South Carolina Public Service Authority

ARMED SERVICES BOARD OF CONTRACT APPEALS
Appeals of -- )
)
South Carolina Public Service Authority ) ASBCA Nos. 60460, 60616
)
Under Contract No. DACW60-77-C-0005 )
APPEARANCE FOR THE APPELLANT: Megan E. Driggers, Esq.
Counsel
APPEARANCES FOR THE GOVERNMENT: Michael P. Goodman, Esq.
Engineer Chief Trial Attorney
John P. Kassebaum, Esq.
Engineer Trial Attorney
U.S. Army Engineer District, Charleston
OPINION BY ADMINISTRATIVE JUDGE MCNULTY
Appellant, South Carolina Public Service Authority (the Authority or appellant)
appeals from a denial of its claim that the government acting through the U.S. Army
Corps of Engineers, is improperly demanding payment for additional electrical
generation capacity provided to the Authority from the government’s St. Stephen
hydroelectric power plant pursuant to an agreement the parties entered into in 1976.
We deny these appeals, though, in accordance with the Board’s internal operating
procedures, this decision has no precedential value because Judges Shackleford and
Prouty concur only in result.
FINDINGS OF FACT 1
The Basis for the Contract
1. The contract at issue in these appeals reflects the settlement of a potential
claim the Authority had against the government arising from the government’s
1 Findings of fact without citation to the record are borrowed, with deletions,
paraphrasing and summarizing as appropriate for these appeals, from previous
decisions relating to the contract, primarily South Carolina Public Service
Authority, ENG BCA No. 5564, 89-3 BCA ¶ 21,921, and South Carolina
Public Service Authority, ENG BCA No. 5564, 91-2 BCA ¶ 23,760. See also
South Carolina Public Service Authority, ASBCA No. 53701, 04-2 BCA
¶ 32,651; and South Carolina Public Service Authority, ASBCA No. 57826,
decision to reduce the shoaling occurring in the Charleston, South Carolina harbor
caused by the increased discharges of water into the Cooper River resulting from the
Authority’s construction and operation of the Santee Cooper Project, by reducing the
discharge of water into the Cooper River from the Santee River. The reduction of
water discharges into the Cooper River adversely affected the Authority’s ability to
generate power.
2. The Santee Cooper Project was constructed by the Authority pursuant to a
license granted to it in 1926 by the Federal Power Commission (now FERC),
beginning in the late 1930’s. The project was designed to harness the hydroelectric
power capability of the Cooper River as enhanced by the discharges from the Santee
River.
3. After a lengthy period of study in the 1960’s, the government proposed
rediverting the water into the Santee River and through a new hydroelectric plant to be
built by the United States Army Corps of Engineers, with the generating capacity and
energy from this new facility being provided to the Authority as compensation for the
loss of water and energy resulting therefrom at the Authority’s Santee Cooper
Project’s Jeffries plant. This plan is referred to by the parties as the “St. Stephen
Plan.”
4. The Authority preferred an alternate plan, the “Price Inlet Plan” because it
would not have affected the generating capacity of its Jeffries plant (R4, tab 10 at 346
¶ 10b).
5. The Authority did not favor the St. Stephen plan because it would “create
unsalable peaking capacity,” as well as result in a loss of energy from the Jeffries
plant. Nevertheless, the Authority agreed to work with the government to develop the
St. Stephen plan under the principle that the Authority would be “kept whole,” made
13 BCA ¶ 35,239. However, familiarity with these prior decisions, which
include lengthy findings of fact setting forth in great detail most of the details
relating to the purpose of the Santee Cooper Project and the contract’s
negotiation and performance is presumed. In Blue Cross Association & Blue
Shield Association, ASBCA No. 25944, 83-1 BCA ¶ 16,524, we stated that we
can take official notice of findings of fact made in prior appeals involving the
same parties, contract, counsel and tribunal. Although these appeals involve a
different tribunal and counsel with respect to some of the decisions above, we
are satisfied, based on our review of the record here, that the previous findings
we have borrowed, paraphrased and summarized are accurate and that it is
appropriate to take official notice thereof for these appeals.
2
neither better nor worse off as a result of the project. 2 The contract between the parties
subsequently negotiated was based on the “keep whole” principle.
6. As part of this principle the Corps, in a 1966 study, recommended that the
government be reimbursed by the Authority for the “betterments,” i.e., the additional
power generated by the St. Stephen plan made available to the Authority. In this
regard the study stated:
It is recommended as an equitable solution that the hydro
plant be constructed, maintained and operated by the Corps
of Engineers; that the power and energy produced be
delivered to and as directed by the South Carolina Public
Service Authority; that the Corps will be liable for
damages resulting from project construction and operation;
and that project betterments be reimbursable to the United
States.
(R4, tab 9 at 160, tab 10 at 278)
7. The study analyzed several alternative plans, including the hydroelectric
plant and related facilities ultimately built. The initial cost estimate from the 1966
study for this plan estimated a total federal investment of $37,592,000 based on an
estimated cost of $35,381,000 plus $2,211,000 in interest and annual charges of
$1,687,000. (R4, tab 9 at 197, 214) The initial estimate of the value of the betterment
of the added dependable capacity was $773,000 per year based on $9.20 per kw year
(id. at 203 ¶ 85). The study also indicated the “Net Power Benefits” would total
$417,0003 per year, which would have the effect of reducing the annual charges from
$1,687,000 to $1,270,000 (id. at 204).
8. All of the project cost analyses performed in the government’s study were
based upon a 50 year economic life for the hydro plant (R4, tab 9 at 226). The basis
for the 50 year period for economic analysis of hydroelectric plants is set forth in the
Federal Power Commission’s “Hydroelectric Power Evaluation” (R4, tab 11 at 517).
In contrast, thermal plants, which the FPC/FERC methodology uses to compare to as
the alternate power source when evaluating hydro plants, are considered to have 30-35
year service lives (finding 32).
9. The annual value of hydroelectric power consists of two measurable
components which are defined as follows: (1) a capacity value, which corresponds to
2 The Authority expressed its understanding that the “kept whole” concept had been
agreed to in principle by the government as early as 1966 (R4, tab 10 at 449).
3 How this figure was derived is not set out in the study.
3
the fixed elements of the cost of power supply from an alternative electric generating
plant; and (2) an energy value, which corresponds to the variable elements of the cost
of power supply from the alternative plant (R4, tab 11 at 596).
10. The 1966 study included a letter from the Authority dated May 5, 1966,
setting forth terms that subsequently, essentially became the agreement between the
government and the Authority (R4, tab 9 at 218-22). The letter set out the principle
that the Authority was to be made “whole” by the government, which would
compensate the Authority annually for the reduced flow of water through the Jefferies
plant and its detrimental effect on the Authority’s power generating. The letter also set
forth the concept that the Authority would credit the government for the added power
generating capacity that the new St. Stephen plant would provide and that title to the
new plant would transfer to the Authority after 50 years, if not sooner by agreement of
the parties. (Id. at 219-20)
11. The study’s findings were incorporated into the Corps’ report to Congress
that is included in Senate Document No. 88, 90th Congress, 2nd Session (S. Doc.
No. 88), which provided the basis for Congress’ approval of the St. Stephen project as
part of Pub. L. No. 90-483 (1968) (R4, tab 10 at 267-69, 279-483).
12. In S. Doc. No. 88, Congress indicated that FPC (FERC) would be the
arbitrator of disputes on the issue of appropriate compensation to make the Authority
whole. However, the authorizing document, Pub. L. No. 90-483 (1968), said that the
Corps and the Authority should consult with the FPC (FERC) regarding the yearly
balancing of energy loss and capacity gain to make the Authority whole.
13. S. Doc. No. 88 included, among other things, a report from the Chief of
Engineers to the Secretary of the Army. In his cover letter dated December 29, 1967,
the Chief of Engineers addressed, in pertinent part, the costs of the rediversion project:
The District and Division Engineers estimate the Federal
construction cost at $ 35,381,000, which includes
provisional fish and wildlife features. Annual charges are
estimated at $1,687,000, including $191,000 for operation
and maintenance. A net power betterment presently
estimated at $417,000 4 annually to be subtracted from this
amount would bring the net annual charges to $1,270,000.
Annual benefits [savings from less government-funded
maintenance dredging in Charleston Harbor] are estimated
4 This figure appears to have been carried over from the 1966 study (finding 7). Once
again how this figure was derived is not set forth in the report.
4
at $2,750,000 and the benefit-cost ratio is 2.2 based on a
50-year period of analysis.
the . . . Secretary. . . acting through the Chief of Engineers,
would be authorized to determine and enter into agreement
with [the Authority], for apportionment of costs between
the United States and [the Authority]. . . . The Board [of
Engineers for Rivers and Harbors] includes the
recommendations that the Secretary . . . acting through the
Chief of Engineers, be authorized to negotiate with [the
Authority] for a limitation of releases from Pinopolis Dam
to Cooper River . . . and to reimburse the Authority for the
cost involved, provided that reimbursement shall not
exceed estimated average attendant reductions in the
Federal cost of maintenance of Charleston Harbor as
determined by the Secretary. . . .
14. On August 13, 1968, Public Law No. 90-483, entitled “Public Works --
Rivers and Harbors,” was enacted. Title I of that law “adopted and authorized” the
Army’s plans and recommendations in S. Doc. No. 88 for the “improvement of rivers
and harbors and other waterways for navigation, flood control and other purposes.”
Pub. L. No. 90-483 authorized the government and the Authority to negotiate an
agreement to apportion between the costs of lost energy and the value of the betterment
of increased capacity in furtherance of the congressional purpose of maintaining the
Authority’s system in a sound condition by keeping it whole after the completion of the
project.
15. The project was listed in the Act with an estimated cost of $35,381,000.5
Pub. L. No. 90-483.
16. Section 101 of the Act authorized the Secretary of the Army with the
supervision of the Chief of Engineers to prosecute the Santee Cooper rediversion
project, in accordance with the plans and subject to the conditions recommended by
the Chief of Engineers in the designated report, S. Doc. No. 88. Pub. L. No. 90-483.
The referenced recommendations appear in paragraphs 111 to 114 of the report (R4,
tab 10 at 245, 325-27). With respect to the increased capacity to be provided by the
construction of the St. Stephen hydroelectric plant, the following recommendation was
made:
b. The costs to the United States shall not include
any betterments to others arising from the increase in
5 The Act authorized many projects in addition to the rediversion project involved in
these appeals.
5
capacity provided. The Secretary of Army, acting through
the Chief of Engineers, is authorized to determine and
enter into agreement with South Carolina Public Service
Authority or its successors in interest, for apportionment of
costs between the United States and the South Carolina
Public Service Authority. Such determinations will be
accomplished in consultation with the Federal Power
Commission.
(Id. at 325) This mirrors the recommendation first made by the Corps in 1967 (id.
at 275-76).
17. The net power benefit reported was estimated to be $417,000 annually 6
(R4, tab 10 at 317). In 1966, the Authority proposed that at the end of each year of
operation of the St. Stephen project that there be a cash settlement of the various
credits to be paid and that the agreement be in effect for 50 years (id. at 333-35). With
respect to the credit to be paid to the government for the dependable capacity of the
St. Stephen plant the Authority stated:
The amount of this credit is still open. We estimate that
the fair value to the Authority of the capacity used, which
will be available only a small percentage of the time, is
$6 per year per kilowatt based on studies which we have
made available to you. The Corps estimates present-day
capacity values at $9.20 per year per kw under pooling
concepts, and $11.05 per year per kw under isolated
systems operation concept.
(Id. at 333) The Authority also suggested that disputes regarding the amount of the
credits be referred to the FPC for resolution (id. at 334 ¶ (d)).
18. Over a period of eight years, but principally in 1974, 1975, and 1976, the
government and the Authority negotiated the contract here at issue in accordance with
the congressional authorization referenced above.
19. The record includes evidence that the initial contract agreement was drafted
by Sverdrup and Parcels (S&P), a consultant to the government in 1974 (R4, tab 12
at 608). S&P also prepared a report for the government in 1974, in which S&P
determined values for capacity and energy, established the values for the betterments
resulting from the rediversion project and estimated the operation and maintenance
costs for the proposed St. Stephen plant (R4, tab 13 at 626). S&P estimated the then
6 Again, how this figure was derived is not set out in the report.
6
present worth of the St. Stephen capacity to be $35,111,500 over 50 years. S&P also
noted that the actual value for any particular year would depend on the maximum
capacity utilized in that year. (Id. at 640) This estimate was based on the FPC
methodology using an equivalent steam-electric plant as the alternate for comparison
purposes (id. at 641).
20. A government letter dated March 28, 1975 indicates that the values for
capacity and energy calculated by the FPC and S&P have varied considerably at
different points in time as follows:
FPC FPC FPC S&P
Item 4 May 65 28 Apr 71 22 Jun 73 1 Jan 74
Capacity $16.20 $17.50 $40.55 $29.81
Energy 3 Mills. 4.85 mills 4.40 mills 7 mills
(R4, tab 15 at 717)
21. On February 17, 1975, the government sent the first draft of an agreement
to the Authority. It contained no values calculated for energy or capacity. At
approximately the same time, the government requested the Federal Power
Commission (FPC) to provide updated capacity and energy values for the project. The
FPC calculated a capacity value for the hydropower facility of $34/kW/yr. based on
the cost of constructing a steam electric facility alternative which would produce the
equivalent capacity of the hydropower project. Capacity is the capability of the project
to produce energy over a period of time.
22. Following initial contract negotiations, the Authority’s General Manager
and the Charleston District Engineer signed a draft contract, subject to the approval of
the Chief of Engineers. A significant feature of the draft contract was that the
Authority would pay for the project's added dependable capacity when used in any one
year. During negotiations, the parties consulted the FPC manual P-35, “Hydroelectric
Power Evaluation,” as a reference to define “dependable capacity.” “Dependable
Capacity” is defined therein as the capacity that can be relied upon to carry a system
load during the most adverse flow conditions of record. The contract, however,
contains no definition of the term.
23. The parties executed an agreement in December 1975, which ultimately
was not approved, as required, by the Chief of Engineers because a government
representative expressed concern that the government would not be sufficiently
compensated for the added capacity provided to the Authority by the project under the
agreement as then drafted (R4, tab 40 at 1204 ¶¶ 2, 31).
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24. The record indicates that one of the stumbling blocks to achieving a final
agreement was the difficulty in estimating the value of the Jefferies plant after the
rediversion (R4, tab 41 at 1208 ¶ 2). To get past this obstacle to achieving the
agreement the government, with consensus from the FPC, decided that the project
gains and losses would offset each other, at least for the initial years of the contract,
despite the government’s long held view that the power benefits provided by the
project exceeded the value of the power losses (R4, tab 42 at 1208 ¶¶ 3-4, tab 48
at 1270).
25. The record reflects that before the contract was signed, the parties had
differing approaches with respect to calculating the capacity value. The Authority
used a gas turbine for the replacement source, whereas the government used a steam
electric plant as the replacement source. (R4, tab 26 at 997 ¶ m) The parties, over a
long period of time, negotiated the costs to be used in exhibit A to generate the
capacity and other values (R4, tab 28 at 1038, ex. A at 1066, tab 30 at 1076, ex. A
at 1106-11, tab 32 at 1161, ex. A at 1163, tabs 36, 38, ex. A at 1184-90, tabs 51-52).
The values derived underwent significant revisions as the parties revised the
assumptions they used regarding the numerous variables in the analysis (R4, tab 32
at 1156, tabs 37-38). Furthermore the various factors used in the various methods that
the parties considered during the period of negotiation in addition to being difficult to
estimate could lead to significant changes in the credits to be paid, such that one
method might result in a net credit to be paid to the Authority, while another method
might result in a net payment to the government (R4, tab 39 at 1198-1203).
26. The parties were unable to agree, or awaited the development of
information in the future regarding several issues and deferred decision in the contract
on these issues. One of the principal examples of this is the decision to defer deciding
what to do with respect to the “objectionable heat rise during cooling of the Jefferies
steam plant. (R4, tab 32 at 1157, tab 2 at 12, 16 ¶ 1.7)
27. The record includes evidence that the Authority was concerned that the
energy value for gas turbines was hard to evaluate for a 50 year project life (R4, tab 38
at 1179-80 ¶ VI. 2).
28. Despite the continuing objections of the Authority to the value (provided
by the FPC) to be placed upon the 84 Mw of added dependable capacity, it never
objected to the determination of 84 Mw as the added dependable capacity. Though the
contract contained variables for determining the credit value for the 84 Mw of
dependable capacity to be given the government and left the final determination of the
value to be decided at a later date under a prescribed formula, the fact of 84 Mw of
added dependable capacity was an unambiguous term and requirement of the contract.
8
29. The following evidence substantiates the general agreement by the negotiating
parties as to the FPC Manual and the accepted industry definition of “dependable
capacity,” as well as the fact that the project provided 84 Mw of added dependable
capacity.
a. The discussion of “dependable capacity” during negotiations centered
upon whether the 84 Mw of added dependable capacity was to be evaluated
in accordance with the combustion turbine alternative or the steam electric
alternative.
b. The Authority first stated in its revision of the contract draft of 1 July
1975, that the capacity of St. Stephen would be 84 Mw.
c. The draft contract of 18 July 1975, explicitly referred to the dependable
capacity at St. Stephen’s to be 84 Mw and Jefferies to be 128 Mw of existing
capacity.
d. The reference to 84 Mw dependable capacity continued, without
modification or discussion, through succeeding drafts.
e. The Authority’s expert during negotiations recommended that the 84
Mw dependable capacity be modified to include a potentially higher
dependable capacity by the inclusion of the words “presently expected to
be.” This was used in the next three drafts of the contract. At this time, the
Authority was concerned that all the added dependable capacity at the
project would be available to it and not made available to another power
company.
f. Following additional discussion between the parties about the contract
terms, wherein dependable capacity was not an issue, the Authority, in an
internal memorandum, stated that, after diversion, St. Stephen would have a
capacity of 84 Mw and Jefferies would have a capacity of 128 Mw.
g. At a meeting between the parties on September 15, 1976, the Authority
disputed the FPC’s value for the added capacity of 84 Mw but did not
contest the validity of the 84 Mw dependable capacity determination.
h. Draft contracts of September, 1976, eliminated the expression
“presently expected to be” in front of the “84 Mw dependable capacity”
and provided for a formula to value the 84 Mw added dependable capacity
at a date closer to the date the St. Stephen’s facility would be placed into
operation. There was no provision for or discussion of reevaluating the 84
9
Mw dependable capacity assessment either in the subsequent negotiations
or contract.
i. The Authority objected to the provisions of the draft contract which
provided for “no cash flow from the government to the Authority” and
which did not include a “four year buildup” for the Authority to utilize the
84 Mw of added dependable capacity in its system.
j. The contract was signed in 1976 with the term “84 Mw dependable
capacity” included, with a buildup provision for the Authority’s inclusion
of the added 84 Mw into its system, and with a provision to place a value
on the 84 Mw of added dependable capacity at a time 18 months before
operation of the project.
k. The Authority’s president in a public speech delivered after the signing
of the contract, spoke of the St. Stephen’s project as providing 84 Mw of
additional dependable capacity.
30. In summary, during the pre-contract negotiations, as well as subsequent to
execution of the contract, the Authority raised issues concerning: the fitting of the
added capacity into its load curve; increasing the flow allowances to permit more
efficient and easier utilization of the added capacity; valuing the added capacity as
combustion turbine rather than steam plant; determining the value of the added
capacity at a time closer to project operation; and, a buildup period for the Authority’s
utilization of added capacity. But the Authority did not raise concerns about the issues
concerning the validity of the determination that 84 Mw of added dependable capacity
would be provided by St. Stephen’s or that 84 Mw of added dependable capacity
would be usable in its system.
Hydropower Adjustment Factor (HAF)
31. The FPC Manual P-35, Hydroelectric Power Evaluation, was used within
the hydropower industry during the mid-1970’s as a guideline and was used by the
parties as a basis for contract negotiations. The manual states, on page 23 that
“usually the credit per kilowatt of capacity will range from 5 to 15 percent of the cost
per kilowatt of thermal capacity.” This percentage is referred to as the HAF.
32. FPC used a thirty-year service life in its analysis for calculating the value
of the added dependable capacity because that is the expected service life of a thermal
plant and hydro plants are appraised by assessing the costs of a similarly sized thermal
plant and making an adjustment with the HAF calculation for the added
benefits/efficiencies associated with a hydro plant. Hydro plants are assumed to have
10
a service life of 50-100 years. (R4, tab 1 at 4-5, tab 11 at 498, 516-18, 521, 525, 578,
587-88, 590)
33. Using the FPC manual, the hydropower adjustment factor (5-15 percent) is
multiplied by the thermal (steam or gas) equivalent of hydropower with the result added to
the thermal equivalent to determine the total capacity cost equivalent of thermal to
hydropower.
34. The purpose of adding the hydropower adjustment factor to the thermal
capacity cost is to recognize the benefits of hydropower’s operating efficiency and to
make a comparison between hydro and thermal power more reasonable and accurate.
Hydropower plants are appraised using a methodology in which it is assumed that the
utility must build either a coal-fired steam plant or a gas combustion plant rather than a
hydroplant to achieve the same capacity. Once the value of such a plant is calculated in
terms of an annual capacity cost, that figure is then adjusted by the hydropower
adjustment percentage to reflect the increased value of the plant because of its use of
water.
35. During negotiations, the parties disagreed upon the appropriate percent of
the hydropower adjustment factor (HAF); but they did not dispute that an adjustment
was appropriate. The government used a 10% HAF in its first draft contract, but the
Authority, contended for a 5% or 0% HAF. Following numerous drafts containing a
10% HAF, the Corps prepared and the Authority signed a contract which contained a
5% HAF for the combustion turbine alternative and a 10% HAF for the steam
alternative. The draft contract containing this agreement was not approved, as required,
by the Chief of Engineers, because the contract did not establish a firm date for the
Authority’s liability to pay for the added dependable capacity.
36. After the Chief of Engineers disapproved the proposed contract, later drafts
contained a 10% HAF in place of the 5% HAF in the disapproved contract. The final
approved contract contained, in exhibit A, a 10% HAF for all calculations. The
contract contains no provision for later adjustment of the 10% HAF. Section 6.1 of the
contract specifically states that “The value of capacity and energy credits shall be
computed in accordance with the procedure shown in exhibit A.” Pages A-4 and A-5
of appendix A show the method of calculating capacity value for both the steam
electric equivalent and the gas turbine equivalent. Both show a 10% HAF multiplied
against a calculated “annual capacity cost” with the result of the multiplication added
to the “annual capacity cost” to establish the “total capacity cost.” This is not the
procedure advocated by the Authority previously, which instead would have calculated
an HAF to be multiplied with the “annual capacity” cost to establish the “total capacity
cost” rather than add the percent HAF to the “annual capacity cost.”
11
37. The contract executed by the parties provided for inter alia the following
key components:
a. A determination that 84 Mw added dependable capacity would be
furnished by St. Stephen’s;
b. A 10% HAF to be applied to the thermal equivalent;
c. Valuation of the 84 Mw added dependable capacity at the gas turbine
equivalent rather than apportioned between steam and gas turbine
equivalents;
d. A three-year phase in by the Authority in using the 84 Mw of added
dependable capacity within its system; and
e. Provision for quantification of the value of the added 84 Mw
dependable capacity 18 months prior to operation of the project.
Other than the 84 Mw of added dependable capacity, which was accepted by
the parties, the parties negotiated in great detail all the other above provisions.
Contract No. DACW60-77-C-005
38. On December 27, 1976, the Authority and the government entered into the
contract. As reflected in its second to the last recital, the contract incorporated the
principles of agreement that the Corps had reported and recommended to Congress,
and that Congress had adopted and authorized in Pub. L. No. 90-483. In the last
recital, the parties stated their intent that the contract effectuate the “make whole”
principle:
WHEREAS, the parties desire that the Government be
compensated for the Project’s benefits to [Santee Cooper]
and that [Santee Cooper] be compensated for the adverse
effects of the Project.
(R4, tab 2 at 13)
39. This “make whole” principle is accomplished under the contract by a
system of credits and annual payments. In general, section 6 of the contract provides
that the government credits the Authority for the value of lost energy on account of the
project, while the Authority credits the government for the value of the capacity added
by the St. Stephen project. These credits are adjusted by various provisions of the
contract, including section 10, which provides that the credit to the government for
additional capacity is reduced when that capacity is unavailable because of an
12
unscheduled outage. Section 7 of the contract provides that there shall be a cash
settlement each year reflecting the balance of credits and adjustments.
40. Exhibit A to the contract provides a formula, or methodology, for
calculating the values of capacity of both steam and gas combustion equivalent
capacity. At paragraph 6.1, the contract provides that the parties are to establish these
values using the exhibit A formulas in consultation with the FPC (now FERC) at a
point in time 18 months before the anticipated date of commercial operation of the
rediversion project. Anticipating completion of the project in early 1985, the
government began to coordinate with FERC in 1982 concerning the appropriate
numbers to be used in the formulas to calculate steam and gas combustion capacities.
The government sought to have the calculations subsequently provided by FERC
approved by the Authority. The Authority refused to agree with these calculations,
taking issue with the number used by FERC in the hydropower adjustment portion of
the formula. The disagreement on this point arose from the parties’ different views as
to the effect on the value of the plant capacity.
41. This disagreement was the subject of the dispute in South Carolina Public
Service Authority, ENG BCA No. 5564, 89-3 BCA ¶ 21,921 and 91-2 BCA ¶ 23,760.
42. Section 1.3 of the contract states:
Transfer title to Project facilities and real estate to
the Authority at the end of a 50-year term commencing on
the date of commercial operation specified in paragraph 3.2.
At anytime during the period of this contract, the parties
may agree to advance the transfer of title upon a lump sum
settlement. Such settlement would be in an amount agreed
to represent the then present worth of the estimated credits
under Section 6 during (a) the then estimated remaining
service life of Jefferies and (b) the remainder thereafter of
the fifty year period specified in paragraph 3.2.
(R4, tab 2 at 15)
43. Section 2 of the contract required the Authority among other things to:
(i) restrict its use and release of water into the Cooper River from its Jefferies
hydroplant in accordance with limits specified by the government; (ii) maintain and
operate the cooling water system to be constructed by the government; (iii) maintain
project transmission lines, government meters on the Authority’s premises, and such
other facilities as may be mutually agreed upon; (iv) operate the St. Stephen
hydroplant by remote control equipment provided by the government; (v) maintain the
remote control equipment at government expense; and (vi) at Section 2.4:
13
Make the maximum use of the additional capacity
resulting from the combined two-plant operation which the
Authority deems economical and practical in light of water
availability, load conditions, costs and other operating
considerations. Credit the Government for the value of the
increase in useful capacity of Jefferies and St. Stephen
created by the Project, as determined pursuant to Section 6.
(R4, tab 2 at 19) The foregoing services were essential services for the commercial
operation of the project.
44. Section 3.2 states:
All obligations of the parties hereto with respect to
the delivery of power and payment therefor and reduction
of discharges from Jefferies shall commence at such time
as all three units at St. Stephen are placed in commercial
operation (herein called the date of commercial operation),
and shall continue in effect for fifty years, after which
ownership shall pass to the Authority pursuant to
paragraph 1.3. At the option of the Authority, transfer may
be effected at an earlier date, on 90 days written notice
after details of the transfer have been agreed upon between
the Authority and the Government.
(R4, tab 2 at 21) (emphasis added)
45. The contract provisions pertinent to the settlement of the parties’ respective
credit obligations are: 7
SECTION 6. Settlement.
Beginning with the date of commercial operation
and continuing for each succeeding contract year, ending
on the 30th day of June, or any partial initial or final year
of this Contract, there shall be a cash settlement between
the Government and the Authority, reflecting the net of:
7 The Board only sets forth in this decision a limited portion of section 6, Settlement.
In its entirety the settlement section includes four pages of the contract and ten
detailed pages of appendices.
14
6.1 Appropriate credits for increased available
capacity and loss of energy generation resulting from using
some of the water through the lower head at St. Stephen
instead of using it at Jefferies. . . . Values will be obtained
as follows for use in computing appropriate credits for
capacity and energy in Exhibit A: 8
a. On or before March 1, 1982, the Government
shall furnish the Authority an expected date of commercial
operation. The values of capacity shall be fixed as of a
date which is 18 months prior to such expected date of
commercial operation. Such values will be established by
the parties after consultation with the Federal Power
Commission and will prevail for a 30-year service life.
b. Current energy value for gas turbine equivalent
will be obtained from the Federal Power Commission. A
new value will be obtained from the Commission before
each June 30 to apply throughout the ensuing year.
c. Current energy value for the Authority system
will be obtained monthly from the Authority using
procedure shown in Exhibit C.
6.2 Pursuant to paragraph 2.3, a credit to the
Government for any weekly average discharge which
exceeds by more than 100 cfs the discharge provided for in
paragraph 2.1. The procedure for computation of credit is
displayed in Exhibit B.
....
6.4 A credit to the Authority for the adverse effect of
St. Stephen on the rights the Authority has acquired and the
facilities it has installed in preparation for expanding its hydro
plant at Jefferies. The amount of this credit shall be
determined according to the procedure displayed in Exhibit D.
....
8 The parties replaced exhibit A in 1995 with a revised version in supplemental
agreement No. 6 (R4, tab 2 at 80 ¶¶ 10, 81-85).
15
6.6 A credit to the Authority pursuant to paragraph
1.7 for all actual operation and maintenance costs of the
cooling water system referred to therein incurred by the
Authority (including capacity and energy valued in
accordance with Exhibits A and C) over and above any
such operation and maintenance costs required in the
absence of the Project.
6.7 . . . The capacity and energy values will be computed
using the values and procedures in Exhibits A and C,
respectively.
....
SECTION 7. Payment.
Payments under this contract shall be made until
title passes to the Authority pursuant to the provisions of
paragraph 1.3. Payment shall be made yearly in the form
of a cash settlement between the Government and the
Authority pursuant to the provisions of Section 6.
Payment shall be due on the 91st day following the 30th
day of June for each year of operation (1 July-30 June) or
partial year of operation of the Project from and after the
date of commercial operation. If either party shall fail to
make any payment under this contract within 30 days of
the date due, interest thereon shall accrue at a rate to be
determined in accordance with the provisions of Section 8.
The yearly payments shall be based on monthly settlement
statements prepared by the Authority and furnished to the
Contracting Officer within 20 days following the end of
each month. In the event of a dispute as to the correct
amount due, any net undisputed amount shall be paid when
due.
16
EXHIBIT A
Procedure for Computation on
an Annual Basis for Capacity and
Energy of Combined Two-Plant
Operation of St. Stephen and Jefferies Hydro Plants*
1. POWER QUANTITIES
JEFFERIES (BEFORE REDIVERSION)
A Capacity = 128,000 KW (1)
B Energy - Amount that could have been produced
annually by A above. See page A-6
for computation. = 657,000,000 KWH (2)
ST. STEPHEN
C Capacity = 84,000 KW (1)
D Energy - Amount attributable annually to C,
above. = 418,000,000 KWH (3)
JEFFERIES (AFTER REDIVERSION) Based on 3000 cfs total average flow.
E Capacity - Steam electric equivalent = 44,000 KW (4)
F Capacity - Gas turbine equivalent = 84,000 KW (4)
G Energy - Amount generated annually by E, above= Varies (5)
H Energy - Amount generated annually by F, above= Varies (5)
(1) Will be reduced when units become unavailable for service other than for
maintenance, repair or replacement or their physical capability is permanently reduced.
(2) Amount shown is based on estimated average annual generation for period of flow
record. Annual amounts will be computed as shown on page A-6.
(3) Amount shown is based on estimated average annual generation for period of flow
record assuming a rediversion of flow. Annual computation will utilize metered
amount actually generated.
17
(4) The distribution of capacity at Jefferies after rediversion will be 44,000 kw steam
electric equivalent and 84,000 kw gas turbine equivalent under the 3,000 cfs/weekly
average flow condition. If the flow at Jefferies is changed, the amount of base load
will be reevaluated pursuant to paragraph 1.4.
(5) The combined energy of G and H has an estimated average annual value of
129,000,000 KWH based on rediversion of all flow except 3000 cfs. Annual
determination of energy and its distribution shall depend on metered generation
distributed pursuant to procedure in paragraph 6.1.
*Monthly settlement statements will be on a prorated basis.
2. POWER VALUES
CAPACITY
R Steam electric base $48/KW (6)
S Gas turbine base $11.85/KW (7)
ENERGY
T Steam electric 10.76 mills/KWH (8)
U Gas turbine 36.8 mills/KWH (9)
3. COMPUTATION
Value of Jefferies (before rediversion) +(AR+BT)
Less value of St. Stephen -(CR+DT)
Less value of production from base -(ER+GT)
capacity at Jefferies after rediversion
Less value of production from added -(FS+HU)
capacity at Jefferies after rediversion ________________
RESULTANT ANNUAL CREDIT =
(6) See page A-4 for derivation. Use fixed charge for capacity over
the service life (30 years). Final value will be fixed in accordance
with paragraph 6.1.
(7) See page A-5 for derivation. Use fixed charge for capacity over
the service life (30 years). Final value will be fixed in accordance
18
with paragraph 6.1.
(8) Furnished monthly by the Authority (See Exhibit C).
(9) Furnished annually by FPC in accordance with paragraph 6.1.
Current value shown.
EXAMPLE (Assuming 10,000,000 KWH generated with 84,000 KW added capacity)
Numerical Assigned
Example Letters
JEFFERIES VALUE (BEFORE REDIVERSION)
Capacity: 128,000 KW at $48 = $ 6,144,000 AR
Energy: 657 million KWH at 10.76 mills = 7,069,320 BT
Total $13,213,320 (AR+BT)
ST. STEPHEN VALUE
Capacity: 84,000 KW at $ 48 = $ 4,032,000 CR
Energy: 418 million KWH at 10.76 mills = 4,497,680 DT
Total = $ 8,529,680 (CR+DT)
JEFFERIES VALUE (AFTER REDIVISION)
Base Capacity: 44,000 KW at $ 48 = $ 2,112,000 ER
Energy with Base Capacity:
119 million KWH at 10.76 mills = 1,280,440 GT
Total = $ 3,392,440 (ER+GT)
Added Capacity: 84,000 KW at $ 11.85 = $ 995,400 FS
Energy with Added Capacity:
10 million KWH at 36.8 mills = 368,000 HU
Total = $ 1,363,400 (FS+HU)
19
SUMMARY CALCULATION
JEFFERIES VALUE (BEFORE REDIVERION) $ 13,213,320 +(AR+BT)
ST. STEPHEN VALUE -8,529,680 -(CR+DT)
JEFFERIES VALUE (AFTER REDIVERSION)
BASE CAPACITY -3,392,440 -(ER+GT)
ADDED CAPACITY -1,363,400 -(FS+HU)
RESULTANT ANNUAL CREDIT = -$ 72,200 (10)
(10) Resultant value of annual energy loss = BT-DT-GT-HU = $ 923,200
Resultant value of annual capacity gain = CR+ER+FS-AR = $ 995,400
Credit is net to Government if capacity gain exceeds energy loss.
Credit is net to Authority if energy loss exceeds capacity gain.
VALUE OF CAPACITY (11)
STEAM ELECTRIC EQUIVALENT
A. Plant Investment $ 350.00/KW $/KW
B. Annual Capacity Cost
1. Fixed Charges Percent
a. Cost of Money to Authority 7.50
b. Depreciation (30 yr sinking fund with
interest at 7.5%) 0.97
c. Interim Replacements 0.35
d. Insurance 0.25
e. Taxes (in lieu of) 0.10
Total Fixed Charges 9.17 $32.10
2. Annual Carry Costs of Fuel Inventory
(9300 BTU/KWH, Plant Factor - .65)
(90 day supply)
11.1 MBTU = $ 1.32/MBTU x 7.85% 1.36
20
3. Fixed Operating Costs
a. Fuel - 4.3 MBTU x $ 1.32/MBTU 5.68
b. Operation and Maintenance = 2.11 x 1.575 3.32
c. Administration (39% of above) 1.29
4. Annual Capacity Cost $43.75
5. Hydropower adjustment at 10% 4.38
6. Total Capacity Cost $48.13
Say $48.00
NOTES
(11) Values shown furnished by FPC (Washington Office) letter dated
4 March 1976. Actual contract value will be established in
accordance with paragraph 6.1.
VALUE OF CAPACITY (11)
GAS TURBINE EQUIVALENT
A. Plant investment $115/KW $/KW
B. Annual Capacity Cost
1. Fixed Charges Percent
a. Cost of Money to Authority 7.50
b. Depreciation
(30 yr sinking fund with
interest at 7.5%) 0.97
c. Interim replacements 0.35
d. Insurance 0.25
e. Taxes (in lieu of) 0.10
TOTAL FIXED CHARGES 9.17 $10.55
21
2. Annual Carry Costs of Fuel Inventory .21
3. Annual Capacity Cost 10.76
4. Hydropower Adjustment at 10% 1.08
5. Total Capacity Cost 11.84
Say $11.85
JEFFERIES HYDRO PLANT
AMOUNT OF ENERGY BEFORE REDIVERSION
The amount of energy that could have been produced by the Jefferies hydro
plant before rediversion shall be the annual summation of computations on a weekly
basis using the following formula:
B KWH/wk = (G+H) KWH/wk +V cfs/wk x 823
B,G,H - See definitions on page A-1
V - Average weekly cfs flow rediverted through St. Stephen,
and/or spilled because of reduction in St. Stephen
capability, provided that the water could have been
used at Jefferies, absent rediversion.
Constant 823 - The figure of 823 equals the product of 168 hours
and 4.9 kw/cfs, the latter ratio being the amount of
net power in kilowatts typically producible at Jefferies
per cfs discharged through the turbines. That figure
varies somewhat (particularly with reservoir levels)
but the yearly average is normally with 1 or 2% up
or down. If the generating efficiency or Jefferies
were to deteriorate significantly in the future as
indicated by a declining ratio, the formula will be
adjusted accordingly.
(R4, tab 2 at 30-35)
46. The contract contains the FERC’s formula for capacity evaluation.
22
Events after Performance Commenced
47. The record indicates that approximately 10 years after executing the contract
representatives of the government may have expressed doubts about the enforceability of
the contract. Notes prepared by the government of a meeting conducted by the parties in
September 1987 indicate the Authority asserted that it considered the contract to be a
legally-binding contract and that the government shared this view (R4, tab 55 at 1337-38).
48. The September 1987 meeting was held in part to discuss a claim
concerning capacity values the Authority had submitted (R4, tab 55 at 1336). The
agenda for the meeting indicates the parties were to discuss revising paragraph 6.1.a,
to “Settle capacity values for first thirty years (refer to claim 9), provide method of
establishing values for last 20 years, and provide for FERC arbitration” (R4, tab 55
at 1340-41). The government subsequently proposed adding the following language to
paragraph 6.1: “The capacity values for the last 20 years will be established following
the same procedures and shall be fixed as of a date 18 months prior to its effective
date” (R4, tab 4 at 115-16).
49. The record reflects that the government maintained this latter position through
the December 1, 1987 meeting between the parties to discuss the then outstanding issues
between the parties (R4, tab 58 at 1359-61). The government proposed using the same
methodology used for establishing the value for the first 30 years to establish the capacity
value for the final 20 years of contract performance, but using October 2013 (18 months
prior to its use in March 2015) cost data regardless of whether the parties used steam
electric or gas turbine as the replacement to compare it to under the FPC valuation
methodology (R4, tab 57 at 1350-51). The record includes notes the government made
following the parties’ December 1, 1987 meeting which were forwarded to the Authority
under date of December 4, 1987 (R4, tab 58 at 1354-58). The government’s notes
indicate with respect to the government’s proposed changes to paragraph 6.1a that the
Authority agreed in concept with the government’s proposal, but that the Authority
“would prefer to address this item at a later date after the capacity value issue is settled”
(id. at 1356 ¶ 8). Although the Authority responded to the government’s meeting notes,
providing its own comments for clarifications, the Authority expressed no opposition or
other comment with regard to the assertion made by the government that it had agreed in
concept to the proposed change to paragraph 6.1, but preferred to address this issue at a
later date (id. at 1352-53). The record includes no evidence that this issue has ever been
revisited by the parties until now.
9 The referenced claim was part of the dispute resolved in South Carolina Public
Service Authority, 89-3 BCA ¶ 21,921; and 91-2 BCA ¶ 23,760 and is not part
of the record in these appeals.
23
50. In July 1987, the Authority learned that the contracting officer, on the
advice of counsel, was questioning whether the government was authorized to make
the annual settlement payments under the contract. The Authority requested a meeting
to discuss this issue.
51. In August 1987, following a meeting with the Authority, the contracting
officer wrote to the Authority, asserting that the contract was a legal binding document
under which appropriate payments would be made by the government.
52. The validity of the contract issue was revisited in December 1987 and the
government again confirmed that it considered the contract to be a valid binding
agreement (R4, tab 58 at 1355 ¶¶ 4-5a.).
53. In view of the government’s questioning of its authority to make annual
payments under the contract, the Authority wrote to the Secretary of the Army, in
February 1988. The Authority requested assurances that in the Secretary’s view the
contract was valid, and that the government was authorized to, and would, make
annual settlement payments thereunder.
54. In April 1988, the Assistant Secretary of the Army, on the advice of the
Corps’ Chief Counsel, advised the Authority that the contract was valid, and that the
Corps would abide by its commitments under the contract.
55. By letter dated September 3, 2015, the government notified the Authority
that the values for the added dependable capacity for the first 30 years of the
contract’s performance period had expired on March 23, 2015. The government’s
letter stated the parties had had many discussions regarding the values to be used for
the remaining period of the contract’s performance, but had been unable to reach an
agreement. The letter also stated the government had determined the values for the
period from March 23 to June 30, 2015 based “on current industry standard rates
noted in the U.S. Energy Administration’s Updated Capital Cost Estimates for Utility
Scale Electricity Generating Plants (April 2013).” The government asserted that use
of this methodology resulted in a credit of $716,874.78, for which the government
requested payment. (R4, tab 5 at 118)
56. As defined by the FPC “dependable capacity” of a hydroelectric plant is the
capacity, which under the most adverse flow conditions of record can be relied upon to
carry system load, provide dependable reserve capacity, and meet firm power
obligations, taking into account seasonal variations and other characteristics of the load
to be supplied (R4, tab 11 at 518). The FPC normally evaluates electric power in terms
of two components, capacity and energy (id. at 517). The capacity value with respect to
hydroelectric plants is derived from a determination of the fixed costs of the selected
alternative source of supply. The energy value is determined from those costs of the
24
alternative, which relate to and vary with the energy output of the alternative plant.
These capacity and energy components or power value are usually expressed in terms
of dollars per kilowatt per year of dependable capacity and mills per kilowatt-hour of
average annual energy. (Id.)
57. Exhibit A initially included the following with respect to “Power Values”:
CAPACITY
R Steam electric base $48/KW (6)
S Gas turbine base $11.85/KW (7)
ENERGY
T Steam electric 10.76 mills/.KWH (8)
U Gas turbine 36.8 mills/KWH (9)
....
(6) See page A-4 for derivation. Use fixed charge for
capacity over the service life (30 years). Final value will
be fixed in accordance with paragraph 6.1.
(7) See page A-5 for derivation. Use fixed charge for
capacity over the service life (30 years). Final value will
be fixed in accordance with paragraph 6.1.
(8) Furnished monthly by the Authority (see Exhibit C).
(9) Furnished annually by FPC in accordance with
paragraph 6.1. Current value shown.
(R4, tab 2 at 41)
58. Pursuant to supplemental agreement No. 6 the parties amended exhibit A.
In addition to reducing the St. Stephen annual energy amount attributable to the agreed
upon capacity for St. Stephen of 84,000 KWH from 418,000,000 KWH to 369,000,000
KWH, the parties revised the “Power Values” as follows:
25
CAPACITY
R Steam electric base $202.25/KW (6)
S Gas turbine base $33.96/KW (7)
ENERGY
T Steam electric VARIES (8)
U Gas turbine VARIES (9)
....
(6) See page A-3 for derivation. Original values
acknowledged by Charles A. Donnell for the Corps and
William C. Mescher for Santee Cooper, in letters dated
November 23, 1984 and December 7, 1984, respectively.
(7) See page A-4 for derivation. Original values
acknowledged by Charles A. Donnell for the Corps and
William C. Mescher for Santee Cooper, in letters dated
November 23, 1984 and December 7, 1984, respectively.
Subsequently revised in decision by Corps of Engineers,
Board of Contract Appeals, Docket #ENG-BCA-5564.
(8) Furnished monthly by the Authority (see Exhibit C).
(9) Furnished monthly by the Authority (see Section 6.1.b).
(R4, tab 2 at 40, 75-85) Review of the pages A-3 to A-5, cited in footnotes (6) and (7)
indicates that the parties significantly revised the underlying values and assumptions
underlying the capacity values corresponding to R (steam electric base) and S (gas
turbine base) (cf. id. at 43-44, 83-84). The parties also revised the value used for D,
the energy attributable to the St. Stephen plant capacity, in the exhibit A credit
computation formula. 10 This value was reduced from the 418,000,000 KWH included
in exhibit A originally, to 369,000,000 KWH set forth in the revised exhibit A. (cf. id.
at 40, 81) The record does not include evidence explaining why the underlying values
10 Value of Jefferies (before rediversion) +(AR+BT) Less value of St. Stephen-(CR+DT)
Less value of production from base capacity at Jefferies after rediversion-(ER+GT)
Less value of production from added capacity at Jefferies after rediversion-(FS+HU)
(R4, tab 2 at 41, 82).
26
and assumptions were changed, how the revised values were derived, or the parties’
negotiations regarding the changes.
59. By letter dated October 2, 2015, the Authority responded to the
government’s September 3, 2015 letter. The Authority advised it disagreed with the
government’s interpretation of the contract and requested a final decision by the
contracting officer determining that no further payment was owed by the Authority for
added capacity beyond March 23, 2015. (R4, tab 3 at 99-102)
60. By letter dated February 2, 2016, the contracting officer issued a final
decision (R4, tab 1 at 1-10). In the final decision the contracting officer advised the
Authority that it was misinterpreting the contract and that the Authority was obligated
to credit the government with the value of the additional capacity provided by the
St. Stephen plant for another 20 years (id. at 8-9).
61. The Authority timely filed its notice of appeal from the contracting
officer’s final decision on February 26, 2016.
62. The record includes evidence that the St. Stephen plant has continued to
produce electric energy for the Authority’s benefit as recently as May 2017 (R4, tab 59
at 1365-67).
Jurisdiction Issue
63. The Authority pled jurisdiction arises from a timely notice of appeal from a
contracting officer’s final decision denying a certified claim submitted under the contract,
which the government mostly admitted (compl. ¶¶ 3-5; answer ¶¶ 3-5). No further facts
were pleaded by the parties with respect to jurisdiction and the parties did not specifically
plead that jurisdiction exists under the Contract Disputes Act, 41 U.S.C. §§ 7101-7109
(CDA).
64. The contract was entered into in 1976, two years before the CDA was enacted
(finding 38). The CDA states that it applies to any express or implied contract entered
into by an executive agency for (1) the procurement of property, other than real property
in being; (2) the procurement of services; (3) the procurement of construction, alteration,
repair or maintenance of real property; or (4) the disposal of real property. 41 U.S.C.
§ 7102.
65. In supplemental agreement No. 8, the Authority agreed to replace the analog
electric actuators used in the operation of the government’s St. Stephen’s plant with
digital controls, for which services the government paid the Authority (R4, tab 2
at 87-89). The Authority provided additional services to the government for which it
27
was compensated pursuant to supplemental agreement Nos. 4 and 9 as well (id.
at 67-72, 90-92).
66. Although not specifically referred to as modifications to the contract, the
record indicates the parties treated the supplemental agreements as modifications to
the contract and not as separate, indivisible contract agreements. Supplemental
agreement No. 6 expressly deletes certain provisions of the original contract and
replaces them with revised provisions (R4, tab 2 at 75-80). Supplemental agreement
Nos. 1 and 2 expressly state they are an amendment to the original contract and also
delete and add provisions to the original contract (id. at 52, 57).
DISCUSSION
The Board’s Jurisdiction to Consider these Appeals
The contract involved in these appeals is relatively unique. It predates the
enactment of the CDA in 1978, which at this point in time, 40 years later, is a
relatively unusual circumstance to encounter. This is due to the fact that the contract
performance period is 50 years, measured from commencement of the operation of the
government’s St. Stephen plant, an event which did not occur until almost 10 years
after the contract was executed. This is another factor that sets it apart from most
government contracts. The nature of the contract, which is to settle a dispute between
the parties regarding the loss of value to the Authority from the government’s
interference with the operation of its Jefferies plant, and value added through the
added St. Stephen plant is also unusual. The concept involved in the contract, to settle
this dispute and keep the Authority whole, is relatively simple, but its execution,
particularly the calculation of the values to be applied to each of the credits the parties
are responsible for under the agreement are somewhat complex and indefinite, in the
sense that the values were not set at the time the contract was entered into, are
somewhat subjective and are also subject to change depending on several variables.
For example, the flow of water through the Jefferies plant and the power produced
thereby, the power produced at St. Stephen and how much of it is taken by the
Authority, and the energy values to be obtained annually from the FPC and monthly
from the Authority. (Findings 20, 25-28, 30, 40, 43, 45, section 6.1 (a)-(c))
Additionally, the record includes evidence that the Authority was reluctant to agree to
extend the energy value for the gas turbines established and used in the methodology
set forth in the contract (exhibit A) for the past 30 years due to the possibility that the
assumptions those values were based upon in the 1970s, when the agreement was
negotiated, would no longer hold true after 30 years (findings 27, 32).
The record indicates that representatives of the government in the past have
asserted the contract might not be valid (findings 47, 50, 52-54). The basis for these
past assertions that the contract might not be valid are not set forth in the record in this
28
appeal. Although neither party is currently contesting the validity of the contract,
given the unique nature of the contract, coupled with the indefinite nature of the value
of the credits to be paid, we deem it prudent to address these issues because our
subject matter jurisdiction under the CDA is ultimately dependent on the existence of a
valid contract. Abdul Khabir Construction Co., ASBCA No. 61155, 18-1 BCA
¶ 37,027 at 180,296 citing Ryste & Ricas, Inc., ASBCA No. 54514, 06-1 BCA
¶ 33,124 at 164,146 aff’d. Ryste & Ricas, Inc. v. Harvey, 477 F.3d 1337 (Fed. Cir.
2007). See also Atlas International Trading Corporation, ASBCA No. 59091, 15-1
BCA ¶ 35,830 at 175,198; Dongbuk R&U Engineering Co., ASBCA No. 58300,
13 BCA ¶ 35,389 at 173,639 (motion for summary judgment granted based on lack of
jurisdiction due to fraudulently obtained contract being void ab initio).
Under the CDA we have jurisdiction to “decide any appeal from a contracting
officer of any executive agency relative to a contract made by that agency.” 41 U.S.C.
§ 7105(e)(1)(A). However not all contracts are encompassed by the CDA. The CDA
covers express and implied contracts made by an executive agency for: (1) the
procurement of property, other than real property in being; (2) the procurement of
services; (3) the procurement of construction, alteration, repair or maintenance of real
property; or (4) the disposal of personal property. Id. § 7102 (a). Thus two potential
jurisdictional pitfalls present themselves in the circumstances of this case; (1) is the
contract valid, despite its indefinite nature and (2) is it a type that is covered by the
CDA?
A. The Contract’s Validity
The Federal Circuit has stated that the elements of a valid contract are:
(1) Mutuality of intent, (2) consideration, (3) an
unambiguous offer and acceptance, and (4) actual authority
on the part of the government’s representative to bind the
government in contract.
Kam-Almaz v. United States, 682 F.3d 1364, 1368 (Fed. Cir. 2012); Suess v. United
States, 535 F.3d 1348, 1359 (Fed. Cir. 2008); Flexfab, L.L.C. v. United States,
424 F.3d 1254, 1265 (Fed. Cir. 2005). There is nothing in the record that suggests
these requirements have not been met. The lengthy period of negotiations leading up
to the contract, followed by the contract’s execution, express affirmation of the
contract’s validity by the parties 10 years into the performance period and continued
performance to date, are all evidence of an intent to contract. The respective credits to
be paid and other obligations of the parties set forth in the agreement satisfy the
requirement for consideration and there is no reason to doubt the authority of the
representative of the parties who signed the agreement to bind the parties in contract.
29
While the terms are unambiguously stated, they do include a degree of
indefiniteness or uncertainty, which in some circumstances has been recognized as a
basis for ruling contracts invalid. See Homestead Golf Club, Inc. v. Pride Stables,
224 F.3d 1195 (10th Cir. 2000) for an example of a contract found to be too indefinite
to be enforceable.
The Restatement (Second) of Contracts § 33 states:
(1) Even though a manifestation of intention is intended to
be understood as an offer, it cannot be accepted so as to
form a contract unless the terms of the contract are
reasonably certain.
(2) The terms of a contract are reasonably certain if they
provide a basis for determining the existence of a breach
and for giving an appropriate remedy.
(3) The fact that one or more terms of a proposed bargain
are left open or uncertain may show that a manifestation of
intention is not intended to be understood as an offer or as
an acceptance.
and the Restatement (Second) of Contracts, § 34 states:
(1) The terms of a contract may be reasonably certain even
though it empowers one or both parties to make a selection
of terms in the course of performance.
(2) Part performance under an agreement may remove
uncertainty and establish that a contract enforceable as a
bargain has been formed.
(3) Action in reliance on an agreement may make a
contractual remedy appropriate even though uncertainty is
not removed.
These appeals bears some resemblance to Kenai v. Ferguson, 732 P.2d 184 (S. Ct.
Alaska 1987), where an agreement was held to be valid and enforceable despite the
parties inability to agree on payments to be made in the future under a 55-year lease
agreement, which included an indefinite provision for renegotiating the lease payments
at five year intervals. The provision at issue in Kenai stated:
In the event this lease is for a term in excess of five years,
the amount of rents or fees specified herein shall be subject
30
to re-negotiation for increase or decrease at intervals of
EVERY FIVE Years from the 1st day of July preceding the
effective date of this lease.
The Kenai renegotiation provision is indefinite because it includes no specified
amount for future payments, or even any methodology for calculating same. It is
merely an agreement to agree in the future. The court held the agreement to be
enforceable and that the intent of the parties, which it discerned from the entirety of
the agreement, was for the payment of a reasonable fair market rent. The court stated
a court could determine what a reasonable fair market rent was if the parties were not
able to come to an agreement. See also Cobble Hill Nursing Home, Inc. v. Henry
& Warren Corp., 548 N.E.2d 203, 206 (N.Y. 1989) (citations omitted) (noting that “a
price term is not necessarily indefinite because the agreement . . . leaves fixing the
amount for the future”).
In these appeals, although the amounts of the credits are indefinite and the
assumptions underlying them appear to be both subjective and subject to variation
depending at least in part on when they are made, the contract includes a methodology
set out in exhibits A-D for calculating the values of the credits due under the contract,
which the parties agreed to and have used for the past 30 years; even making
significant revision thereto, presumably to maintain the equitable nature of the
agreement, although the record includes no evidence to explain how the parties agreed
upon the revisions made to the valuation methodology (findings 20, 25-26, 28, 31-37,
45, 57-58). Due to this pricing methodology we find the contract is sufficiently
definite to be valid and enforceable, particularly in light of the significant performance
that has occurred and the parties’ respective reliance upon same over the 41 years
since the contract was executed. Restatement (Second) of Contracts § 34(2), 3). See
also Premier Exhibitions, Inc. v. Marmargar, Inc., 908 F. Supp. 2d 741 (ED Va.
2012).
B. The Type of Contract Involved
The contract includes services provided to the government, which provides
subject matter jurisdiction under the CDA, as we previously held in South Carolina
Public Service Authority, ASBCA No. 57826, 13 BCA ¶ 35,239 at 173,008-09. These
services include regulating the flow of water into the Cooper River, purchasing the
electricity produced from the government’s St. Stephen plant via the credit system
established in the contract, maintaining and operating the cooling water system,
maintaining the transmission lines from the St. Stephen plant and other government
owned equipment, and operating the St. Stephen plant remotely (finding 43). In
addition to regulating the flow of water in the Cooper River, etc., the Authority has
provided other services under the contract’s modifications. For example the Authority
replaced analog control equipment with digital controls pursuant to supplemental
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agreement No. 8 and provided other services under supplemental agreements Nos. 4
and 9 (finding 65). Accordingly, the contract, which includes the provision of
significant services to the government, is covered by the CDA and thus confers subject
matter jurisdiction.
The Dispute
The government’s position is that the contract requires the Authority to
continue paying the credit for the value of the additional capacity provided by the
St Stephen plant for the full 50-year performance period covered by the contract (gov’t
br. at 18-20). The Authority maintains the parties have agreed to make payment for
the additional capacity for only the first 30 years of the contract (app. br. at 37-39). In
this regard the Authority contends: “Section 6.1 and 6.1.a specify that the value of
capacity ‘shall be computed in accordance with the procedure shown in Exhibit A’ and
that the values of capacity ‘will prevail for a 30-year service life’” (app. br. at 39 citing
R4, tab 2 at 24-26). There is no provision in section 2 (Obligations of the Authority),
or section 6 (Settlement), or exhibit A which specifically requires (or obligates)
payment after 30 years or sets forth any methodology or value for payment after
expiration of the 30-year payment period (id. at 39).
The government asserted its right to receive payment for the value of the
additional capacity after the completion of the first 30 years of performance
(finding 55). The Authority rejected this interpretation of the contract and requested a
final decision from the contracting officer (finding 59). The contracting officer issued
a final decision disagreeing with the Authority’s position, which the Authority timely
appealed (findings 60-61). We are thus asked to interpret the contract.
We begin, as we must always do when faced with issues of contract interpretation,
with the language of the contract. TEG-Paradigm Environmental, Inc. v. United States,
465 F.3d 1329, 1338 (Fed. Cir. 2006). When the language is unambiguous it must be
given its “plain and ordinary” meaning and we may not look to extrinsic evidence to
interpret the language. Id. Although extrinsic evidence may not be used to interpret an
unambiguous contract provision, we may consider it to confirm that the parties intended
for the language to have its plain and ordinary meaning. Id. (citing Coast Fed. Bank, FSB
v. United States, 323 F.3d 1035, 1040 (Fed. Cir. 2003) (en banc)). Any issue of contract
interpretation requires consideration of the contract as a whole to effectuate its spirit,
giving reasonable meaning to all of the contract’s terms. Hercules, Inc. v. United States,
292 F.3d 1378, 1381 (Fed. Cir. 2002).
Neither party asserts the language of the contract is ambiguous, they simply
draw different conclusions as to what the language means. We agree the language is
clear and without ambiguity. Although the parties have different interpretations of the
contract’s language, we do not find the language to be ambiguous because we find the
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Authority’s interpretation to be unreasonable. In order to be determined to be
reasonable, the interpretation must be logically consistent with the contract and the
parties’ objectively ascertainable intentions. ECCI-C Metag, JV, ASBCA No. 59031,
15-1 BCA ¶ 36,145 at 176,418. The Authority argues, relying upon the principle of
interpretation referred to as expressio unius est exclusio alterius, that the failure of the
agreement to expressly state that payments for the value of the additional capacity will
be required beyond the 30-year service life period set forth in section 6.1 of the
contract, coupled with no similarly stated period with respect to the energy credits due
from the government for the reduced capacity of the Authority’s Jefferies plant,
presumes there is no requirement for capacity payments to be made after thirty years
(app. br. at 39). See also SYMVONICS, Inc., ASBCA Nos. 60355, 60612, 17-1 BCA
¶ 36,790. This interpretation is unreasonable because it is not logically consistent with
the contract and is contrary to the spirit of the agreement when all of its provisions are
considered.
The contract clearly and unambiguously requires the Authority to continue
paying for the benefit of the added capacity it receives from the St. Stephen plant upon
the plant becoming operational through the full 50 years of the contract’s performance
period. This begins with the recital that states that the parties desire that the
government be compensated for the project’s benefits to the Authority. (Finding 38)
Next, paragraph 3.2 of the contract states that the obligation to pay for the power
delivered commences upon the operation of the St. Stephen plant and continues for
50 years (finding 44). The “Settlement” provision of the contract, paragraph 6, which
sets forth the various credits to be calculated and paid for under the contract states that
beginning with the date of commercial operation and continuing for each succeeding
contract year, there will be a cash settlement reflecting the net value of the credits to
be paid by the parties, including the credit for the increased available capacity. The
“Payment” provision of the contract, paragraph 7, requires that the payments due
under the contract be made until title to the St. Stephen plant passes to the Authority,
an event not scheduled to occur until the 50-year performance period has been
completed. 11 Finally, footnotes 6 and 7 to exhibit A indicate that a fixed charge for the
capacity value over the 30-year service life will be followed by a “final” value fixed in
accordance with paragraph 6.1. (Finding 45) Nothing in this contract language
supports the argument advanced by the Authority that the contract obligates it to pay
for the benefit of the capacity added by the St. Stephen plant for only 30 years.
The Authority does not argue that it is no longer receiving any benefit from the
additional capacity of the St. Stephen plant, nor does the record include any evidence
that this benefit is no longer being received by the Authority. The evidence in the
11 Title transfer can be accelerated but neither party has argued this has occurred
(findings 42, 44). Nor is there any evidence of this having occurred in the
record.
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record is that the Authority has continued to receive the benefit of the additional
capacity provided by the St. Stephen plant, at least as recently as May 2017.
(Finding 62) Accordingly, pursuant to the plain language of the contract, the Authority
must continue to pay for this benefit in accordance with the methodology set forth in
exhibit A pursuant to paragraph 6.1 of the contract, with current values obtained from
FERC for the sub-components of the computation formula where needed. The
Authority does suggest that the parties intended to amortize and pay for over 30 years,
the 50-year value of the benefit the Authority was to receive from the additional
capacity of the St. Stephen plant, but this contention is contrary to the language of the
contract (app. br. at 43). Nor is there any evidence in the record to support this
contention.
The record includes extrinsic evidence that confirms the plain language of the
contract is what the parties intended. The record indicates that the concept, that there be
a cash settlement, of the various credits to be paid, made at the end of each year after the
St. Stephen plant became operational and that this procedure be in effect for 50 years,
may have originated with the Authority. (Finding 10) The record includes evidence that
the Authority viewed fixing the value for a key component of the exhibit A formula for
the 50-year life of the agreement as being difficult to do beyond 30 years (finding 27).
This tends to support the view that the contract only fixed the values underlying the net
credit settlement system in the contract for the first 30 years of the agreement. The initial
30-year period that was spelled out in the contract corresponds to the FPC methodology
for evaluating hydropower projects, which is based on an evaluation of an alternate
thermal plant, which have 30-year service lives, adjusted for the greater operating
efficiencies of hydro plants and service lives of 50 to 100 years (findings 8, 32, 34). This
FPC methodology was incorporated into the contract (finding 46). The parties met
several years after performance had commenced, in part to discuss the methodology to be
used to settle the capacity values for the last 20 years of the contract’s performance
period, the issue that is raised in this appeal (findings 48-49). The government proposed
using the same methodology used for the first 30 years, but waiting until 18 months prior
to the effective date to obtain the current values from the FPC, similar to what the parties
had done with respect to the first 30 years of the performance period (findings 37(e),
48-49). The record includes evidence the Authority agreed with this proposal, but wished
to postpone decision on this issue until after the then pending dispute regarding the
capacity value, the subject of the appeal in South Carolina Public Service Authority, 89-3
BCA ¶ 21,921, and 91-2 BCA ¶ 23,760 was resolved (findings 48-49).
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CONCLUSION
For the reasons set forth above, we find the language of the contract clearly and
unambiguously requires the Authority to continue to make payment for the benefit
received of the additional capacity provided by the St. Stephen power plant. These
appeals are denied and remanded to the parties for negotiation of the value of the
additional capacity for the final 20 years of the contract performance period in
accordance with the provisions of paragraphs 3, 6, and 7 of the contract.
Dated: July 22, 2020
CHRISTOPHER M. MCNULTY
Administrative Judge
Armed Services Board
of Contract Appeals
I concur in result (see separate opinion) I concur in result (see separate opinion)
RICHARD SHACKLEFORD J. REID PROUTY
Administrative Judge Administrative Judge
Acting Chairman Vice Chairman
Armed Services Board Armed Services Board
of Contract Appeals of Contract Appeals
35
OPINION BY JUDGE SHACKLEFORD AND JUDGE PROUTY
CONCURRING IN RESULT
We concur in result because we agree with Judge McNulty regarding the
Authority’s obligations under this contract. We do not, however, necessarily agree
with all of the other analyses in his opinion. Moreover, we find the section regarding
the applicability of the Contract Disputes Act to this contract to unnecessarily revisit a
matter previously decided (with the same result) in a prior appeal. See South Carolina
Public Service Authority, ASBCA No. 57826, 13 BCA ¶ 35,239 at 173,010.
Dated: July 22, 2020
RICHARD SHACKLEFORD J. REID PROUTY
Administrative Judge Administrative Judge
Acting Chairman Vice Chairman
Armed Services Board Armed Services Board
of Contract Appeals of Contract Appeals
I certify that the foregoing is a true copy of the Opinion and Decision of the
Armed Services Board of Contract Appeals in ASBCA Nos. 60460, 60616, Appeals of
South Carolina Public Service Authority, rendered in conformance with the Board’s
Charter.
Dated: July 22, 2020
PAULLA K. GATES-LEWIS
Recorder, Armed Services
Board of Contract Appeals
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