loan agreements.
Under the most restrictive tests, at December 31, 1994, the Company
could issue (i) approximately $745 million of additional first mortgage
bonds or (ii) approximately $373 million of additional preferred stock at an
assumed dividend rate of 8.55% or (iii) a combination thereof.
ENVIRONMENT
The Company's operations are subject to environmental regulation by
federal, state and local authorities. Capital expenditures for
environmental controls on all Company facilities are estimated at $22.6
million for the period 1995 through 1997. Due to the inherent uncertainties
surrounding the development of federal and state environmental and energy
laws and regulations, the Company cannot determine the impact such laws may
have on its existing and future facilities.
Federal Comprehensive Environmental Response, Compensation and
Liability Act, and the Washington State Model Toxics Control Act
- ----------------------------------------------------------------
The federal Comprehensive Environmental Response, Compensation and
Liability Act (commonly referred to as the "Superfund Act") subjects certain
parties to liability for remedial action at contaminated disposal sites.
The Company has been named by the Environmental Protection Agency
("EPA") as a Potentially Responsible Party ("PRP") at four sites in
Washington State. The Company has reached settlements with the EPA on all
9
four sites under which the Company has paid approximately $7.6 million. To
date, the Company has recovered $3.6 million from its insurance companies in
connection with remediation and legal costs and expects to recover an
additional $3.1 million in the next twelve months. Estimated future
remediation costs at these four sites are expected to be $0.8 million.
These sites represent all significant superfund sites at which the Company
believes it has liability. There is, however, no assurance that all
contaminated sites and contaminants for which the Company may have a
responsibility have been identified or that remedial actions planned to date
at current sites, including actions pursuant to consent decrees, will be
adequate.
In addition, the Company has remediated two locations at the Company's
Electron Generating Station under provisions of the state's Model Toxics
Control Act beginning in 1991 and completed in 1992. A final remedial
report has been filed with and reviewed by the Washington Department of
Ecology. No further action by the Company is expected to be required.
The Company also participated in a joint research project with the
Electric Power Research Institute to clean up the Snoqualmie Railroad site
in the town of Snoqualmie, Washington. The site has been leased from the
Company since 1959 by the non-profit Puget Sound Railway Historical
Association. The contamination consists of heavy petroleum hydrocarbons
which were used as lubricants for railroad equipment. The purpose of the
project was to provide a field demonstration of new technologies to treat
heavy molecular weight petroleum hydrocarbons in soil. Remediation of the
research project site was completed in February 1994.
The Company has also commenced a program to test, replace and remediate
certain underground storage tanks as required by federal and state laws.
Remediation and testing of Company vehicle service facilities and storage
yards have also been commenced. Estimated future remediation costs at
Company-owned sites was $2.7 million at December 1994. (See Note 16 to the
Consolidated Financial Statements for further discussion of environmental
obligations and the related regulatory treatment.)
Federal Clean Air Act Amendments of 1990
- ----------------------------------------
The Company has an ownership interest in coal-fired, steam-electric
generating plants at Centralia, Washington and Colstrip, Montana which are
subject to the federal Clean Air Act Amendments of 1990 ("CAAA") and other
regulatory requirements.
The Centralia Project and the Colstrip Projects meet the sulfur dioxide
limits of the CAAA in Phase I (1995). Pacific Power & Light Company, which
operates the Centralia Project, is working on compliance plans to meet the
Phase II limits in the year 2000.
Montana Power, which operates the Colstrip 3 and 4 Project, is working
to meet the Phase II limits in the year 2000. Under the CAAA, allowances
may be used to achieve compliance. It is believed that Units 1 and 2 may
have an excess of allowances above what is currently set for Phase II
requirements and that Units 3 and 4 have sufficient allowances for Phase II
requirements.
10
The Company owns combustion turbine units which are capable of being
fueled by natural gas or oil. The nature of these units provides
operational flexibility in meeting air emission standards.
There is no assurance that in the future environmental regulations
affecting sulfur dioxide or nitrogen oxide emissions may not be further
restricted, and there is no assurance that restrictions on emissions of
carbon dioxide or other combustion by-products may not be imposed.
Federal Endangered Species Act
- ------------------------------
In November 1991, the NMFS listed the Snake River Sockeye as an
endangered species pursuant to the federal Endangered Species Act. Since
the Sockeye listing, the Snake River fall and spring/summer Chinook have
also been listed as threatened. In response to the listings, a team of
experts was formed to develop a plan for the recovery needs of these
species. In anticipation of the listings, the Northwest Power Planning
Council ("NWPPC") previously developed a fishery enhancement plan which
combines increased springtime flows with habitat enhancements, harvest
reductions, and other measures. The spring flow augmentation portion of the
plan began in 1991. Federal agencies that operate the Federal Columbia
River Power System must consult with the NMFS to determine whether any
action they undertake will unduly jeopardize the listed species. In 1995,
the NMFS issued a biological opinion that could, depending on flow
conditions and implementation procedures, significantly change the operation
of the Federal Columbia River Power System.
The NWPPC plan and plans developed by NMFS affect the Mid-Columbia
projects from which the Company purchases power on a long-term basis, and
will further reduce the flexibility of the regional hydroelectric system.
Although the full impacts are unknown at this time, the plan ultimately
developed by NMFS could shift an amount of the Company's generation from the
Mid-Columbia projects from winter periods into the spring when it is not
needed for system loads, and will increase the potential for spill and loss
of generation at the Mid-Columbia projects. Under the NWPPC's plan
presently in effect, in years of critical water flows, the maximum amount of
generation that the Company would have to transfer into the spring is
limited to approximately 275,000 MWH. The Company's share of energy
production from the Mid-Columbia during 1994 was approximately 5,841,000 MWH
and the total production from all resources was more than 23,192,000 MWH.
Other species are also proposed for listing as endangered species and
could further restrict system flexibility and energy production.
11
<PAGE>
Puget Sound Power & Light Company
OPERATING STATISTICS
<TABLE>
<CAPTION>
Year Ended or on December 31 1994 1993 1992 1991 1990
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues by classes
(thousands):
- --------------------------------------------------------------------------------------------
Residential $ 532,124 $ 502,037 $ 443,490 $480,356 $452,385
Commercial 375,751 356,586 323,764 310,824 288,346
Industrial 163,574 150,063 138,416 127,164 122,983
Other consumers 38,759 28,189 35,779 26,897 25,731
- --------------------------------------------------------------------------------------------
Operating revenues billed
to consumers 1,110,208 1,036,875 941,449 945,241 889,445
Unbilled revenues -
net increase (decrease) (2,522) 14,409 15,080 (16,216) 19,171
PRAM accrual 25,835 42,100 42,119 670 --
- --------------------------------------------------------------------------------------------
Total operating revenues
from consumers 1,133,521 1,093,384 998,648 929,695 908,616
Other utilities 60,537 19,494 26,322 27,074 26,657
- --------------------------------------------------------------------------------------------
Total operating revenues 1,194,058 1,112,878 $1,024,970 $956,769 $935,273
- --------------------------------------------------------------------------------------------
Number of customers (average):
Residential 723,566 708,123 692,100 673,883 651,060
Commercial 85,203 82,875 80,963 78,691 76,536
Industrial 3,851 3,715 3,659 3,574 3,502
Other 1,325 1,289 1,254 1,226 1,193
- --------------------------------------------------------------------------------------------
Total customers (average) 813,945 796,002 777,976 757,374 732,291
KWH generated, purchased
and interchanged (thousands):
Total Company generated 7,011,932 6,414,311 7,420,058 6,819,348 6,630,767
Purchased power 16,268,042 14,608,899 13,408,522 14,770,597 14,212,117
Interchanged power (net) (87,771) 174,478 (118,346) (139,110) 62,964
- --------------------------------------------------------------------------------------------
Total energy output 23,192,203 21,197,688 20,710,234 21,450,835 20,905,848
Losses and Company use (1,291,322) (1,096,599) (1,202,194) (1,267,919) (1,334,337)
- --------------------------------------------------------------------------------------------
Total energy sales 21,900,881 20,101,089 19,508,040 20,182,916 19,571,511
- --------------------------------------------------------------------------------------------
Electric energy sales, KWH
(thousands):
Residential 8,913,903 8,974,787 8,297,293 8,906,470 8,364,737
Commercial 6,301,568 6,175,911 5,945,284 5,930,385 5,565,672
Industrial 3,724,931 3,690,473 3,704,450 3,598,683 3,559,574
Other consumers 200,622 196,246 193,563 185,879 182,568
- --------------------------------------------------------------------------------------------
Total energy billed
to consumers 19,141,024 19,037,417 18,140,590 18,621,417 17,672,551
Unbilled energy sales -
net increase (decrease) (72,352) 139,329 209,565 (309,279) 343,053
- --------------------------------------------------------------------------------------------
12
(Continued from prior page 1994 1993 1992 1991 1990
- --------------------------------------------------------------------------------------------
Total energy sales
to consumers 19,068,672 19,176,746 18,350,155 18,312,138 18,015,604
Sales to other
electric utilities 2,832,209 924,343 1,157,885 1,870,778 1,555,907
- --------------------------------------------------------------------------------------------
Total energy sales 21,900,881 20,101,089 19,508,040 20,182,916 19,571,511
- --------------------------------------------------------------------------------------------
Per residential customer:
Annual use (KWH) 12,319 12,674 11,989 13,217 12,848
Annual billed revenue $735.42 $708.97 $640.79 $712.82 $694.84
Billed revenue per KWH $.0597 $.0559 $.0534 $.0539 $.0541
Company-owned generation
capability - kilowatts:
Hydro 309,950 309,950 309,950 309,950 309,950
Steam 771,900 857,700 857,700 857,700 857,700
Other 702,350 702,350 702,350 702,350 702,350
- --------------------------------------------------------------------------------------------
Total 1,784,200 1,870,000 1,870,000 1,870,000 1,870,000
- --------------------------------------------------------------------------------------------
Heating degree days 4,341 4,691 4,090 4,556 4,773
% of normal of 30 year
average (5,121) 84.8% 91.6% 79.9% 89.0% 93.2%
Load factor 54.7% 52.5% 57.0% 54.8% 47.8%
</TABLE>
13
<PAGE>
EXECUTIVE OFFICERS AT DECEMBER 31, 1994:
Name Age Offices
- ---------------- --- ---------------------------------------------------
R. R. Sonstelie 49 President and Chief Executive Officer since 1992;
President and Chief Operating Officer 1991-1992;
President and Chief Financial Officer 1987-1991;
Executive Vice President 1985-1987;
Senior Vice President Finance 1983-1985;
Vice President Engineering and Operations 1980-1983;
Director since 1987.
W. S. Weaver 50 Executive Vice President and Chief Financial Officer
and Director since 1991. For more than five years
prior to that time, a Partner in the law firm Perkins
Coie.
R. V. Myers 61 Senior Vice President since May 10, 1994;
Senior Vice President Operations 1985-1994;
Vice President Engineering and Operations 1983-1985;
Vice President Generation Resources 1980-1983.
G. B. Swofford 53 Senior Vice President Customer Operations since
May 10, 1994; Vice President Divisions and Customer
Services 1991-1994; Vice President Rates and Customer
Programs 1986-1991; Director Conservation and
Division Services 1980-1986.
S. M. Vortman 49 Senior Vice President Corporate & Regulatory
Relations since May 10, 1994; Vice President
Strategic Planning and Regulatory Affairs
February 10, 1994 - May 9, 1994; Vice President
Corporate Services 1992-1994; Director Real Estate
1990-1992; Manager Community and Economic
Development 1986-1990.
R. G. Bailey 55 Vice President Power Systems since 1980.
J. W. Eldredge 44 Chief Accounting Officer since October 10, 1994;
Corporate Secretary and Controller since 1993;
Controller since 1988; Manager Budgets and
Performance 1987-1988; Manager General Accounting
1984-1987.
G. N. Ferencz 48 Vice President Divisions since May 10, 1994; Director
Division Services 1992-1994; General Manager Thurston
Division 1990-1992; Division Administrator Southern
Division 1982-1990.
D. E. Gaines 37 Treasurer since October 10, 1994; Director Strategic
Planning 1992-1994; Manager Financial Planning 1986 -
1992.
14
J. L. Henry 49 Vice President Engineering and Operating Services
since January 11, 1994; Vice President Operations
Services 1991-1994; Director South Central Division
1990-1991; Director Division Operations 1984-1990.
C. A. Knutsen 48 Vice President Administration and Corporate Services
since February 10, 1994; Vice President Corporate
Planning 1989-1994; Director Strategic Planning
1987-1988; Manager Demand and Resource Evaluation
Project 1986-1987.
J. R. Lauckhart 46 Vice President Power Planning since 1991;
Director Power Planning 1986-1991.
Officers are elected for one-year terms.
15
<PAGE>
ITEM 2. PROPERTIES
The principal generating plants owned by the Company are described under
Item 1 - "Business - Power Resources." The Company owns its transmission and
distribution facilities, and various other properties. Substantially all
properties of the Company are subject to the lien of the Company's Mortgage
Indenture.
ITEM 3. LEGAL PROCEEDINGS
See Notes 10 and 16 to the Consolidated Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - NONE
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
The Company's common stock is traded on the New York Stock Exchange
(symbol PSD). The number of stockholders of record of the Company's common
stock at December 31, 1994, was 62,364.
The Company has paid dividends on its common stock each year since 1943
when such stock first became publicly held. Future dividends will be
dependent upon earnings, the financial condition of the Company and other
factors.
Certain provisions relating to the Company's senior securities limit
funds available for payment of dividends to net income available for
dividends on common stock (as defined in the Company's Mortgage Indenture)
accumulated after December 31, 1957, plus the sum of $7.5 million. As of
December 31, 1994, the balance of earnings reinvested in the business that
was not restricted as to dividends on common stock was approximately $251
million. (See Note 6 to the Consolidated Financial Statements.)
Dividends paid and high and low stock prices for each quarter over the
last two years were:
1994 1993
--------------------------- ---------------------------
Price Range Price Range
--------------- Dividends --------------- Dividends
Quarter Ended High Low Paid High Low Paid
- ------------- ------ ------ --------- ------ ------ ---------
March 31 24-7/8 22 $.46 28-3/4 26-1/8 $.45
June 30 22-3/4 16-1/2 $.46 29-3/8 26-1/4 $.46
September 30 20 18-3/8 $.46 29-3/4 25-5/8 $.46
December 31 21 19-3/8 $.46 26-7/8 23-1/2 $.46
16
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
Year Ended December 31 1994 1993 1992 1991 1990
- ---------------------------- --------- ---------- ---------- ---------- ----------
(Thousands of Dollars except per share data)
<S> <C> <C> <C> <C> <C>
Operating Revenue $1,194,058 $1,112,878 $1,024,970 $ 956,769 $ 935,273
Operating Income $ 193,498 $ 210,980 $ 214,670 $ 213,731 $ 215,376
Net Income $ 120,059 $ 138,327 $ 135,720 $ 132,777 $ 132,343
Income for Common Stock $ 104,328 $ 121,885 $ 121,836 $ 122,738 $ 119,948
Common Shares Outstanding -
Weighted Average 63,632,057 60,930,859 56,283,949 55,561,647 55,561,647
Earnings Per Common Share
(Note 1 to the
Financial Statements) $1.64 $2.00 $2.16 $2.21 $2.16
Dividends Per Common Share $1.84 $1.83 $1.79 $1.76 $1.76
Book Value Per Common Share $18.43 $18.65 $17.76 $16.96 $16.52
Total Assets at Year End* $3,463,770 $3,341,130 $2,997,721 $2,676,438 $2,602,536
Long-term Obligations $ 963,298 $1,036,079 $1,044,992 $1,052,309 $1,005,834
Redeemable Preferred Stock $ 91,242 $ 93,176 $ 93,822 $ 20,189 $ 28,766
</TABLE>
* The Company adopted Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes," effective January 1, 1993, providing deferred
taxes for items which previously had tax benefits flowed through to
ratepayers. A corresponding regulatory asset was recorded under long-term
assets. For years prior to 1993, the Company has reclassified as
liabilities deferred taxes previously netted with plant and other property
and investments.
17
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net income in 1994 was $120.1 million on operating revenues of $1.194
billion, compared to $138.3 million on operating revenues of $1.113 billion
in 1993 and $135.7 million on operating revenues of $1.025 billion in 1992.
Income for common stock was $104.3 million, $121.9 million and $121.8
million for 1994, 1993 and 1992, respectively.
Earnings per share in 1994 were $1.64 on 63.6 million weighted average
common shares outstanding during the period compared to $2.00 on 60.9
million weighted average common shares outstanding in 1993 and $2.16 on 56.3
million weighted average common shares outstanding in 1992.
Return on the average book value of the Company's common equity in 1994 was
8.9%, compared to 11.0% in 1993 and 12.6% in 1992. The dividend payout
ratio was 112.2% in 1994, compared to 91.5% in 1993 and 82.9% in 1992.
The decline in net income during 1994 reflects after-tax charges totaling
$13.6 million associated with the Company's two voluntary early retirement
and separation programs and related business office and service facility
consolidations. These charges, recorded in other operation expenses,
represent a decrease in earnings per common share of $0.21 for the period.
Also contributing to this decline in net income was the reduction in the
Company's allowed rate of return on common equity from 12.8% to 10.5%
resulting from the Company's September 21, 1993 general rate order.
Total kilowatt-hour sales to ultimate consumers in 1994 were 19.1 billion,
compared with 19.2 billion in 1993 and 18.4 billion in 1992. Kilowatt-hour
sales to other utilities were 2.8 billion in 1994, 0.9 billion in 1993 and
1.2 billion in 1992.
The preferred stock dividend accrual decreased $0.7 million in 1994 compared
to 1993. The decrease was due to the redemptions of the $50 million,
Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred
Stock ("FLEX DARTS"), Series B in July 1993 and the $40 million, Adjustable
Rate Cumulative Preferred Stock, Series A ($100 par value) in February 1994.
These decreases were partially offset by the issuance in February 1994 of
the $50 million, Adjustable Rate Cumulative Preferred Stock, Series B ($25
par value).
The preferred stock dividend accrual increased $2.6 million in 1993 and $3.8
million in 1992 compared to 1991 primarily due to the issuance of the 7.75%
Series Preferred Stock in March 1992 and the 7.875% Series Preferred Stock
in July 1992. This was partially offset by the reacquisition of the Series
A FLEX DARTS in April 1992. The 1993 increase was also partially offset by
the reacquisition of the Series B FLEX DARTS in July 1993. Lower dividend
rates associated with the FLEX DARTS were also an offsetting factor during
1992.
18
<PAGE>
Years Ending December 31
Increase (Decrease) Over Preceding Year
(Dollars in Millions)
1994 1993 1992
- -----------------------------------------------------------------------
Operating revenues
General rate increase $27.0 $ 14.2 $ --
PRAM surcharge billed 29.6 48.8 44.8
Accrual of revenue under
the PRAM - Net (16.3) -- 41.5
BPA Residential Purchase and
Sale Agreement 2.3 (15.0) (25.1)
Sales to other utilities 41.0 (6.8) (0.8)
Load and other changes (2.4) 46.7 7.8
- -----------------------------------------------------------------------
Total operating revenue changes 81.2 87.9 68.2
- -----------------------------------------------------------------------
Operating expenses
Purchased and interchanged power 77.1 81.5 18.2
Fuel (5.5) (4.4) 11.9
Other operation expenses 26.0 5.9 9.9
Maintenance (2.5) (1.8) (0.4)
Depreciation and amortization 0.1 (7.2) 6.6
Taxes other than federal income taxes 7.2 6.1 4.8
Federal income taxes (3.7) 11.5 16.3
- -----------------------------------------------------------------------
Total operating expense changes 98.7 91.6 67.3
- -----------------------------------------------------------------------
Allowance for funds used during
construction ("AFUDC") (0.8) 1.5 (1.0)
Other income 1.0 (5.5) 12.3
Interest charges 1.0 (10.3) 9.3
- -----------------------------------------------------------------------
Net income changes ($18.3) $ 2.6 $ 2.9
=======================================================================
The following information pertains to the changes outlined in the table
above:
OPERATING REVENUES
Revenues since October 1, 1994, increased as a result of rates authorized
by the Washington Utilities and Transportation Commission (the "Washington
Commission") under the fourth Periodic Rate Adjustment Mechanism ("PRAM")
filing. Revenues since October 1, 1993, increased as a result of rates
authorized by the Washington Commission in its general rate order issued on
September 21, 1993. Revenues since October 1, 1992, increased as a result
of rates authorized by the Washington Commission under the second PRAM
filing. (See "Rate Matters.")
Revenues have been reduced by virtue of the credit that the Company
received through the Residential Purchase and Sale Agreement with the
19
Bonneville Power Administration ("BPA"). This agreement enables the
Company's residential and small farm customers to receive the benefits of
lower-cost federal power. A corresponding reduction is included in
purchased and interchanged power expenses.
Revenues in 1993 were higher due to PRAM rate adjustments and continuing
load growth. Revenues in 1992 were higher as a result of the recognition
of $6.7 million in September 1992 related to incentive payments authorized
by the Washington Commission for meeting energy conservation targets during
1991. These revenues were collected in rates beginning October 1, 1992.
Although the Company is dependent on purchased power to meet customer
demand, it may, from time to time, have energy available for sale to other
utilities, depending principally upon water conditions for the generation
of hydroelectric power, customer usage and the energy requirements of other
utilities.
OPERATING EXPENSES
Purchased and interchanged power expenses increased $77.1 million in 1994
when compared to 1993. Higher payments related to new firm power purchase
contracts from non-utility generators contributed an increase of $89.3
million. Also contributing to the increase was a reduction in credits
associated with the Residential Purchase and Sale Agreement with BPA of
$2.2 million. (See discussion of the Residential Purchase and Sale
Agreement under "Operating Revenues.") Partially offsetting these increases
were lower secondary power purchases from other utilities of $15.6 million.
Purchased and interchanged power expenses increased $81.5 million in 1993.
Purchased power expenses increased $95.8 million due primarily to new firm
power purchase contracts and higher secondary power purchases from other
utilities. This increase was partially offset by increased credits
associated with the Residential Purchase and Sale Agreement with BPA, which
resulted in a reduction of $14.4 million.
Purchased and interchanged power expenses increased $18.2 million in 1992.
Higher purchased power expenses of $42.3 million were influenced by new
firm power purchase contracts and higher costs on certain firm power
purchase contracts with other utilities. The Residential Purchase and Sale
Agreement with BPA resulted in a reduction of $23.9 million.
Fuel expense decreased $5.5 million in 1994 as the Company purchased
additional power from cogeneration facilities rather than run Company-owned
gas turbines to generate electricity. Fuel expense decreased $4.4 million
in 1993 due to decreased use of the coal-fired plants. Fuel expense
increased $11.9 million in 1992 over the previous year due to increased
usage of the coal-fired and gas turbine plants.
Other operation expenses increased $26.0 million in 1994. Included in the
increase were charges totaling $20.9 million reflecting costs associated
with the Company's two voluntary early retirement and separation programs
and related business office and service facility consolidations. (See Note
11 to the Consolidated Financial Statements.) Also included was an
increase of $4.0 million in amortization expense associated with the
20
Company's energy conservation program and an increase of $1.8 million in
transmission and distribution expenses.
Other operation expenses increased $5.9 million in 1993 due primarily to a
$5.1 million increase in the amortization of energy conservation
expenditures. Also influencing 1993 expenses was an increase of $1.8
million in steam generation expenses and a decrease of $2.3 million in
administration and general expenses.
Other operation expenses increased $9.9 million in 1992. Transmission
expense accounted for $5.3 million of the increase. Also contributing was
a $2.2 million rise in customer service expenses and a $1.5 million
increase in administration and general expenses.
Maintenance expense in 1994 was lower by $2.5 million compared to 1993 due
primarily to a $4.4 million decrease in distribution maintenance expense.
This decrease was partially offset by a $1.3 million increase in
administration and general maintenance expense. Maintenance expense in
1993 declined $1.8 million compared to 1992 due primarily to a $2.2 million
decrease in distribution maintenance expense. Maintenance expense in 1992
was largely unchanged from levels of the previous year.
Depreciation and amortization expense increased $0.1 million in 1994
compared to the prior year. Increased depreciation expense related to
additional plant being placed into service was offset by the completion of
the 10 year amortization period related to two terminated generating
projects. Depreciation and amortization expense declined $7.2 million in
1993. This decrease was due to a change in depreciation rates approved by
the Washington Commission staff in the second quarter of 1993 that was made
retroactive to the beginning of 1993. This adjustment had the effect of
decreasing depreciation expense by $10.5 million during 1993. This
adjustment was partially offset by the effects of additional plant being
placed into service. Depreciation and amortization expense increased $6.6
million in 1992 as a result of additional plant being placed into service.
Taxes other than federal income taxes increased $7.2 million in 1994
compared to the prior year. Municipal and state excise taxes, which are
revenue-based, were higher by $4.5 million. Also contributing to the
increase were higher Washington and Montana state property tax payments of
$1.4 million. Taxes other than federal income taxes increased $6.1 million
in 1993 due primarily to higher excise and municipal tax payments. Taxes
other than federal income taxes increased $4.8 million in 1992. An
increase in Washington state property tax payments of $2.2 million
accounted for much of the increase.
Federal income taxes on operations decreased $3.7 million in 1994 compared
to the prior year due primarily to lower pre-tax operating income during
1994. Federal income taxes on operations increased $11.5 million in 1993.
The increase was due in part to higher pre-tax operating income in 1993 and
an increase in the corporate tax rate from 34 to 35 percent, retroactive to
January 1, 1993. Federal income taxes on operations increased $16.3
million in 1992 due to an increase in pre-tax operating income and a change
in the method in which energy conservation expenditures are deducted for
federal tax purposes. (See Note 13 to the Consolidated Financial
Statements.)
21
AFUDC
(See Note 1 to the Consolidated Financial Statements.)
OTHER INCOME
Total other income increased $1.0 million in 1994 over 1993. Included was
an increase in subsidiary earnings of $2.2 million due primarily to an
after-tax gain of $1.9 million resulting from the sale of a small
hydroelectric generating project by the Company's Hydro Energy Development
Corporation subsidiary. Cash received from the sale, which totaled $30.1
million, has been paid to the Company and is recorded on the Statement of
Cash Flows as "Cash received from subsidiary."
Other income decreased $5.5 million in 1993. The decrease was due in part
to a charge totaling $1.4 million as a result of the Washington
Commission's September 1993 general rate case ruling and a $1.4 million
decrease in excess AFUDC over the Federal Energy Regulatory Commission
("FERC") maximum allowed by the Washington Commission. Also contributing
to the 1993 decrease was a non-recurring $2.3 million decrease in non-
operating federal income taxes in the second quarter of 1992 as a result of
an IRS settlement.
Other income increased $12.3 million in 1992 over 1991 levels. This
increase was due in part to an increase of $4.2 million in Allowance for
Funds Used to Conserve Energy ("AFUCE"). The Washington Commission, in its
April 1, 1991 order authorizing the PRAM, ordered the Company to start
accruing carrying costs on energy conservation expenditures until such
investments are included in ratebase. These accruals commenced in May 1991
but did not become significant until the third quarter of 1991. The AFUDC
allowed by the Washington Commission in excess of the FERC maximum
contributed $2.0 million to the increase over 1991. In addition, other
income increased $3.8 million because of net income from subsidiaries of
$1.0 million in 1992 versus losses of $2.8 million in 1991 and $1.1 million
from lower non-operating federal income taxes.
INTEREST CHARGES
Interest charges, which consist of interest and amortization on long-term
debt and other interest, increased $1.0 million in 1994 compared to 1993.
Interest and amortization on long-term debt alone decreased $1.9 million.
Contributing $8.1 million in reduced interest expense were eight First
Mortgage Bond and Secured Medium-Term Note retirements or redemptions
totaling $191 million over the previous 22 months. Partially offsetting
this was $6.4 million in new interest expense associated with nine issues
of Secured Medium-Term Notes totaling $169 million issued over the previous
23 months.
Other interest expense increased $2.9 million in 1994 compared to the prior
year. The increase was the result of higher average daily short-term
borrowings and higher weighted average interest rates in 1994 as compared
to 1993.
Interest charges decreased $10.3 million in 1993 compared to 1992.
22
Interest and amortization on long-term debt alone decreased $3.5 million.
Contributing $29.1 million in reduced interest expense were 11 issues of
First Mortgage Bonds totaling $510 million redeemed or retired over the
previous 21 months. Partially offsetting this was $23.7 million in new
interest expense associated with 22 issues of Secured Medium-Term Notes
totaling $549 million issued over the previous 23 months. Other interest
expense decreased $6.8 million in 1993 compared to the prior year. Much of
the decrease was the result of a $5.3 million non-recurring interest charge
in 1992 relating to a federal income tax assessment. Also contributing
were lower average daily short-term borrowings and lower weighted average
interest rates in 1993.
Interest charges increased $9.3 million in 1992 compared to the prior year.
Interest and amortization on long-term debt alone increased $4.7 million.
Contributing $24.0 million of new interest expense were 19 issues of
Secured Medium-Term Notes totaling $645 million issued over the previous 19
months. Partially offsetting this were $21.1 million in interest
reductions from First Mortgage Bond retirements or redemptions of $451
million over the same period. Also contributing an increase of $1.5
million were the effects of three issues of fixed rate pollution control
bonds that were used to refund floating rate pollution control bonds of
identical amounts. Other interest expense increased $4.6 million in 1992
compared to 1991. An interest charge of $5.3 million relating to a federal
income tax assessment was partially offset by lower short-term interest
rates in 1992.
CONSTRUCTION AND FINANCING PROGRAM
Current construction expenditures are primarily transmission and
distribution-related, designed to meet continuing customer growth.
Construction expenditures, which include energy conservation expenditures
and exclude AFUDC and AFUCE, were $242.8 million in 1994 and are expected to
be approximately $154.9 million in 1995 and $198.1 million in 1996. The
ratio of cash from operations (net of dividends, AFUDC and AFUCE) to
construction expenditures (excluding AFUDC and AFUCE) was 49.2% in 1994.
The Company expects to fund an average of 72% of its total 1995 and 1996
estimated construction expenditures (excluding AFUDC and AFUCE) from cash
from operations (net of dividends, AFUDC and AFUCE) and the balance through
the sale of securities, the nature, amount and timing of which will be
subject to market and other relevant factors. The Company made a final
payment of $77.6 million in December 1994 for capacity rights to BPA's third
A.C. transmission line to the southwestern United States following an
initial payment of $8.0 million in May 1993. Construction expenditure
estimates are subject to periodic review and adjustment.
In October 1992, the Company filed a shelf registration statement with the
Securities and Exchange Commission for the offering, on a delayed or
continuous basis, of up to an additional $450 million principal amount of
First Mortgage Bonds. The First Mortgage Bonds can be issued as Secured
Medium-Term Notes, through underwritten offerings, pursuant to delayed
delivery contracts or any combination thereof. These Secured Medium-Term
Notes were designated Series B. As of February 10, 1995, the Company has
issued $364 million in Series B Notes having an average coupon rate of
6.90%.
23
On February 1, 1994, the Company issued $55 million principal amount of
Secured Medium-Term Notes, Series B, due February 1, 2024, bearing interest
at 7.35% per annum. Proceeds of this issue were used to extinguish $50
million principal amount of the Company's First Mortgage Bonds, 9.625%
Series due 1997. The Company redeemed $24.5 million through a tender offer
completed February 7, 1994. A portfolio of U.S. Government Treasury
Securities was purchased to defease the remaining $25.5 million of the
bonds.
On February 14, 1994, the Company redeemed $15 million principal amount of
First Mortgage Bonds, 4.75% Series due May 1, 1994.
On May 27, 1994, the Company issued $30 million principal amount of Secured
Medium-Term Notes Series B, due May 27, 2004, bearing interest at 7.80% per
annum. Proceeds of this issue were used to pay down short-term debt.
In February 1992, the Company filed a shelf registration statement with the
Securities and Exchange Commission for the offering, on a delayed or
continuous basis, of up to $200 million of preferred stock. In 1992, the
Company issued an aggregate of $150 million of preferred stock from this
shelf. On February 3, 1994, the Company issued $50 million Adjustable Rate
Cumulative Preferred Stock, Series B ($25 par value). The proceeds were
used to retire the $40 million principal amount of Adjustable Rate
Cumulative Preferred Stock, Series A ($100 par value) and to pay down short-
term debt.
Short-term borrowings from banks and the sale of commercial paper are used
to provide working capital for the construction program. At December 31,
1994, the Company had in place $176.5 million in lines of credit with
several banks, which provided liquidity support for outstanding commercial
paper of $139.6 million, effectively reducing the available borrowing
capacity under these lines of credit to $36.9 million. (See Note 8 to the
Consolidated Financial Statements.)
RATE MATTERS
In the Washington Commission's September 21, 1993 general rate case order,
the Company was allowed a 10.5% return on common equity and 8.94% return on
rate base, based on a capital structure of 47% debt, 8% preferred stock and
45% common equity.
On September 27, 1994 the Washington Commission issued two rate orders, one
regarding the case initiated by the Washington Commission to review the
prudence of nine of the Company's recent purchase power contracts, the other
related to an annual rate adjustment under the Washington Commission's PRAM.
In the order relating to the prudence review case, the Washington Commission
ruled that 1.2% of the contract payments on the Tenaska cogeneration
purchased power contract and 3% of the contract payments on the March Point
Phase II cogeneration purchased power contract should not be recovered in
rates. In light of the Washington Commission order, the Company, in
December 1994, reduced PRAM deferral revenue by $1.5 million, representing
the disallowance for the period from October 1, 1993 through December 31,
1994. On January 12, 1995, the Company filed a petition for review in King
24
County Superior Court appealing the Washington Commission's final order. No
disallowance was ordered in respect to the other seven purchased power
contracts under review.
On September 27, 1994 the Washington Commission also acted on the Company's
pending annual rate increase under the PRAM. The Company had requested a
$55.5 million revenue increase and the Washington Commission allowed $53.7
million. The items of revenue disallowed were the $1.6 million related to
the two purchased power contracts and $208,000 related to a $978,000
reduction that the Washington Commission ordered in the Company's rate base
for its conservation program. Previously deferred conservation program
costs of $690,000 were written off to expense in the third quarter of 1994
to conform deferred conservation program costs to the Washington
Commission's September 27, 1994 order.
The decrease in allowed return on common equity from 12.8% to 10.5% in the
last general rate case has put downward pressure on earnings since the order
became effective on October 1, 1993. In addition, it will be difficult for
the Company to earn its full allowed rate of return because of changes made
by the rate orders in the recovery methods of certain costs.
OTHER
The electric utility industry in general is facing a more competitive
environment, particularly in wholesale generation and industrial customer
markets, with the prospect of changes in utility regulation which could
accelerate competitive pressures. The National Energy Policy Act of 1992
has intensified competition in the wholesale electric generation market by
easing restrictions on producers of wholesale power and by authorizing the
FERC to mandate access by wholesale power producers to electric transmission
systems owned by others. The potential for increased competition at the
retail level through mandated retail wheeling has also been the subject of
legislative and administrative agency interest in a number of states
including the state of Washington. Retail wheeling is the term for
regulatory changes that would allow competing electric suppliers access to
transmission and distribution lines owned by others to distribute power to
any industrial, commercial or residential customer, regardless of service
territory boundaries. In April 1994 utility regulators in California
proposed a plan to open competition in the sale of electricity at the retail
level, suggesting that both industrial and residential customers be allowed
to shop freely for electricity among competing suppliers. Recommendations
by the utility regulators to the California legislature are expected by the
end of 1995. In December 1994 the Washington Commission issued a notice of
inquiry seeking comments from utility companies, ratepayers and other
interested parties on costs and benefits of retail competition and on
creating a new regulatory structure to better accommodate the electric
utility industry as it evolves towards retail competition. Any substantial
changes in utility regulation in Washington state, such as mandating retail
wheeling, would require legislative action. The major credit rating
agencies have expressed the view that competitive developments are likely to
increase business risks in the electric utility industry, with resulting
pressures on utility credit quality and investor returns. The Company and
other electric utilities now face an increasing prospect of competition for
customers and resources from other investor-owned utilities, government
25
agencies, independent power producers, exempt wholesale power producers,
industrial customers developing cogeneration and other power resources, and
suppliers of natural gas and other fuels.
The Company seeks to build on the strengths of its efficient electric
distribution and transmission system to become a leading provider of energy
and related services to homes and businesses in the Pacific Northwest. To
prepare for a more competitive business environment, the Company has
committed itself to being a low cost supplier of electricity. The Company
has taken steps to reduce costs, including work force reductions, facility
consolidations and reductions in capital budgets. The Company has also
conducted joint customer service operations with Washington Natural Gas
Company to lower costs of serving customers of both utilities. The Company
intends to pursue opportunities for improved operating efficiencies and
productivity, including possible restructuring of its power supply resources
and contracts. The Company is also actively pursuing opportunities to
become a provider of new high value services such as wireless automated
meter reading and billing, to utility customers and other utilities.
In the first quarter of 1994, the Company offered to 650 manager-level and
eligible professional staff the opportunity to voluntarily leave or, if
eligible, to retire from the Company. The offer was accepted by 98
employees in March 1994. A charge of $6.9 million ($4.5 million or 7 cents
a share after-tax) was taken in the first quarter to reflect costs
associated with this program and is included in other operation expenses.
During the second quarter, 155 Company employees, including 131 bargaining
unit employees, elected to accept a second voluntary retirement package
offered by the Company. A charge of $9.6 million ($6.2 million or 10 cents
a share after-tax) was taken in the second quarter to reflect costs
associated with this program and is included in other operation expenses.
In the third and fourth quarters of 1994, the Company recorded charges
totaling $4.4 million ($2.9 million or 5 cents a share after-tax) for costs
related to the work force reductions described above and related
consolidation of facilities. These costs are also included in other
operation expenses.
The Company and BPA have entered into a letter of intent, subject to various
conditions, regarding pursuit of construction of a joint transmission
project in Whatcom and Skagit counties in northern Washington state, the
northernmost portion of the Company's service territory. The joint project
is intended to provide the Company and BPA with certain transfer capacity
with Canadian utilities and is intended to relieve certain transmission
constraints on the respective systems of BPA and the Company. The joint
project would involve a combination of existing facility upgrades and new
construction and is currently under environmental review. The Company's
efforts in this project are preliminary in nature and, as such, the Company
cannot give assurance that any construction will result.
The Company is in the process of replacing the High Molecular Weight ("HMW")
underground distribution cable installed during the 1960s and 1970s. The
Company installed about 4,800 miles of industrial standard HMW cable between
1964 and 1979, but the Company and other utilities have experienced
26
increasing cable failures in recent years. The Company is continuing to
analyze cable failure trends to find ways to mitigate the long term effect
of cable failures on customer service, within budgetary constraints. To
minimize the impact of increasing cable failures, the Company replaces a
certain amount of HMW cable each year. The Company estimates that the total
cost of replacing all 4,800 miles of cable will be approximately $550
million. With 458 miles of cable replaced to date, the Company expects to
spend $53 million during the period 1995-1998 for replacement of this cable.
For a discussion of environmental obligations, see Note 16 to the
Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See index on page 32.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE - NONE.
PART III
Part III is incorporated by reference from the Company's definitive
proxy statement issued in connection with the 1995 Annual Meeting of
Shareholders. Certain information regarding executive officers is set forth
in Part I.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report:
1) Financial statement schedule - see index on page 32.
2) Exhibits - see index on page 61.
(b) Reports on Form 8-K:
1) Form 8-K dated December 16, 1994, Item 5 - Other Events,
related to the Company's petition for reconsideration of the
Washington Commission's September 27, 1994 order.
27
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 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.
PUGET SOUND POWER & LIGHT COMPANY
By R. R.Sonstelie
--------------------------------------
R. R. Sonstelie
President and Chief Executive Officer
Date: February 28, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
- --------------------------- ---------------------------- ------------
R. R. Sonstelie President and
- --------------------------- Chief Executive Officer
(R. R. Sonstelie) and Director
William S. Weaver Executive Vice President and
- --------------------------- Chief Financial Officer
(William S. Weaver) and Director
February 28,
1995
James W. Eldredge Corporate Secretary
- --------------------------- and Controller and
(James W. Eldredge) Chief Accounting Officer
Douglas P. Beighle Director
- ---------------------------
(Douglas P. Beighle)
Charles W. Bingham Director
- ---------------------------
(Charles W. Bingham)
28
Signatures, continued
Phyllis J. Campbell Director
- ---------------------------
(Phyllis J. Campbell)
John D. Durbin Director
- ---------------------------
(John D. Durbin)
John W. Ellis Director
- ---------------------------
(John W. Ellis)
Director
- ---------------------------
(Daniel J. Evans)
Nancy L. Jacob Director
- ---------------------------
(Nancy L. Jacob)
R. Kirk Wilson Director
- ---------------------------
(R. Kirk Wilson)
29
<PAGE>
Puget Sound Power & Light Company
Report of Management: February 28, 1995
The accompanying consolidated financial statements of Puget Sound Power &
Light Company have been prepared under the direction of management, which is
responsible for their integrity and objectivity. The statements have been
prepared in accordance with generally accepted accounting principles and
include amounts based on judgments and estimates by management where
necessary. Management also has prepared the other information in the Annual
Report on Form 10-K and is responsible for its accuracy and consistency with
the financial statements.
The Company maintains a system of internal control which, in management's
opinion, provides reasonable assurance that assets are properly safeguarded
and transactions are executed in accordance with management's authorization
and properly recorded to produce reliable financial records and reports. The
system of internal control provides for appropriate division of
responsibility and is documented by written policy and updated as necessary.
The Company's internal audit staff assesses the effectiveness and adequacy of
the internal controls on a regular basis and recommends improvements when
appropriate. Management considers the internal auditor's and independent
auditor's recommendations concerning the Company's internal controls and
takes steps to implement those that they believe are appropriate in the
circumstances.
In addition, Coopers & Lybrand L.L.P., the independent auditors, have
performed audit procedures deemed appropriate to obtain reasonable assurance
about whether the financial statements are free of material misstatement.
The Board of Directors pursues its oversight role for the financial
statements through the audit committee, which is composed solely of outside
Directors. The audit committee meets regularly with management, the internal
auditors and the independent auditors, jointly and separately, to review
management's process of implementation and maintenance of internal accounting
controls and auditing and financial reporting matters. The internal and
independent auditors have unrestricted access to the audit committee.
R. R. Sonstelie William S. Weaver James W. Eldredge
___________________ _______________________ ________________________
R. R. Sonstelie William S. Weaver James W. Eldredge
President and Executive Vice President Corporate Secretary
Chief Executive and Chief Financial Officer and Controller
Officer (Chief Accounting
Officer)
<PAGE>
30
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of
Puget Sound Power & Light Company
We have audited the consolidated financial statements and the financial
statement schedule of Puget Sound Power & Light Company listed on page 32 of
this Annual Report on Form 10-K. These financial statements and financial
statement schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Puget Sound
Power & Light Company as of December 31, 1994 and 1993, and the consolidated
results of its operations and its cash flows for each of the three years in
the period ended December 31, 1994 in conformity with generally accepted
accounting principles. In addition, in our opinion, the financial statement
schedule referred to above, when considered in relation to the basic
financial statements taken as a whole, presents fairly, in all material
respects, the information required to be included therein.
As discussed in Notes 13 and 14, effective January 1, 1993, the Company
changed its method of accounting for income taxes and postretirement benefits
other than pensions.
Coopers & Lybrand L.L.P.
Seattle, Washington
February 10, 1995
31
<PAGE>
PUGET SOUND POWER & LIGHT COMPANY
CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
COVERED BY THE FOREGOING REPORT OF INDEPENDENT ACCOUNTANTS
CONSOLIDATED FINANCIAL STATEMENTS: Page
Consolidated Statements of Income for the years ended
December 31, 1994, 1993 and 1992........................................33
Consolidated Balance Sheets, December 31, 1994 and 1993...................34
Consolidated Statements of Capitalization, December 31, 1994 and 1993.....36
Consolidated Statements of Earnings Reinvested in the Business
for the years ended December 31, 1994, 1993 and 1992....................37
Consolidated Statements of Cash Flows for the years
ended December 31, 1994, 1993 and 1992..................................38
Notes to Consolidated Financial Statements................................39
SCHEDULE:
II. Valuation and Qualifying Accounts and Reserves for the
years ended December 31, 1994, 1993 and 1992........................60
All other schedules have been omitted because of the absence of the
conditions under which they are required, or because the information
required is included in the financial statements or the notes thereto.
Financial statements of the Company's subsidiaries are not filed herewith
inasmuch as the assets, revenues, earnings and earnings reinvested in the
business of the subsidiaries are not material in relation to those of the
Company.
32
<PAGE>
Consolidated Statements of Income
Puget Sound Power & Light Company
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------
Year Ended December 31 1994 1993 1992
- --------------------------------------------------------------------------------------------
(Dollars in Thousands except per share amounts)
<S> <C> <C> <C>
Operating Revenues $1,194,058 $1,112,878 $1,024,970
- --------------------------------------------------------------------------------------------
Operating Expenses:
Operation (Note 16):
Purchased and interchanged power 394,758 317,642 236,179
Fuel 47,166 52,654 57,014
Other (Notes 11 and 12) 203,476 177,444 171,555
Maintenance 51,342 53,900 55,706
Depreciation and amortization 115,738 115,690 122,931
Taxes other than federal income taxes (Note 11) 107,821 100,598 94,466
Federal income taxes (Note 13) 80,259 83,970 72,449
- --------------------------------------------------------------------------------------------
Total operating expenses 1,000,560 901,898 810,300
- --------------------------------------------------------------------------------------------
Operating Income 193,498 210,980 214,670
- --------------------------------------------------------------------------------------------
Other Income:
Allowance for funds used during construction
equity portion 530 2,301 443
Miscellaneous (Notes 10, 11 and 13) 12,290 11,277 16,761
- --------------------------------------------------------------------------------------------
Total other income - net 12,820 13,578 17,204
- --------------------------------------------------------------------------------------------
Income Before Interest Charges 206,318 224,558 231,874
- --------------------------------------------------------------------------------------------
Interest Charges:
Interest on long-term debt 80,213 82,065 86,702
Allowance for funds used during construction
debt portion (3,667) (2,714) (3,046)
Other interest 5,782 2,915 9,691
Amortization of debt expense,
net of premium (Note 7) 3,931 3,965 2,807
- --------------------------------------------------------------------------------------------
Total interest charges 86,259 86,231 96,154
- --------------------------------------------------------------------------------------------
Net Income 120,059 138,327 135,720
- --------------------------------------------------------------------------------------------
Less Preferred Stock Dividend Accruals 15,731 16,442 13,884
- --------------------------------------------------------------------------------------------
Income for Common Stock $104,328 $121,885 $121,836
- --------------------------------------------------------------------------------------------
Common shares outstanding weighted average 63,632,057 60,930,859 56,283,949
Earnings per common share (Note 1) $1.64 $2.00 $2.16
============================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
33
<PAGE>
Consolidated Balance Sheets
Puget Sound Power & Light Company
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------
Assets
December 31 1994 1993
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C>
Utility Plant:
Electric plant, at original cost (Notes 1, 2, 7 and 16) $3,306,854 $3,134,747
Less: Accumulated depreciation 1,039,943 981,535
- --------------------------------------------------------------------------------------------
Net utility plant 2,266,911 2,153,212
- --------------------------------------------------------------------------------------------
Other Property and Investments:
Investment in Bonneville Exchange Power Contract (Note 10) 101,309 108,002
Investment in terminated generating projects -- 12,612
Investment in and advances to subsidiaries 76,517 90,423
Energy conservation loans to customers 1,409 2,284
Other investments, at cost 12,203 15,960
- --------------------------------------------------------------------------------------------
Total other property and investments 191,438 229,281
Current Assets:
Cash (Note 9) 5,284 3,445
- --------------------------------------------------------------------------------------------
Accounts receivable:
Customers 80,503 75,216
Other 27,695 16,170
Less allowance for doubtful accounts 610 523
- --------------------------------------------------------------------------------------------
Total accounts receivable 107,588 90,863
- --------------------------------------------------------------------------------------------
Estimated unbilled revenue 86,745 89,266
PRAM accrued revenues 47,178 37,212
Materials and supplies, at average cost 49,543 52,383
Prepayments and Other 5,260 5,185
- --------------------------------------------------------------------------------------------
Total current assets 301,598 278,354
- --------------------------------------------------------------------------------------------
Long-Term Assets:
Regulatory asset for deferred income taxes (Note 13) 275,296 280,639
PRAM accrued revenues (net of current portion) 63,663 47,795
Unamortized debt expense 8,076 8,550
Unamortized energy conservation charges 239,500 231,331
Other 117,288 111,968
- --------------------------------------------------------------------------------------------
Total long-term assets 703,823 680,283
- --------------------------------------------------------------------------------------------
Total Assets $3,463,770 $3,341,130
============================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
34
<PAGE>
- -------------------------------------------------------------------------------
Capitalization and Liabilities
<TABLE>
<CAPTION>
December 31 1994 1993
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C>
Capitalization (see "Consolidated Statements of Capitalization"):
Common equity $1,172,729 $1,186,475
Preferred stock not subject to mandatory redemption 125,000 115,000
Preferred stock subject to mandatory redemption 91,242 93,176
Long-term debt 963,298 1,036,079
- --------------------------------------------------------------------------------------------
Total capitalization 2,352,269 2,430,730
- --------------------------------------------------------------------------------------------
Current Liabilities:
Accounts payable 58,025 53,449
Short-term debt (Notes 8 and 9) 234,454 149,306
Current maturities of long-term debt (Note 7) 108,000 23,000
Accrued expenses:
Taxes 40,337 39,124
Salaries and wages 20,809 26,289
Interest 26,181 23,832
Other 25,018 22,216
- --------------------------------------------------------------------------------------------
Total current liabilities 512,824 337,216
- --------------------------------------------------------------------------------------------
Deferred Income Taxes:
Deferred Income Taxes (Note 13) 541,501 528,665
Investment tax credits 726 1,142
- --------------------------------------------------------------------------------------------
Total deferred income taxes 542,227 529,807
- --------------------------------------------------------------------------------------------
Other Deferred Credits:
Customer advances for construction 21,939 19,131
Other 34,511 24,246
- --------------------------------------------------------------------------------------------
Total other deferred credits 56,450 43,377
- --------------------------------------------------------------------------------------------
Commitments and Contingencies
(Notes 1, 10, 12, 13, 14, 15 and 16) -- --
Total Capitalization and Liabilities $3,463,770 $3,341,130
============================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
35
<PAGE>
Consolidated Statements of Capitalization
Puget Sound Power & Light Company
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------
December 31 1994 1993
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C>
Common Equity:
Common stock - ($10 stated value) - 80,000,000 shares
authorized, 63,640,861 and 63,629,416 shares
outstanding (Notes 3 and 15) $ 636,409 $ 636,294
Additional paid-in capital (Notes 5 and 15) 328,753 329,922
Earnings reinvested in the business (Note 6) 207,567 220,259
- --------------------------------------------------------------------------------------------
Total common equity 1,172,729 1,186,475
- --------------------------------------------------------------------------------------------
Preferred Stock Not Subject to Mandatory
Redemption - cumulative (Note 3):
$25 par value:*
7.875% series - 3,000,000 shares authorized and outstanding 75,000 75,000
$100 par value:*
Adjustable Rate, Series A - 400,000 shares authorized
and outstanding in 1993 -- 40,000
$25 par value:*
Adjustable Rate, Series B - 2,000,000 shares authorized
and outstanding 50,000 --
- --------------------------------------------------------------------------------------------
Total preferred stock not subject to mandatory redemption 125,000 115,000
- --------------------------------------------------------------------------------------------
Preferred Stock Subject To Mandatory Redemption - cumulative
(Notes 4 and 9):
$100 par value:*
4.84% series - 150,000 shares authorized,
47,956 and 52,061 shares outstanding 4,796 5,206
4.70% series - 150,000 shares authorized,
66,215 and 69,406 shares outstanding 6,621 6,941
8% series - 150,000 shares authorized,
48,253 and 60,296 shares outstanding 4,825 6,029
7.75% series - 750,000 shares authorized and outstanding 75,000 75,000
- --------------------------------------------------------------------------------------------
Total preferred stock subject to mandatory redemption 91,242 93,176
- --------------------------------------------------------------------------------------------
Long-Term Debt (Notes 7 and 9):
First mortgage bonds 894,000 874,000
Guaranteed collateralized bonds 16,000 24,000
Pollution control revenue bonds:
Revenue refunding 1991 series, due 2021 50,900 50,900
Revenue refunding 1992 series, due 2022 87,500 87,500
Revenue refunding 1993 series, due 2020 23,460 23,460
Other notes 24 38
Unamortized discount - net of premium (586) (819)
Long-term debt due within one year (108,000) (23,000)
- --------------------------------------------------------------------------------------------
Total long-term debt excluding current maturities 963,298 1,036,079
- --------------------------------------------------------------------------------------------
Total Capitalization $2,352,269 $2,430,730
============================================================================================
</TABLE>
* 16,000,000 shares authorized for $25 par value preferred stock
and 3,750,000 shares authorized for $100 par value preferred stock.
The accompanying notes are an integral part of the financial statements.
36
<PAGE>
Consolidated Statements of Earnings Reinvested in the Business
Puget Sound Power & Light Company
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------
Year Ended December 31 1994 1993 1992
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C> <C>
Balance at Beginning of Year $220,259 $210,544 $188,084
Net Income 120,059 138,327 135,720
- --------------------------------------------------------------------------------------------
Total 340,318 348,871 323,804
- --------------------------------------------------------------------------------------------
Deductions:
Dividends Declared:
Preferred stock:
$4.84 per share on 4.84% series 242 252 316
$4.70 per share on 4.70% series 319 327 329
$8.00 per share on 8% series 410 495 532
$7.75 per share on 7.75% series 5,813 5,813 3,713
$1.97 per share on 7.875% series 5,906 5,906 1,870
Adjustable Rate, Series A 700 2,800 2,885
Adjustable Rate, Series B 2,277 -- --
Flexible Dutch Auction Rate Transferable
Securities (Note 3):
Series A -- -- 579
Series B -- 912 2,033
Common stock 117,084 111,498 100,692
Loss on reacquisition of preferred stock -- 609 311
- --------------------------------------------------------------------------------------------
Total deductions 132,751 128,612 113,260
- --------------------------------------------------------------------------------------------
Balance at End of Year (Note 6) $207,567 $220,259 $210,544
============================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
37
<PAGE>
Consolidated Statements of Cash Flows
Puget Sound Power & Light Company
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------
Year Ended December 31 1994 1993 1992
- --------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C> <C>
Operating Activities:
Net income $120,059 $138,327 $135,720
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 115,738 115,690 122,931
Deferred income taxes and tax credits - net 17,762 30,149 7,283
Equity portion of AFUDC (530) (2,301) (443)
PRAM accrued revenues (25,835) (42,100) (42,119)
Other 37,813 (15,079) 12,946
Change in certain current assets and
liabilities (Note 18) (5,979) 9,645 (39,307)
- --------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 259,028 234,331 197,011
- --------------------------------------------------------------------------------------------
Investing Activities:
Construction expenditures - excluding equity AFUDC (213,982) (156,123) (185,881)
Additions to energy conservation program (36,648) (64,027) (58,541)
Decrease in energy conservation loans 875 1,688 2,293
Cash received from subsidiary 30,136 -- --
Other (including advances to subsidiaries) (8,116) (438) (21,171)
- --------------------------------------------------------------------------------------------
Net Cash Used by Investing Activities (227,735) (218,900) (263,300)
- --------------------------------------------------------------------------------------------
Financing Activities:
Increase (decrease) in short-term debt 85,148 58,856 (21,340)
Dividends paid (net of newly issued shares
totaling $239,000 in 1994
and $25,658,000 in 1993 (132,513) (102,345) (100,886)
Issuance of common and preferrred stock
(Notes 3, 4 and 5) 50,000 113,377 217,905
Issuance of bonds (Note 7) 85,000 107,460 552,500
Redemption of bonds and notes (73,014) (255,472) (405,912)
Redemption of preferred stock (41,865) (50,643) (51,093)
Issue costs of bonds and stock (2,210) (4,325) (10,382)
- --------------------------------------------------------------------------------------------
Net Cash Provided (Used) by Financing Activities (29,454) (133,092) 180,792
Increase (decrease) in Cash 1,839 (117,661) 114,503
Cash at Beginning of Year 3,445 121,106 6,603
- --------------------------------------------------------------------------------------------
Cash at End of Year $ 5,284 $ 3,445 $121,106
============================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
38
<PAGE>
Puget Sound Power & Light Company
Notes To Consolidated Financial Statements
- -------------------------------------------------------------------------
1) Summary of Significant Accounting Policies
Significant accounting policies are described below.
Utility Plant:
The costs of additions to utility plant, including renewals and betterments,
are capitalized at original cost. Costs include indirect costs such as
engineering, supervision, certain taxes and pension and other benefits, and
an allowance for funds used during construction. Replacements of minor
items of property are included in maintenance expense. The original cost of
operating property together with removal cost, less salvage, is charged to
accumulated depreciation when the property is retired and removed from
service.
Consolidation and Investment in Subsidiaries:
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiary, Puget Energy, Inc. ("Puget Energy").
Guaranteed Collateralized Bonds were issued by Puget Energy and the net
proceeds from the sale of bonds were advanced to the Company (see Note 7).
Puget Energy has no independent operations. Investments in all other
subsidiaries are stated on an equity basis.
Operating Revenues:
Operating revenues are recorded on the basis of service rendered, which
include estimated unbilled revenue and revenue accrued under the Periodic
Rate Adjustment Mechanism ("PRAM").
Energy Conservation:
The Company accumulates energy conservation expenditures which are included
in rate base and amortized to expense over a ten-year period when authorized
by the Washington Utilities and Transportation Commission ("Washington
Commission"). The Washington Commission allows an additional annual overall
rate of return of .90% on the Company's unamortized energy conservation
expenditures and on energy conservation loans to customers made prior to
January 1, 1991.
Self-Insurance:
Prior to October 1, 1993, provision was made for uninsured storm damage,
comprehensive liability, industrial accidents and catastrophic property
losses, with the approval of the Washington Commission, on the basis of the
amount of outside insurance in effect and historical losses. To the extent
actual costs varied from the provision, the difference was deferred for
incorporation into future rates. The amount deferred and included in other
long-term assets at December 31, 1994, was approximately $24.1 million.
In its September 21, 1993 order, the Washington Commission terminated,
39
prospectively, the provision for deferral of uninsured storm damage except
for certain losses associated with major catastrophic events. The
Washington Commission in its order did provide for recovery annually of $2.8
million in deferred storm damage costs in retail rates, beginning October 1,
1993. The order also terminated the provision for deferral of other
uninsured losses retroactively, resulting in an after-tax writeoff in 1993
of $2.0 million. At December 31, 1994, the Company had no insurance
coverage for storm damage.
Depreciation and Amortization:
For financial statement purposes, the Company provides for depreciation on a
straight-line basis. The depreciation of automobiles, trucks, power
operated equipment and tools is allocated to asset and expense accounts
based on usage.
With the Washington Commission's approval, the Company reduced its
depreciation rates in 1993. This adjustment had the effect of reducing
depreciation expense by $10.5 million during 1993. The annual depreciation
provision stated as a percent of average original cost of depreciable
utility plant was 3.0% in 1994, 3.1% in 1993 and 3.4% for 1992.
The Company's investments in terminated generating projects were amortized
on a straight-line basis over ten years for regulatory purposes (included in
operating income as "Depreciation and amortization"). The amortization
period on these investments ended in 1994.
Amounts recoverable through rates related to investments in terminated
generating projects and the Bonneville Exchange Power Contract were adjusted
to their present value in prior years in accordance with Statement of
Financial Accounting Standards No. 90 ("Statement No. 90"). These
adjustments result in reduced net amortization expense over the recovery
periods, the effect of which is included in miscellaneous income in the
amount, net of federal income tax expense, of $1.8 million, $2.7 million and
$3.6 million for 1994, 1993 and 1992, respectively.
Federal Income Taxes:
The Company normalizes, with the approval of the Washington Commission,
certain items. Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards No. 109. (See Note 13.)
Allowance for Funds Used During Construction:
The Allowance for Funds Used During Construction ("AFUDC") represents the
cost of both the debt and equity funds used to finance utility plant
additions during the construction period. The amount of AFUDC recorded in
each accounting period varies depending principally upon the level of
construction work in progress and the AFUDC rate used. AFUDC is capitalized
as a part of the cost of utility plant and is credited as a non-cash item to
other income and interest charges currently. Cash inflow related to AFUDC
does not occur until these charges are reflected in rates.
The AFUDC rate allowed by the Washington Commission is the Company's
authorized rate of return, which was 10.16% effective October 1, 1991 and
40
8.94% effective October 1, 1993. To the extent this rate exceeds the
maximum AFUDC rate calculated using the Federal Energy Regulatory Commission
("FERC") formula, the Company capitalizes the excess as a deferred asset,
crediting miscellaneous income. The amounts included in income were:
$3,016,000 for 1994; $2,309,000 for 1993; and $3,680,000 for 1992.
Allowance For Funds Used to Conserve Energy:
The Washington Commission has authorized the Company to capitalize, as part
of energy conservation costs, related carrying costs calculated at a rate
established by the Washington Commission. This Allowance for Funds Used to
Conserve Energy ("AFUCE") has been credited as a non-cash item to
miscellaneous income in the amount of $3,317,000 in 1994, $4,276,000 in 1993
and $4,454,000 in 1992. Cash inflow related to AFUCE occurs when these
charges are reflected in rates.
Periodic Rate Adjustment Mechanism:
In April 1991, the Washington Commission issued an order establishing a PRAM
designed to operate as an interim rate adjustment mechanism between tri-
annual general rate cases. Under the PRAM, the Company is allowed to
request annual rate adjustments, on a prospective basis, to reflect changes
in certain costs as set forth in the PRAM order. Also, under terms of the
order, recovery of certain costs is decoupled from levels of electricity
sales.
Rates established for the PRAM period are subject to future adjustment based
on actual customer growth and variations in certain costs, principally those
affected by hydro and weather conditions. To the extent revenue billed to
customers varies from amounts allowed under the methodology established in
the PRAM order, the difference is accumulated, without interest, for rate
recovery which will be established in the next PRAM hearing. In its
September 27, 1994 order, the Washington Commission approved the Company's
latest PRAM filing and the recovery of $53.7 million over the period October
1, 1994 through September 30, 1995. A receivable of approximately $110.8
million was recorded at December 31, 1994 under this methodology. Amounts
expected to be collected within one year have been included in current
assets.
Other:
Debt premium, discount and expenses are amortized over the life of the
related debt.
Certain costs have been deferred for amortization in subsequent years, as it
is considered probable that such costs will be recovered through future
rates.
Earnings Per Common Share:
Earnings per common share have been computed based on the weighted average
number of common shares outstanding.
41
<PAGE>
2) Property Plant and Equipment
- ----------------------------------------------------------------------------
December 31 1994 1993
- ----------------------------------------------------------------------------
(Dollars in Thousands)
Electric utility plant classified by prescribed
accounts at original cost:
Intangible plant $ 36,458 $ 33,754
Production plant 897,139 897,218
Transmission plant 499,016 404,173
Distribution plant 1,513,264 1,434,390
General plant 246,351 245,348
Construction work in progress 94,067 97,932
Plant held for future use 19,310 20,683
Acquisition adjustments 1,249 1,249
- ----------------------------------------------------------------------------
Total electric utility plant $3,306,854 $3,134,747
============================================================================
42
<PAGE>
3) Capital Stock
<TABLE>
<CAPTION>
Preferred Stock Preferred Stock
Not Subject to Subject to Common
Mandatory Redemption Mandatory Redemption Stock
- ------------------------------------------------------------------------------------------
Without
Par Value
$25 Par $100 Par $100 Par ($10 Stated
Value Value Value Value)
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Shares outstanding
January 1, 1992 -- 1,400,000 201,887 55,561,647
Sold to Public:
1992 3,000,000 -- 750,000 2,300,000
1993 -- -- -- 3,450,000
1994 2,000,000 -- -- --
Issued to trustee of
employee investment plan:
1992 -- -- -- 63,085
1993 -- -- -- 130,009
Issued to shareholders under
the stock purchase and
dividend reinvestment plan:
1992 -- -- -- 649,901
1993 -- -- -- 1,474,774
1994 -- -- -- 11,445
Acquired for sinking fund:
1992 -- -- (13,665) --
1993 -- -- (6,459) --
1994 -- -- (19,339) --
Called for redemption
and cancelled:
1992 -- (500,000) -- --
1993 -- (500,000) -- --
1994 -- (400,000) -- --
- ------------------------------------------------------------------------------------------
Shares outstanding
December 31, 1994 5,000,000 -- 912,424 63,640,861
==========================================================================================
</TABLE>
See "Consolidated Statements of Capitalization" for details on specific
series.
On January 15, 1991, the Board of Directors declared a dividend of one
preference share purchase right (a "Right") on each outstanding common share
of the Company. The dividend was distributed on January 25, 1991, to
shareholders of record on that date. The Rights will be exercisable only if
a person or group acquires 10 percent or more of the Company's common stock
or announces a tender offer which, if consummated, would result in ownership
by a person or group of 10 percent or more of the common stock. Each Right
entitles the registered holder to purchase from the Company one one-
thousandth of a share of Preference Stock, $50 par value per share, at an
exercise price of $45, subject to adjustments. The description and terms
43
of the Rights are set forth in a Rights Agreement between the Company and
The Chase Manhattan Bank, N.A., as Rights Agent. The Rights expire on
January 25, 2001, unless earlier redeemed by the Company.
In February 1992, the Company filed a shelf registration statement with the
Securities and Exchange Commission for the offering, on a delayed or
continuous basis, of up to $200 million of preferred stock. On March 25,
1992, the Company issued $75 million, 7.75% Series, $100 par value Preferred
Stock. The proceeds were used to retire $50 million principal amount of its
Flexible Dutch Auction Rate Transferable Securities, $100 par value
Preferred Stock ("FLEX DARTS"), Series A and to pay down short-term debt.
On July 21, 1992, the Company issued $75 million, 7.875% Series, $25 par
value Preferred Stock. The proceeds of this issue were used to pay down
short-term debt. The 7.875% Series may be redeemed after July 14, 1997 at
$25 per share plus accrued dividends. On July 1, 1993, the FLEX DARTS
Series B were redeemed with the proceeds from the sale of the Company's
common stock. The weighted average dividend rate for Series B was 3.30% for
1993 and 3.60% for 1992. The weighted average dividend rate for Series A
was 4.18% in the first three months of 1992.
On February 3, 1994, the Company issued $50 million, Adjustable Rate
Cumulative Preferred Stock ("ARPS"), Series B ($25 par value). The proceeds
were used to retire the $40 million principal amount of its ARPS Series A
($100 par value). The weighted average dividend rate for the ARPS Series B
was 5.93% for 1994. The weighted average dividend rate for the ARPS Series
A was 7.00% in the first two months of 1994, 7.00% for 1993 and 7.17% for
1992.
For each quarterly period, dividends on the ARPS Series B, determined in
advance of such period, will be set at 83% of the highest of three interest
rates as defined in the Statement of Relative Rights and Preferences for
ARPS Series B. The dividend rate for any dividend period will in no event
be less than 4% per annum or greater than 10% per annum. The Company may
redeem the ARPS Series B at any time on not less than 30 days notice at
$27.50 per share on or prior to February 1, 1999, and at $25 per share
thereafter, plus in each case accrued dividends to the date of redemption;
provided however, that no shares shall be redeemed prior to February 1,
1999, if such redemption is for the purpose or in anticipation of refunding
such share at an effective interest or dividend cost to the Company of less
than 5.37% per annum.
4) Preferred Stock Subject to Mandatory Redemption
The Company is required to deposit funds annually in a sinking fund
sufficient to redeem the following number of shares of each series of
preferred stock at $100 per share plus accrued dividends: 4.84% Series and
4.70% Series, 3,000 shares each; 8% Series, 6,000 and 1,000 shares through
2003 and 2004, respectively; and 7.75% Series, 37,500 shares on each
February 15, commencing on February 15, 1998. Previous requirements have
been satisfied by delivery of reacquired shares. At December 31, 1994,
there were 15,044 shares of the 4.84% Series, 2,785 shares of the 4.70%
Series and 747 shares of the 8% Series acquired by the Company and available
for future sinking fund requirements. Upon involuntary liquidation, all
preferred shares are entitled to their par value plus accrued dividends.
44
The preferred stock subject to mandatory redemption (see Note 3) may also be
redeemed by the Company at the following redemption prices per share plus
accrued dividends: 4.84% Series, $102; 4.70% Series, $101; and 8% Series,
$101. The 7.75% Series may be redeemed by the Company, subject to certain
restrictions, at $106.20 per share plus accrued dividends through February
15, 1996 and at per share amounts which decline annually to a price of $100
after February 15, 2007.
<PAGE>
5) Additional Paid-in Capital
1994 1993 1992
- ---------------------------------------------------------------------------
(Dollars in Thousands)
Balance at beginning of year $329,922 $243,874 $198,733
Excess of proceeds over stated values of:
Common stock issued to trustee of
employee investment plan -- 2,234 1,046
Common stock issued under the
stock purchase and
dividend reinvestment plan 124 24,584 10,841
Common stock sold to the public -- 61,669 37,950
Par value over cost of reacquired
preferred stock 68 612 579
Issue costs of common stock -- (3,035) (1,950)
Issue costs of preferred stock (1,361) (16) (3,325)
- ---------------------------------------------------------------------------
Balance at end of year $328,753 $329,922 $243,874
===========================================================================
6) Earnings Reinvested in the Business
Earnings reinvested in the business unrestricted as to payment of cash
dividends on common stock approximated $251 million at December 31, 1994,
under the provisions of the most restrictive covenants applicable to
preferred stock and long-term debt contained in the Company's Articles of
Incorporation and indentures. The adjustments made to the carrying value of
costs associated with the terminated generating projects and Bonneville
Exchange Power as a result of Statement No. 90 and the disallowance of
certain terminated generating project costs by the Washington Commission do
not impact the amount of earnings reinvested in the business for purposes of
payment of dividends on common stock under the terms of the aforementioned
Articles and indentures. (See Note 1.)
45
<PAGE>
7) Long-Term Debt
First Mortgage Bonds and Guaranteed Collateralized Bonds
- --------------------------------------------------------
First Mortgage Bonds at December 31:
Series Due 1994 1993 Series Due 1994 1993
- ----------------------------------------------------------------------------
(Dollars in Thousands) (Dollars in Thousands)
4.75% 1994 $ -- $ 15,000 7.07% 2002 $ 27,000 $ 27,000
8.25% 1995 100,000 100,000 7.15% 2002 5,000 5,000
5.25% 1996 20,000 20,000 7.625% 2002 25,000 25,000
4.85% 1996 15,000 15,000 7.02% 2003 30,000 30,000
9.625% 1997 -- 50,000 6.20% 2003 3,000 3,000
7.875% 1997 100,000 100,000 6.40% 2003 11,000 11,000
6.17% 1998 10,000 10,000 7.70% 2004 50,000 50,000
5.70% 1998 5,000 5,000 7.80% 2004 30,000 --
8.83% 1998 25,000 25,000 8.06% 2006 46,000 46,000
6.50% 1999 16,500 16,500 8.14% 2006 25,000 25,000
6.65% 1999 10,000 10,000 7.75% 2007 100,000 100,000
6.41% 1999 20,500 20,500 8.40% 2007 10,000 10,000
7.25% 1999 50,000 50,000 8.59% 2012 5,000 5,000
6.61% 2000 10,000 10,000 8.20% 2012 30,000 30,000
9.14% 2001 30,000 30,000 7.35% 2024 55,000 --
7.85% 2002 30,000 30,000
- ----------------------------------------------------------------------------
Total First Mortgage Bonds $894,000 $874,000
============================================================================
Guaranteed Collateralized Bonds at December 31:
Series Due 1994 1993 Series Due 1994 1993
- ----------------------------------------------------------------------------
(Dollars in Thousands) (Dollars in Thousands)
8.15% 1994 $ -- 8,000 8.45% 1996 $ 8,000 $ 8,000
8.30% 1995 $ 8,000 8,000
- ----------------------------------------------------------------------------
Total Guaranteed Collateralized Bonds $ 16,000 $ 24,000
============================================================================
The Company has unconditionally guaranteed all payments of principal and
premium, if any, and interest on each series of the Guaranteed
Collateralized Bonds of Puget Energy issued in 1986. The guarantee of the
Company with respect to each series of the Guaranteed Collateralized Bonds
is backed by a related series of the Company's First Mortgage Bonds. Each
related series of First Mortgage Bonds has been issued to the trustee for
the Guaranteed Collateralized Bonds and so long as payment is made on the
Guaranteed Collateralized Bonds no payment is due with respect to the
related series of First Mortgage Bonds.
Substantially all properties owned by the Company are subject to the lien of
the First Mortgage Bonds.
46
In February 1994, the Company extinguished $50 million principal amount of
First Mortgage Bonds, 9.625% Series due 1997. The Company redeemed $24.5
million through a tender offer. A portfolio of U.S. Government Treasury
Securities was purchased to defease the remaining $25.5 million of the
bonds. The defeased bonds will be called on October 15, 1995.
Pollution Control Revenue Bonds
- -------------------------------
In June 1986, the Company entered into an agreement with the City of
Forsyth, Montana, (the "City") borrowing $115 million obtained by the City
from the sale of Customized Purchase Pollution Control Revenue Refunding
Bonds due in 2012 (1986 Series) issued to finance the pollution control
facilities of Colstrip Units 3 and 4.
In April 1987, the Company entered into an agreement with the City,
borrowing $23.4 million obtained by the City from the sale of Customized
Purchase Pollution Control Revenue Refunding Bonds due December 1, 2016,
(1987 Series) issued to finance additional pollution control facilities of
Colstrip Unit 4.
On August 7, 1991, the Company refunded $27.5 million of the 1986 Series and
the entire $23.4 million of the 1987 Series with two new series of bonds,
consisting of $27.5 million principal amount of a 7.05% Series due 2021 and
$23.4 million principal amount of a 7.25% Series due 2021. In March 1992,
the Company refunded the remaining $87.5 million of the 1986 Series with a
new series at a rate of 6.80%, maturing in 2022. Each new series of bonds
is collateralized by a pledge of the Company's First Mortgage Bonds, the
terms of which match those of the pollution control bonds. No payment is
due with respect to the related series of First Mortgage Bonds, so long as
payment is made on the pollution control bonds.
On April 29, 1993, the Company issued $23.46 million Pollution Control
Revenue Refunding Bonds, 5.875% 1993 Series due 2020. The proceeds were
used to refund $16.46 million Pollution Control Revenue Bonds, 5.90% 1973
Series and $7 million Pollution Control Revenue Bonds, 6.30% 1977 Series.
Long-Term Debt Maturities and Sinking Fund Requirements
- --------------------------------------------------------
The principal amounts of long-term debt maturities and sinking fund
requirements for the next five years are as follows:
1995 1996 1997 1998 1999
- ----------------------------------------------------------------------------
(Dollars in Thousands)
Maturities of
long-term debt $108,000 $ 43,000 $100,000 $ 40,000 $ 97,000
- ----------------------------------------------------------------------------
Sinking fund requirements $ 200 $ -- $ -- $ -- $ --
- ----------------------------------------------------------------------------
The sinking fund requirement for the First Mortgage Bonds may be met by
substitution of certain credits as provided in the indenture.
47
8) Short-Term Debt
The Company has short-term borrowing arrangements which include a $100
million line of credit with five major banks, a $75 million line of credit
with five banks and a $1.5 million line with another two banks. The
agreements provide the Company with the ability to borrow at different
interest rate options. For the $100 million and $75 million lines of
credit, the options are: (1) the higher of the prime rate or the Federal
Funds rate plus 1/2 of 1 percent or (2) the bank Certificate of Deposit rate
plus 1/2 of 1 percent or (3) the Eurodollar rate plus 3/8 of 1 percent.
These Credit Agreements require an availability fee of 1/5 of 1% per annum
on the unused loan commitment. Borrowings on the $1.5 million credit line
are at the prime rate and compensating balances of 2-1/2% are required.
In addition, the Company has agreements with several banks to borrow on an
uncommitted, as available, basis at money-market rates quoted by the banks.
There are no costs, other than interest, for these arrangements. The
Company also uses commercial paper to fund its short-term borrowing
requirements.
At December 31: 1994 1993 1992
- ---------------------------------------------------------------------
(Dollars in Thousands)
Short-term borrowings outstanding:
Bank notes $ 94,900 $ 79,300 $ 69,800
Commercial paper notes $139,554 $ 70,006 $ 20,650
Weighted average interest rate 6.24% 3.49% 4.37%
Unused lines of credit (a) $176,500 $152,000 $152,000
- ---------------------------------------------------------------------
(a) Provides liquidity support for outstanding commercial paper in the
amount of $139.6 million, $70.0 million and $20.7 million for 1994,
1993 and 1992, respectively, effectively reducing the available
borrowing capacity under these credit lines to $36.9 million, $82.0
million and $131.3 million, respectively.
9) Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at December 31, 1994 and 1993.
1994 1993
------------------ -------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(Dollars in Millions)
Financial Assets:
Cash $ 5.3 $ 5.3 $ 3.4 $ 3.4
Financial Liabilities:
Short-term debt 234.5 234.5 149.3 149.3
Preferred stock subject to
mandatory redemption 91.2 84.4 93.2 93.7
Long-term debt $1,071.9 $1,011.0 $1,059.9 $1,126.0
48
The fair value of outstanding bonds including current maturities is
estimated based on quoted market prices.
The preferred stock subject to mandatory redemption is estimated based on
dealer quotes.
The carrying value of short-term debt is considered to be a reasonable
estimate of fair value. The carrying amount of cash, which includes
temporary investments with maturities of 3 months or less, is also
considered to be a reasonable estimate of fair value.
10) Investment in Bonneville Exchange Power Contract
The Company has a five percent interest, as a tenant in common with three
other investor-owned utilities and Washington Public Power Supply System
("WPPSS"), in the WPPSS Unit 3 project. Unit 3 is a partially constructed
1,240,000 kilowatt nuclear generating plant at Satsop, Washington, which was
in a state of extended construction delay instituted by the Bonneville Power
Administration ("BPA") and WPPSS in 1983. Unit 3 was recently terminated by
WPPSS and the other owners. Under the terms of a settlement agreement (the
"Settlement Agreement"), which includes a Settlement Exchange Agreement
("Bonneville Exchange Power Contract") between the Company and BPA dated
September 17, 1985, the Company is receiving electric power (the "Bonneville
Exchange Power") from the federal power system resources marketed by the BPA
for a period of approximately 30.5 years which commenced January 1, 1987.
The Settlement Agreement settled the claims of the Company against WPPSS and
BPA relating to the construction delay of the WPPSS Unit 3 project.
In its general rate case order issued on January 17, 1990, the Washington
Commission found that all WPPSS Unit 3/Bonneville Exchange Power costs had
been prudently incurred. Under terms of the order, approximately two-thirds
or $97 million of the investment in Bonneville Exchange Power is included in
rate base and amortized on a straight-line basis over the remaining life of
the contract (amortization is included in "Purchased and interchanged
power"). The remainder of the Company's investment is being recovered in
rates over ten years, without a return during the recovery period. The
related amortization is included in "Depreciation and amortization,"
pursuant to a FERC accounting order.
Several issues in the litigation relating to WPPSS Unit 3, including claims
on behalf of WPPSS Unit 5 against the Company and the other Unit 3 owners
seeking recovery of certain common costs, were not settled by the Settlement
Agreement. The claims with respect to WPPSS Unit 3 and Unit 5 common costs,
made in the United States District Court for the Western District of
Washington, arise out of the fact that Unit 3 and Unit 5, which was also
terminated prior to completion, were being constructed adjacent to each
other and were planned to share certain costs. The Company and a number of
the litigants have signed, subject to various conditions, a memorandum of
understanding intended to result in settlement and dismissal of the claims.
Under the memorandum of understanding, the Company's share of the settlement
amount will be $500,000, an expense which was accrued by the Company in
December 1994.
49
<PAGE>
11) Supplementary Income Statement Information
1994 1993 1992
- ---------------------------------------------------------------------------
(Dollars in Thousands)
Taxes:
Real estate and personal property $ 33,050 $ 29,354 $ 30,839
State business 42,241 40,102 35,798
Municipal, occupational and other 25,132 23,064 21,136
Payroll 9,514 9,664 9,517
Other 4,194 3,462 5,300
- ---------------------------------------------------------------------------
Total taxes $114,131 $105,646 $102,590
- ---------------------------------------------------------------------------
Charged to:
Tax expense $107,821 $100,598 $ 94,466
Other accounts, including
construction work in progress 6,310 5,048 8,124
- ---------------------------------------------------------------------------
Total taxes $114,131 $105,646 $102,590
===========================================================================
See "Consolidated Statements of Income" for maintenance and depreciation
expense.
Other operating expenses in 1994 include charges totaling $20.9 million
related to two early separation and retirement programs and associated
facilities consolidations. Severance packages accepted by employees totaled
$18.3 million, including retirement benefits and pension expenses of $6.9
million. Facility consolidation expenses were $2.6 million.
Advertising, research and development expenses and amortization of
intangibles are not significant. The Company pays no royalties.
12) Leases
The Company classifies leases as operating or capital leases. Capitalized
leases are not material. The Company treats all leases as operating leases
for ratemaking purposes as required by the Washington Commission.
Rental and lease payments for the years ended December 31, 1994, 1993 and
1992 were approximately $13,874,000, $14,016,000, and $13,773,000,
respectively. At December 31, 1994, future minimum lease payments for
noncancelable leases are $9,145,000 for 1995, $9,109,000 for 1996,
$9,062,000 for 1997, $9,018,000 for 1998, $9,050,000 for 1999 and in the
aggregate $35,596,000 thereafter.
50
<PAGE>
13) Federal Income Taxes
The details of federal income taxes ("FIT") are as follows:
1994 1993 1992
- ---------------------------------------------------------------------------
Charged to Operating Expense: (Dollars in Thousands)
Current $63,935 $56,908 $67,762
Deferred investment tax credits - net (415) (2,118) (4,018)
Deferred - net 16,739 29,180 8,705
- ---------------------------------------------------------------------------
Total FIT charged to operations $80,259 $83,970 $72,449
===========================================================================
Charged to Miscellaneous Income:
Current $(1,253) $(3,665) $(5,207)
Deferred 1,438 3,087 2,596
- ---------------------------------------------------------------------------
Total FIT charged to miscellaneous income $ 185 $ (578) $(2,611)
===========================================================================
Total FIT $80,444 $83,392 $69,838
===========================================================================
The following is a reconciliation of the difference between the amount of
FIT computed by multiplying pre-tax book income by the statutory tax rate,
and the amount of FIT in the Consolidated Statements of Income:
1994 1993 1992
- ---------------------------------------------------------------------------
(Dollars in Thousands)
- ---------------------------------------------------------------------------
FIT at the statutory rate $70,177 $77,602 $69,890
- ---------------------------------------------------------------------------
Increase (Decrease):
Depreciation expense deducted in the
financial statements in excess of tax
depreciation, net of depreciation
treated as a temporary difference 4,717 4,698 5,295
AFUDC included in income in the financial
statements but excluded from taxable income (2,525) (2,563) (2,438)
Investment tax credit amortization (415) (2,118) (4,018)
Amortization of Pebble Springs and Skagit/
Hanford projects, deducted for financial
statements but not deducted for income tax
purposes, net of amount treated as a
temporary difference 748 1,465 1,748
Energy conservation expenditures - net 5,607 5,608 (1,245)
Other 2,135 (1,300) 606
- ---------------------------------------------------------------------------
Total FIT $80,444 $83,392 $69,838
===========================================================================
Effective tax rate 40.1% 37.6% 34.0%
===========================================================================
51
<PAGE>
The following are the principal components of FIT as reported:
1994 1993 1992
- ---------------------------------------------------------------------------
(Dollars in Thousands)
- ---------------------------------------------------------------------------
Current FIT $62,682 $53,243 $62,555
===========================================================================
Deferred FIT - other:
Conservation tax settlement 341 (257) (22,645)
Periodic rate adjustment mechanism (PRAM) 9,287 14,959 14,321
Deferred taxes related to insurance
reserves (938) 1,409 596
Terminated generating projects (3,345) (5,735) (6,647)
Reversal of Statement No. 90 present
value adjustments 926 1,477 2,374
Residential Purchase and Sale
Agreement - net (624) 4,136 2,491
Normalized tax benefits of the
accelerated cost recovery system 19,042 19,839 21,237
Energy conservation program (2,253) (2,938) (3,360)
Other (4,259) (623) 2,934
- ---------------------------------------------------------------------------
Total deferred FIT - other $18,177 $32,267 $11,301
===========================================================================
Deferred investment tax credits -
net of amortization $ ( 415) $(2,118) $(4,018)
- ----------------------------------------------------------------------------
Total FIT $80,444 $83,392 $69,838
===========================================================================
Deferred tax amounts shown above result from temporary differences for tax
and financial statement purposes. Deferred tax provisions are not recorded
in the income statement on certain temporary differences between tax and
financial statement purposes because they are not allowed for ratemaking
purposes.
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" ("Statement No.
109"). Statement No. 109 requires recording deferred tax balances, at the
currently enacted tax rate, for all temporary differences between the book
and tax bases of assets and liabilities, including temporary differences for
which no deferred taxes had been previously provided because of use of flow-
through tax accounting for rate-making purposes. Under the provision of
Statement No. 109, the Company recorded at the date of adoption an
additional deferred tax liability of approximately $272 million. Because of
prior, and expected future, ratemaking treatment for differences resulting
from flow-through tax accounting, a corresponding $272 million regulatory
asset for income taxes recoverable through future rates was also established
at the date of adoption. At December 31, 1994, the balance of this asset is
$275 million. The effect on net income in 1993 from adoption of Statement
No. 109 was not significant and adoption of Statement No. 109 is not
expected to significantly impact income tax expense in the future.
52
The deferred tax liability at December 31, 1994 and 1993 is comprised of
amounts related to the following types of temporary differences:
1994 1993
------- -------
(Dollars in Thousands)
Utility plant $446,177 $425,210
PRAM 38,795 29,885
Energy conservation charges 35,836 44,548
Contributions in aid of construction (24,075) (21,814)
Bonneville Exchange Power 16,672 18,968
Other 28,096 31,868
------- -------
Total $541,501 $528,665
======= =======
The totals of $542 million and $529 million for 1994 and 1993 consist of
deferred tax liabilities of $576 million and $559 million net of deferred
tax assets of $34 million and $30 million, respectively.
In 1992, the Company reached an agreement with the Internal Revenue Service
settling a number of issues. The net income impact of the settlement was
approximately $1.4 million.
14) Retirement Benefits
The Company has a noncontributory defined benefit pension plan covering
substantially all of its employees. The benefit formula is a function of
both years of service and the average of the five highest consecutive years
of basic earnings within the last ten years of employment. The Company
funds pension cost using the "frozen entry-age" actuarial cost method.
Through September 30, 1993, in accordance with the methodology confirmed in
the January 17, 1990 general rate order from the Washington Commission, the
Company has recognized pension costs for ratemaking and financial statement
purposes using a formula based on a multi-year average of actual
contributions to the plan. Effective October 1, 1993, because of a change
in methodology made by the Washington Commission in its September 21, 1993
rate order, the Company's pension costs for financial statement purposes are
determined in accordance with the provisions of Statement of Financial
Accounting Standards No. 87, "Accounting for Pensions."
53
<PAGE>
Net pension costs for 1994, 1993 and 1992, including $2,752,000 for 1994,
$1,440,000 for 1993 and $811,000 for 1992 which were charged to construction
and other asset accounts, were comprised of the following components:
1994 1993 1992
- ---------------------------------------------------------------------------
(Dollars in Thousands)
Service cost (benefits earned during
the period) $ 7,244 $ 6,952 $ 6,492
Interest cost on projected benefit
obligation 14,895 14,676 13,743
Actual return on plan assets 4,392 (21,786) (9,426)
Net amortization and deferral (21,539) 5,121 (5,470)
- ---------------------------------------------------------------------------
Net pension costs under FASB Statement No. 87 4,992 4,963 5,339
- ---------------------------------------------------------------------------
Regulatory adjustment 1,263 (2,083) (3,575)
- ---------------------------------------------------------------------------
Net pension costs $ 6,255 $ 2,880 $ 1,764
===========================================================================
Funded Status of Plan
At December 31: 1994 1993
- ---------------------------------------------------------------------------
(Dollars in Thousands)
Actuarial present value of benefit obligations:
Vested $(154,950) $(151,399)
Nonvested (1,029) (1,090)
- ---------------------------------------------------------------------------
Accumulated benefit obligation (155,979) (152,489)
Effect of future compensation levels (39,455) (53,998)
- ---------------------------------------------------------------------------
Total projected benefit obligation (195,434) (206,487)
Plan assets at market value 205,655 214,580
- ---------------------------------------------------------------------------
Plan assets in excess of projected benefit
obligation 10,221 8,093
Unrecognized net gain due to variance
between assumptions and experience (19,453) (14,344)
Prior service cost 10,295 11,232
Transition asset as of January 1, 1986,
being amortized on a straight-line
basis over 18 years (3,774) (4,194)
Regulatory adjustment, cumulative 6,190 7,453
- ---------------------------------------------------------------------------
Prepaid pension cost recognized
in long-term assets on balance sheet $ 3,479 $ 8,240
===========================================================================
Assumptions used for the above calculations are as follows: settlement
(discount) rate for 1994 - 8.25%, for 1993 - 7.5% and for 1992 - 8.5%; rate
of annual compensation increase for 1994 - 5.5%, for 1993 - 5.5%, and for
1992 - 6%; and long-term rate of return on assets for 1994 - 8.5%, for 1993
- - 8.5%, and for 1992 - 9%.
54
Plan assets consist primarily of U.S. Government securities, corporate debt
and equity securities.
Effective October 1, 1991, the Company's Board of Directors approved
supplemental retirement plans for officer and director level employees.
Expenses for this plan for 1994, 1993 and 1992 were $1,043,000, $651,000,
and $606,000, respectively.
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees.
Substantially all of the Company's employees may become eligible for health
care benefits and salaried employees become eligible for life insurance
benefits if they reach normal retirement age while working for the Company.
These benefits are provided principally through an insurance company whose
premiums are based on the benefits paid during the year. The expense in
1992 related to those benefits was $2,025,000.
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions" ("Statement No. 106") which requires the costs
associated with postretirement benefits to be accrued during the working
careers of active employees. The Company is recognizing the impact of
Statement No. 106 by amortizing its transition obligation of $24.9 million
to expense over 20 years. The resulting 1994 and 1993 annual costs under
Statement No. 106 is approximately $3.6 million and $3.8 million,
respectively.
In the rate order issued by the Washington Commission on September 21, 1993,
the Washington Commission approved adoption of accrual accounting for
postretirement benefits. For rate purposes, the difference between accrual
and pay-as-you-go accounting will be phased in over five years. The
Washington Commission's calculation of Statement No. 106 costs for rate
purposes is lower than the Company's cost. In 1994 and 1993, the expenses
recognized for postretirement benefits were $2.4 million and $2.8 million,
respectively, including $.1 million and $.5 million which were disallowed by
the Washington Commission.
15) Employee Investment Plan
The Company has a qualified employee Investment Plan under which employee
salary deferrals and after-tax contributions are used to purchase several
different investment fund options. The Company makes a monthly contribution
equal to 55% of the basic contribution of each participating employee. The
basic contribution is limited to 6% of the employee's eligible earnings.
All Company contributions are used to purchase Company common stock on the
open market or directly from the Company.
The Company contributions to the plan were $3,321,000, $3,520,000, and
$3,317,000 for the years 1994, 1993 and 1992, respectively. The
shareholders have authorized the issuance of up to 2,000,000 shares of
common stock under the plan, of which 959,142 were issued through December
31, 1994. The employee Investment Plan eligibility requirements are set
forth in the plan documents.
55
16) Commitments and Contingencies
Commitments
For the twelve months ended December 31, 1994, approximately 25% of the
Company's energy output was obtained at an average cost of approximately
12.1 mills per KWH through long-term contracts with several of the
Washington public utility districts ("PUDs") owning hydroelectric projects
on the Columbia River.
The purchase of power from the Columbia River projects is generally on a
"cost-of-service" basis under which the Company pays a proportionate share
of the annual cost of each project in direct ratio to the amount of power
allocated to it. Such payments are not contingent upon the projects being
operable. These projects are financed through substantially level debt
service payments, and their annual costs should not vary significantly over
the term of the contracts unless additional financing is required to meet
the costs of major maintenance, repairs or replacements or license
requirements. The Company's share of the costs and the output of the
projects is subject to reduction due to various withdrawal rights of the
PUDs and others over the lives of the contracts.
<PAGE>
As of December 31, 1994, the Company was entitled to purchase portions of
the power output of the PUDs' projects as set forth in the following
tabulation:
Company's Annual Amount
Bonds Purchasable (Approximate)
Outstanding --------------------------
Contract License 12/31/94(a) % of Kilowatt Costs(b)
Project Exp.Date Exp.Date (Millions) Output Capacity
(Millions)
- ----------------------------------------------------------------------------
Rock Island
Original units 2012 2029 $ 90.0 60.3 )
) 502,000 $ 43.2
Additional units 2012 2029 325.3 100.0 )
Rocky Reach 2011 2006(c) 218.0 38.9 505,311 14.8
Wells 2018 2012(c) 195.3 34.8 292,320 10.3
Priest Rapids 2005 2005(c) 131.2 8.0 71,680 2.3
Wanapum 2009 2005(c) 186.4 10.8 98,280 2.7
- --------------------------------------------------------------------------
Total 1,469,591 $ 73.3
==========================================================================
(a) The contracts for purchases are generally coextensive with the term
of the PUD bonds associated with the project. Under the terms of some
financings, however, long-term bonds were sold to finance certain assets
whose estimated useful lives extend beyond the expiration date of the power
sales contracts. Of the total outstanding bonds sold for each project, the
percentage of principal amount of bonds which mature beyond the contract
expiration dates are: 69.2% at Rock Island; 30.7% at Rocky Reach; 64.3% at
Priest Rapids; and 40.1% at Wanapum.
56
(b) The components of 1995 costs associated with the interest portion
of debt service are: Rock Island, $26.0 million for all units; Rocky Reach,
$5.2 million; Wells, $3.4 million; Priest Rapids, $.7 million; and Wanapum,
$1.1 million.
(c) The Company is unable to predict whether the licenses under the
Federal Power Act will be renewed to the current licensees or what effect
the term of the licenses may have on the Company's contracts.
- -----------------------------
The Company's estimated payments for power purchases from the Columbia River
projects are $73.4 million for 1995, $73.1 million for 1996, $75.7 million
for 1997, $80.7 million for 1998, $82.3 million for 1999, and in the
aggregate $999 million thereafter through 2018.
The Company also has numerous long-term firm purchased power contracts with
other utilities and non-utility generators in the region. The Company is
not obligated to make payments under these contracts unless power is
delivered. The Company's estimated payments for firm power purchases from
other utilities and non-utility generators are $468.7 million for 1995,
$484.8 million for 1996, $494.5 million for 1997, $528.0 million for 1998,
$555.2 million for 1999 and in the aggregate $6.062 billion thereafter
through 2024. These contracts have varying terms and may include escalation
and termination provisions.
Total purchased power contracts provided the Company with approximately 16.0
million, 13.5 million and 12.7 million MWH of firm energy at a cost of
approximately $450.7 million, $353.5 million and $274.6 million for the
years 1994, 1993 and 1992, respectively.
The following table indicates the Company's percentage ownership and the
extent of the Company's investment in jointly-owned generating plants in
service at December 31, 1994:
Energy Company's Plant in Accumulated
Source Ownership Service Depreciation
Project (Fuel) Share (%) (Millions) (Millions)
Centralia Coal 7 $ 26.5 $ 15.9
Colstrip 1 & 2 Coal 50 181.4 86.1
Colstrip 3 & 4 Coal 25 443.2 130.8
Financing for a participant's ownership share in the projects is provided
for by such participant. The Company's share of related operating and
maintenance expenses is included in corresponding accounts in the
Consolidated Statements of Income.
Certain purchase commitments have been made in connection with the Company's
construction program.
Contingencies
The Company is subject to environmental regulation by federal, state and
local authorities. The Company has been named a Potentially Responsible
Party by the Environmental Protection Agency ("EPA") at four sites. The
57
Company has reached settlements with the EPA on all four sites under which
the Company has paid approximately $7.6 million. To date the Company has
recovered $3.6 million from its insurance companies in connection with
remediation and legal costs and expects to recover an additional $3.1
million in the next twelve months. Based on the best estimates available at
this time, the Company anticipates future costs for environmental
remediation at all sites, including those owned by the Company, will
approximate $3.5 million, which was recorded as an accrued liability at
December 31, 1994.
On April 1, 1992, the Washington Commission issued an order regarding the
treatment of costs incurred by the Company for certain sites under its
environmental remediation program. The order authorizes the Company to
accumulate and defer prudently incurred cleanup costs paid to third parties
for recovery in rates established in future rate proceedings.
The Company believes a significant portion of its past and future
environmental remediation costs are recoverable from either insurance
companies, third parties, or under the Washington Commission's order. At
December 31, 1994, the estimated recoverable amount for these costs is
approximately $11.9 million.
Other contingencies, arising out of the normal course of the Company's
business, exist at December 31, 1994. The ultimate resolution of these
issues is not expected to have a material adverse impact on the financial
condition, results of operations or liquidity of the Company.
<PAGE>
17) Supplemental Quarterly Financial Data (Unaudited)
The following unaudited amounts, in the opinion of the Company, include all
adjustments (consisting of normal recurring adjustments) necessary for a
fair presentation of the results of operations for the interim periods.
Annual amounts are not generated evenly by quarter during the year due to
the seasonal nature of the utility business.
1994 Quarter Ended March 31 June 30 Sept. 30 Dec. 31
- --------------------------------------------------------------------------
(Dollars in Thousands except per share amounts)
Operating revenues $329,222 $263,612 $264,289 $336,935
Operating income $ 63,892 $ 35,579 $ 33,104 $ 60,924
Other income $ 3,881 $ 3,341 $ 3,279 $ 2,318
Net income $ 46,527 $ 17,772 $ 14,927 $ 40,833
Earnings per common share $ 0.67 $ 0.22 $ 0.17 $ 0.58
- --------------------------------------------------------------------------
1993 Quarter Ended March 31 June 30 Sept. 30 Dec. 31
- --------------------------------------------------------------------------
(Dollars in Thousands except per share amounts)
Operating revenues $323,974 $237,617 $230,178 $321,109
Operating income $ 72,922 $ 43,039 $ 35,505 $ 59,514
Other income $ 3,718 $ 4,614 $ 3,536 $ 1,712
Net income $ 54,682 $ 26,213 $ 18,071 $ 39,361
Earnings per common share $ 0.86 $ 0.37 $ 0.23 $ 0.56
- --------------------------------------------------------------------------
58
<PAGE>
18) Consolidated Statement of Cash Flows
For purposes of the Statement of Cash Flows, the Company considers all
temporary investments to be cash equivalents. These temporary cash
investments are securities held for cash management purposes, having
maturities of three months or less. The net change in current assets and
current liabilities for purposes of the Statement of Cash Flows excludes
short-term debt, current maturities of long-term debt and the current
portion of PRAM accrued revenues.
The following provides additional information concerning cash flow
activities:
Year Ended December 31: 1994 1993 1992
- --------------------------------------------------------------------------
(Dollars in Thousands)
Changes in certain current
assets and current liabilities:
Accounts receivable $(16,725) $ (5,050) $(13,848)
Deferred energy costs -- -- (20)
Unbilled revenues 2,521 (14,410) (15,081)
Materials and supplies 2,840 1,054 (1,338)
Prepayments and Other (75) 5,809 (6,346)
Accounts payable 4,576 10,731 (5,948)
Accrued expenses and Other 884 11,511 3,274
- --------------------------------------------------------------------------
Net change in certain current assets
and current liabilities $(5,979) $ 9,645 $(39,307)
==========================================================================
Cash payments:
Interest (net of capitalized interest) $83,959 $80,646 $97,242
Income taxes $63,477 $32,585 $76,050
- --------------------------------------------------------------------------
59
<PAGE>
Puget Sound Power & Light Company
Schedule II. Valuation and Qualifying Accounts and Reserves
- -----------------------------------------------------------------------------
(Dollars in Thousands)
- -----------------------------------------------------------------------------
Column A Column B Column C Column D Column E
- -----------------------------------------------------------------------------
Additions
Balance at Charged to Balance
Beginning Costs and at End
of Period Expenses Deductions of Period
Year Ended December 31, 1994
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 523 $ 3,537 $ 3,450 $ 610
=============================================================================
Year Ended December 31, 1993
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 488 $ 2,799 $ 2,764 $ 523
- -----------------------------------------------------------------------------
Reserves:
Accumulated provision
for self-insurance $ 87 $13,634(A) $13,721(A) $ --
=============================================================================
Year Ended December 31, 1992
- ----------------------------
Accounts deducted from assets
on balance sheet:
Allowance for doubtful
accounts receivable $ 531 $ 1,981 $ 2,024 $ 488
- -----------------------------------------------------------------------------
Reserves:
Accumulated provision
for self-insurance $ 792 $ 4,610(A) $ 5,315(A) $ 87
=============================================================================
Note (A): Includes charges of $10.3 million in 1993 and $1.8 million in 1992
which were transferred to a deferred asset account.
60
<PAGE>
EXHIBIT INDEX
Certain of the following exhibits are filed herewith. Certain other of the
following exhibits have heretofore been filed with the Commission and are
incorporated herein by reference.
3-a Restated Articles of Incorporation of the Company. (Exhibit 1.2
to Registration Statement on Form 8-A filed February 14, 1994, Commission
File No. 1-4393)
3-b Restated Bylaws of the Company. (Exhibit 4-b to Registration
No. 33-18506)
4.1 Fortieth through Seventy-fifth Supplemental Indentures defining
the rights of the holders of the Company's First Mortgage Bonds. (Exhibit 2-
d to Registration No. 2-60200; Exhibit 4-c to Registration No. 2-13347;
Exhibits 2-e through and including 2-k to Registration No. 2-60200; Exhibit 4-
h to Registration No. 2-17465; Exhibits 2-l, 2-m and 2-n to Registration No.
2-60200; Exhibits 2-m to Registration No. 2-37645; Exhibit 2-o through and
including 2-s to Registration No. 2-60200; Exhibit 5-b to Registration No. 2-
62883; Exhibit 2-h to Registration No. 2-65831; Exhibit (4)-j-1 to
Registration No. 2-72061; Exhibit (4)-a to Registration No. 2-91516; Exhibit
(4)-b to Annual Report on Form 10-K for the fiscal year ended December 31,
1985, Commission File No. 1-4393; Exhibits (4)(a) and (4)(b) to Company's
Current Report on Form 8-K, dated April 22, 1986; Exhibit (4)a to Company's
Current Report on Form 8-K, dated September 5, 1986; Exhibit (4)-b to
Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
1986, Commission File No. 1-4393; Exhibit (4)-c to Registration No. 33-18506;
Exhibit (4)-b to Annual Report on Form 10-K for the fiscal year ended
December 31, 1989, Commission File No. 1-4393; Exhibit (4)-b to Annual Report
on Form 10-K for the fiscal year ended December 31, 1990, Commission File No.
1-4393; Exhibits (4)-b and (4)-c to Registration No. 33-45916; Exhibit (4)-c
to Registration No. 33-50788; Exhibit (4)-a to Registration No. 33-53056; and
Exhibit 4.3 to Registration No. 33-63278.)
4.2 Credit Agreement dated as of December 1, 1991, among the Company
and various banks named therein, Seattle-First National Bank as Agent.
(Exhibit (4)-d to Registration No. 33-45916)
4.3 Credit Agreement dated as of December 1, 1991, among the Company
and various banks named therein, Bank of New York as Agent. (Exhibit (4)-e
to Registration No. 33-45916)
4.4 Final form of Indenture dated as of November 1, 1986, among
Puget Energy, the Company, and The First National Bank of Boston, as Trustee.
(Exhibit 4-a to Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1986, Commission File No. 1-4393)
4.5 Final form of Pledge Agreement dated November 1, 1986, between
the Company and The First National Bank of Boston, as Trustee. (Exhibit 4-c
to Company's Quarterly Report on Form 10-Q for the quarter ended September
30, 1986, Commission File No. 1-4393)
61
4.6 Rights Agreement, dated as of January 15, 1991, between the
Company and The Chase Manhattan Bank, N.A., as Rights Agent. (Exhibit 2.1 to
Registration Statement on Form 8-A filed on January 17, 1991, Commission File
No. 1-4393)
4.7 Pledge Agreement dated August 1, 1991, between the Company and
The First National Bank of Chicago, as Trustee. (Exhibit (4)-j to
Registration No. 33-45916)
4.8 Loan Agreement dated August 1, 1991, between the City of
Forsyth, Rosebud County, Montana and the Company. (Exhibit (4)-k to
Registration No. 33-45916)
4.9 Statement of Relative Rights and Preferences for the Adjustable
Rate Cumulative Preferred Stock, Series B ($25 Par Value). (Exhibit 1.1 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File
No. 1-4393)
4.10 Statement of Relative Rights and Preferences for the Series A
Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred
Stock. (Exhibit 1.3 to Registration Statement on Form 8-A filed February 14,
1994, Commission File No. 1-4393)
4.11 Statement of Relative Rights and Preferences for the Series B
Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred
Stock. (Exhibit 1.4 to Registration Statement on Form 8-A filed February 14,
1994, Commission File No. 1-4393)
4.12 Statement of Relative rights and Preferences for the Preference
Stock, Series R, $50 Par Value. (Exhibit 1.5 to Registration Statement on
Form 8-A filed February 14, 1994, Commission File No. 1-4393)
4.13 Statement of Relative Rights and Preferences for the 7 3/4%
Series Preferred Stock Cumulative, $100 Par Value. (Exhibit 1.6 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File
No. 1-4393)
4.14 Statement of Relative Rights and Preferences for the 7 7/8%
Series Preferred Stock Cumulative, $25 Par Value. (Exhibit 1.7 to
Registration Statement on Form 8-A filed February 14, 1994, Commission File
No. 1-4393)
4.15 Pledge Agreement, dated as of March 1, 1992, by and between the
Company and and Chemical Bank relating to a series of first mortgage bonds.
(Exhibit 4.15 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1993, Commission File No. 1-4393)
4.16 Pledge Agreement, dated as of April 1, 1993, by and between the
Company and The First National Bank of Chicago, relating to a series of first
mortgage bonds. (Exhibit 4.16 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1993, Commission File No. 1-4393)
62
10.1 Assignment and Agreement, dated as of August 13, 1964,
between Public Utility District No. 1 of Chelan County, Washington and
the Company, relating to the Rock Island Project. (Exhibit 13-b to
Registration No. 2-24262)
10.2 First Amendment, dated as of October 4, 1961, to Power Sales
Contract between Public Utility District No. 1 of Chelan County,
Washington and the Company, relating to the Rocky Reach Project.
(Exhibit 13-d to Registration No. 2-24252)
10.3 Assignment and Agreement, dated as of August 13, 1964,
between Public Utility District No. 1 of Chelan County, Washington and
the Company, relating to the Rocky Reach Project. (Exhibit 13-e to
Registration No. 2-24252)
10.4 Assignment and Agreement, dated as of August 13, 1964,
between Public Utility District No. 2 of Grant County, Washington and the
Company, relating to the Priest Rapids Development. (Exhibit 13-j to
Registration No. 2-24252)
10.5 Assignment and Agreement, dated as of August 13, 1964,
between Public Utility District No. 2 of Grant County, Washington and the
Company, relating to the Wanapum Development. (Exhibit 13-n to
Registration No. 2-24252)
10.6 First Amendment, dated February 9, 1965, to Power Sales
Contract between Public Utility District No. 1 of Douglas County,
Washington and the Company, relating to the Wells Development. (Exhibit
13-p to Registration No. 2-24252)
10.7 First Amendment, executed as of February 9, 1965, to
Reserved Share Power Sales Contract between Public Utility District No. 1
of Douglas County, Washington and the Company, relating to the Wells
Development. (Exhibit 13-r to Registration No. 2-24252)
10.8 Assignment and Agreement, dated as of August 13, 1964,
between Public Utility District No. 1 of Douglas County, Washington and
the Company, relating to the Wells Development. (Exhibit 13-u to
Registration No. 2-24252)
10.9 Pacific Northwest Coordination Agreement, executed as of
September 15, 1964, among the United States of America, the Company and
most of the other major electrical utilities in the Pacific Northwest.
(Exhibit 13-gg to Registration No. 2-24252)
10.10 Contract dated November 14, 1957, between Public Utility
District No. 1 of Chelan County, Washington and the Company, relating to
the Rocky Reach Project. (Exhibit 4-1-a to Registration No. 2-13979)
10.11 Power Sales Contract, dated as of November 14, 1957, between
Public Utility District No. 1 of Chelan County, Washington and the
Company, relating to the Rocky Reach Project. (Exhibit 4-c-1 to
Registration No. 2-13979)
63
10.12 Power Sales Contract, dated May 21, 1956, between Public
Utility District No. 2 of Grant County, Washington and the Company,
relating to the Priest Rapids Project. (Exhibit 4-d to Registration No.
2-13347)
10.13 First Amendment to Power Sales Contract dated as of August
5, 1958, between the Company and Public Utility District No. 2 of Grant
County, Washington, relating to the Priest Rapids Development. (Exhibit
13-h to Registration No. 2-15618)
10.14 Power Sales Contract dated June 22, 1959, between Public
Utility District No. 2 of Grant County, Washington and the Company,
relating to the Wanapum Development. (Exhibit 13-j to Registration No. 2-
15618)
10.15 Reserve Share Power Sales Contract dated June 22, 1959, between
Public Utility District No. 2 of Grant County, Washington and the Company,
relating to the Priest Rapids Project. (Exhibit 13-k to Registration No. 2-
15618)
10.16 Agreement to Amend Power Sales Contracts dated July 30, 1963,
between Public Utility District No. 2 of Grant County, Washington and the
Company, relating to the Wanapum Development. (Exhibit 13-1 to Registration
No. 2-21824)
10.17 Power Sales Contract executed as of September 18, 1963, between
Public Utility District No. 1 of Douglas County, Washington and the Company,
relating to the Wells Development. (Exhibit 13-r to Registration No. 2-
21824)
10.18 Reserved Share Power Sales Contract executed as of September
18, 1963, between Public Utility District No. 1 of Douglas County,
Washington and the Company, relating to the Wells Development. (Exhibit 13-
s to Registration No. 2-21824)
10.19 Exchange Agreement dated April 12, 1963, between the United
States of America, Department of the Interior, acting through the Bonneville
Power Administrator and Washington Public Power Supply System and the
Company, relating to the Hanford Project. (Exhibit 13-u to Registration 2-
21824)
10.20 Replacement Power Sales Contract dated April 12, 1963, between
the United States of America, Department of the Interior, acting through the
Bonneville Power Administrator and the Company, relating to the Hanford
Project. (Exhibit 13-v to Registration No. 2-21824)
10.21 Contract covering undivided interest in ownership and operation
of Centralia Thermal Plant, dated May 15, 1969. (Exhibit 5-b to
Registration No. 2-3765)
10.22 Construction and Ownership Agreement dated as of July 30, 1971,
between The Montana Power Company and the Company. (Exhibit 5-b to
Registration No. 2-45702)
64
10.23 Operation and Maintenance Agreement dated as of July 30, 1971,
between The Montana Power Company and the Company. (Exhibit 5-c to
Registration No. 2-45702)
10.24 Coal Supply Agreement, dated as of July 30, 1971, among The
Montana Power Company, the Company and Western Energy Company. (Exhibit 5-d
to Registration No. 2-45702)
10.25 Power Purchase Agreement with Washington Public Power Supply
System and the Bonneville Power Administration dated February 6, 1973.
(Exhibit 5-e to Registration No. 2-49029)
10.26 Ownership Agreement among the Company, Washington Public Power
Supply System and others dated September 17, 1973. (Exhibit 5-a-29 to
Registration No. 2-60200)
10.27 Contract dated June 19, 1974, between the Company and P.U.D.
No. 1 of Chelan County. (Exhibit D to Form 8-K dated July 5, 1974
10.28 Restated Financing Agreement among the Company, lessee,
Chrysler Financial Corporation, owner, Nevada National Bank and Bank of
Montreal (California), trustee, dated December 12, 1974 pertaining to a
combustion turbine generating unit trust. (Exhibit 5-a-35 to Registration
No. 2-60200)
10.29 Restated Lease Agreement between the Company, lessee, and the
Bank of California, and National Association, lessor, dated December 12,
1974 for one combustion generating unit. (Exhibit 5-a-36 to Registration
No. 2-60200)
10.30 Financing Agreement Supplement and Amendment among the Company,
lessee, Chrysler Financial Corporation, owner, The Bank of California,
National Association, trustee, Pacific Mutual Life Insurance Company,
Bankers Life Company, and The Franklin Life Insurance Company, lenders,
dated as of March 26, 1975, pertaining to a combustion turbine generating
unit trust. (Exhibit 5-a-37 to Registration No. 2-60200)
10.31 Lease Agreement Supplement and Amendment between the Company,
lessee, and The Bank of California, National Association, lessor, dated as
of March 26, 1975 for one combustion turbine generating unit. (Exhibit 5-a-
38 to Registration No. 2-60200)
10.32 Exchange Agreement executed August 13, 1964, between the United
States of America, Columbia Storage Power Exchange and the Company, relating
to Canadian Entitlement. (Exhibit 13-ff to Registration No. 2-24252)
10.33 Loan Agreement dated as of December 1, 1980 and related
documents pertaining to Whitehorn turbine construction trust financing.
(Exhibit 10.52 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1980, Commission File No. 1-4393)
10.34 Letter Agreement dated March 31, 1980, between the Company and
Manufacturers Hanover Leasing Corporation. (Exhibit b-8 to Registration No.
2-68498)
65
10.35 Coal Supply Agreement for Colstrip 3 and 4, dated as of July 2,
1980; Amendment No. 1 to Coal Supply Agreement, dated as of July 10, 1981;
and Coal Transportation Agreement dated as of July 10, 1981. (Exhibit 20-a
to Quarterly Report on Form 10-Q for the quarter ended September 30, 1981,
Commission File No. 1-4393)
10.36 Residential Purchase and Sale Agreement between the Company and
the Bonneville Power Administration, effective as of October 1, 1981.
(Exhibit 20-b to Quarterly Report on Form 10-Q for the quarter ended
September 30, 1981, Commission File No. 1-4393)
10.37 Letter of Agreement to Participate in Licensing of Creston
Generating Station, dated September 30, 1981. (Exhibit 20-c to Quarterly
Report on Form 10-Q for the quarter ended September 30, 1981, Commission
File No. 1-4393)
10.38 Power sales contract dated August 27, 1982 between the Company
and Bonneville Power Administration. (Exhibit 10-a to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1982, Commission File No. 1-
4393)
10.39 Agreement executed as of April 17, 1984, between the United
States of America, Department of the Interior, acting through the Bonneville
Power Administration, and other utilities relating to extension energy from
the Hanford Atomic Power Plant No. 1. (Exhibit (10)-47 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1984, Commission File No. 1-
4393)
10.40 Agreement for the Assignment of Output from the Centralia
Thermal Project, dated as of April 14, 1983, between the Company and Public
Utility District No. 1 of Grays Harbor. (Exhibit (10)-48 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1984, Commission File
No. 1-4393)
10.41 Settlement Agreement and Covenant Not to Sue executed by the
United States Department of Energy acting by and through the Bonneville
Power Administration and the Company dated September 17, 1985. (Exhibit
(10)-49 to Annual Report on Form 10-K for the fiscal year ended December 31,
1985, Commission File No. 1-4393)
10.42 Agreement to Dismiss Claims and Covenant Not to Sue dated
September 17, 1985 between Washington Public Power Supply System and the
Company. (Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1985, Commission File No. 1-4393)
10.43 Irrevocable Offer of Washington Public Power Supply System
Nuclear Project No. 3 Capability for Acquisition executed by the Company,
dated September 17, 1985. (Exhibit A of Exhibit (10)-50 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-
4393)
10.44 Settlement Exchange Agreement ("Bonneville Exchange Power
Contract") executed by the United States of America Department of Energy
acting by and through the Bonneville Power Administration and the Company,
66
dated September 17, 1985. (Exhibit B of Exhibit (10)-50 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-
4393)
10.45 Settlement Agreement and Covenant Not to Sue between the
Company and Northern Wasco County People's Utility District, dated
October 16, 1985. (Exhibit (10)-53 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.46 Settlement Agreement and Covenant Not to Sue between the
Company and Tillamook People's Utility District, dated October 16, 1985.
(Exhibit (10)-54 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1985, Commission File No. 1-4393)
10.47 Settlement Agreement and Covenent Not to Sue between the
Company and Clatskanie People's Utility District, dated September 30,
1985. (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1985, Commission File No. 1-4393)
10.48 Stipulation and Settlement Agreement between the Company and
Muckleshoot Tribe of the Muckleshoot Indian Reservation, dated October
31, 1986. (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal
year ended December 31, 1986, Commission File No. 1-4393)
10.49 Transmission Agreement dated April 17, 1981, between the
Bonneville Power Administration and the Company (Colstrip Project). (Exhibit
(10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393)
10.50 Transmission Agreement dated April 17, 1981, between the
Bonneville Power Administration and Montana Intertie Users (Colstrip
Project). (Exhibit (10)-56 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.51 Ownership and Operation Agreement dated as of May 6, 1981,
between the Company and other Owners of the Colstrip Project (Colstrip 3 and
4). (Exhibit (10)-57 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393)
10.52 Colstrip Project Transmission Agreement dated as of May 6, 1981,
between the Company and Owners of the Colstrip Project. (Exhibit (10)-58 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.53 Common Facilities Agreement dated as of May 6, 1981, between the
Company and Owners of Colstrip 1 and 2, and 3 and 4. (Exhibit (10)-59 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.54 Agreement for the Purchase of Power dated as of October 29,
1984, between South Fork II, Inc. and the Company (Weeks Falls Hydroelectric
Project). (Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
67
10.55 Agreement for the Purchase of Power dated as of October 29,
1984, between South Fork Resources, Inc. and the Company (Twin Falls
Hydroelectric Project). (Exhibit (10)-61 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.56 Agreement for Firm Purchase Power dated as of January 4, 1988,
between the City of Spokane, Washington, and the Company (Spokane Waste
Combustion Project). (Exhibit (10)-62 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.57 Agreement for Evaluating, Planning and Licensing dated as of
February 21, 1985 and Agreement for Purchase of Power dated as of February
21, 1985 between Pacific Hydropower Associates and the Company (Koma Kulshan
Hydroelectric Project). (Exhibit (10)-63 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.58 Power Sales Agreement dated as of August 1, 1986, between
Pacific Power & Light Company and the Company. (Exhibit (10)-64 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1987, Commission
File No. 1-4393)
10.59 Agreement for Purchase and Sale of Firm Capacity and Energy
dated as of August 1, 1986 between The Washington Water Power Company and the
Company. (Exhibit (10)-65 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.60 Amendment dated as of June 1, 1968, to Power Sales Contract
between Public Utility District No. 1 of Chelan County, Washington and the
Company (Rocky Reach Project). (Exhibit (10)-66 to Annual Report on Form 10-
K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.61 Coal Supply Agreement dated as of October 30, 1970, between the
Washington Irrigation & Development Company and the Company and other Owners
of the Centralia Thermal Project (Centralia Generating Plant). (Exhibit (10)-
67 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987,
Commission File No. 1-4393)
10.62 Interruptible Natural Gas Service Agreement dated as of May 14,
1980, between Cascade Natural Gas Corporation and the Company (Whitehorn
Combustion Turbine). (Exhibit (10)-68 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.63 Interruptible Natural Gas Service Agreement dated as of January
31, 1983, between Cascade Natural Gas Corporation and the Company (Fredonia
Generating Station). (Exhibit (10)-69 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.64 Interruptible Gas Service Agreement dated May 14, 1981, between
Washington Natural Gas Company and the Company (Fredrickson Generating
Station). (Exhibit (10)-70 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1987, Commission File No. 1-4393)
10.65 Settlement Agreement dated April 24, 1987, between Public
Utility District No. 1 of Chelan County, the National Marine Fisheries
68
Service, the State of Washington, the State of Oregon, the Confederated
Tribes and Bands of the Yakima Indian Nation, Colville Indian Reservation,
Umatilla Indian Reservation, the National Wildlife Federation and the Company
(Rock Island Project). (Exhibit (10)-71 to Annual Report on Form 10-K for
the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.66 Amendment No. 2 dated as of September 1, 1981, and Amendment No.
3 dated September 14, 1987, to Coal Supply Agreement between Western Energy
Company and the Company and the other Owners of Colstrip 3 and 4. (Exhibit
(10)-72 to Annual Report on Form 10-K for the fiscal year ended December 31,
1987, Commission File No. 1-4393)
10.67 Amendatory Agreement No. 1 dated August 27, 1982, and Amendatory
Agreement No. 2 dated August 27, 1982, to the Power Sales Contract between
the Company and the Bonneville Power Administration dated August 27, 1982.
(Exhibit (10)-73 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1987, Commission File No. 1-4393)
10.68 Transmission Agreement dated as of December 30, 1987, between
the Bonneville Power Administration and the Company (Rock Island Project).
(Exhibit (10)-74 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1988, Commission File No. 1-4393)
10.69 Agreement for Purchase and Sale of Firm Capacity and Energy
between The Washington Water Power Company and the Company dated as of
January 1, 1988. (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the
quarter ended March 31, 1988, Commission File No. 1-4393)
10.70 Amendment dated as of August 10, 1988, to Agreement for Firm
Purchase Power dated as of January 4, 1988, between the City of Spokane,
Washington, and the Company (Spokane Waste Combustion Project).(Exhibit (10)-
76 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988,
Commission File No. 1-4393)
10.71 Agreement for Firm Power Purchase dated October 24, 1988,
between Northern Wasco People's Utility District and the Company (The Dalles
Dam North Fishway). (Exhibit (10)-77 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1988, Commission File No. 1-4393)
10.72 Agreement for the Purchase of Power dated as of October 27,
1988, between Pacific Power & Light Company (PacifiCorp) and the Company.
(Exhibit (10)-78 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1988, Commission File No. 1-4393)
10.73 Agreement for Sale and Exchange of Firm Power dated as of
November 23, 1988, between the Bonneville Power Administration and the
Company. (Exhibit (10)-79 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1988, Commission File No. 1-4393)
10.74 Agreement for Firm Power Purchase, dated as of February 24,
1989, between Sumas Energy, Inc. and the Company. (Exhibit (10)-1 to
Quarterly Report on Form 10-Q for the quarter ended March 31, 1989,
Commission File No. 1-4393)
69
10.75 Settlement Agreement, dated as of April 27, 1989, between Public
Utility District No. 1 of Douglas County, Washington, Portland General
Electric Company, PacifiCorp, The Washington Water Power Company and the
Company. (Exhibit (10)-1 to Quarterly Report on Form 10-Q the for quarter
ended September 30, 1989, Commission File No. 1-4393)
10.76 Agreement for Firm Power Purchase (Thermal Project), dated as of
June 29, 1989, between San Juan Energy Company and the Company. (Exhibit
(10)-2 to Quarterly Report on Form 10-Q for the quarter ended September 30,
1989, Commission File No. 1-4393)
10.77 Agreement for Verification of Transfer, Assignment and
Assumption, dated as of September 15, 1989, between San Juan Energy Company,
March Point Cogeneration Company and the Company. (Exhibit (10)-3 to
Quarterly Report on Form 10-Q for the quarter ended September 30, 1989,
Commission File No. 1-4393)
10.78 Power Sales Agreement between The Montana Power Company and the
Company, dated as of October 1, 1989. (Exhibit (10)-4 to Quarterly Report on
Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-
4393)
10.79 Conservation Power Sales Agreement dated as of December 11,
1989, between Public Utility District No. 1 of Snohomish County and the
Company. (Exhibit (10)-87 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1989, Commission File No. 1-4393)
10.80 Memorandum of Understanding dated as of January 24, 1990,
between the Bonneville Power Administrator and The Washington Public Power
Supply System, Portland General Electric Company, Pacific Power & Light
Company, The Montana Power Company, and the Company. (Exhibit (10)-88 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1989,
Commission File No. 1-4393)
10.81 Amendment No. 1 to Agreement for the Assignment of Power from
the Centralia Thermal Project dated as of January 1, 1990, between Public
Utility District No. 1 of Grays Harbor County, Washington, and the Company.
(Exhibit (10)-89 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1990, Commission File No. 1-4393)
10.82 Preliminary Materials and Equipment Acquisition Agreement dated
as of February 9, 1990, between Northwest Pipeline Corporation and the
Company. (Exhibit (10)-90 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1990, Commission File No. 1-4393)
10.83 Amendment No. 1 to the Colstrip Project Transmission Agreement
dated as of February 14, 1990, among the Montana Power Company, The
Washington Water Power Company, Portland General Electric Company, PacifiCorp
and the Company. (Exhibit (10)-91 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.84 Settlement Agreement dated as of February 27, 1990, among United
States of America Department of Energy acting by and through the Bonneville
Power Administrator, the Washington Public Power Supply System, and the
70
Company. (Exhibit (10)-92 to Annual Report on Form 10-K for the fiscal year
ended December 31, 1990, Commission File No. 1-4393)
10.85 Amendment No. 1 to the Fifteen-Year Power Sales Agreement dated
as of April 18, 1990, between Pacificorp and the Company. (Exhibit (10)-93
to Annual Report on Form 10-K for the fiscal year ended December 31, 1990,
Commission File No. 1-4393)
10.86 Settlement Agreement dated as of October 1, 1990, among Public
Utility District No. 1 of Douglas County, Washington, the Company, Pacific
Power and Light Company, The Washington Water Power Company, Portland General
Electric Company, the Washington Department of Fisheries, the Washington
Department of Wildlife, the Oregon Department of Fish and Wildlife, the
National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the
Confederated Tribes and Bands of the Yakima Indian Nation, the Confederated
Tribes of the Umatilla Reservation, and the Confederated Tribes of the
Colville Reservation. (Exhibit (10)-95 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.87 Agreement for Firm Power Purchase dated July 23, 1990, between
Trans-Pacific Geothermal Corporation, a Nevada corporation, and the Company.
(Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March
31, 1991, Commission File No. 1-4393)
10.88 Agreement for Firm Power Purchase dated July 18, 1990, between
Wheelabrator Pierce, Inc., a Delaware corporation, and the Company. (Exhibit
(10)-2 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991,
Commission File No. 1-4393)
10.89 Agreement for Firm Power Purchase dated September 26, 1990,
between Encogen Northwest, L.P., A Delaware Corporation and the Company.
(Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended March
31, 1991, Commission File No. 1-4393)
10.90 Agreement for Firm Power Purchase (Thermal Project) dated
December 27, 1990, among March Point Cogeneration Company, a California
general partnership comprising San Juan Energy Company, a California
corporation; Texas-Anacortes Cogeneration Company, a Delaware corporation;
and the Company. (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the
quarter ended March 31, 1991, Commission File No. 1-4393)
10.91 Agreement for Firm Power Purchase dated March 20, 1991, between
Tenaska Washington, Inc. a Delaware corporation, and the Company. (Exhibit
(10)-1 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991,
Commission File No. 1-4393)
10.92 Letter Agreement dated April 25, 1991, between Sumas Energy,
Inc., and the Company, to amend the Agreement for Firm Power Purchase dated
as of February 24, 1989. (Exhibit (10)-2 to Quarterly Report on Form 10-Q
for the quarter ended June 30, 1991, Commission File No. 1-4393)
10.93 Amendment dated June 7, 1991, to Letter Agreement dated April
25, 1991, between Sumas Energy, Inc., and the Company. (Exhibit (10)-3 to
Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission
File No. 1-4393)
71
10.94 Amendatory Agreement No. 3, dated August 1, 1991, to the Pacific
Northwest Coordination Agreement, executed September 15, 1964, among the
United States of America, the Company and most of the other major electrical
utilities in the Pacific Northwest. (Exhibit (10)-4 to Quarterly Report on
Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393)
10.95 Amendment dated July 11, 1991, to the Agreement for Firm Power
Purchase dated September 26, 1990, between Encogen Northwest, L.P., a
Delaware limited partnership and the Company. (Exhibit (10)-1 to Quarterly
Report on Form 10-Q for the quarter ended September 30, 1991, Commission File
No. 1-4393)
10.96 Agreement between the 40 parties to the Western Systems Power
Pool (the Company being one party) dated July 27, 1991. (Exhibit (10)-2 to
Quarterly Report on Form 10-Q for the quarter ended September 30, 1991,
Commission File No. 1-4393)
10.97 Memorandum of Understanding between the Company and the
Bonneville Po wer Administration dated September 18, 1991. (Exhibit (10)-3 to
Quarterly Report on Form 10-Q for the quarter ended September 30, 1991,
Commission File No. 1-4393)
10.98 Amendment of Seasonal Exchange Agreement, dated December 4,
1991, between Pacific Gas and Electric Company and the Company. (Exhibit
(10)-107 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.99 Capacity and Energy Exchange Agreement, dated as of October 4,
1991, between Pacific Gas and Electric Company and the Company. (Exhibit
(10)-108 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.100 Intertie and Network Transmission Agreement, dated as of October
4, 1991, between Bonneville Power Administration and the Company. (Exhibit
(10)-109 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.101 Amendatory Agreement No. 4, executed June 17, 1991, to the Power
Sales Agreement dated August 27, 1982, between the Bonneville Power
Administration and the Company. (Exhibit (10)-110 to Annual Report on Form
10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.102 Amendment to Agreement for Firm Power Purchase, dated as of
September 30, 1991, between Sumas Energy, Inc. and the Company. (Exhibit
(10)-112 to Annual Report on Form 10-K for the fiscal year ended December 31,
1991, Commission File No. 1-4393)
10.103 Centralia Fuel Supply Agreement, dated as of January 1, 1991,
between Pacificorp Electric Operations and the Company and other Owners of
the Centralia Steam-Electric Power Plant. (Exhibit (10)-113 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1991, Commission File No.
1-4393)
72
10.104 Agreement for Firm Power Purchase dated August 10, 1992, between
Pyrowaste Corporation, Puget Sound Pyroenergy Corporation and the Company.
(Exhibit (10)-114 to Annual Report on Form 10-K for the fiscal year ended
December 31, 1992, Commission File No. 1-4393)
10.105 Memorandum of Termination dated August 31, 1992, between Encogen
Northwest, L.P. and the Company. (Exhibit (10)-115 to Annual Report on Form
10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.106 Agreement Regarding Security dated August 31, 1992, between
Encogen Northwest, L.P. and the Company. (Exhibit (10)-116 to Annual Report
on Form 10-K for the fiscal year ended December 31, 1992, Commission File No.
1-4393)
10.107 Consent and Agreement dated December 15, 1992, between the
Company, Encogen Northwest, L.P. and The First National Bank of Chicago, as
collateral agent. (Exhibit (10)-117 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.108 Subordination Agreement dated December 17, 1992, between the
Company, Encogen Northwest, L.P., Rolls-Royce & Partners Finance Limited and
The First National Bank of Chicago. (Exhibit (10)-118 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-
4393)
10.109 Letter Agreement dated December 18, 1992, between Encogen
Northwest, L.P. and the Company regarding arrangements for the application of
insurance proceeds. (Exhibit (10)-119 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.110 Guaranty of Ensearch Corporation in favor of the Company dated
December 15, 1992. (Exhibit (10)-120 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.111 Letter Agreement dated October 12, 1992, between Tenaska
Washington Partners, L.P. and the Company regarding clarification of issues
under the Agreement for Firm Power Purchase. (Exhibit (10)-121 to Annual
Report on Form 10-K for the fiscal year ended December 31, 1992, Commission
File No. 1-4393)
10.112 Consent and Agreement dated October 12, 1992, between the
Company, and The Chase Manhattan Bank, N.A., as agent. (Exhibit (10)-122 to
Annual Report on Form 10-K for the fiscal year ended December 31, 1992,
Commission File No. 1-4393)
10.113 Settlement Agreement dated December 29, 1992, between the
Company and the Bonneville Power Administration (BPA) providing for power
purchase by BPA. (Exhibit (10)-123 to Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.114 Contract with W. S. Weaver, Executive Vice President & Chief
Financial Officer, dated April 24, 1991. (Exhibit 10.114 to Annual Report on
Form 10-K for the fiscal year ended December 31, 1993, Commission File No. 1-
4393)
73
*10.115 General Transmission Agreement dated as of December 1, 1994,
between the Bonneville Power Administration and the Company (BPA Contract No.
DE-MS79-94BP93947)
*10.116 PNW AC Intertie Capacity Ownership Agreement dated as of October
11, 1994 between the Bonneville Power Administration and the Company (BPA
Contract No. DE-MS79-94BP94521)
*12-a Statement setting forth computation of ratios of earnings to
fixed charges (1990 through 1994).
*12-b Statement setting forth computation of ratios of earnings to
combined fixed charges and preferred stock dividends (1990 through 1994).
21 List of subsidiaries. (Exhibit 22 to Annual Report on Form 10-K
for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
*23 Consent of accountants.
*27 Financial Data Schedule
_________________________________
*Filed herewith.
74
EXHIBIT 10.115
Contract No. DE-MS79-94BP93947
GENERAL TRANSMISSION AGREEMENT
entered into by the
UNITED STATES OF ANLERICA
DEPARTMENT OF ENERGY
acting by and through the
BONNEVILLE POWER ADMINISTRATION
and
PUGET SOUND POWER & LIGHT COMPANY
Index to Sections
_____________________________________________________________________________
Section Page
1. Term of Agreement............................................... 3
2. Termination of Prior Agreements................................. 4
3. Definitions and Explanation of Terms............................ 4
4. Exhibits: Interpretations...................................... 8
5. Transmission of Electric Power.................................. 9
6. Payment by the Company.......................................... 14
7. Power Scheduling................................................ 15
8. Reactive Power.................................................. 16
9. Revision of Exhibits............................................ 16
10. Addition or Deletion of Points of Integration and Points of
Delivery and Changes in Transmission Demands.................... 18
11. Special Provisions.............................................. 22
12. Miscellaneous................................................... 23
Exhibit A (Transmission Rate Schedules and General
Transmission Rate Schedule Provisions)........... 8
Exhibit B (General Wheeling Provisions [GWP Form 4R])........ 8
Exhibit C (Transmission Parameters).......................... 8
Exhibit D (Calculation of Losses)............................ 8
This GENERAL TRANSMISSION AGREEMENT (Agreement) is entered into as of
December 1, 1994, by the UNITED STATES OF AMERICA (Government), Department of
Energy, acting by and through the BONNEVILLE POWER ADMINISTRATION
(Bonneville), and PUGET SOUND POWER & LIGHT COMPANY (Company), a corporation
of the State of Washington. Each of Bonneville and the Company is sometimes
referred to in this Agreement as "Party"; both of Bonneville and the Company
are sometimes referred to in this Agreement as "Parties".
WITNESSETH:
WHEREAS Bonneville and the Company on August 27, 1982, entered into
Contract No. DE-MS79-81BP90426, as amended and replaced to the date hereof,
and
WHEREAS Bonneville and the Company have entered into Letter Agreement
No. DE-MS79-91BP93160 (Letter Agreement) which contemplates a new General
Transmission Agreement (IR Agreement) for integration of resources and for
certain other contractual arrangements, and Bonneville and the Company intend
this Agreement to be the IR Agreement contemplated by the Letter Agreement;
and
WHEREAS the Parties have entered into the following agreements for
transmission of Electric Power (collectively referred to herein as Prior
Agreements): Contract No. DE-MS79-88BP92292, providing transmission service
for the Company's share of the electric output of the Centralia Project;
Contract No. DE-MS79-81BP90169, providing transmission service for the
Company's share of the electric output of the Colstrip Thermal Generating
Plant; and Contract No. DE-MS79-92BP93741, providing transmission service for
a portion of the electric output of Montana Power Company's Colstrip # 4; and
WHEREAS Bonneville and the Company desire to terminate the Prior
Agreements and replace the Prior Agreements with this Agreement; and
WHEREAS Bonneville recognizes that the Company's Tono Transmission
Facilities have a design capacity of 400 MW, but due to parallel path and
other considerations, the Parties desire to transmit Electric Power pursuant
to the terms of this Agreement; and
WHEREAS the Company and The Washington Water Company (WWP) have
entered into an agreement pursuant to which WWP exchanges 197 MW of Electric
Power from the Centralia Project, located in Centralia, Washington, with the
Company for an equal amount of Electric Power from the Colstrip Thermal
Generating Plant, located in Colstrip, Montana, and the Company intends to
enter into an amendment or replacement of such exchange agreement with WWP;
and
WHEREAS Bonneville and the Company, concurrently with the
effectiveness of this Agreement, have entered into a Pacific Northwest (PNW)
AC Intertie Capacity Ownership Agreement, Contract No. DE-MS79-94BP94521
, (Capacity Ownership Agreement) which,
2
among other things, provides for ownership by the Company of a portion of the
capability of Bonneville's PNWAC Intertie (as defined in the Capacity
Ownership Agreement); and
WHEREAS the Parties desire to provide in this Agreement for, among other
things, the transmission over the Federal Columbia River Transmission System,
to and from the Company's transmission system, of Electric Power scheduled
for transmission over the PNW AC Intertie pursuant to the Capacity Ownership
Agreement; and
WHEREAS Bonneville is authorized pursuant to law to dispose of Electric
Power generated at various Federal hydroelectric projects in the PNW or
acquired from other resources; to construct and operate transmission
facilities; to provide transmission and other services; and to enter into
agreements to carry out such authority;
NOW, THEREFORE, the Parties agree as follows:
1. TERM OF AGREEMENT
(a) This Agreement shall be effective at 2400 hours on the latest
of (1) the date of execution and delivery of this Agreement; (2)
the earliest date on which the Company may exercise its Capacity
Ownership Rights (as defined in the Capacity Ownership Agreement)
pursuant to the Capacity Ownership Agreement; and (3) the date by
which this Agreement has, with respect to the Company, been
approved, accepted for filing or otherwise permitted to become
effective by FERC; provided, that if FERC approves or accepts for
filing this Agreement, or otherwise permits this Agreement to
become effective with any change or new condition, this Agreement
shall not be or become effective unless both of the Parties have
agreed in writing, and until the date by which both of the Parties
have so agreed, to such change or new condition (such latest date,
the Effective Date). This Agreement shall continue in effect until
2400 hours on July 31, 2014; provided, however, that all
liabilities accrued under this Agreement shall be preserved until
satisfied.
(b) One (1) year prior to the expiration of this Agreement, Bonneville
shall offer to provide to the Company transmission services as
provided hereunder, on terms and conditions consistent with the
terms and conditions for such
3
transmission services being offered at that time by Bonneville to
other Bonneville customers similarly situated.
(c) If the Total Transmission Demand is reduced to zero pursuant to the
terms and provisions of section 10(c), the Company may, subject to
satisfaction of all obligations accrued hereunder and completion
of all notice periods specified in section 10(c), terminate this
Agreement by written notice of such termination to Bonneville.
(d) The Company may terminate this Agreement or any Transmission Demand
under this Agreement upon 1-year's prior written notice of such
termination to Bonneville if Bonneville discontinues application
of cost-based rates for service provided under this Agreement.
2. TERMINATION OF PRIOR AGREEMENTS
(a) The Prior Agreements are hereby terminated as of 2400 hours on the
Effective Date but all liabilities accrued thereunder to the
Effective Date are hereby preserved until satisfied.
(b) Contract No. DE-MS79-91BP93053 (Intertie and Network Transmission
Agreement) shall terminate as of 2400 hours on the Effective Date
but all liabilities accrued thereunder to the Effective Date are
hereby preserved until satisfied; provided, that the penultimate
sentence of section 5(b) of such contract shall not be applicable
for seasons during which such contract terminates pursuant to this
Agreement.
3. DEFINITIONS AIND EXPLANATION OF TERMS
(a) "Connecting Transmission" means, with respect to a Resource
integrated at a Point of Integration, transmission service or
facilities needed or used for transmission of such Resource to
such Point of Integration for transmission under this Agreement.
4
(b) "DC Intertie" means Bonneville's rights in the 1000 kV direct
current (DC) transmission line, and associated substation
facilities, extending from the Government's Big Eddy Substation to
the Nevada-Oregon Border.
(c) "Eastern Intertie" means the transmission facilities
consisting of the Townsend-Garrison double-circuit 500 kV
transmission line segment, including related terminals at the
Garrison Substation.
(d) "Electric Power" or "Power" means electric peaking capacity,
expressed in kilowatts, or electric energy, expressed in
kilowatthours, or both.
(e) "FCRTS" or "Federal Columbia River Transmission System" means the
transmission facilities of the Federal Columbia River Power System,
which include all transmission facilities owned by the Government
and operated by Bonneville, and other facilities over which
Bonneville has obtained transmission rights.
(f) "FERC" means the Federal Energy Regulatory Commission or its
regulatory successors.
(g) "Montana Intertie Agreement" means Contract No. DE-MS79-8IBP90210
between Bonneville and the Company, as amended.
(h) "Operational Constraints" means limitations on the ability of the
FCRTS to operate due to any system emergency, loading condition,
or maintenance outage with respect to Bonneville facilities, or
the facilities of an interconnected utility, that make it prudent
to reduce system loadings consistent with Prudent Utility
Practice, whether or not all facilities are in service.
(i) "PNW AC Intertie has the meaning set forth in the Capacity
Ownership Agreement.
5
(j) "Point of Delivery" means:
(1) any of the points set forth in Exhibit C, Part B, where
Electric Power shall be made available to the Company pursuant
to this Agreement; and
(2) any other point mutually agreed upon by the Parties where
Electric Power shall be made available to the Company pursuant
to this Agreement.
(k) "Point of Integration" means:
(1) any of the points set forth in Exhibit C, Part A, where
Electric Power from Resources shall be integrated into the
FCRTS pursuant to this Agreement; and
(2) any other point mutually agreed upon by the Parties where
Electric Power from Resources may be made available to
Bonneville for nonfirm transmission to any of the Points of
Delivery pursuant to this Agreement.
(l) "Prudent Utility Practice" means, at any particular time, the
generally accepted practices, methods, and acts in the electrical
utility industry in the Western Systems Coordinating Council area
immediately prior to such time that would achieve the desired
result or, if there are no such practices, methods, and acts, then
the practices, methods and acts which, in the exercise of
reasonable judgment in the light of facts known at the time the
decision was made, could have been expected to accomplish the
desired result consistent with reliability and safety.
(m) "Resource" means:
(1) any Electric Power from a source set forth in Exhibit C, Part
A; and
(2) any Electric Power transmitted over the PNW AC Intertie
pursuant to the Capacity Ownership Agreement and made
available to Bonneville
6
at the John Day Substation Point of Integration. Upon request
by Bonneville, the Company shall identify the source of such
Electric Power; provided, however, that if such Electric Power
can only be identified as a system sale, then the Company
shall be obligated pursuant to this section 3(m)(2) to
identify only the utility generating such Electric Power; and
(3) any Electric Power (i) which the Company has a right to
receive, and (ii) for which nonfirm transmission service is
requested by the Company on the FCRTS, and (iii) the Electric
Power from which is made available to Bonneville at one or
more of the Points of Integration; and
(4) any other Electric Power for which nonfirm transmission
service is requested by the Company for the purpose of
providing station service to any of the Company's sources of
Electric Power interconnected with the FCRTS, and which
Electric Power is made available to Bonneville at any of the
Points of Integration.
(n) "Total Power Wheeled" means with respect to any hour the sum of the
Electric Power made available to Bonneville during such hour for
transmission on the FCRTS pursuant to this Agreement, including but
not limited to section 7, at all Points of Integration.
(o) "Total Transmission Demand" means the sum of the Company's
Transmission Demands.
(p) "Transmission Demand" with respect to any Point of Integration,
means the maximum firm transmission capacity (expressed in
kilowatts) as set forth in Exhibit C, Part A, which Bonneville
shall be obligated pursuant to this Agreement to have available at
such Point of Integration during any hour for the purpose of
integrating into the FCRTS any Resource. The level of each
Transmission Demand, with respect to each Point of Integration set
forth in Exhibit C, Part A, (except for the John Day Substation
Point of Integration). shall be based on the hourly peak capability
of the source(s) of Electric Power
7
listed in Exhibit C, Part A, to be integrated into the FCRTS at
such Point of Integration.
(q) "Use-of-Facilities Charge" means the charges, if any, specified in
Exhibit C, applicable to Points of Integration and Points of
Delivery for the purpose of recovering the cost of identifiable
facilities provided by Bonneville for the Company's use. Such
charges and their application shall be consistent with the Use-of-
Facilities Transmission Rate Schedule, contained in Exhibit A, and
shall, subject to section 9(c), also be consistent with
Bonneville's Customer Service Policy.
(r) "Use Limit" means with respect to any Point of Delivery the amounts
(in kilowatts) set forth in Exhibit C, Part B, corresponding to
such Point of Delivery.
(s) "Northern Intertie" means that segment of the FCRTS assigned by
Bonneville for Bonneville transfer capability at the United States-
Canada border.
(t) "Workday" means any day which both of the Parties observe as a
regular workday.
4. EXHIBITS; INTERPRETATIONS
Exhibits A, B, C, and D (Exhibits) attached hereto are by this reference
incorporated into and made a part of this Agreement. The Parties agree
that "contract body" as used in section 1 of Exhibit B shall mean
sections 1 through 12 of this Agreement. The provisions of section 38 of
the General Wheeling Provisions (GWP Form-4R), require that Bonneville
provide a notice consistent with a minimum notice period prior to a Rate
Adjustment Date (as defined in Exhibit B). If the rates set forth in or
applicable to this Agreement are disapproved or if conditions are placed
on such rates by FERC, Bonneville shall not be required to give such
notice prior to resubmitting the rates to FERC or implementing FERC
approved rates. The headings used in this Agreement are for convenient
reference only, and shall not affect the interpretation of this
Agreement. The Company shall be deemed to be the "Transferee" and
Bonneville shall be deemed to be the "Transferor" referred to in the
General Wheeling Provisions, Exhibit B.
8
5. TRANSMISSION OF ELECTRIC POWER
(a) Bonneville shall, during each hour of the term of this Agreement,
make an amount of Electric Power equal to the Total Power Wheeled
available to the Company at one or more of the Points of Delivery,
subject to sections 5(a)(1) through 5(a)(5) below. In the event
that service hereunder must be curtailed due to Operational
Constraints, Bonneville obligation to mitigate the effects of such
curtailment are set forth in section 5(e) below and in section 12
of Exhibit B, (except to the extent that such section 12 conflicts
with sections 1 through 12 of this Agreement), and in footnote 3
of Exhibit C, Part A, and Bonneville shall have no other
obligation to mitigate the effects of such curtailment pursuant to
this Agreement.
(1) Bonneville may, but shall not be obligated to, integrate into
the FCRTS during any hour amounts of Electric Power to the
extent that such amounts exceed the Total Transmission
Demand.
(2) Firm transmission capability of the FCRTS between the
Company's system and John Day Substation shall,
notwithstanding any Operational Constraints or any other
constraint on the ability of the FCRTS to operate, be deemed
to exist during any hour (i) for north-to-south transmission,
in an amount equal to the Company's Total Transmission Demand,
and (ii) for south-to-north transmission, in an amount equal
to the Company's Transmission Demand for the John Day
Substation Point of Integration. The net of the Company's
schedules in a north-to-south direction and in a south-to-nor-
north direction during any hour shall be used to determine
use of such transmission. The Company shall be billed for
transmission of Electric Power for such hour pursuant to the
provisions of section 6.
(3) Bonneville may, but shall not be obligated to, integrate at a
Point of Integration during any hour, amounts of Electric
Power to the extent that such amounts exceed the Transmission
Demand at such Point of Integration.
9
(4) Bonneville may, but shall not be obligated to, integrate
Electric Power other than Resources set forth in Exhibit C,
Part A, provided that the Points of Integration for such
Electric Power have been mutually agreed upon by the Parties
pursuant to this Agreement.
(5) Notwithstanding anything to the contrary set forth in this
Agreement, Bonneville shall not withhold its agreement (A) to
any point proposed by the Company as a Point of Integration
pursuant to section 3(k)(2) or to any amount of Electric Power
proposed by the Company to be integrated at such point or (B)
to integrate at any Point of Integration set forth in Exhibit
C, Part A, amounts of Electric Power in excess of the
Transmission Demand with respect to such Point of Integration,
except to the extent that (i) capacity of the facilities
located at such point or at such Point of Integration, as the
case may be, is not available due to Operational Constraints,
or (ii) Bonneville requires the use of such capacity, or any
portion thereof, for purposes of transmitting Bonneville
nonfirm power; provided however, that capacity at such point
or at such Point of Integration, as the case may be, not
required by Bonneville for transmission of Bonneville's
nonfirm power shall be made available to the Company in an
amount equal to the product of (x) the ratio of (i) the amount
of Electric Power requested by the Company to be transmitted
on a nonfirm basis at such point or such Point of Integration,
as the case may be, to (ii) the total amount of Electric Power
requested by entities other than Bonneville to be transmitted
on a nonfirm basis at such point or such Point of Integration,
as the case may be, and (y) the amount of capacity at such
point or such Point of Integration, as the case may be, not
required by Bonneville for transmission of Bonneville's
nonfirm power. Nothing in this section 5(a)(5) is intended by
the Parties to constrain Bonneville from engaging in design of
a successor to the Energy Transmission Rate.
(b) The Parties' respective rights and obligations with respect to
Bonneville's PNW AC Intertie are set forth in the Capacity
Ownership Agreement. Nothing in this Agreement, including, without
limitation, delivery by Bonneville of Power at the John Day
Substation Point of Delivery, or
10
integration of Power into the FCRTS at the John Day Substation
Point of Integration is intended by the Parties to limit, alter,
add to or otherwise affect the respective rights and obligations of
the Parties pursuant to the Capacity Ownership Agreement. Nothing
in this Agreement, including, without limitation, delivery by
Bonneville of Power at the Big Eddy Point of Delivery, is intended
by the Parties to provide rights to use the DC Intertie. Nothing
in this Agreement is intended by the Parties to limit, alter, add
to or otherwise affect the respective rights and obligations of the
Parties pursuant to the Montana Intertie Agreement.
(c) If the Company determines that it has an amount of Electric Power
available during any hour for nonfirm transmission on the FCRTS,
the scheduling and transmission of which would cause the Total
Power Wheeled to exceed in such hour the Total Transmission Demand,
the Company may request from Bonneville nonfirm transmission
service for transmission on the FCRTS for such amount of Electric
Power during such hour. Bonneville may provide such transmission
service. The Company shall be billed for such transmission service
pursuant to the provisions of section 6(d).
(1) The option pursuant to this section 5(c) to make available
Electric Power for nonfirm transmission on the FCRTS by
Bonneville shall not be used by the Company to avoid having a
Total Transmission Demand which reasonably reflects the
annual peak transmission needs of all of the sources of
Electric Power set forth in Exhibit C, Part A, and the
combined total annual peak demand for wheeling with respect to
all of such sources of Electric Power which the Company
regularly places on Bonneville. Bonneville shall have the
right to refuse to provide the Company transmission service on
a nonfirm basis to the extent Bonneville determines consistent
with this section 5(c)(1), that the Transmission Demand at a
Point of Integration should be increased.
(2) To the extent Bonneville wheels, pursuant to this Agreement,
any Electric Power of the Company's on the FCRTS in connection
with a transaction which is exempt from wheeling charges or
loss assessment
11
at the time of actual transmission of such Electric Power,
(such as any qualifying transaction under the Coordination
Agreement (Contract No 14-03-48221)), and which is
subsequently converted to a sale other than under the terms of
the Coordination Agreement, to an entity other than
Bonneville, Bonneville shall have the right to retroactively
(to the date of such conversion) bill the Company for such
wheeling as nonfirm transmission service pursuant to
Bonneville's Energy Transmission (ET-93) Rate Schedule in
effect at the time such Electric Power was wheeled, or its
successor rate schedule, and the provisions of section 6(d),
and to assess losses consistent with this Agreement with
respect to any Electric Power so wheeled in connection with
such transaction unless billing or losses for such subsequent
conversion is otherwise provided for under another agreement
to which Bonneville is a Party. Such qualifying transactions
shall not be subject to sections 5(c)(1) above and 5(c)(3)
below.
(3) Except for any Electric Power made available by the Company
for nonfirm transmission pursuant to this section 5(c),
amounts of Electric Power wheeled hereunder from a Point of
Integration which exceed the Transmission Demand at such Point
of Integration shall be subject to billing as a Ratchet Demand
in accordance with section 6(b). To the extent the Energy
Transmission Rate Schedule (ET-93), or its successor rate
schedule, is applied, a Ratchet Demand shall not be applied.
(d) To compensate Bonneville for losses incurred in providing
transmission services pursuant to this Agreement, the Company shall
make available to Bonneville at one or more Points of Delivery
(unless otherwise mutually agreed between the Parties), on the
corresponding hour 168 hours later or on another hour mutually
agreed upon by the Parties, an amount of Electric Power equal to
the product of (1) the amount of Electric Power (expressed in
megawatthours) for which transmission service is provided to the
Company during a given hour pursuant to sections 5(a) and 5(c), and
(2) the appropriate loss factor set forth in Exhibit D.
12
(e) Bonneville shall, if requested by the Company to do so and if it
is within Bonneville's capability to do so without adversely
affecting performance of its other obligations, make replacement
Electric Power available to the Company hereunder, without
additional cost to the Company except as provided in this section
5(e), if Electric Power cannot be made available by the Company to
Bonneville pursuant to this Agreement solely because of (i)
limitations on the ability of the FCRTS to operate due to any
system emergency, loading condition, or maintenance outage with
respect to Bonneville facilities that makes it prudent to reduce
system loadings consistent with Prudent Utility Practice, whether
or not all facilities are in service; or (ii) suspension or
interruption of, or interference with, the operation of the FCRTS;
or (iii) both. The Company shall, at Bonneville's option:
(1) reimburse Bonneville for any cost or loss of revenue incurred
by Bonneville in making such replacement Electric Power
available;
(2) replace all or a portion of such replacement Electric Power
with the Company's Electric Power at a time and place agreed
upon by the Parties prior to delivery; or
(3) reimburse and replace pursuant to sections 5(e)(1) and 5(e)(2)
above in amounts determined by Bonneville which in total are
equivalent in value to (A) the cost or loss of revenue
incurred by Bonneville in making replacement Electric Power
available to the Company pursuant to this section 5(e) or (B)
the Electric Power made available by Bonneville pursuant to
this section 5(e).
The method to replace or reimburse shall be specified by Bonneville
at the time of the Company's request for replacement Electric
Power. The Company shall have the right to withdraw such request
for replacement Electric Power, prior to delivery thereof and prior
to Bonneville's incurring any cost therefor, after Bonneville
specifies the method to replace and/or the amount to reimburse
pursuant to this section 5(e).
13
(f) The Company shall not use its rights under this Agreement to
provide wheeling to another entity if such wheeling is inconsistent
with the Company's rights in the PNW AC Intertie Capacity Ownership
Agreement, Contract No. DE-MS79-94BP94521.
(g) Bonneville shall give the Company notice of any likely or actual
occurrence or existence of (i) any Operational Constraint and (ii)
any suspension or interruption of, or interference with, the
operation of the FCRTS, to the extent that the same affects the
provision of service by Bonneville with respect to any Point of
Integration or Point of Delivery pursuant to this Agreement. Such
notice shall be given as promptly as practicable by Bonneville.
6. PAYMENT BY THE COMPANY
As full compensation for services provided under sections 5(a) and 5(c),
the Company shall pay Bonneville each month during the term hereof,
amounts determined in accordance with Exhibit A and Exhibit C, and as
follows:
(a) For integration of Electric Power pursuant to section 5(a), the
Company shall, subject to sections 5(b), 5(c), and 5(d), pay
Bonneville in accordance with the Integration of Resources
Transmission Rate Schedule (IR-93), or its successor rate schedule,
and, to the extent expressly provided in other provisions of this
Agreement, in accordance with the Use-of-Facilities Rate Schedule
(UFT-83), or its successor rate schedule; provided, that for the
purposes of this Agreement, the term "scheduled" as used in Section
III.B. of the Integration of Resources Transmission Rate Schedule
(IR-93), or its successor rate schedule, shall mean or refer to any
submission (or arrangement for submission) by the Company of any
schedule or retroactive report pursuant to section 7 of this
Agreement.
(b) The billing demand shall be determined in accordance with the
Integration of Resources (IR-93) Transmission Rate Schedule, or its
successor rate schedule. Any Ratchet Demand that may occur is for
billing purposes only and does not constitute an increase in any
Transmission Demand pursuant to section 10. Any continued service
with respect to any Point of Integration pursuant to this Agreement
at a level, to the extent that such level exceeds the
14
Transmission Demand with respect to such Point of Integration, will
depend on the availability of facilities for such purpose as
reasonably determined by Bonneville.
(c) The billing energy for each month pursuant to the Integration of
Resources Transmission Rate Schedule (IR-93), or its successor rate
schedule, and the Energy Transmission Rate Schedule (ET-93), or its
successor rate schedule, shall be the sum of the greater of the
hourly amounts of (A) kilowatthours scheduled from the Points of
Integration to the Company's transmission system over Bonneville's
transmission system hereunder, or (B) kilowatthours scheduled over
Bonneville's transmission system hereunder from the Company's
transmission system to the John Day Point of Delivery and the Big
Eddy Point of Delivery.
(d) The Company shall be billed for transmission of Electric Power up
to an amount equal to the Total Transmission Demand pursuant to the
Integration of Resources Transmission Rate Schedule (IR-93), or its
successor rate schedule. To the extent the Total Transmission
Demand is exceeded, the Company shall be billed for nonfirm
transmission of Electric Power pursuant to the Energy Transmission
Rate Schedule (ET-93), or its successor rate schedule. For
transmission pursuant to section 5(c)(2), the Company shall be
billed in accordance with the Energy Transmission (ET-93) Rate
Schedule, or its successor rate schedule.
7. POWER SCHEDULING
The Company shall submit or arrange to have submitted to Bonneville by
1000 hours (Pacific Time) (or any other hour agreed upon by the Parties)
of each Workday:
(a) for the Resource referred to in section 3(m)(1), a retroactive
report of the Electric Power made available to Bonneville for
integration into the FCRTS during each hour of the immediately
preceding Workday and of the days other than a Workday (if any)
succeeding such immediately preceding Workday;
15
(b) for the Resources referred to in sections 3(m)(2), 3(m)(3) and
3(m)(4), a separate schedule of the Electric Power to be made
available to Bonneville for integration into the FCRTS during each
hour of the next succeeding Workday and of the days other than a
Workday (if any) immediately preceding such next succeeding
Workday; and
(c) a separate schedule of the Electric Power to be made available to
Bonneville for losses pursuant to section 5(d) during each hour of
the next succeeding Workday and of the days other than a Workday
(if any) immediately preceding such next succeeding Workday.
8. REACTIVE POWER
It is the intent of the Parties hereto that the voltage level at the
Points of Integration and the Points of Delivery be controlled in
accordance with Prudent Utility Practice. The Parties hereto shall
jointly plan and operate their systems so as not to place an undue
burden on the other Party to supply or absorb reactive power
accompanying or resulting from deliveries of Electric Power hereunder.
9. REVISION OF EXHIBITS
(a) The rate schedules included in Exhibit A shall be replaced by
successor rate schedules adopted in accordance with the provisions
of section 7(i) of the Pacific Northwest Power Act and FERC rules.
(b) Bonneville may review Exhibit D and, no more frequently than once
in a 12-month period commencing on the anniversary of the Effective
Date, may revise such Exhibit to reflect any change in condition
that would substantially affect the loss factor set forth in
Exhibit D; provided, however, that any change to the loss factor
pursuant to this Agreement
(1) shall be prospective only;
(2) shall be made in an equitable manner so as to be consistent
with such change in condition;
16
(3) shall incorporate values which represent then current FCRTS
operating conditions or incorporate any value, used in Exhibit
D to calculate the losses, which has changed due to a change
in methodology; and
(4) shall in no event result in a loss factor that is greater than
the loss factor which Bonneville is then applying with respect
to any of its other customers for firm transmission under an
Integration of Resources Transmission Agreement.
Any changes to Bonneville's loss methodology or formula, other than
numerical values, shall be made only after consultation with the
Company. During such consultation, Bonneville shall provide to the
Company material used by Bonneville as a basis for such changes to such
loss methodology or formula. Exhibit D as revised pursuant to this
section 9(b) shall become effective as of the date specified therein;
provided, however, that in no event shall such revised Exhibit D be
effective sooner than the date on which the Company is notified by
Bonneville in writing of such revision to Exhibit D.
(c) No Use-of-Facilities Charges or any rates or charges other than
charges pursuant to the Integration of Resources Transmission Rate
Schedule (IR-93), or its successor rate schedule, or the Energy
Transmission Rate Schedule (ET-93), or its successor rate schedule,
shall be assessed pursuant to this Agreement for delivery from the
C.W. Paul Substation, Garrison Substation, or John Day Substation
Point of Integration to the Points of Delivery specified in Exhibit
C, Part D, on the Effective Date, at levels of service specified in
Exhibit C on the Effective Date, except if and to the extent that
the Parties mutually agree that conditions have changed and that
such charge is appropriate as a result of such change.
(d) In the event Bonneville proposes any wheeling rate for transmission
service on Bonneville's main grid that includes costs of the PNW AC
Intertie, the Eastern Intertie, the DC Intertie, or the Northern
Intertie, such proposed rate shall include a credit or other
mechanism that ensures that the Company is not charged any of the
PNW AC Intertie, the Eastern Intertie, the DC Intertie, or the
Northern Intertie costs for deliveries of power that
17
utilize up to the capacity share of each such intertie, if any, to
which the Company is entitled pursuant to other agreements with
Bonneville.
10. ADDITION OR DELETION OF POINTS OF INTEGRATION AND POINTS OF DELIVERY AND
CHANGES IN TRANSMISSION DEMANDS
(a) Except as otherwise provided in section 10(b), Points of
Integration and Points of Delivery shall be added and Transmission
Demands shall be increased, subject to mutual agreement of the
Parties, which agreement shall not be unreasonably withheld or
delayed, and to Bonneville's determination of available
transmission capacity, upon 3-months' prior written notice by the
Company to Bonneville of such addition or increase; provided, that
Points of Integration and Points of Delivery may not be added, and
Transmission Demands may not be increased, more frequently than
once during any 12-month period commencing on the anniversary of
the Effective Date.
(b) Transmission Demand associated with the John Day Substation Point
of Integration may be increased upon prior written notice from the
Company to Bonneville, to the extent that Bonneville has capacity
in excess of its needs and obligations at such time, in an amount
equal to an increase in the megawatt amount of the Company's
Capacity Ownership Rights under the PNW AC Intertie Capacity
Ownership Agreement in a south-to-north direction.
(c) Points of Integration and Points of Delivery may be deleted and
Transmission Demands may be reduced only upon the written request
of the Company and, upon such request, only in accordance with the
provisions of sections 10(c)(1) through 10(c)(5).
(1) Except as otherwise provided in this section 10(c),
Transmission Demands with respect to any individual Point of
Integration may be reduced once (but no more frequently than
once) in any 12-month period commencing on the anniversary of
the Effective Date for any Point of Integration, it being
understood that any such reduction shall be subject to section
10(c)(4) and shall be permitted pursuant to this Agreement
only:
18
(A) to the extent that the Company's right to receive any
Resource set forth in Exhibit C, Part A, as being
integrated at such Point of Integration (or right to
Connecting Transmission for such Resource) is reduced or
is eliminated or expires; or
(B) to the extent that the Company sells or assigns all or a
portion of its share of a Resource integrated at such
Point of Integration (or sells or assigns all or a
portion of the Company's right to Connecting Transmission
for such Resource); or
(C) to the extent of a permanent partial or total reduction
in the Company's entitlement to a share of a Resource
integrated at such Point of Integration (or partial or
total reduction of the Company's right to Connecting
Transmission for such Resource); or
(D) to the extent of any loss, destruction, abandonment, or
sale of any of the facilities generating or transmitting
a Resource integrated at such Point of Integration (or
loss, destruction, abandonment, or sale of the Connecting
Transmission for such Resource); or
(E) to the extent of the discontinuation of operation of any
of the facilities generating or transmitting a Resource
integrated at such Point of Integration (or
discontinuation of the Connecting Transmission for such
Resource) pursuant to a final order of a public official
having authority to issue such order; or
(F) with respect to the Garrison Substation Point of
Integration, to the extent of the expiration of the
Montana Intertie Agreement, including extensions thereof.
(2) A Point of Integration may be deleted, upon 3-months' prior
written notice by the Company of such deletion to Bonneville,
but only after the Transmission Demand with respect to such
Point of Integration has been reduced to zero pursuant to
sections 10(c)(1) and 10(c)(5).
19
(3) A Point of Delivery may be deleted, subject to mutual
agreement of the Parties and to section 10(c)(4), upon 3-
months' prior written notice by the Company of such deletion
to Bonneville.
(4) If, and to the extent that, any Use-of-Facilities charges are
added to this Agreement pursuant to section 9(c), the terms
and conditions related to such Use-of-Facilities charges shall
be subject to the mutual written agreement of the Parties
prior to the addition of such charges.
(5) The Company shall provide Bonneville no less than 3-
years' written notice of any decrease in a Transmission
Demand, except as follows:
(A) The Company shall provide no less than 3-months' written
notice of a decrease in Transmission Demand if there is
an equal increase in Transmission Demand by another
customer of Bonneville at the same Point of Integration
resulting from the sale or assignment of a Resource, or
of the facilities generating or transmitting a Resource,
and involving no loss of revenue to Bonneville; or
(B) The Company shall provide written notice as soon as
practicable, which would be effective on the later of the
date such notice is received by Bonneville or the date
stated in such notice, if such decrease in Transmission
Demand is due to any loss, destruction, or abandonment of
any of the facilities generating or transmitting a
Resource, or discontinuation of operation of a Resource
under a final order of a public official having authority
to issue such order, or if the Company's right to receive
Electric Power is reduced or eliminated according to the
terms of an agreement between the Company and another
entity for such Electric Power.
(6) Notwithstanding anything in this Agreement to the contrary, if
the megawatt amount of the capability of the PNW AC Intertie
to which the Company is entitled pursuant to the Capacity
Ownership Agreement is at any time reduced, Transmission
Demand with respect
20
to the John Day Substation Point of Integration shall be
concurrently reduced by a megawatt amount equal to such
reduction with respect to the PNW AC Intertie upon prior
written notice of such reduction by the Company to Bonneville.
(d) Projected Company loads at each Point of Delivery shall be
prepared, projected for 10 years, and forwarded to Bonneville by
October 1, of each year. If, based on long-range power flow studies
and actual system loadings, such projected loads are expected to
exceed the Use Limits with respect to such Point of Delivery within
the projected years, within a reasonable planning horizon for the
facilities involved, the Company and Bonneville shall enter into
joint discussions to:
(1) discuss how the Company plans to modify the load on Bonneville
at such Point of Delivery to stay within the Use Limit;
(2) discuss the Company's plan for facility additions, revisions,
or upgrades, which will increase capacity at such Point of
Delivery;
(3) discuss Bonneville's plan for facility additions, revisions,
or upgrades, which will increase capacity at such Point of
Delivery; or
(4) discuss the extent to which the capacity of facilities with
respect to such Point of Delivery would be available so as to
increase the Use Limit with respect to such Point of Delivery.
Prior to the implementation of any facility addition, revision or
upgrade that increases capacity at a Point of Delivery as
contemplated by this section 10(d), the Parties shall negotiate the
allocation of costs for such facility addition, revision or
upgrade, and the allocation of any increase in capacity at such
Point of Delivery, each such allocation to be pursuant to then-
existing FERC policies applicable to Bonneville and the Company,
respectively, as such policies apply to cost and capacity
allocations, and also subject to any other applicable statutory and
regulatory requirements. The Company shall be assessed costs for
studies conducted by Bonneville in connection with this section
10(d) consistent with the manner in which
21
Bonneville assesses study costs to other Bonneville customers who
receive transmission service pursuant to the Integration of
Resources (IR) Transmission Rate Schedule, or its successor rate
schedule; provided that, in any event, the costs of any such study
conducted by Bonneville in connection with this section 10(d) shall
be equitably allocated among the Company, Bonneville and
Bonneville's other customers based upon the respective system
benefits derived by such parties as a result of such facility
addition, revision or upgrade.
To the extent that other entities may receive system benefits from
such facility addition, revision or upgrade, Bonneville shall
invite such entities to participate in discussions with respect to
cost allocation and system benefits referred to in this section
10(d).
(e) When changes are made pursuant to this section, Bonneville shall
incorporate such changes in a new Exhibit C as soon as practicable.
11. SPECIAL PROVISIONS
(a) In recognition of the Company's existing agreement with Seattle
City Light (Seattle) to wheel Electric Power from the Centralia
Project, and notwithstanding anything in this Agreement to the
contrary, the Company may reduce the Transmission Demand with
respect to the C.W. Paul Substation Point of Integration no more
frequently than once in any 12-month period commencing on the
anniversary of the Effective Date to the extent of any reduction in
the amount of Electric Power that the Company is obligated pursuant
to such agreement to wheel from the Centralia Project to Seattle.
The Company shall provide 3-months' written notice to Bonneville of
any decrease in such Transmission Demand pursuant to this
subsection.
(b) If the Company contracts hereafter with another entity, including
Seattle, to transmit Electric Power over the Company's Tono
Transmission facilities the Transmission Demand with respect to the
C.W. Paul Point of Integration shall be increased in an amount
equal to the amount transmitted by the Company for such other
entity.
22
12. MISCELLANEOUS
(a) Any notice, demand, request or other communication
provided for in this Agreement, or served, given or made in
connection with this Agreement, shall be given in writing (unless
otherwise provided in this Agreement) and shall be deemed to be
served, given or made upon receipt if delivered in person or sent
by acknowledged delivery, or sent by registered or certified mail,
postage prepaid, to the persons addressed as set forth below:
If to Bonneville:
The Bonneville Power Administration
905 N.E. llth Avenue
Portland, Oregon 97232
Attention: Group Vice President for Marketing, Conservation
and Production
If to Puget:
Puget Sound Power & Light Company
411 108th Avenue N.E.
15th Floor
Bellevue, Washington 98005-5515
Attention: Vice President Power Planning
Either Party may change the address set forth above by giving the
other Party written notice of such change in accordance with this
section 12(a).
(b) Except as may be expressly otherwise provided in this Agreement,
this Agreement may be amended or modified only by a written
agreement hereafter entered into by Bonneville and Puget, and no
provision of this Agreement shall be varied or contradicted by any
oral agreement, any course of dealing or performance or any other
matter not hereafter set forth in a written agreement signed by
both of the Parties.
(c) The invalidity or unenforceability of any provision of this
Agreement shall not affect the other provisions hereof, and this
Agreement shall be construed in all respects as if such invalid or
unenforceable provision were omitted.
23
(d) Nothing contained in this Agreement shall be construed to create an
agency, association, joint venture, trust or partnership covenant,
obligation or liability on or with regard to either of the Parties.
Each Party shall be individually responsible for its own covenants,
obligations and liabilities under this Agreement. All rights and
obligations of the Parties are several, not joint. No Party shall
be deemed to control, to be under the control of, or to be the
agent of, the other Party.
(e) Nothing contained in this Agreement shall grant any rights to, or
obligate either Party to provide, any services hereunder directly
to or for retail customers of the other Party.
(f) There are no third-party beneficiaries of this Agreement. This
Agreement shall not be construed to create rights in, or grant
remedies to, any third party as a beneficiary of this Agreement or
of any duty, obligation or undertaking established herein.
(g) Whenever it is provided in this Agreement that either Party shall
determine or make a determination or judgment, or that any action,
determination or judgment shall be in such Party's determination or
judgment, the exercise of such determination or judgment shall be
made solely by such Party and shall be final and not subject to
challenge, so long as such Party exercises its
24
determination or judgment (a) in good faith and not arbitrarily or
capriciously, and (b) consistent with Prudent Utility Practice.
IN WITNESS WHEREOF, the Parties hereto have executed this Agreeemnt in
several counterparts.
UNITED STATES OF AMERICA
Department of Energy
Bonneville Power Administration
By Patrick McRae
------------------------
Senior Account Executive
Name Patrick McRae
------------------------
Date 12/1/94
------------------------
PUGET SOUND POWER & LIGHT COMPANY
By J. R. Lauckhart
-----------------------
Name J. R. Lauckhart
-----------------------
Title V. P. Power Planning
-----------------------
Date 12/1/94
-----------------------
25
EXHIBIT 10.115
Exhibit A
1993
TRANSMISSION RATE SCHEDULES AND
. . GENERAL TRANSMISSION RATE SCHEDULE PROVISIONS
TRANSMISSION RATE SCHEDULES AND GENERAL TRANSMISSION RATE
SCHEDULE PROVISIONS
TABLE OF CONTENTS
Transmission Rate Schedules Page
FPT-93.1 Formula Power Transmission................................1
FPT-91.3 Formula Power Transmission................................3
IR-93 Integration of Resources..................................5
IS-93 Southern Intertie Transmission............................6
IN-93 Northern Intertie Transmission............................7
IE-93 Eastern Intertie Transmission.............................8
ET-93 Energy Transmission.......................................9
MT-91 Market Transmission......................................10
UFT-83 Use-of-Facilides Transmission............................11
TGT-1 Townsend-Garrison Transmission...........................12
AC-93 Southern Intertie Annual Cost............................14
General Transmission Rate Schedule Provisions
Section I Adoption of Revised Transmission Rate Schedules and
General Transmission Rate Schedule Provisions............16
Section II Billing Factor Definitions and Billing Adjustments.......16
Section III Other Definitions........................................17
Section IV Billing Information......................................19
Schedule FPT-93.1
Formula Power Transmission
SECTION l. AVAILABILITY
This schedule supersedes schedule FPT-91.1 for all firm transmission
agreements which provide that rates may be adjusted not more frequently than
once a year. It is available for firm transmission of electric power and
energy using the Main Grid and/or Secondary System of the Federal Columbia
River Transmission System (FCRTS). This schedule is for full-year and
partial-year service and for either continuous or intermittent service when
firm availability of service is required. For facilities at voltages lower
than the Secondary System, a different rate schedule may be specified.
Service under this schedule is subject to BPA's General Transmission Rate
Schedule Provisions (GTRSPs).
SECTION 11. RATES
A. Full-Year Service
The monthly charge per kilowatt of billing demand shall be one-twelfth of
the sum of the Main Grid Charge and the Secondary System Charge, as
applicable and as specified in the Agreement.
1. Main Grid Charge
The Main Grid Charge per kilowatt of billing demand shall be the sum
of one or more of the following component factors as specified in the
Agreement:
a. Main Grid Distance Factor: amount computed by multiplying the
Main Grid Distance by $0.0371 per mile.
b. MainGrid Interconnection Terminal Factor: $0.27
c. Main Grid Terminal Factor: $0.44
d. Main Grid Miscellaneous Facilities Factor: $1.88
2. Secondary System Charge
The Secondary System Charge per kilowatt of billing demand shall the
the sum of one or more of the following component factors as
specified in the Agreement:
a. Secondary System Distance Factor: The amount determined by
multiplying the Secondary System Distance by $0.2784 per mile
b. Secondary System Transformation Factor: $4.10
c. Secondary System Intermediate Terminal Factor: $1.29
d. Secondary System Interconnection Terminal Factor: $0.68
B. Partial-Year Service
The monthly charge per kilowatt of billing demand shall be as specified
in Section II.A. for all months of the year except for agreements with
terms 5 years or less and which specify service for fewer than 12 months
per year. The monthly charge shall be:
1. During months for which service is specified, the monthly charge
defined in Section II.A., and
2. During other months, the monthly charge defined in Section II.A.
multiplied by 0.2.
SECTION III. BILLING FACTORS
Unless otherwise stated in the Agreement, the billing demand shall be the
largest of:
A. The Transmission Demand;
B. The highest hourly Scheduled Demand for the month; or
C. The Ratchet Demand
Schedule FPT-91.3
Formula Power Transmission
SECTION 1 AVAILABILITY
This schedule continues schedule FPT-91.3 for all firm transmission
agreements which provide that rates may he adjusted not more frequently than
once every 3 years. It is available for firm transmission of electric power
and energy using the Main Grid and/or Secondary System of the Federal
Columbia River Transmission System. This schedule is for full-year and
partial-year service and for either continuous or intermittent service when
firm availability of service is required. For facilities at voltages lower
than the Secondary System, a different rate schedule may be specified.
Service under this schedule is subject to BPA's General Transmission Rate
Schedule Provisions.
SECTION II. RATE
A. Full-Year Service
The monthly charge per kilowatt of billing demand shall be one-twelfth of
the sum of the Main Grid Charge and the Secondary System Charge, as
applicable and as specified in the Agreement.
1. The Main Grid Charge
The Main Grid Charge per kilowatt of billing demand shall be the sum
of one or more of the following component factors as specified in the
agreement.
a. Main Grid Distance Factor: The amount computed by multiplying
the Main Grid Distance by $0.0281 per mile
b. Main Grid Interconnection Terminal Factor: $0.27
c. Main Grid Terminal Factor: $0.30
d. Main Grid Miscellaneous Facilities Factor: $1.31
2. Secondary System Charge
The Secondary System Charge per kilowatt of billing demand shall be
the sum of one or more of the following component factors as
specified in the Agreement.
a. Secondary System Distance Factor: The amount determined by
multiplying the Secondary System Distance by $0.1961 per mile.
b. Secondary system Transformation Factor: $2.53
c. Secondary System Intermediate Terminal Factor: $0.84
d. Secondary System Interconnection Terminal Factor: $0.44
B. Partial-Year Service
The monthly charge per kilowatt of billing demand shall be as specified
in Section II.A. for all months of the year except for agreements with
terms 5 years or less and which specify service for fewer than 12 months
per year. The charge shall be:
1. during months for which service is specified, the monthly charge
defined in Section II.A., and
2. During other months, the monthly charge defined in Section II.A.
multiplied by 0.2.
SECTION III. BILLING FACTORS
Unless otherwise stated in the Agreement, the billing demand shall be the
largest of:
A. The Transmission Demand;
B. The highest hourly Scheduled Demand for the month; or
C. The Ratchet Demand
Schedule IR-93
Integration of Resources
SECTION 1. AVAILABILITY
Ths schedule supersedes IR-91 and is available for firm transmission service
for electric power and energy using the Main Grid and/or Secondary System of
the Federal Columbia River Transmission System. The definitions of Main Grid
and Secondary Systems are the same as for the FPT-93.1 and FPT-91.3 rate
schedules and are contained in the General Transmission Rate Schedule
Provisions (GTRSPs). For facilities at voltages lower than the Secondary
System, a different rate schedule may be specified. Service under this
schedule is subject to BPA's GTRSPS.
SECTION 11. RATE
The monthly charge shall be the sum of A and B where:
A. Demand Charge
1. $0.424 per kilowatt of billing demand; or
2. For Points of Integration (POI) specified in the Agreement as being
short distance POIs, for which Main Grid and Secondary System
facilities are used for a distance of less than 75 circuit miles, the
following formula applies:
[0.2 + (0.8/75 x transmission distance)]
($0.424 per kilowatt of billing demand)
Where:
the billing demand for a short distance POI is the demand level
specified in the Agreement for such POI, and the transmission
distance is the circuit miles between the POI for a generating
resource of the customer and a designated Point of Delivery serving
load of the customer. Short distance POIs are determined by BPA
after considering factors in addition to transmission distance.
B. Energy Charge
1.06 mills per kilowatthour of billing energy.
SECTION III. BILLING FACTORS
To the extent that the Agreement provides for the customer to be billed for
transmission in excess of the Transmission Demand or Total Transmission
Demand, as defined in the Agreement, at the nonfirm transmission rate
(currently ET-93), such transmission service shall not contribute to either
the Billing Demand or the Billing Energy for the IR rate provided that the
customer requests such treatment and BPA approves in accordance with the
prescribed provisions in the Agreement.
A. Billing Demand
The billing demand shall be the largest of:
1. The Transmission Demand, except under General Transmission Agreements
where a Total Transmission Demand is defined:
2. The highest hourly Scheduled Demand for the month; or
3. The Ratchet Demand.
B. Billing Energy
The billing energy shall be the monthly sum of scheduled kilowatthours.
SCHEDULE IS-93
SOUTHERN INTERTIE TRANSMISSION
SECTION I. AVAILABILITY
This schedule supersedes IS-91 and is available for all transmission on the
Southern Intertie. Service under this schedule is subject to BPA's General
Transmission Rate Schedule Provisions.
SECTION II. RATE
A. Nonfirm Transmission Rate
The charge for nonfirm transmission of non-BPA power shall be 3.11 mills
per kilowatthour of billing energy. This charge applies for both north-
to-south and south-to-north transactions.
B. Firm Transmission Rate
The charge for firm transmission service shall be $0.706 per kilowatt per
month of billing demand and 1.69 mills per kilowatthour of billing
energy. Firm transmission will only be made available to customers under
this rate schedule who have executed a contract with BPA specifying use
of the Firm Transmission rate for either north-to-south or south-to-north
transactions.
SECTION III. BILLING FACTORS
A. For services under Section II.A. the billing energy shall be the monthly
sum of the scheduled kilowatthours, plus the monthly sum of kilowatthours
allocated but not scheduled. The amount of allocated but not scheduled
energy that is subject to billing may be reduced pro rata by BPA due to
forced Intertie outages and other uncontrollable forces that may reduce
Intertie capacity. The amount of allocated but not scheduled energy that
is subject to billing also may be reduced upon mutual agreement between
BPA and the customer.
B. For services under Section II.B. the billing demand shall be the
Transmission Demand as defined in the Agreement. The billing energy
shall be the monthly sum of scheduled kilowatthours, unless otherwise
specified in the Agreement.
Schedule IN-93
NORTHERN INTERTIE TRANSMISSION
SECTION I. AVAILABILITY
This schedule supersedes IN-91 and is available for all transmission on the
Northern Intertie pursuant to an Agreement. Service under this schedule is
subject to BPA's General Transmission Rate Schedule Provisions.
SECTION II. RATE
The charge for transmission of non-BPA power on the Northern Intertie shall
be 0.86 mills per kilowatthour.
SECTION III. BILLING FACTORS
Billing Energy
The billing energy shall be the monthly sum of the scheduled kilowatthours.
Schedule IE-93
EASTERN INTERTIE TRANSMISSION
SECTION 1. AVAILABILITY
This schedule supersedes IE-91 and is available for all nonfirm transmission
on the Eastern lntertie. Service under this schedule is subject to BPA's
General Transmission Rate Schedule Provisions.
SECTION 11. RATE
The charge for nonfirm transmission on the Eastern Intertie shall be 2.04
mills per kilowatthour.
SECTION III. BILLING FACTORS
Billing Energy
The billing energy shall be the monthly sum of the scheduled kilowatthours.
Schedule ET-93
ENERGY TRANSMISSION
Section I. Availability
This schedule supersedes ET-91, unless otherwise specified in the Agreement,
with respect to delivery using Federal Columbia River Transmission System
facilities other than the Southern Intertie, Eastern Intertie, or the
Northern Intertie, and is available for firm (of not more than 1 year
duration) or nonfirm transmission between points within the Pacific
Northwest. BPA may interrupt nonfirm service which is provided under this
rate schedule. Service under this schedule is subject to BPA's General
Transmission Rate Schedule Provisions.
SECTION II. Rate
The charge for transmission of non-BPA power shall be 2.02 mills per
kilowatthour.
SECTION III. BILLING FACTORS
Billing Energy
The billing energy shall be the monthly sum of scheduled kilowatthours.
Schedule MT-91
MARKET TRANSMISSION
SECTION I. AVAILABILITY
This schedule supersedes MT-89 and is available for Transmission Service for
transactions using Federal Columbia River Transmission System facilities
pursuant to the Western Systems Power Pool (WSPP) Agreement. General
Transmission Rate Schedule Provisions.
SECTION II. RATE
The charge shall he determined in advance by BPA. The charge shall be based
on the duration of the proposed transaction and shall not exceed the
following rates.
A. Hourly Rate
The maximum charge shall be 6.5 mills per kilowatt hour where the total
hourly revenues from a given transaction during a calendar day shall not
exceed the product of the Daily rate and the maximum demand scheduled
during any such day.
B. Daily Rate
The maximum charge shall be $.105 per kilowattday where the total demand
charge revenues in any consecutive 7-day period shall not exceed the
product of the Weekly rate and the highest demand experienced on any day
in the 7-day period.
C. Weekly Rate
The maximum charge shall be $.52 per kilowattweek.
D. Monthly Rate.
The maximum charge shall be $2.27 per kilowattmonth.
SECTION III. BILLING FACTORS
The billing factors shall be specified in advance by BPA, as to representing
the Transmission Service use or reservation.
Schedule UFT-83
USE-OF-FACILITIES TRANSMISSION
SECTION I. AVAILABILITY
This schedule supersedes UFT-1 and UFT-2 unless otherwise provided in the
Agreement, and is available for firm transmission over specified Federal
Columbia River Transmssion system facilities. Service under this schedule is
subject to BPA's General Transmission Rate Schedule Provisions.
SECTION II. RATE
The monthly charge per kilowatt of Transmission Demand specified in the
Agreement shall be one-twelfth of the annual cost of capacity of the
specified facilities divided by the sum of Transmission Demands (in
kilowatts) using such facilities. Such annual cost shall be determined in
accordance with Section III.
SECTION III. DETERMINATION OF TRANSMISSION RATE
A. From time to time, but not more often than once in each Contract Year,
BPA shall determine the following data for the facilities which have been
constructed or otherwise acquired by BPA and which are used to transmit
electric power:
1. The annual cost of the specified FCRTS facilities, as determined from
the capital cost of such facilities and annual cost ratios developed
from the Federal Columbia River Power System financial statement,
including interest and amortization, operation and maintenance,
administrative and general, and general plant costs.
2. The yearly noncoincident peak demands of all users of such facilities
or other reasonable measurement of the facilities' peak use.
B. the monthly charge per kilowatt of billing demand shall be one-twelfth of
the sum of the annual cost of the FCRTS facilites used divided by the sum
of Transmission Demands. The annual cost per kilowatt of Transmission
Demand for a facility constructed or otherwise acquired by BPA shall be
determined in accordance with the following formula:
A
-
D
Where:
A = The annual cost of such facility as determined in accordance with
A.1. above.
D = The sum of the yearly noncoincident demands on the facility as
determined in accordance with A.2. above.
The annual cost per kilowatt of facilities listed in the Agreement which are
owned by another entity, and used by BPA for making deliveries to the
transferee, shall be determined from the costs specified in the Agreement
between BPA and such other entity.
SECTION IV. DETERMINATION OF BILLING DEMAND
Unless otherwise stated in the Agreement, the factor to be used in
determining the kilowatts of billing demand shall be the largest of:
A. The Transmission Demand in kilowatts specified in the Agreement;
B. The highest hourly Measured or Scheduled Demand for the month, the
Measured Demand being adjusted for power factor; or
C. The Ratchet Demand.
Schedule TGT-1
TOWNSEND-GARRISON TRANSMISSION
SECTION I. AVAILABILITY
This schedule shall apply to all agreements which provide for the firm
transmission of electric power and energy over transmission facilities of
BPA's section of the Montana [Eastern] Intertie. Service under this schedule
is subject to BPA's General Transmission Rate Schedule Provisions.
SECTION II. RATE
The monthly charge shall be one-twelfth of the sum of the annual charges
listed below, as applicable and as specified in the agreements for firm
transmission. The Townsend-Garrison 500-kV lines and associated terminal,
line compensation, and communication facilities are a separately identified
portion of the Federal Transmission System. Annual revenues plus credits for
government use should equal annual costs of the facilities, but in any given
year there may be either a surplus or a deficit. Such surpluses or deficits
for any year shall be accounted for in the computation of annual costs for
succeeding years. Revenue requirements for firm transmission use will be
decreased by any revenues received from nonfirm use and credits for all
government use. The general methodology for determining the firm rate is to
divide the revenue requirement by the total firm capacity requirements.
Therefore, the higher the total capacity requirements, the lower will be the
unit rate.
If the government provides firm transmission service in its section of the
Montana [Eastern] Intertie in exchange for firm transmission service in a
customer's section of the Montana Intertie, the payment by the government for
such transmission services provided by such customer will be made in the form
of a credit in the calculation of the Intertie Charge for such customer.
During an estimated 1- to 3-year period following the commercial operation of
the third generating unit at the Colstrip Thermal Generating Plant at
Colstrip, Montana, the capability of the Federal Transmission System west of
Garrison Substation may be different from the long-term situation. It may
not be possible to complete the extension of the 500-kV portion of the
Federal Transmission System to Garrison by such commercial operation date.
In such event, the 500/230 kV transformer will be an essential extension of
the Townsend-Garrison Intertie facilities, and the annual costs of such
transformer will be included in the calculation of the Intertie Charge.
However, starting 1 month after extension to Garrison of the 500-kV portion
of the Federal Transmission System, the annual costs of such transformer will
no longer be included in the calculation of the Intertie Charge.
A. Nonfirm Transmission Charge:
This charge will be filed as a separate rate schedule and revenues
received thereunder will reduce the amount of revenue to be collected
under the Intertie Charge below.
B. Intertie Charge for Firm Transmission Service:
Intertie Charge =
(CR-EC)
[((TAC/12)-NFR) x -------]
TCR
SECTION III. DEFINITIONS
A. TAC = Total Annual Costs of facilities associated with the Townsend-
Garrison 500-kV Transmission line including terminals, and prior to
extension of the 500-kV portion of the Federal Transmission System to
Garrison, the 500/230 kV transformer at Garrison. Such annual costs are
the total of: (1) interest and amortization of associated Federal
investment and the appropriate allocation of general plant costs; (2)
operation and maintenance costs; (3) allowance for BPA's general
administrative costs which are appropriately allocable to such
facilities, and (4) payments made pursuant to section 7(m) of Public Law
96-501 with respect to these facilities. Total Annual Costs shall be
adjusted to reflect reductions to unpaid total costs as a result of any
amounts received, under agreements for firm transmission service over the
Montana Intertie, by the government on account of any reduction in
Transmission Demand, termination or partial termination of any such
agreement or otherwise to compensate BPA for the unamortized investment,
annual cost, removal, salvage, or other cost related to such facilities.
B. NFR = Nonfirm Revenues, which are equal to: (1) the product of the
Nonfirm Transmission Charge described in II(A) above, and the total
nonfirm energy transmitted over the Townsend-Garrison line segment under
such charge for such month; plus (2) the product of the Nonfirm
Transmission Charge and the total nonfirm energy transmitted in either
direction by the Government over the Townsend-Garrison line segment for
such month.
C. CR = Capacity Requirement of a customer on the Townsend-Garrison 500-kV
transmission facilities as specified in its firm transmission agreement.
D. TCR = Total Capacity Requirement on the Townsend-Garrison 500-kV
transmission facilities as calculated by adding (1) the sum of all
Capacity Requirements (CR) specified in all transmission agreements
described in section I; and (2) the Government's firm capacity
requirement. The Government's firm capacity requirement shall be no less
than the total of the amounts, if any, specified in firm transmission
agreements for use of the Montana Intertie.
E. EC = Exchange Credit for each customer which is the product of: (1) the
ratio of investment in the Townsend-Broadview 500-kV transmission line to
the investment in the Townsend-Garrison 500-kV transmission line; and (2)
the capacity which the Government obtains in the Townsend-Broadview 500-
kV transmission line through exchange with such customer. If no exchange
is in effect with a customer, the value of EC for such customer shall be
zero.
Schedule AC-93
Southern Intertie Annual Cost
SECTION I. AVAILABILITY
This schedule is applicable to all parties (New Owners) that execute PNW AC
Intertie Capacity Ownership Agreements (Agreements) and will be effective on
the date described in the Agreement. Service under this schedule is subject
to BPA's General Transmission Rate Schedule Provisions.
SECTION II. RATE
The rate charges reflect the terms of the Memorandum of Understanding (MOU),
signed in the fall of 1991, between BPA and potential New owners. The MOU
provides for the payment by New Owners of their prorated share of: (1) BPA's
annual operations, maintenance and general plant expense (including
applicable overheads) properly chargeable to the AC Intertie facilities; and
(2) BPA's share of capitalized replacements on the AC Intertie. The monthly
charge shall be the sum of the charges specified in sections II.A. and II.B.
A. Operations, Maintenance, and General Plant
The monthly charge shall equal $325 per megawatt of billing demand.
B. Replacements
The monthly charge shall equal $0 per megawatt of billing demand.
SECTION III. ADJUSTMENT TO REPLACEMENTS RATE
A. Determination of Billing Adjustment
New Owners will receive a billing adjustment if BPA incurs AC Intertie
replacement cost during the rate period. The Replacements Rate
Adjustment equals
AC Intertie work orders ($000) * %
----------------------------------
725 MW * # months
where:
"# months" equals: (1) the number of months that this
rate schedule is in effect during the fiscal year for
the Initial Replacements Rate Adjustment; or (2) the
number of months in the rate period for the Final
Replacements Rate Adjustment; and
"%" equals the New Owners' percentage share of BPA's
total AC Intertie Rated Transfer Capability as specified
in the Agreements.
B. Initial Replacements Rate Adjustment
New Owners will receive a billing adjustment for each fiscal year that
BPA incurs AC Intertie replacement cost. At the end of each fiscal year,
the cost associated with AC Intertie capital replacement work orders that
have closed during the fiscal year will be determined. The unit rate
that would result using these closed work orders is the basis of the
Initial Replacements Rate Adjustment.
1. Notice Provisions
Following each fiscal year, BPA shall notify all New Owners by
December 15, of the proposed Replacements Rate Adjustment. BPA will
provide the calculation of the adjustment and a short description of
the work performed and the associated cost used as the basis for the
billing adjustment. In addition to written notification, BPA may,
but is not obligated to, hold a public meeting to clarify its
determinations.
Written comments on the Initial Replacements Rate Adjustment will be
accepted through the end of January. Consideration of comments
submitted by the New Owners may result in the billing adjustment
differing from the initially proposed adjustment. BPA shall notify
all New Owners of the Initial Replacements Rate Adjustment by the
last day of February.
2. Adjustment of Monthly Bills
An adjustment will be made on the New Owner's monthly bill prepared
during March. The Initial Replacements Rate adjustment will be
multiplied by the sum of the monthly billing factors from the
relevant fiscal year (i.e., the New Owner's share in megawatts of
BPA's PNW AC Intertie Rated Transfer Capability multiplied by the
numbers of months that this rate schedule is effective during the
fiscal year). The Initial Replacements Rate Adjustment will appear
as a charge to the New Owner on the monthly bill prepared during
March.
C. Final Replacements Rate Adjustment
The actual costs associated with the AC Intertie capital replacement work
orders that occur during the rate period may change after BPA performs
its final analysis of the work orders. BPA shall compare the unit rate
for the rate period using the results of the final work order analysis to
the weighted average of the unit rates from the Initial Replacements Rate
Adjustments.
1. Notice Provisions
BPA shall notify all New Owners in May 1998 of the results of the
calculations, an explanation of work order changes(s), and any
resulting billing adjustment. Written comments from New Owners will
be accepted through the end of June. BPA shall notify all New Owners
of the Final Replacements Rate Adjustment by July 31. Consideration
of comments submitted by the New Owners may result in the Final
Replacements Rate Adjustment differing from the initially proposed
adjustment.
2. Adjustment of Monthly Bills
If the absolute value of the Final Replacements Rate Adjustment is
greater than or equal to $1 per megawatt per month, an adjustment
will be made on the New Owner's monthly bill prepared during August.
For each New Owner, the Final Replacements Rate Adjustment will be
multiplied by the sum of the monthly billing factors from the
relevant fiscal years (i.e., the New Owner's share in megawatts of
BPA's PNW AC Intertie Rated Transfer Capability multiplied by the
number of months that this rate schedule is effective during the
fiscal years). The Final Replacements Rate Adjustment will appear as
a charge or credit to the New Owner on the monthly bill prepared
during August. Interest, as determined by BPA's Office of Financial
Management, will be included in any adjustment.
SECTION IV. BILLING FACTOR
The billing demand shall be the New Owner's capacity ownership share in
megawatts of BPA's PNW AC Intertie Rated Transfer Capability as specified in
the Agreement.
General Transmission Rate Schedule Provisions
SECTION I. ADOPTION OF REVISED TRANSMISSION RATE SCHEDULES AND GENERAL
TRANSMISSION RATE SCHEDULE PROVISIONS (GTRSPs)
A. Approval of Rates
These rate schedules and GTRSPs shall become effective upon interim
approval or upon final confirmation and approval by FERC. BPA will
request FERC approval effective October 1, 1993.
B. General Provisions
These 1993 Transmission Rate Schedules and associated GTRSPs are
virtually identical to and supersede BPA's 1991 Transmission Rate
schedules and GTRSPs (which became effective October 1, 1991) but do not
supersede prior rate schedules required by agreement to remain in force.
Transmission service provided shall be subject to the following Acts, as
amended: the Bonneville Project Act, the Regional Preference Act (P.L.
88-552), the Federal Columbia River Transmission System Act, and the
Pacific Northwest Electric Power Planning and Conservation Act, and the
Energy Policy Act of 1992, Pub. L. 102-486, 106 Stat. 2776 (1992).
The meaning of terms used in the transmission rate schedules shall be as
defined in agreements or provisions which are attached to the Agreement
or as in any of the above Acts.
C. Interpretation
If a provision in the executed Agreement is in conflict with a provision
contained herein, the former shall prevail.
SECTION II. BILLING FACTOR DEFINITIONS AND BILLING ADJUSTMENTS
A. Billing Factors
1. Scheduled Demand
The largest of hourly amounts wheeled which are scheduled by the
customer during the time period specified in the rate schedules.
2. Metered Demand
The Metered Demand in kilowatts shall be the largest of the 60-minute
clock-hour integrated demands measured by meters installed at each
POD during each time period specified in the applicable rate
schedule. Such measurements shall be made as specified in the
Agreement. BPA, in determining the Metered Demand, will exclude any
abnormal readings due to or resulting from: (a) emergencies or
breakdowns on, or maintenance of, the FCRTS; or (b) emergencies on
the customer's facilities, provided that such facilities have been
adequately maintained and prudently operated as determined by BPA.
If more than one class of power is delivered to any POD, the portion
of the metered quantities assigned to any class of power shall be as
agreed to by the parties. The amount so assigned shall constitute
the Metered Demand for such class of power.
3. Transmission Demand
The demand as defined in the Agreement.
4. Total Transmission Demand
The sum of the transmission demands as defined in the Agreement.
5. Ratchet Demand
The maximum demand established during the previous 11 billing months.
Exception: if a Transmission Demand or Total Transmission Demand has
been decreased pursuant to the terms of the Agreement during the
previous 11 billing months, such decrease will be reflected in
determining the Ratchet Demand.
B. Billing Adjustments
Average Power Factor
The adjustment for average power factor, when specified in a transmission
rate schedule or in the Agreement, shall be made in accordance with the
average power factor section of the General Wheeling Provisions.
To maintain acceptable operating conditions on the Federal system, BPA
may restrict deliveries of power at any time that the average leading
power factor or average lagging power factor for all classes of power
delivered to such point or to such system is below 85 percent.
SECTION III. OTHER DEFINITIONS
Definitions of the terms below shall be applied to these provisions and the
Transmission Rate Schedules, unless otherwise defined in the Agreement.
A. Agreement
An agreement between BPA and a customer to which these rate schedules and
provisions may be applied.
B. Eastern Intertie
The segment of the FCRTS for which the transmission facilities consist of
the Townsend-Garrison double-circuit 500 kV transmission line segment
including related terminals at Garrison
C. Electric Power
Electric peaking capacity (kW) and/or electric energy (kWh).
D. Federal Columbia River Transmission System
The transmission facilities of the Federal Columbia River Power System,
which include all transmission facilities owned by the government and
operated by BPA, and other facilities over which BPA has obtained
transmission rights.
E. Firm Transmission Service
Transmission service which BPA provides for any non-BPA power except for
transmission service which is scheduled as nonfirm. If the firm service
is provided pursuant to the Agreement, the terms of the Agreement may
further define the service.
F. Integrated Network
The segment of the FCRTS for which the transmission facilities provide
the bulk of transmission of electric power within the Pacific Northwest,
excluding facilities not segmented to the network as shown in the
Wholesale Power Rate Development Study used in BPA's rate development.
G. Main Grid
As used in the FPT and IR rate schedules, that portion of the Integrated
Network with facilities rated 230 kV and higher.
H. Main Grid Distance
As used in the FPT rate schedules, the distance in airline miles on the
Main Grid between the POI and the POD, multiplied by 1.15.
I. Main Grid Interconnection Terminal
As used in the FPT rate schedules, Main Grid terminal facilities that
interconnect the FCRTS with non-BPA facilities.
J. Main Grid Miscellaneous Facilities
As used in the FPT rate schedules, switching, transformation, and other
facilities of the Main Grid not included in other components.
K. Main Grid Terminal
As used in the FPT rate schedules, the Main Grid terminal facilities
located at the sending and/or receiving end of a line exclusive of the
Interconnection terminals.
L. Nonfirm Transmission Service
Interruptible transmission service which BPA may provide for non-BPA
power.
M. Northern Intertie
The segment of the FCRTS for which the transmission facilities consist of
two 500 kV lines between Custer Substation and the United States-Canadian
border, one 500 kV line between Custer and Monroe Substations, and two
230 kV lines from Boundary Substation to the United States-Canadian
border, and the associated substation facilities.
N. Point of Integration (POI)
Connection points between the FCRTS and non-BPA facilities where non-
Federal power is made available to BPA for wheeling.
O. Point of Delivery (POD)
Connection points between the FCRTS and non-BPA facilities where non-
Federal power is delivered to a customer by BPA.
P. Secondary System
As used in the FPT and IR rate schedules that portion of the Integrated
Network facilities with operating voltage of 115 kV or 69 kV.
Q. Secondary System Distance
As used in the FPT rate schedules, the number of circuit miles of
Secondary System transmission lines between the secondary POI and the
Main Grid or the secondary POD, or the Main Grid and the secondary POD.
R. Secondary System Interconnection Terminal
As used in the FPT rate schedules, the terminal facilities on the
Secondary System that interconnect the FCRTS with non-BPA facilities.
S. Secondary System Intermediate Terminal
As used in the FPT rate schedules, the first and final terminal
facilities in the Secondary System transmission path exclusive of the
Secondary System Interconnection terminals.
T. Secondary Transformation
As used in the FPT rate schedules, transformation from Main Grid to
Secondary System facilities.
U. Southern Intertie
The segment of the FCRTS for which the major transmission facilities
consist of two 500 kV AC lines from John Day Substation to the Oregon-
California border, a portion of the 500 kV AC line from Buckley
Substation to Summer Lake Substation; when completed, the Third AC
facilities which include Captain Jack Substation and the Alvey-Meridian
500 kV AC line; one 1,000 kV DC line between the Celilo Substation and
the Oregon-Nevada border, and associated substation facilities.
V. Transmission Service
As used in the MT rate schedule, Transmission Service is as defined in
the Western Systems Power Pool Agreement.
SECTION IV. BILLING INFORMATION
A. Payment of Bills
Bills for transmission service shall be rendered monthly by BPA. Failure
to receive a bill shall not release the customer from liability for
payment. Bills for amounts due of $50,000 or more must be paid by direct
wire transfer, customers who expect that their average monthly bill will
not exceed $50,000 and who expect special difficulties in meeting this
requirement may request, and BPA may approve, an exemption from this
requirement. Bills for amounts due BPA under $50,000 may be paid by
direct wire transfer or mailed to the Bonneville Power Administration,
P.O. Box 6040, Portland, Oregon 97228-6040, or to another location as
directed by BPA. The procedures to be following in making direct wire
transfers will be provided by the Office of Financial Management and
updated as necessary.
1. Computation of Bills
The transmission billing determinant is the electric power quantified
by the method specified in the Agreement or Transmission Rate
Schedule. Scheduled power or metered power will be used.
The transmission customer shall provide necessary information to BPA
for any computation required to determine the proper charges for use
of the FCRTS, and shall cooperate with BPA in the exchange of
additional information which may be reasonably useful for respective
operations.
Demand and energy billings for transmission service under each
applicable rate schedule shall be rounded to whole dollar amounts, by
eliminating any amount which is less than 50 cents and increasing any
amounts from 50 cents through 99 cents to the next higher dollar.
2. Estimated Bills
At its option, BPA may elect to render an estimated bill to be
followed at a subsequent billing date by a final bill. The estimated
bill shall have the validity of and be subject to the same payment
provisions as a final bill.
3. Billing Month
For charges based on scheduled quantities, the billing month is the
calendar month. For charges based on metered quantities, the billing
month is defined as the interval between scheduled meter-reading
dates. The billing month will not exceed 31 days in any case. While
it may be necessary to read meters on a day other than the scheduled
meter-reading date, for determination of billing demand, the billing
month will cease at 2400 hours on the last scheduled meter-reading
date. Schedules will be predetermined. The customer must give 30
days notice to request a change to the schedule.
4. Due Date
Bills shall be due by close of business on the 20th day after the
date of the bill (due date). should the 20th day be a Saturday,
Sunday, or holiday (as celebrated by the customer), the due date
shall be the next following business day.
5. Late Payment
Bills not paid in full on or before close of business on the due date
shall be subject to a penalty charge of $25. In addition, an
interest charge of one-twentieth percent (0.05 percent) shall be
applied each day to the sum of the unpaid amount and the penalty
charge. This interest charge shall be assessed on a daily basis
until such time as the unpaid amount and penalty charge are paid in
full.
Remittances received by mail will be accepted without assessment of
the charges referred to in the preceding paragraph provided the
postmark indicates the payment was mailed on or before the due date.
Whenever a power bill or a portion thereof remains unpaid subsequent
to the due date and after giving 30 days' advance notice in writing,
BPA may cancel the contract for service to the customer. However,
such cancellation shall not affect the customer's liability for any
charges accrued prior thereto under such agreement.
6. Disputed Billings
In the event of a disputed billing, full payment shall be rendered to
BPA and the disputed amount noted. Disputed amounts are subject to
the late payment provisions specified above. BPA shall separately
account for the disputed amount. If it is determined that the
customer is entitled to the disputed amount, BPA shall refund the
disputed amount with interest, as determined by BPA's Office of
Financial Management.
BPA retains the right to verify, in a manner satisfactory to the
Administrator, all data submitted to BPA for use in the calculation
of BPA's rates and corresponding rate adjustments. BPA also retains
the right to deny eligibility for any BPA rate or corresponding rate
adjustment until all submitted data have been accepted by BPA as
complete, accurate, and appropriate for the rate or adjustment under
consideration.
7. Revised Bills
As necessary, BPA may render a revised bill.
a. If the amount of the revised bill is less than or equal to the
amount of the original bill, the revised bill shall replace all
previous bills issued by BPA that pertain to the specified
customer for the specified billing period and the revised bill
shall have the same date as the replaced bill.
b. If a revision causes an additional amount to be due BPA or the
specified customer beyond the amount of the original bill, a
revised bill will be issued for the difference and the date of
the revised bill shall be its date of issue.
Exhibit B
GWP Form-4R (04-15-83)
GENERAL WHEELING PROVISIONS
---------------------------
Index to Sections
Section ----------------- Page
GENERAL APPLICATION
1. Interpretation.................................................. 2
2. Definitions..................................................... 2
3. Prior Demands................................................... 4
4. Measurements.................................................... 4
5. Measurements and Installation of Meters......................... 5
6. Tests of Metering Installations................................. 5
7 Adjustment for Inaccurate Metering.............................. 5
B. Character of Service............................................ 6
9. Point(s) of Delivery and Delivery Voltage....................... 6
10. Combining Deliveries Coincidentally............................. 6
11. Suspension of Deliveries........................................ 6
12. Continuity of Service........................................... 6
13. Uncontrollable Forces........................................... 7
14. Reducing Charges for Interruptions............................ 7
15. Net Billing..................................................... 7
16. Average Power Factor............................................ 7
17. Permits......................................................... 8
18. Ownership of Facilities......................................... 8
19. Adjustment for Change of Conditions............................. 8
20. Dispute Resolution and Arbitration.............................. 9
21. Contract Work Hours and Safety Standards........................ 10
22. Convict Labor................................................... 11
23. Equal Employment Opp6rtunity.................................... 11
24. Additional Provisions........................................... 12
25. Reports......................................................... 12
26. Assignment of Contract.......................................... 12
27. Waiver of Default............................................... 13
28. Notices and Computation of Time................................. 13
29. Interest of Member of Congress.................................. 13
APPLICABLE ONLY IF TRANSFEREE IS A PARTY TO THIS CONTRACT
30. Balancing Phase Demands......................................... 13
31. Adjustment for Unbalanced Phase Demands..13
32. Changes in Requirements or Characteristics...................... 13
33. Inspection of Facilities.........................................13
34. Electric Disturbances............................................14
35. Harmonic Control................................................ 15
APPLICABLE ONLY IF TRANSFEREE IS NOT A PARTY TO THIS CONTRACT
36. Protection of the Transferor.................................... 15
RELATING ONLY TO RURAL ELECTRIFICATION BORROWERS
37. Approval of Contract............................................ 15
APPLICABLE ONLY IF BONNEVILLE IS THE TRANSFEROR
38. Equitable Adjustment of Rates................................... 15
GENERAL APPLICATION
1. Interpretation.
(a) The provisions in this exhibit shall be deemed to be a part of the
contract body to which they are an exhibit. If a provision in such
contract body is in conflict with a provision contained herein, the
former shall prevail.
(b) If a provision in the General Transmission Rate Schedule Provisions
is in conflict with a provision in this exhibit or the contract
body, this exhibit or the contract body shall prevail.
(c) Nothing contained in this contract shall, in any manner, be
construed to abridge, limit, or deprive any party thereto of any
means of enforcing any remedy, either at law or in equity, for the
breach of any of the provisions thereof which it would otherwise
have.
2. Definitions. As used in this contract:
(a) "Contractor," "Utility" or "Borrower" means the party- to this
contract other than Bonneville.
(b) "Federal System" or "Federal System Facilities" means the
facilities of the Federal Columbia River Power System, which for
the purposes of this contract shall be deemed to include the
generating facilities of the Government in the Pacific Northwest
for which Bonneville is designated as marketing agent; the
facilities of the Government under the jurisdiction of Bonneville;
and any other facilities:
(1) from which Bonneville receives all or a portion of the
generating capability (other than station service) for use in
meeting Bonneville's loads, such facilities being included
only to the extent Bonneville has the right to receive such
capability; provided, however, that "Bonneville's loads" shall
not include that portion of the loads of any Bonneville
customer which are served by a nonfederal generating resource
purchased or owned directly by such customer which may be
scheduled by Bonneville;
(2) which Bonneville may use under contract, or license; or
(3) to the extent of the rights acquired by Bonneville pursuant to
the Treaty, between the Government and Canada, relating to the
cooperative development of water resources of the Columbia
River Basin, signed in Washington, D.C., on January 17, 1961.
(c) "Integrated Demand" means the number of kilowatts which is equal to
the number of kilowatt-hours delivered at any point during a clock
hour.
(d) "Measured Demand" means the maximum Integrated Demand for a billing
month determined from measurements made as specified in the
contract or as determined in section 4 hereof when metering or
other data are not available
2
for such purpose. Bonneville, in determining the Measured Demand,
will exclude any abnormal Integrated Demands due to, or resulting
from (a) emergencies or breakdowns on, or maintenance of, either
parties' facilities, and (b) emergencies on facilities of the
Transferee, provided that such facilities have been adequately
maintained and prudently operated as determined by Bonneville.
If the contract provides for delivery of more than one class of
power to a Transferee at any Point of Delivery, the portion of each
Integrated Demand assigned to any class of power shall be
determined as specified in the contract. The portion of the
Integrated Demand so assigned shall constitute the Measured Demand
for such class of power.
(e) "Month" means the period commencing at the time when the meters
mentioned in this contract are read by Bonneville and ending
approximately 30 days thereafter when a subsequent reading of such
meters is made by Bonneville.
(f) "Point(s) of Delivery" means the point(s) of delivery listed either
in the Points of Delivery Exhibit to this contract or in the body
of this contract.
(g) "System" or "Facilities" means the transmission facilities: (1)
which are owned or controlled by either party, or (2) which either
party may use under lease, easement, or license.
(h) "Transferee" means an entity which receives power or energy from
the system of the Transferor.
(i) "Transferor" means an entity which receives at one point on its
system a supplying entity's power or energy and makes such power or
energy available at another point an its system for the account of
the delivering entity or a third party.
(j) "Uncontrollable Forces" means:
(1) strikes or work stoppage affecting the operation of the
Contractor's works, system, or other physical facilities or of
the Federal System Facilities or the physical facilities of
any Transferee upon which such operation is completely
dependent; the term "strikes or work stoppage" shall be deemed
to include threats of imminent strikes or work stoppage which
reasonably require a party or Transferee to restrict or
terminate its operations to prevent substantial loss or damage
to its works, system, or other physical facilities; or
(2) such of the following events as the Contractor or Bonneville
or any Transferee by exercise of reasonable diligence and
foresight, could not reasonably have been expected to avoid:
(A) events, reasonably beyond the control of either party or
any Transferee, causing failure, damage, or destruction
of any works, system or facilities of such party or
Transferee; the word "failure"
3
shall be deemed to include interruption of, or
interference with, the actual operation of such works,
system, or facilities;
(B) floods or other conditions caused by nature which limit
or prevent the operation of, or which constitute an
imminent threat of damage to, any such works, system, or
facilities; and
(C) orders and temporary or permanent injunctions which
prevent operation, in whole or in part, of the works,
system, or facilities of either party or any Transferee,
and which are issued in any bona fide proceeding by:
i. any duly constituted court of general jurisdiction;
or
ii. any administrative agency or officer other than
Bonneville or its officers, provided by law (a) if
said party or Transferee has no right to a review of
the validity of such order by a court of competent
jurisdiction; or (b) if such order is operative and
effective unless suspended, set aside, or annulled
by a court of competent jurisdiction and such order
is not suspended, set aside, or annulled in a
judicial proceeding prosecuted by said party or
Transferee in good faith; provided, however, that if
such order is suspended, set aside, or annulled in
such a judicial proceeding, it shall be deemed to be
an "uncontrollable force" for the period during
which it is in effect; provided, further, that said
party or Transferee, shall not be required to
prosecute such a proceeding, in order to have the
benefits of this section, if the parties agree that
there is no valid basis for contesting the order.
The term "operation" as used in this subsection shall be
deemed to include construction, if construction is
required to implement the contract and is specified
therein.
3. Prior Demands.
(a) In determining any credit demand mentioned in, or money
compensation to be paid under this contract for any month,
Integrated Demands at which electric energy was delivered by the
Transferor at Points of Delivery mentioned herein for the account
of the other party to this contract prior to the date upon which
the contract takes effect shall be considered in the same manner as
if this contract had been in effect.
(b) If either party has delivered electric power and energy to the
other party at any Point of Delivery specified in this contract or
in any previous contract, and such Point of Delivery is superseded
by another Point of Delivery specified in this contract, the
Measured Demands, if any, at the superseded Point of Delivery shall
be considered for the purpose of determining the charges paid to
the Transferor for the electric power and energy delivered under
this contract at such superseded point.
4. Measurements. Except as it is otherwise provided in section 7, each
measurement of each meter mentioned in this contract shall be the
measurement
4
automatically recorded by such meter or, at the request of either party,
the measurement as mutually determined by the best available
information.
If it is provided in this contract that measurements made by any of the
meters specified therein are to be adjusted for losses, such adjustments
shall be made by using factors, or by compensating the meters, as agreed
upon by the parties hereto. If changes in conditions occur which
substantially affect any such loss factor or compensation, it will be
changed in a manner which will conform to such change in conditions.
5. Measurements and Installation of Meters. Bonneville may at any time
install a meter or metering equipment to make the measurements for any
Point of Delivery required for any computation or determination
mentioned in this contract, and if so installed, such measurements shall
be used thereafter in such computation or determination.
6. Tests of Metering Installations. Each party to this contract shall, at
its expense, test its metering installations associated with this
contract at least once every two years. and, if requested to do so by
the other party, shall make additional tests or inspections of such
installations, the expense of which shall be paid by such other party
unless such additional tests or inspections show the measurements of
such installations to be inaccurate as specified in section 7. Each
party shall give reasonable notice of the time when any such test or
inspection is to be made to the other party who may have representatives
present at such test or inspection. Any component of such
installations found to be defective or inaccurate shall be adjusted,
repaired or replaced to provide accurate metering.
7. Adjustment for Inaccurate Metering
(a) If any meter mentioned in this contract fails to register, or if
the measurement made by such meter during a test made as provided
in section 6 varies by more than one percent from the measurement
made by the standard meter used in such test, or if an error in
meter reading occurs, adjustment shall be made correcting all
measurements for the actual period during which such inaccurate
measurements were made, if such period can be determined. If such
period cannot be determined, the adjustment shall be made for the
period immediately preceding the test of such meter which is equal
to the lesser of (a) one-half the time from the date of the last
preceding test of such meter, or (b) six months. Such corrected
measurements shall be used to recompute the amounts of any electric
power and energy to be made available, or any credits to be made in
any exchange energy account, and of any money compensation to be
paid to the Transferor as provided in this contract.
(b) If the credit theretofore made to the Transferor in the exchange
energy account varies from the credit to be made as recomputed, the
amount of the variance will be credited in such exchange energy
account to the party entitled thereto.
(c) If the money compensation theretofore paid to the Transferor varies
from the money compensation to be paid as recomputed, the amount of
the variance will be paid to the party entitled thereto after both
parties have agreed to such recomputation and within 30 days after
receipt of invoice by the designated payment office of the payer
provided, however, that the other
5
party may deduct such amount due it from any money compensation
which thereafter becomes due the Transferor under this contract.
8. Character of Service. Unless otherwise specifically provided for in the
contract, electric power and energy made available pursuant to this
contract shall be in the form of three-phase current, alternating at a
nominal frequency of 60 hertz.
9. Point(s) of Delivery and Delivery Voltage. Electric power and energy
shall be delivered to each Transferee at such point or points and at
such voltage or voltages as are agreed upon by the parties hereto.
10. Combining Deliveries Coincidentally. If it is provided in this contract
that charges for electric power and energy made available at two or more
Points of Delivery will be made by combining deliveries at such points
coincidentally:
(a) the total Measured Demand to be considered in determining the
billing demand for each billing month shall be the largest sum
obtained by adding for each demand interval of such month the
corresponding Integrated Demands of the Transferee at all such
points after adjusting said Integrated Demands as appropriate to
such points;
(b) the number of kilowatthours to be used in determining the energy
charge, if any, and the average power factor at which electric
energy is delivered at such points under this contract, during such
month, shall be the sum of the amounts of electric energy delivered
at such points under this contract during such month; and
(c) the number of reactive kilovolt-ampere-hours to be used in
determining such average monthly power factor shall be the sum of
the reactive kilovolt-ampere-hours delivered at such points under
this contract such month.
11. Suspension of Deliveries. The other party to this contract may at any
time notify the Transferor in writing to suspend the deliveries of
electric power and energy provided for in this contract. Upon receipt
of any such notice, the Transferor will forthwith discontinue, and will
not resume, such deliveries until notified to do so by the other party,
and upon receipt of such notice from the other party to do so, will
forthwith resume such deliveries.
12. Continuity of Service. Either party may temporarily interrupt or
reduce deliveries of electric power and energy if such party determines
that such interruption or reduction is necessary or desirable in case of
system emergencies, Uncontrollable Forces, or in order to install
equipment in, make repairs to, make replacements within, make
investigations and inspections of, or perform other maintenance work on
its system. Except in case of emergency and in order that each party's
operations will not be unreasonably interfered with, such party shall
give notice to the other party of any such interruption or reduction,
the reason therefor, and the probable duration thereof to the extent
such party has knowledge thereof. Each party shall effect the use of
temporary facilities or equipment to minimize the effect of any such
interruption or outage to the extent reasonable or appropriate.
13. Uncontrollable Forces. Each party shall notify the other as soon as
possible of any Uncontrolled Forces which may in any way affect the
delivery of power hereunder. In the event the operations of either
party are interrupted or curtailed due to such Uncontrollable Forces,
such party shall exercise due diligence to reinstate such operations
with reasonable dispatch.
14. Reducing Charges for Interruptions. If deliveries of electric power
and energy to the Transferee are suspended, interrupted, interfered with
or curtailed due to Uncontrollable Forces on either the Transferee's
System or Transferor's System, or if the Transferor interrupts or
reduces deliveries to the Transferee for any of the reasons stated in
section 12 hereof, the credit in the exchange energy account which would
otherwise be made, or the money compensation which would otherwise be
paid to the Transferor, shall be appropriately reduced. No
interruption, or equivalent interruption, of less than 30 minutes
duration will be considered for computation of such reduction in
charges.
15. Net Billing. Upon mutual agreement of the parties, payment due one
Party may be offset against payments due the other party under all
contracts between the parties hereto for the sale and exchange of
electric power and energy, use of transmission facilities, operation and
maintenance of electric facilities, lease of electric facilities, mutual
supply of emergency and standby electric power and energy, and under
such other contracts between such parties as the parties may agree,
unless otherwise provided in existing contracts between the parties.
Under contracts included in this procedure, all payments due one party
in any month shall be offset against payments due the other party in
such month, and the resulting net balance shall be paid to the party in
whose favor such balance exists unless the latter elects to have such
balance carried forward to be added to the payments due it in a
succeeding month.
16. Average Power Factor.
(a) The formula for determining average power factor is as follows:
Average Power Factor = Kilowatthours
------------------------------------------------------
2 2
/(Kilowatthours) + (Reactive Kilovolt-ampere-hours)
The data used in the above formula shall be obtained from meters
which are ratcheted to prevent reverse registration.
(b) When delivery of electric poster and energy by the Transferor at
any point is commingled with any other class or classes of power
and it is impracticable to separately meter the kilowatthours and
reactive kilovolt-ampere-hours for each class, the average power
factor of the total delivery of such electric power and energy for
the month will be used, where applicable, as the power factor for
each of the separate classes.
(c) Except as it is otherwise specifically provided in this contract,
no adjustment will be made for power factor at any point of
delivery described in this contract while the varhours delivered at
such point are not measured.
(d) The Transferor may, but shall not be obligated to, deliver electric
energy hereunder at a power factor of less than 0.85 leading or
lagging.
17. Permits.
(a) If any equipment or facilities associated with any Point of
Delivery and belonging to a party to this contract are or are to be
located on the property of the other party, a permit to install,
test, maintain, inspect, replace, repair, and operate during the
term of this contract and to remove such equipment and facilities
at the expiration of said term, together with the right of entry to
said property at all reasonable times in such term, is hereby
granted by the other party.
(b) Each party shall have the right at all reasonable times to enter
the property of the other party for the purpose of reading any and
all meters mentioned in this contract which are installed on such
property.
(c) If either party is required or permitted to install, test,
maintain, inspect, replace, repair, remove, or a operate equipment
on the property of the other, the owner of such property shall
furnish the other party with accurate drawings and wiring diagrams
of associated equipment and facilities, or, if such drawings or
diagrams are not available, shall furnish accurate information
regarding such equipment or facilities. The owner of such property
shall notify the other party of any subsequent modification which
may affect the duties of the other party in regard to such
equipment, and furnish the other party with accurate revised
drawings, if possible.
18. Ownership of Facilities.
(a) Except as otherwise expressly provided, ownership of any and all
equipment, and of all salvable facilities installed or previously
installed by a party to this contract on the property of the other
party shall be and remain in the installing party.
(b) Each party shall identify all movable equipment and all other
salvable facilities which are installed by such party on the
property of the other by permanently affixing thereto suitable
markers plainly stating the' name of the owner of the equipment and
facilities so identified. Within a reasonable time subsequent to
initial installation, and subsequent to any modification of such
installation, representatives of the parties shall jointly prepare
an itemized list of said movable equipment and facilities.
19. Adjustment for Change of Conditions. If changes in conditions hereafter
occur which substantially affect any factor required by this contract to
be used in determining (a) any credit in any exchange energy account to
be made, money compensation to be paid, or amount of electric power and
energy or losses to be made available to one party by the other party,
or (b) any maximum replacement demand, or average power factor mentioned
in this contract, such factor will be changed in an equitable manner
which will conform to such changes of conditions, If an increase in the
capacity of the facilities being used by the Transferor in making
deliveries hereunder is required at any time after execution of this
contract to enable the Transferor to make the deliveries herein required
together with those required for its own operations, the construction or
installation of additional or other
8
equipment or facilities for that purpose shall be deemed to be a change
of conditions within the meaning of the preceding sentence.
If, pursuant to the terms of the agreement establishing such exchange
energy account, another rate is substituted for the rate to be used in
settling the balance in such account, the number of kilowatthours to be
credited to the Transferor in such account for each month as provided in
this agreement, shall be changed for each month thereafter to the amount
computed by multiplying such number of kilowatthours by 2.5 mills and
dividing the resulting product by the currently effective substituted
rate in mills per kilowatthour.
20. Dispute Resolution and Arbitration.
(a) Pending resolution of a disputed matter the parties will continue
performance of their respective obligations pursuant to this
contract. If the parties cannot reach timely mutual agreement on
any matter in the administration of this contract Bonneville shall,
unless otherwise specifically provided for in subsection (b) below
and, to the extent necessary for its continued performance, make a
determination of such matter without prejudice to the rights of the
other party. Such determination shall not constitute a waiver of
any other remedy belonging to the Contractor.
(b) The questions of fact stated below shall be subject to arbitration.
Other questions of fact under this contract may be submitted to
arbitration upon written mutual agreement of the parties. The
party calling for arbitration shall serve notice in writing upon
the other party, setting forth in detail the question or questions
to be arbitrated and the arbitrator appointed by such party. The
other party shall, within 10 days after the receipt of such notice,
appoint a second arbitrator, and the two so appointed shall choose
and appoint a third. In case such other party fails to appoint an
arbitrator within said 10 days, or in case the two so appointed
fail for 10 days to agree upon and appoint a third, the party
calling for the arbitration, upon 5 days' written notice delivered
to the other party, shall apply to the person who at the time shall
be the presiding judge of the United States Court of Appeals for
the Ninth Circuit for appointment of the second and third
arbitrator, as the case may be.
The determination of the question or questions submitted for
arbitration shall be made by a majority of the arbitrators and
shall be binding on the parties. Each party shall pay for the
services and expenses of the arbitrator appointed by or for it, for
its own attorney fees, and for compensation for its witnesses or
consultants. All other costs incurred in connection with the
arbitration shall be shared equally by the parties thereto.
The questions of fact to be determined as provided in this section
shall be limited to:
(1) the determination of the measurements to be made by the
parties hereto pursuant to section 4;
(2) the correction of the measurements to be made pursuant to
section 7;
9
(3) the duration of the interruption or equivalent interruption
in section 14;
(4) whether changes in conditions mentioned in section 19 have
occurred;
(5) whether the changes mentioned in section 30 were made
"promptly";
(6) whether an increase or decrease in load or change in load
factor mentioned in section 32 is unusual;
(7) any issue which both parties agree is an issue of fact
mentioned in sections 30, 31, and 34;
(8) the occurrence of an abnormal nonrecurring demand and the
amount and time thereof;
(9) whether a party has complied with section 34(b); and
(10) the acceptable level of harmonics for purposes of section 35.
21. Contract Work Hours and Safety Standards. This contract, if and to the
extent required by applicable law and if not otherwise exempted, is
subject to the following provisions:
(a) Overtime Requirements. No Contractor or subcontractor contracting
for any part of the contract work which may require or involve the
employment of laborers or mechanics, shall require or permit any
laborer or mechanic in any workweek in which such worker is
employed on such work to work in excess of 8 hours in any calendar
day or in excess of 40 hours in such workweek unless such laborer
or mechanic receives compensation at a rate not less than one and
one-half times such worker's basic rate of pay for all hours worked
in excess of eight hours in any calendar day or in excess of 40
hours in such workweek, as the case may be.
(b) Violation; Liability for Unpaid Wages; Liquidated Damages. In the
event of any violation of the provisions of subsection (a), the
Contractor and any subcontractor responsible therefor shall be
liable to any affected employee for such employee's unpaid wages.
In addition, such contractor and subcontractor shall be liable to
the Government for liquidated damages. Such liquidated damages
shall be computed with respect to each individual laborer or
mechanic employed in violation of the provisions of subsection (a)
in the sum of $10 for each calendar day on which such employee was
required or permitted to be employed in such work in excess of
eight hours or in excess of such employee's standard workweek of 40
hours without payment of the overtime wages required by subsection
(a) above.
(c) Withholding for Unpaid Wages and Liquidated Damages. Bonneville
may withhold or cause to be withheld, from any moneys payable on
account of work performed by the Contractor or subcontractor, such
sums as may administratively be determined to be necessary to
satisfy any liabilities of such Contractor or subcontractor for
unpaid wages and liquidated damages as provided in subsection (b)
above.
10
(d) Subcontracts. The Contractor shall insert in any subcontracts the
clauses set forth in subsections (a) through (c) of this provision
and also a clause requiring the subcontractors to include these
clauses in any lower tier subcontracts which they may enter into,
together with a clause requiring this insertion in any further
subcontracts that may in turn be made.
(e) Records. The Contractor shall maintain payroll records
containing the information specified in 29 CFR 516.2(a). Such
records shall be preserved for 3 years from the completion of the
contract.
22. Convict Labor. In connection with the performance of work under this
contract, the Contractor agrees, if and to the extent required by
applicable law or if not otherwise exempted, not to employ any person
undergoing sentence of imprisonment except as provided by Public Law 89-
176, September 10, 1965 (18 U.S.C. 4082(c)(2)) and Executive Order
11755, December 29, 1973.
23. Equal Employment Opportunity. During the performance of this contract,
if and to the extent required by applicable law or if not otherwise
exempted, the Contractor agrees as follows:
(a) 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 Bonneville
setting forth the provisions of the Equal Opportunity clause.
(b) 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.
(c) The Contractor will send to each labor union or representative of
workers with which said Contractor has a collective bargaining
agreement or other contract or understanding, a notice, to be
provided by Bonneville, advising the labor union or worker's
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.
(d) The Contractor will comply with all provisions of Executive Order
No. 11246 of September 24, 1965, and of the rules, regulations, and
relevant orders of the Secretary of Labor.
(e) The Contractor will furnish all information and reports required
by Executive Order No. 11246 of September 24, 1965, and by the
rules, regulations, and relevant orders of the Secretary of Labor,
or pursuant
11
thereto, and will permit access to said Contractor's books,
records, and accounts by Bonneville and the Secretary of Labor for
purposes of investigations to ascertain compliance with such rules,
regulations, and orders.
(f) In the event of the Contractor's noncompliance with the Equal
Opportunity clause of this contract or with any of such rules,
regulations, or orders, this contract may be cancelled, 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.
(g) The Contractor will include the provisions of paragraphs (a)
through (f) 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 order as Bonneville may
direct as a means of enforcing such provisions, including sanctions
for noncompliance. 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 Bonneville, the Contractor
may request the Government to enter into such litigation to protect
the interests of the Government.
24. Additional Provisions. The Contractor agrees to comply with the clauses
for Government contracts contained in the following statutes, Executive
Orders, and regulations to the extent applicable:
(a) the Rehabilitation Act of 1973, Public Law 93-112, as amended, and
41 CFR 60-741 (affirmative action for handicapped workers);
(b) the Vietnam Era Veterans Readjustment Assistance Act of 1974,
Public Law 92-540, as amended, and 41 CFR 60-250 (affirmative
action for disabled veterans and veterans of the Vietnam era);
(c) Executive Order 11625 and 41 CFR 1-1.1310-2 (utilization of
minority business enterprises);
(d) the Small Business Act, as amended.
25. Reports. The other party to this contract will furnish Bonneville such
information as is necessary for making any computation required for the
purposes of this contract, and the parties will cooperate in exchanging
such additional information as may be reasonably useful for their
respective operations.
26. Assignment of Contract. This contract shall inure to the benefit of,
and shall be binding upon the respective successors and assigns of the
parties to this contract. Such contract or any interest therein shall
not be transferred or assigned by either party to any party other than
the Government or an agency thereof without the written consent of the
other except as
12
specifically provided in this section. The consent of Bonneville is
hereby given to any security assignment or other like financing
instrument which may be required under terms of any mortgage, trust,
security agreement or holder of such instrument of indebtedness made by
and between the Contractor and any mortgagee, trustee, secured party,
subsidiary of the Contractor or holder of such instrument of
indebtedness, as security for bonds of other indebtedness of such
Contractor, present or future; such mortgagee, trustee, secured party,
subsidiary, or holder may realize upon such security in foreclosure or
other suitable proceedings, and succeed to all right, title, and
interests of such Contractor.
27. Waiver of Default. Any waiver at any time by any party to this contract
of its rights with respect to any default of any other party thereto, or
with respect to any other matter arising in connection with such
contract, shall not be considered a waiver with respect to any
subsequent default or matter.
28. Notices and Computation of Time. Any notice required by this contract
to be given to any party shall-be effective when it is received by such
party, and in computing any period of time from such notice, such period
shall commence at 2400 hours on the date of receipt of such notice.
29. Interest of Member of Congress. No Member of, or Delegate to Congress,
or Resident Commissioner shall be admitted to any share or part of this
contract or to any benefit that may arise therefrom, but this provision
shall not be construed to extend to this contract if made with a
corporation for its general benefit.
APPLICABLE ONLY IF TRANSFEREE IS A PARTY TO THIS CONTRACT
30. Balancing Phase Demands. If required by the Transferor at any time
during the term of this contract, the Transferee shall promptly make
such changes as are necessary on its system to balance the phase
currents at any Point of Delivery so that the current of any one phase
shall not exceed the current on any other phase at such point by more
than 10 percent.
31. Adjustment for Unbalanced Phase Demands. If the Transferee fails to
promptly make the changes mentioned in section 30, the Transferor may,
after giving written-notice one month in advance, determine that the
Measured Demand of the Transferee at the Point of Delivery in question
during each month thereafter, until such changes are made, is equal to
the product obtained by multiplying by three the largest of the
Integrated Demands on any phase adjusted as appropriate to such point
during such month.
32. Changes in Requirements or Characteristics. The Transferee will,
Whenever possible, give reasonable notice to the transferor of any
unusual increase or decrease of its demands for electric power and
energy on the Transferor's system, or of any unusual change in the load-
factor or power factor at which the Transferee will take delivery of
electric power and energy under this contract.
33. Inspection of Facilities. Each party may for any reasonable purpose
under this contract inspect the other party's electric installation at
any reasonable time. Such inspection, or failure to inspect, shall not
render
13
such party its officers, agents, or employees, liable or responsible for
any injury, loss, damage, or accident resulting from defects in such
electric installation, or for violation of this contract. The
inspecting party shall observe written instructions and rules posted in
facilities and such other necessary instructions or standards for
inspection as the parties agree to. Only those electric installations
used in complying with the terms of this contract shall be subject to
inspection.
34. Electric Disturbances.
(a) For the purposes of this section, an electric disturbance is any
sudden, unexpected, changed, or abnormal electric condition
occurring in or on an electric system which causes damage.
(b) Each party shall design, construct, operate, maintain and use its
electric system in conformance with accepted utility practices:
(1) to minimize electric disturbances such as, but not limited
to, the abnormal flow of power which may damage or interfere
with the electric system of the other party or any electric
system connected with such other party's electric system; and
(2) to minimize the effect on its electric system and on its
customers of electric disturbances originating on its own or
another electric system.
(c) If both parties to this contract are parties to the Western
Interconnected Electric System Agreement, their relationship with
respect to system damages shall be governed by that Agreement.
(d) During such time as a party to this contract is not a party to the
Agreement Limiting Liability Among Western Interconnected Systems,
its relations with the other party with respect to system damages
shall be governed by the following sentence, notwithstanding the
fact that the other party may be a party to said Agreement Limiting
Liability Among Western Interconnected Systems. A party to this
contract shall not be liable to the other party for damage to the
other party's system or facilities caused by an electric
disturbance on the first party's system, whether or not such
electric disturbance is the result of negligence by the first
party, if the other party has failed to fulfill its obligations
under subsection (b)(2) above.
(e) If one of the parties to this contract is not a party to the
Agreement Limiting Liability Among Western Interconnected Systems,
each party to this contract shall hold harmless and indemnify the
other party, its officers and employees, from any claims for loss,
injury, or damage suffered by those to whom the first party
delivers power not for resale, which loss, injury or damage is
caused by an electric disturbance on the other party's system,
whether or not such electric disturbance results from the
negligence of such other party, if such first party has failed to
fulfill its obligations under subsection (b)(2) above, and such
failure contributed to the loss, injury or damage.
14
(f) Nothing in this section shall be construed to create any duty to,
any standard of care with reference to, or any liability to any
person not a party to this contract.
35. Harmonic Control. Each party shall design, construct, operate, maintain
and use its electric facilities in accordance with good engineering
practices to reduce to acceptable levels the harmonic currents and
voltages which pass into the other party's facilities. Harmonic
reductions shall be accomplished with equipment which is specifically
designed and permanently operated and maintained as an integral part of
the facilities of the party which owns the system on which harmonics are
generated.
APPLICABLE ONLY IF TRANSFEREE IS NOT A PARTY TO THIS CONTRACT
36. Protection of the Transferor. Protection is or will be afforded to
Bonneville or its Transferor under such of the following provisions and
conditions as are specified in each contract executed or to be executed
by Bonneville and each third party Transferee named in this contract:
the power factor clause of the applicable Bonneville Wholesale Rate
Schedule and the subject matter set forth in the General Contract
Provisions under the following titles, namely:
Adjustment for Unbalanced Phase Demands; Uncontrollable Forces;
Continuity of Service; Changes in Demands or Characteristics; Electric
Disturbances; Harmonic Control; Balancing Phase Demands; Permits;
Ownership of Facilities; and Inspection of Facilities.
RELATING TO RURAL ELECTRIFICATION ADMINISTRATION BORROWERS
37. Approval of Contract. If the Contractor borrows from the Rural
Electrification Administration or any other entity under an indenture
which requires the lender's approval of contracts, this contract and any
amendment thereto shall not be binding on the parties thereto if they
are not approved by the Rural Electrification Administration or such
other entity. The Contractor shall notify Bonneville of any such
entity. If approval is given, such contract or amendment shall be
effective at the time stated therein.
APPLICABLE ONLY IF BONNEVILLE IS THE TRANSFEROR
38. Equitable Adjustment of Rates.
(a) Bonneville shall establish, periodically review and revise rates
for the wheeling of electric power and/or energy pursuant to the
terms of this contract. Such rates shall be established in
accordance with applicable law.
(b) As used in this section. the words "Rate Adjustment Date" shall
mean any date specified by Bonneville in a notice of intent to file
revised rates as published in the Federal Register; provided
however, that such date shall not occur sooner than (1) nine months
from the date that such notice of intent is published; or (2)
twelve months from any previous Rate Adjustment Date. By giving
written notice to the Contractor 45 days prior to such Rate
Adjustment Date, Bonneville may delay such Rate Adjustment Date for
up to 90 days if Bonneville determines either that the revenue
level of the proposed rates
15
differs by more than five percent from the revenue requirements
indicated by most recent repayment studies entered in the hearings
record or that external events beyond Bonneville's control will
prevent Bonneville from meeting such Rate Adjustment Date.
Bonneville may cancel a notice of intent to file revised rates at
any time (1) by written notice to the Contractor; or (2) by
publishing in the Federal Register a new notice of intent to file
revised rates which specifically cancels a previous notice.
(c) The Contractor shall pay Bonneville for the service made available
under this contract during the period commencing on each Rate
Adjustment Date and ending at the beginning of the next Rate
Adjustment Date at the rate specified in any rate schedule
available at the beginning of such period for service of the
class, quality, and type provided for in this contract, and in
accordance with the terms thereof, and of the General Transmission
Rate Schedule Provisions, if any, as changed with, incorporated in
or referred to in such rate schedule. New rates shall not be
effective on any Rate Adjustment Date unless they have been
approved on a final or interim bases by a governmental agency
designated by law to approve Bonneville's rates. Rates shall be
applied in accordance with the terms thereof, the General
Transmission Rate Schedule Provisions as changed with, incorporated
in or referred to in such rate schedule and the terms of this
contract.
(WP-PKJ-0222f)
Exhibit C, Page 1 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
TRANSMISSION PARAMETERS
A. Points Of Integration, Transmission Demands, Resources, And Use-Of
Facilities Charges
Use-of-
Facilities
Transmission Sources to Charge
Point of Integration (Voltage) Demand (kW) be Integrated $/kW/mo.
- -------------------------------- ------------ ------------- ----------
1. C.W. Paul Substation (500kV) 173,000 Electric Output 0
Centralia(1)
2. Garrison Substation (500 kV) 466,000(2) Electric Output 0
of Colstrip
Nos. 1-4(2)
3. Garrison Substation (230 kV) 94,000 Electric Output 0
of Colstrip
No. 4(3)
4. John Day Substation (500 kV) 300,000 Any Electric Power 0
transmitted over
the PNW AC Intertie
pursuant to the
Capacity Ownership
Agreement
Total Transmission Demand 1,033,000
(1) The Transmission Demand with respect to this Resource shall be reduced
to 100,000 kW on the effective date of the 197 MW (or lesser amount) of
incremental Transmission Demand specified in footnote 2 below.
Bonneville shall integrate at the C. W. Paul Substation Point of
Integration, in an amount up to the Transmission Demand with respect to
such Point of Integration, shares of the Centralia Project Electric
Power acquired by Puget from other entities. Bonneville shall integrate
such Electric Power on the same basis that Bonneville integrates
Electric Power from the Company's ownership share of the Centralia
Project.
(2) Bonneville shall integrate at the Garrison Substation Point of
Integration in an amount up to the Transmission Demand, Electric Power
from Colstrip 1, 2, 3, and 4 acquired by Puget. Bonneville shall
integrate at the Garrison Substation Point of Integration in an amount
up to the Transmission Demand with respect to such Point of Integration,
Electric Power from other resources, unless Bonneville determines that
Electric Power from such other resources cannot be integrated due to
Operational Constraints. Bonneville shall integrate such Electric Power
on the same basis that Bonneville is obligated to integrate Electric
Power from the Company's Colstrip ownership share. This provision does
not increase or decrease any rights that the Company has pursuant to
Contract No. DE-MS79-81BP90210 (Montana Intertie Agreement).
(2) (cont'd):
In consideration of the Company's maintaining in effect with The
Washington Water Power Company (WWP) until November 30, 1998, the
Exchange Agreement, as amended or replaced, pursuant to which the
Company exchanges 197 MW of its Colstrip Project generation for 197 MW
of WWP's Centralia Project generation, Bonneville shall provide the
Company beginning December 1, 1998, with a right to 197 MW of East-to-
West incremental firm
Exhibit C, Page 2 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
transmission service. At such time that the Company exercises such
right, a Transmission Demand in the amount of 197 MW, or a lesser amount
if so requested by the Company, shall be added to this Exhibit C, Part
A. with respect to the Garrison Substation Point of Integration. To the
extent of such Transmission Demand, Bonneville shall provide
transmission service under this Agreement from the Garrison Substation
Point of Integration to one or more of the Points of Delivery. The
Company's right as provided for in this paragraph shall terminate if not
exercised prior to November 30, 2000, or a later date determined by
Bonneville. If the Company does not maintain in effect until November
30, 1998, the Exchange Agreement with WWP pursuant to which the Company
exchanges 197 MW of its Colstrip Project generation for 197MW of WWP's
Centralia Project generation, then upon the Company's request a
Transmission Demand in the amount of 197 MW, or a lesser amount if so
requested by the Company, shall be added to Exhibit C, Part A, with
respect to the Garrison Substation Point of Integration; provided,
however, that to the extent the transmission service Bonneville provides
to the Company with respect to such 197 MW must be curtailed due to
Operational Constraints, the Company shall receive a pro rata reduction
in Demand Charge, and the Company shall not be assessed charges for
energy pursuant to the Integration of Resources Transmission Rate
Schedule (IR-93), or its successor rate schedule. If and to the extent
the Company contracts with WWP to provide access across the "West-of-
Hatwai Cutplane" (as defined in footnote 3 below), the Company will he
assessed losses as if such Electric Power had flowed on the FCRTS;
provided, that, notwithstanding the foregoing, Bonneville shall deliver
on a firm basis to one or more Points of Delivery such 197 MW of
Electric Power (or any lesser amount) as may be scheduled by the
Company.
(3) If this Resource (94 MW Colstrip 4 purchase from Montana) cannot be made
available to Bonneville due solely because of (i) Operational
Constraints, including, without limitation, Western System Coordinating
Council scheduling requirements. involving the West-of-Hatwai Cutplane,
which do not involve an outage of transmission facilities (ii)
suspension or interruption of, or interference with, the operation of
the FCRTS, or (iii) both, and it is within Bonneville's capability to do
so without adversely affecting performance of its existing obligations
on the Effective Date, then Bonneville shall, if requested by the
Company, make replacement Electric Power available to the Company equal
to the amount of-such Resource the Company would have otherwise made
available to Bonneville at the Garrison Substation Point of Integration
and the Company shall at Bonneville's option: (1) reimburse Bonneville
at Bonneville's Nonfirm Energy rate or Surplus Firm Energy rate when
Bonneville is selling such energy; or (2) return replacement Electric
Power 168 hours later or at a time and place agreed upon by Bonneville
and the Company, or (3) reimburse Bonneville for Bonneville's costs to
obtain replacement Electric Power from third parties including
associated wheeling and administrative fees. If Bonneville is unable to
make replacement Electric Power available, then transmission services
for this Resource under this Agreement shall be curtailed before any
other firm wheeling contracts executed prior to the effective date of
Contract No. DE-MS79-92BP93741, as amended or replaced, with the
exception of Bonneville's Electric Power purchase from Basin Electric
Power Cooperative (Basin). "West-of-Hatwai Cutplane" means the parallel
transmission facilities consisting of the following transmission lines
and facilities, Grand Coulee-Bell 230 kV lines 3 and 5, Grand Coulee-
Bell 115 kV lines 1 and 2, Grand Coulee-Westside 230 kV line, Hatwai-
Lower Granite 500 kV line, Hatwai-Lolo 230 kV line, Lind-Warden 115 kV
line, Lolo 230/115 kV Transformer #1 and #2. Harrington-Odessa 115 kV
line, Dry Gulch Transformer 115/69 kV, North Lewiston-Walla Walla 230 kV
line, and the North Lewiston-Walla Walla 115 kV line which connect two
areas of a power system. The provisions set forth in this footnote shall
be void and of no force or effect after November 30, 1998.
Exhibit C, Page 3 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
B. Points of Delivery and Use Limits
Point of Delivery Use Limit
----------------------- --------------
(Voltage) (kW)(1)
Christopher Tap 230 kV 450,000 kW
Covington Substation 230 kV 880,000 kW (2)
Custer Substation 230 kV 475,000 kW (3)(8)
Maple Valley Substation 230 kV 1,570,000 kW
Monroe Substation 230 kV 430,000 kW (4)
Sedro Woolly Substation 230 kV 125,000 kW (8)
White River Substation 230 kV 170,000 kW
Big Eddy Substation 230 kV (5)
John Day Substation 500 kV 400,000 kW (6)
Fairmount Substation 69 kV 60,000 kW (7)
(115 kV upon installation and
energization of 115 kV facilities)
Kitsap Substation 115 kV 410,000 kW
Olympia Substation 115 kV 270,000 kW
Bellingham Substation 115 kV 100,000 kW (8)
Beverly Park Substation 115 kV 50,000 kW
C. W. Paul Substation 500 kV 280,000 kW
Sedro Woolley Tap 230 kV 265,000 kW (9)
(1) Use Limits may be developed based on the rating of the
Government's limiting facility at each Point of Delivery. These
values are determined based on (A) the rating of the Bonneville
facilities at the Point of Delivery, and (B) an allocation of such
rating between (i) the Company's Use Limit under this Agreement at
such Point of Delivery (including but not limited to any requested
increases in such Use Limit) and (ii) other Bonneville uses but
these values shall in any event, if requested by the Company in
writing pursuant to this footnote be not less than the sum of
contract demands at such Point of Delivery. Each numerical Use
Limit set forth above indicates that for the Point of Delivery
opposite such numerical Use Limit there is a limit (equal to such
Use Limit) to the rate of delivery on a firm basis at such Point of
Delivery that is available to the Company under this Agreement.
The Company's Use Limit under this Agreement at any Point of
Delivery may be increased pursuant to the provisions of section
10(d). The Use Limit under this Agreement at a Point of Delivery
shall be decreased upon written request of the Company. Bonneville
shall not unilaterally decrease any Use Limit. In the event it is
determined that the total deliveries by Bonneville pursuant to all
agreements between the Company and Bonneville which require
deliveries of Electric Power to be made at a specific Point of
Delivery may exceed the Use Limit for that Point of Delivery, and
joint studies indicate a need for reinforcement, Bonneville and the
Company will conduct and conclude the joint discussions described
in section 10(d) within 6 months of the above determination, and
implement any resulting plan as soon as is reasonably practicable.
Under no circumstances, and notwithstanding anything to the
contrary set forth in this Agreement, shall Use Limits, without the
Company's prior written consent, be less than the transmission
demands in effect under the Prior Agreements immediately prior to
their termination pursuant to section 2(a).
Exhibit C, Page 4 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
(2) The Use Limit with respect to the Covington Substation Point of
Delivery includes the Use Limits for the Christopher Tap and White
River Substation Points of Delivery.
(3) The Use Limit with respect to the Custer Substation Point of
Delivery includes the Use Limits for the Bellingham Substation and
Sedro Woolley Substation Points of Delivery, and includes
deliveries to Portal Way.
(4) The Use Limit with respect to the Monroe Substation Point of
Delivery includes the Use Limits for the Sedro Woolley Tap and
Beverly Park Substation Points of Delivery.
(5) Nothing in this Agreement or the Capacity Ownership Agreement
provides the Company with rights to use the DC Intertie.
Deliveries at this Point of Delivery are subject to available
transmission capacity and any nonfirm rights the Company has on an
hour to wheel Electric Power over the DC Intertie.
(6) If the megawatt amount of the capability of the PNW AC Intertie to
which the Company is entitled pursuant to the Capacity Ownership
Agreement is at any time increased or reduced, the Use Limit with
respect to the John Day Substation Point of Delivery shall be
concurrently increased or reduced by a megawatt amount equal to
such increase or reduction with respect to the PNW AC Intertie upon
prior written notice of such increase or reduction by the Company
to Bonneville.
(7) The Use Limit with respect to the Fairmount Substation Point of
Delivery shall be increased to 70,000 kW upon installation and
energization of 115 kV facilities at Fairmount Substation.
(8) The Use Limits for the Custer Substation, Sedro Woolley Substation
and Bellingham Substation Points of Delivery will be adjusted, if
necessary, to be consistent with the Bellingham Upgrade Northern
Intertie agreement.
(9) The Sedro Woolley Tap Point of Delivery is a temporary Point of
Delivery, pursuant to the terms of Contract No. 14-03-64431. The
provisions of Contract No. 14-03-64431 shall continue to apply to
this Point of Delivery.
<PAGE>
Exhibit C, Page 5 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
C. Calculation of Charges Pursuant to the UFT-83 Rate Schedule
<TABLE>
<CAPTION>
I&A I&A O&M Sum of Non-
Annual Annual Annual Coincidental
Facility Investment Cost Ratio Cost Cost Demands $/kW/yr Demand
-------- ---------- ---------- ------ ------ ------------ ------- ------
<S> <C> <C> <C> <C> <C> <C> <C>
None
------- ------
Total UFT Charge = 0.00/kW/yr kW
$0.00/KW/mo
____________________
Unit Charge = (I&A Annual Cost) + O&M Annual Cost = $/kW yr
---------------------------------------------
Sum of Non-Coincidental Demands
Monthly Charge = ($/kW yr) (Project Demand) = $/mo.
--------------------------
12 Months
</TABLE>
<PAGE>
Exhibit C, Page 6 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
D. Description of Points of Integration and Points of Delivery
Note: These are definitions only. Designations of these points as
either Points of Integration or Points of Delivery are in Part A
or Part B of this exhibit.
1. Big Eddy Substation
Location: the points in the Government's Big Eddy Substation
where the line terminals of the Government's Celilo Converter
Station are connected to the 230 kV bus.
Voltage: 230 kV.
2. C.W. Paul Substation
Location: the points in the Government's C.W. Paul Substation
where the 500 kV facilities of the Government and the Centralia
Thermal Project are connected;
Voltage: 500 kV,
Metering: at the Centralia Thermal Project, in the 20 kV circuits
over which Electric Power flows.
Exception: There shall be an adjustment for losses between the
Point of Integration and the metering point.
3. Christopher Tap
Location: the point on the Government's Covington-Tacoma 230 kV
circuit over which Electric Power flows;
Voltage: 230 kV;
Metering: in the Company's O'Brien Substation, in the 230 kV
circuit over which Electric Power flows;
Exception: there shall be an adjustment for losses between the
Point of Delivery and the point of metering.
4. Covington Substation
Location: the point in the Government's Covington Substation where
the 230 kV facilities of the parties hereto are connected;
Exhibit C, Page 7 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
Voltage: 230 kV;
Metering: in the Government's Covington Substation in the 230 kV
circuit over which Electric Power flows;
Exception: the integrated demands at the Covington and White River
Point of Delivery's are totaled.
5. Custer Substation
Location: the point in the Government's Custer Substation in the
230 kV facilities of the Parties hereto are connected;
Voltage: 230 kV;
Metering: in the Government's Custer Substation in the 230 kV
circuits over which Electric Power flows.
6. Garrison Substation
Location: the points in the Government's Garrison Substation where
the line terminals of the Garrison-Townsend transmission lines are
connected to the 500 kV bus;
Voltage: 500 kV;
Metering: in the Government's Garrison Substation in the 500 kV
circuits over which Electric Power flows.
7. John Day Substation
Location: the points in the Government's John Day Substation where
the line terminals of the Southern Intertie are connected to the
500 kV bus;
Voltage: 500 kV.
8. Maple Valley Substation
Location: the points in the Government's Maple Valley Substation
where the 230 kV facilities of the Parties hereto are connected;
Voltage: 230 kV;
Metering: in the Government's Maple Valley Substation, in the 230
kV circuits over which Electric Power flows.
Exhibit C, Page 8 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
9. Monroe Substation
Location: the point in the Government's Monroe Substation where
the Monroe-Sammamish No. 1 Line is connected;
Voltage: 230 kV;
Metering: in the Company's Sammamish Substation, in the 230 kV
circuits over which Electric Power flows; until such time as the
Government's Sno-King tap is disconnected from the Monroe-Sammamish
No. 1 Line and thereafter in the Government's Monroe Substation, in
the 230 kV circuit over which such Electric Power will flow;
Exceptions: there shall be an adjustment for losses between the
Point of Delivery and the metering point.
10. Sedro Woolley Substation
Location: the point at Structure No. 26/7 of the Government's
Murray-Bellingham 230 kV Line where the facilities of the Parties
hereto are connected;
Voltage: 230 kV;
Metering: in the Company's Sedro Woolley Substation, in the 230 kV
circuits over which Electric Power flows;
Exceptions: the current and potential transformers are owned by
Puget.
11. White River Substation
Location: the points in the Company's White River Substation where
the 230 kV facilities of the Government and the Company are
interconnected;
Voltage: 230 kV;
Exhibit C, Page 9 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
Metering:
(1) the Government's Covington-White River No. 1 Line is metered
at the Government's Covington Substation in the 230 kV
circuits over which Electric Power flows;
(2) the Government's Olympia-White River No. 1 Line is metered in
the Company's White River Substation in the 230 kV circuits
over which Electric Power flows;
Exception: there shall be an adjustment for losses between metering
point (1) above, and the Point of Delivery.
12. (a) Fairmount Substation
Location: the point in the Government's Fairmount Substation where
the 69 kV facilities (115 kV upon installation and energization) of
the Parties are connected;
Voltage: 69 kV (115 kV upon installation and energization of such
facilities );
Metering: in the Government's Fairmount Substation. in the 69 kV
circuits (115 kV circuit upon installation and energization) over
which Electric Power flows.
(b) Fairmount Substation
Location: the point in the Government's Fairmount Substation where
the 69 kV facilities of Public Utility District No. 1 of Clallam
County, Washington, and the Government are connected;
Voltage: 69 kV;
Metering: in the Company's Discovery Bay Substation, in the 12.5
kV circuits over which Electric Power is distributed by the
Company;
Exception: there shall be an adjustment for losses between the
Point of Delivery and the metering point.
13. Kitsap Substation
Location: the points in the Government's Kitsap Substation where
the 115 kV facilities of the Parties hereto are connected;
Voltage: 115 kV;
Exhibit C, Page 10 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
Metering: in the Government's Kitsap Substation, in the 115 kV
circuits over which Electric Power flows.
14. Olympia Substation
Location: the point in the Government's Olympia Substation where
the 115 kV facilities of the Parties are connected;
Voltage: 115 kV;
Metering: in the Government's Olympia Substation, in the 115 kV
circuits over which Electric Power flows.
15. Bellingham Substation
Location: the point in the Government's Bellingham Substation
where the 115 kV facilities of the Parties are connected;
Voltage: 115 kV;
Metering: in the Government's Bellingham Substation, in the 115 kV
circuits over which Electric Power flows.
16. Beverly Park Substation
Location: the point in Snohomish's Beverly Park Substation where
the 115 kV facilities of the Government and Snohomish are
connected;
Voltage: 115 kV;
Metering: in Snohomish's Beverly Park Substation, in the 115 kV
circuits over which Electric Power flows.
17. C. W. Paul Substation
Location: the point in the Government's C.W. Paul Substation where
the 500 kV facilities of the Parties are connected;
Voltage: 500 kV;
Metering: in the Company's Tono Substation, in the 115 kV circuits
over which Electric Power flows;
Exhibit C, Page 11 of 11
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
Exception: there shall be an adjustment for losses between the
Point of Delivery and the metering point.
18. Sedro Woolley Tap
Location: the point at structure 5/2 at the Sedro Woolley Tap to
the Monroe-Snohomish Line No. 1 where the 230 kV facilities of the
Parties are connected,
Voltage: 230 kV;
Metering: in the Company's Sedro Woolley Substation, in the 230 kV
circuits over which Electric Power flows;
Exception: there shall be an adjustment for losses between the
Point of Delivery and the metering point.
PMLAN-MPSM-W:\PMT\CT\93947\EXC.DOC))
Exhibit D, Page 1 of 1
Contract No. DE-MS79-94BP93947
Puget Sound Power & Light Company
Effective on the Effective Date
TRANSMISSION LOSS FACTORS
-------------------------
A. Transmission Loss Factor to be Applied to Transmission Pursuant to the
Integration of Resources (IR) Rate Schedule.
Rate Loss
Schedule Factor
-------- ------
IR-93 1.6%(1)
B. Transmission Loss Factor to be Applied to Transmission Pursuant to the
Energy Transmission (ET) Rate Schedule.
Rate Loss
Schedule Factor
-------- ------
ET-93 1.6%(1)
- ------------------------------------------
(1) Bonneville reserves the right to change the Loss Factor in accordance
with section 9(b).
(PMLAN-PMT-W:\PMT\CT\93947\ExD.DOC)
EXHIBIT 10.116
Contract No. DE-MS79-94BP94521
PNW AC INTERTIE CAPACITY OWNERSHIP AGREEMENT
executed by the
UNITED STATES OF AMERICA
DEPARTMENT OF ENERGY
acting by and through the
BONNEVILLE POWER ADMINISTRATION
and
PUGET SOUND POWER & LIGHT COMPANY
Index to Sections
- ---------------------------------------------------------------------------
SECTION PAGE
1. Definitions..........................................................4
2. Term and Termination................................................15
3. Capacity Rights.....................................................16
4. Scheduling..........................................................22
5. Upgrades............................................................24
6. Sale or Assignment..................................................28
7. Operation, Maintenance, and Management..............................29
8. Existing Agreements.................................................31
9. Payment Provisions..................................................32
10. Transmission Losses.................................................49
11. Remedial Actions....................................................50
12. Capacity Owners' Committee..........................................52
13. Operating Plan and Amendments to the Operating Plan.................56
14. Arbitration.........................................................70
15. Nonbinding Arbitration..............................................75
16. Audit Rights........................................................85
17. Protected Areas.....................................................90
18. Establishment and Maintenance of Rates and Relief from
Regulatory Action...................................................91
19. Exhibits...........................................................102
1
20. Rules of Law.......................................................104
21. Notices............................................................105
22. Waiver.............................................................106
23. Miscellaneous......................................................106
Exhibit A (CO-94, AC-93, IS-93 Rate Schedules and General
Transmission Rate Schedule Provisions)
Exhibit B (Annual Costs Rate)
Exhibit C (Capacity Ownership Share, Capacity Ownership Percentage,
Scheduling Percentage, and Scheduling Share)
Exhibit D (Lump Sum Payment Calculation)
Exhibit E (Transmission Loss Factors)
Exhibit F (Bonneville's PNW AC Intertie)
Exhibit G (Capacity Owners)
Exhibit H (Provisions Required by Statute or Executive Order)
Exhibit I (Bonneville's PNW AC Intertie Costs)
Exhibit J (Puget's Initial Transaction with California Utility)
This PNW AC INTERTIE CAPACITY OWNERSHIP AGREEMENT (Agreement) is
entered into as of ____________, 1994, by the UNITED STATES OF AMERICA,
Department of Energy, acting by and through the BONNEVILLE POWER
ADMINISTRATION (Bonneville or BPA) and PUGET SOUND POWER & LIGHT COMPANY
(Puget), a corporation of the state of Washington. Each of Bonneville and
Puget is sometimes referred to individually in this Agreement as "Party";
Bonneville and Puget are sometimes referred to together in this Agreement as
"Parties."
W I T N E S S E T H :
WHEREAS Bonneville, Portland General Electric Company (Portland), and
PacifiCorp Electric Operations (PacifiCorp) planned and constructed
improvements and additions to the Northwest portion of the PNW-PSW Intertie;
and
WHEREAS such construction was completed in December 1993 resulting in
1600 MW of additional PNW AC Intertie Rated Transfer Capability in a north-
2
to-south direction and 1225 MW of additional PNW AC Intertie Rated Transfer
Capability in a south-to-north direction; and
WHEREAS pursuant to the Northwest Intertie Agreements, Bonneville
operates the PNW AC Intertie, in coordination with Portland and PacifiCorp,
as a single system so as to maximize PNW AC Intertie Rated Transfer
Capability and Operational Transfer Capability consistent with Prudent
Utility Practice; and
WHEREAS Bonneville has developed a proposal to offer to PNW non-Federal
scheduling utilities and joint agencies capacity ownership rights in 725 MW
of Bonneville's PNW AC Intertie Rated Transfer Capability; and
WHEREAS such proposal has been studied in Bonneville's Final Non-
Federal Participation Environmental Impact Statement, dated January 1994,
and was the selected alternative in the Administrator's Record of Decision,
dated March 25, 1994; and
WHEREAS Bonneville and Puget executed a Memorandum of Understanding, DE-
MS79-91BP93466, dated September 18, 1991, which, among other things, sets
forth the principles for Puget's capacity ownership rights in Bonneville's
PNW AC Intertie; and
WHEREAS interest expressed in capacity ownership by PNW non-Federal
scheduling utilities and joint agencies exceeded the 725 MW of Bonneville's
PNW AC Intertie Rated Transfer Capability offered by Bonneville, and as a
result Bonneville developed and applied an allocation methodology selected
in the Administrator's Capacity Ownership Record of Decision, dated March
25, 1994; and
WHEREAS concurrent with the execution of this Agreement, Bonneville and
Puget are executing Contract No. DE-MS79-94BP93947 to provide Puget with,
among other things, network wheeling between the John Day Substation and
Puget's transmission system; and
WHEREAS Bonneville is authorized pursuant to law to dispose of electric
power generated at various Federal hydroelectric projects in the PNW, or
acquired
3
from other resources, to construct and operate transmission facilities, to
provide transmission and other services, and to enter into agreements to
carry out such authority;
NOW, THEREFORE, Bonneville and Puget agree as follows:
1. DEFINITIONS
(a) "Adjusted Capacity Ownership Price" means the price calculated
pursuant to column 2, section B of Exhibit D and section IV.B of
the CO-94 rate in Exhibit A.
(b) "Adjusted Lump Sum Payment" means the Adjusted Capacity Ownership
Price multiplied by Puget's Capacity Ownership Share (in
kilowatts), as described with more particularity in section D of
Exhibit D.
(c) "Allocated Direct Costs" means for each fiscal year the Operations
Cost as allocated to Bonneville's PNW AC Intertie in accordance
with section I.C of Exhibit I for such fiscal year. Allocated
Direct Costs are not included in Direct Costs, Indirect Costs, or
Overhead Costs.
(d) "Allowance for Funds Used During Construction" or "AFUDC"
constitutes interest on the funds used for utility plant under
construction. The AFUDC rate approximates the cost of money being
used to finance current construction work in progress and is
calculated in accordance with FERC's Uniform System of Accounts,
18 CFR, Part 101, Electric Plant Instructions 3.A(17), or its
successors. AFUDC shall be capitalized in accordance with
Bonneville's accounting procedures and practices, and in any event
consistent with FERC's Uniform System of Accounts, 18 CFR, Part
101, Electric Plant Instructions 3.A(17), or its successors.
(e) "Billing Provisions" means those provisions set forth in Exhibit
B, Part B.
4
(f) "Bonneville's PNW AC Intertie" means facilities of the PNW AC
Intertie owned partially or entirely by Bonneville specified in
Exhibit F together with the equipment and facilities installed in
or connected to such facilities specified in Exhibit F, to the
extent such facilities are necessary for the transmission of power
on the PNW AC Intertie.
(g) "Bonneville's PNW AC Intertie Operational Transfer Capability"
means Bonneville's PNW AC Intertie Rated Transfer Capability as
reduced by limitations beyond the control of the Parties, and by
operational limitations (as determined by Bonneville in accordance
with the agreement between Bonneville and PacifiCorp, Contract No.
DE-MS79-94BP94332, as amended from time to time pursuant to the
terms thereof, and with the agreement between Bonneville and
Portland, Contract No. DE-MS79-87BP92340, as amended from time to
time pursuant to the terms thereof, and in accordance with Prudent
Utility Practice) resulting from, among other things, line or
equipment outages, stability limits, or loopflow.
(h) "Bonneville's PNW AC Intertie Rated Transfer Capability" means
Bonneville's share of the PNW AC Intertie Rated Transfer
Capability as determined in accordance with the agreement between
Bonneville and PacifiCorp, Contract No. DE-MS79-94BP94332, as
amended from time to time pursuant to the terms thereof, and with
the agreement between Bonneville and Portland, Contract No. DE-
MS79-87BP92340, as amended from time to time pursuant to the terms
thereof.
(i) "Capacity Owner" means each of the parties listed in Exhibit G to
the extent that such party has entered into a Capacity Ownership
Agreement.
(j) "Capacity Ownership Agreement" means, in the singular, this
Agreement or the agreement, substantially identical to this
Agreement, entered into by each Capacity Owner (other than Puget)
and Bonneville, and in the plural, this Agreement and all such
substantially identical agreements entered into respectively by
5
Capacity Owners (other than Puget) and Bonneville, as each such
agreement may be amended or supplemented from time to time
pursuant to the terms of such agreement, concerning (among other
things) the rights of such Capacity Owner with respect to the PNW
AC Intertie.
(k) "Capacity Ownership Percentage" means, as of the Effective Date,
in the singular, the percentage of Bonneville's PNW AC Intertie
Rated Transfer Capability owned by Puget pursuant to this
Agreement, which percentage is determined by dividing Puget's
Capacity Ownership Share as of the Effective Date by Bonneville's
PNW AC Intertie Rated Transfer Capability as of the Effective Date
(such percentage being subject to change pursuant to the terms of
this Agreement), and in the plural, the percentages of
Bonneville's PNW AC Intertie Rated Transfer Capability owned by
the other Capacity Owners, respectively, pursuant to their
respective Capacity Ownership Agreements (other than this
Agreement), which percentages are set forth in Exhibit G (each of
such percentages being subject to change pursuant to the
respective terms of such Capacity Ownership Agreements).
(l) "Capacity Ownership Rights" means the rights of Puget pursuant to
this Agreement.
(m) "Capacity Ownership Share" means, except as such term is otherwise
used in sections III.A and III.B of the CO-94 rate set forth in
Exhibit A on the Effective Date, in the singular, the MW amount of
Bonneville's PNW AC Intertie Rated Transfer Capability owned by
Puget pursuant to this Agreement, which MW amount is set forth in
Exhibit C (such amount being subject to change pursuant to the
terms of this Agreement), and in the plural, the MW amounts of
Bonneville's PNW AC Intertie Rated Transfer Capability owned by
the other Capacity Owners, respectively, pursuant to their
respective Capacity Ownership Agreements (other than this
Agreement), which amounts are set forth in Exhibit G (each of such
amounts being subject to
6
change pursuant to the respective terms of such Capacity Ownership
Agreements).
(n) "Committee" has the meaning set forth in subsection 12(a).
(o) "Contracts and Rates Costs" means, upon and after the effective
date of Exhibit B pursuant to this Agreement, for any fiscal year
Bonneville's total contracts and rates costs (as described in
section VI of Exhibit I) for such fiscal year as functionalized
and allocated in accordance with section VI of Exhibit I to
determine Contracts and Rates Costs for Bonneville's PNW AC
Intertie.
(p) "Direct Costs" means any costs incurred by Bonneville which are
readily identifiable, or obviously traceable to, and directly
benefit, a specific Bonneville program, project, or other cost
objective. Direct Costs are not included in Allocated Direct
Costs, Overhead Costs, or Indirect Costs. The methods for
determining Direct Costs for Bonneville's PNW AC Intertie are set
forth in sections II.B and III.A of Exhibit I.
(q) "Effective Date" means the date as of which this Agreement becomes
effective pursuant to section 2.
(r) "End of Term Costs" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, Bonneville's costs
associated with decommissioning the PNW AC Intertie determined in
accordance with section VIII of Exhibit I.
(s) "FERC" means the Federal Energy Regulatory Commission or its
regulatory successor.
(t) "General Plant Cost" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any fiscal year any
costs (including direct costs, indirect costs, overhead costs, and
AFUDC) for Bonneville's general plant investment for such fiscal
year. The
7
method for determining General Plant Cost is set forth in section
IV of Exhibit I.
(u) "GTRSP" or "GTRSPs" means Bonneville's General Transmission Rate
Schedule Provisions, set forth in Exhibit A, as such provisions
may be revised from time to time.
(v) "Indirect Costs" means any costs incurred by Bonneville which
indirectly benefit and are directly charged to a specific
Bonneville program, project, or other cost objective for which a
Direct Cost or Allocated Direct Cost is charged. Indirect Costs
shall not be included in Allocated Direct Costs, Direct Costs, or
Overhead Costs. The methods for determining Indirect Costs for
Bonneville's PNW AC Intertie are set forth in sections I.D, II.D,
and III.B of Exhibit I.
(w) "Initial Capacity Ownership Price" means $215 per kilowatt, the
calculation of which charge is set forth in column 1, section B of
Exhibit D and in section III.A of the CO-94 rate in Exhibit A.
(x) "Initial Lump Sum Payment" means the Initial Capacity Ownership
Price multiplied by Puget's Capacity Ownership Share (in
kilowatts), as described with more particularity in section C of
Exhibit D.
(y) "Interconnection Agreement" means the "Interim Interconnection
Agreement Between Certain California-Oregon Transmission Project
Participants and Northwest Participants," Contract No. DE-MS79-
91BP93158, as amended or superseded.
(z) "Joint AC Intertie" is as defined in the agreement between
Bonneville and Portland, Contract No. DE-MS79-87BP92340, as
amended from time to time pursuant to the terms thereof.
(aa) "Joint Intertie Scheduling Office" or "JISO" means the group of
Bonneville, Portland, and PacifiCorp schedulers, which, among
other things, accepts PNW-PSW Intertie Preschedules.
8
(bb) "Maintenance Cost" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any fiscal year any
maintenance Direct Costs for Bonneville's PNW AC Intertie,
maintenance Indirect Costs for Bonneville's PNW AC Intertie, and
maintenance Overhead Costs for Bonneville's PNW AC Intertie for
such fiscal year, each being determined in accordance with section
II of Exhibit I.
(cc) "MW" means megawatt.
(dd) "Northwest Intertie Agreements" means the agreement between
Bonneville and PacifiCorp, Contract No. DE-MS79-94BP94332, as
amended from time to time pursuant to the terms thereof, and the
agreement between Bonneville and Portland, Contract No. DE-MS79-
87BP92340, as amended from time to time pursuant to the terms
thereof.
(ee) "Operating Plan" means, subject to subsection 13(o), with respect
to any fiscal year commencing on or after the day on which the
annual costs rate set forth in Exhibit B has been approved on an
interim or final basis by FERC, the written document containing
the information described in subsection 13(c), as such document
may be amended pursuant to section 13, 14, or 16.
(ff) "Operations Cost" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any fiscal year any
Allocated Direct Costs for Bonneville's PNW AC Intertie,
operations Indirect Costs for Bonneville's PNW AC Intertie, and
operations Overhead Costs for Bonneville's PNW AC Intertie for
such fiscal year, each being determined in accordance with section
I of Exhibit I.
(gg) "Other Costs" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, Bonneville's other costs for
Bonneville's PNW AC Intertie described in and determined pursuant
to section V of Exhibit I.
9
(hh) "Overhead Cost" means administrative and general costs, support
service costs, or other costs similar in nature which are
distributed or allocated by Bonneville to Bonneville's PNW AC
Intertie. Overhead Costs are not included in Direct Costs,
Allocated Direct Costs, or Indirect Costs. The methods for
determining Overhead Costs are set forth in sections I.E, II.E,
and III.B of Exhibit I.
(ii) "Pacific Northwest" or "PNW" means the area defined as the Pacific
Northwest in the Pacific Northwest Electric Power Planning and
Conservation Act, 16 U.S.C. section 839a(14).
(jj) "Pacific Time" means Pacific Standard Time and Pacific Daylight
Time as each is in force.
(kk) "PNW AC Intertie" means facilities including, but not limited to,
the following: two 500 kV transmission lines extending from John
Day Substation to the Malin Substation and to the California-
Oregon border; portions of John Day, Grizzly, and Malin
Substations and the Sand Springs, Fort Rock, and Sycan
Compensation Stations; a portion of the Buckley-Summer Lake 500 kV
transmission line and associated substations; portions of the
Buckley-Marion and Marion-Alvey 500 kV transmission lines and
associated facilities; a portion of Bonneville's capacity rights
in the Summer Lake-Malin 500 kV transmission line; Bonneville's
rights in the Meridian-Malin 500 kV transmission line and
Bonneville's share of ownership of the Alvey-Meridian 500 kV
transmission line; Captain Jack Substation; the 500 kV
transmission line from Captain Jack Substation to the California-
Oregon border; and any modifications, additions, improvements, or
other alterations thereto.
(ll) "PNW AC Intertie Operational Transfer Capability" means the PNW AC
Intertie Rated Transfer Capability as reduced by limitations
beyond the control of the Parties, and operational limitations (as
determined by Bonneville in accordance with the agreement between
Bonneville and PacifiCorp, Contract No. DE-MS79-94BP94332, as
amended from time to time pursuant to the terms thereof, and with
10
the agreement between Bonneville and Portland, Contract No. DE-
MS79-87BP92340, as amended from time to time pursuant to the terms
thereof, and in accordance with Prudent Utility Practice)
resulting from, among other things, line or equipment outages,
stability limits, or loopflow.
(mm) "PNW AC Intertie Rated Transfer Capability" means the north-to-
south and south-to-north capability of the PNW AC Intertie to
transfer power in a reliable manner as determined consistent with
Prudent Utility Practice.
(nn) "Pacific Northwest-Pacific Southwest Intertie" or "PNW-PSW
Intertie" means the DC transmission line between the Celilo
Converter Station in The Dalles, Oregon, and the Sylmar Converter
Station near Los Angeles, California, the PNW AC Intertie, and the
AC Intertie in California including, without limitation, the
California-Oregon Transmission Project.
(oo) "Pacific Northwest Non-Federal Utility" means any electric utility
that serves retail load in the region consisting of (1) the states
of Oregon, Washington, and Idaho, the portion of the state of
Montana west of the Continental Divide, and such portions of the
States of Nevada, Utah, and Wyoming as are within the Columbia
River Basin drainage basin, and (2) any contiguous areas, not in
excess of seventy-five air miles from the area referred to in (1)
above, which areas are a part of the service area of a rural
electric cooperative power customer served by Bonneville on the
effective date of the Pacific Northwest Power Planning and
Conservation Act (P.L. 96-501) having a distribution system from
which it serves both within and without such region.
(pp) "Power Scheduling Costs" means, upon and after the effective date
of Exhibit B pursuant to this Agreement, Bonneville's total power
scheduling costs (as described in section VII of Exhibit I) as
functionalized and allocated in accordance with section VII of
Exhibit
11
I to determine Power Scheduling Costs for Bonneville's PNW AC
Intertie.
(qq) "Preschedule" means the schedule submitted by Puget to the JISO
pursuant to paragraph 4(b)(1) for transactions prepared each
Working Day for the period beginning 2400 hours of the current
Working Day through 2400 hours of the next Working Day.
(rr) "Prudent Utility Practice" means, at any particular time, the
generally accepted practices, methods, and acts in the electrical
utility industry in the Western Systems Coordinating Council area
prior thereto that would achieve the desired result or, if there
are no such practices, methods, and acts, the practices, methods,
and acts which, in the exercise of reasonable judgment in the
light of facts known at the time the decision was made, could have
been expected to achieve the desired result consistent with
reliability and safety.
(ss) "Real-time Schedule" means a schedule, or change to the
Preschedule, submitted during the period which begins when the
Preschedule is deemed by the JISO to be complete and concludes at
2400 hours on the day for which the Preschedule is submitted by
Puget.
(tt) "Reinforcement" means any transmission plant modification,
addition, improvement, or other alteration to the Federal Columbia
River Transmission System which is not a Replacement or an Upgrade
and which is made pursuant to subsection 7(c).
(uu) "Reinforcement Costs" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any Reinforcement, the
Direct Costs, Indirect Costs, Overhead Costs, and AFUDC for such
Reinforcement, all capitalized to plant-in-service together with
(1) simple interest on the foregoing costs accrued from the date
on which Bonneville stops accruing AFUDC on the foregoing costs
until the due date of the bill to Puget for the foregoing costs
pursuant to subparagraph 9(b)(2)(B) and (2) the costs of removal
and any salvage credit with respect to any PNW AC Intertie
facility removed on
12
account of such Reinforcement. Reinforcement Costs do not include
capitalized general plant cost. The method for determining
Reinforcement Costs for Bonneville's PNW AC Intertie is set forth
in section III of Exhibit I.
(vv) "Replacement" means for any transmission plant addition,
betterment, renewal and equipment or facility that takes the place
of or adds to any existing equipment or facility on Bonneville's
PNW AC Intertie that does not increase Bonneville's PNW AC
Intertie Rated Transfer Capability.
(ww) "Replacement Costs" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any Replacement, the
Direct Costs, Indirect Costs, Overhead Costs, and AFUDC for such
Replacement, all capitalized to plant-in-service together with (1)
simple interest on the foregoing costs accrued from the date on
which Bonneville stops accruing AFUDC on the foregoing costs until
the due date of the bill to Puget for the foregoing costs pursuant
to subparagraph 9(b)(2)(B) and (2) the costs of removal and any
salvage credit with respect to any PNW AC Intertie facility
removed on account of such Replacement. General Plant Cost is not
included in Replacement Costs. The method for determining
Replacement Costs for Bonneville's PNW AC Intertie is set forth in
section III of Exhibit I.
(xx) "Revised Adjusted Capacity Ownership Price" means a price
calculated pursuant to column 3, section B of Exhibit D and
section IV.B of the CO-94 rate in Exhibit A.
(yy) "Revised Adjusted Lump Sum Payment" means a Revised Adjusted
Capacity Ownership Price multiplied by Puget's Capacity Ownership
Share (in kilowatts), as described with more particularity in
section E of Exhibit D.
(zz) "Scheduler" means the person authorized by a Party to accept or
submit schedules pursuant to section 4 and authorized to
implement,
13
interpret, and vary the scheduling procedures set forth in such
section pursuant to this Agreement.
(aaa) "Scheduling Percentage" means the percentage of the PNW AC
Intertie Rated Transfer Capability owned by Puget pursuant to this
Agreement, which percentage is determined by dividing Puget's
Capacity Ownership Share by the PNW AC Intertie Rated Transfer
Capability.
(bbb) "Scheduling Share" means, for any given hour, the MW amount equal
to the product of Puget's Scheduling Percentage and the PNW AC
Intertie Operational Transfer Capability for such hour.
(ccc) "Scheduling Utility" means either (i) a Pacific Northwest Non-
Federal Utility that serves a retail service area and operates a
generation control area, or (ii) a Pacific Northwest Non-Federal
Utility designated by Bonneville as a "computed requirements
customer" or its equivalent.
(ddd) "Term" means the period of effectiveness of this Agreement set
forth in subsection 2(a).
(eee) "Third AC Intertie" means the Third AC Intertie Project, which
project increased the PNW AC Intertie Rated Transfer Capability by
1600 MW in a north-to-south direction and by 1225 MW in a south-to-
north direction.
(fff) "Third AC Intertie Project" means the Third AC Intertie System
Reinforcement and the construction of the Alvey-Meridian 500 kV
transmission line and of facilities related to such transmission
line during the period from July 1984 through December 1993.
(ggg) "Third AC Intertie System Reinforcement" means the improvements,
additions and modifications to the PNW AC Intertie constructed
during the period from July 1984 through December 1993 plus the
construction of the Captain Jack substation and of facilities
related to
14
such substation during the period from July 1984 through December
1993.
(hhh) "Upgrade" means any MW increase to Bonneville's PNW AC Intertie
Rated Transfer Capability which arises from or is related to an
increase to the PNW AC Intertie Rated Transfer Capability.
(iii) "Working Day" means any day other than Saturday, Sunday, and a
legal holiday recognized by the Federal government or Puget.
2. TERM AND TERMINATION
(a) This Agreement shall become effective as of the later of (1) the
date of execution and delivery of this Agreement by both of the
Parties, and (2) the date by which this Agreement has, with
respect to Puget, been approved, accepted for filing or otherwise
permitted to become effective by FERC; provided, that if FERC
approves this Agreement for filing or otherwise permits this
Agreement to become effective with any change or new condition,
this Agreement shall not be or become effective unless both of the
Parties have agreed in writing, and until the date by which both
of the Parties have so agreed to such change or new condition. To
the extent Puget is required to submit this Agreement to FERC,
Puget shall submit this Agreement to FERC for approval no later
than three Working Days after the date on which this Agreement is
executed and delivered by both Parties. Bonneville shall provide
Puget with a copy of the executed Agreement on the next Working
Day after Bonneville executes the Agreement. Without limiting any
of the foregoing, Puget shall use best efforts to obtain from FERC
on the earliest possible date (following the date on which Puget
is required to submit this Agreement to FERC pursuant to this
subsection 2(a)) FERC's acceptance for filing or permission that
this Agreement become effective in accordance with this subsection
2(a). This Agreement shall continue in effect so long as any
facilities of the PNW AC Intertie are in existence and operable,
unless otherwise
15
earlier terminated by written agreement of both of the Parties or
unless terminated pursuant to the terms of this Agreement. All
liabilities incurred under this Agreement shall be preserved until
satisfied.
(b) Notwithstanding subsection 2(a), no Capacity Ownership Rights may
be exercised by Puget until payment is made by Puget pursuant to
paragraph 9(a)(1) and received by Bonneville.
(c) If Bonneville does not receive the payment from Puget pursuant to
paragraph 9(a)(1), then Bonneville shall have the option to
terminate this Agreement by delivering to Puget written notice of
such termination.
(d) Notwithstanding subsection 2(a), if Bonneville incurs End of Term
Costs, the following provisions of this Agreement, and all rights
and obligations thereunder, shall continue in full force and
effect until Bonneville renders its final bill to Puget pursuant
to subsection 9(b), unless this Agreement is earlier terminated by
mutual agreement of the Parties: subsections 2(b), 2(c), and
2(d), sections 1, 7, 8, 9, 12, 13, 14, 15, 16, 18, 19, 20, 21, 22,
and 23, and Exhibits A, B, C, D, F, G, H, and I. All liabilities
incurred under such provisions of this Agreement shall be
preserved until satisfied.
(e) If this Agreement has not become effective pursuant to subsection
2(a) within 12 months following the date upon which Bonneville
executes and delivers this Agreement to Puget, this Agreement
shall be void ab initio and of no force or effect.
3. CAPACITY RIGHTS
(a) Purchase and Sale of Capacity
Pursuant to the terms and conditions of this Agreement, Puget
purchases from Bonneville and Bonneville sells to Puget the
Capacity Ownership Rights.
16
(b) Right to Wheel for Third Parties
No later than 30 days after the Effective Date, Puget shall notify
Bonneville in writing of Puget's decision to utilize its
Scheduling Share pursuant to either paragraph 3(b)(1) or paragraph
3(b)(2), and Puget shall have the right to utilize its Scheduling
Share pursuant to the paragraph Puget elects. Prior to
Bonneville's receipt of such notification, Puget shall utilize its
Scheduling Share pursuant to paragraph 3(b)(1). If Puget fails to
make an election within the prescribed time period, Puget shall be
deemed to have elected the option set forth in paragraph 3(b)(1).
(1) No Third Party Wheeling
(A) Except as expressly provided in subparagraph 3(b)(1)(B),
Puget shall not use its Scheduling Share to transmit
power or energy (except for inadvertent power flows)
that Puget does not own at the California-Oregon border
or for which transmission Puget receives any revenue
that would be reportable in Puget's accounting system
where revenues received for wheeling for other entities
would be booked.
(B) If Puget's Scheduling Share is not fully utilized by
Puget in any hour, Bonneville may schedule for such hour
Bonneville's transactions (including, without
limitation, Bonneville wheeling for other entities) and
wheel such transactions over the unused portion of
Puget's Scheduling Share for such hour but no longer
than such hour. Puget shall be compensated for such
wheeling solely by the payments as described in sections
3(b)(1)(B)(i) and (ii) below. For purposes of this
subparagraph 3(b)(1)(B), Puget's Scheduling Share shall
be deemed to be not fully utilized in a given hour to
the extent that Puget has not scheduled, or does not
schedule, on a Preschedule or Real-time Schedule basis,
17
any transaction for such hour on any MW amount of
Puget's Scheduling Share. In return for Puget's
Scheduling Share being made available to Bonneville
pursuant to this subparagraph 3(b)(1)(B), Bonneville
shall pay Puget
(i) an amount equal to the product of (1) all
wheeling revenues received by Bonneville from
providing short term wheeling in a north-to-south
direction under the IS-93 rate, section II.A, or
its successor to other entities in such hour, and
(2) the ratio of Puget's unused Scheduling Share
in such hour to the total amount of PNW AC
Intertie Operational Transfer Capability made
available by Bonneville for such wheeling in such
hour, and
(ii) an amount equal to the product of (1) all
wheeling revenues received by Bonneville from
providing short term wheeling in a south-to-north
direction under the IS-93 rate, section II.A or
its successor to other entities in such hour, and
(2) the ratio of Puget's unused Scheduling Share
in such hour to the total amount of PNW AC
Intertie Operational Transfer Capability made
available by Bonneville for such wheeling in such
hour; provided, however, that Bonneville shall not
be required to make payments for such south-to-
north wheeling pursuant to this section
3(b)(1)(B)(ii) earlier than two years after the
Effective Date.
Bonneville shall make payments pursuant to this
subparagraph 3(b)(1)(B) in accordance with paragraph
9(f)(1).
18
(C) During an outage resulting from maintenance activities
on the PNW AC Intertie performed by Bonneville other
than maintenance activities undertaken due to
emergencies or uncontrollable forces, the following
shall apply:
(i) When Puget's Scheduling Share for any given hour
is reduced as a consequence of such outage which
reduces in Bonneville's PNW AC Intertie
Operational Transfer Capability such that Puget's
Scheduling Share for such hour is less than the MW
amount of the aggregate of Puget's net firm
transactions identified by Puget to Bonneville
pursuant to section 3(b)(1)(C)(iv) for such hour,
Bonneville shall, subject only to sections
3(b)(1)(C)(ii) and (iii) and to the immediately
succeeding sentence, wheel on a firm basis that
portion of Puget's firm transactions that equals
the difference between Puget's Scheduling Share
for such hour and the MW amount of the aggregate
of Puget's firm transactions for such hour up to,
but not in excess of, Puget's Capacity Ownership
Share. Notwithstanding the foregoing, Bonneville
shall only be obligated to provide such wheeling
to the extent that each party with whom Puget is
conducting such firm transactions has received a
sufficient AC Intertie capacity allocation in
California to accommodate such transactions.
Puget shall pay the IS-93 rate, section II.A, or
its successor for such wheeling pursuant to this
section 3(b)(1)(C)(i) in accordance with
subsection 9(d).
(ii) Bonneville shall not be obligated to provide such
wheeling to Puget pursuant to section
19
3(b)(1)(C)(i) if no PNW AC Intertie Operational
Transfer Capability is available to Bonneville
after Bonneville has scheduled all of Bonneville's
Firm Schedules. For purposes of this section,
"Bonneville's Firm Schedules" shall mean schedules
for assured delivery or other firm transmission
contracts pursuant to the Long-Term Intertie
Access Policy, as revised or amended, or its
successor, and schedules for Bonneville's firm
power and energy sales and exchange transactions.
(iii) Bonneville shall not be obligated to provide such
wheeling to Puget pursuant to section
3(b)(1)(C)(i) until Bonneville has successfully
developed software to allow Bonneville to provide
such wheeling to Puget or until October 1, 1994,
whichever occurs sooner.
(iv) No later than ten Working Days prior to the first
day of deliveries under a firm transaction, Puget
shall identify such firm transaction to
Bonneville. Puget shall identify such firm
transaction to Bonneville by providing to
Bonneville a copy of Puget's contract for such
firm transaction (after information considered
proprietary by Puget has been redacted by Puget).
Bonneville shall review such contract to verify
that the transaction is firm. If Puget and its
contractor represent or state in writing that the
transaction set forth in their contract is firm,
Bonneville shall accept that written
representation or statement as dispositive of the
question of whether such transaction is firm.
Implementation of such procedures in this section
3(b)(1)(C)(iv) may be varied by the
20
mutual agreement of the Parties' Schedulers.
Such mutual agreement may, but need not, be
written.
(D) Puget retains any and all rights of access which it
would otherwise have to Bonneville's PNW-PSW Intertie
through the Long-Term Intertie Access Policy, as revised
or amended, or its successor.
(2) Third Party Wheeling
(A) Puget may use its Scheduling Share to transmit any and
all power and energy, whether or not such power or
energy is owned by Puget. Puget shall have no
obligation under this Agreement to make available to
Bonneville any portion of Puget's Scheduling Share which
is unused in any hour, and Bonneville shall not schedule
over Puget's Scheduling Share without Puget's prior
consent.
(B) Puget hereby waives any and all rights of access to
Bonneville's PNW-PSW Intertie through the Long-Term
Intertie Access Policy, as revised or amended, or its
successor; provided, however, that Bonneville may, at
its option, provide Puget with access to Bonneville's
PNW-PSW Intertie pursuant to any provision of the Long-
Term Intertie Access Policy, as revised or amended, or
its successor.
(C) Puget shall provide Bonneville with the information set
forth in sections 3(b)(2)(C)(i) through 3(b)(2)(C)(iii)
when Puget uses its Scheduling Share to export from the
Pacific Northwest energy or power received from third
parties. Such exports of energy or power on a real-time
basis or for durations of less than four months are
excluded from this obligation. For exports of four
21
months or longer duration made on behalf of third
parties pursuant to paragraph 3(b)(2), such information
shall include:
(i) the name and business address of the third party;
(ii) the amount of power or energy and the duration of
the transaction; and
(iii) the name of the recipient or purchaser of such
power.
Any additional information needed by Bonneville will be
obtained from such third party.
4. SCHEDULING
(a) Puget (and only Puget) shall be entitled to schedule on the PNW AC
Intertie, in any hour, a MW amount up to Puget's Scheduling Share
for such hour. The MW amount of Puget's Scheduling Share deemed
to be scheduled on the PNW AC Intertie pursuant to this Agreement,
in any hour, shall be determined as the net of Puget's north-to-
south schedules and south-to-north schedules (net schedules) for
such hour.
(b) Puget shall submit all schedules of its Scheduling Share on its
own behalf in accordance with the procedures set forth in
paragraphs 4(b)(1) and 4(b)(2). Such procedures may be varied by
the mutual agreement of the Parties' Schedulers. Such mutual
agreement may, but need not, be written. All hours referenced in
paragraphs 4(b)(1) and 4(b)(2) are Pacific Time.
(1) Preschedules
(A) Bonneville shall make available to Puget on each Working
Day as soon as practicable after 0800 hours
22
information regarding the PNW AC Intertie Operational
Transfer Capability with respect to Preschedules. In
the event an emergency or uncontrollable force causes a
change in the PNW AC Intertie Operational Transfer
Capability, Bonneville shall notify Puget of such change
as soon as practicable.
(B) If Long-Term Intertie Access Policy Condition 1 Formula
Allocation Procedures or their successor (Condition 1)
are expected by Bonneville to become effective,
Bonneville shall so notify Puget no later than 0930
hours on the Working Day prior to the day on which
Condition 1 is expected to become effective. Bonneville
shall notify Puget no later than 0930 hours on the
Working Day prior to the day on which Condition 1 ceases
to be in effect.
(C) Puget shall submit its Preschedule to the Joint Intertie
Scheduling Office no later than 1000 hours on each
Working Day if Condition 1 is in effect. If Condition 1
is not in effect, Puget shall submit its Preschedule to
the JISO no later than 1430 hours on each Working Day.
(2) Real-time Scheduling
(A) Real-time Schedules shall be arranged through
Bonneville's real-time scheduling office. Bonneville's
real-time Scheduler shall make reasonable efforts to
receive Real-time Schedules; provided, however, that
Bonneville's real-time Scheduler may, but is not
required to, accept Real-time Schedules between 1500 and
2200 hours on the Working Day preceding the day for
which such Real-time Schedule is submitted.
23
(B) Real-time Schedules shall be arranged for a full hour.
Arrangements shall be completed no later than 30 minutes
prior to that hour.
(C) Puget shall use best efforts to keep schedule changes to
a minimum; provided, however, that for purposes of this
subparagraph 4(b)(2)(C), "best efforts" shall not be
deemed to refer to efforts made regardless of their
economic effect.
(D) The requirements set forth in subparagraphs 4(b)(2)(B)
and 4(b)(2)(C) do not preclude schedule changes at other
times as may be deemed necessary by any control area
operators or other entities involved in effectuating
such schedule changes. Such control area operators and
other entities shall be notified by Bonneville of such
schedule changes as soon as practicable in accordance
with Prudent Utility Practice for purposes of
coordinating ramps and proper accounting. Such schedule
changes shall be deemed to occur at mid-ramp. The mid-
ramp time and the integrated value for the hour shall be
subject to the mutual agreement by such control area
operators and other entities.
(E) Subject to compliance with subparagraphs 4(b)(2)(A)
through 4(b)(2)(D) and with other applicable PNW AC
Intertie scheduling practices then in effect, Bonneville
shall make Puget's schedule change.
24
(c) Bonneville shall make deliveries of power or energy to the
California-Oregon border or the John Day Substation, as
appropriate, pursuant to schedules submitted in accordance with
this section 4; provided, however, that Bonneville shall not be
required to make such deliveries in an hour to the extent that
Puget's schedule exceeds Puget's Scheduling Share for such hour,
except as may be expressly provided pursuant to subparagraph
3(b)(1)(C).
5. UPGRADES
(a) Bonneville shall consult with the Committee one time each year
regarding any plans for Upgrades.
(b) Prior to the completion of an Upgrade, Bonneville shall provide to
Puget information in writing regarding estimated costs and the MW
amount of such Upgrade, to the extent that such information is
available to Bonneville.
(c) As soon as practicable following the completion of an Upgrade,
Bonneville shall notify Puget in writing of the following: (1)
the MW amount of such Upgrade; (2) the capital and related costs
(less any amount of such costs collected by Bonneville through
rates or charges other than pursuant to the CO-94 rate in Exhibit
A), if any, to Bonneville for completing or implementing such
Upgrade; and (3) calculations of (A) Puget's Capacity Ownership
Percentage multiplied by the MW amount of such Upgrade and (B)
Puget's Capacity Ownership Percentage multiplied by the capital
and related costs, if any, to Bonneville for completing or
implementing such Upgrade. Puget may elect to acquire a share of
such Upgrade in an amount up to Puget's Capacity Ownership
Percentage multiplied by the MW amount of such Upgrade. Within
100 days from receipt of such written notice from Bonneville,
Puget shall notify Bonneville in writing of Puget's decision
regarding such acquisition. If Puget elects to acquire, pursuant
to this subsection 5(c), a portion of such Upgrade, Puget's notice
to Bonneville shall include the percentage of such Upgrade that
Puget elects to acquire (Acquisition Percentage). If
25
Puget fails to notify Bonneville within such 100-day period, Puget
shall be deemed to have elected not to acquire any of such
Upgrade.
(d) If Puget elects to acquire a portion of an Upgrade pursuant to
subsection 5(c), the cost to Puget shall be Puget's Acquisition
Percentage multiplied by the capital and related costs for such
Upgrade pursuant to the CO-94 rate and subsection 9(c) (less any
amount of such cost collected by Bonneville through rates or
charges other than pursuant to the CO-94 rate in Exhibit A), if
any, incurred by Bonneville for completing or implementing such
Upgrade. Puget shall pay such costs pursuant to such payment
terms as may be mutually agreed to in writing by the Parties.
(e) If Puget's Acquisition Percentage with respect to an Upgrade
equals its Capacity Ownership Percentage and the Acquisition
Percentage of any other Capacity Owner with respect to such
Upgrade is less than its Capacity Ownership Percentage, then the
following shall apply:
(1) Bonneville shall, in a timely manner, provide written notice
simultaneously to Puget and to each other Capacity Owner
(whose Acquisition Percentage equals its Capacity Ownership
Percentage) of the MW amount equal to 100 percent of that
portion of an Upgrade offered to, but not acquired by, the
Capacity Owners pursuant to subsection 5(c) (Unacquired
Share). If Puget and each of such other Capacity Owners have
agreed in writing to an apportionment as among themselves of
the Unacquired Share (Apportionment), Puget may, within 45
days following receipt of such written notice from
Bonneville, by written notice request Bonneville to offer in
writing to Puget such portion of the Unacquired Share as has
been apportioned to Puget pursuant to the Apportionment, and
Bonneville shall offer to Puget such portion of the
Unacquired Share.
(2) If Bonneville does not receive from Puget and from each
Capacity Owner referred to in paragraph 5(e)(1) the requests
for offer pursuant to paragraph 5(e)(1) within the 45-day
period
26
specified in such paragraph, Bonneville shall, in a timely
manner, offer in writing simultaneously to Puget and to each
other Capacity Owner (whose Acquisition Percentage equals its
Capacity Ownership Percentage), respectively, a portion of an
Upgrade offered to, but not acquired by, the other Capacity
Owners pursuant to paragraph 5(e)(1) (Second Unacquired
Share) up to the "Additional Share Offered" determined as
follows:
Additional Share Offered = (A divided by B) x C
where: A = Puget's Capacity Ownership Percentage.
B = Percentage equal to the sum of Capacity
Ownership Percentages of Capacity Owners that
acquired respectively an Acquisition Percentage
equal to their Capacity Ownership Percentage.
C = Second Unacquired Share.
(3) Within 30 days following Puget's receipt of Bonneville's
written offer pursuant to paragraph 5(e)(2), Puget shall
notify Bonneville in writing of Puget's decision regarding
acquisition of the Additional Share Offered. If Puget fails
to notify Bonneville within such 30-day period, Puget shall
be deemed to have elected not to acquire any of the
Additional Share Offered. If Puget elects pursuant to this
paragraph 5(e)(3) to acquire any or all of the Additional
Share Offered, then:
(A) Puget shall include in its notice to Bonneville pursuant
to this paragraph 5(e)(3) such share (Additional Share
Acquired) of the Additional Share Offered as Puget
elects to acquire pursuant to this paragraph 5(e)(3),
and
(B) the cost to Puget with respect to such acquisition shall
be equal to the proportion of the Additional Share
Acquired to such Upgrade multiplied by the capital and
related costs for such Upgrade pursuant to the CO-94
27
rate and subsection 9(c) (less any amount of such costs
collected by Bonneville through charges other than
payments by Puget pursuant to subsection 5(d) or
subparagraph 5(e)(3)(B)), if any, to Bonneville for
completing or implementing such Upgrade. Puget shall
pay such costs pursuant to such payment terms as may be
mutually agreed to in writing by the Parties.
(f) All capacity offered but not acquired pursuant to subsections 5(c)
and (e) shall for purposes of this Agreement remain with
Bonneville.
(g) After Puget has either accepted or declined all offers of capacity
by Bonneville pursuant to subsections 5(c) and (e), Puget's
Capacity Ownership Share, Capacity Ownership Percentage, and
Scheduling Percentage in Exhibit C shall be revised to reflect
changes resulting from Puget's elections pursuant to subsections
5(c) and (e). Revision of Exhibit C shall be pursuant to
subsection 19(d). Exhibit G shall be revised accordingly pursuant
to subsection 19(i).
6. SALE OR ASSIGNMENT
(a) This Agreement or any interest herein shall not be transferred,
sold, alienated, or assigned by Puget to any person without
Bonneville's prior and express written consent. Such consent
shall not be unreasonably withheld. In determining whether to
grant its consent under this subsection 6(a), Bonneville shall
take into consideration information including, but not limited to,
whether the person or entity to whom this Agreement or any
interest therein is proposed to be transferred, sold, alienated,
or assigned is a person or entity entitled to request and receive
transmission services pursuant to section 211 of the Federal Power
Act, whether such person or entity can either provide its own
scheduling services or has contracted with another entity to
provide such scheduling services, whether such person or entity
has the financial capability to meet the payment obligations under
this Agreement, and whether the person or entity is either
electrically interconnected to Bonneville's transmission system or
has
28
contractual arrangements for wheeling with others who are
electrically interconnected to Bonneville's transmission system.
This Agreement shall inure to the benefit of and be binding upon
the Parties, their respective legal representatives, permitted
assigns, and successors in interest. Any transfer, sale,
alienation, or assignment made by Puget in violation of this
section 6 shall be void ab initio and without any force or effect
whatsoever.
(b) Bonneville hereby consents to the transfer, sale, alienation, or
assignment by Puget to any other Capacity Owner of all or part of
its Capacity Ownership Share and all of Puget's rights and
obligations pursuant to this Agreement with respect thereto.
Bonneville hereby further consents to the transfer, sale,
alienation, or assignment by Puget of the entire Agreement and of
all of Puget's rights and obligations under this Agreement to a
Scheduling Utility.
(c) Bonneville hereby consents to the assignment by Puget of this
Agreement or of any of Puget's rights under this Agreement as
security for any indebtedness, whether present or future, of Puget
pursuant to any mortgage, trust, security agreement or similar
instrument of indebtedness (each such instrument, a Debt
Instrument) made by and between Puget and any mortgagee, trustee,
secured party or holder of such instrument of indebtedness,
respectively; provided, however, that if Puget has defaulted in
the performance of its obligations under any Debt Instrument, such
that the mortgagee, trustee, secured party or holder of such Debt
Instrument, as the case may be, would be entitled at that time to
accelerate the amount of indebtedness under such Debt Instrument,
Puget shall give Bonneville prompt written notice in reasonable
detail of such default and shall, at Bonneville's election, enter
into good faith discussions with Bonneville regarding the cure of
such default.
(d) If Puget transfers, sells, alienates, or assigns, with
Bonneville's consent, all or any portion of this Agreement and any
rights and obligations pursuant to this Agreement to any person or
party, Puget shall give Bonneville written notice of such
transfer, sale, alienation,
29
or assignment within 10 days after the execution and delivery of
the agreement effectuating such transaction by all parties to such
transaction.
7. OPERATION, MAINTENANCE, AND MANAGEMENT
(a) Pursuant to the terms and conditions of the Northwest Intertie
Agreements, Bonneville is the operator of the PNW AC Intertie. As
such, Bonneville is responsible for the dispatch of the PNW AC
Intertie in accordance with Prudent Utility Practice.
Bonneville's duties as operator of the PNW AC Intertie shall
include, but are not limited to, consistent with Prudent Utility
Practice and Northwest Intertie Agreements: (1) determining the
PNW AC Intertie Operational Transfer Capability; (2) implementing
and assisting in rectifying emergency outages on the PNW AC
Intertie due to system emergencies or uncontrollable forces; (3)
implementing maintenance outages; and (4) giving and receiving
switching orders on the PNW AC Intertie. In making any
determination or in taking any other action referred to in the
immediately preceding sentence, Bonneville shall give fair
consideration to Puget's interests to the extent such interests
have been expressed to Bonneville in writing. Bonneville shall
operate, maintain, and manage Bonneville's PNW AC Intertie, and
study, plan, and implement Upgrades, consistent with Prudent
Utility Practice.
(b) Bonneville shall determine and revise as necessary the PNW AC
Intertie Rated Transfer Capability consistent with Prudent Utility
Practice and engineering studies based on then existing
reliability criteria developed by the North American Electric
Reliability Council, the Western Systems Coordinating Council, the
Northwest Power Pool, and Bonneville. In the event the PNW AC
Intertie Rated Transfer Capability is changed, Bonneville shall
promptly notify Puget in writing of such change and the new PNW AC
Intertie Rated Transfer Capability. If and to the extent that the
reliability criteria for determining the PNW AC Intertie Rated
Transfer Capability
30
change substantially, Bonneville shall notify Puget in writing of
such change.
(c) If at any time during the Term, Bonneville's PNW AC Intertie Rated
Transfer Capability becomes less than 3450 MW, or if at any time
during the Term there is an imminent likelihood that Bonneville's
PNW AC Intertie Rated Transfer Capability would become less than
3450 MW, then Bonneville shall reinforce the Federal Columbia
River Transmission System so as to raise Bonneville's PNW AC
Intertie Rated Transfer Capability to 3450 MW or otherwise to
prevent Bonneville's PNW AC Intertie Rated Transfer Capability
from becoming less than 3450 MW. Puget's Capacity Ownership Share
shall not be decreased on account of any failure by Bonneville to
reinforce the Federal Columbia River Transmission System pursuant
to this subsection 7(c).
(d) In the event that Bonneville implements a Reinforcement pursuant
to subsection 7(c), Bonneville shall equitably allocate the
Reinforcement Cost for such Reinforcement between Bonneville and
Puget based on factors including, but not limited to, load
responsibility, contractual obligation and generation integration
responsibility. Any equitable allocation or agreed to allocation
(pursuant to the immediately succeeding sentence) of a
Reinforcement Cost pursuant to this subsection 7(d) shall be
reflected as a Reinforcement Cost in an Operating Plan proposed by
Bonneville pursuant to section 13. To the extent that Bonneville
and Puget have agreed in writing to an allocation of a
Reinforcement Cost incurred by Bonneville pursuant to an agreement
or modification referred to in subsection 8(b), the Reinforcement
Cost so allocated shall not be subject to arbitration pursuant to
section 14 or section 15. Any Reinforcement Cost not allocated to
Puget pursuant to this subsection 7(d) shall not be payable by
Puget pursuant to this Agreement.
(e) Bonneville shall provide Puget notice of maintenance outages in
accordance with the accepted standards for notice on the PNW AC
Intertie. Such notice shall include an evaluation of the impact
on
31
Puget's Scheduling Share. In scheduling or planning maintenance
on PNW AC Intertie, Bonneville shall give fair consideration to
Puget's interests to the extent such interests have been expressed
to Bonneville in writing.
8. EXISTING AGREEMENTS
(a) Bonneville shall use good faith efforts to maintain in effect the
Interconnection Agreement or its successor.
(b) Bonneville shall use its best efforts to maintain Puget's rights
under this Agreement (i) by making no modification to the
Northwest Intertie Agreements, (ii) by not entering into any other
agreement with respect to the ownership, operation, maintenance,
or management of the PNW AC Intertie, and (iii) by making no
modification to the agreements referred to in the immediately
preceding clause (ii) that would have a substantial negative
impact on Puget's rights pursuant to sections 3, 4, 7, or to
subsection 9(b), 9(c), or 11(a) without Puget's prior written
consent. Without limiting, modifying, or otherwise affecting any
of its rights pursuant to sections 9, 13, 14, 15, and 16, Puget
hereby consents to Bonneville's modification of the Northwest
Intertie Agreements or Bonneville's entering into other agreements
or modification to such Agreements with respect to the ownership,
operation, maintenance, or management of the PNW AC Intertie to
the extent that such modification or such agreement is made or
entered into by Bonneville for the purpose of performing
Bonneville's obligations pursuant to subsection 7(c).
9. PAYMENT PROVISIONS
As full compensation for their respective payment obligations under
this Agreement, Puget shall make payments to Bonneville in accordance
with the provisions of this section 9, and Bonneville shall make
payments and refunds to Puget in accordance with the provisions of this
section 9.
32
(a) Lump Sum Payment
(1) As soon as practicable after the Effective Date, Bonneville
shall render a bill to Puget for the Initial Lump Sum Payment
(less the negotiation deposit, if any, with applicable
interest as described in section C of Exhibit D) and such
bill shall include as an attachment and as part of such bill
a completed section C of Exhibit D, setting forth the
calculation of such Initial Lump Sum Payment due Bonneville
in accordance with section IV.A of the CO-94 rate set forth
in Exhibit A. Puget shall make such payment pursuant to the
CO-94 rate and the applicable GTRSPs set forth in Exhibit A.
Each of Bonneville and Puget agrees that section C of Exhibit
D is consistent with the CO-94 rate set forth in Exhibit A on
the Effective Date.
(2) Calculation and Billing of the Adjusted Capacity Ownership
Price
(A) Approximately December 1995, or as soon as practicable
thereafter, Bonneville shall, in accordance with section
IV.B of the CO-94 rate set forth in Exhibit A, calculate
the Adjusted Capacity Ownership Price to reflect actual
construction costs of the facilities listed in section A
of Exhibit D and the actual AFUDC with respect to such
facilities. Such calculation shall be made in
accordance with column 2, section B of Exhibit D.
(B) Promptly after Bonneville has calculated the Adjusted
Capacity Ownership Price pursuant to subparagraph
9(a)(2)(A), Bonneville shall render a bill or refund
voucher to Puget, and such bill or refund voucher shall
include as an attachment and as part of such bill or
refund voucher section A of Exhibit D (with a completed
column 2), section B of Exhibit D (with a completed
column 2), and a completed section D of Exhibit D
reflecting the Adjusted Lump Sum Payment. If the
33
Adjusted Lump Sum Payment is greater than the Initial
Lump Sum Payment, Puget shall pay to Bonneville, within
45 days from the date of such bill or within such other
time period to which the Parties may mutually agree, the
amount set forth in such bill, which amount shall be
equal to the amount set forth on line 7, section D of
Exhibit D (such amount including interest as set forth
on line 6, section D of Exhibit D). If the Adjusted
Lump Sum Payment is less than the Initial Lump Sum
Payment, Bonneville shall pay to Puget, within 30 days
after the date of such refund voucher, the amount set
forth in such refund voucher, which amount shall be
equal to the amount set forth on line 7, section D, of
Exhibit D (such amount including interest as set forth
on line 6, section D, of Exhibit D). Each of Bonneville
and Puget agrees that sections A, B, and D of Exhibit D
are consistent with the CO-94 rate set forth in Exhibit
A on the Effective Date.
(3) Calculation and Billing of the Revised Adjusted Capacity
Ownership Price
(A) After payment is made by Puget pursuant to subparagraph
9(a)(2)(B), or a refund is made by Bonneville to Puget
pursuant to subparagraph 9(a)(2)(B), Bonneville may, in
accordance with the CO-94 rate set forth in Exhibit A,
make one or more adjustments to the Adjusted Capacity
Ownership Price; provided, that any such adjustment
shall be made by Bonneville within 30 days after the
date on which (i) Bonneville receives, pursuant to any
audit with respect to the Third AC Intertie Project by
Bonneville, Transmission Agency of Northern California,
PacifiCorp or any other entity performing work for
Bonneville on the Third AC Intertie Project, payment
from Transmission Agency of Northern California,
PacifiCorp, or any other entity performing work for
Bonneville on the Third AC Intertie Project, or
(ii) Bonneville pays, pursuant to any audit with respect
to the Third AC Intertie Project by Bonneville,
Transmission Agency of Northern California, PacifiCorp,
or any other entity performing work for Bonneville on
the Third AC Intertie Project, any amount to
Transmission Agency of Northern California,
34
PacifiCorp, or any other entity performing work for
Bonneville on the Third AC Intertie Project; and
provided, further, that no adjustment of the Adjusted
Capacity Ownership Price or of any Revised Adjusted
Capacity Ownership Price shall be made by Bonneville
after December 31, 2005.
(B) Promptly after Bonneville has calculated a Revised
Adjusted Capacity Ownership Price, Bonneville shall
render to Puget a bill or refund voucher with respect to
such Revised Adjusted Capacity Ownership Price and such
bill or refund voucher shall include as an attachment
and as part of such bill or refund voucher section A of
Exhibit D (with a completed column 2 and a completed
column with respect to each Revised Adjusted Capacity
Ownership Price), section B of Exhibit D (with a
completed column 2 and a completed column with respect
to each Revised Adjusted Capacity Ownership Price), and
a completed section E of Exhibit D reflecting the
current Revised Adjusted Capacity Ownership Price and
the current Revised Adjusted Lump Sum Payment. If the
current Revised Adjusted Lump Sum Payment with respect
to such Revised Adjusted Capacity Ownership Price is
greater than the Adjusted Lump Sum Payment or the
immediately preceding Revised Adjusted Lump Sum Payment,
as the case may be, then Puget shall pay to Bonneville,
within 45 days from the date of such bill or within such
other time period to
35
which the Parties may mutually agree, the amount set
forth in the bill referred to in this subparagraph
9(a)(3)(B), which amount shall be equal to the amount
set forth on line 7, section E, of Exhibit D with
respect to the current Revised Adjusted Lump Sum Payment
(such amount including interest as set forth on line 6,
section E, of Exhibit D). If the current Revised
Adjusted Lump Sum Payment is less than the Adjusted Lump
Sum Payment or the immediately preceding Revised
Adjusted Lump Sum Payment, as the case may be,
Bonneville shall pay to Puget, within 30 days after the
date of such refund voucher, the amount set forth in the
refund voucher referred to in this subparagraph
9(a)(3)(B), which amount shall be equal to the amount
set forth on line 7, section E of Exhibit D with respect
to the current Revised Adjusted Lump Sum Payment (such
amount including interest as set forth on line 6,
section E of Exhibit D). Each of Bonneville and Puget
agrees that section E of Exhibit D is consistent with
the CO-94 rate set forth in Exhibit A on the Effective
Date.
(4) For purposes of implementing the CO-94 rate, the following
shall apply:
(A) the calculations pursuant to paragraphs 9(a)(2) and
9(a)(3) shall be deemed to be the adjustment "to reflect
the difference between the actual and the estimated
Capacity Ownership Price" required under section IV.B of
the CO-94 rate;
(B) the calculations of interest pursuant to footnote 2 of
section D of Exhibit D and footnote 2 of section E of
Exhibit D shall be deemed to be the computation of
"interest using the weighted average interest rate on
Bonneville's outstanding bonds" required pursuant to
section IV.B of the CO-94 rate;
36
(C) the calculations of the Adjusted Capacity Ownership
Price and of the Revised Adjusted Capacity Ownership
Price pursuant to paragraphs 9(a)(2) and 9(a)(3) shall
be deemed to be the determination of the "actual
Capacity Ownership Price" required pursuant to section
IV.B of the CO-94 rate;
(D) as used in the CO-94 rate, the terms "Bonneville's PNW
AC Intertie," "PNW AC Intertie," "Third AC Intertie,"
"Third AC Intertie Project," and "Third AC Intertie
System Reinforcement" shall be deemed to have the
respective meanings of such terms set forth in section
1;
(E) as used in the CO-94 rate, the term "Capacity Ownership
Share" shall be deemed to mean "Capacity Ownership
Percentage" as defined in section 1;
(F) the indirect costs and overhead costs described in
footnote 5 of section B of Exhibit D shall be deemed to
be the indirect costs and overhead costs referred to in
section III.A of the CO-94 rate; and
(G) the last paragraph of section I.B of the General
Transmission Rate Schedule Provisions set forth in
Exhibit A shall be deemed to read in its entirety as
follows:
The meaning of terms used in the transmission rate
schedules shall be as defined in the Agreement or
in provisions which are attached to the Agreement
or, if not defined therein, such terms shall be as
defined in any of the above Acts.
37
(5) For purposes of application of the CO-94 rate set forth in
Exhibit A, no provision of the General Transmission Rate
Schedule Provisions set forth in Exhibit A, other than the
following provisions of the General Transmission Rate
Schedule Provisions set forth in Exhibit A (or their
successors in substance), shall have any application or
effect with respect to this Agreement:
(A) section I;
(B) section III.A;
(C) the last three sentences of section IV.A, without regard
to subsections 1, 2, 3, 4, 5, 6 and 7 of such section
IV.A;
(D) subsection 4 of section IV.A;
(E) the first paragraph and the first sentence of the second
paragraph of subsection 5 of section IV.A; and
(F) for purposes of subsection 16(e) of this Agreement and
as deemed necessary by Bonneville to correct
mathematical and computational errors on bills,
subsection 7 of section IV.A.
(b) Annual Charges
(1) Payments Pursuant to AC-93 Rate
(A) From and after the first Working Day after Bonneville
receives payment from Puget pursuant to paragraph
9(a)(1), Bonneville shall bill Puget on the monthly
power bill in accordance with the AC-93 rate set forth
in Exhibit A. Puget shall pay such bill in accordance
with the applicable GTRSPs set forth in Exhibit A.
38
(B) For purposes of application of the AC-93 rate, no
provision of the General Transmission Rate Schedule
Provisions set forth in Exhibit A, other than the
following provisions of the General Transmission Rate
Schedule Provisions set forth in Exhibit A (or their
successors in substance), shall have any application or
effect with respect to this Agreement:
(i) section I;
(ii) section III.A;
(iii) the last three sentences of section IV.A,
without regard to subsections 1, 2, 3, 4, 5, 6
and 7 of such section IV.A;
(iv) the first sentence of subsection 3 of section
IV.A;
(v) subsection 4 of section IV.A;
(vi) the first paragraph and the first sentence of
the second paragraph of subsection 5 of section
IV.A;
(vii) the first paragraph of subsection 6 of section
IV.A; and
(viii) as deemed necessary by Bonneville to correct
mathematical and computational errors on bills,
subsection 7 of section IV.A.
(C) The last paragraph of section I.B of the General
Transmission Rate Schedule Provisions set forth in
Exhibit A shall be deemed to read in its entirety as
follows:
39
The meaning of terms used in the transmission rate
schedules shall be as defined in the Agreement or
in provisions which are attached to the Agreement
or, if not defined therein, such terms shall be as
defined in any of the above Acts.
(D) Bonneville hereby agrees that the provisions of the AC-
93 rate shall have no application or effect with respect
to the following:
(i) any replacement of the series capacitor banks
containing polychlorinated biphenyl at the Sand
Springs, Sycan and Fort Rock Substations; and
(ii) any replacement commenced prior to the Effective
Date or not completed prior to September 30, 1995.
(E) Upon and after the effective date of the annual costs
rate set forth in Exhibit B, Bonneville shall cease
billing Puget pursuant to the AC-93 rate.
(2) Payments Pursuant to Annual Costs Rate
From and after the date the annual costs rate set forth in
Exhibit B becomes effective, the following shall apply:
(A) Operations Costs, Maintenance Costs, General Plant
Costs, Other Costs, Contracts and Rates Costs, Power
Scheduling Costs, and End of Term Costs
(i) During each fiscal year during the Term,
Bonneville shall bill Puget on the monthly power
bill, and Puget shall pay, pursuant to Exhibit B,
40
forecast Operations Costs, forecast Maintenance
Costs, General Plant Costs, forecast Other Costs,
forecast Contracts and Rates Costs, forecast Power
Scheduling Costs, and forecast End of Term Costs
for such fiscal year. Such costs shall be,
respectively, the forecast Operations Costs,
forecast Maintenance Costs, General Plant Costs,
forecast Other Costs, forecast Contracts and Rates
Costs, forecast Power Scheduling Costs, and
forecast End of Term Costs set forth in the
Operating Plan for the fiscal year in which such
month occurs.
(ii) Within eight months after the end of each fiscal
year during the Term (such fiscal year being
hereinafter referred to as a "Fiscal Year"),
Bonneville shall determine and calculate, pursuant
to Exhibit I, Schedules A, B, D, E, F, G, and H,
actual Operations Costs, actual Maintenance Costs,
General Plant Costs, actual Other Costs, actual
Contracts and Rates Costs, actual Power Scheduling
Costs, and actual End of Term Costs for the Fiscal
Year most recently ended.
(iii) If, based on the calculation performed pursuant
to section 9(b)(2)(A)(ii), the sum of the forecast
Operations Costs, forecast Maintenance Costs,
General Plant Costs, forecast Other Costs,
forecast Contracts and Rates Costs, forecast Power
Scheduling Costs, and forecast End of Term Costs
for the Fiscal Year is greater than the sum of the
actual Operations Costs, actual Maintenance Costs,
General Plant Costs, actual Other Costs, actual
Contracts and Rates Costs, actual Power Scheduling
Costs, and actual End
41
of Term Costs for the Fiscal Year, Bonneville
shall refund to Puget the difference between such
forecast costs and such actual costs as a lump sum
payment, with interest pursuant to section
9(b)(2)(A)(vi), within 30 days after the date on
which the calculation referred to in section
9(b)(2)(A)(ii) is made. Bonneville shall,
promptly following the date on which the
calculation of such difference is made, provide
Puget written notice of such refund. Within the
30-day period referred to in the first sentence of
this section 9(b)(2)(A)(iii), Bonneville shall
provide to Puget an Operating Plan amended in
accordance with subsection 13(k) containing
revised schedules in the format set forth in
Exhibit I, Schedules A, B, D, E, F, G, and H,
respectively, with a completed last column
reflecting the difference between actual and
forecast Operations Costs, actual and forecast
Maintenance Costs, General Plant Costs, actual and
forecast Other Costs, actual and forecast
Contracts and Rates Costs, actual and forecast
Power Scheduling Costs, and actual and forecast
End of Term Costs for the Fiscal Year.
(iv) If, based on the calculation performed pursuant
to subparagraph 9(b)(2)(A)(ii), the sum of the
actual Operations Costs, actual Maintenance Costs,
General Plant Costs, actual Other Costs, actual
Contracts and Rates Costs, actual Power Scheduling
Costs, and actual End of Term Costs for the Fiscal
Year is equal to or less than 105 percent, but
greater than 100 percent, of the sum of the
forecast Operations costs, forecast Maintenance
Costs, General Plant Costs, forecast Other Costs,
forecast Contracts and
42
Rates Costs, forecast Power Scheduling Costs, and
forecast End of Term Costs in the Operating Plan
for the Fiscal Year, Bonneville shall bill to
Puget on the monthly power bill the difference
between such actual costs and such forecast costs
as a lump sum charge, with interest pursuant to
section 9(b)(2)(A)(vi), within 30 days after the
date on which the calculation referred to in
section 9(b)(2)(A)(ii) is made. Puget shall pay
such bill in accordance with the Billing
Provisions. Within the 30-day period referred to
in the immediately preceding sentence, Bonneville
shall provide to Puget an amended Operating Plan
containing revised schedules in the format set
forth in Exhibit I, Schedules A, B, D, E, F, G,
and H, respectively, with a completed last column
reflecting the difference between actual and
forecast Operations Costs, actual and forecast
Maintenance Costs, General Plant Costs, actual and
forecast Other Costs, actual and forecast
Contracts and Rates Costs, actual and forecast
Power Scheduling Costs, and actual and forecast
End of Term Costs for the Fiscal Year.
(v) If, based on the calculation performed pursuant
to section 9(b)(2)(A)(ii), the sum of the actual
Operations Cost, actual Maintenance Cost, General
Plant Costs, actual Other Costs, actual Contracts
and Rates Costs, actual Power Scheduling Costs,
and actual End of Term Costs for the Fiscal Year
is greater than 105 percent of the sum of the
forecast Operations Cost, forecast Maintenance
Cost, General Plant Costs, forecast Other Costs,
forecast Contracts and Rates Costs, forecast Power
Scheduling Costs, and forecast
43
End of Term Costs for the Fiscal Year, Bonneville
shall bill to Puget on the monthly power bill the
difference between such actual costs and such
forecast costs as a lump sum charge, with interest
pursuant to section 9(b)(2)(A)(vi), within 30 days
after the date on which the calculation referred
to in section 9(b)(2)(A)(ii) is made. Puget shall
pay such bill in accordance with the Billing
Provisions; provided, however, that Bonneville
shall not bill Puget pursuant to this section
9(b)(2)(A)(v) any amount which exceeds 105 percent
of the sum of the forecast Operations Costs,
forecast Maintenance Costs, General Plant Costs,
forecast Other Costs, forecast Contracts and Rates
Costs, forecast Power Scheduling Costs, and
forecast End of Term Costs set forth in the
Operating Plan for the Fiscal Year unless and
until such amount which exceeds 100 percent of the
sum of the forecast Operations Costs, forecast
Maintenance Costs, General Plant Costs, forecast
Other Costs, forecast Contracts and Rates Costs,
forecast Power Scheduling Costs, and forecast End
of Term Costs set forth in the Operating Plan for
the Fiscal Year has been included in an Operating
Plan amended pursuant to subsection 13(k).
(vi) Simple interest shall be accrued on payments or
refunds due pursuant to this paragraph 9(b)(2)
with respect to any fiscal year during the Term
using the weighted average interest rate on
Bonneville's outstanding bonds or other debt
instruments then used by Bonneville and such
interest shall accrue from (and including) the
date of the last day of such fiscal year to (but
44
excluding) the date of refund to Puget or to (but
excluding) the due date of a payment due
Bonneville.
(B) Replacement Cost and Reinforcement Cost
Bonneville shall bill Puget on the monthly power bill
Replacement Costs for any Replacement and Reinforcement
Costs for any Reinforcement. Bonneville shall render
such bill within 15 months following the date on which
the project work order for such Replacement or such
Reinforcement, as the case may be, is closed. Puget
shall pay such bill pursuant to Exhibit B and sections
9(b)(2)(B)(i), 9(b)(2)(B)(ii), 9(b)(2)(B)(iii) and
9(b)(2)(B)(iv).
(i) If the forecast Replacement Cost for a
Replacement is greater than the actual Replacement
Cost for such Replacement or if the forecast
Reinforcement Cost for a Reinforcement is greater
than the actual Reinforcement Cost for such
Reinforcement, Bonneville shall bill Puget the
actual Replacement Cost for such Replacement or
the actual Reinforcement Cost for such
Reinforcement, as the case may be. Bonneville
shall provide to Puget an Operating Plan amended
in accordance with subsection 13(k) containing a
revised schedule in the format set forth in
Exhibit I, Schedule C, reflecting the actual and
forecast Replacement Cost for such Replacement or
the actual and forecast Reinforcement Cost for
such Reinforcement, as the case may be.
(ii) If, for each Replacement or Reinforcement, the
actual Replacement Cost or actual
45
Reinforcement Cost is equal to or less than 105
percent, but greater than 100 percent, of the
forecast Replacement Cost or forecast
Reinforcement Cost, Bonneville shall bill Puget
such actual Replacement Cost or such actual
Reinforcement Cost, as the case may be, on the
monthly power bill and Puget shall pay such bill
pursuant to subparagraph 9(b)(2)(B). Bonneville
shall provide to Puget an amended Operating Plan
containing a revised schedule in the format set
forth in Exhibit I, Schedule C, reflecting the
difference between the actual and forecast
Replacement Cost for such Replacement or the
actual and forecast Reinforcement Cost for such
Reinforcement.
(iii) If, for each Replacement or Reinforcement, the
actual Replacement Cost or actual Reinforcement
Cost is greater than 105 percent of the forecast
Replacement Cost or forecast Reinforcement Cost,
Bonneville shall bill Puget such actual
Replacement Cost or such actual Reinforcement
Cost, as the case may be, on the monthly power
bill and Puget shall pay such bill pursuant to
subparagraph 9(b)(2)(B); provided, however, that
Bonneville shall not bill Puget pursuant to this
subparagraph 9(b)(2)(B) any amount which exceeds
105 percent of the forecast Replacement Cost or
forecast Reinforcement Cost, as the case may be,
unless and until such amount which exceeds
100 percent of such forecast Replacement or such
forecast Reinforcement Cost, as the case may be,
has been included in an amended Operating Plan
pursuant to subsection 13(k).
46
(iv) Charges pursuant to sections 9(b)(2)(B)(i), (ii)
and (iii) for Replacement Costs and Reinforcement
Costs shall accrue simple interest pursuant to
section III.D of Exhibit I.
(c) Upgrade Charges
For purposes of implementing the CO-94 rate, the following shall
apply:
(1) as used in the CO-94 rate, the term "upgrade" shall be deemed
to mean "Upgrade" as defined in section 1, the term "rated
transfer capability" shall be deemed to mean "PNW AC Intertie
Rated Transfer Capability" as defined in section 1 and the
term "AFUDC" shall be deemed to have the meaning set forth
for such term in section 1;
(2) the "Capacity Ownership Share of the capital and related cost
of the upgrade," referred to in section III.B of the CO-94
rate shall be deemed to be the costs pursuant to subsection
5(d) and subparagraph 5(e)(3)(B), as applicable; and
(3) "construction costs (including direct, indirect and overhead
costs) and AFUDC" referred to in section III.B of the CO-94
rate and "related costs" referred to in section III.B of the
CO-94 rate together shall be deemed to be Upgrade costs and
shall be determined in the same manner in which Replacement
Costs are determined pursuant to section III of Exhibit I;
provided, however, that expenses that are properly allocable
to an Upgrade (i.e., "related costs" referred to in section
III.B of the CO-94 rate) in accordance with generally
accepted accounting principles (as defined in Exhibit I) may
be included by Bonneville in Upgrade costs for such Upgrade.
47
(d) Payments of Charges Pursuant to Section 3(b)(1)(C)(i)
Bonneville shall bill Puget for wheeling provided pursuant to
section 3(b)(1)(C)(i) on Puget's monthly power bill in accordance
with the IS-93 rate, section II.A, or its successor, set forth in
Exhibit A and Puget shall pay such bill in accordance with the IS-
93 rate, section II.A, or its successor, set forth in Exhibit A;
provided, however, that under any successor to the IS-93 rate,
Puget shall not be obligated to pay any rate or charge greater
than the rate or charge payable by any other party to which
Bonneville provides nonfirm wheeling services on Bonneville's PNW
AC Intertie for such party's nonfirm transaction of a duration
similar to Puget's wheeling transaction pursuant to section
3(b)(1)(C)(i).
(e) Suspension for Failure to Perform
(1) If at any time during the term of this Agreement Bonneville
does not receive payment due and owing to Bonneville pursuant
to paragraph 9(a)(2) or 9(a)(3) or to subsection 9(b) or
9(d), Bonneville shall be entitled to suspend performance of
its obligations to Puget pursuant to section 4 without
incurring any liability to Puget therefor; provided, that
Bonneville shall not be entitled to suspend performance
pursuant to this paragraph 9(e)(1) earlier than five Working
Days following receipt from Bonneville by Puget of written
notice of such suspension. Such suspension shall continue in
effect until the next Working Day following the Working Day
on which Puget makes payment in full to Bonneville of the
balance owed to Bonneville pursuant to paragraph 9(a)(2) or
9(a)(3) or to subsection 9(b) or 9(d). During the period of
such suspension, Puget shall not be entitled to participate
through the Committee in any review of an Operating Plan
commenced by the Committee pursuant to section 13 during such
period of suspension, or to participate in any arbitration
commenced by the Committee pursuant to sections 14 and 15
during such period of suspension, or to participate in any
audit commenced
48
by the Committee pursuant to section 16 during such period of
suspension.
(2) If during any period in any month Bonneville fails to make
deliveries in accordance with subsection 4(c), Puget shall be
entitled, without incurring any liability to Bonneville
therefor, to delay any payment due and owing to Bonneville by
Puget pursuant to subsection 9(b) or 9(d) for a period, equal
to the period during which Bonneville failed to make such
deliveries, commencing on the date the monthly power bill for
such month would otherwise be payable by Puget pursuant to
this Agreement; provided, however that Puget's entitlement
pursuant to this paragraph 9(e)(2) shall apply only with
respect to the amount of such monthly power bill to be paid
directly to Bonneville or its agent.
(f) Payments or Refunds by Bonneville
(1) Bonneville shall make any payment to Puget pursuant to
subparagraph 3(b)(1)(B) within 30 days following the end of
the month in which such payment becomes due to Puget pursuant
to subparagraph 3(b)(1)(B).
(2) Bonneville shall pay to Puget, in a lump sum, any refund due
to Puget pursuant to subsection 16(e) or paragraph 16(f)(2)
within 30 days following the date on which such refund
becomes due to Puget pursuant to subsection 16(e) or
paragraph 16(f)(2), respectively.
(3) Bonneville shall pay any refund, credit, or payment due to
Puget under section 18 pursuant to the terms and conditions
set forth in section 18.
(4) Each payment, credit or refund due to Puget by Bonneville
pursuant to this Agreement shall be made by Bonneville, at
Bonneville's option, (A) by check payable to the order of
Puget,
49
(B) by electronic funds transfer of immediately available funds
into such account as may be designated in writing by Puget
from time to time for such purpose or (C) by crediting the
amount of such payment, credit or refund on Puget's power
bill.
10. TRANSMISSION LOSSES
(a) To compensate Bonneville for transmission losses incurred by
Bonneville in making deliveries scheduled by Puget pursuant to
this Agreement, Puget shall make available, or arrange to have
made available, to Bonneville, at any point mutually acceptable to
the Parties at which the respective electric systems of Puget and
Bonneville are interconnected, on the corresponding hour 168 hours
later or on another hour to be agreed upon, the amounts of
electric power equal to Puget's net PNW AC Intertie schedule
multiplied by the appropriate loss factor specified in Exhibit E.
Puget's net PNW AC Intertie schedule shall be, for any given hour,
the absolute value of the sum of Puget's north-to-south schedules
(positive) and south-to-north schedules (negative) for such hour.
(b) Upon the conclusion of any review by Bonneville of the loss factor
in Exhibit E, Part A, pursuant to subsection 19(f), Bonneville
shall present the results of its review, including any revisions
to the loss factor in Exhibit E, Part A, to the Committee as part
of the Operating Plan provided to the Committee pursuant to
section 13. The Committee may make recommendations regarding such
results and any revisions to the loss factor in Exhibit E, Part A.
Only recommendations regarding assumptions (including, without
limitation, data inputs and source of date) made by Bonneville in
its review or revision of the loss factor in Exhibit E, Part A,
and recommendations regarding the results of such review or
revision shall be subject to arbitration pursuant to section 14.
(c) Puget's Scheduling Share shall not be reduced by any amount of
losses returned to Bonneville pursuant to subsection 10(a).
50
11. REMEDIAL ACTIONS
(a) Bonneville's Responsibilities
(1) Within five days after the Effective Date, Bonneville shall
notify Puget in writing of the plan for remedial actions
required to maintain the PNW AC Intertie Rated Transfer
Capability, which plan shall be consistent with Western
System Coordinating Council standards and Prudent Utility
Practice. If and to the extent that such plan is amended,
modified, or replaced, Bonneville shall, promptly following
such amendment, modification, or replacement, provide written
notice to Puget of such amendment, modification, or
replacement, as the case may be. Bonneville shall be
responsible for providing a capability to arm and having
available appropriate remedial actions, which may include
generator dropping, load tripping, or other acceptable
remedial actions, required to maintain the portion of
Bonneville's PNW AC Intertie Rated Transfer Capability not
purchased by Capacity Owners. Such remedial actions shall be
consistent with Western System Coordinating Council standards
and Prudent Utility Practice.
(2) Bonneville shall be responsible for generating appropriate
control signals for transmission to Puget for purposes of
effectuating remedial actions pursuant to this section.
(b) Puget's Responsibilities
(1) Puget shall be responsible for providing a capability to arm
and having available appropriate remedial actions, which may
include generator dropping, load tripping, or other remedial
actions required to maintain Puget's Capacity Ownership
Share. Such remedial actions shall be consistent with
Western System Coordinating Council standards, the plan
referred to in paragraph 11(a)(1) and Prudent Utility
Practice. Bonneville
51
may perform engineering analyses to confirm Puget's providing
capability to arm and having available appropriate remedial
actions pursuant to this paragraph 11(b)(1).
(2) In any given hour, Puget shall be responsible for providing
sufficient remedial actions, which may include generator
dropping, load tripping, or other acceptable remedial
actions, to maintain Puget's schedule on the PNW AC Intertie
for such hour. To the extent that load tripping or generator
dropping is required as a remedial action by Puget pursuant
to this paragraph 11(b)(2) in any given hour, the required
amount of such load tripping or such generator dropping shall
be determined by dividing the amount of power scheduled by
Puget on Puget's Scheduling Share in such hour by the total
amount of power scheduled on the PNW AC Intertie in such hour
and multiplying the result by the total amount of generation
or load (in MW) to be armed for the PNW AC Intertie in such
hour.
(3) Puget shall provide, design, operate, and maintain the
necessary equipment to accept control signals from Bonneville
and to transmit such signals to Puget's generator dropping,
load tripping, or other remedial action sites, and to arm and
initiate the appropriate control action(s). Such design,
operation, and maintenance shall be consistent with Western
System Coordinating Council standards, the plan referred to
in paragraph 11(a)(1), and Prudent Utility Practice.
(4) Puget and Bonneville may mutually agree that Bonneville will,
pursuant to terms and conditions mutually acceptable to the
Parties, provide the remedial actions required of Puget
pursuant to subsection 11(b).
52
12. CAPACITY OWNERS' COMMITTEE
(a) Composition of Committee
Puget may appoint one representative (and an alternate who may act
in the absence of such representative) as a member of the Capacity
Owners' Committee (Committee). If during any period Puget fails
to appoint a representative to the Committee, Puget waives any and
all rights during such period that would otherwise have accrued to
it, individually or as a member of the Committee, pursuant to
sections 12, 13, 14, 15, and 16 of this Agreement. Puget hereby
appoints as its representative pursuant to this subsection the
following representative and alternate to the Committee:
Representative: Vice President Power Planning
Alternate: Manager Power Contracts
(b) Convening Meetings
(1) Any Capacity Owner that has appointed a representative to the
Committee may convene a meeting of the Committee pursuant to
the procedures set forth in subsection 12(e). The Capacity
Owner convening a Committee meeting shall be responsible for
preparing any necessary notices, identifying the subject
matter and issues to be discussed, and transmitting notices
and relevant documents to the other Committee members and, if
appropriate, to Bonneville.
(2) At the written request of any Capacity Owner that has
appointed a representative to the Committee, Bonneville shall
attend Committee meetings.
(3) The Committee may conduct business only at a properly
convened meeting at which a quorum, as defined in subsection
12(c), is present. The Committee shall make or convey any
53
request, designation, recommendation, notice, appointment,
submission, audit report or exception, or statement to which
Bonneville is required to respond or which creates or
triggers an obligation of Bonneville, pursuant to this
Agreement, only upon a decision of the Committee made at a
properly convened meeting at which a quorum is present.
(4) Each fiscal year, Bonneville shall convene an annual meeting
of the Committee. The purpose of such annual meeting shall
be to discuss the Operating Plan delivered, pursuant to
subsection 13(b), to each Capacity Owner that has appointed a
representative to the Committee. Bonneville shall convene
such annual meeting no earlier than 15 days, but no later
than 30 days, following the date of such delivery of the
Operating Plan.
(5) In addition to the meeting referred to in paragraph 12(b)(4),
Bonneville may, at its discretion, convene meetings of the
Committee, pursuant to the procedures set forth in
subsection 12(e), to present to the Committee any information
Bonneville deems relevant.
(c) Meeting Quorum
The respective representatives of all of the Capacity Owners that
have appointed a representative to the Committee, less one, shall
constitute a quorum.
(d) Meetings by Telephone Conference
Committee meetings pursuant to the Capacity Ownership Agreements
may be conducted by telephone provided all Capacity Owners and, if
appropriate, Bonneville, are notified pursuant to the procedures
set forth in subsection 12(e) of any such meeting.
54
(e) Meeting Notices
(1) All Committee meeting notices pursuant to the Capacity
Ownership Agreements shall be provided in writing no less
than 14 days prior to such meeting.
(2) Any Committee meeting notice required by this section shall
be deemed properly made if delivered in person, by electronic
facsimile, or by mail or other qualified delivery service,
postage prepaid, to the person specified below:
If to Bonneville:
Group Vice President for Marketing, Conservation and
Production
Bonneville Power Administration
905 NE 11th Avenue
Portland, OR 97232
Telephone (503) 230-5152
Facsimile (503) 230-5207
If to Puget:
Vice President Power Planning
Puget Sound Power & Light Company
411 108th Avenue NE 15th Floor
Bellevue, WA 98004-5515
Telephone (206) 462-3137
Facsimile (206) 462-3175
If to Seattle:
Director, Power Management Division
Seattle City Light
1111 Third Avenue, Room 420
Seattle, WA 98101
Telephone (206) 386-4530
Facsimile (206) 386-4955
55
If to PNGC:
Director of Power Management
Pacific Northwest Generating Cooperative
711 NE Halsey Street, Suite 200
Portland, OR 97232
Telephone (503) 288-1234
Facsimile (503) 288-2334
If to Snohomish:
Manager of Power Supply
Public Utility District No. 1 of Snohomish
County, Washington
2320 California Street
P.O. Box 1107
Everett, WA 98201
Telephone (206) 258-8211
Facsimile (206) 258-8305
If to Tacoma:
Light Division Superintendent
Tacoma Public Utilities
3628 S. 35th Street
Tacoma, WA 98411
Telephone (206) 502-8294
Facsimile (206) 502-8628
Attendance at a meeting by a representative of a Capacity
Owner constitutes waiver by such Capacity Owner of notice of
such meeting.
(3) Either Party may, by written notice to the other Party and to
the Capacity Owners other than Puget, change the designation,
address, or facsimile number of the person so specified by it
in subsection 12(a) or paragraph 12(e)(2).
56
13. OPERATING PLAN AND AMENDMENTS TO THE OPERATING PLAN
(a) The provisions of this section shall become effective commencing
August 1, 1995; provided, however, that unless and until the
annual costs rate set forth in Exhibit B is approved by FERC on an
interim basis, Bonneville shall not have any right pursuant to
this Agreement to bill or charge to Puget, and Puget shall not
have any obligation pursuant to this Agreement to pay to
Bonneville, any amount pursuant to any Operating Plan.
(b) Delivery of Operating Plan
(1) On or before August 1, 1995, Bonneville shall deliver to each
Capacity Owner that has appointed a representative to the
Committee an Operating Plan for Bonneville's PNW AC Intertie
for fiscal year 1996 and an Operating Plan for Bonneville's
PNW AC Intertie for fiscal year 1997.
(2) Not later than one year preceding the first day of each
fiscal year, other than the fiscal years specified in
paragraph 13(b)(1), Bonneville shall deliver to each Capacity
Owner that has appointed a representative to the Committee an
Operating Plan for Bonneville's PNW AC Intertie for such
fiscal year.
(c) Each Operating Plan delivered pursuant to subsection 13(b) shall
contain the following information for Bonneville's PNW AC Intertie
with respect to forecast costs for the fiscal year to which such
Operating Plan pertains, and such Operating Plan may contain such
other information as Bonneville may deem relevant; and each
amendment of an Operating Plan delivered pursuant to subsection
13(k) shall contain the following information for Bonneville's PNW
AC Intertie with respect to forecast or actual costs, as
appropriate, for the fiscal year to which such Operating Plan
pertains, and such amendment may contain such other information as
Bonneville may deem relevant:
57
(1) a forecast of, or the actual, Allocated Direct Cost of
Operations Cost (pursuant to section I.C of Exhibit I),
Indirect Cost of Operations Cost (pursuant to section I.D of
Exhibit I), and Overhead Cost of Operations Cost (pursuant to
section I.E of Exhibit I) in the format set forth in Exhibit
I, Schedule A;
(2) a forecast of, or the actual, Direct Cost of Maintenance Cost
(pursuant to section II.B of Exhibit I), Indirect Cost of
Maintenance Cost (pursuant to section II.D of Exhibit I), and
Overhead Cost of Maintenance Cost (pursuant to section II.E
of Exhibit I) in the format set forth in Exhibit I, Schedule
B;
(3) a forecast of, or the actual, Direct Cost of Replacements and
Reinforcements (pursuant to section III.A of Exhibit I),
Indirect Cost and Overhead Cost of Replacements and
Reinforcements (pursuant to section III.B of Exhibit I), and
AFUDC of Replacements and Reinforcements (pursuant to section
III.C of Exhibit I) in the format set forth in Exhibit I,
Schedule C, for each Reinforcement and Replacement which is
expected to be, in the fiscal year to which the Operating
Plan pertains, a planned new start, construction work in
progress on a previously initiated Reinforcement or
Replacement, as the case may be, or a closed work order. The
forecast shall include for each such Reinforcement or
Replacement an estimate of the total cost of construction and
the cost to be incurred with respect to such Reinforcement or
Replacement during each fiscal year until the work order for
such Reinforcement or Replacement has been closed.
Bonneville may elect, but shall not be required, to include
in any such forecast the information set forth in the
immediately preceding sentence regarding any Replacement and
Reinforcement which is expected to be planned a new start in
any fiscal year following the fiscal year to which the
Operating Plan pertains. In the event Bonneville elects to
forecast Direct Cost, Indirect Cost, and Overhead Cost of any
Reinforcement or Replacement which is expected to be a
58
planned new start in any fiscal year subsequent to the fiscal
year to which the Operating Plan pertains, Bonneville shall
provide to the Committee such forecast costs, in the format
set forth in Exhibit I, Schedule C (together with additional
information pertinent to such forecast costs as required by
paragraph 13(c)(9)), 30 days prior to the date such Operating
Plan is delivered to the Committee pursuant to subsection
13(b). In addition, Bonneville shall include such forecast
costs in the Operating Plan delivered to the Committee
pursuant to subsection 13(b);
(4) the General Plant Cost (pursuant to section IV of Exhibit I)
in the format set forth in Exhibit I, Schedule D;
(5) a forecast of, or the actual, Other Costs (pursuant to
section V of Exhibit I) in the format set forth in Exhibit I,
Schedule E;
(6) a forecast of, or the actual, Contracts and Rates Costs
(pursuant to section VI of Exhibit I) in the format set forth
in Exhibit I, Schedule F;
(7) a forecast of, or the actual, Power Scheduling Costs
(pursuant to section VII of Exhibit I) in the format set
forth in Exhibit I, Schedule G;
(8) a forecast of, or the actual, End of Term Costs (pursuant to
section VIII of Exhibit I) in the format set forth in Exhibit
I, Schedule H. Such forecast shall include Bonneville's
proposed apportionment of such End of Term Costs among Puget
and Capacity Owners other than Puget and Bonneville's
rationale for such apportionment;
(9) additional information pertinent to the forecast costs,
actual costs, and General Plant Cost provided pursuant to
paragraphs 13(c)(1) through 13(c)(8), including, without
limitation, descriptions of the activities or projects and
explanations of the
59
costs comprising the Direct Cost components of such forecast
costs, actual costs, and General Plant Cost, and explanations
of MFU counts; and
(10) if Bonneville has reviewed the loss factor in Exhibit E, Part
A, pursuant to subsection 19(f), the Operating Plan shall
contain the results of such review, including any revision to
the loss factor in Exhibit E, Part A, pursuant to subsection
10(b), and any additional information pertinent to such
review.
(d) Requests by Committee
(1) No later than 15 days after the date on which the annual
meeting was convened pursuant to paragraph 12(b)(4), the
Committee may make a single request of Bonneville in writing
for:
(A) such supporting documentation, data, and information as
may be reasonably necessary to analyze (i) the Operating
Plan, or its constituent parts, delivered to the
Committee pursuant to subsection 13(b), or (ii) any
amendment to an Operating Plan pursuant to subsection
13(k); and
(B) such documentation, data, and information relating to
Bonneville's present or past activities or practices
concerning Bonneville's PNW AC Intertie and to
alternatives considered by Bonneville to costs or
activities described in the Operating Plan or any
amendment to an Operating Plan as may be reasonably
necessary for the Committee to formulate recommendations
pursuant to subsection 13(e);
provided, however, that with regard to requests for
documentation, data, and information pursuant to this
paragraph 13(d)(1), the Committee must designate in such
60
request the specific item in the Operating Plan or in any
amendment to an Operating Plan to which such requested
documentation, data, or information is directly related and
explain the need for such documentation, data, or
information. Such single request may contain multiple parts.
(2) The Committee shall use reasonable efforts to minimize and
limit the scope and number of parts of the request for
documentation, data, and information made pursuant to
paragraph 13(d)(1).
(3) Bonneville shall have 20 days from the date it receives any
request pursuant to paragraph 13(d)(1) to provide the
documentation, data, and information requested; provided,
however, that Bonneville shall be under no obligation (A) to
create additional documentation, data, or information, (B) to
provide documentation, data, or information that is not
readily available to it, (C) to provide to the Committee
documentation, data, or information that Bonneville has
previously provided to the Committee, or (D) to provide
documentation, data, or information that Bonneville would not
otherwise be required to provide or that would otherwise be
exempted from disclosure pursuant to the Freedom of
Information Act, 5 U.S.C. section 552 (including, without
limitation, the Freedom of Information Reform Act of 1986),
as amended or superseded, or any regulation and Executive
Order applicable to Bonneville.
(4) The Committee in such request shall designate one of its
members to be its representative for the sole purpose of
receiving such documentation, data, or information from
Bonneville pursuant to this subsection 13(d). Bonneville
shall deliver such documentation, data, or information to the
representative designated by the Committee to receive such
materials.
61
(5) For purposes of this subsection 13(d) and subsection 13(f),
each of Bonneville and the Committee shall cooperate and use
reasonable efforts to, in a timely manner, resolve disputes
regarding, and clarify requests for, documentation, data, and
information and responses to such requests.
(e) The Committee shall have 20 days from the date on which it
receives documentation, data, or information from Bonneville
pursuant to subsection 13(d) or, if none was requested, 50 days
from the date on which the annual meeting was convened pursuant to
paragraph 12(b)(4), whichever date is later, to recommend to
Bonneville in writing a revision or revisions to any forecast cost
or General Plant Cost in the Operating Plan. The Committee shall
have the time periods set forth in subsection 13(m) to recommend
to Bonneville in writing a revision or revisions to a forecast
cost or actual cost or General Plant Cost in any amendment to an
Operating Plan. Such recommendation shall set forth, at a
minimum, the exact revisions to the forecast cost or General Plant
Cost proposed by the Committee and the reasons for such revisions.
Failure of the Committee to recommend a revision or revisions to
all or any portion of a forecast cost or General Plant Cost in the
Operating Plan or a forecast cost or actual cost or General Plant
Cost in any amendment to an Operating Plan within the applicable
time limit set forth above shall be deemed to constitute
acceptance by the Committee of all portions of the forecast costs
and General Plant Cost of the Operating Plan for which the
Committee has not recommended a revision.
(f) No later than 15 days after receipt of a Committee recommendation
made pursuant to subsection 13(e), Bonneville may make a single
request (which may contain multiple parts) in writing of the
Committee for such supporting documentation, data, and information
as may be reasonably necessary to analyze the Committee's
recommendation, including without limitation, any estimated costs
or forecast costs contained in such recommendation; provided,
however, that the Capacity Owners that have appointed a
representative to the Committee shall be under no obligation (1)
to create additional
62
documentation, data, or information, (2) to provide documentation,
data, or information that is not readily available to the
Committee or to any Capacity Owner that has appointed a member to
the Committee, (3) to provide to Bonneville documentation, data,
or information that the Committee has previously provided to
Bonneville; provided, further, that with regard to requests for
documentation, data, and information pursuant to this subsection
13(f), (1) Bonneville must designate in such request the specific
item in the Committee's recommendation to which such requested
documentation, data, or information is directly related and
explain the need for such documentation, data, or information, and
(2) Bonneville shall use reasonable efforts, consistent with
Bonneville's needs as set forth in this subsection 13(f), to
minimize and limit the scope and number of parts of the request
for documentation, data, and information made pursuant to this
subsection. Such single request shall be made of the Committee by
delivering a copy of the request to each Capacity Owner that has
appointed a representative to the Committee. The Committee shall
have 20 days from the date of its receipt of Bonneville's request
to provide a single response containing the documentation, data,
and information requested.
(g) If the Committee makes any recommendation in writing pursuant to
subsection 13(e), Bonneville shall have the greater of 15 days
from the date of receipt of the requested documentation, data, and
information requested pursuant to subsection 13(f) or, if none was
requested, 30 days from the date of receipt of the Committee's
recommendations made pursuant to subsection 13(e) to, by written
notice to each Capacity Owner that has appointed a representative
to the Committee, accept the recommendation, accept the
recommendation in part, reject the recommendation, or propose an
action that is responsive to the Committee's recommendation and
that is different from Bonneville's proposal contained in the
Operating Plan. If Bonneville makes such a proposal, Bonneville
shall set forth in such written notice the exact revisions to the
Operating Plan. The Committee shall have 7 days from the date of
receipt of Bonneville's proposal to make any requests in writing
for supporting
63
documentation, data, and information as set forth in subsection
13(d). Bonneville shall have 7 days to respond to those requests
as set forth in subsection 13(d). Failure of Bonneville to
respond in writing to any recommendation of the Committee within
the applicable time period set forth in this subsection 13(g)
shall be deemed to constitute rejection of such recommendation.
(h) If Bonneville rejects all or any portion of the Committee's
recommendation, or if the Committee elects not to accept a
proposal made by Bonneville pursuant to subsection 13(g), then the
Committee may
(1) elect by written notice to Bonneville to refer to binding
arbitration, pursuant to section 14 and consistent with
subsections 13(i) and 14(b), that portion of such
recommendation of the Committee not accepted by Bonneville or
that portion of a recommendation of the Committee to which
Bonneville responded with a proposal pursuant to subsection
13(g); and
(2) elect by written notice to Bonneville to refer to nonbinding
arbitration pursuant to section 15 and consistent with
subsections 15(a) and 15(d), that portion of such
recommendation of the Committee not accepted by Bonneville or
that portion of a recommendation of the Committee to which
Bonneville responded with a proposal pursuant to subsection
13(g).
Failure of the Committee to elect to refer to arbitration
(A) such portion of any recommendation of the Committee not
accepted by Bonneville within 15 days following Bonneville's
rejection or acceptance in part of such recommendation of the
Committee pursuant to subsection 13(g), or
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(B) any proposal made by Bonneville pursuant to subsection 13(g)
within 15 days following Bonneville's written notice of such
proposal or, if documentation, data, or information was
requested by the Committee pursuant to subsection 13(g),
within 15 days following receipt by the Committee of such
documentation, data, or information pursuant to subsection
13(g),
shall be deemed to constitute acceptance by the Committee of
Bonneville's rejection or acceptance in part of the recommendation
of the Committee or of Bonneville's proposal and waiver by the
Committee of any right pursuant to this section 13 or to section
15 to arbitrate such recommendation or portion thereof.
(i) The Committee may, subject to the immediately succeeding sentence,
arbitrate, pursuant to subsection 13(h), any recommendation by the
Committee concerning a revision pursuant to this Agreement to a
loss factor set forth in any Operating Plan or in any amendment to
an Operating Plan or concerning any forecast cost or actual
(allocated or otherwise) cost set forth in any Operating Plan or
in any amendment to an Operating Plan (including the following
costs and related items set forth in any Operating Plan, or in any
amendment to an Operating Plan, pursuant to Exhibit I, Schedule A,
lines 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12 and 13; Exhibit I,
Schedule B, lines 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14
and 15; Exhibit I, Schedule C, lines 1, 2, 3, 4 and 5; Exhibit I,
Schedule D, lines 3, 4, 5, 6, 7, 8, 9, 10 and 11; Exhibit I,
Schedule E, lines 2 and 3; Exhibit I, Schedule F, lines 1, 2, 3,
4, 5, 6, 7, 8, and 9; Exhibit I, Schedule G, lines 1, 2, 3, 4, 5,
6 7, 8, and 9; and Exhibit I, Schedule H, lines 1, 2, 3, and 4).
The Committee's right pursuant to this subsection 13(i) to
arbitrate any such recommendation shall be subject to the
following limitations:
(1) if such recommendation, or portion thereof, includes a
Replacement Cost for a Replacement or a Reinforcement Cost
for a Reinforcement, and such Replacement Cost or
Reinforcement Cost was included in a previous Operating Plan
65
(either of such costs, a Previous Operating Plan Cost), the
Committee may arbitrate pursuant to this subsection 13(i)
such recommendation, or portion thereof, only to the extent
that such recommendation, or portion thereof, includes any
Replacement Cost or Reinforcement Cost in excess of the
Previous Operating Plan Cost;
(2) the Committee may arbitrate pursuant to this subsection 13(i)
any such recommendation, or portion thereof, pertaining to a
revision to a loss factor pursuant to this Agreement only to
the extent such arbitration is permitted by subsection 10(b);
(3) the Committee may arbitrate pursuant to this subsection 13(i)
any recommendation, or portion thereof, concerning an Other
Cost only to the extent that such Other Cost is a cost set
forth in an Operating Plan or amendment to an Operating Plan
pursuant to Exhibit I, Schedule E, line 2 and such
recommendation, or portion thereof pertains to whether such
Other Cost is properly allocated to Bonneville's PNW AC
Intertie pursuant to Exhibit I, section V;
(4) if the sum of the actual Operations Costs, actual Maintenance
Costs, General Plant Costs, actual Other Costs, actual
Contracts and Rates Costs, actual Power Scheduling Costs, and
actual End of Term Costs in any Operating Plan exceeds 105
percent of the sum of the forecast Operations Costs, forecast
Maintenance Costs, General Plant Costs, forecast Other Costs,
forecast Contracts and Rates Costs, forecast Power Scheduling
Costs, and forecast End of Term Costs set forth in such
Operating Plan or in any amendment to an Operating Plan, the
Committee may arbitrate pursuant to this subsection 13(i) any
such recommendation, or portion thereof, concerning any
actual cost for any activity or project described in such
Operating Plan only to the extent that such actual cost
exceeds 105 percent of the forecast cost for such activity or
such project; provided, however, that, without limiting any
of Puget's rights
66
and benefits pursuant to subsection 16(c), the Committee may
not arbitrate pursuant to this subsection 13(i) any
recommendation, or portion thereof, concerning any actual
cost for any activity or project described in such Operating
Plan or in any amendment to an Operating Plan if such actual
cost is less than 105 percent of the forecast for such
activity or such project;
(5) the Committee may not arbitrate, pursuant to this subsection
13(i), (a) the allocation by Bonneville pursuant to this
Agreement of any of its costs to overall overhead costs or to
overall indirect costs, or (b) the allocation by Bonneville
pursuant to this Agreement of a portion of Bonneville's
overall overhead costs and overall indirect costs to its
total system operations costs, its total system maintenance
costs, its total capital costs or its total indirect and
overhead power scheduling costs; provided, however, that
nothing in this paragraph (5) shall be deemed to prevent or
restrict the Committee from arbitrating pursuant to this
subsection 13(i) the level (rather than the allocation) of
any of Bonneville's Exhibit I, Schedule A, line 9 total
system operations indirect costs and line 11 total system
operations overhead costs; Bonneville's Exhibit I, Schedule
B, line 11 total system maintenance indirect costs and line
13 total system maintenance overhead costs; Bonneville's
total capital costs; Bonneville's Exhibit I, Schedule F,
line 6 total indirect contracts and rates costs and
Bonneville's Exhibit I, Schedule F, line 7 total overhead
contracts and rates costs; or Bonneville's Exhibit I,
Schedule G, line 6 total indirect power scheduling costs and
Bonneville's Exhibit I, Schedule G, line 7 total overhead
power scheduling costs;
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(6) the Committee may not arbitrate any recommendation, or any
portion thereof, regarding any amendment to an Operating Plan
made pursuant to sections 9(b)(2)(A)(iv) and 9(b)(2)(B)(ii),
or subsection 14(j), 16(e), or paragraph 16(f)(2);
(7) the Committee may not arbitrate any such recommendation, or
portion thereof, to the extent that in doing so the
arbitrators would be required to decide a matter of law in
order to render a decision pursuant to subsection 14(h). If,
subsequent to the Effective Date, Bonneville is given legal
authority to submit to binding arbitration matters of law,
Bonneville shall enter into good faith negotiations with
Puget and Capacity Owners other than Puget regarding a
revision to this paragraph 13(i)(7) enabling arbitration of
matters of law pursuant to this subsection 13(i) consistent
with such legal authority; and
(8) the Committee may not arbitrate any recommendation, or
portion thereof, regarding an allocation of a Reinforcement
Cost to the extent prohibited by subsection 7(d).
In arbitrating any recommendation, or portion thereof, pursuant to
this subsection 13(i), the Committee may raise in support of such
recommendation arguments regarding whether any forecast or actual
cost should be based upon activities different in degree, but not
in kind, from the activities upon which such forecast or actual
cost in the Operating Plan is based.
(j) Each Operating Plan provided pursuant to subsection 13(b) which
has completed the Committee review process set forth in
subsections 13(d) through 13(g) shall take effect on the first day
of the fiscal year to which such Operating Plan pertains and shall
remain in effect for the duration of such fiscal year.
(k) At any time during the fiscal year in which an Operating Plan is in
effect, or within 8 months after the end of such fiscal year,
Bonneville may amend such Operating Plan, pursuant to subsections
13(l) through 13(n), to reflect a different forecast or actual
Operations Cost, Maintenance Cost, General Plant Cost, Other Cost,
Contracts and Rates Cost, Power Scheduling Cost, or End of Term
Cost in such Operating Plan. At any time during the fiscal year
an Operating Plan
68
is in effect, or within 30 months after a work order for a
Replacement or Reinforcement is closed, Bonneville may amend such
Operating Plan, pursuant to subsections 13(l) through 13(n), to
reflect a different forecast cost or actual cost component for
such Replacement or Reinforcement.
(l) Any amendment made to any Operating Plan pursuant to subsection
13(k) shall be provided by delivery of a copy in writing of such
amendment by Bonneville to each Capacity Owner that has appointed
a representative to the Committee.
(m) Consideration of amendments to the Operating Plan pursuant to
subsection 13(l) shall be consistent with the procedures set forth
above in subsections 13(c) through 13(k), except that the time
limits set forth in such subsections shall be reduced as follows:
15 days shall be 7 days, 20 days shall be 10 days, 30 days shall
be 15 days, and 50 days shall be 25 days. For purposes of
computing the time limits in this subsection 13(m), the date
Bonneville provides the Capacity Owners with a proposed amendment,
pursuant to subsection 13(k), shall be deemed to be the date the
annual meeting was convened for purposes of paragraph 13(d)(1) and
subsection 13(e).
(n) Without limiting any of Puget's rights and benefits pursuant to
subsection 13(i) and sections 14 and 15, any Operating Plan
amended pursuant to section 9(b)(2)(A)(v) or 9(b)(2)(B)(iii), or
subsection 13(k) shall take effect when such amendment is accepted
by the Committee pursuant to subsection 13(e) or 13(h). Any
Operating Plan amended pursuant to section 9(b)(2)(A)(iii),
9(b)(2)(A)(iv), 9(b)(2)(B)(i), or 9(b)(2)(B)(ii), or subsection
14(j), 16(e), or paragraph 16(f)(2) shall take effect as soon as
such amendment is delivered by Bonneville to each Capacity Owner
that has appointed a representative to the Committee.
(o) An Operating Plan shall, during the fiscal year in which such
Operating Plan is in effect, establish the costs which Puget is
obligated to pay pursuant to the terms and conditions of this
69
Agreement. In no event shall such Operating Plan, or any portion
thereof, contain or constitute an obligation of Bonneville to
undertake, or to expend funds on, activities described or
indicated in such Operating Plan.
14. ARBITRATION
(a) During any arbitration process conducted pursuant to this section
14, Puget shall act through the Committee. Each of Bonneville and
Puget agrees to be bound by any decision rendered by the
arbitrators in any arbitration brought pursuant to
subsection 13(i) and this section 14.
(b) The Committee may initiate arbitration pursuant to subsection
13(i) by taking the following actions:
(1) an affirmative vote to initiate arbitration by at least the
respective representatives of all of the Capacity Owners that
have appointed representatives to the Committee, less one;
and
(2) either of the following:
(a) giving written notice to Bonneville of the Committee's
decision to initiate arbitration pursuant to subsection
13(i) within the applicable time period established in
subsection 13(h); or
(b) giving written notice to Bonneville of the Committee's
decision to initiate arbitration within 20 days after
the date on which Bonneville notifies in writing each
Capacity Owner that has appointed a representative to
the Committee of Bonneville's disagreement with any
exception pursuant to subsection 16(f).
The notice referred to in this subsection 14(b) shall set forth in
detail the matter or matters to be arbitrated and the name, street
address and telephone number of the arbitrator appointed by the
Committee.
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(c) Bonneville shall, within 10 Working Days after receipt of the
notice by the Committee referred to in subsection 14(b), appoint a
second arbitrator and provide by written notice to each Capacity
Owner that has appointed a representative to the Committee the
name, street address and telephone number of the arbitrator
appointed by Bonneville. The two arbitrators appointed by the
Committee and by Bonneville, respectively, shall appoint a third
arbitrator within 15 days after the date of the appointment of an
arbitrator by Bonneville.
(1) If the arbitrators appointed by the Committee and by
Bonneville, respectively, fail to appoint a third arbitrator
within 15 days after the date of the appointment of an
arbitrator by Bonneville, then within 30 days after the date
of the appointment of an arbitrator by Bonneville, the
Committee may apply to the Chief Judge of the United States
District Court for the District of Oregon for appointment of
a third arbitrator.
(2) If Bonneville fails to appoint an arbitrator within 15 days
after receipt of the notice by the Committee referred to in
subsection 14(b), then within 30 days after the date of such
notice, the Committee may apply to the Chief Judge of the
United States District Court for the District of Oregon for
appointment of two arbitrators.
(3) If, pursuant to either paragraph 14(c)(1) or 14(c)(2), the
Committee applies to the Chief Judge of the United States
District Court for the District of Oregon for appointment of
one or more arbitrators, then the Committee shall give
Bonneville written notice of such application within 5 days
after the date of filing such application.
(d) The three arbitrators appointed pursuant to subsections 14(b) and
14(c) shall select by a majority vote an alternative pursuant to
subsection 14(g).
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(e) Within 10 days after the appointment of a third arbitrator
pursuant to subsection 14(c), the arbitrators shall establish a
schedule for submission of written positions by Bonneville and
Puget, respectively. The arbitrators must establish a schedule
for such submissions pursuant to this subsection 14(e) that will
allow the arbitration to be concluded, and the decision of the
arbitrators rendered pursuant to subsection 14(g), within 120 days
following the date of the appointment of the third arbitrator. A
copy of any submission by the Committee to the arbitrators
pursuant to this section 14 shall be simultaneously served by the
Committee on Bonneville, and a copy of any submission by
Bonneville to the arbitrators pursuant to this section 14 shall be
simultaneously served by Bonneville on each Capacity Owner that
has appointed a representative to the Committee. The Committee
shall state, in a letter to the arbitrators, as its proposed
alternative to each Bonneville proposal in dispute, the
recommendation proposed by the Committee pursuant to subsection
13(g) and rejected in whole or in part by Bonneville pursuant to
subsection 13(g). Bonneville shall state its position and
proposed resolution of the dispute in a letter to the arbitrators.
If Bonneville made a proposal in response to such recommendation
of the Committee pursuant to subsection 13(g), then such position
and proposed resolution shall set forth such proposal, or if
Bonneville made no such proposal, then such position and proposed
resolution shall set forth the relevant portion of the Operating
Plan. If, however, the arbitration concerns an exception pursuant
to paragraph 16(f)(3), then the positions and proposed resolutions
of Bonneville and the Committee shall be as established pursuant
to such subsection. The Committee may then submit a response to
Bonneville's letter, and Bonneville may thereafter submit a reply
to the Committee's response. Bonneville and the Committee shall
have an equal number of days to prepare and serve their replies.
(f) No submission by either the Committee or Bonneville to the
arbitrators pursuant to subsection 14(e) shall be more than 50
pages in length (not including exhibits). If requested in writing
by either the
72
Committee or Bonneville, and for good cause shown, the arbitrators
may permit any submission by such Party to exceed 50 pages.
(g) The arbitrators shall select, as between the Committee's
recommendation pursuant to subsection 13(e), on the one hand, and
the portion of Bonneville's proposed Operating Plan to which the
Committee's recommendation pertains or Bonneville's proposal
pursuant to subsection 13(g) not accepted by the Committee, on the
other, the alternative which
(1) is consistent with the provisions of this Agreement and
(2) (A) in conformity with the generally accepted practices,
methods, and acts in the electrical utility industry in the
Western Systems Coordinating Council area prior thereto,
would better achieve the desired result consistent with
safety, reliability, and cost-benefit or (B) if there are no
such generally accepted practices, methods, and acts in the
electrical utility industry in the Western Systems
Coordinating Council area, would, in the exercise of
reasonable judgment in light of the facts known at the time
the decision is made, be reasonably expected to better
achieve the desired result consistent with safety,
reliability, and cost-benefit.
(h) In applying the standards set forth in subsection 14(g), the
arbitrators shall take into consideration, among other things (a)
that Bonneville and Puget each have responsibilities for service
to customers within and without the Pacific Northwest region in
accordance with applicable law, (b) that Bonneville and others
jointly own the PNW AC Intertie and Bonneville owes contractual
obligations to those parties regarding the PNW AC Intertie, (c)
that Bonneville must operate, as a practical matter, the PNW AC
Intertie in coordination with the operation of the interconnected
intertie facilities in California, and (d) that the PNW AC
Intertie is a major import-export facility important to the
service of loads in and out of the region.
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(i) In any arbitration pursuant to this section 14, the arbitrators
shall choose, pursuant to subsection 14(g), only between the
alternatives proposed by Bonneville and the Committee and shall
have no authority to resolve such arbitration other than by
selecting an alternative proposed by either Bonneville or the
Committee.
(j) Upon selection by the arbitrators of an alternative pursuant to
subsection 14(g), then Bonneville shall amend the Operating Plan
to cause it to conform to the decision of the arbitrators.
(k) If the arbitrators have not made a selection of an alternative
pursuant to subsection 14(i) before the date on which the
Operating Plan becomes effective pursuant to subsection 13(j),
then Puget shall make payments of annual charges pursuant to such
Operating Plan. If the arbitrators subsequently select the
Committee's alternative, then Bonneville shall, subsequent to
amending such Operating Plan pursuant to subsection 14(j), refund
to or bill Puget its pro rata share of the amount of the
incremental difference between the costs set forth in such
Operating Plan as amended pursuant to subsection 14(j) and 105
percent of the costs set forth in such Operating Plan, prior to
its amendment pursuant to subsection 14(j), to the extent that
such costs were incurred during the period from the first day of
effectiveness of such Operating Plan pursuant to subsection 13(j)
to the date of the arbitrators' decision, such refund to be made
pursuant to subsection 9(f) and such payment to be made pursuant
to subsection 9(b).
(l) Bonneville shall be responsible to pay a fraction of the costs for
the services and expenses of the arbitrators pursuant to this
section 14 equal to 1 (n + 1), where "n" equals the number of
Capacity Owners. The Committee shall be responsible to pay the
balance of the costs for the services and expenses of the
arbitrators. Each of Bonneville and the Committee shall pay its
own expenses related to the arbitration proceeding including,
without limitation, attorney fees, costs incurred in development
and preparation of documents, staff costs, and compensation for
consultants.
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(m) Any judgment rendered by a court of competent jurisdiction upon an
award made by the arbitrators pursuant to this section 14 may be
entered in any court having jurisdiction thereof.
15. NONBINDING ARBITRATION
(a) The Initiating Party (as defined in paragraph 15(e)(1)) may,
subject to the immediately succeeding sentence, elect by written
notice to Responding Party (as defined in paragraph 15(e)(1)) to
refer to nonbinding arbitration pursuant to the other provisions
of this section 15 the following: (i) if the Initiating Party is
the Committee, any recommendation by the Committee, or any portion
thereof, concerning any forecast cost or actual cost set forth in
any Operating Plan or in any amendment to an Operating Plan
pursuant to Exhibit I, Schedule A, lines 9 and 11; Exhibit I,
Schedule B, lines 11 and 13; Exhibit I, Schedule D, lines 1 and 2;
Exhibit I, Schedule F, lines 6 and 7; and Exhibit I, Schedule G,
lines 6 and 7 and (ii) any other issue, dispute, or controversy
regarding the Parties' respective rights and obligations pursuant
to this Agreement. The Initiating Party's right pursuant to this
subsection 15(a) to arbitrate any recommendation or any issue,
dispute or controversy shall be subject to the following
limitations:
(1) the Initiating Party may not arbitrate pursuant to this
subsection 15(a): (A) any recommendation with respect to an
Operating Plan or any amendment to an Operating Plan or
(B) any issue, dispute, or controversy, which recommendation,
issue, dispute or controversy may be arbitrated pursuant to
subsection 13(i) or 16(f);
(2) the Initiating Party may not arbitrate pursuant to this
subsection 15(a) any recommendation not permitted to be
arbitrated pursuant to paragraphs 13(i)(1), 13(i)(3),
13(i)(4), and 13(i)(8);
(3) the Initiating Party may not arbitrate pursuant to this
subsection 15(a) any recommendation, issue, dispute, or
75
controversy concerning a loss factor or revision to a loss
factor set forth in Exhibit E, Part A or Part B pursuant to
this Agreement;
(4) the Committee may not (but the Puget or Bonneville may)
arbitrate pursuant to this subsection 15(a) any
recommendation, issue, dispute, or controversy concerning any
right or obligation of Puget pursuant to this Agreement that
is not a right or obligation, as the case may be, of each
other Capacity Owner under its respective Capacity Ownership
Agreement; or
(5) if the sum of the actual Operations Costs, actual Maintenance
Costs, General Plant Costs, actual Other Costs, actual
Contracts and Rates Costs, actual Power Scheduling Costs and
actual End of Term Costs in any Operating Plan exceeds 105
percent of the sum of the forecast Operating Costs, forecast
Maintenance Costs, General Plant Costs, forecast Other Costs,
forecast Contracts and Rates Costs, forecast Power Scheduling
Costs and forecast End of Term Costs set forth in such
Operating Plan, the Committee may arbitrate pursuant to this
subsection 15(a) any recommendation, or portion thereof,
concerning any actual cost for any activity or project set
forth in any Operating Plan or in any amendment to an
Operating Plan pursuant to Exhibit I, Schedule A, lines 9 and
11; Exhibit I, Schedule B, lines 11 and 13; Exhibit I,
Schedule D, lines 1 and 2; Exhibit I, Schedule F, lines 6 and
7; and Exhibit I, Schedule G, lines 6 and 7 only to the
extent that such actual cost exceeds 105 percent of the
forecast for such activity or such project; provided,
however, that, without limiting any of Puget's rights and
benefits pursuant to section 16(f), no Initiating Party may
arbitrate pursuant to this subsection 15(a) any
recommendation, or portion thereof, concerning any actual
cost for any activity or project set forth in any Operating
Plan or in any amendment to an Operating Plan pursuant to
Exhibit I, Schedule A, lines 9 and 11; Exhibit I, Schedule B,
76
lines 11 and 13; Exhibit I, Schedule D, lines 1 and 2;
Exhibit I, Schedule F, lines 6 and 7; and Exhibit I, Schedule
G, lines 6 and 7 if such actual cost is less than 105 percent
of the forecast for such activity or such project; and
(6) the Initiating Party may not arbitrate pursuant to this
subsection 15(a) any issue, dispute, or controversy (A)
concerning matters of ratemaking (for purposes of this
subsection 15(a), the term "ratemaking" shall mean the
determination of matters appropriately determined pursuant to
section 7(i) of the Regional Act, including (i) Bonneville's
revenue requirements (including without limitation
Bonneville's depreciation and repayment standards and planned
net revenues for risk, but excluding program level issues
determined in the Federal budget process), (ii) Bonneville's
cost of service analysis (including functionalization,
segmentation, and allocation of costs contained in such
analysis, but excluding any allocation of costs contemplated
in Exhibit I), (iii) Bonneville's rate design, and (iv) any
related environmental analysis of proposed rates; (B)
concerning a final action of Bonneville, which final action
is not itself performance of any obligation of Bonneville or
Bonneville's Administrator under this Agreement; or (C)
concerning, or requiring the decision of, a matter not
arising under this Agreement or the other Capacity Ownership
Agreements.
(b) Except as otherwise provided in paragraph 15(a)(4), all
arbitrations pursuant to this section 15 shall be between
Bonneville and the Committee.
(c) A copy of any submission (including, without limitation, any
statement of position or any brief) by the Initiating Party or the
Responding Party to the arbitrators pursuant to this section 15
shall be simultaneously served by such party on the Responding
Party or Initiating Party, respectively. No submission by either
the Initiating
77
Party or the Responding Party to the arbitrators shall be more
than 50 pages in length (not including exhibits). If requested in
writing by either the Initiating Party or the Responding Party,
and for good cause shown, the arbitrators may permit any
submission by such party to exceed 50 pages.
(d) With respect to any arbitration pursuant to this section 15 of any
forecast cost or actual cost set forth in any Operating Plan or in
any amendment to an Operating Plan pursuant to Exhibit I, Schedule
A, lines 9 and 11; Exhibit I, Schedule B, lines 11 and 13; Exhibit
I, Schedule D, lines 1 and 2; Exhibit I, Schedule F, lines 6 and
7; and Exhibit I, Schedule G, lines 6 and 7, the following shall
apply:
(1) Only the Committee may initiate arbitration with respect to
any forecast cost or actual cost set forth in any Operating
Plan or in any amendment to an Operating Plan pursuant to
Exhibit I, Schedule A, lines 9 and 11; Exhibit I, Schedule B,
lines 11 and 13; Exhibit I, Schedule D, lines 1 and 2;
Exhibit I, Schedule F, lines 6 and 7; and Exhibit I, Schedule
G, lines 6 and 7. The Committee may initiate nonbinding
arbitration pursuant to this section 15 by taking the
following actions:
(A) an affirmative vote to initiate arbitration pursuant to
this section 15 by the respective representatives of all
of the Capacity Owners that have appointed
representatives to the Committee, less one; and
(B) either of the following:
(i) giving written notice to Bonneville of the
Committee's decision to initiate arbitration
pursuant to this section 15 within the applicable
time period set forth in subsection 13(h); or
(ii) giving written notice to Bonneville of the
Committee's decision to initiate arbitration
78
within 20 days after the date on which Bonneville
notifies in writing each Capacity Owner that has
appointed a representative to the Committee of
Bonneville's disagreement with any exception
pursuant to subsection 16(f).
The notice referred to in this subparagraph 15(d)(1)(B)
shall (x) indicate that such vote has been taken and (y)
set forth in detail the matters to be arbitrated and the
name, street address and telephone number of the
arbitrator appointed by the Committee.
(2) The respective rights and obligations of the Committee and of
Bonneville with respect to arbitration pursuant to this
subsection 15(d), unless otherwise provided in this
subsection 15(d), shall be as set forth in subsections 14(d)
through 14(l).
(e) With respect to any arbitration pursuant to this section 15 of any
issue, dispute, or controversy other than with respect to any
forecast cost or actual cost set forth in any Operating Plan or in
any amendment to an Operating Plan pursuant to Exhibit I, Schedule
A, lines 9 and 11; Exhibit I, Schedule B, lines 11 and 13; Exhibit
I, Schedule D, lines 1 and 2; Exhibit I, Schedule F, lines 6 and
7; and Exhibit I, Schedule G, lines 6 and 7, the following shall
apply:
(1) The party (which term, for purposes of this subsection 15(e),
shall refer to Bonneville, on the one hand, and to the
Committee or Puget, on the other) initiating arbitration
(Initiating Party) shall initiate arbitration pursuant to
this section 15 by serving written notice on the other party
(Responding Party) of its initiation of arbitration. If the
Committee is the party initiating arbitration, the Committee,
in addition to serving such notice, shall initiate such
arbitration by an affirmative vote to do so of at least the
respective representatives of all of the Capacity Owners that
have appointed representatives to the Committee, less one.
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The Committee shall indicate that such vote has been taken in
such notice to Bonneville. Any such notice by an Initiating
Party shall set forth in detail the following: (A) the
issue, dispute, or controversy to be arbitrated and the
Initiating Party's position regarding such issue, dispute, or
controversy; (B) the relief sought by the Initiating Party;
and (C) the name, street address, and telephone number of the
arbitrator appointed by the Initiating Party. The Responding
Party shall, within 15 days after receipt of the notice by
the Initiating Party referred to in this subsection 15(e),
appoint a second arbitrator and provide written notice to the
Initiating Party and to the arbitrator appointed by the
Initiating Party of the name, street address and telephone
number of the arbitrator appointed by the Responding Party.
The arbitrators appointed by the Initiating Party and by
Bonneville, respectively, shall appoint a third arbitrator
within 15 days after the date of the appointment of an
arbitrator by the Responding Party.
(A) If the arbitrators appointed by the Initiating Party and
by the Responding Party, respectively, fail to appoint a
third arbitrator within 15 days after the date of the
appointment of an arbitrator by the Responding Party,
then within 30 days after the date of the appointment of
an arbitrator by the Responding Party the Initiating
Party may apply to the Chief Judge of the United States
District Court for the District of Oregon for
appointment of a third arbitrator.
(B) If the Responding Party fails to appoint an arbitrator
within 15 days after receipt of the notice by the
Initiating Party referred to in paragraph 15(e)(1), then
within 30 days after the date of such notice the
Initiating Party may apply to the Chief Judge of the
United States District Court for the District of Oregon
for appointment of two arbitrators.
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(C) If, pursuant to either subparagraph 15(e)(1)(A) or
15(e)(1)(B), the Initiating Party applies to the Chief
Judge of the United States District Court for the
District of Oregon for appointment of one or more
arbitrators, then the Initiating Party shall give the
Responding Party written notice of such application
within one day after the date of filing such
application.
(2) The three arbitrators appointed pursuant to paragraph
15(e)(1) shall decide any issue, dispute, or controversy by
majority vote.
(3) Within 20 days after the appointment of a third arbitrator
pursuant to paragraph 15(e)(1) with respect to any
arbitration pursuant to this subsection 15(e), the
arbitrators shall establish a schedule for the completion of
such arbitration. The first day pursuant to such schedule
shall be hereafter referred to in this subsection 15(e) as
the "Arbitration Commencement Date."
(4) No later than 15 days after the Arbitration Commencement
Date, the Initiating Party may make a single request in
writing to the Responding Party for documentation, data, and
information relevant to or reasonably necessary to support
the Initiating Party's position communicated to the
Responding Party pursuant to paragraph 15(e)(1). Such single
request may contain multiple parts. The Initiating Party
shall use reasonable efforts to minimize and limit the scope
and number of parts of the request for documentation, data,
and information pursuant to this paragraph.
(5) The Responding Party shall have 20 days from the date it
receives the request from the Initiating Party pursuant to
paragraph 15(e)(4) to provide the documentation, data, and
information requested; provided, however, that the Responding
Party shall be under no obligation pursuant to this paragraph
15(e)(5)(A) to create additional documentation, data, or
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information, (B) to provide documentation, data, or
information that is not readily available to it, (C) to
provide to the Committee documentation, data, or information
that Bonneville has previously provided to the Initiating
Party or (D) if Bonneville is the Responding Party, to
provide documentation, data, or information that Bonneville
would not otherwise be required to provide or that would
otherwise be exempted from disclosure pursuant to the Freedom
of Information Act, 5 U.S.C. section 552 (including, without
limitation, the Freedom of Information Reform Act of 1986),
as amended or superseded, or pursuant to any regulation and
Executive Order applicable to Bonneville.
(6) No later than 15 days after the Arbitration Commencement
Date, the Responding Party may make a single request in
writing to the Initiating Party for documentation, data and
information relevant to Initiating Party's position
communicated to the Responding Party pursuant to subsection
15(e)(4). Such single request may contain multiple parts.
The Responding Party shall use reasonable efforts to minimize
and limit the scope and number of parts of the request for
documentation, data and information pursuant to this
paragraph.
(7) The Initiating Party shall have 20 days from the date it
receives the request from the Responding Party pursuant to
paragraph 15(e)(6) to provide the documentation, data and
information requested; provided, however, that the Initiating
Party shall be under no obligation pursuant to this paragraph
15(e)(7) (A) to create additional documentation, data, or
information, (B) to provide documentation, data or
information that is not readily available to it, (C) to
provide to the Responding Party documentation, data, or
information that the Initiating Party has previously provided
to the Responding Party or (D) if Bonneville is the
Initiating Party, to provide documentation, data, or
information that Bonneville would not
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otherwise be required to provide or that would otherwise be
exempted from disclosure pursuant to the Freedom of
Information Act, 5 U.S.C. section 552 (including, without
limitation, the Freedom of Information Act of 1986), as
amended or superseded, or pursuant to any regulation and
Executive Order applicable to Bonneville.
(8) For purposes of this subsection 15(e), each of the Initiating
Party and the Responding Party shall cooperate and use
reasonable efforts to, in a timely manner, resolve disputes
regarding, and clarify requests by it for, documentation,
data, and information and responses to such requests.
(9) Within 65 days following the Arbitration Commencement Date,
each of the Initiating Party and the Responding Party may
state in reasonable detail its position regarding any issue,
dispute or controversy to be arbitrated pursuant to this
subsection 15(e) in a letter to the arbitrators and to the
other party to the arbitration of such issue, dispute, or
controversy Within 85 days following the Arbitration
Commencement Date, each of the Initiating Party and the
Responding Party may submit a letter to the arbitrators and
to the other party responding to the letter that the other
submitted to the arbitrators pursuant to the immediately
preceding sentence.
(10) The arbitrators shall resolve any issue, dispute, or
controversy pursuant to this subsection 15(e) by deciding
(taking into consideration, among other things, any letter
submitted by the Initiating Party or the Responding Party
with respect to such issue, dispute, or controversy) whether
the position of the Initiating Party or the position of the
Responding Party regarding the action taken or proposed to be
taken by the Responding Party conforms more closely with the
standard for such action set forth in this Agreement. The
arbitrators shall have no authority to fashion a resolution
of such arbitration other than pursuant to this paragraph
15(e)(10).
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(f) Any selection by the arbitrators of an alternative pursuant to
subsection 15(d) and any decision by the arbitrators pursuant to
subsection 15(e) shall be reported by the Initiating Party to the
Bonneville Administrator (Administrator) for review within 30 days
after such selection or decision is made. The Administrator shall
either accept or reject in writing such selection or decision. If
the Administrator fails to either accept or reject such selection
or decision, as the case may be, within 90 days after such
selection or decision is made, such selection or decision, as the
case may be, shall be deemed to be accepted by the Administrator.
(g) If the Administrator accepts any selection by the arbitrators of
an alternative pursuant to subsection 15(d) or any decision by the
arbitrators pursuant to subsection 15(e), such selection or
decision shall become binding upon Puget and Bonneville at the
time of its acceptance.
(h) The Administrator may reject any selection by the arbitrators of
an alternative pursuant to subsection 15(d) or any decision by the
arbitrators pursuant to subsection 15(e) only for one or more of
the following reasons:
(1) the arbitrators did not follow the arbitration procedures set
forth in this section 15;
(2) the arbitrators decided a matter that is not a matter arising
under this Agreement as set forth in paragraph 15(a)(6);
(3) the arbitrators did not completely apply the appropriate
standard for arbitration pursuant to this section 15;
(4) the arbitrators granted relief in contravention of this
Agreement; 84
(5) the arbitrators' decision is not supported by substantial,
competent evidence; or
(6) implementation of the arbitrators' decision would cause
Bonneville to violate a statutory obligation of Bonneville's
or would cause Bonneville to breach a contractual obligation
not in contravention of this Agreement.
(i) Bonneville shall be responsible to pay a fraction of the costs for
the services and expenses of the arbitrators pursuant to this
section 15 equal to 1 divided by (n + 1), where "n" equals the
number of Capacity Owners. The Committee shall be responsible to
pay the balance of the costs for the services and expenses of the
arbitrators. Each of Bonneville and the Committee shall pay for
its own expenses related to the arbitration proceeding, including,
without limitation, attorney fees, costs incurred in development
and preparation of documents, staff costs, and compensation for
consultants.
(j) If the Initiating Party elects to arbitrate any issue, dispute, or
controversy pursuant to this section 15, the Initiating Party must
initiate arbitration of such issue, dispute, or controversy within
one year following the occurrence of the event giving rise to such
issue, dispute, or controversy. Failure of the Initiating Party
to initiate arbitration of any such issue, dispute, or controversy
within such one-year period shall constitute a waiver of the
Initiating Party's right to arbitrate such issue, dispute, or
controversy pursuant to this section 15.
16. AUDIT RIGHTS
(a) The Committee shall have the right to perform an audit of
Bonneville's books, records, and documents used in or relating to
the determination of the Adjusted Capacity Ownership Price, or
used in or relating to any billing or refund with respect to the
Adjusted Capacity Ownership Price. Such audit shall be performed
within 24 months
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after the date of Bonneville's bill or refund voucher rendered by
Bonneville pursuant to subparagraph 9(a)(2)(B).
(b) The Committee shall have the right to perform an audit of
Bonneville's books, records and documents used in or relating to
the determination of any Revised Adjusted Capacity Ownership
Price, or used in or relating to any billing or refund with
respect to any Revised Adjusted Capacity Ownership Price. Such
audit shall be performed within 24 months after the date of
Bonneville's bill or refund voucher rendered by Bonneville
pursuant to subparagraph 9(a)(3)(B).
(c) The Committee shall have the right to audit Bonneville's books,
records, and documents (i) used in or relating to the
determination of any charge (including, without limitation, any
MFU count made pursuant to section I.A of Exhibit I) billed to
Puget pursuant to paragraph 9(b)(2) and subsection 9(c), or
(ii) used in or relating to any billing or refund with respect to
any such charge. Such audit shall be performed within 36 months
after the date of Bonneville's bill or refund voucher for such
charge rendered by Bonneville to Puget pursuant to paragraph
9(b)(2) or subsection 9(c), as the case may be.
(d) Bonneville shall not be responsible to pay any of the expenses
incurred by any of the Capacity Owners in performing any audit
pursuant to this section 16. Bonneville shall not directly charge
Puget or any Capacity Owner other than Puget for Bonneville's
costs incurred by Bonneville with respect to any audit pursuant to
this section 16 unless Bonneville develops a general practice of
charging, through direct charges, each of its customers for such
costs incurred by Bonneville in connection with audits undertaken
pursuant to those customers' respective contracts with Bonneville.
(e) After completing any audit specified above, the Committee shall
promptly provide to Bonneville a written report of the results of
such audit. If such audit report includes any exception taken as
a result of such audit and Bonneville agrees with such exception,
Bonneville
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shall, within 30 days following Bonneville's receipt of such audit
report and consistent with such audit exception,
(1) if such exception is with respect to the Adjusted Lump Sum
Payment or to any Revised Adjusted Lump Sum Payment, render
to Puget a revised bill or refund voucher pursuant to
paragraph 9(a)(2)(B) or 9(a)(3)(B), respectively, with
respect to such Adjusted Lump Sum Payment or such Revised
Adjusted Lump Sum Payment, and
(2) if such exception is with respect to an Operating Plan, amend
the Operating Plan to which such exception pertains and
either (A) render to Puget a revised bill, consistent with
such Operating Plan, pursuant to the applicable GTRSPs set
forth in Exhibit A and to the Billing Provisions set forth in
Part B of Exhibit B or (B) cause to be refunded to Puget as a
lump sum payment, within 30 days after the date on which such
Operating Plan is so amended, an amount consistent with such
Operating Plan (multiplied by Puget's Capacity Ownership
Percentage).
The amount of any refund or bill payable pursuant to this
subsection 16(e) shall be paid with interest on such amount
calculated at a rate equal to the weighted average of Bonneville's
then-outstanding bonds or other debt instruments from (and
including) the date on which such audit report is received by
Bonneville to (but excluding) the date on which such amount is
refunded to Puget.
(f) If an audit report provided to Bonneville by Puget pursuant to
subsection 16(e) includes any exception taken as a result of such
audit and Bonneville does not agree with such exception, then the
following shall apply:
(1) Bonneville may, within 30 days following its receipt of such
audit report, propose to the Committee a resolution of any
87
inconsistency noted in any exception taken as a result of
such audit;
(2) If the Committee accepts such resolution proposed by
Bonneville, then Bonneville shall, within 30 days following
Bonneville's receipt of such audit report and consistent with
such resolution,
(A) if such exception is with respect to the Adjusted Lump
Sum Payment or to any Revised Adjusted Lump Sum Payment,
render to Puget a revised bill or refund voucher
pursuant to subparagraph 9(a)(2)(B) or 9(a)(3)(B),
respectively, with respect to such Adjusted Lump Sum
Payment or such Revised Adjusted Lump Sum Payment, and
(B) if such exception is with respect to an Operating Plan,
amend the Operating Plan to which such exception
pertains and shall either (i) render to Puget a revised
bill, consistent with such Operating Plan, pursuant to
the applicable GTRSPs set forth in Exhibit A and to the
Billing Provisions set forth in Part B of Exhibit B or
(ii) cause to be refunded to Puget as a lump sum
payment, within 30 days after the date on which such
Operating Plan is so amended, an amount consistent with
such Operating Plan (multiplied by Puget's Capacity
Ownership Percentage).
The amount of any refund or bill payable pursuant to this
paragraph 16(f)(2) shall be paid with interest on such amount
calculated at a rate equal to the weighted average of
Bonneville's then-outstanding bonds or other debt instruments
from (and including) the date on which such resolution is
accepted by the Committee to (but excluding) the date on
which such amount is refunded to Puget; and
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(3) If the Committee does not accept such resolution, if any,
proposed by Bonneville with respect to any such exception, or
if Bonneville does not propose any such resolution, then the
Committee
(A) shall have the right to arbitrate, pursuant to section
14, any cost with respect to which such exception is
taken to the extent that such cost is permitted to be
arbitrated pursuant to subsection 13(i); and
(B) shall have the right to arbitrate, pursuant to section
15, any cost with respect to which such exception is
taken to the extent that such cost is permitted to be
arbitrated pursuant to section 15.
The Committee must refer to arbitration pursuant to subparagraph
16(f)(3)(A) or 16(f)(3)(B) any cost to which exception is taken as
a result of any audit within eight months after the date the
Committee commences such audit. Failure of the Committee to elect
to so refer to arbitration any cost within such eight-month period
shall be deemed to constitute waiver by the Committee of any right
pursuant to this section 16 to arbitrate such cost.
(g) Puget shall have the right to participate in any audit pursuant to
this section 16 only by acting through the Committee. If Puget
chooses not to participate in any audit undertaken by the
Committee, then Puget shall accept the findings of the Committee
with respect to such audit and any resolution by the Committee and
Bonneville of any inconsistency noted in any exception taken as a
result of such audit.
(h) Any audits undertaken by the Committee shall be upon reasonable
notice to Bonneville and at reasonable times and shall commence no
more frequently than once in any 24 consecutive months. The audit
rights provided in this section shall not be construed to permit a
general audit of Bonneville's books, records, and documents.
Audits shall be in conformance with generally accepted auditing
standards.
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Prior to and for the duration of any audit, Bonneville shall
retain all pertinent books, records, and documents prepared in the
normal course of business. After commencement of an audit
pursuant to subsection 16(a), 16(b), or 16(c), the Committee may
request and Bonneville shall promptly provide reasonably available
supporting documentation for any cost or charge subject to audit.
If the Committee fails to commence an audit pursuant to subsection
16(a), 16(b), or 16(c) within the time periods set forth in
subsection 16(a), 16(b), or 16(c), such failure shall constitute
waiver by Puget of any right pursuant to this section 16 to
arbitrate any charge or refund billed or refunded by Bonneville.
(i) If Puget is operating pursuant to paragraph 3(b)(1), Bonneville
shall have the right, at its own expense, to review Puget's books,
records, and documents that directly pertain to the revenue
reportable in Puget's accounting system where revenues received
for wheeling for other entities would be booked for the purpose of
verifying compliance with paragraph 3(b)(1). Bonneville shall
have the right to perform such audit no more frequently than once
every 36 months.
17. PROTECTED AREAS
Puget shall not use its Scheduling Share for transmission of power on
the PNW AC Intertie from new hydroelectric projects which are
constructed in Columbia River Basin Protected Areas after designation
thereof by Bonneville unless Puget is required by regulatory authority
to purchase or provide transmission for the output of such project or
unless Bonneville receives sufficient demonstration that a particular
project would provide benefits to Bonneville's existing or planned fish
and wildlife investments or the Pacific Northwest Electric Power and
Conservation Planning Council's Fish and Wildlife Program. The Parties
agree that System Sales shall not be taken into consideration in any
determination of whether Puget has used its Scheduling Share for
transmission of power on the PNW AC Intertie from the hydroelectric
projects referred to in the immediately preceding sentence. For
purposes of this section 17, "System Sale" means any sale of power or
energy to Puget or by a seller of power or energy, which power or
energy is not
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resource-specific and is delivered to Puget at a point that connects
one or more resources or transmission systems.
18. ESTABLISHMENT AND MAINTENANCE OF RATES AND RELIEF FROM REGULATORY
ACTION
(a) Bonneville shall use good faith efforts to maintain in effect such
of the following rates that has been approved by FERC on an
interim or final basis, during the rate approval period
established by FERC for such rate:
(1) any rate containing the terms set forth in Exhibit B, Part A
and Part B, on the Effective Date;
(2) the Initial Successor Rate;
(3) the Alternative Successor Rate; and
(4) the Bonneville Successor Rate.
(b) If Bonneville's Administrator submits to FERC a rate that is
different from that set forth in Exhibit B, Part A and Part B, on
the Effective Date, as the first rate proposed by Bonneville
(Initial Successor Rate) to replace the AC-93 rate set forth in
Exhibit A or that is for a rate approval period which is less than
the remainder of the Term following the expiration of the AC-93
rate, Puget may, within 90 days after Bonneville submits the
Initial Successor Rate to FERC and without regard to FERC's
interim or final disposition of such rate, elect by written notice
to Bonneville to terminate this Agreement and shall in such notice
to Bonneville elect to exercise one of the two following options:
(1) Puget may elect to proceed pursuant to paragraphs 18(f)(1),
18(f)(2), and 18(f)(3); or
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(2) Puget may elect to have its Initial Lump Sum Payment,
Adjusted Lump Sum Payment, or any Revised Adjusted Lump Sum
Payment, whichever has been most recently paid by Puget to
Bonneville pursuant to subsection 9(a), refunded by
Bonneville subject to the following terms and conditions:
(A) This Agreement shall terminate upon the date Bonneville
receives Puget's notification to terminate this
Agreement pursuant to this subsection 18(b) except for
those rights and obligations set forth in this paragraph
18(b)(2).
(B) Bonneville shall refund within the next three succeeding
rate periods but, in any event, within 8 years after
Puget has made its election for such refund (such period
to begin no later than the 25th month after Bonneville's
receipt of Puget's notification to terminate this
Agreement and to end on the 96th month after
Bonneville's receipt of such notification) in equal
monthly amounts an amount equal to the "Refunded Lump
Sum Payment" calculated as follows:
A-((B/540)XA)+ I = Refunded Lump Sum Payment
where:
A = The Initial Lump Sum Payment, Adjusted Lump Sum
Payment, or any Revised Adjusted Lump Sum Payment,
whichever has been most recently paid by Puget to
Bonneville pursuant to subsection 9(a).
B = The number of months between the Effective Date
and the termination date of this Agreement
pursuant to this subsection 18(b).
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540 = 12 months X 45-year period over which Bonneville
will amortize the Initial Lump Sum Payment,
Adjusted Lump Sum Payment, or such Revised
Adjusted Lump Sum Payment, as the case may be.
I = Interest on A-((B/540)XA), accruing from (and
including) the date of Bonneville's receipt of
Puget's Initial Lump Sum Payment to (but
excluding) the date on which Bonneville receives
Puget' notification to terminate this Agreement
pursuant to this subsection 18(a), at the 5-year
Treasury note rate in effect on the date on which
Bonneville receives Puget's Initial Lump Sum
Payment.
(C) Bonneville shall, subject to the immediately succeeding
sentence, pay interest on the Refunded Lump Sum Payment
at a rate equal to Bonneville's weighted average
interest rate on Bonneville's then-outstanding bonds and
on Bonneville's then-outstanding debt instruments. Such
interest payable pursuant to this subparagraph
18(b)(2)(C) shall be paid by Bonneville on the amount of
each monthly amount of the Refunded Lump Sum Payment
payable by Bonneville pursuant to subparagraph
18(b)(2)(B).
(D) Bonneville shall refund the Refunded Lump Sum Payment
pursuant to paragraph 9(f)(4).
(E) At any time during the repayment period referenced in
subparagraph 18(b)(2)(B), Bonneville may accelerate
payment to Puget of the amount of the Refunded Lump Sum
Payment.
If Puget elects to proceed under this paragraph 18(b)(2),
Bonneville shall not develop a rate or charge that would
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inequitably allocate to Puget and Capacity Owners other than
Puget, or to any of them, the cost to Bonneville of the
Refunded Lump Sum Payment; provided, however, that such
allocation shall not be deemed to be inequitable solely
because it causes the recovery of a portion of the cost to
Bonneville of the Refunded Lump Sum Payment from Puget or any
Capacity Owner other than Puget.
(c) If FERC approves the Initial Successor Rate, the Alternative
Successor Rate (as defined in subsection 18(d)), or the Bonneville
Successor Rate (as defined in subsection 18(d)) for a term less
than the remainder of the Term following the expiration of the AC-
93 rate, and if Bonneville's Administrator thereafter submits to
FERC a rate (Replacement Rate) that is different from the Initial
Successor Rate, the Alternative Successor Rate or the Bonneville
Successor Rate (whichever had been approved by FERC on an interim
or final basis) or that is for a rate approval period which is
less than the remainder of the Term following the expiration of
the Initial Successor Rate, the Alternative Successor Rate or the
Bonneville Successor Rate (whichever had been approved by FERC on
an interim or final basis), Puget may, within 90 days after
Bonneville submits such rate to FERC and without regard to FERC's
interim or final disposition of such rate, elect by written notice
to Bonneville to terminate this Agreement and shall in such notice
to Bonneville elect to exercise one of the two following options:
(1) Puget may elect to proceed pursuant to paragraphs 18(f)(1),
18(f)(2), and 18(f)(3); or
(2) Puget may elect to have its Initial Lump Sum Payment,
Adjusted Lump Sum Payment, or any Revised Adjusted Lump Sum
Payment, whichever has been most recently paid by Puget to
Bonneville pursuant to subsection 9(a), refunded by
Bonneville subject to the following terms and conditions:
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(A) This Agreement shall terminate upon the date Bonneville
receives Puget's notification to terminate this
Agreement pursuant to this subsection 18(c) except for
those rights and obligations set forth in this paragraph
18(c)(2).
(B) Bonneville shall refund within the next three succeeding
rate periods but, in any event, within 8 years after
Puget has made its election for such refund (such period
to begin no later than the 25th month after Bonneville's
receipt of Puget's notification to terminate this
Agreement and to end on the 96th month after
Bonneville's receipt of such notification) in equal
monthly amounts an amount equal to the "Refunded Lump
Sum Payment" calculated as follows:
A-((B/540)XA)+ R = Refunded Lump Sum Payment
where:
A = The Initial Lump Sum Payment, Adjusted Lump Sum
Payment, or any Revised Adjusted Lump Sum Payment,
whichever has been most recently paid by Puget to
Bonneville pursuant to subsection 9(a).
B = The number of months between the Effective Date
and the termination date of this Agreement.
540 = 12 months X 45-year period over which Bonneville
will amortize the Initial Lump Sum Payment,
Adjusted Lump Sum Payment, or such Revised
Adjusted Lump Sum Payment, as the case may be.
R = 2.5 times the amount paid pursuant to
subparagraphs 9(b)(2)(A) and 9(b)(2)(B) for the
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immediately preceding fiscal year times the ratio
of (a) the amount forecast to be paid pursuant to
subparagraphs 9(b)(2)(A) and 9(b)(2)(B) for the
first fiscal year during the proposed rate
approval period pursuant to the rate submitted by
Bonneville to FERC to replace the immediately
preceding annual costs rate over (b) the amount
forecast to be paid pursuant to subparagraphs
9(b)(2)(A) and 9(b)(2)(B) for the same fiscal year
were the immediately preceding annual costs rate
to remain in effect; provided, however, that the
ratio of (a) over (b) shall in no event be less
than one for purposes of this subsection.
(C) Bonneville shall, subject to the immediately succeeding
sentence, pay interest on the Refunded Lump Sum Payment
at a rate equal to Bonneville's weighted average
interest rate on Bonneville's then-outstanding bonds and
on Bonneville's then-outstanding debt instruments. Such
interest payable pursuant to this subparagraph
18(c)(2)(C) shall be paid by Bonneville on the amount of
each monthly amount of the Refunded Lump Sum Payment
payable by Bonneville pursuant to subparagraph
18(c)(2)(B).
(D) Bonneville shall refund the Refunded Lump Sum Payment
pursuant to paragraph 9(f)(4).
(E) At any time during the repayment period referenced in
subparagraph 18(c)(2)(B), Bonneville may accelerate
payment to Puget of the amount of Refunded Lump Sum
Payment.
If Puget elects to proceed under this paragraph 18(c)(2),
Bonneville shall not develop a special rate or charge that
would inequitably allocate to Puget and Capacity Owners other
than
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Puget, or to any of them, the cost to Bonneville of the
Refunded Lump Sum Payment; provided, however, that such
allocation shall not be deemed to be inequitable solely
because it causes the recovery of a portion of the cost to
Bonneville of the Refunded Lump Sum Payment from Puget or any
Capacity Owner other than Puget.
The terms of this subsection 18(c) shall be effective through
December 31, 2040.
(d) If (i) FERC remands or approves a rate which materially differs
from the rate schedule and Billing Provisions set forth in Exhibit
B, Part A and Part B, on the Effective Date, or (ii) FERC grants
final approval to a rate containing the terms set forth in
Exhibit B, Part A and Part B, on the Effective Date, or to the
Initial Successor Rate for a rate approval period of less than the
remainder of the Term following the expiration of the AC-93 rate,
or (iii) FERC remands or disapproves the Initial Successor Rate,
then in any such event Bonneville, Puget, and Capacity Owners
other than Puget shall use good faith efforts to develop an
alternative successor rate (Alternative Successor Rate) which
would place Puget in substantially the same position with respect
to Puget's rights and obligations under this Agreement as if the
rate schedule and Billing Provisions set forth in Exhibit B, Part
A and Part B, on the Effective Date, had been approved by FERC for
the remainder of the Term following the expiration of the AC-93
rate. Bonneville, Puget, and Capacity Owners other than Puget
shall use good faith efforts to reach agreement on an Alternative
Successor Rate within 6 months after the date of the FERC order
regarding the Initial Successor Rate contemplated in this
subsection 18(d) or within the time period established in such
FERC order, whichever is earlier.
(1) If Bonneville, Puget, and Capacity Owners other than Puget
reach such an agreement regarding an Alternative Successor
Rate within the applicable time period referred to in the
immediately preceding sentence, then Bonneville shall,
subject
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to section 7(i) of the Regional Act, submit such Alternative
Successor Rate to FERC for approval and confirmation.
(2) If Bonneville, Puget, and Capacity Owners other than Puget do
not reach such an agreement regarding an Alternative
Successor Rate within the applicable time period referred to
in the immediately preceding sentence, Bonneville shall
develop a rate, which, among other things, in Bonneville's
judgment, protects the rights and obligations of Puget and
Capacity Owners other than Puget and, subject to section 7(i)
of the Regional Act, shall submit such rate (Bonneville
Successor Rate) to FERC for approval and confirmation.
Nothing in this subsection 18(d) shall limit or otherwise affect
any provisions of subsection 18(b) or 18(c).
(e) If Bonneville, Puget, and Capacity Owners other than Puget are
unable to agree upon an Alternative Successor Rate pursuant to
subsection 18(d), or if FERC approves the Alternative Successor
Rate for a period of less than 15 years or with terms and
conditions that differ from the terms and conditions of the
Alternative Successor Rate, or if FERC remands the Alternative
Successor Rate, or if FERC approves the Bonneville Successor Rate,
Puget may elect, within 6 months of any of the foregoing events,
to terminate this Agreement and execute a long-term contract with
Bonneville for firm wheeling on the PNW-PSW Intertie for a term
not less than the remaining term of the agreement(s) specified in
Exhibit J for wheeling of an amount of power on the PNW-PSW
Intertie up to Puget's Capacity Ownership Share, pursuant to
subsection 18(f).
(f) Should Puget elect to proceed pursuant to paragraph 18(b)(1) or
18(c)(1) or subsection 18(e), the Parties shall take the following
steps:
(1) Puget shall provide Bonneville with written notification of
its election to terminate this Agreement and with a written
request for a long-term contract for firm wheeling on the PNW-
PSW
98
Intertie for a period not less than the remaining term of the
agreement(s) specified in Exhibit J for wheeling of an amount
of power on the PNW-PSW Intertie up to Puget's Capacity
Ownership Share.
(2) As soon as practicable after receipt by Bonneville of the
written notice sent pursuant to paragraph 18(f)(1),
Bonneville shall offer to Puget a long-term contract for firm
wheeling on the PNW-PSW Intertie of an amount of power equal
to the amount of power specified in Puget's written request
pursuant to paragraph 18(f)(1), such offered contract to
contain other terms and conditions substantially similar to
those then being offered by Bonneville to its other firm
wheeling customers for transactions on the PNW-PSW Intertie.
The termination date of this Agreement shall be the same date as
the effective date of the long-term contract for firm wheeling
referred to in this paragraph 18(f)(2), and such date shall in any
event be no more than 6 months after Bonneville's receipt of
Puget's notification pursuant to paragraph 18(f)(1).
(3) The long-term contract for firm wheeling offered to Puget
pursuant to paragraph 18(f)(2) shall also contain provisions
which:
(A) Require Bonneville to credit or pay (any such payment to
be made pursuant to paragraph 9(f)(4)), in equal monthly
amounts during the term of such long-term contract for
firm wheeling, against the amount payable by Puget to
Bonneville pursuant to such long-term wheeling agreement
an amount equal to the "Credited Lump Sum Payment"
calculated as follows:
A-((B/540)XA)= credited Lump Sum Payment
where:
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A = The Initial Lump Sum Payment, Adjusted Lump Sum
Payment, or any Revised Adjusted Lump Sum Payment,
whichever has been most recently paid by Puget to
Bonneville pursuant to subsection 9(a).
B = The number of months between the Effective Date
and the termination date of this Agreement
pursuant to this subsection 18(e).
540 = 12 months X 45-year period over which Bonneville
will amortize the Initial Lump Sum Payment,
Adjusted Lump Sum Payment, or such Revised
Adjusted Lump Sum Payment, as the case may be.
(B) Require Bonneville, subject to the immediately
succeeding sentence, to credit or pay interest on the
Credited Lump Sum Payment at a rate equal to
Bonneville's weighted average interest rate on
Bonneville's then-outstanding bonds and on Bonneville's
then-outstanding debt instruments. Such interest to be
credited or paid pursuant to this provision shall be
credited or paid by Bonneville on the amount of each
monthly amount of the Credited Lump Sum Payment to be
credited or paid by Bonneville pursuant to the provision
set forth in subparagraph 18(f)(3)(A).
(C) Permit Bonneville to accelerate payment to Puget of the
amount of Credited Lump Sum Payment which remains
uncredited at any time during the term of such long-term
contract for firm wheeling.
(g) Puget's right to terminate this Agreement pursuant to subsections
18(d) through 18(f) is a one-time only right that must be
exercised after FERC action pursuant to subsection 18(d). If
Puget fails to
100
terminate the Agreement pursuant to subsection 18(e) as prescribed
therein as a result of FERC action, Puget shall have no future
rights to terminate the Agreement under this section 18 as a
result of FERC action.
(h) Bonneville shall use best efforts to establish and maintain in
effect the AC-93 rate, set forth in Exhibit A, during the
remainder of the Term, but only until the annual costs rate set
forth in Exhibit B, or other rate submitted to FERC, pursuant to
subsections 18(b) through 18(d), that is confirmed and approved by
FERC on an interim or final basis, becomes effective. If FERC
does not confirm and approve on a final basis the AC-93 rate for a
rate approval period of sufficient duration so that the AC-93 rate
is effective until the annual costs rate set forth in Exhibit B,
or such other rate, becomes effective, then upon expiration of the
rate approval period of such AC-93 rate, Bonneville shall submit
to FERC a rate based on the methodology used to determine the AC-
93 rate (revised AC-93 rate) and shall use best efforts to obtain
a rate approval period for the revised AC-93 rate of sufficient
duration so that the revised AC-93 rate is effective until the
annual costs rate set forth in Exhibit B, or other rate submitted
to FERC, pursuant to subsections 18(b) through 18(d), becomes
effective. If, at any time during the Term, FERC does not confirm
and approve on an interim or final basis the AC-93 rate or revised
AC-93 rate for any reason other than the duration of the rate
approval period, Bonneville and Puget shall use best efforts to
develop a rate that would replace the AC-93 rate or revised AC-93
rate, and Bonneville shall submit such rate to FERC, pursuant to
section 7(i) of the Regional Act, for confirmation and approval if
such rate is agreed to by Bonneville, Puget and Capacity Owners
other than Puget. If Bonneville and Puget do not succeed in
developing such rate, Bonneville shall submit to FERC, pursuant to
section 7(i) of the Regional Act, a rate which in Bonneville's
judgment recovers Bonneville's costs. Bonneville shall bill
Puget, and Puget shall pay Bonneville, in accordance with the AC-
93 rate or, if FERC does not confirm and approve on an interim or
final basis the AC-93 rate, the rate confirmed and approved by
FERC on an interim or final basis. Bonneville shall revise
Exhibit A so that it contains, at a given time, the AC-93 or other
rate confirmed and approved by FERC on an interim or final basis.
101
19. EXHIBITS
(a) Exhibits A through J attached to this Agreement are by this
reference made a part of this Agreement. In the event of a
conflict between any provision in Exhibits A through J and the
provisions of sections 1 through 23 of this Agreement, the
provisions of sections 1 through 23 of this Agreement shall
prevail.
(b) Bonneville shall revise Exhibit A pursuant to subsections 18(g)
and 18(h) and this subsection 19(b). The rate schedules attached
hereto as Exhibit A have been conditionally or finally confirmed
by FERC. If the final rate schedules which are approved by FERC
are an amendment or modification of the initial rate schedules,
the applicable amended or modified rate schedules and associated
GTRSPs shall be attached to and made part of this Agreement
effective as of the date specified in FERC's approval. The rate
schedules and GTRSPs included in Exhibit A shall be replaced by
successor rate schedules and provisions in accordance with the
provisions of section 7(i) of the Regional Act and FERC rules.
(c) Upon interim or final approval by FERC of any rate submitted to
FERC pursuant to subsections 18(a) through 18(g), Bonneville shall
revise Exhibit B so that Exhibit B contains such rate approved by
FERC as contemplated in this subsection 19(c). For purposes of
this Agreement, such rate shall be effective as of the date of
effectiveness specified in FERC's approval of such rate. Subject
to the provisions of subsections 18(a) through 18(g), the rate
schedule set forth in Exhibit B, Part A and Part B, on the
Effective Date, shall be replaced by successor rate schedules and
provisions pursuant to section 7(i) of the Northwest Power Act and
applicable FERC rules.
102
(d) Bonneville shall revise or modify Exhibit C from time to time to
reflect changes hereafter agreed to in writing by the Parties in
Puget's Capacity Ownership Share, Capacity Ownership Percentage,
Scheduling Percentage, and Scheduling Share.
(e) Bonneville shall revise Exhibit D pursuant to subsection 9(a).
Revision or modification of Exhibit D shall not require an
executed amendment or revision to this Agreement.
(f) Not more frequently than annually, Bonneville shall review and, as
appropriate, revise Exhibit E, Part A, in accordance with
Bonneville's standard methodology and formula for calculation of
average losses incurred by Bonneville in providing transmission on
Bonneville's PNW AC Intertie. Such methodology and formula are
intended to forecast average annual actual losses incurred by
Bonneville in providing transmission on Bonneville's PNW AC
Intertie Operational Transfer Capability. Any changes to the loss
methodology or formula, other than numerical values, shall be made
only after consultation with the Committee. During such
consultation, Bonneville shall provide to the Committee material
pertinent to such changes to the loss methodology or formula.
Upon conclusion of any review of the loss factor in Exhibit E,
Part A, Bonneville shall present the results of its review,
including any revisions to the loss factor in Exhibit E, Part A,
to the Committee as part of the Operating Plan pursuant to section
13. If the Committee pursues arbitration pursuant to subsection
10(b) and section 14, Bonneville shall revise Exhibit E, Part A,
to reflect the selection of the arbitrators pursuant to subsection
14(j).
(g) Bonneville shall revise the loss factor in Exhibit E, Part B, as
necessary to equal the same factor for average losses as
Bonneville generally applies to transmission over Bonneville's
share of the PNW-PSW Intertie. Revision of Exhibit E, Part B,
shall not require an executed amendment or revision to this
Agreement.
(h) Bonneville shall revise Exhibit F as appropriate to reflect the
facilities in Bonneville's PNW AC Intertie. Revision or
modification of
103
Exhibit F shall not require an executed amendment or revision to
this Agreement.
(i) Bonneville shall revise Exhibit G as appropriate to reflect the
complete list of all of the Capacity Owners and their respective
Capacity Ownership Shares and Capacity Ownership Percentages from
time to time pursuant to this Agreement.
(j) Bonneville shall revise Exhibit H as appropriate to reflect all
provisions required by statute or Executive Order. Revision or
modification of Exhibit H shall not require an executed amendment
or revision to this Agreement.
(k) Bonneville shall revise Exhibit I to reflect changes as agreed to
in writing by Puget and Capacity Owners other than Puget.
(l) Bonneville shall revise Exhibit J as mutually agreed to in writing
by the Parties.
20. RULES OF LAW
(a) Bonneville and Puget agree that each fully participated in the
drafting of each provision of this Agreement. The rule of law
interpreting ambiguities against the drafting Party shall not be
applicable to or utilized in resolving any dispute over the
meaning or intent of this Agreement or any of its provisions.
(b) This Agreement shall not be construed to establish a partnership,
association, agency relationship, joint venture, or trust.
Neither Party shall be under the control of or shall be or
represent itself as, the agent of, or have a right or power to
bind, the other Party without the other's express written consent,
except as provided in this Agreement.
(c) All applicable law is incorporated in and made part of this
Agreement.
104
21. NOTICES
(a) Unless the Agreement requires otherwise, any notice, demand or
request provided for in this Agreement, or served, given or made
in connection with it, shall be in writing and shall be served,
given, or made if delivered in person or sent by acknowledged
delivery, or sent by registered or certified mail, postage
prepaid, to the persons addressed as set forth below:
To Bonneville:
Group Vice President for Marketing, Conservation and Production
Bonneville Power Administration
905 NE 11th Avenue
Portland, OR 97232
To Puget:
Vice President Power Planning
Puget Sound Power & Light Company
411 108th Avenue NE 15th Floor
Bellevue, WA 98004-5515
To Seattle:
Director, Power Management Division
Seattle City Light
1111 Third Avenue, Room 420
Seattle, WA 98101
To PNGC:
Director of Power Management
Pacific Northwest Generating Cooperative
711 NE Halsey Street, Suite 200
Portland, OR 97232
105
To Snohomish:
Manager of Power Supply
Public Utility District No. 1 of Snohomish
County, Washington
2320 California Street
P.O. Box 1107
Everett, WA 98201
To Tacoma:
Light Division Superintendent
Tacoma Public Utilities
3628 S. 35th Street
Tacoma, WA 98411
(b) Either Party may, by written notice to the other Party pursuant to
subsection 21(a), change the address set forth in subsection 21(a)
for the notifying Party.
(c) All notices pursuant to this Agreement shall be effective on the
date of receipt.
22. WAIVER
Any waiver at any time by a Party of its rights with respect to any
matter arising in connection with this Agreement shall not be deemed a
waiver with respect to any subsequent or other matter. Except as
otherwise provided herein or as agreed in writing by the Parties, no
provision in this Agreement may be waived except as documented or
confirmed in writing.
23. MISCELLANEOUS
(a) Effect of Section Headings
Section headings and subheadings appearing in this Agreement are
inserted for convenience only and shall not be construed as
interpretations of provisions of this Agreement.
106
(b) Amendments
Except as may be expressly otherwise provided in this Agreement,
this Agreement may be amended only with the express written
consent of both of the Parties, and no provision of this Agreement
shall be varied or contradicted by any oral agreement, course of
dealing or performance or any other matter not hereafter set forth
in a written agreement signed by both of the Parties.
(c) Entire Agreement
This Agreement constitutes, on and as of the date hereof, the
entire agreement of the Parties with respect to the subject matter
of this Agreement, and all prior understandings or agreements,
whether written or oral, between the Parties with respect to the
subject matter of this Agreement are hereby superseded in their
entireties.
(d) No Third Party Beneficiaries
There are no third party beneficiaries of this Agreement. This
Agreement shall not be construed to create rights in, or to grant
remedies to, any third party as a beneficiary of this Agreement or
of any duty, obligation, or undertaking established herein.
(e) Regulatory Approvals
Each Party shall use its best efforts to obtain and maintain in
effect regulatory approvals that are necessary to permit such
Party to perform its obligations under this Agreement in
accordance with its terms and conditions. Neither Party shall
oppose in any way or seek to alter or amend the terms and
conditions of this Agreement by application to or participation in
any application of any regulatory authority or court having
jurisdiction. Puget shall not oppose in any way or seek to alter
or amend the terms or conditions of the annual costs rate set
forth in Exhibit B, the CO-94 rate, the AC-93 rate, or
107
any rate described in section 18 that is agreed to by the Parties
subsequent to each entering into this Agreement, in any proceeding
pursuant to section 7 of the Pacific Northwest Electric Power
Planning and Conservation Act before FERC or in any court of
competent jurisdiction.
(f) Other Capacity Ownership Agreements
If Bonneville offers to enter into (i) a Capacity Ownership
Agreement with any other Capacity Owner or (ii) any written
amendment of any Capacity Ownership Agreement (other than this
Agreement), then Bonneville shall offer to Puget an amendment of
this Agreement that contains the terms and conditions of such
Capacity Ownership Agreement with such other Capacity Owner or of
such written amendment, as the case may be. Bonneville shall
advise, and use reasonable efforts to consult with, Puget during
the development or consideration of any offer to any Capacity
Owner other than Puget to enter into a Capacity Ownership
Agreement or any amendment of such agreement.
(g) Singular and Plural Forms
For purposes of interpreting and construing this Agreement, the
singular form of a word shall include its plural and the plural
form of a word shall include its singular, unless otherwise
expressly provided by this Agreement.
(h) Performance Pending Dispute
Except as otherwise expressly provided in this Agreement, pending
resolution of any dispute, issue, or controversy arising under
this Agreement, the Parties shall each continue performance of
their respective obligations pursuant to this Agreement.
108
(i) Time Periods
For purposes of calculating any time period prescribed by this
Agreement, if the last day of the time period falls on a day that
is not a Working Day, then the last day of the time period shall
be the first Working Day following such day as would otherwise be
the last day of the time period.
(j) Double Counting
In developing rates or charges under section 7 of the Pacific
Northwest Electric Power Planning and Conservation Act for any
rate period, Bonneville shall not set rates or charges that
recover, more than once, the costs associated with capital
projects that are paid or forecast to be paid under the CO-94 rate
and the AC-93 rate and annual costs rate set forth in Exhibit B,
or the remaining Bonneville's PNW AC Intertie costs forecast to be
paid under the AC-93 rate and annual costs rate set forth in
Exhibit B. Bonneville's forecast of revenues chargeable under the
CO-94 rate, AC-93 rate, and annual costs rate set forth in Exhibit
B shall be based on the best available information, including
information provided pursuant to section 13 of this Agreement.
In the event Bonneville proposes any wheeling rate for
transmission service on Bonneville's main grid that includes costs
of the PNW AC Intertie, such proposed rate shall include a credit
or other mechanism that ensures that Puget is not charged any of
the PNW AC Intertie costs for deliveries of power that utilize up
to the Puget's Capacity Ownership Share, as that term is defined
in this Agreement.
(k) Committee Action
Each of the Parties agrees that to the extent it is provided in
sections 13, 14, and 16 that the Committee shall take any action
or shall make any decision, such action or decision shall be taken
or made, as the case may be, by the Committee, and not by Puget
acting individually.
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(l) Fiscal Year
For purposes of this Agreement, the term "fiscal year" shall mean
Bonneville's fiscal year.
(m) Rights and Remedies Cumulative
All rights and remedies of either Party under this Agreement and
at law and in equity shall be cumulative and not mutually
exclusive and the exercise of one right or remedy shall not be
deemed a waiver of any other right or remedy. Nothing contained
in any provision of this Agreement shall be construed to limit or
exclude any right or remedy of either Party (arising on account of
the breach or default by the other Party or otherwise) now or
hereafter existing under any other provision of this Agreement, at
law or in equity.
110
IN WITNESS WHEREOF, the Parties hereto have executed this Agreement.
UNITED STATES OF AMERICA
Department of Energy
Bonneville Power Administration
By Walter E. Pollock
-------------------------
Group Vice President for
Marketing, Conservation and
Production
Name Walter E. Pollock
-------------------
(Print/Type)
Date October 11, 1994
------------------
Puget Sound Power & Light Company
By J. R. Lauckhart
-------------------
Name J. R. Lauckhart
-----------------
(Print/Type)
Title V. P. Power Planning
----------------------
Date 9/26/94
---------
Effective Date _________________
Exhibit A, Page 1 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
Schedule CO-94
CAPACITY OWNERSHIP RATE SCHEDULE
SECTION I. AVAILABILITY
This schedule applies to all agreements which provide life-of-facilities
capacity rights to non-Federal participants (Capacity Owners) in 725 MW
of Bonneville's PNW AC Intertie and any upgrades thereto. Service under
this schedule is subject to Bonneville's General Transmission Rate
Schedule Provisions.
SECTION II. RATE
The charge for capital and related costs for non-Federal capacity
ownership in Bonneville PNW AC Intertie shall be determined by the
methodologies set out in Section III below.
SECTION III. DETERMINATION OF RATE
A. Capacity Ownership Price
The charge for capacity ownership in Bonneville's PNW AC Intertie shall
be the Capacity Ownership Share of the actual capital and related costs
of facilities as determined by the formula shown below. The Capacity
Ownership Share shall be determined pursuant to the Capacity Ownership
agreement.
(A-B)+C+D
--------- = Capacity Ownership Price in $/kW
E
Capacity Ownership Price in $/kW x number of kW contracted for by
Capacity Owner = Capacity Owner's payment to Bonneville.
Where:
A = Bonneville's cost of new facilities for the Third AC
Intertie, which increased the rated transfer capability
of the PNW AC Intertie by approximately 1600 MW, is the
construction costs (including direct, indirect and
overhead costs) of the facilities associated with the
Third AC Intertie System Reinforcements and the Alvey-
Meridian Transmission Line (also known as Eugene-Medford
500 kV Transmission Line), referred to jointly as the
Third AC Intertie Project.
Exhibit A, Page 2 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
B = Bonneville's cost of new facilities needed for the first
800 MW increment of the 1600 MW Third AC Intertie
Project, which includes a portion of the construction
costs (including direct, indirect and overhead costs)
associated with the Third AC Intertie System
Reinforcement.
A-B = The cost of new facilities for the second 800 MW
increment of the 1600 MW Third AC Intertie Project
(presented in Exhibit C of the Capacity Ownership
agreement).
C = Allowance for Funds Used During Construction (AFUDC)
constitutes interest on the funds used for the Third AC
Intertie Project while it was under construction. AFUDC
is calculated and capitalized consistent with FERC
requirements as described in FERC's Uniform System of
Accounts, 18 CFR, Part 101, Electric Plant Instructions,
3.A(17). The AFUDC applies to that amount capitalized on
the second 800 MNW increment of the 1600 MW Third AC
Intertie Project, or A-B.
D = Book value of existing Bonneville support facilities that
are dedicated to the PNW AC Intertie equal to
$19,100,000.
E = 725,000 kW, which equals Bonneville's share of the second
800 MW of the Third AC Intertie.
B. PNW AC Intertie Upgrade Price
The charge for upgrades to Bonneville's PNW AC Intertie facilities that
occur after December 1993, and which result in an increase of rated
transfer capability, shall be the Capacity Ownership Share of the capital
and related costs of the upgrade. The Capacity ownership Share of any
upgrades shall be determined pursuant to the Capacity Ownership
agreement. The capital costs shall consist of the construction costs
(including direct, indirect and overhead costs) and AFUDC (as described
in Section III.A. Above) of the facilities associated with such upgrades.
Exhibit A, Page 3 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
SECTION IV. ADJUSTMENTS AND SPECIAL PROVISIONS
A. Initial Lump Sum Payment
Capacity Owners shall make an initial, lump sum payment of an estimate of
the Capacity Ownership Price equal to $215/kW pursuant to the Capacity
Ownership agreement.
B. Adjustment to Reflect Actual Construction Costs
Approximately December 1995 or as soon as practicable thereafter, the
Capacity owner's initial lump sum payment shall be adjusted to reflect
the difference between the actual and the estimated Capacity ownership
Price. The actual Capacity Ownership Price shall be determined pursuant
to Section III.A. above. There will be no adjustment for the book value
of the support facilities dedicated to the PNW AC Intertie. Capacity
Owners will either receive a refund, with interest, from Bonneville or
make an additional payment, with interest, to Bonneville. Bonneville
shall compute interest using the weighted average interest rate on
Bonneville's outstanding bonds.
C. PNW AC Intertie Upgrade Payments
Capacity Owners shall pay a share of the upgrades to Bonneville's PNW AC
Intertie in the manner and time to be determined when participation in
such upgrades are agreed to pursuant to the Capacity Ownership agreement.
Exhibit A, Page 4 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
Schedule AC-93
Southern Intertie Annual Cost
SECTION I. AVAILABILITY
This schedule is applicable to all parties (New Owners) that execute PNW AC
Intertie Capacity Ownership Agreements (Agreements) and will be effective on
the date described in the Agreement. Service under this schedule is subject
to BPA's General Transmission Rate Schedule Provisions.
SECTION II. RATE
The rate charges reflect the terms of the Memorandum of Understanding (MOU),
signed in the fall of 1991, between BPA and potential New owners. The MOU
provides for the payment by New Owners of their prorated share of: (1) BPA's
annual operations, maintenance and general plant expense (including
applicable (overheads) properly chargeable to the AC Intertie facilities; and
(2) BPA's share of capitalized replacements on the AC Intertie. The monthly
charge shall be the sum of the charges specified in sections II.A. and II.B.
A. Operations, Maintenance, and General Plant
The monthly charge shall equal $325 per megawatt of billing demand.
B. Replacements
The monthly charge shall equal $0 per megawatt of billing demand.
SECTION III. ADJUSTMENT TO REPLACEMENT RATE
A. Determination of Billing Adjustment
New Owners will receive a billing adjustment if BPA incurs AC Intertie
replacement cost during the rate period. The Replacements Rate
Adjustment equals
AC Intertie work orders ($000) * %
----------------------------------
725 MW * # months
where
"# months" equals: (1) the number of months that this
rate is in effect during the fiscal year for the Initial
Replacements Rate Adjustment; or (2) the number of
months in the rate period for the Final Replacements
Rate Adjustment; and
"%" equals the New Owners' percentage share of BPA's
total AC Intertie Rated Transfer Capability as specified
in the Agreements.
Exhibit A, Page 5 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
B. Initial Replacements Rate Adjustment
New Owners will receive a billing adjustment for each fiscal year that
BPA incurs AC Intertie replacement cost. At the end of each fiscal year,
the cost associated with AC Intertie capital replacement work orders that
have closed during the fiscal year will be determined. The unit rate
that would result using these closed work orders is the basis of the
Initial Replacements Rate Adjustment.
1. Notice Provisions
Following each fiscal year, BPA shall notify all New Owners by
December 15, of the proposed Replacements Rate Adjustment. BPA will
provide the calculation of the adjustment and a short description of
the work performed and the associated cost used as the basis for the
billing adjustment. In addition to written notification, BPA may,
but is not obligated to, hold a public meeting to clarify its
determinations.
Written comments on the Initial Replacements Rate Adjustment will be
accepted through the end of January. Consideration of comments
submitted by the New Owners may result in the billing adjustment
differing from the initially proposed adjustment. BPA shall notify
all New Owners of the Initial Replacements Rate Adjustment by the
last day of February.
2. Adjustment of Monthly Bills
An adjustment will be made on the New Owner's monthly bill prepared
during March. The Initial Replacements Rate adjustment will be
multiplied by the sum of the monthly billing factors from the
relevant fiscal year (i.e., the New Owner's share in megawatts of
BPA's PNW AC Intertie Rated Transfer Capability multiplied by the
numbers of months that this rate schedule is effective during the
fiscal year). The Initial Replacements Rate Adjustment will appear
as a charge to the New Owner on the monthly bill prepared during
March.
C. Final Replacements Rate Adjustment
The actual costs associated with the AC Intertie capital replacement work
orders that occur during the rate period may change after BPA performs
its final analysis of the work orders. BPA shall compare the unit rate
for the rate period using the results of the final work order analysis to
the weighted average of the unit rates from the Initial Replacements Rate
Adjustments.
1. Notice Provisions
BPA shall notify all New Owners in May 1998 of the results of the
calculations, an explanation of work order changes(s), and any
Exhibit A, Page 6 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
resulting billing adjustment. Written comments from New Owners will
be accepted through the end of June. BPA shall notify all New Owners
of the Final Replacements Rate Adjustment by July 31. Consideration
of comments submitted by the New Owners may result in the Final
Replacements Rate Adjustment differing from the initially proposed
adjustment.
2. Adjustment of Monthly Bills
If the absolute value of the Final Replacements Rate Adjustment is
greater than or equal to $1 per megawatt per month, an adjustment
will be made on the New Owner's monthly bill prepared during August.
For each New Owner, the Final Replacements Rate Adjustment will be
multiplied by the sum of the monthly billing factors from the
relevant fiscal years (i.e., the New Owner's share in megawatts of
BPA's PNW AC Intertie Rated Transfer Capability multiplied by the
number of months that this rate schedule is effective during the
fiscal years). The Final Replacements Rate Adjustment will appear as
a charge or credit to the New Owner on the monthly bill prepared
during August. Interest, as determined by BPA's Office of Financial
Management, will be included in any adjustment.
SECTION IV. BILLING FACTOR
The billing demand shall be the New Owner's capacity ownership share in
megawatts of BPA's PNW AC Intertie Rated Transfer Capability as specified in
the Agreement.
Exhibit A, Page 7 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
SCHEDULE IS-93
SECTION I. AVAILABILITY
This schedule supersedes IS-91 and is available for all transmission on the
Southern Intertie. Service under this schedule is subject to BPA's General
Transmission Rate Schedule Provisions.
SECTION II. RATE
A. Nonfirm Transmission Rate
The charge for nonfirm transmission of non-BPA power shall be 3.11 mills
per kilowatthour of billing energy. This charge applies for both north-
to-south and south-to-north transactions.
B. Firm Transmission Rate
The charge for firm transmission service shall be $0.706 per kilowatt per
month of billing demand and 1.69 mills per kilowatthour of billing
energy. Firm transmission will only be made available to customers under
this rate schedule who have executed a contract with BPA specifying use
of the Firm Transmission rate for either north-to-south or south-to-north
transactions.
SECTION III. BILLING FACTORS
A. For services under Section II.A. the billing energy shall be the monthly
sum of the scheduled kilowatthours, plus the monthly sum of kilowatthours
allocated but not scheduled. The amount of allocated but not scheduled
energy that is subject to billing may be reduced pro rata by BPA due to
forced Intertie outages and other uncontrollable forces that may reduce
Intertie capacity. The amount of allocated but not scheduled energy that
is subject to billing also may be reduced upon mutual agreement between
BPA and the customer.
B. For services under Section II.B. the billing demand shall be the
Transmission Demand as defined in the Agreement. The billing energy
shall be the monthly sum of scheduled kilowatthours, unless otherwise
specified in the Agreement.
Exhibit A, Page 8 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
General Transmission Rate Schedule Provisions
SECTION I. ADOPTION OF REVISED TRANSMISSION RATE SCHEDULES AND GENERAL
TRANSMISSION RATE SCHEDULE PROVISIONS (GTRSPs)
A. Approval of Rates
These rate schedules and GTRSPs shall become effective upon interim
approval or upon final confirmation and approval by FERC. BPA will
request FERC approval effective October 1, 1993.
B. General Provisions
These 1993 Transmission Rate Schedules and associated GTRSPs are
virtually identical to and supersede BPA's 1991 Transmission Rate
schedules and GTRSPs (which became effective October 1, 1992) but do not
supersede prior rate schedules required by agreement to remain in force.
Transmission service provided shall be subject to the following Acts, as
amended: the Bonneville Project Act, the Regional Preference Act (P.L.
88-552), the Federal Columbia River Transmission System Act, and the
Pacific Northwest Electric Power Planning and Conservation Act, and the
Energy Policy Act of 1992, Pub. L. 102-486, 106 Stat. 2776 (1992).
The meaning of terms used in the transmission rate schedules shall be as
defined in agreements or provisions which are attached to the Agreement
or as in any of the above Acts.
C. Interpretation
If a provision in the executed Agreement is in conflict with a provision
contained herein, the former shall prevail.
SECTION II. BILLING FACTOR DEFINITIONS AND BILLING ADJUSTMENTS
A. Billing Factors
1. Scheduled Demand
The largest of hourly amounts wheeled which are scheduled by the
customer during the time period specified in the rate schedules.
2. Metered Demand
The Metered Demand in kilowatts shall be the largest of the 60-minute
clock-hour integrated demands measured by meters installed at each
POD during each time period specified in the applicable rate
schedule. Such measurements shall be made as specified in the
Agreement. BPA, in determining the Metered Demand, will exclude any
abnormal readings due to or resulting from: (a) emergencies or
Exhibit A, Page 9 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
breakdowns on, or maintenance of, the FCRTS; or (b) emergencies on
the customer's facilities, provided that such facilities have been
adequately maintained and prudently operated as determined by BPA.
If more than one class of power is delivered to any POD, the portion
of the metered quantities assigned to any class of power shall be as
agreed to by the parties. The amount so assigned shall constitute
the Metered Demand for such class of power.
3. Transmission Demand
The demand as defined in the Agreement.
4. Total Transmission Demand
The sum of the transmission demands as defined in the Agreement.
5. Ratchet Demand
The maximum demand established during the previous 11 billing months.
Exception: if a Transmission Demand or Total Transmission Demand has
been decreased pursuant to the terms of the Agreement during the
previous 11 billing months, such decrease will be reflected in
determining the Ratchet Demand.
B. Billing Adjustments
Average Power Factor
The adjustment for average power factor, when specified in a transmission
rate schedule or in the Agreement, shall be made in accordance with the
average power factor section of the General Wheeling Provisions.
To maintain acceptable operating conditions on the Federal system, BPA
may restrict deliveries of power at any time that the average leading
power factor or average lagging power factor for all classes of power
delivered to such point or to such system is below 85 percent.
SECTION III. OTHER DEFINITIONS
Definitions of the terms below shall be applied to these provisions and the
Transmission Rate Schedules, unless otherwise defined in the Agreement.
A. Agreement
An agreement between BPA and a customer to which these rate schedules and
provisions may be applied.
Exhibit A, Page 10 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
B. Eastern Intertie
The segment of the FCRTS for which the transmission facilities consist of
the Townsend-Garrison double-circuit 500 kV transmission line segment
including related terminals at Garrison
C. Electric Power
Electric peaking capacity (kW) and/or electric energy (kWh).
D. Federal Columbia River Transmission System
The transmission facilities of the Federal Columbia River Power System,
which include all transmission facilities owned by the government and
operated by BPA, and other facilities over which BPA has obtained
transmission rights.
E. Firm Transmission Service
Transmission service which BPA provides for any non-BPA power except for
transmission service which is scheduled as nonfirm. If the firm service
is provided pursuant to the Agreement, the terms of the Agreement may
further define the service.
F. Integrated Network
The segment of the FCRTS for which the transmission facilities provide
the bulk of transmission of electric power within the Pacific Northwest,
excluding facilities not segmented to the network as shown in the
Wholesale Power Rate Development Study used in BPA's rate development.
G. Main Grid
As used in the FPT and IR rate schedules, that portion of the Integrated
Network with facilities rated 230 kV and higher.
H. Main Grid Distance
As used in the FPT rate schedules, the distance in airline miles on the
Main Grid between the POI and the POD, multiplied by 1.15.
I. Main Grid Interconnection Terminal
As used in the FPT rate schedules, Main Grid terminal facilities that
interconnect the FCRTS with non-BPA facilities.
J. Main Grid Miscellaneous Facilities
As used in the FPT rate schedules, switching, transformation, and other
facilities of the Main Grid not included in other components.
Exhibit A, Page 11 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
K. Main Grid Terminal
As used in the FPT rate schedules, the Main Grid terminal facilities
located at the sending and/or receiving end of a line exclusive of the
Interconnection terminals.
L. Nonfirm Transmission Service
Interruptible transmission service which BPA may provide for non-BPA
power.
M. Northern Intertie
The segment of the FCRTS for which the transmission facilities consist of
two 500 kV lines between Custer Substation and the United States-Canadian
border, one 500 kV line between Custer and Monroe Substations, and two
230 kV lines from Boundary Substation to the United States-Canadian
border, and the associated substation facilities.
N. Point of Integration (POI)
Connection points between the FCRTS and non-BPA facilities where non-
Federal power is made available to BPA for wheeling.
O. Point of Delivery (POD)
Connection points between the FCRTS and non-BPA facilities where non-
Federal power is delivered to a customer by BPA.
P. Secondary System
As used in the FPT and IR rate schedules that portion of the Integrated
Network facilities with operating voltage of 115 kV or 69 kV.
Q. Secondary System Distance
As used in the FPT rate schedules, the number of circuit miles of
Secondary System transmission lines between the secondary POI and the
Main Grid or the secondary POD, or the Main Grid and the secondary POD.
R. Secondary System Interconnection Terminal
As used in the FPT rate schedules, the terminal facilities on the
Secondary System that interconnect the FCRTS with non-BPA facilities.
S. Secondary System Intermediate Terminal
As used in the FPT rate schedules, the first and final terminal
facilities in the Secondary System transmission path exclusive of the
Secondary System Interconnection terminals.
Exhibit A, Page 12 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
T. Secondary Transformation
As used in the FPT rate schedules, transformation from Main Grid to
Secondary System facilities.
U. Southern Intertie
The segment of the FCRTS for which the major transmission facilities
consist of two 500 kV AC lines from John Day Substation to the Oregon-
California border, a portion of the 500 kV AC line from Buckley
Substation to Summer Lake Substation; when completed, the Third AC
facilities which include Captain Jack Substation and the Alvey-Meridian
500 kV AC line; one 1,000 kV DC line between the Celilo Substation and
the Oregon-Nevada border, and associated substation facilities.
V. Transmission Service
As used in the MT rate schedule, Transmission Service is as defined in
the Western Systems Power Pool Agreement.
SECTION IV. BILLING INFORMATION
A. Payment of Bills
Bills for transmission service shall be rendered monthly by BPA. Failure
to receive a bill shall not release the customer from liability for
payment. Bills for amounts due of $50,000 or more must be paid by direct
wire transfer, customers who expect that their average monthly bill will
not exceed $50,000 and who expect special difficulties in meeting this
requirement may request, and BPA may approve, an exemption from this
requirement. Bills for amounts due BPA under $50,000 may be paid by
direct wire transfer or mailed to the Bonneville Power Administration,
P.O. Box 6040, Portland, Oregon 97228-6040, or to another location as
directed by BPA. The procedures to be following in making direct wire
transfers will be provided by the Office of Financial Management and
updated as necessary.
1. Computation of Bills
The transmission billing determinant is the electric power quantified
by the method specified in the agreement or Transmission Rate
Schedule. Scheduled power or metered power will be used.
The transmission customer shall provide necessary information to BPA
for any computation required to determine the proper charges for use
of the FCRTS, and shall cooperate with BPA in the exchange of
additional information which may be reasonably useful for respective
operations.
Demand and energy billings for transmission service under each
applicable rate schedule shall be rounded to whole dollar amounts, by
Exhibit A, Page 13 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
eliminating any amount which is less than 50 cents and increasing any
amounts from 50 cents through 99 cents to the next higher dollar.
2. Estimated Bills
At its option, BPA may elect to render an estimated bill to be
followed at a subsequent billing date by a final bill. The estimated
bill shall have the validity of and be subject to the same payment
provisions as a final bill.
3. Billing Month
For charges based on scheduled quantities, the billing month is the
calendar month. For charges based on metered quantities, the billing
month is defined as the interval between scheduled meter-reading
dates. The billing month will not exceed 31 days in any case. While
it may be necessary to read meters on a day other than the scheduled
meter-reading date, for determination of billing demand, the billing
month will cease at 2400 hours on the last scheduled meter-reading
date. Schedules will be predetermined. The customer must give 30
days notice to request a change to the schedule.
4. Due Date
Bills shall be due by close of business on the 20th day after the
date of the bill (due date). should the 20th day be a Saturday,
Sunday, or holiday (as celebrated by the customer), the due date
shall be the next following business day.
5. Late Payment
Bills not paid in full on or before close of business on the due date
shall be subject to a penalty charge of $25. In addition, an
interest charge of one-twentieth percent (0.05 percent) shall be
applied each day to the sum of the unpaid amount and the penalty
charge. This interest charge shall be assessed on a daily basis
until such time as the unpaid amount and penalty charge are paid in
full.
Remittances received by mail will be accepted without assessment of
the charges referred to in the preceding paragraph provided the
postmark indicates the payment was mailed on or before the due date.
Whenever a power bill or a portion thereof remains unpaid subsequent
to the due date and after giving 30 days' advance notice in writing,
BPA may cancel the contract for service to the customer. However,
such cancellation shall not affect the customer's liability for any
charges accrued prior thereto under such agreement.
6. Disputed Billings
In the event of a disputed billing, full payment shall be rendered to
BPA and the disputed amount noted. Disputed amounts are subject to
Exhibit A, Page 14 of 14
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
the late payment provisions specified above. BPA shall separately
account for the disputed amount. If it is determined that the
customer is entitled to the disputed amount, BPA shall refund the
disputed amount with interest, as determined by BPA's Office of
Financial Management.
BPA retains the right to verify, in a manner satisfactory to the
Administrator, all data submitted to BPA for use in the calculation
of BPA's rates and corresponding rate adjustments. BPA also retains
the right to deny eligibility for any BPA rate or corresponding rate
adjustment until all submitted data have been accepted by BPA as
complete, accurate, and appropriate for the rate or adjustment under
consideration.
7. Revised Bills
As necessary, BPA may render a revised bill.
a. If the amount of the revised bill is less than or equal to the
amount of the original bill, the revised bill shall replace all
previous bills issued by BPA that pertain to the specified
customer for the specified billing period and the revised bill
shall have the same date as the replaced bill.
b. If a revision causes an additional amount to be due BPA or the
specified customer beyond the amount of the original bill, a
revised bill will be issued for the difference and the date of
the revised bill shall be its date of issue.
Exhibit B, Page 1 of 9
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
ANNUAL COSTS RATE
A. PROPOSED SOUTHERN INTERTIE ANNUAL COST RATE
SECTION I. AVAILABILITY
This schedule is applicable to each party (Capacity Owner) that executes a
PNW AC Intertie Capacity Ownership Agreement (Agreement). Billings pursuant
to this schedule is subject to the Billing Provisions in Exhibit B of the
Agreement. This rate schedule shall be effective on the first day of the
fiscal year following the earlier of interim or final FERC approval of this
rate schedule. Unless otherwise defined in this rate schedule, capitalized
terms used in this rate schedule shall have the respective definitions set
forth in section 1 of this Agreement.
SECTION II. RATE
A. OPERATIONS
The monthly charge equals:
Operations Cost * Capacity Ownership Percentage
-----------------------------------------------
Months
Where
"Months" is equal to 12, or, if the Operating Plan has, during the
fiscal year to which such Operating Plan pertains, been amended
with respect to Operations Cost, the number of full months
remaining in the fiscal year after such amended Operating Plan
becomes effective for which Capacity Owners have not been billed.
"Operations Cost" means, upon and after the effective date of Exhibit
B pursuant to this Agreement, for any fiscal year any Allocated
Direct Costs for Bonneville's PNW AC Intertie, operations Indirect
Costs for Bonneville's PNW AC Intertie, and operations Overhead
Costs for Bonneville's PNW AC Intertie for such fiscal year, each
being determined in accordance with section I of Exhibit I.
"Capacity Ownership Percentage" is as defined in subsection 1(k) of
each Capacity Owner's Agreement.
The monthly charge for the Operations rate shall be calculated using the
forecast Operations Cost in the Operating Plan in effect during the
month for which the monthly charge is calculated; provided, however, if
the Operating Plan is amended during the fiscal year to which such
Operating Plan pertains, the monthly charge for Operations Cost shall be
calculated using the forecast Operations Cost less the Operations Cost
Exhibit B, Page 2 of 9
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
already billed for such fiscal year for the remaining months of the
fiscal year following such amendment.
B. MAINTENANCE
The monthly charge equals:
Maintenance Cost * Capacity Ownership Percentage
------------------------------------------------
Months
Where
"Months" is equal to 12, or, if the Operating Plan has, during the
fiscal year to which such Operating Plan pertains, been amended
with respect to Maintenance Cost, the number of full months
remaining in the fiscal year after such amended Operating Plan
becomes effective for which Capacity Owners have not been billed.
"Maintenance Cost" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any fiscal year any
maintenance Direct Costs for Bonneville's PNW AC Intertie,
maintenance Indirect Costs for Bonneville's PNW AC Intertie, and
maintenance Overhead Costs for Bonneville's PNW AC Intertie for
such fiscal year, each being determined in accordance with section
II of Exhibit I.
"Capacity Ownership Percentage" is as defined in subsection 1(k) of
each Capacity Owner's Agreement.
The monthly charge for the Maintenance rate shall be calculated using
the forecast Maintenance Cost in the Operating Plan in effect during the
month for which the monthly charge is calculated; provided, however, if
the Operating Plan is amended during the fiscal year to which such
Operating Plan pertains, the monthly charge for Maintenance Cost shall
be calculated using the forecast Maintenance Cost less the Maintenance
Cost already billed for such fiscal year for the remaining months of the
fiscal year following such amendment.
C. GENERAL PLANT
The monthly charge equals:
General Plant Cost * Capacity Ownership Percentage
--------------------------------------------------
Months
Where
"Months" is equal to 12, or, if the Operating Plan has, during the
fiscal year to which such Operating Plan pertains, been amended
Exhibit B, Page 3 of 9
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
with respect to General Plant Cost, the number of full months
remaining in the fiscal year after such amended Operating Plan
becomes effective for which Capacity Owners have not been billed.
"General Plant Cost" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any fiscal year any costs
(including direct costs, indirect costs, overhead costs, and AFUDC)
for Bonneville's general plant investment for such fiscal year.
The method for determining General Plant Cost is set forth in
section IV of Exhibit I.
"Capacity Ownership Percentage" is as defined in subsection 1(k) of
each Capacity Owner's Agreement.
The monthly charge for the General Plant rate shall be calculated using
the General Plant Cost in the Operating Plan in effect during the month
for which the monthly charge is calculated; provided, however, if the
Operating Plan is amended during the fiscal year to which such Operating
Plan pertains, the monthly charge for General Plant Cost shall be
calculated using the General Plant Cost less the General Plant Cost
already billed for such fiscal year for the remaining months of the
fiscal year following such amendment.
D. OTHER COSTS
The monthly charge equals:
Other Costs * Capacity Ownership Percentage
-------------------------------------------
Months
Where
"Months" is equal to 12, or, if the Operating Plan has, during the
fiscal year to which such Operating Plan pertains, been amended
with respect to Other Cost, the number of full months remaining in
the fiscal year after such amended Operating Plan becomes effective
for which Capacity Owners have not been billed.
"Other Costs" means, upon and after the effective date of Exhibit B
pursuant to this Agreement, Bonneville's other costs for
Bonneville's PNW AC Intertie described in and determined pursuant
to section V of Exhibit I.
"Capacity Ownership Percentage" is as defined in subsection 1(k) of
each Capacity Owner's Agreement.
The monthly charge for the Other Costs rate shall be calculated using
the forecast Other Costs in the Operating Plan in effect during the
month for which the monthly charge is calculated; provided, however, if
the Operating Plan is amended during the fiscal year to which such
Operating Plan pertains, the monthly charge for Other Costs shall be
Exhibit B, Page 4 of 9
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
calculated using the forecast Other Costs less the Other Costs already
billed for such fiscal year for the remaining months of the fiscal year
following such amendment.
E. CONTRACTS AND RATES
The monthly charge equals:
Contracts and Rates Costs * Capacity Ownership Percentage
---------------------------------------------------------
Months
Where
"Months" is equal to 12, or, if the Operating Plan has, during the
fiscal year to which such Operating Plan pertains, been amended
with respect to Contracts and Rates Cost, the number of full months
remaining in the fiscal year after such amended Operating Plan
becomes effective for which Capacity Owners have not been billed.
"Contracts and Rates Costs" means, upon and after the effective date
of Exhibit B pursuant to this Agreement, for any fiscal year
Bonneville's total contracts and rates costs (as described in
section VI of Exhibit I) for such fiscal year as functionalized and
allocated in accordance with section VI of Exhibit I to determine
Contracts and Rates Costs for Bonneville's PNW AC Intertie.
"Capacity Ownership Percentage" is as defined in subsection 1(k) of
each Capacity Owner's Agreement.
Contracts and Rates Cost is determined in accordance with section VI of
Exhibit I as of the Effective Date. If Exhibit I is amended pursuant to
subsection 19(k) of the Agreement to provide that the Contracts and
Rates Cost determined in accordance with section VI of Exhibit I (and
reflected in the Operating Plan for the fiscal year to which such
Operating Plan pertains) is directly assigned to the Capacity Owners
pursuant to such amended Exhibit I (and reflected in the Operating Plan
for the fiscal year to which such Operating Plan pertains), the Capacity
Ownership Percentage in the monthly charge calculation for such fiscal
year shall be replaced by the ratio of (a) each Capacity Ownership Share
to (b) the sum of all Capacity Ownership Shares.
The monthly charge for the Contracts and Rates rate shall be calculated
using the forecast Contracts and Rates Costs in the Operating Plan in
effect during the month for which the monthly charge is calculated;
provided, however, if the Operating Plan is amended during the fiscal
year to which such Operating Plan pertains, the monthly charge for
Contracts and Rates Cost shall be calculated using the forecast
Contracts and Rates Cost less the Contracts and Rates Cost already
billed for such fiscal year for the remaining months of the fiscal year
following such amendment.
Exhibit B, Page 5 of 9
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
F. POWER SCHEDULING
The monthly charge equals:
Power Scheduling Costs * Capacity Ownership Percentage
------------------------------------------------------
Months
Where
"Months" is equal to 12, or, if the Operating Plan has, during the
fiscal year to which such Operating Plan pertains, been amended
with respect to Power Scheduling Cost, the number of full months
remaining in the fiscal year after such amended Operating Plan
becomes effective for which Capacity Owners have not been billed.
"Power Scheduling Costs" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, Bonneville's total power
scheduling costs (as described in section VII of Exhibit I) as
functionalized and allocated in accordance with section VII of
Exhibit I to determine Power Scheduling Costs for Bonneville's PNW
AC Intertie.
"Capacity Ownership Percentage" is as defined in subsection 1(k) of
each Capacity Owner's Agreement.
Power Scheduling Cost is determined in accordance with section VII of
Exhibit I as of the Effective Date. If Exhibit I is amended pursuant to
subsection 19(k) of the Agreement to provide that the Power Scheduling
Cost determined in accordance with section VII of Exhibit I (and
reflected in the Operating Plan for the fiscal year to which such
Operating Plan pertains) is directly assigned to the Capacity Owners
pursuant to such amended Exhibit I (and reflected in the Operating Plan
for the fiscal year to which such Operating Plan pertains), the Capacity
Ownership Percentage in the monthly charge calculation for such fiscal
year shall be replaced by the ratio of (a) each Capacity Ownership Share
to (b) the sum of all Capacity Ownership Shares.
The monthly charge for the Power Scheduling rate shall be calculated
using the forecast Power Scheduling Costs in the Operating Plan in
effect during the month for which the monthly charge is calculated;
provided, however, if the Operating Plan is amended during the fiscal
year to which such Operating Plan pertains, the monthly charge for Power
Scheduling Cost shall be calculated using the forecast Power Scheduling
Cost less the Power Scheduling Cost already billed for such fiscal year
for the remaining months of the fiscal year following such amendment.
G. END OF TERM
The monthly charge shall equals:
End of Term Costs * Capacity Ownership Percentage
Exhibit B, Page 6 of 9
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
-------------------------------------------------
Months
Where
"Months" is equal to 12, or, if the Operating Plan has, during the
fiscal year to which such Operating Plan pertains, been amended
with respect to End of Term Costs, the number of full months
remaining in the fiscal year after such amended Operating Plan
becomes effective for which Capacity Owners have not been billed.
"End of Term Costs" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, Bonneville's costs associated
with decommissioning the PNW AC Intertie determined in accordance
with section VIII of Exhibit I.
"Capacity Ownership Percentage" is as defined in subsection 1(k) of
each Capacity Owner's Agreement.
The monthly charge for the End of Term rate shall be calculated using
the forecast End of Term Costs in the Operating Plan in effect during
the month for which the monthly charge is calculated; provided, however,
if the Operating Plan is amended during the fiscal year to which such
Operating Plan pertains, the monthly charge for End of Term Costs shall
be calculated using the forecast End of Term Costs less the End of Term
Cost already billed for such fiscal year for the remaining months of the
fiscal year following such amendment.
H. REPLACEMENTS AND REINFORCEMENTS
1. For each Replacement, the charge equals:
Replacement Cost * Capacity Ownership Percentage
2. For each Reinforcement, the charge equals:
Reinforcement Cost * Capacity Ownership Percentage
Where
"Replacement Cost" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any Replacement, the
Direct Costs, Indirect Costs, Overhead Costs, and AFUDC for such
Replacement, all capitalized to plant-in-service together with (1)
simple interest on the foregoing costs accrued from the date on
which Bonneville stops accruing AFUDC on the foregoing costs until
the due date of the bill to Capacity Owner for the foregoing costs
pursuant to subparagraph 9(b)(2)(B) and (2) the costs of removal
and any salvage credit associated with removal or replacement of
Exhibit B, Page 7 of 9
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
existing facilities. Replacement Cost does not include capitalized
general plant cost. The method for determining Replacement Costs
for Bonneville's PNW AC Intertie is set forth in section III of
Exhibit I.
"Reinforcement Cost" means, upon and after the effective date of
Exhibit B pursuant to this Agreement, for any Reinforcement, the
Direct Costs, Indirect Costs, Overhead Costs, and AFUDC for such
Reinforcement, all capitalized to plant-in-service together with
(1) simple interest on the foregoing costs accrued from the date on
which Bonneville stops accruing AFUDC on the foregoing costs until
the due date of the bill to Capacity Owner for the foregoing costs
pursuant to subparagraph 9(b)(2)(B) and (2) the costs of removal
and any salvage credit associated with removal or replacement of
existing facilities. Reinforcement Cost does not include
capitalized general plant cost. The method for determining
Reinforcement Costs for Bonneville's PNW AC Intertie is set forth
in section III of Exhibit I.
"Capacity Ownership Percentage" is as defined in subsection 1(k) of
each Capacity Owner's Agreement.
The charge for the Replacements and Reinforcements rate shall use the
actual Replacement Cost and Reinforcement Cost in the Operating Plan.
SECTION III. ADJUSTMENTS
If an amendment to the Operating Plan results in a net amount that
Bonneville owes the Capacity Owners pursuant to sections II.A-G or
pursuant to section II.H, Bonneville shall refund such net amount
pursuant to paragraph 9(f)(4) of the Agreement.
The monthly charges assessed Capacity Owners under sections II.A-G shall
be adjusted, and payment or refund made with interest, pursuant to
paragraphs 9(b)(2) or 9(f)(4) of the Agreement, to reflect amendments to
the Operating Plan that occur after the year to which such Operating
Plan pertains. A Capacity Owner's share of the adjustment shall be
determined using the same Capacity Ownership Percentage used in the
billings under sections II.A-G during the fiscal year that such
Operating Plan is effective.
B. BILLING PROVISIONS
I. General Provisions
A. Approval of Rates
The annual costs rate shall become effective upon interim approval or
upon final confirmation and approval by FERC. Bonneville will request
FERC approval of such rate schedule effective on the first day of a
Bonneville fiscal year.
Exhibit B, Page 8 of 9
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
B. Application of Billing Provisions
These Billing Provisions shall apply to bills rendered by Bonneville
pursuant to the annual costs rate.
C. Definition of Terms
The meaning of terms used in the AC-95 rate shall be as defined in the
Agreement or, if no definition is provided by the Agreement, such terms
shall be defined according to applicable Federal law.
II. Billing Information
Payment of Bills
Charges pursuant to the AC-95 rate shall be included in Bonneville's
monthly power bill to Capacity Owner. Failure to receive a power bill
shall not release Capacity Owner from liability for payment. Power
bills for amounts due of $50,000 or more must be paid by direct wire
transfer. If Capacity Owner anticipates special difficulties in meeting
this requirement, Capacity Owner may request and Bonneville may approve
an exemption from this requirement. Power bills for amounts due
Bonneville under $50,000 may be paid by direct wire transfer or mailed
to the Bonneville Power Administration, P.O. Box 6040, Portland, Oregon
97228-6040, or to another location as directed by Bonneville. The
procedures to be followed in making direct wire transfers will be
provided by Bonneville's Financial Services Group and updated as
necessary.
(1) Computation of Bills
(a) Bonneville shall bill Capacity Owner in accordance with the
annual costs rate.
(b) Capacity Owner shall provide necessary information to
Bonneville for any computation required to determine proper charges
pursuant to the Agreement and shall cooperate with Bonneville in
the exchange of additional information which may be reasonably
useful for respective operations.
(c) Bills rendered pursuant to this Agreement shall be rounded to
whole dollar amounts, by eliminating any amount which is less than
50 cents and increasing any amounts from 50 cents to 99 cents to
the next higher whole dollar.
(2) Billing Month
For charges pursuant to the annual costs rate the billing month shall be
the same as for the power bill rendered by Bonneville to Capacity Owner.
(3) Due Date
Exhibit B, Page 9 of 9
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Charges pursuant to the annual costs rate shall be included in the power
bill rendered by Bonneville to Capacity Owner and shall be due as part
of the power bill when such power bill is due.
(4) Late Payment
The penalties for failure to pay a bill in full on or before close of
business on the due date shall be the same as those contained in the
late payment provisions in Bonneville's General Transmission Rate
Schedule Provisions in effect on the date of the bill; provided,
however, that no other provision of any such General Transmission Rate
Schedule Provisions, including, but not limited to, provisions regarding
cancellation, termination, or suspension of service, shall have
application with respect to the payment of any rate or charge pursuant
to the annual costs rate set forth in Exhibit B. Bonneville's right to
suspend service for late payment under the Agreement shall be pursuant
to paragraph 9(e)(1) of this Agreement, which right shall in no way be
limited by this section.
(5) Disputed Bills
In the event of a disputed bill, full payment shall be rendered to
Bonneville and the disputed amount noted. Disputed amounts are subject
to the late payment provisions specified in section II(4) of the Billing
Provisions of this Exhibit B. Bonneville shall separately account for
the disputed amount. If it is determined that Capacity Owner is
entitled to the disputed amount, Bonneville shall refund the disputed
amount with interest, such interest to be determined by Bonneville's
Financial Services Group. In the event that Bonneville and Capacity
Owner do not resolve such dispute, Capacity Owner shall not be
prevented by this section II(5)of the Billing Provisions of this Exhibit
B from initiating arbitration pursuant to and to the extent allowed by
section 15 of this Agreement.
(6) Revised Bills
If Bonneville determines that it has over- or under-charged Capacity
Owner due to a computational error or pursuant to an amendment to the
Operating Plan in any given billing month, Bonneville may render to
Capacity Owner a revised bill.
(i) If the amount of the revised bill is less than or equal to the
amount of the original bill for such billing month, the revised
bill shall replace the original bill issued by Bonneville. The
revised bill shall have the same date as the original bill.
(ii) If the amount of the revised bill is greater than the amount
of the original bill for such billing month, a new bill will be
issued for the difference between the revised bill and the original
bill. The date of the new bill shall be its date of issuance, and
Capacity Owner shall make payment to Bonneville as specified in the
Billing Provisions of this Exhibit B.
Exhibit C, Page 1 of 1
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
CAPACITY OWNERSHIP SHARE, CAPACITY OWNERSHIP PERCENTAGE
SCHEDULING PERCENTAGE, AND SCHEDULING SHARE
Capacity Ownership
Share = 400 MW
Capacity Ownership
Percentage = Capacity Ownership Share divided by
Bonneville's PNW AC Intertie Rated
Transfer Capability (1)
Scheduling Percentage = Capacity Ownership Share divided by
PNW AC Intertie Rated Transfer Capability
Scheduling Share = Scheduling Percentage PNW AC Intertie
Operational Transfer Capability
- --------------------
(1) As of the Effective Date, Bonneville's PNW AC Intertie Rated Transfer
Capability in a north-to-south direction, calculated in accordance with
the Northwest Intertie Agreements equals 3450 MW (total PNW AC Intertie
Rated Transfer Capability (4800MW) - Portland's PNW AC Intertie Rated
Transfer Capability (950 MW) - PacifiCorp's PNW AC Intertie Rated
Transfer Capability (400 MW)).
Exhibit D, Page 1 of 5
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
LUMP SUM PAYMENT CALCULATION
A. SECOND 800 MW COSTS, ESTIMATED (1), ACTUAL (2), AND REVISED ACTUAL (3)
($ in Thousands)
(2) BPA's
(1) BPA's Costs
FACILITIES WHOSE COSTS WILL BE ADJUSTED BPA's Costs Costs Revised
Using Change Between Estimate And Actual Estimated Actual Actual
- ---------------------------------------- ----------- -------- -------
1. Alvey (Marion-Alvey Caps) $5,739
2. Slatt (Loop in - Breaker) 3,044
3. Grizzly (BPA Breakers) 11,044
4. Loop into Slatt 656
5. Malin-Meridian loop into Captain Jack 982
6. Alvey Substation - BPA 8,168
7. Dixonville - PacifiCorp 8,635
8. Meridian - PacifiCorp 6,548
9. Power System Control 3,575
10. Alvey-Spencer - BPA 1,346
11. Spencer-Dixonville - PacifiCorp 20,388
12. Dixonville-Meridian - PacifiCorp 32,140
-------
SUBTOTAL 102,265
FACILITIES WHOSE COSTS WILL BE ADJUSTED USING CHANGE
BETWEEN ESTIMATE AND ACTUAL, MULTIPLIED BY 50 PERCENT
13. Captain Jack (BPA Breakers) $14,335
14. Captain Jack (Communication
and Control) 5,100
15. Captain Jack (Series Capacitors) 722
16. Power System Control 5,596
17. Captain Jack line to
Oregon-Calif. border 5,724
------
SUBTOTAL $31,477
50 PERCENT OF SUBTOTAL 15,739
-------
TOTAL $118,004
-------
- --------------------
(1) Based on mid-1989 program planning levels.
(2) Actual costs will be available approximately December 1995, or as soon as
practicable thereafter. Supporting documentation will be provided
including work orders and accounting data for each line item.
(3) For each calculation of the Revised Adjusted Capacity Ownership Price,
Bonneville will include the revised actual costs of facilities pertaining
to each such calculation of the Revised Adjusted Capacity Ownership
Price.
Exhibit D, Page 2 of 5
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
B. INITIAL, ADJUSTED, AND REVISED ADJUSTED CAPACITY OWNERSHIP PRICE (1)
($ in Millions)
(1) (2) Revised
Initial Adjusted Adjusted
Capacity Capacity Capacity
Ownership Ownership Ownership
Price Price Price
COST ITEM
1. Second 800 MW $118 $___ $___
2. AFUDC(3) on Second 800 MW + 19 + ___ + ___
3. Existing Support Facilities + 19.1 + 19.1(4) + 19.1(4)
--- --- ---
4. Total Cost(5) $156 $___ $___
5. PRICE PER KW (CO-94)(6) $215 $___ $___
- --------------------
(1) Initial, Adjusted, and Revised Adjusted Capacity Ownership Price are
determined in accordance with the CO-94 rate in Exhibit A.
(2) Bonneville may make multiple calculations of the Revised Adjusted
Capacity Ownership Price pursuant to paragraph 9(a)(3). For each
calculation of the Revised Adjusted Capacity Ownership Price, Bonneville
will include the column pertaining to such calculation and the columns
for any previous calculations of the Revised Adjusted Capacity Ownership
Price.
(3) AFUDC will be calculated in accordance with the CO-94 rate in Exhibit A.
(4) Not adjusted in calculating the Adjusted Capacity Ownership Price or the
Revised Adjusted Capacity Ownership Price.
(5) Bonneville's indirect costs and overhead costs shall be included. Such
indirect costs and overhead costs shall be allocated or distributed to
the Third AC Intertie Project using the indirect and overhead allocation
and distribution methodologies employed by Bonneville to allocate and
distribute indirect and overhead costs to all of Bonneville's other
capital projects during the time the Third AC Intertie Project was under
construction. Such allocation or distribution methodologies shall not be
required to meet any stricter standard of benefit to Bonneville's Third
AC Intertie Project than with respect to any other transmission projects
under construction at the same time.
(6) Price per kW is derived by dividing the Total Cost by 725 MW.
Exhibit D, Page 3 of 5
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
C. INITIAL LUMP SUM PAYMENT
1. Puget's Capacity Ownership Share = 400 MW
2. Initial Capacity ownership Price
X $215 ($215,000/MW)
3. Initial Lump Sum Payment (1)
= $86,000,000
4. Deduction:
Negotiation Deposit with Interest (2) -
5. Due to Bonneville: =
- --------------------
(1) Initial Lump Sum Payment is calculated in accordance with section IV.A of
the CO-94 rate in Exhibit A.
(2) Interest is calculated as specified in Bonneville's April 23, 1993,
letter to Puget. The rate of interest for the computation is the
interest rate applicable to 3-month Treasury Bills as specified in the
FEDERAL RESERVE Statistical Release G.13. The rates are determined for
the 3-month yield reported on the first day of the month of receipt of
the negotiation deposit and on the first day of each subsequent third
month thereafter. Interest is compounded quarterly from May 11, 1993,
through the date Bonneville receives payment pursuant to paragraph
9(a)(1).
Exhibit D, Page 4 of 5
No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
D. ADJUSTED LUMP SUM PAYMENT
1. Puget's Capacity Ownership Share = 400 MW
2. Adjusted Capacity Ownership Price
X $
3. Adjusted Lump Sum Payment (1) =
4. Initial Lump Sum Payment - ______________
5. SUBTOTAL due to Bonneville, or Refund
Due to Puget =
6. Interest (2) +
7. Due to Bonneville, or Refund
Due to Puget =
- --------------------
(1) Adjusted Lump Sum Payment is calculated in accordance with the CO-94 rate
in Exhibit A.
(2) Interest will be calculated in accordance with the CO-94 rate in Exhibit
A using the weighted average interest rate on Bonneville's outstanding
bonds. Simple interest will be accrued from the date Bonneville receives
payment pursuant to paragraph 9(a)(1) through the date Bonneville or
Puget receives payment pursuant to subparagraph 9(a)(2)(B).
Exhibit D, Page 5 of 5
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
E. REVISED ADJUSTED LUMP SUM PAYMENT
1. Puget's Capacity Ownership Share = 400 MW
2. Current Revised Adjusted Capacity
Ownership Price x $
3. Current Revised Adjusted Lump Sum
Payment (1) =
4. Adjusted Lump Sum Payment/immediately - ____________________
preceding Revised Adjusted Lump Sum
Payment
5. SUBTOTAL due to Bonneville, or Refund
Due to Puget =
6. Interest (2) +
7. Due to Bonneville, or Refund
Due to Puget =
- --------------------
(1) Revised Adjusted Lump Sum Payment is calculated in accordance with the CO-
94 rate in Exhibit A. Bonneville will calculate a Revised Adjusted Lump
Sum Payment each time a Revised Adjusted Capacity Ownership Price is
calculated pursuant to paragraph 9(a)(3).
(2) Interest will be calculated in accordance with the CO-94 rate in Exhibit
A using the weighted average interest rate on Bonneville's outstanding
bonds. Simple interest will be accrued from (a) the date Bonneville or
Puget receives payment with respect to the Adjusted Lump Sum Payment
pursuant to paragraph 9(a)(2)(B) or (b) the date Bonneville or Puget
receives payment with respect to the Revised Adjusted Lump Sum Payment
immediately preceding the current Revised Adjusted Lump Sum Payment
through the date Bonneville or Puget receives payment with respect to the
current Revised Adjusted Lump Sum Payment pursuant to subparagraph
9(a)(3)(B).
Exhibit E, Page 1 of 1
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
Transmission Loss Factors
A. The transmission loss factor to be applied to Puget's schedules for
transactions transmitted on Puget's Scheduling Share shall be 2.5
percent.
B. The transmission loss factor to be applied to Puget's schedules for
transactions transmitted pursuant to subparagraph 3(b)(1)(C) shall be
3.0 percent.
Exhibit F, Page 1 of 10
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
BONNEVILLE'S PNW AC INTERTIE
A. TRANSMISSION LINE FACILITIES
% APPLICABLE TO
% BPA OWNED PNW AC INTERTIE
----------- ---------------
1. McNary-John Day 500 kV Line 100 100
---------------------------
Loop into Slatt:
---------------
McNary-Slatt Str. 108/1 to
substation dead end tower,
155 meters
Slatt-John Day Str. 1/1 to
substation dead end tower,
194 meters
2. John Day-Grizzly No. 1 500 kV 100 100
3. John Day-Grizzly No. 2 500 kV 100 100
4. Grizzly-Captain Jack No. 1 500 kV 100 100
5. Captain Jack-Malin No. 1 500 kV 100 100
6. Buckley-Grizzly 500 kV 100 57
7. Grizzly-Summer Lake 500 kV 100 57
8. 500 kV double circuit between 100 25
Buckley and Marion that supports
the Buckley-Marion No. 1 and the
Ashe-Marion No. 2 500 kV circuits
(Str. No. 1/3 to Marion, 159 km)
9. Marion-Alvey 500 kV 100 50
10. Captain Jack-COB (10 km) 500 kV 100 100
11. Alvey-Dixonville 500 kV 50 100
12. Dixonville-Meridian 500 kV 50 100
B. SUBSTATION FACILITIES (1)(2)
% APPLICABLE TO
% BPA OWNED PNW AC INTERTIE
----------- ---------------
1. SLATT 500 kV (Dispatch one-line
diagram No. 228962)
John Day line terminal
----------------------
New Breaker D#5021 100 100
Existing 500 kV MOD D#5020/7022 100 100
New 500 kV MOD D#5022 100 100
Existing 500 kV MOD D#5019 100 50
Existing Breaker D#5018 100 50
Exhibit F, Page 2 of 10
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
% APPLICABLE TO
% BPA OWNED PNW AC INTERTIE
----------- ---------------
Associated Terminal Arresters 100 100
Associated Line PTs 100 100
McNary line terminal
--------------------
500 kV MOD D#5023/7847 100 100
Associated Terminal Arresters 100 100
Associated Line PTs 100 100
Station General
2. JOHN DAY 500 kV (Dispatch one-line
diagram No. 132281)
Grizzly No.2 line terminal
--------------------------
Breaker D#4131 100 50
Breaker D#4134 100 100
MOD D#4132 100 50
MOD D#4133/7867 100 100
MOD D#4135 100 100
Associated Line PTs 100 100
Grizzly No.1 line terminal
--------------------------
Breaker D#4140 100 50
Breaker D#4143 100 100
MOD D#4141 100 50
MOD D#4142/7869 100 100
MOD D#4144 100 100
Associated Terminal Arresters 100 100
Associated Line PTs 100 100
Station General
3. BUCKLEY 500 KV, GAS INSULATED
SUBSTATION (Dispatch one-line
diagram No. 232583)
Slatt No. 1 line terminal
-------------------------
Breaker D#4967 100 57
Isolating switch D#4966/7328 100 57
Isolating switch D#4968/7355 100 57
Ground switch D#7415 100 57
Associated Terminal Arresters 100 57
Associated Line PTs 100 57
Summer Lake No. 1 line terminal
-------------------------------
Breaker D#4961 100 57
Exhibit F, Page 3 of 10
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
% APPLICABLE TO
% BPA OWNED PNW AC INTERTIE
----------- ---------------
Isolating switch D#4960/7312 100 57
Isolating switch D#4962/7313 100 57
Ground switch D#7311 100 57
Associated Terminal Arresters 100 57
Associated Line PTs 100 57
Marion No. 1 line terminal
--------------------------
Breaker D#4964 100 57
Isolating switch D#4963/7314 100 57
Isolating switch D#4965/7321 100 57
Ground switch D#7477 100 57
Associated Terminal Arresters 100 57
Associated Line PTs 100 57
Station General
4. MARION 500 kV (Dispatch one-line
diagram No. 136180)
Buckley line terminal
---------------------
Breaker D#4389 100 50
Breaker D#4386 100 25
MOD D#4387 100 25
MOD D#4390 100 50
MOD D#4388/7751 100 50
Associated Line PTs 100 50
Alvey line terminal
-------------------
Breaker D#4374 100 50
Breaker D#4377 100 25
MOD D#4376 100 25
MOD D#4375/7922 100 50
MOD D#4373 100 50
Associated Line PTs 100 50
Station General
5. ALVEY 500 kV (Dispatch one-line
diagram No. 121424)
Bank No. 5 terminal
-------------------
Breaker D#5081 50 100
MOD D#5080 50 100
MOD D#5082 50 100
MOD D#5090 50 100
Exhibit F, Page 4 of 10
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
% APPLICABLE TO
% BPA OWNED PNW AC INTERTIE
----------- ---------------
MOD D#5089/8157 50 100
Associated Terminal Arresters 50 100
Associated Line PTs 50 100
Marion No. 1 line terminal
--------------------------
Breaker D#5084 50 100
MOD D#5083/8155 50 100
MOD D#5085 50 100
Associated Terminal Arresters 50 100
Associated Line PTs 50 100
Dixonville No. 1 line terminal
------------------------------
Breaker D#5087 50 100
MOD D#5086/8156 50 100
MOD D#5088 50 100
Associated Terminal Arresters 50 100
Associated Line PTs 50 100
500 kV Series Capacitor Bank 50 100
---------------------------
(Marion-Alvey 500 kV line)
MODs D#5100/8160,5101/8159,
5102/8158 50 100
Bypass breaker D#5103 50 100
Station General
6. BPA/PACIFICORP DIXONVILLE 500 kV STATION
(PacifiCorp's one-line diagram PD-40020)
Note: PacifiCorp will be invoicing BPA for any future replacements of
these items listed consistent with Exhibit C of Bonneville-PacifiCorp
Amendatory Agreement No. 2 to Contract No. DE-MS79-86BP92299, as revised
or amended.
For Alvey and Meridian line terminals
-------------------------------------
Breakers 11U1, 11U2, 11U3 50 100
Isolating MODs 11U701, 11U700/ 11U507,
11U702, 11U703/11U505, 11U704, 11U705/
11U506, 11U706, 11U707, 11U708/11U501 50 100
Two sets of line terminal PTs 50 100
Two sets of line terminal arresters 50 100
Exhibit F, Page 5 of 10
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
% APPLICABLE TO
% BPA OWNED PNW AC INTERTIE
----------- ---------------
Series Capacitor Bank in Alvey- 50 100
Dixonville 500 kV line and
associated isolating devices
180 MVAR Shunt Reactor Bank S664, 665, 50 100
666, 667 and associated arresters,
PTs, and isolating devices
Station General
7. BPA/PACIFICORP MERIDIAN 500 kV
YARD (PacifiCorp's one-line diagram
PD-32976)
Note: PacifiCorp will be invoicing BPA for any future replacements of
these items listed consistent with Exhibit C of Bonneville-PacifiCorp
Amendatory Agreement No. 2 to Contract No. DE-MS79-86BP92299.
For Dixonville line terminal
---------------------------
Breakers 11R2, 11R6 50 50
Isolating MODs 11R702, 11R703/ 100 100
11R501, 11R704, 11R710, 11R711
One set of line PTs 50 100
One set of line terminal arresters 50 100
for the Dixonville line and one set
for the Captain Jack line
180 MVAR Shunt Reactor Bank S690, 50 100
691 ,692, 693 and associated
arresters, PTs, and isolating devices
Series Capacitor Bank in the 50 100
Dixonville- Meridian 500 kV line
and associated isolating devices.
Station General
8. GRIZZLY 500 kV (Dispatch one-line
diagram No. 103924)
John Day No. 1 line terminal
----------------------------
Breaker D#4058 100 100
Breaker D#5040 100 100
MOD D#4059 100 100
MOD D#4057/7848 100 100
Exhibit F, Page 6 of 10
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
% APPLICABLE TO
% BPA OWNED PNW AC INTERTIE
----------- ---------------
MOD D#4056 100 100
MOD D#5039 100 100
Associated Terminal Arresters 100 100
Associated Line PTs 100 100
John Day No. 2 line terminal
----------------------------
Breaker D#4042 100 100
Breaker D#4046 100 100
MOD D#4043 100 100
MOD D#4044/7845 100 100
MOD D#4045 100 100
MOD D#4047 100 100
Associated Terminal Arresters 100 100
Associated Line PTs 100 100
Buckley No. 1 line terminal
---------------------------
Breaker D#5031 100 100
Breaker D#5028 100 100
MOD D#5032 100 100
MOD D#5030/8122 100 100
MOD D#5029 100 100
MOD D#5027 100 100
Associated Line PTs 100 100
Captain Jack No. 1 line terminal
--------------------------------
Breaker D#5037 100 100
Breaker D#5034 100 100
MOD D#5038 100 100
MOD D#5036/8123 100 100
MOD D#5035 100 100
MOD D#5033 100 100
Associated Terminal Arresters 100 100
Associated Line PTs 100 100
Summer Lake line terminal
-------------------------
Breaker D#5025 100 100
MOD D#5026/8121 100 100
MOD D#5024 100 100
Associated Terminal Arresters 100 100
Associated Line PTs 100 100
Exhibit F, Page 7 of 10
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
% APPLICABLE TO
% BPA OWNED PNW AC INTERTIE
----------- ---------------
180 MVAR Reactor Bank No. 1 100 100
---------------------------
Breaker D#4222 100 100
Isolating Switch D#4060 100 100
Associated Arresters 100 100
300 MVAR Reactor Bank No. 2 100 100
---------------------------
Breaker D#4720 100 100
Isolating Switch D#4719 100 100
Associated Arresters 100 100
300 MVAR Reactor Bank No. 3 and 100 100
Neutral Reactor
Breaker D#4038 100 100
Isolating Switch D#4062 100 100
Neutral isolating switch D#4109/4081 100 100
Associated Arresters 100 100
Associated PTs 100 100
North Main Bus 500 kV PTs 100 100
South Main Bus 500 kV PTs 100 100
Station General
9. SAND SPRING 500 kV COMPENSATION
STATION (Dispatch one-line
diagram No. 142239)
Series Cap.Bank No. 1 100 100
---------------------
(Grizzly-Captain Jack line)
and associated equipment
Series Cap. Bank No. 3 100 100
----------------------
(Grizzly-Summer Lake line)
and associated equipment
Station General
10. FORT ROCK 500 kV COMPENSATION STATION
(Dispatch one-line diagram No. 142237)
Series Cap. Bank No. 1 100 100
----------------------
(Grizzly-Captain Jack line)
and associated equipment
Series Cap. Bank No. 3 100 100
---------------------------
(Grizzly-Summer Lake line)
and associated equipment
Station General
11. SYCAN 500 kV COMPENSATION STATION
(Dispatch one-line diagram No. 142238)
Exhibit F, Page 8 of 10
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
% APPLICABLE TO
% BPA OWNED PNW AC INTERTIE
----------- ---------------
Series Cap. Bank No. 1 100 100
----------------------
(Grizzly- Captain Jack line) and
associated equipment
Series Cap. Bank No. 3 65 100
----------------------
(Summer Lake-Malin line) and
associated equipment but EXCLUDING
the bypass MOD D#5065 and
transmission tower
Station General
12. SUMMER LAKE 500 kV (Dispatch one-
line diagram No. 232667)
Grizzly line terminal
----------------------
(formerly Buckley-Ponderosa Tap)
Breaker D#4959 100 57
MOD D#4955 100 57
MOD D#4956/7309 100 57
Associated Terminal Arresters 100 57
Associated Line PTs 100 57
Malin line terminal
-------------------
Line protective relays 0 100
Station General
13. MALIN 500 kV (Dispatch one-
line diagram No. 103923)
Captain Jack No. 1 line terminal
--------------------------------
Breaker D#4066 100 100
Breaker D#4064 100 100
MOD D#4068 100 100
MOD D#4067/7849 100 100
MOD D#4065
Associated Terminal Arresters 100 100
Associated Line PTs 100 100
Round Mountain line No. 1 terminal
----------------------------------
Breaker D#4186 50 100
MOD D#4063/7970 100 100
MOD D#4185 50 100
MOD D#4187 50 100
Associated Terminal Arresters 100 100
Associated Line PTs 100 100
Round Mountain line No. 2 terminal
----------------------------------
Exhibit F, Page 9 of 10
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
% APPLICABLE TO
% BPA OWNED PNW AC INTERTIE
----------- ---------------
Breaker D#4582 50 100
MOD D#4583 50 100
MOD D#4581 50 100
MOD D#4074/7856 75 100
Grizzly No. 2/Round Mountain No. 2
----------------------------------
line position
-------------
Breaker D#4072 75 100
MOD D#4073 75 100
North Main Bus 500 kV PTs 100 100
-------------------------
South Main Bus 500 kV PTs 50 100
-------------------------
300 MVAR Shunt Reactor Bank No. 1 100 100
---------------------------
and associated arresters and
isolating devices (D#4327, 4393) 100 100
2-239 MVAR Shunt Cap. Banks and
---------------------------
associated isolating devices (D#4183,
4181, 4184, 4182, 8065, 8066)
Line protective relays for Summer 0 100
---------------------------------
Lake line
---------
Station General
14. CAPTAIN JACK 500 kV (Dispatch one-line
diagram No. 248548)
Series Cap. Bank No. 1
----------------------
(Captain Jack-Olinda line) 100 100
MODs D#4974/8101, 4973/8099, 100 100
4975/ 8100
Bypass breaker D#4971, 4972
Grizzly No. 1 line terminal
---------------------------
Breaker D#4990 100 100
Breaker D#4993 100 100
MOD D#4989 100 100
MOD D#4991/8104 100 100
MOD D#4992 100 100
MOD D#4994/8105 100 100
Associated Terminal Arresters 100 100
Associated Line PTs 100 100
Malin No. 1 line terminal
-------------------------
Breaker D#4996 100 100
Exhibit F, Page 10 of 10
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
% APPLICABLE TO
% BPA OWNED PNW AC INTERTIE
----------- ---------------
MOD D#4995 100 100
MOD D#4997 100 100
Associated Terminal Arresters 100 100
Associated Line PTs 100 100
Olinda No. 1 line terminal
--------------------------
Breaker D#4977 100 100
Breaker D#4980 100 100
MOD D#4976 100 100
MOD D#4978 100 100
MOD D#4979 100 100
MOD D#4981 100 100
Associated Terminal Arresters 100 100
Associated Line PTs (2 sets) 100 100
North Main Bus 500 kV PTs 100 100
-------------------------
South Main Bus 500 kV PTs 100 100
Station General
15. CHIEF JOSEPH SUBSTATION (Dispatch 100 100
one-line diagram No. 124313)
230kV, 1400 MW Braking Resistor
-------------------------------
Includes breaker dispatch No. A-594,
a high speed vacuum switch and one 230 kV
isolating switch in Bay 12
-----------------------------
(1) Station General will be allocated to each substation according to
Bonneville's standard methodology.
(2) Each substation includes associated relays.
Exhibit G, Page 1 of 1
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
CAPACITY OWNERS
CAPACITY CAPACITY
CONTRACT OWNERSHIP OWNERSHIP
CAPACITY OWNER NUMBER SHARE (MW) PERCENTAGE
PNGC DE-MS79-94BP94523 50 1.4
Puget DE-MS79-94BP94521 400 11.6
Seattle DE-MS79-94BP94522 160 4.6
Snohomish DE-MS79-94BP94525 42 1.2
Tacoma DE-MS79-94BP94524 41 1.1
PNGC: Pacific Northwest Generating Cooperative
Puget: Puget Sound Power & Light Company
Seattle: City of Seattle, City Light Department
Snohomish: Public Utility District No. 1 of Snohomish County
Tacoma: Tacoma Public Utilities
Exhibit H, Page 119 of
6
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
Provisions Required by Statute or Executive Order
1. Contract Work Hours and Safety Standards Act (40 U.S.C. & 327, et seq.).
-----------------------------------------------------------------------
(a) Overtime Requirements.
---------------------
Puget, contracting for any part of the contract work which may require
or involve the employment of laborers or mechanics, shall not require or
permit any such laborers or mechanics in any workweek in which the
individual is employed on such work to work in excess of 40 hours in
such workweek unless such laborer or mechanic receives compensation at a
rate not less than 1-1/2 times the basic rate of pay for all hours
worked in excess of 40 hours in such workweek.
(b) Violation: liability for unpaid wages; liquidated damages.
----------------------------------------------------------
In the event of any violation of the provisions set forth in section 1
of this Exhibit H, Puget and any subcontractor responsible therefore
shall be liable for the unpaid wages. In addition, Puget and such
subcontractor shall be liable to the United States for liquidated
damages. Such liquidated damages shall be computed with respect to each
individual laborer or mechanic employed in violation of the provisions
set forth in section 1 of this Agreement in the sum of $10.00 for each
calendar day on which such individual was required or permitted to work
in excess of the standard workweek of 40 hours without payment of the
overtime wages required by provision set forth in section 1 of this
Exhibit.
(c) Withholding for unpaid wages and liquidated damages.
---------------------------------------------------
The person designated in writing by Bonneville's Administrator with the
Authority to enter into, administer, modify, suspend or terminate this
Exhibit, make related determinations and findings and bind Bonneville
only to the extent of delegated authority shall upon his or her own
action or upon written request of an authorized representative of the
Department of Labor withhold or cause to be withheld, from any moneys
payable on account of work performed by Puget or its subcontractor, if
any, under any such contract or any other federal contract subject to
the Contract Work Hours and Safety Standards Act which is held by the
same prime contractor, such sums as may be determined to be necessary to
satisfy any liabilities of Puget or such subcontractor for unpaid wages
and liquidated damages as provided in section 2 of this Exhibit.
2. Convict Labor (Exec. Order No. 11755, Dec. 29, 1979).
----------------------------------------------------
In connection with the performance or work under this Agreement, Puget
and any subcontractor, if any agrees not to employ any person undergoing
sentence of imprisonment except as otherwise provided by law.
Exhibit H, Page 2 of 6
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
3. Equal Opportunity (Exec. Order No. 11246, Sep. 24, 1965).
--------------------------------------------------------
(a) If , during any 12-month period (including the 12 months preceding
the award of this contract), Puget has been or is awarded nonexempt
federal contracts and/or subcontracts that have an aggregate value in
excess of $25,000.00, Puget shall comply with sections 3(b)(1) through
3(b)(11) below. Upon request, Puget shall provide information necessary
to determine the applicability of this clause.
(b) During performance of this Agreement, Puget agrees as follows:
(1) Puget shall not discriminate against any employee or applicant
for employment because of race, color, religion, sex or national
origin.
(2) Puget shall 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:
(1) employment; (2) upgrading; (3) demotion; (4) transfer;
(5) recruitment or recruitment advertising; (6) layoff or
termination; (7) rates of pay or other forms of compensation; and
(8) selection for training, including apprenticeship.
(3) Puget shall post in conspicuous places, available to employees
and applicants for employment, the notices that explain this
clause, such notices to be provided by the person designated in
writing by Bonneville's Administrator with the authority to enter
into, administer, modify, suspend or terminate this Agreement, make
related determinations and findings and bind Bonneville only to the
extent of delegated authority (Contracting Officer).
(4) Puget shall, in all solicitations or advertisements for
employees placed by or on behalf of Puget, state that all qualified
applicants will receive consideration for employment without regard
to race, color, religion, sex or national origin.
(5) Puget shall send, to each labor union or representative or of
workers with which it has a collective bargaining agreement or
other contract or understanding, the notice provided by the
Contracting Officer advising the labor union or workers'
representative of Puget's commitments under this clause, and post
copies of the notice in conspicuous places available to employees
and applicants for employment.
(6) Puget shall comply with Executive Order No. 11246,
Sep. 24, 1965 (30 Fed. Reg. 12319), as amended, and the rules,
regulations and orders of the Secretary of Labor.
(7) Puget shall furnish to Bonneville all information required by
Executive Order No. 11246, as amended, and by the rules,
regulations and orders of the Secretary of Labor. Standard Form
Exhibit H, Page 3 of 6
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
100 (EEO-1), or any successor form, is the prescribed form to be
filed within 30 days following the award of this contract, unless
filed within 12 months preceding the date of the award of this
contract.
(8) Puget shall permit access to its books, records and accounts
by Bonneville or the Office of Federal Contract Compliance Programs
(OFCCP) for purpose of investigation to ascertain Puget's
compliance with such rules, regulations and orders.
(9) If the OFCCP determines that Puget is not in compliance with
this clause or any rule, regulation or order of the Secretary of
Labor, this Agreement may be canceled, terminated, or suspended in
whole or in part and Puget may be declared ineligible for further
Government contracts, under the procedures authorized in Executive
Order No. 11246, as amended. In addition, sanctions may be imposed
and remedies invoked against Puget as provided in Executive Order
No. 11246, as amended, the rules, regulations and orders of the
Secretary of Labor, or as otherwise provided by law.
(10) Puget shall include the terms and conditions of sections
3(b)(1) through 3(b)(11) of this Exhibit in every subcontract or
purchase order that is not exempted by the rules, regulations, or
orders of the Secretary of Labor issued under Executive Order No.
11246, as amended, so that these terms and conditions will be
binding upon each subcontractor or vendor.
(11) Puget shall take such action with respect to any subcontract
or purchase order as may direct as means of enforcing these terms
and conditions, including sanctions for noncompliance: Provided,
that if Puget becomes involved in, or is threatened with,
litigation with a subcontractor or vendor as a result of any
direction, Puget may request the Government to enter into the
litigation to protect the interest of the United States.
(c) Notwithstanding any other clause in this Agreement, disputes
relative to this clause will be governed by the procedures in 41 CFR
66-1.1.
4. Certification of Non-segregated Facilities (48 CFR Section 22.810).
------------------------------------------------------------------
(a) Puget certifies that it does not and will not maintain or provide
for employees any segregated facilities at any of its establishments and
that it does not and will not permit its employees to perform their
services at any location under its control where segregated facilities
are maintained. Puget agrees that a breach of this certification is a
violation of section 3 (the Equal Opportunities Clause) of this Exhibit.
(b) Puget agrees that it will (1) obtain identical certifications from
proposed subcontractors prior to the award of subcontracts exceeding
$10,000.00 which are not exempt from the provisions of the Equal
Exhibit H, Page 4 of 6
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
Opportunity Clause; (2) retain such certifications in its files (3)
forward the following notice to such proposed subcontractors,
except where the proposed subcontractors have submitted identical
certifications of specific time periods:
"Notice to Prospective Subcontractors of Requirement for
Certifications of Non-segregated Facilities.
"A Certification of Non-segregated Facilities must be submitted
prior to the award of a subcontract under which the subcontractor
will be subject to the Equal Opportunity clause. This
certification may be submitted either for each subcontract or for
all subcontracts during a period (i.e., quarterly, semiannually or
annually)."
5. Officials Not to Benefit (41 U.S.C. Section 22).
-----------------------------------------------
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
arising from it. However, this clause does not apply to this Agreement
to the extent that this Agreement is made with a corporation for the
corporation's general benefit.
6. Bonneville's Obligations Not General Obligations of the United States
---------------------------------------------------------------------
(16 U.S.C. Section 839(j)).
-------------------------
None of the offerings of obligations, or promotional materials for such
obligations, which may be offered by Puget to fund its activities
pursuant to this Agreement, shall be construed to be, general
obligations of the United States, nor are such obligations intended to
be or are they secured by the full faith and credit of the United
States.
7. Small Business Act (15 U.S.C. Sections 631 and 637).
---------------------------------------------------
(a) It is the policy of the Government that small business concerns
owned and controlled by socially and economically disadvantaged
individuals shall have the maximum practicable opportunity to
participate in the performance of contracts let by any federal agency.
(b) Puget hereby agrees to carry out the policy set forth in 7(a) in
awarding subcontracts to the fullest extent consistent with the
efficient performance of this Agreement. Puget further agrees to
cooperate on any studies or surveys as may be conducted by the United
States Small Business Administration or Bonneville as may be necessary
to determine the extent of Puget's compliance with this clause.
(c) As used in this agreement the term "small business concern" shall
mean a small business as defined in section 3 of Small Business Act
Exhibit H, Page 5 of 5
Exhibit H, Page 5 0f 6
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
(15 U.S.C. Section 632) and relevant regulations promulgated pursuant
thereto. The term "small business concern owned and controlled by
socially and economically disadvantaged individuals" shall mean a small
business concern:
(1) which is at least 51 percent owned by one or more socially
disadvantaged individuals; or, in the case of any publicly owned
business, at least 51 percent of the stock of which is owned by one
or more socially or economically disadvantaged individuals; and
(2) whose management and daily business operations are controlled
by one or more such individuals.
Puget shall presume that socially and economically disadvantaged
individuals include Black Americans, Hispanic Americans, Native
Americans, Asian Pacific Americans and other minorities, or any
other individual found to be disadvantaged by the United States
Small Business Administration pursuant to section 8(a) of the Small
Business Act.
(d) Puget acting in good faith may rely on written representations by
its subcontractor regarding its status as either a small business
concern or a small business concern owned and controlled by socially and
economically disadvantaged individuals.
8. Other Statutes, Executive Orders and Regulations.
------------------------------------------------
(a) Puget agrees to comply with the following statutes, executive
orders and regulations to the extent applicable:
(1) False Claims Act, 31 U.S.C. Section 3729, et seq. Whoever
makes or presents to any person or officer in the civil military or
naval service of the United States, or to any department or agency
thereof, any claim upon or against the United States, or any
department or agency thereof, knowing such claim to be false,
fictitious or fraudulent, shall be fined not more than $10,000.00
or imprisoned not more than 5 years, or both;
(2) Rehabilitation Act of 1973, 29 U.S.C. Section 793, as amended,
Executive Order No. 11758, Jan. 15, 1974, and the regulations of
the Secretary of Labor, 41 CFR Part 60-250, et seq., which concern
affirmative action for handicapped workers;
(3) Vietnam Era Veterans Readjustment Assistance Act of 1972,
38 U.S.C. Sections 101, 102, 240, 241, 1502, 1504, 1507, as
amended, and the clauses contained in 41 CFR Part 60-250, et seq.,
which concern affirmative action for disabled veterans and veterans
of the Vietnam Era;
(4) Executive Order No. 11625, Oct. 13, 1971, and implementing
regulations which concern utilization of small disadvantaged
business concerns;
Exhibit H, Page 6 of 6
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
(5) Anti-Kickback Act, 41 U.S.C. Section 51, et seq.; and
(6) Privacy Act of 1974, 5 U.S.C. Section 552a
(b) Puget agrees to comply with requirements deemed necessary by
Bonneville in order to implement Bonneville's obligations under the
National Historic Preservation Act of 1966, U.S.C. Section 470, et seq.
Exhibit I, Page 1 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
BONNEVILLE'S PNW AC INTERTIE COSTS
All costs in sections I through VIII of this Exhibit I shall be subject to
the following provisions:
PURPOSE
- -------
Bonneville shall determine and calculate Operations Costs, Maintenance Costs,
Replacement Costs and Reinforcement Costs, General Plant Costs, Other Costs,
Contracts and Rates Costs, Power Scheduling Costs, and End of Term Costs with
respect to Bonneville's PNW AC Intertie in accordance with this Exhibit I.
None of Operations Costs, Maintenance Costs, Replacement Costs and
Reinforcement Costs, General Plant Costs, Other Costs, Contracts and Rates
Costs, and End of Term Costs (each of the foregoing for purposes of this
sentence, a Cost) shall include any other Cost.
SOURCE OF INFORMATION AND COSTS
- -------------------------------
Bonneville shall forecast in accordance with this Exhibit I the costs
reflected in any Operating Plan pursuant to Schedules A through H of this
Exhibit using the most detailed information available to Bonneville from its
budget process at the time the forecast is made. Bonneville shall determine
the actual costs reflected in any Operating Plan pursuant to Schedules A
through H, using Bonneville's then existing accounting system in accordance
with this Exhibit I. All costs reflected in Schedules A through H shall be
net of credit.
Bonneville shall determine its overall overhead and overall indirect costs.
A portion of Bonneville's overall overhead and indirect costs shall be
allocated to such total system operations costs (pursuant to section I
below), total system maintenance costs (pursuant to section II below), total
capital costs (pursuant to sections III and IV below), Other Costs (pursuant
to section V below), Contracts and Rates Costs (pursuant to section VI
below), Power Scheduling Costs (pursuant to section VII below), and End of
Term Costs (pursuant to section VIII below) using Bonneville's normal
allocation or distribution methodologies for such costs, as such
methodologies may be changed by Bonneville from time to time. Such
allocations or distribution methodologies shall not be required to meet any
stricter standard of benefit to Bonneville's PNW AC Intertie than with
respect to other transmission facilities.
Bonneville shall record its costs into its accounting systems in accordance
with generally accepted accounting principles. For purposes of this
Agreement, "generally accepted accounting principles" means the common set of
accounting concepts, standards, and procedures that are adopted by entities
(such as the utility industry) for purposes of financial statement
disclosure.
Whenever Bonneville alters its accounting system or methods to permit costs
referred to in this Exhibit I, which were previously allocated to functions
Exhibit I, Page 2 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
and activities, to be directly assigned to function and activities, then in
that event Puget and Bonneville shall, in concert with the Capacity Owners
other than Puget, in good faith negotiate revisions to this Exhibit I to
include such directly assigned costs.
COSTS
- -----
I. Operations Costs
----------------
A. Operations Costs - Allocation Factor
The allocation factor (Schedule A, line 3) used to determine the
Allocated Direct Cost of Operations Cost, Indirect Cost of Operations
Cost, and Overhead Cost of Operations Cost is the ratio of major
facility units (MFUs) of Bonneville's PNW AC Intertie operated by
Bonneville to MFUs of the Federal Columbia River Transmission System.
An MFU (Schedule A, lines 1 and 2) is any of the following major
pieces of power system equipment which, at any given time, is
installed on and is a part of the Federal Columbia River Transmission
System: substation switchgear (such as power circuit breakers;
potential devices; disconnects, load interrupters, hot-stick operated
bus links; switching devices, circuit switchers, ground switches; and
switchyard equipment terminals); protective equipment (such as
grounding devices; reactors; arrestors and resistors; voltage
regulators; engine generators and motor generators; and high voltage
fuses); transformation equipment (such as power transformers; diesel
generators; grounding transformers; regulators and shunt reactors;
synchronous condensers; and shunt or series capacitors); station
equipment (such as switchyard lighting, batteries and chargers, air
compressors, station service equipment, and lightening arrestors);
instruments, control, and supervisory equipment (such as switchboards,
instruments, and control panels; relay panels, transfer trip, and
single-pole relaying; and oscillographs; fault detectors and locators;
sequential events recorders, supervisory control, and data acquisition
equipment; and indicating meters, instruments, and loggers); and
equipment specific to direct current and static var compensator
stations (such as mercury arc valves; thyristor systems; air handling
packages; water control packages; harmonic filtering systems; motor
control centers, such as fans, pumps, and dampening resistors; and
valve damping resistors); or devices that perform similar types of
functions.
Once each fiscal year, Bonneville shall count the number of MFUs on
Bonneville's PNW AC Intertie (exclusive of facilities operated by
others) (Schedule A, line 1) and the number of MFUs on the Federal
Columbia River Transmission System (Schedule A, line 2). In
calculating the forecast Allocated Direct Cost, Indirect Cost, and
Overhead Cost components of Operations Costs, Bonneville shall use the
most recent MFU count available at the time of such calculation in
Exhibit I, Page 3 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
developing its initial Operating Plan for a given fiscal year. For
each Operating Plan which is for the same fiscal year, Bonneville
shall use the same MFU count in calculating the forecast and actual
Allocated Direct Cost, Indirect Cost, and Overhead Cost components of
Operations Costs.
B. Operations Costs - Operations Functionalization Factor
For each Operating Plan, Bonneville's total system operations direct
cost, indirect cost and overhead cost (Schedule A, lines 7, 9, and 11)
shall be adjusted by an operations functionalization factor
(Schedule A, line 6) so that Capacity Owners pay only transmission-
related system operations costs. The operations functionalization
factor shall be based on a ratio of costs from Bonneville's general
rate case most recently approved by FERC on an interim basis. Using
the costs developed for the last year of the rate period for which
Bonneville has developed rates, the operations functionalization
factor shall be the ratio of (a) Bonneville's total system operations
cost functionalized to transmission (Schedule A, line 4) over
(b) Bonneville's total system operations cost (Schedule A, line 5).
For each Operating Plan, Bonneville shall use the same
functionalization factor in calculating the forecast and actual
Allocated Direct Cost, Indirect Cost, and Overhead Cost components of
Operations Costs.
C. Operations Costs - Allocated Direct Costs
For each Operating Plan, Bonneville shall allocate its total system
operations direct costs as set forth in Schedule A, lines 7 and 8, to
determine Allocated Direct Costs of Operations Cost (Schedule A, line
8).
Schedule A, line 7, shall reflect Bonneville's total system operations
direct costs for a fiscal year. Bonneville's total system operations
direct costs for a fiscal year shall include all system operations
expenses for such fiscal year for any of the following: salaries,
wages, employee benefits, overtime pay, travel, service contracts,
consulting contracts, materials, spare parts, tools, direct support
services (including equipment use activities, general shops
activities, and heavy mobile equipment maintenance), and other
expenses, each of which being incurred by Bonneville in connection
with the performance of any of the following activities: substation
operations (which provides for, among other things, making equipment
adjustments to maintain loads and voltages within acceptable limits,
switching to de-energize lines and equipment during maintenance
outages, isolating damaged equipment, restoring service to customers,
visually inspecting equipment, and reading meters that record line and
equipment loading and voltages), power system control and dispatching
(which provides for, among other things, central dispatching, control,
Exhibit I, Page 4 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
and monitoring of the electric operation of the Federal transmission
system; load, frequency, and voltage control of Federal generating
plants; the operating of the system control and data computers at the
Dittmer and Eastern Control Centers; and modification and maintenance
of the operation-related computers), and operations standards and
engineering (which provides for, among other things, analyzing system
loads, voltage levels, outage information, stability levels, and other
data; making policy recommendations for system operations; planning
operations' practices, restoration plans and disturbance ports;
development of control center requirements for centralized automation
of substations and generation; and Bonneville's participation with
other utilities in developing utility operating standards and guides);
and other system operations activities undertaken by Bonneville that
are consistent with system operations activities similar to the above-
listed activities undertaken by utilities in the Western Systems
Coordinating Council.
Schedule A, line 8, shall reflect Allocated Direct Cost of Operations
Cost.
D. Operations Costs - Indirect Costs
For each Operating Plan, Bonneville shall allocate its total system
operations indirect costs as set forth in Schedule A, lines 9 and 10,
to determine Indirect Costs of Operations Costs.
Schedule A, line 9, shall reflect Bonneville's total system operations
indirect costs for a fiscal year. Bonneville's total system
operations indirect costs for a fiscal year shall include all system
operations indirect expenses for such fiscal year for any of the
following: salaries, wages, employee benefits, overtime pay, travel,
service contracts, consulting contracts, materials, tools, direct
support services (including equipment use activities, general shops
activities, and heavy mobile equipment maintenance), and other
expenses, each of which being incurred by Bonneville in connection
with the performance of any of the following activities: general
supervision and management, office support, planning, budgeting,
training, direction of facilities' operation, and other system
operations activities undertaken by Bonneville that are consistent
with system operations activities similar to the above-listed
activities undertaken by utilities in the Western Systems Coordinating
Council.
Schedule A, line 10, shall reflect Indirect Cost of Operations Cost.
Exhibit I, Page 5 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
E. Operations Costs - Overhead Costs
For each Operating Plan, Bonneville shall allocate its total system
operations overhead costs as set forth in Schedule A, lines 11 and 12,
to determine Overhead Costs of Operations Costs.
Schedule A, line 11, shall reflect Bonneville's total system
operations overhead costs for a fiscal year. Bonneville's total
system operations overhead costs for a fiscal year shall include all
system operations overhead expenses for such fiscal year for any of
the following: salaries, wages, employee benefits, overtime pay,
travel, service contracts, consulting contracts, materials, spare
parts, and other expenses, each of which being incurred by Bonneville
in connection with any of the following activities and services of
Bonneville: (a) support services (including services with respect to
mainframe computers, microcomputers, laboratories, building
management, materials and procurement, Electric Power Research
Institute, fixed-wing aircraft, helicopter, tools, and work
equipment); (b) general and administrative activities (including
general and administrative activities with respect to the office of
the Administrator, the Washington DC office, and the offices of:
contracts and property management; fish and wildlife; equal employment
opportunity; information resources; environment; internal audit;
external affairs; general counsel; quality improvement; planning
council liaison; financial management; power sales; energy resources;
management services; area offices; operations, maintenance, and
construction; and engineering); and (c) other system operations
overhead activities undertaken by Bonneville that are consistent with
system operations activities similar to the above-listed activities
undertaken by utilities in the Western System Coordinating Council.
Schedule A, line 12, shall reflect Overhead Cost of Operations Cost.
Schedule A, line 13, shall reflect Operations Cost.
II. Maintenance Costs
-----------------
A. Maintenance Costs - Power System Control Maintenance
Functionalization Factor
For each Operating Plan, the Power System Control (PSC) maintenance
cost (Schedule B, line 4) shall be adjusted by a PSC maintenance
functionalization factor (Schedule B, line 3). PSC maintenance is the
testing, repair, and engineering support for Bonneville's
communications and control systems. The PSC maintenance
functionalization factor shall be based on a ratio of costs from
Bonneville's general rate case most recently approved by FERC on an
interim basis. Using costs for the last year of the rate period for
which Bonneville has developed rates, the PSC functionalization factor
Exhibit I, Page 6 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
shall be the ratio of (a) Bonneville's total PSC maintenance cost
functionalized to transmission from such general rate case
(Schedule B, line 1) over (b) Bonneville's total PSC maintenance cost
from such general rate case (Schedule B, line 2).
B. Maintenance Costs - Direct Costs
The Direct Costs of Maintenance Costs for a fiscal year (Schedule B,
line 7) shall be Bonneville's direct costs of maintaining Bonneville's
PNW AC Intertie and shall include all maintenance expenses for such
fiscal year for any of the following: salaries, wages, employee
benefits, overtime pay, travel, service contracts, consulting
contracts, materials, spare parts, transportation of spare parts,
tools, direct support services (including equipment use activities,
general shops activities, and heavy mobile equipment maintenance), and
other expenses, each of which being incurred by Bonneville in
connection with the performance of any of the following activities for
maintenance of Bonneville's PNW AC Intertie: transmission line
maintenance; substation maintenance; power system control maintenance;
nonelectric plant maintenance; pollution control and abatement; and
other system maintenance activities related to preventive and
corrective maintenance of Bonneville's PNW AC Intertie undertaken by
Bonneville that are consistent with activities similar to the above-
listed activities undertaken by utilities in the Western Systems
Coordinating Council.
With the exception of PSC maintenance costs, Bonneville shall
specifically identify the direct costs of maintaining Bonneville's PNW
AC Intertie (Schedule B, line 7). To determine PSC direct maintenance
cost for Bonneville's PNW AC Intertie (Schedule B, line 6), the total
PSC direct maintenance cost (Schedule B, line 4) shall be multiplied
by (a) the PSC maintenance functionalization factor (Schedule B, line
3) and (b) the MFU allocation factor (Schedule B, line 5) set forth in
Schedule A, line 3. The Direct Costs of Maintenance Costs (Schedule
B, line 8) shall be the sum of (a) PSC direct maintenance cost for
Bonneville's PNW AC Intertie (Schedule B, line 6) and (b) the direct
cost of maintaining Bonneville's PNW AC Intertie excluding PSC
maintenance cost (Schedule B, line 7).
C Maintenance Costs - Allocation Factor
The allocation factor (Schedule B, line 10) used to determine Indirect
Cost of Maintenance Cost and Overhead Cost of Maintenance Cost shall
be the ratio of the Direct Cost of Maintenance Cost (Schedule B, line
8) to Bonneville's total system maintenance direct cost (Schedule B,
line 9), as described below.
Schedule B, line 9, shall reflect Bonneville's total system
maintenance direct costs for a fiscal year. Bonneville's total system
maintenance direct costs for a fiscal year shall include all
Exhibit I, Page 7 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
maintenance expenses for such fiscal year for any of the following:
salaries, wages, employee benefits, overtime pay, travel, service
contracts, consulting contracts, materials, spare parts,
transportation of spare parts, tools, direct support services
(including equipment use activities, general shops activities, and
heavy mobile equipment maintenance), and other expenses, each of which
being incurred by Bonneville in connection with the performance of any
of the following activities: transmission line maintenance;
substation maintenance; power system control maintenance; nonelectric
plant maintenance; establishing, monitoring, and updating system
maintenance standards, policies, and procedures; pollution control and
abatement; and other system maintenance activities related to
preventive and corrective maintenance of the Federal Columbia River
Transmission System undertaken by Bonneville that are consistent with
system maintenance activities similar to the above-listed activities
undertaken by utilities in the Western Systems Coordinating Council.
Schedule B, line 10, shall reflect the percentage which shall be used
to allocate Bonneville's total system maintenance indirect cost and
total system maintenance overhead cost to Bonneville's PNW AC
Intertie.
D. Maintenance Costs - Indirect Costs
For each Operating Plan, Bonneville shall allocate its total system
maintenance indirect costs as set forth in Schedule B, lines 11 and
12, to determine Indirect Costs of Maintenance Costs.
Schedule B, line 11, shall reflect Bonneville's total system
maintenance indirect costs for a fiscal year. Bonneville's total
system maintenance indirect costs for a fiscal year shall include all
system maintenance indirect expenses for such fiscal year for any of
the following: salaries, wages, employee benefits, overtime pay,
travel, service contracts, consulting contracts, materials, spare
parts, administration of spare parts, transportation of spare parts,
tools, tools procurement and administration, direct support services
(including equipment use activities, general shops activities, and
heavy mobile equipment maintenance), and other expenses, each of which
being incurred by Bonneville in connection with the performance any of
the following activities: supervision and management, office support,
technical analyses, engineering studies, program analyses, planning,
budgeting, training, and other system maintenance activities
undertaken by Bonneville that are consistent with system maintenance
activities similar to the above-listed activities undertaken by
utilities in the Western Systems Coordinating Council.
Schedule B, line 12, shall reflect Indirect Cost of Maintenance Cost.
Exhibit I, Page 8 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
E. Maintenance Costs - Overhead Costs
For each Operating Plan, Bonneville shall allocate its total system
maintenance overhead costs as set forth in Schedule B, lines 13 and
14, to determine Overhead Costs of Maintenance Costs.
Schedule B, line 13, shall reflect Bonneville's total system
maintenance overhead costs for a fiscal year. Bonneville's total
system maintenance overhead costs for a fiscal year shall include all
system maintenance overhead expenses for such fiscal year for any of
the following: salaries, wages, employee benefits, overtime pay,
travel, service contracts, consulting contracts, materials, spare
parts, and other expenses, each of which being incurred by Bonneville
in connection with any of the following activities and services of
Bonneville: (a) support services (including services with respect to
mainframe computers, microcomputers, laboratories, building
management, materials and procurement, Electric Power Research
Institute, fixed-wing aircraft, helicopter, tools, and work
equipment); (b) general and administrative activities (including
general and administrative activities with respect to the office of
the Administrator, the Washington DC office, and the offices of:
contracts and property management; fish and wildlife; equal employment
opportunity; information resources; environment; internal audit;
external affairs; general counsel; quality improvement; planning
council liaison; financial management; power sales; energy resources;
management services; area offices; operations, maintenance, and
construction; and engineering); and (c) other system maintenance
overhead activities undertaken by Bonneville that are consistent with
system maintenance activities similar to the above-listed activities
undertaken by utilities in the Western System Coordinating Council.
Schedule B, line 14, shall reflect Overhead Cost of Maintenance Cost.
Schedule B, line 15, shall reflect Maintenance Cost.
III. Replacement Costs and Reinforcement Costs
-----------------------------------------
A. Replacement Costs and Reinforcement Costs - Direct Costs
The Direct Costs for Replacements and Reinforcements for a fiscal year
(Schedule C, line 1) shall be Bonneville's direct capital costs for
Replacements and Reinforcements for such fiscal year and shall include
all costs for any of the following: salaries, wages, employee
benefits, overtime pay, travel, service contracts, consulting
contracts, land, materials and equipment, spare parts, administration
of spare parts, transportation of spare parts, tools, tools
procurement and administration, direct support services (including
equipment use activities, general shops activities, and heavy mobile
equipment maintenance), and other costs, each of which being incurred
by Bonneville in connection with the performance of the following
Exhibit I, Page 9 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
activities: planning, environmental analyses and mitigation, survey,
design, land, materials and equipment, turnkey contracts, contract
construction, force account construction, and other reinforcement and
replacement activities undertaken by Bonneville that are consistent
with reinforcement and replacement activities similar to the above-
listed activities undertaken by utilities in the Western Systems
Coordinating Council. The Direct Costs for any Replacement or
Reinforcement for a fiscal year shall also include the costs of
removal and any salvage credits with respect to any PNW AC Intertie
facility removed on account of such Replacement or Reinforcement.
B. Replacement Costs and Reinforcement Costs - Indirect Costs and
Overhead Costs
For each Replacement and Reinforcement project, the Indirect Costs and
Overhead Costs for Replacements and Reinforcements (Schedule C, line
2) shall be allocated or distributed to such Replacements and
Reinforcements using the indirect and overhead allocation and
distribution methodologies employed by Bonneville to allocate and
distribute indirect and overhead costs to all of Bonneville's other
capital projects during the time the Replacements and Reinforcements
are under construction. Schedule C, line 2, shall reflect the
Indirect Costs and Overhead Costs of Replacements and Reinforcements.
Indirect Costs of Replacements and Reinforcements shall include all
costs for any of the following: salaries, wages, employee benefits,
overtime pay, travel expenses, service contracts, consulting
contracts, administration of materials, tools, tools procurement and
administration, direct support services (including equipment use
activities, general shops activities, and heavy mobile equipment
maintenance), and other costs, each of which being incurred by
Bonneville in connection with the performance of any of the following
activities: supervision, technical analyses, engineering studies,
program analyses, planning, budgeting, training, and other
reinforcement and replacement activities undertaken by Bonneville that
are consistent with reinforcement and replacement activities similar
to the above-listed activities undertaken by utilities in the Western
Systems Coordinating Council.
Overhead Costs for Replacements and Reinforcements shall include all
costs for any of the following: salaries, wages, employee benefits,
overtime pay, travel, service contracts, consulting contracts,
materials, spare parts, and other costs, each of which being which
being incurred by Bonneville in connection with any of the following
activities and services of Bonneville: (a) support services
(including services with respect to mainframe computers,
microcomputers, laboratories, building management, materials and
procurement, Electric Power Research Institute, fixed-wing aircraft,
helicopter, tools, and work equipment); (b) general and administrative
activities (including general and administrative activities with
Exhibit I, Page 10 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
respect to the office of the Administrator, the Washington DC office,
and the offices of: contracts and property management; fish and
wildlife; equal employment opportunity; information resources;
environment; internal audit; external affairs; general counsel;
quality improvement; planning council liaison; financial management;
power sales; energy resources; management services; area offices;
operations, maintenance, and construction; and engineering); and (c)
other replacement and reinforcement activities undertaken by
Bonneville that are consistent with replacement and reinforcement
activities similar to the above-listed activities undertaken by
utilities in the Western System Coordinating Council.
C. Replacement Costs and Reinforcement Costs - Allowance for Funds
Used During Construction (AFUDC)
Schedule C, line 3, shall reflect AFUDC for Replacements and
Reinforcements. At the beginning of each fiscal year, Bonneville
shall calculate the AFUDC rate for such fiscal year. Bonneville shall
apply such AFUDC rate monthly to the costs in accounts for
construction work in progress for Replacements and Reinforcements.
D. Replacement Costs and Reinforcement Costs - Interest
Schedule C, line 4, shall reflect the interest cost payable by Puget
pursuant to this Agreement with respect to any Replacement or
Reinforcement. Such interest cost for any Replacement or any
Reinforcement shall be simple interest calculated at a rate equal to
the weighted average interest rate on Bonneville's then outstanding
bonds or other debt instruments and such interest shall accrue from
the date Bonneville stops accruing AFUDC (approximately the date the
work order for such Replacement or such Reinforcement is closed) with
respect to such Replacement or such Reinforcement to the due date of
the monthly power bill containing the charge for such Replacement or
such Reinforcement.
IV. General Plant Costs
-------------------
For each Operating Plan, Bonneville shall adjust, amortize, and
allocate Bonneville's total general plant investment (as described
below) and Bonneville's Dittmer control equipment investment as set
forth in Schedule D, lines 1 through 11, to determine General Plant
Cost.
Schedule D, line 1, shall reflect for a fiscal year Bonneville's total
cumulative general plant investment. Bonneville's total general plant
investment shall include Bonneville's investments in any of the following:
land-general plant, structures/improvements-general plant, office furniture
and equipment, transportation equipment, stores equipment, tools/shop/garage
equipment, laboratory equipment, power operated equipment, communication
equipment, miscellaneous equipment
Exhibit I, Page 11 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
(including equipment or apparatus used in Bonneville's utility
operations which are not includable in any other general plant
investment category), and other similar investment made by Bonneville
that is consistent with general plant investment made by utilities in
the Western Systems Coordinating Council.
Schedule D, line 2, shall reflect for a fiscal year Bonneville's
cumulative investment in Dittmer control equipment.
Schedule D, line 3, shall reflect Bonneville's total general plant
investment and Bonneville's Dittmer control equipment investment
functionalized to generation using the methodology for functionalizing
general plant as set forth in Bonneville's general rate case most
recently approved by FERC on an interim basis.
Schedule D, line 4, shall reflect any general plant investment
recovered from all Capacity Owners under the CO-94 rate as such
general plant investment is unitized by Bonneville; provided, however,
for the first two Operating Plans Bonneville shall estimate the amount
of the general plant investment included in the Initial Capacity
Ownership Price, which estimate shall be reflected in Schedule D, line
4, and Bonneville shall modify such Operating Plans by December 1995,
or as soon as practicable thereafter, to reflect in Schedule D, line
4, the actual general plant investment included in the Adjusted
Capacity Ownership Price.
Schedule D, line 5, shall reflect any general plant investment
recovered from Capacity Owners pursuant to section 5 for Upgrades.
The agreements referred to in subsection 5(d) and subparagraph
5(e)(3)(B) shall specify the portion of costs of an Upgrade that will
be considered general plant investment.
Schedule D, line 6, shall reflect Bonneville's adjusted general plant
investment functionalized to transmission and shall be calculated by
adding line 1 and line 2, and from the sum of line 1 and line 2
subtracting line 3, line 4, and line 5.
Schedule D, line 7, shall reflect Bonneville's annual cost of
Bonneville's adjusted general plant investment functionalized to
transmission (Schedule D, line 6). Such annual cost shall be the sum
of the annual interest and amortization amounts for each category of
adjusted general plant investment. The annual interest and
amortization amounts for each category shall be calculated by using
the investment amounts for each such category, the weighted average
interest rate for all Bonneville then outstanding bonds, and the
average service lives for each such category from Bonneville's most
recent depreciation study. If Bonneville changes its practice of
financing general plant investment with bonds, the interest rate used
in the calculation referred to in the immediately preceding sentence
shall reflect the weighted average interest rate for all of
Bonneville's then outstanding debt instruments.
Exhibit I, Page 12 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
Schedule D, line 8, shall reflect for a fiscal year Bonneville's total
cumulative transmission plant-in-service investment (not including
general plant investment). Bonneville's total transmission plant-in-
service investment shall include Bonneville's investment in any of the
following items reflected as total transmission plant-in-service (not
including general plant investment) in the Segmentation Study (from
Bonneville's general rate case most recently approved by FERC on an
interim basis: land and land rights-transmission plant,
structures/improvements-transmission plant, station equipment, towers
and fixtures, poles and fixtures, overhead conductor, underground
conductor, roads and trails, and other transmission plant investment
made by Bonneville that is consistent with transmission plant
investments made by utilities in the Western Systems Coordinating
Council.
Schedule D, line 9, shall be the annual cost ratio of Bonneville's PNW
AC Intertie transmission-related general plant derived by dividing
Schedule D, line 7, by Schedule D, line 8.
Schedule D, line 10, shall reflect Bonneville's PNW AC Intertie
investment. Bonneville's PNW AC Intertie investment shall include
Bonneville's investment in any of the following items reflected as
Bonneville's PNW AC Intertie plant-in-service in the Segmentation
Study from Bonneville's general rate case most recently approved by
FERC on an interim basis (or the successor to the Segmentation Study,
as determined by Bonneville): land and land rights-transmission
plant, structures/improvements-transmission plant, station equipment,
towers and fixtures, poles and fixtures, overhead conductor,
underground conductor, roads and trails, and other transmission plant
investment made by Bonneville that is consistent with transmission
plant investments made by utilities in the Western Systems
Coordinating Council.
V. Other Costs
For each Operating Plan, Bonneville shall include Other Costs
associated with Bonneville's PNW AC Intertie for a fiscal year. Such
Other Costs (Schedule E, line 3) for a fiscal year shall include for
such fiscal year any of the following: (1) the costs of operation;
maintenance; capital replacements, reinforcements, additions,
betterments, renewals; or related costs which Bonneville is obligated
to pay pursuant to the Northwest Intertie Agreements or other
contracts referred to in subsection 8(b) of this Agreement; and (2)
costs paid by Bonneville including monetary judgments, settlements,
binding awards, non-contract penalties, contract penalties, liquidated
damages, or forfeiture costs, and Bonneville's costs related to such
monetary judgments, settlements, binding awards, non-contract
penalties, contract penalties, liquidated damages, or forfeiture costs
Exhibit I, Page 13 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
assessed against or incurred by Bonneville as a facilities owner of,
or the operator of, the PNW AC Intertie; provided, however, that Puget
shall not be obligated to pay a share of any such costs that are not
properly allocated to Bonneville's PNW AC Intertie.
Bonneville shall forecast its share of operations, maintenance,
capital, and related costs for activities that PacifiCorp performs on
Bonneville/PacifiCorp jointly-owned PNW AC Intertie facilities based
on forecasts received from PacifiCorp or on actual costs for the most
recent 12 consecutive month period prior to preparation of an
Operating Plan.
VI. Contracts and Rates Costs
-------------------------
A. Contracts and Rates Costs - Functionalization Factor
For each Operating Plan, Bonneville's total contracts and rates direct
costs, indirect costs, and overhead costs (Schedule F, lines 5, 6, and
7) shall be adjusted by a contracts and rates functionalization factor
(Schedule F, line 3). The contracts and rates functionalization
factor shall be based on a ratio of costs from Bonneville's general
rate case most recently approved by FERC on an interim basis. Using
costs developed for the last year of the rate period for which
Bonneville has developed rates, the contracts and rates
functionalization factor shall be the ratio of (a) Bonneville's total
transmission-related contracts and rates cost (Schedule F, line 1)
over (b) Bonneville's total contracts and rates cost (Schedule F, line
2). For each Operating Plan, Bonneville shall use the same
functionalization factor in calculating the forecast and actual
Contracts and Rates Cost.
B. Contracts and Rates Costs - Allocation Factor
The allocation factor (Schedule F, line 4) shall be the allocation
factor established in Schedule A, line 3.
C. Contracts and Rates Costs - Total Contracts and Rates Costs
Bonneville's total contracts and rates costs for a fiscal year
(Schedule F, line 8) shall include Bonneville's expenses (including
direct, indirect, and overhead costs) for such fiscal year for any of
the following: salaries, wages, employee benefits, overtime pay,
travel, service contracts, consulting contracts, materials, tools, and
direct support services (including equipment use activities, general
shops activities, and heavy mobile equipment maintenance), and other
expenses, each of which being incurred by Bonneville in connection
with the performance of the following activities: rate filings with
FERC, development of rates customers pay Bonneville for electric power
and for wheeling their own power on Bonneville's transmission system;
Exhibit I, Page 14 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
negotiation, administration, and coordination of contracts for power
sales, power exchanges, conservation, wheeling and resource services;
and analyzing, processing, and issuing all customer power bills; and
other activities undertaken by Bonneville that are consistent with
activities similar to the above-listed activities undertaken by
utilities in the Western Systems Coordinating Council.
Schedule F, line 9, shall reflect Contracts and Rates Cost.
VII. Power Scheduling Costs
----------------------
For each Operating Plan, Bonneville's total power scheduling direct
costs, indirect costs, and overhead costs (Schedule G, lines 5, 6, and
7) shall be adjusted by a power scheduling functionalization factor
(Schedule G, line 3). The power scheduling functionalization factor
shall be based on a ratio of costs from Bonneville's general rate case
most recently approved by FERC on an interim basis. Using costs
developed for the last year of the rate period for which Bonneville
has developed rates, the power scheduling functionalization factor
shall be the ratio of (a) Bonneville's total transmission-related
power scheduling cost (Schedule G, line 1) over (b) Bonneville's total
power scheduling cost (Schedule G, line 2). For each Operating Plan,
Bonneville shall use the same functionalization factor in calculating
the forecast and actual Power Scheduling Cost.
B. Power Scheduling Costs - Allocation Factor
The allocation factor (Schedule G, line 4) shall be the allocation
factor established in Schedule A, line 3.
C. Power Scheduling Costs - Total Power Scheduling Costs
Bonneville's total power scheduling costs for a fiscal year (Schedule
G, line 8) shall include Bonneville's expenses (including direct,
indirect, and overhead costs) for such fiscal year for any of the
following: salaries, wages, employee benefits, overtime pay, travel,
service contracts, consulting contracts, materials, tools, and direct
support services (including equipment use activities, general shops
activities, and heavy mobile equipment maintenance), and other
expenses, each of which being incurred by Bonneville in connection
with the performance of the following activities: scheduling and
marketing power to Bonneville customers and interconnected utilities,
forecasting the hourly power requirements of Bonneville customers and
the interchange of power with the region's interconnected electric
utilities and with utilities outside the region, scheduling power to
be generated at each Federal plant, weather and streamflow
forecasting, controlling the reservoirs, implementing the intertie
access policy, coordinating power production with the multi-purpose
operation of the Federal power system, seasonal load/resource
planning, developing current short-term operating plans, short-term
Exhibit I, Page 15 of 15
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
marketing of Bonneville's surplus firm power, exchanges, and nonfirm
energy, and other activities undertaken by Bonneville that are
consistent with activities similar to the above-listed activities
undertaken by utilities in the Western Systems Coordinating Council.
Schedule G, line 9, shall reflect Power Scheduling Cost.
VIII. End of Term Costs
-----------------
When all facilities of the PNW AC Intertie are determined, in
accordance with Northwest Intertie Agreements, to be no longer
operable, Bonneville shall include a forecast of all Bonneville's
costs associated with decommissioning the PNW AC Intertie and credits
resulting from such decommissioning in the Operating Plan for each
fiscal year that such End of Term Costs are to be incurred.
Bonneville's End of Term Costs for a fiscal year (Schedule H, line 4)
shall include Bonneville's costs (including direct, indirect, and
overhead costs) for such fiscal year for any of the following:
salaries, wages, employee benefits, overtime pay, travel, service
contracts, consulting contracts, materials, spare parts,
transportation of spare parts, tools, direct support services
(including equipment use activities, general shops activities, and
heavy mobile equipment maintenance), and other costs, each of which
being incurred by Bonneville in connection with the performance of any
of the following activities: decommissioning, razing structures,
disposal of debris, site restoration, meeting all requirements of
Federal, state, or local applicable law relating to the foregoing
activities, and other decommissioning activities undertaken by
Bonneville that are consistent with decommissioning activities similar
to the above-listed activities undertaken by utilities in the Western
Systems Coordinating Council.
Exhibit I, Schedule A
Page 1
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
Line
No.1 Forecast Actual Difference
SCHEDULE A FOR FY XXXX
I. Operations Costs
A. Allocation Factor
MFUs of Bonneville PNW AC
Intertie 1 ________
MFUs of the FCRTS 2 ________
Allocation factor 3 ________
(Line 1/Line2)
B. Operations
Functionalization Factor
Bonneville's total 4 ________
transmission-related
system operations cost
from rate case
Bonneville's total systems 5 ________
operations cost from rate
case
Operations functionalization 6 ________
factor (Line 4/Line5)
C. Allocated Direct Cost
Bonneville's total system 7 ________ ________ __________
Allocated Direct Cost of 8 ________ ________ __________
Operations Cost
(Line 3*Line 6*Line 7)
<PAGE>
Exhibit I, Schedule A
Page 2
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
Line
No.1 Forecast Actual Difference
D. Indirect Cost
Bonneville's total system 9 ________ ________ __________
operations indirect cost
Indirect Cost of Operations Cost 10 ________ ________ __________
(Line 3*Line 6*Line 9)
E. Overhead Cost
Bonneville's total system 11 ________ ________ __________
operations overhead cost
Overhead Cost of Operations Cost 12 _________ ________ __________
(Line 3*Line 6*Line 11)
F. Operations Cost 13 _________ ________ __________
(Lines 8+10+12)
<PAGE>
Exhibit I, Schedule B
Page 1
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
SCHEDULE B FOR FY XXXX
Line
No.1 Forecast Actual Difference
II. Maintenance Cost
A. Power System Control (PSC)
Maintenance Functionali-
zatio Factor
Bonneville's transmission- 1 ________
related PSC maintenance
cost from rate case
Bonneville's total PSC 2 ________
maintenance cost from
rate case
PSC maintenance 3 ________
functionalization factor
(Line1/Line2)
B. Direct Cost
Total PSC direct cost 4
cost
MFU Allocation Factor 5 ________
(Schedule A, line 3)
PSC direct maintenance 6 ________ ________ __________
cost for Bonneville's
PNW AC Intertie
(Line 4*Line 3*Line 5)
Bonneville's direct cost of 7 ________ ________ __________
maintaining Bonneville's
PNW AC Intertie excluding
PSC maintenance cost
Direct Cost of Maintenance 8 ________ ________ __________
Cost (Line 6+Line 7)
<PAGE>
Exhibit I, Schedule B
Page 2
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
C. Allocation Factor
Bonneville's total system 9 ________ ________ __________
maintenance direct cost
Allocation factor for 10 ________ ________ __________
Indirect Cost and
Overhead Cost
(Line 8/Line9)
D. Indirect Cost
Bonneville's total 11 ________ ________ __________
system maintenance
indirect cost
Indirect Cost of 12 ________ ________ __________
Maintenance Cost
(Line 11*Line 10)
E. Overhead Cost
Bonneville's total system 13 ________ ________ __________
system maintenance
overhead cost
Overhead Cost of 14 ________ ________ __________
Maintenance Cost
(Line 13*Line 10)
F. Maintenance Cost 15 ________ ________ __________
(Lines 8+12+14)
<PAGE>
Exhibit I, Schedule C
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
SCHEDULE C
Line
No.1 Forecast Actual Difference
III. Replacement Costs and
Reinforcement Costs
A. Direct Cost
Direct Costs of Replace- 1 ________ ________ _________
ments and Reinforcements
B. Indirect Costs and Overhead
Costs
Indirect Costs and Overhead 2 ________ ________ ________
Costs of Replacements
and Reinforcements
C. AFUDC
AFUDC of Replacements and 3 ________ ________ ________
Reinforcements
D. Interest
Interest Cost of Replacements 4 ________
and Reinforcements
E. Total Replacement Costs and 5 ________ ________ ________
Reinforcement Costs
(Lines 1+2+3+4)
Notes:
A separate Schedule C will be provided in the Operating Plan for each
Replacement and Reinforcement.
Forecasts of Replacement Costs and Reinforcement Costs will be provided;
Capacity Owners shall be billed for Replacements and Reinforcements
using actual cost pursuant to section 9(b)(2)(B).
<PAGE>
Exhibit I, Schedule D
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
SCHEDULE D FOR FY XXXX
Line Allocated
No. Actual
IV. General Plant Cost
Bonneville's total general plant 1 __________
investment
Bonneville's Dittmer control 2 __________
equipment investment
General plant investment of lines 1 3 __________
and 2 functionalized to generation
General plant investment recovered 4 __________
from all Capacity Owners in Adjusted
Capacity Ownership Price and Revised
Adjusted Capacity Ownership Price
General plant investment recovered 5 __________
from Capacity Owners for Upgrades
Adjusted general plant investment 6 __________
functionalized to transmission
(Line 1 + Line 2 - Line 3 - Line 4
- Line 5)
BPA total annual cost of Line 6 7 __________
general plant investment
BPA total transmission plant-in- 8 __________
service investment (not including
general plant investment) from
Segmentation Study
ACR for Bonneville's PNW AC 9 __________
Intertie (Line 7/Line 8)
Bonneville's PNW AC Intertie 10 __________
Investment from Segmentation Study
General Plant Cost 11 __________
(Line 9*Line 10)
<PAGE>
Exhibit I, Schedule E
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
SCHEDULE E FOR FY XXXX
Line
No.1 Forecast Actual Difference
V. Other Costs
A. PacifiCorp and related costs 1 ________ ______ __________
B. Other PNW AC Intertie costs 2 ________ ______ __________
C. Total Other Costs 3 ________ ______ __________
<PAGE>
Exhibit I, Schedule F
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
SCHEDULE F FOR FY XXX
Line
No.1 Forecast Actual Difference
VI. Contracts and Rates Costs
A. Contracts and Rates
Functionalization Factor
Transmission-related 1 ________
contracts and rates cost
from rate case
Total contracts and rates 2 ________
cost from rate case
Contracts and rates cost 3 ________
functionalization factor
(Line 1/Line 2)
B. Allocation Factor
MFU allocation factor 4 ________
(Schedule A, line 3)
C. Total Contracts and
Rates Costs
Contracts and rates direct 5 ________ ________ __________
costs
Contracts and rates 6 ________ ________ __________
indirect costs
Contracts and rates overhead 7 ________ ________ __________
costs
Bonneville's total contracts 8 ________ ________ __________
and rates costs
(Line 5 + Line 6 + Line 7)
D. Contracts and Rates Cost 9 ________ _________ __________
(Line 8 * Line * Line 4)
<PAGE>
Exhibit I, Schedule G
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
SCHEDULE G FOR FY XXXX
Line
No.1 Forecast Actual Difference
VII. Power Scheduling Costs
A. Power Scheduling
Functionalization Factor
Transmission-related power 1 ________
scheduling costs from rate
case
Total power scheduling cost 2 ________
from rate case
Power scheduling cost 3 ________
functionalization factor
(Line 1/Line 2)
B. Allocation Factor
MFU allocation factor 4 ________
(Schedule A, line 3)
C. Total Power Scheduling Costs
Power scheduling direct costs 5 ________ ________ _________
Power scheduling indirect costs 6 ________ ________ _________
Power scheduling overhead costs 7 ________ ________ _________
Bonneville's total power 8 ________ ________ _________
scheduling costs
(Line 5 + Line 6 + Line 7)
D. Power Scheduling Cost 9 ________ ________ _________
(Line 8 * Line 3 * Line 4)
<PAGE>
Exhibit I, Schedule H
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the effective date of Exhibit B
SCHEDULE H FOR FY XXXX
Line
No.1 Forecast Actual Difference
VIII. End of Term Costs
A. Direct Cost
Direct Cost of End of Term 1 ________ ________ __________
Costs
B. Indirect Costs and Over-
head Costs
Indirect Costs and Overhead 2 ________ ________ __________
Costsof End of Term costs
C. Credits
Credits from decommissioning 3 ________ ________ __________
PNW AC Intertie facilities
D. End of Term Costs 4 ________ ________ __________
<Page
Exhibit J, Page 1 of 1
Contract No. DE-MS79-94BP94521
Puget Sound Power & Light Company
Effective on the Effective Date
Puget's Initial Transaction with California Utility
Name of parties: Puget/Pacific Gas & Electric Company
Terms of Contract: Variable
Date of Execution: October 25, 1991
Amount of Transaction (MW): 300 MW
Exhibit 12a
PUGET SOUND POWER & LIGHT COMPANY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
<TABLE>
<CAPTION>
Year Ended December 31
-----------------------------------------------
1994 1993 1992 1991 1990
-----------------------------------------------
<S> <C> <C> <C> <C> <C>
EARNINGS AVAILABLE FOR FIXED CHARGES
Pre-tax income:
Net income per statement of income $120,059 $138,327 $135,720 $132,777 $132,343
Federal income taxes 80,259 83,970 72,449 56,180 64,094
Federal income taxes charged to
other income - net 1,556 (382) (2,106) (2,267) 12
Undistbuted (earnings) or losses
of less-than-fifty-percent-owned
entities -- -- (567) (16) (114)
-----------------------------------------------
Total $201,874 $221,915 $205,496 $186,674 $196,335
Fixed charges:
Interest on long-term debt $ 84,144 $ 86,030 $ 89,509 $ 84,791 $ 81,766
Other interest 6,249 3,542 10,477 6,384 8,368
Portion of rentals representative
of the interest factor 4,218 3,937 4,474 4,463 4,388
-----------------------------------------------
Total $ 94,611 $ 93,509 $104,460 $ 95,638 $ 94,522
Earnings available for
fixed charges $296,485 $315,424 $309,956 $282,312 $290,857
=========================================================================================
RATIO OF EARNINGS TO FIXED CHARGES 3.13x 3.37x 2.97x 2.95x 3.08x
</TABLE>
Exhibit 12b
PUGET SOUND POWER & LIGHT COMPANY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
(Dollars in Thousands)
<TABLE>
<CAPTION>
Year Ended December 31
-----------------------------------------------
1994 1993 1992 1991 1990
-----------------------------------------------
<S> <C> <C> <C> <C> <C>
EARNINGS AVAILABLE FOR COMBINED FIXED
CHARGES AND PREFERRED DIVIDEND REQUIREMENTS
Pretax Income:
Net Income per statement
of income $120,059 $138,327 $135,720 $132,777 $132,343
Federal income taxes 80,259 83,970 72,449 56,180 64,094
Federal income taxes charged to
other income - net 1,556 (382) (2,106) (2,267) 12
-----------------------------------------------
Subtotal 201,874 221,915 205,496 186,690 196,449
Undistributed (earnings) or losses
of less-than-fifty-percent-owned
entities -- -- (567) (16) (114)
-----------------------------------------------
Total $201,874 $221,915 $205,496 $186,674 $196,335
Fixed charges:
Interest on long-term debt $ 84,144 $ 86,030 $ 89,509 $ 84,791 $ 81,766
Other interest 6,249 3,542 10,477 6,384 8,368
Portion of rentals representative
of the interest factor 4,218 3,937 4,474 4,463 4,388
------------------------------------------------
Total $ 94,611 $ 93,509 $104,460 $ 95,638 $ 94,522
Earnings available for combined
fixed charges and preferred
dividend requirements $296,485 $315,424 $309,956 $282,312 $290,857
=========================================================================================
DIVIDEND REQUIREMENT:
Fixed charges above $ 94,611 $ 93,509 $104,460 $ 95,638 $ 94,522
Preferred dividend requirements 26,451 26,377 21,080 14,115 18,399
-----------------------------------------------
Total $121,062 $119,886 $125,540 $109,753 $112,921
=========================================================================================
RATIO OF EARNINGS TO COMBINED FIXED
CHARGES AND PREFERRED STOCK DIVIDENDS 2.45 2.63 2.47 2.57 2.58
COMPUTATION OF PREFERRED DIVIDEND
REQUIREMENTS:
(a) Pre-tax income $201,874 $221,915 $206,063 $186,690 $196,449
(b) Net income $120,059 $138,327 $135,720 $132,777 $132,343
(c) Ratio of (a) to (b) 1.6815 1.6043 1.5183 1.4060 1.4844
(d) Preferred dividends $ 15,731 $ 16,442 $ 13,884 $ 10,039 $ 12,395
Preferred dividend requirements
[(d) multiplied by (c)] $ 26,451 $ 26,377 $ 21,080 $ 14,115 $ 18,399
=========================================================================================
</TABLE>
Exhibit 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements
of Puget Sound Power & Light Company on Form S-3 (File Nos. 33-26818 and 33-
53056) and Form S-8 (No. 33-27396 and 33-52127) of our report dated February
10, 1995, on our audits of the consolidated financial statements and
financial statement schedule of Puget Sound Power & Light Company as of
December 31, 1994 and 1993, and for the years ended December 31, 1994, 1993
and 1992, which report is included in this Annual Report on Form 10-K.
Coopers & Lybrand L.L.P.
Seattle, Washington
March 10, 1995
<TABLE> <S> <C>
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,266,911
<OTHER-PROPERTY-AND-INVEST> 191,438
<TOTAL-CURRENT-ASSETS> 301,598
<TOTAL-DEFERRED-CHARGES> 0
<OTHER-ASSETS> 703,823
<TOTAL-ASSETS> 3,463,770
<COMMON> 636,409
<CAPITAL-SURPLUS-PAID-IN> 328,753
<RETAINED-EARNINGS> 207,567
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,172,729
91,242
125,000
<LONG-TERM-DEBT-NET> 963,298
<SHORT-TERM-NOTES> 94,900
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 139,554
<LONG-TERM-DEBT-CURRENT-PORT> 108,000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 769,047
<TOT-CAPITALIZATION-AND-LIAB> 3,463,770
<GROSS-OPERATING-REVENUE> 1,194,058
<INCOME-TAX-EXPENSE> 80,259
<OTHER-OPERATING-EXPENSES> 920,301
<TOTAL-OPERATING-EXPENSES> 1,000,560
<OPERATING-INCOME-LOSS> 193,498
<OTHER-INCOME-NET> 12,820
<INCOME-BEFORE-INTEREST-EXPEN> 206,318
<TOTAL-INTEREST-EXPENSE> 86,259
<NET-INCOME> 120,059
15,731
<EARNINGS-AVAILABLE-FOR-COMM> 104,328
<COMMON-STOCK-DIVIDENDS> 117,084
<TOTAL-INTEREST-ON-BONDS> 80,213
<CASH-FLOW-OPERATIONS> 259,028
<EPS-PRIMARY> 1.64
<EPS-DILUTED> 1.64
</TABLE>
