Public Service Co. v. State Corp. Com'n

Full title: PUBLIC SERVICE COMPANY OF OKLAHOMA, Oklahoma Industrial Energy Consumers…

Court: Supreme Court of Oklahoma

Date published: Jul 13, 2005

2005 OK 47 (Okla. 2005)

2005 OK 47

Opinion

Nos. 100,123, 100,152.

June 21, 2005. As Corrected July 13, 2005.

On Appeal from the Oklahoma Corporation Commission.

¶ 0 Applicant sought from the Oklahoma Corporation Commission an order approving the terms of an agreement for the sale to respondent of applicant's net electrical output, including the determination of purchased power rates for such sales. The Oklahoma Corporation Commission, one commissioner dissenting, issued an order prescribing the final terms of a power sales agreement, establishing purchased power rates, and directing that the agreement be executed. Respondent and intervener, Oklahoma Industrial Energy Consumers, appealed in Cause No. 100,123. The Attorney General appealed in Cause No. 100,152. The appeals stand consolidated under surviving Cause No. 100,123, which is retained for this court's disposition by a single opinion.

ORDER AFFIRMED IN PART AND VACATED IN PART; PROCEEDING REMANDED WITH DIRECTIONS TO CONDUCT FURTHER INQUIRY AND MAKE ADDITIONAL FINDINGS.

Jack P. Fite and Jay M. Galt, White, Coffey, Galt Fite, P.C., Oklahoma City, OK, and Marc E. Lewis, American Electric Power, Ft. Wayne, Indiana, for Appellant, Public Service Company of Oklahoma.

Graydon Dean Luthey, Jr., Thomas P. Schroedter, James D. Satrom, and Sharon T. Thomas, Hall, Estill, Hardwick, Gable, Golden Nelson, P.C., Oklahoma City, OK and Tulsa, OK, for Appellant, Oklahoma Industrial Energy Consumers.

W.A. Drew Edmondson, Attorney General, State of Oklahoma and William L. Humes, Assistant Attorney General, State of Oklahoma, Oklahoma City, OK, for Appellant, Office of the Attorney General.

Ben Jackson and Michele O'Neill Craig, Oklahoma Corporation Commission, Oklahoma City, OK, for Appellee, Oklahoma Corporation Commission.

Kenneth N. McKinney, McKinney Stringer, P.C., Oklahoma City, OK, Connie M. Bryan, Mitzner Rubenstein Bryan McCormick Pitts, P.L.L.C., Edmond, OK, Deborah R. (Morgan) Thompson, Lawton Cogeneration, L.L.C., Oklahoma City, OK, and Cheryl A. Vaught, Vaught Conner, P.L.L.C., Oklahoma City, OK, for Appellee, Lawton Cogeneration, L.L.C.

Ronald D. Cates, City Attorney, City of Owasso, OK, Martha Rupp Carter, City Attorney, and Robert R. Edmiston, Assistant City Attorney, City of Tulsa, OK, and Michael R. Vanderburg, City Attorney, City of Broken Arrow, OK, for amici curiae, Cities of Owasso, Tulsa, and Broken Arrow.

Mark D. Christiansen, Crowe Dunlevy, Oklahoma City, OK, for amicus curiae, Lawton Ft. Sill Chamber of Commerce and Industry.¹

1 Identified herein are those counsel for the parties and amici whose names appear on their respective briefs.

OPALA, J.

¶ 1 Two dispositive questions are presented for review: (1) Is the Corporation Commission's order sustained by substantial evidence and (2) Does it conform to the requirements of federal and state law? These questions must be answered for each of the following Commission decisions: (a) determining that applicant incurred a legally enforceable obligation to deliver power to respondent, thereby obligating the Corporation Commission to set purchased power rates for the term of the proposed power sales agreement; (b) rejecting a market-based approach to the calculation of avoided costs; (c) setting an avoided capacity rate; (d) setting an avoided energy rate; (e) omitting from the power sales agreement a provision corresponding to the terms of 18 C.F.R. § 292.304(f); (f) setting a twenty-year term for the power sales agreement; (g) setting terms and conditions for the power sales agreement; and (h) altering the power sales agreement after the record was closed. We affirm the Commission's decisions as to the issues raised in parts (a), (b), (c), (e), (f), and (h), but because the Commission failed to treat adequately issues material to the decision in parts (d) and (g), we vacate the order with regard to those parts. The Commission is directed to conduct further inquiry and make additional findings with respect to the issues raised in part (d) of this pronouncement and to adjust resolutions affirmed herein only if and to the extent necessary to accommodate the Commission's post-remand findings and conclusions with respect to the issues discussed in part (d).

I ANATOMY OF THE PROCEEDINGS

¶ 2 Lawton Cogeneration, L.L.C. ("Lawton" or "cogenerator") is a limited liability company organized for the purpose of developing a cogeneration facility to be located in the Lawton Industrial Park in Lawton, Oklahoma. A cogeneration facility is a plant that produces two or more usable forms of energy, one of which is electricity.² Lawton has been certified pursuant to the provisions of the Public Utility Regulatory Policies Act of 1978 ("PURPA")³ as a qualifying cogeneration facility ("QF"), i.e. a cogeneration facility which meets certain standards for size, fuel use, and fuel efficiency and which is owned by a person not primarily engaged in the generation or sale of electric power.⁴ Lawton proposes to produce electricity and steam. It intends to sell the steam to two companies in Lawton that use steam in their operations.

2 See the provisions of 16 U.S.C. § 796, which state in pertinent part:

"The words defined in this section shall have the following meanings for purposes of this chapter, to wit:

(18)(A) `cogeneration facility' means a facility which produces —

(i) electric energy, and

(ii) steam or forms of useful energy (such as heat) which are used for industrial, commercial, heating, or cooling purposes; . . ."

3 See the provisions of 16 U.S.C. §§ 796 and 824a-3 et seq.

4 See the provisions of 16 U.S.C. § 796, which state in pertinent part:

"The words defined in this section shall have the following meanings for purposes of this chapter, to wit:

(18)(B) `qualifying cogeneration facility' means a cogeneration facility which —

(i) the Commission [the Federal Energy Regulatory Commission] determines, by rule, meets such requirements (including requirements respecting minimum size, fuel use, and fuel efficiency) as the Commission may, by rule, prescribe; and

(ii) is owned by a person not primarily engaged in the generation or sale of electric power (other than electric power solely from cogeneration facilities or small power production facilities); . . ."

¶ 3 On 23 January 2002 Lawton filed an application with the Oklahoma Corporation Commission ("Commission") pursuant to the provisions of PURPA, for an order directing AEP-Public Service Company of Oklahoma ("AEP", "AEP-PSO", "PSO" or "the utility")⁵ to purchase electric power generated by Lawton, setting purchased power rates, and approving the terms of a contract between the cogenerator and the utility. PSO moved on 29 March 2002 to dismiss the application, arguing that Lawton had not incurred a legally enforceable obligation to deliver power to PSO, a pre-condition under PURPA for obtaining a state regulatory agency's order setting purchased power rates for the term of a power sales agreement. An administrative law judge ("ALJ") heard oral argument on the motion and, upon finding that Lawton had not created a legally enforceable obligation to deliver power to PSO, recommended that the application be dismissed without prejudice. Lawton appealed. The Commission en banc ruled on 26 July 2002 that oral argument provided an inadequate evidentiary basis for deciding the issue raised in PSO's motion to dismiss and remanded the cause to the ALJ to conduct a full evidentiary hearing.

5 PSO is an electric utility providing power in eastern and southwestern Oklahoma. It is wholly owned by American Electric Power, a company that operates electric utilities in a number of states.

¶ 4 After an additional legal challenge to the application's sufficiency failed to secure its dismissal and after much wrangling over the procedural schedule and discovery issues, the cause was finally scheduled to be heard by the ALJ on 21 January 2003. Shortly before the hearing date arrived, the parties agreed to forego a hearing, submit their evidence to the ALJ by filing written testimony accompanied by exhibits, and waive cross examination of witnesses regarding their filed testimony.⁶ As ordered by the Commission, the record was opened on 21 January 2003 for public comment. It was again opened on 30 January 2003 for the identification of exhibits, for their placement into the record, and for the oral announcement of the ALJ's recommendation. The ALJ issued a written Report and Recommendation on 14 February 2003, concluding that Lawton had created a legally enforceable obligation as of the date it had tendered to PSO a proposed power sales agreement and recommending a method for determining the rates PSO should pay Lawton for the purchase of the latter's electrical output.

6 Lawton filed direct, rebuttal, and surrebuttal testimony. PSO filed responsive, rebuttal, and surrebuttal testimony. The Attorney General's office and the Commission Staff filed responsive testimony.

¶ 5 Lawton, PSO, and the Oklahoma Industrial Energy Consumers ("OIEC"), a trade organization that had earlier intervened in the cause,⁷ appealed to the Commission. The Commission en banc heard oral arguments on 11 March 2003. It then issued an order dated 28 April 2003, in which it reopened sua sponte the record, set a hearing date before the Commission en banc, identified witnesses whose testimony the commissioners wanted to hear, and allowed the parties to request additional witnesses be permitted to testify.

7 OIEC is a trade organization composed of companies engaged in processing and manufacturing industries. Its members receive electric service from PSO and are hence PSO ratepayers.

¶ 6 The Commission heard testimony on 20, 21 and 22 May 2003. On 26 November 2003, the Commission, two commissioners concurring, issued the order that is the subject of this appeal, finding that Lawton established a legally enforceable obligation no later than 26 September 2002⁸ and was hence entitled to a determination — as of that date — of the rates PSO is to pay for Lawton's electrical power.⁹ The Commission then proceeded to make that determination and to order the parties, including both AEP and PSO, to execute the power sales agreement tendered by Lawton, as revised by the Commission.

8 This date corresponds to the date on which Lawton filed its direct testimony detailing the development of the Lawton facility since its inception.

9 Order No. 483091 in Cause No. PUD 200200038. The dissenting commissioner did not disagree with the majority's finding that a legally enforceable obligation had arisen.

¶ 7 PSO appealed and OIEC filed a "cross-appeal" under the same docket number.¹⁰ The Attorney General brought a separate appeal. The court consolidated the separate appeals under surviving Cause No. 100,123 and then granted a motion to retain the consolidated appeal. The City of Owasso, Oklahoma, and the City of Tulsa, Oklahoma, requested leave to file briefs amicus curiae in support of PSO and were granted leave to file a combined brief. The Lawton Fort Sill Chamber of Commerce and Industry requested and was granted leave to file a brief amicus curiae in support of Lawton. The City of Broken Arrow requested and was granted leave to join in the amicus brief to be filed by the cities of Tulsa and Owasso.

10 OIEC designated its appeal as a cross-appeal. A true cross-appeal is one brought by an appellee in the original appeal who seeks relief against another appellee only. A counter-appeal is one brought by an appellee who invokes the court's appellate jurisdiction for relief against the original appellant. The status of original appellant is conferred on the aggrieved party who wins the race to the clerk's office to file the first petition-in-error. Spears v. Preble, 1983 OK 8, ¶ 4, 661 P.2d 1337, 1344 (Opala, J., concurring in result.). Having filed the first petition-in-error in this case, PSO is the original appellant. Its petition-in-error did not confer any appellate-party status on OIEC. OIEC's petition-in-error would hence more correctly be termed a co-appeal.

II STANDARD OF REVIEW

¶ 8 The power to review Commission decisions is vested in this court by the Oklahoma Constitution, Art. 9, § 20.¹¹ That provision fashions two standards of review — a de novo standard for appeals based on alleged violations of constitutional rights and a more deferential standard for all other appeals.¹² Today's pronouncement employs the more circumscribed standard, in which review extends no further than determining whether the Commission adequately performed its duty under federal and state law and whether the Commission's findings are supported by substantial evidence.¹³ The term "substantial evidence" means "more than a mere scintilla"¹⁴ but may be something less than the weight of the evidence.¹⁵ It is proof that possesses something of real and relevant consequence and that carries with it a fitness to induce conviction.¹⁶ In testing evidence for substantiality, a reviewing court must consider not only the evidence supporting the decision, but also the evidence which detracts from it.¹⁷ In cases before the Commission involving the testimony of expert witnesses, a factual finding is supported by substantial evidence when the evidence is offered by a qualified expert who has a rational basis for his views, even if other experts disagree.¹⁸ It is for the Commission to weigh conflicting expert testimony. Because Commission decisions often involve complex issues of economics, accounting, engineering, and other special knowledge, a presumption of correctness accompanies the Commission's findings in matters it frequently adjudicates and in which it possesses expertise.¹⁹

11 The pertinent terms of the Oklahoma Constitution, Art. 9, § 20, provide:

"From any action of the Corporation Commission prescribing rates, charges, services, practices, rules or regulations of any public utility or public service corporation, or any individual, person, firm, corporation, receiver or trustee engaged in the public utility business, an appeal may be taken by any party affected, or by any person deeming himself aggrieved by any such action, or by the State, directly to the Supreme Court of the State of Oklahoma, in the manner and in the same time in which appeals may be taken to the Supreme Court from the District Courts, except that such an appeal shall be of right, . . ."

12 Id. Its pertinent provisions are:

"The Supreme Court's review of appealable orders of the Corporation Commission shall be judicial only, and in all appeals involving an asserted violation of any right of the parties under the Constitution of the United States of the Constitution of the State of Oklahoma, the Court shall exercise its own independent judgment as to both the law and the facts. In all other appeals from orders of the Corporation Commission the review by the Supreme Court shall not extend further than to determine whether the Commission has regularly pursued its authority, and whether the findings and conclusions of the Commission are sustained by the law and substantial evidence. Upon review, the Supreme Court shall enter judgment, either affirming or reversing the order of the Commission appealed from."

13 Smith Cogeneration Management, Inc. v. Corp. Comm'n, 1993 OK 147, ¶ 9, 863 P.2d 1227, 1232; Forest Oil Corp. v. Corp. Comm'n, 1990 OK 58, ¶ 32, 807 P.2d 774, 788.

14 Mustang Production Co. v. Corp. Comm'n, 1989 OK 35, ¶ 14, 771 P.2d 201, 204.

15 Teleco, Inc. v. Corp. Comm'n, 1982 OK 124, ¶ 6, 653 P.2d 209, 212. The United States Supreme Court has described it as "enough to justify, if the trial were to a jury, a refusal to direct a verdict when the conclusion sought to be drawn from it is one of fact for the jury." National Labor Relations Board v. Columbian Enameling Stamping Co., 306 U.S. 292, 300, 59 S.Ct. 501, 505, 83 L.Ed. 660 (1939).

16 Tecumseh Gas System, Inc. v. State, 1977 OK 20, ¶ 22, 565 P.2d 356, 359. As the United States Supreme Court noted, substantial evidence "means such relevant evidence as a reasonable mind might accept as adequate to support a conclusion." Richardson v. Perales, 402 U.S. 389, 401, 91 S.Ct. 1420, 28 L.Ed.2d 842 (1971).

17 Marathon Oil Co. v. Corp. Comm'n, 1994 OK 28, ¶ 18, 910 P.2d 966, 970; El Paso Natural Gas Co. v. Corp. Comm'n, 1981 OK 150, ¶ 9, 640 P.2d 1336, 1338-39 (adopting the view expressed by the United States Supreme Court in Universal Camera Corp. v. Nat'l Labor Relations Bd., 340 U.S. 474, 488, 71 S.Ct. 456, 464, 95 L.Ed. 456 (1951) that "the substantiality of evidence must take into account whatever in the record fairly detracts from its weight."). For an account of the development of the substantial evidence test, see Larry Derryberry and Patrick D. Shore, " Public Utility Regulation in Oklahoma: An Historical Perspective," 19 Oklahoma City University Law Review 465 (Fall 1994).

18 Consumers Power Co. v. Public Service Comm'n, 189 Mich.App. 151, 472 N.W.2d 77, 92 (1991).

19 MCI Telecommunications Corp. v. State, 1991 OK 86, ¶ 22, 823 P.2d 351, 358; Turpen v. Okla. Corp. Comm'n, 1988 OK 126, ¶ 16, 769 P.2d 1309, 1317.

III PURPA

¶ 9 The United States Congress enacted PURPA in 1978 in response to the nationwide energy crisis of the 1970's. Its goal was to reduce the country's dependence on imported fuels by encouraging the addition of cogeneration and small power production facilities to the nation's electrical generating system. Cogeneration facilities are desirable because they are able to produce more than one form of energy at the same time with less fuel than it would take to produce them separately.²⁰ PURPA requires electric utilities to purchase all electric energy made available by cogenerators at rates that (a) are just and reasonable to electric consumers, (b) do not discriminate against QFs, and (c) do not exceed "the incremental cost to the electric utility of alternative electric energy."²¹ The incremental cost to the utility means the amount it would cost the utility to generate or purchase the electric energy but for the purchase from the cogenerator.²² The incremental cost standard is intended to leave ratepayers economically indifferent to the source of a utility's energy by ensuring that the cost to the utility of purchasing power from a QF does not exceed the cost the utility would incur in the absence of the QF purchase.²³ The Federal Energy Regulatory Commission ("FERC") in 1980 issued rules implementing PURPA,²⁴ in which it adopted what it called a utility's "avoided costs" as the standard for implementation of the incremental cost requirement.²⁵

20 Snow Mountain Pine Co. v. Maudlin, 84 Or.App. 590, 734 P.2d 1366, 1367 (1987). See 45 Fed.Reg. 12215 (1980).

21 The provisions of 16 U.S.C. § 824a-3 provide in pertinent part:

"(a) Cogeneration and small power production rules

"Not later than 1 year after November 9, 1978, the Commission [FERC] shall prescribe, and from time to time thereafter revise, such rules as it determines necessary to encourage cogeneration and small power production, which rules require electric utilities to offer to —

(1) sell electric energy to qualifying cogeneration facilities and qualifying small power production facilities and

(2) purchase electric energy from such facilities . . ."

(b) Rates for purchases by electric utilities

The rules prescribed under subsection (a) of this section shall insure that, in requiring any electric utility to offer to purchase electric energy from any qualifying cogeneration facility or qualifying small power production facility, the rates for such purchase —

(1) shall be just and reasonable to the electric consumers of the electric utility and in the public interest, and

(2) shall not discriminate against qualifying cogenerators or qualifying small power producers.

No such rule prescribed under subsection (a) of this section shall provide for a rate which exceeds the incremental cost to the electric utility of alternative electric energy."

22 The provisions of 16 U.S.C. § 824a-3(d) provide the following definition of "incremental cost of alternative electric energy":

"For purposes of this section, the term "incremental cost of alternative electric energy" means, with respect to electric energy purchased from a qualifying cogenerator or qualifying small power producer, the cost to the electric utility of the electric energy which, but for the purchase from such cogenerator or small power producer, such utility would generate or purchase from another source."

23 Armco Advanced Materials Corp. v. Pennsylvania Public Utility Comm'n, 535 Pa. 108, 634 A.2d 207, 209 (1993).

24 The rules governing electric utilities' obligation to purchase from and sell to QFs are found at 18 C.F.R. § 292.303; the rules governing the rates electric utilities must pay for QF power are found at 18 C.F.R. § 292.304.

25 See American Paper Inst. v. American Elec. Power Serv., 461 U.S. 402, 406, 103 S.Ct. 1921, 76 L.Ed.2d 22 (1983) (stating that "the term full `avoided costs' used in the regulations is the equivalent of the term `incremental cost of alternative electric energy' used in § 210(d) of PURPA"). The FERC's definitions of terms used in implementing PURPA are found at 18 C.F.R. § 292.101. The term "avoided costs" is defined as follows:

"Avoided costs means the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source."

¶ 10 While the applicable statutes and rules are matters of federal law, PURPA gives to state regulatory authorities the responsibility of determining a utility's avoided costs.²⁶ Accordingly, in 1981 the Oklahoma Legislature enacted 17 O.S. 34.1, giving the Commission the power to implement and administer PURPA.²⁷ The Commission in turn promulgated its own rule, which imposes avoided cost informational filing requirements on utilities and provides cogenerators with rights commensurate with those granted by PURPA.²⁸

26 The provisions of 16 U.S.C. § 824a-3(f) obligate state regulatory agencies to implement FERC's rules through their own rulemaking. FERC v. Mississippi, 456 U.S. 742, 102 S.Ct. 2126, 72 L.Ed.2d 532 (1982). See the provisions of 16 U.S.C. § 824a-3 (f), which state:

"Implementation of rules for qualifying cogeneration . . . facilities

(1) Beginning on or before the date one year after any rule is prescribed by the Commission under subsection (a) of this section or revised under such subsection, each State regulatory authority shall, after notice and opportunity for public hearing, implement such rule (or revised rule) for each electric utility for which it has ratemaking authority."

27 The provisions of 17 O.S. 1981 34.1, state in pertinent part:

"The Commission shall have the power to implement and administer the Public Utility Regulatory Policies Act (P.L.95-617). The Public Utility Division of the Corporation Commission shall be responsible for assisting the Commission in the performance of these duties. . . . The Corporation Commission shall adopt such rules and regulations as are necessary to implement the purpose of all federal laws which are administered or enforced by the Corporation Commission."

Section 34.1 was amended effective July 20, 1987. The amendment did not alter the substance of the above quoted provision.

28 The pertinent provisions of OAC 165:35-29-1 state:

"(e)Each utility will maintain on file for all other potential cogenerators a small power producers information sufficient to guide such parties in regard to avoided costs and procedures. Such information shall include, but not be limited to:

(1) The utility's response to avoided cost interrogatories as requested by the Commission.

(2) A copy of this Chapter.

(3) A copy of the experimental tariff

(4) Such reports and analyses as shall be prescribed by the Commission.

(5) For investor owned utilities, the information required by Section 210 of the Public Utility Regulatory Policies Act (PURPA) of 1978.

(f) A cogenerator or small power producer has the right:

(1) To generate in parallel with the utility.

(2) To sell, at his/her option, his/her total generation or his/her generation net of electrical requirements.

(3) To receive for his/her generation a fair rate based on the costs avoided by the utility because of his/her delivery, reliability, dispatchability and other factors, as determined by the commission.

(4) To other substantive rights granted by PURPA.

(5) To good faith negotiations by the utility.

(6) To bring complaint or dispute to the Commission for mediation, hearing or other resolution."

IV

THE COMMISSION'S DETERMINATION THAT LAWTON INCURRED A LEGALLY ENFORCEABLE OBLIGATION TO DELIVER POWER TO PSO IS CONSISTENT WITH FEDERAL AND STATE LAW AND IS SUPPORTED BY SUBSTANTIAL EVIDENCE

¶ 11 Lawton's application with the Commission seeks to compel PSO to purchase power from Lawton and to determine the "avoided cost" rate PSO must pay for that power. The FERC rules give QFs two options for the calculation of avoided costs. Under the first option, a QF can provide energy as the QF determines such energy to be available for purchase and have the purchasing utility's avoided cost rates calculated at the time the power is delivered. Under the second option, a QF can provide power pursuant to a "legally enforceable obligation" over a specified term. If a qualifying facility chooses to provide power pursuant to a legally enforceable obligation, it may choose to have the purchase price based on the utility's avoided costs calculated at the time the power is delivered or based on cost projections for the life of the obligation as calculated at the time the obligation is incurred.²⁹ Lawton asked the Commission to find that it had incurred a legally enforceable obligation and calculate PSO's avoided costs for the life of the obligation at the time the obligation was incurred. The Commission so found and fixed PSO's avoided cost rates for the duration of the power sales agreement.³⁰

29 See the provisions of 18 C.F.R. § 292.304(d), which state:

"Purchases "as available" or pursuant to a legally enforceable obligation. Each qualifying facility shall have the option either:

(1) To provide energy as the qualifying facility determines such energy to be available for such purchases, in which case the rates for such purchases shall be based on the purchasing utility's avoided costs calculated at the time of delivery; or

(2) To provide energy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term, in which case the rates for such purchases shall, at the option of the qualifying facility exercised prior to the beginning of the specified term, be based on either:

(i) The avoided costs calculated at the time of delivery; or

(ii) The avoided costs calculated at the time the obligation is incurred."

30 The Order, after setting out the evidence, concludes:

"Taking into consideration, the Applicant's request for relief, the Power Sales Agreement ("PSA") tendered by Lawton on April 8, 2002, that includes appropriate sanctions, the Project Development Activities of Lawton set forth in the testimony of various Lawton witnesses, including the Direct Testimony filed on September 26, 2002, and the Project Book (Exhibit 272), the Commission finds that Lawton established a legally enforceable obligation, as that term is employed by PURPA, no later than September 26, 2002, and, accordingly, . . . [PSO's] avoided costs are to be determined as of that date. The Commission further finds that Lawton is capable of performing under the terms of the PSA and is, therefore, viable."

¶ 12 The FERC has expressly delegated to the states the responsibility to determine whether a QF has incurred a legally enforceable obligation to deliver power and, if so, when the obligation arose.³¹ PSO and OIEC argue on appeal that the Commission erred in finding under state law that Lawton incurred a legally enforceable obligation entitling it to lock in avoided cost rates. PSO contends that a legally enforceable obligation to deliver power exists only if a utility is able to compel through legal process the cogenerator's performance of the obligation or to recover damages for the cogenerator's failure to perform. PSO argues that it can do neither in this case because Lawton is not a viable project and because the power sales agreement Lawton tendered contains only illusory penalties for a failure to perform.

31 Metropolitan Edison Co., 72 FERC 61,015, 61,050, 1995 WL 397198 (1995) ("It is up to the States, not [FERC], to determine the specific parameters of individual QF power purchase agreements, including the date at which a legally enforceable obligation is incurred under State law.").

¶ 13 At the outset, we note that the creation of a legally enforceable obligation is not governed by the common law of contracts. It is a concept created by federal and state statutes, regulations and administrative rules. It is clear from these sources that electric utilities need not be willing participants in the creation of a legally enforceable obligation. Rather, a utility's obligation to purchase power is imposed by law. ³² As one court aptly described the context in which courts must assess whether a QF has incurred a legally enforceable obligation, "We are not, after all, dealing with completely free enterprise. We are, rather, dealing with the twilight world of regulated monopolies."³³

32 Snow Mountain Pine Co., supra note 20 at 1370.

33 Armco Advanced Materials Corp., supra note 23 at 212.

¶ 14 We implicitly recognized in Smith Cogeneration Management v. Oklahoma Corporation Commission ³⁴ that only a viable project can incur a legally enforceable obligation. In concluding that the cogenerator in Smith had not created a legally enforceable obligation, the court noted that "Smith did not . . . attempt to obtain a contract for construction, operation and maintenance of the proposed project or a contract for the purchase of natural gas."³⁵ Other jurisdictions have also required a degree of project development before finding that a QF is capable of incurring a legally enforceable obligation.³⁶

34 Supra note 13.

35 Id. at ¶ 13, at 1234.

36 In Appeal of Public Service Company of New Hampshire, 130 N.H. 285, 539 A.2d 275 (1988), the Supreme Court of New Hampshire held that a legally enforceable obligation is created when a filed rate petition demonstrates inter alia that "most of the developmental problems have been resolved, giving rise to a reasonable expectation that the project will be on-line on the date specified in the rate filing" and the QF can demonstrate the economic viability of its project over the life of the project. Id. at 281. In South River Power Partners, L.P. v. Pennsylvania Public Utility Commission, 696 A.2d 926 (Pa.Commw.Ct. 1997), the Commonwealth Court of Pennsylvania indicated that a QF must take steps toward development of the project that demonstrate it has the ability to carry out its responsibilities. Id. at 930. The court indicated that acceptable steps include undertaking "substantial action . . . to acquire the necessary permits, site development approval, construction plans, and financing." Id. at 931.

¶ 15 The record in this case provides substantial evidence that significant progress has been made toward bringing the Lawton generating facility into existence. Lawton's principals have invested significant amounts of time, effort, and money in the project. Although contracts for each and every element of the project may not have been finalized, meaningful progress has been made toward the project's completion. The Commission's decision that Lawton is viable is supported by substantial evidence.³⁷

37 The Commission's order states:

"The Commission further finds that Lawton has made significant progress in the development of the Lawton Qualifying Facility, including but not limited to, attempts in obtaining environmental and other necessary permits, in securing contracts for natural gas supply and transportation, for construction of the facility, and for the operations and maintenance contract, including site studies, plant design, and negotiations with vendors for these services. Lawton has also taken steps to secure financing. Lawton has continued to develop the Lawton Qualifying Facility and has now executed definitive contracts for construction, operations and maintenance and for its natural gas supply and transportation."

¶ 16 We also disagree with PSO's contention that the power sales agreement approved by the Commission does not create a legally enforceable obligation because it is an "output contract." An output contract is one in which a buyer agrees to buy a seller's entire output of production.³⁸ According to PSO, the power sales agreement is an output contract because "there is not a known specific amount of electric power contained in the PSA which PSO could legally require Lawton to either provide or pay damages for [its failure to provide]." PSO argues that under both the common law and the Uniform Commercial Code,³⁹ an output contract does not create a legally enforceable obligation because it provides a remedy for non-performance only if the promisor fails to act in good faith. PSO insists that such a remedy is a non-remedy — it does not really obligate Lawton to do anything. Lawton responds that the PSA is not an output contract because it specifies a readily ascertainable numeric quantity of power to be delivered to PSO.⁴⁰ The Commission found that the PSA specifies a numeric quantity of power to be delivered to PSO and is hence not an output contract.⁴¹

38 Lenape Resources Corp. v. Tenn. Gas Pipeline Co., 925 S.W.2d 565, 569 (Tex. 1996).

39 Because this court has never decided whether the Uniform Commercial Code applies to the sale of electricity, i.e. whether electricity constitutes "goods," the parties addressed the output-contract issue under both the Code and the common law.

40 The PSA specifies that x kilowatt hours per hour shall be made available to PSO, but that if after it is up and running Lawton is unable to generate that quantity of electricity, Lawton must within 24 months specify the amount of electricity it will supply, which cannot be less than y kilowatt hours per hour or more than z kilowatt hours per hour. For an explanation of the term kilowatt hour, see infra note 73.

41 Relying on the UCC, the Commission stated that the UCC's good faith rule applies only when an output contract meets both of the following criteria: (1) the seller must agree to sell its entire output of production; and (2) the seller's output amount cannot be quantified for purposes of enforcing the contract. Lenape Resources, supra note 38 at 569. The Commission found that the PSA in this case does not meet the second criteria for an output contract under the UCC because it specifies a numeric quantity of power to be delivered to PSO. Although the Commission acknowledges that the PSA permits Lawton to adjust the specified quantity within a minimum and maximum range by a specific date, the quantity is readily ascertainable for purposes of enforcing the contract.

¶ 17 We need not decide whether the PSA is or is not an output contract. Assuming arguendo that it is, we hold that in the contemplation of PURPA, an output contract may give rise to a legally enforceable obligation.⁴² Contracts lacking a definite and certain quantity term are valid and enforceable in Oklahoma under both the common law⁴³ and under the Uniform Commercial Code.⁴⁴ Under the Uniform Commercial Code, a seller cannot tender an amount that is unreasonably disproportionate to the seller's anticipated output as measured by any stated approximation. A stated minimum or maximum further establishes the boundaries of the agreement's elasticity.⁴⁵ The PSA provides an approximation of Lawton's electrical output along with a minimum and maximum range of permissible deviation from that approximation. While the PSA does not provide a specific, unalterable numeric quantity, it clearly affords the necessary specificity under Oklahoma law for the agreement's enforceability.⁴⁶

42 See Baker v. Murray Tool Supply Co., 1929 OK 97, 279 P. 340; Bell-Wayland Co. v. Russell Jobbers' Mills 1923 OK 672, 218 P. 827. See also Holleyman v. Holleyman, 2003 OK 48, ¶ 17, 78 P.3d 921, 935. (Opala, J. concurring) ("Even under pure contract law the lack of the assumed obligation's specificity would not preclude its enforceability if the trial court is able to determine with a reasonable degree of certainty, what the parties had intended. [citations omitted] A contract will not fail for lack of specificity in its terms if it is clear that the parties contemplated the open terms to be resolved in a specified manner and in a specified time.").

43 Baker, supra note 42; McMichael v. Price, 1936 OK 373, 58 P.2d 549.

44 See the provisions of 12A O.S. 2-306, which state:

"§ 2-306. Output, Requirements and Exclusive Dealings

(1) A term which measures the quantity by the output of the seller or the requirements of the buyer means such actual output or requirements as may occur in good faith, except that no quantity unreasonably disproportionate to any stated estimate or in the absence of a stated estimate to any normal or otherwise comparable prior output or requirements may be tendered or demanded.

(2) A lawful agreement by either the seller or the buyer for exclusive dealing in the kind of goods concerned imposes unless otherwise agreed an obligation by the seller to use best efforts to supply the goods and by the buyer to use best efforts to promote their sale."

45 Id. at Comment 3.

46 Holleyman, supra note 42 at ¶ 17, at 935 (Opala, J. concurring) ("A contract will not fail for lack of specificity in its terms if it is clear that the parties contemplated the open terms to be resolved in a specified manner and in a specified time.").

¶ 18 PSO next argues that the PSA contains exclusive remedies for Lawton's breach and that the remedies provided are illusory. Lawton responds that the remedies contained in the PSA are genuine and that in any event they are not the only remedies available to PSO. Lawton insists that nothing in the PSA limits PSO's resort to other remedies provided by law. The Commission agreed with Lawton. Its order states:

"Further, the Commission finds that the PSA tendered by Lawton does not contain any language limiting the remedies or sanctions available to AEP should Lawton fail to perform. See generally, Power Sales Agreement, § IX. Therefore, both the UCC and Oklahoma statutory and common law (regardless of which one an Oklahoma Court would apply) provide AEP adequate remedies for any breach by Lawton. These remedies are part of the total legal obligation of Lawton under the PSA. Practical Prod. Corp. v. Brightmere (sic), 1992 OK 158, 864 P.2d 330, 332 ( citing 12 O.S. § 1-201(11))(sic)."⁴⁷

47 The correct spelling of the defendant's name in the cited case is Brightmire. The citation at the end of the quoted text should be to 12A O.S., not 12 O.S.

47 The correct spelling of the defendant's name in the cited case is Brightmire. The citation at the end of the quoted text should be to 12A O.S., not 12 O.S.

¶ 19 We agree with the Commission's construction of the PSA. It is a basic principle of contract law that the parties to a contract may agree to an exclusive remedy for breach, which if reasonable will be enforced and will exclude other remedies.⁴⁸ At the same time, Oklahoma law recognizes a distinction between language in a contract that restricts remedies and language that actually expands rights under the contract. Provisions that expand rights give the non-defaulting party a course of action in addition to recourse through other legally available remedies. ⁴⁹ The Commission read the PSA as expanding the rights of PSO rather than as providing exclusive remedies. We find the Commission's construction of the relevant provisions of the PSA to be reasonable.

48 Pan Mut. Royalties, Inc. v. McElhiney, 1962 OK 210, ¶ 21, 376 P.2d 232, 235.

49 Anderson v. Pickering, 1975 OK CIV APP 42, ¶¶ 23-24, 541 P.2d 1361, 1365-66.

V AVOIDED COSTS

¶ 20 A critical matter in controversy in this case is the Commission's calculation of PSO's avoided costs. Some background information is necessary for an understanding of the issues raised. The FERC rules recognize two categories of costs avoided by a utility when it purchases power from a QF: "capacity costs" and "energy costs."⁵⁰ Capacity costs generally represent the fixed capital costs of a generating facility. These include the costs of constructing a plant, installing generating equipment, and the financial carrying costs of the utility's investment in the plant. These costs do not vary with changes in the plant's actual production.⁵¹ Energy costs are the variable costs of operating, maintaining and providing fuel to the plant. Energy costs vary depending on actual generation, i.e. they increase or decrease according to the amount of fuel consumed and the cost of operating and maintaining the plant.⁵²

50 See Small Power Production and Cogeneration Facilities; Regulations Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, 45 Fed.Reg. 12,214, 12,222 (1980) ("Preamble").

51 Rosebud Enterprises, Inc. v. Idaho Public Utilities Comm'n, 128 Idaho 609, 917 P.2d 766, 772, n. 4 (1996).

52 Id.

¶ 21 Capacity and energy can be self-generated or purchased. They are self-generated when a utility builds a new generating unit and places its production on its own system. Capacity purchases occur when a utility buys the right to call on the resources of another generating entity if the purchasing utility's own ability to generate electrical energy is insufficient to satisfy its obligations. Energy purchases occur when a utility buys electricity from another generator. Energy purchases may be made to satisfy the purchasing utility's obligations or they may be made solely because it is more economical at a certain point in time for the utility to buy energy than to generate it itself.

¶ 22 A QF is only entitled to an avoided capacity payment from a utility if the purchase of the QF's capacity permits the utility to avoid building additional capacity of its own or purchasing it from another source.⁵³ The state regulatory authority must hence consider whether a utility needs additional capacity and, if so, what type of capacity is needed. In contrast, a QF is always entitled to a payment reflecting avoided energy costs. This is so because a utility can always avoid costs associated with the production of energy by decreasing the operation of one or more of its own units or by foregoing an energy purchase and replacing that energy with energy from the QF.

53 City of Ketchikan, Alaska, 94 FERC ¶ 61,293, 2001 WL 275023, *6 (stating that "In implementing section 210 of PURPA, the Commission made clear that an avoided cost rate need not include capacity costs (as distinct from energy costs) where a QF does not `permit the purchasing utility to avoid the need to construct a generating unit, to build a smaller, less expensive plant, or to reduce firm power purchases from another utility.' Order No. 69, FERC Stats. Regs., Regs. Preambles 1977-1981 ¶ 30,128 at 30,865 . . . Accordingly, an avoided cost rate need not include capacity unless the QF purchase will permit the purchasing utility to avoid building or buying future capacity. Thus, while utilities may have an obligation under PURPA to purchase from a QF, that obligation does not require a utility to pay for capacity that it does not need."). Some state regulatory authorities will not calculate a capacity payment on the grounds that the utility cannot "avoid" costs it has already incurred. See e.g. Cincinnati Gas Elec. Co., 63 PUR 4th 187, 188-90 (Ohio Pub. Util. Comm'n 1984). Other states assess a capacity payment based on the present net value of future estimated avoided capacity costs, reasoning that the addition of QF capacity will permit the utility to avoid capacity additions in the future. See e.g. Potomac Elec. Power Co., 63 PUR 4th 531, 579-80 (D.C. Pub. Serv. Comm'n 1984).

¶ 23 Implementation of the avoided cost standard has proved quite problematic. States use a variety of methodologies for calculating avoided costs and their results have often either overestimated or underestimated the costs utilities actually avoid by purchasing energy from a QF. In 1988 the FERC issued a Notice of Proposed Rulemaking entitled "Administrative Determination of Full Avoided Costs, Sales of Power to Qualifying Facilities, and Interconnection Facilities"⁵⁴ (the "NOPR"), in which it addressed some of the problems encountered in determining avoided costs. One of its proposals was to have wholesale purchases play a greater role in the avoided cost determination. The FERC terminated the NOPR in 1998 without adopting new rules based on the ideas it expressed. Nevertheless, in 1995 in Southern California Edison Co. ⁵⁵ the FERC issued a ruling disapproving of an avoided cost determination that did not take into account "all sources of generation capacity" available to the purchasing utility.⁵⁶

54 FERC Stats. Regs. 1988-1998 ¶ 32,457, 53 Fed.Reg. 9331 (March 22, 1988).

55 70 F.E.R.C. ¶ 61,215, ¶ 61,675-76, 1995 WL 169000 (Feb. 22, 1995), clarified on denial of reconsideration, 71 F.E.R.C. ¶ 61,269, 1995 WL 327268 (June 2, 1995).

56 Id. at ¶ 61,675-76.

¶ 24 It is important to note that the FERC has never limited states to a single methodology for determining avoided costs. Each state regulatory authority continues to have its own rules and regulations and its own methodology for implementing PURPA. As long as the method employed both reasonably accounts for a utility's avoided costs and encourages cogeneration⁵⁷ it will be deemed in compliance with PURPA even if the avoided cost estimate differs from actual avoided costs at the time the energy is delivered.⁵⁸

57 See Preamble, supra note 50 ("Therefore, to the extent that the method of calculating the value of capacity from qualifying facilities reasonably accounts for the utility's avoided costs, and does not fail to provide the required encouragement of cogeneration. . . . it will be considered satisfactorily implementing [FERC's] rules.").

58 See 18 C.F.R. 292.304(b)(5) ("In the case in which the rates for purchases are based upon estimates of avoided costs over the specific term of the contract or other legally enforceable obligation, the rates for such purchases do not violate this subpart if the rates for such purchases differ from avoided costs at the time of delivery.").

VI

THE COMMISSION'S REFUSAL TO BASE AVOIDED COSTS ON WHOLESALE MARKET PRICES IS SUPPORTED BY SUBSTANTIAL EVIDENCE AND IS CONSISTENT WITH PURPA

¶ 25 Appellants contend that if PSO is required to purchase Lawton's power at the avoided cost rates ordered by the Commission, ratepayers will be subjected to unnecessary and costly rate increases. Appellants argue that the Commission made a critical error by refusing to calculate avoided costs in accordance with the evidence PSO tendered establishing the availability of low cost electrical power for purchase in the wholesale electricity market and by opting instead to base avoided costs on the addition to PSO's system of a hypothetical generating unit.

¶ 26 PSO witnesses testified that for the foreseeable future its resource plan is to purchase any needed capacity in the market rather than to build new generating plants. PSO witnesses also testified that the utility intends to supply its energy needs with purchases whenever that option is more economical than operating its own generating units. In support of this plan, appellants offered evidence that there is a glut of energy in the market resulting in market prices that are lower than the costs PSO would incur if it were to build and operate a plant of its own. Several witnesses testified that the chance of prices rising significantly in the next five to ten years is remote because it will take that long to work off the market surplus, making PSO's planned reliance on market purchases both sensible and prudent.

¶ 27 Accordingly, PSO proposed that its avoided capacity costs should be calculated based on market prices, which would be determined through a competitive bidding process overseen by the Commission or from "offers" PSO had already received from market participants. PSO also proposed that its avoided energy costs be tied to market prices obtained from industry publications that provide forecasts of energy prices several years into the future. PSO advocated a contract term of no more than five years, corresponding to its prediction that market prices will remain the least cost alternative for at least that period of time.

¶ 28 The Commission's Staff witness testified that he could neither support nor refute the claim that market prices would remain low for three to five years, but testified that markets are volatile in both price and power availability. He further testified that it is inappropriate and risky for a utility to rely on purchases at projected wholesale market prices for a significant portion of its resource needs without locking in a price and ensuring availability through a contract or other binding agreement. Although the Staff witness recommended using market prices to establish avoided costs for the first three to five years of the power sales agreement, he told the Commission that relying on the market for more than six to twelve months into the future is dangerous. A PSO witness agreed that energy markets are subject to "significant uncertainty and variability."

¶ 29 The Commission found PSO's reliance on market purchases for its resource plan to be an unacceptable means of providing for its future generation needs. The Commission criticized PSO for failing to offer any "specific long-range strategy in the way of planned generation assets . . . other than simply further reliance upon purchased power." The Commission found that the market is volatile and that PSO's reliance on market purchases is short-sighted and risky. With regard to the "offers" PSO received, the Commission found them to be unreliable evidence of future market prices and insufficiently detailed to be useful.⁵⁹ The Commission also rejected competitive bidding as a method for determining market prices, concluding that there are numerous unresolved problems with instituting such a process.⁶⁰ While rejecting the recommendation of its own staff witness to base avoided costs on the market for the first few years of the power sales agreement, the Commission was clearly persuaded by that witness's testimony regarding the inadequacy of PSO's resource plan and the volatility of the market.

59 The Commission found that none of the offers (1) extended beyond 2009 while the term of the contract approved by the Commission extends to 2025; (2) was for power beginning in 2005 or later; (3) incorporated the energy costs PSO would avoid by purchasing energy from Lawton; or (4) addressed the costs of delivering the power to PSO.

60 The Commission concluded that it was not prepared to oversee a competitive bidding process. It noted that it has no rules in place to govern such a process and the Commissioners were skeptical that a process could be developed and carried out without a tremendous delay in the proceedings. The Commission was uncertain that competitive bidding would yield a reliable result given AEP-PSO's market power. Furthermore, the parties disagreed as to whether PURPA would gave Lawton first-in-line status to match any bid. If so, the Commission questioned whether legitimate bids will be made if bidders know their bids will only be used to calculate avoided costs for a QF purchase. The Commission's Staff witness also questioned whether PSO's resource plan was sufficiently detailed to support a competitive bidding process. Appellants did not challenge the Commission's decision to reject competitive bidding as being in violation of PSO's right to due process.

¶ 30 We are presented here with highly conflicting evidence in a matter within the Commission's expertise. Much of the evidence consists of conflicting opinions by experts as to the volatility of the electricity market and what effect market volatility should have on the Commission's evaluation of PSO's resource plan and its view of the market's usefulness in determining avoided costs. While we might also have viewed a different outcome as supported by substantial evidence, we cannot say that the Commission's decision to reject the market as the basis for PSO's avoided costs does not rest on a substantial evidentiary basis. Qualified experts having a rational basis for their view offered evidence that supports the Commission's decision. It is not for this court to re-weigh the proof and substitute its judgment for that of the Commission as to where the weightier evidence lies. The Commission's view of the electricity market and of its own ability to oversee a market-based procedure for determining avoided costs is within the Commission's special knowledge as regulators in this field and we will not reverse its decision in the absence of a compelling reason to do so.

¶ 31 Finally, we do not agree with PSO that PURPA requires the Commission to use wholesale market prices to determine avoided costs. FERC has stated that:

"there is no requirement in our regulations that avoided costs be established through competitive bidding or other competitive procurement mechanisms. Our existing regulations permit avoided cost to be established administratively, so long as all alternative sources of electric energy, i.e., all resource technologies and all types of sellers (QF and non-QF), are taken into account."⁶¹

61 Metropolitan Edison Co. and Pennsylvania Electric Co., Order Denying Petition for Enforcement and Declaratory Order, 72 FERC P 61,015, 61,051, 1995 WL 397198 (1995).

61 Metropolitan Edison Co. and Pennsylvania Electric Co., Order Denying Petition for Enforcement and Declaratory Order, 72 FERC P 61,015, 61,051, 1995 WL 397198 (1995).

¶ 32 The FERC's proviso that all alternative sources should be taken into account does not mean that every alternative source proposed by one party or another must be utilized in determining avoided costs. A source may be "taken into account" by dismissing it as inappropriate. In other words, state regulatory authorities retain discretion to determine what sources of capacity and energy should be considered in determining avoided costs.⁶²

62 Even in the terminated NOPR, which advocated greater use of wholesale market prices in calculating avoided cost, the FERC says,

"[S]tates . . . retain the discretion to determine what wholesale sources are appropriate to take into account, and what sources may be inappropriate, as long as the states . . . provide written reasons for their decisions to exclude any source."

VII

THE COMMISSION'S DETERMINATION OF AVOIDED CAPACITY COSTS IS SUPPORTED BY SUBSTANTIAL EVIDENCE

¶ 33 The determination of a utility's avoided capacity costs begins with an analysis of the utility's capability to meet the demand made on it for electricity. Demand for electricity varies hourly and seasonally. A utility must have sufficient generating capability to meet the maximum demand, whenever that occurs.⁶³ Because electricity cannot be produced in advance and be then stored, a utility must have generation resources available to meet periods of peak demand.⁶⁴ Consequently, a portion of a utility's generating units will stand idle most of the day or year, coming online only during periods of peak demand.⁶⁵

63 LEONARD S. HYMAN, AMERICA'S ELECTRIC UTILITIES: PAST, PRESENT AND FUTURE 25 (Public Utilities Reports, Inc., 5th ed. 1994).

64 Id.

65 Id.

¶ 34 To economically deal with the situation of variable demand, utilities use three types of generating units that optimally match costs with usage. Baseload plants are designed to operate continuously to meet a system's minimum load. They are expensive to build, but because they use low cost fuels, they are relatively inexpensive to operate.⁶⁶ In contrast, peaking units are designed to run for only short periods of time when demand for electricity is at its highest.⁶⁷ They are less expensive to build than baseload plants, but because their fuel costs are higher, they are more expensive to operate.⁶⁸ The third category of generating units are intermediate plants, which as the name suggests operate more than a baseload unit and less than a peaking unit with commensurate costs.⁶⁹

66 Id. at 27.

67 Id.

68 Id.

69 Id. See also, Connecticut Light and Power Co. v. Department of Public Utility Control, 216 Conn. 627, 583 A.2d 906, 908, n. 5 (1990).

¶ 35 Based on evidence of PSO's capability to meet projected future demand, the Commission found that PSO will need to secure additional peaking capacity beginning in 2005 and that its need for capacity to meet peak demand and reserves will increase each year thereafter. Accordingly, the Commission found that PSO needs the capacity Lawton will provide. Having rejected competitive bidding and the "offers" received by PSO as means of determining avoided costs, the Commission selected a newly constructed combustion turbine peaking plant as the most efficient alternative source of supply of PSO's next unit of required capacity. These findings and conclusions are supported by substantial evidence.

¶ 36 The Commission found that a levelized capacity payment of $77.01/kW/year was a reasonable estimate of the capacity costs of a peaking plant. This amount was consistent with the testimony of expert witnesses regarding the capacity costs of a peaking plant. We hold that the Commission's findings and conclusion as to PSO's avoided capacity costs are supported by substantial evidence.

¶ 37 Although PSO does not dispute that its future need is for peaking capacity, it suggests that it might be more appropriate in this case to use the costs avoided by the addition of a hypothetical baseload unit on its system. This argument is based on the fact that the power sales agreement approved by the Commission requires PSO to accept power from Lawton not just at hours of peak demand when PSO needs Lawton's power to meet demand, but all day every day of the year.⁷⁰ In other words, PSO's need for peaking capacity is not matched by the amount of power it will have to accept from Lawton. PSO argues that the amount of power it must take from Lawton is characteristic of a baseload unit, not a peaking unit, so that regardless of what its future needs may be, its avoided costs for taking Lawton's power would be better reflected by using a baseload unit as the proxy. As PSO points out, energy costs make up a large percentage of total avoided costs. Hence, while the fixed costs of a baseload unit would be considerably greater than those of a peaking unit, over the course of the contract's term the higher capacity(fixed) costs of a baseload unit would be more than offset by that unit's lower operating costs. The Commission's staff witness in fact recommended that a baseload unit be used as a proxy for avoided costs during a portion of the contract's term.

70 PURPA requires a utility to purchase the net electrical output of a qualifying facility. The Lawton facility will be producing steam for two "steam hosts," businesses that operate using steam power. This will require Lawton to operate around the clock. The PSA requires PSO to purchase electricity from Lawton 92% of the hours in the year.

¶ 38 In the next part of this pronouncement, we hold that on remand the Commission must revisit its determination of PSO's avoided energy costs. While the evidence of PSO's future capacity needs clearly supports the Commission's decision to base avoided capacity costs on the capital costs of a peaking unit, reconsideration of PSO's avoided energy costs may create a need to reconsider the use of a peaking unit as the proxy for avoided capacity costs during the entire contract term. We are not directing the Commission to make any particular decision in this regard, but are merely giving the commissioners permission to revisit this issue if necessary. Regardless of how energy payments are determined, it may well be that the lower costs of building a peaking unit make that unit a more accurate measure of capacity costs in current dollars than generating units that take longer to build, are more complex, and have greater exposure to regulatory and environmental measures.⁷¹ We simply want to make clear that while we affirm the Commission's use of a proxy peaking unit for capacity costs, we are not forbidding the Commission to revisit the proxy unit chosen for capacity payment purposes to the extent that the Commission determines such revisiting of the subject is necessitated by its reconsideration of PSO's avoided energy costs.

71 Re Rates for Sale and Purchase of Electricity Between Electric Utilities and Qualifying Facilities, 64 PUR 4th 369, 386 (N.C. Utilities Comm'n 1985).

VIII

THE COMMISSION'S APPROACH TO PSO'S AVOIDED ENERGY COSTS IS NOT SUPPORTED BY SUBSTANTIAL EVIDENCE

¶ 39 Energy costs are the variable costs of operating, maintaining and providing fuel to an electrical generating unit. They are variable because they change with production. Energy costs have two principal components: a heat rate and a fuel cost. Heat rate measures the number of British Thermal Units (Btu)⁷² necessary to generate one kilowatt-hour⁷³ of electricity. Heat rate is represented as x Btu/KWh. The lower a generating unit's heat rate, the less fuel it burns to generate electricity and the less it costs to operate. For example, a generating unit that is able to produce one kilowatt-hour of electricity with 7,000 Btu of fuel is 30% less costly to operate than a generating unit that requires 10,000 Btu of fuel to produce one kilowatt-hour. Fuels used for the production of electricity include natural gas, coal, hydro power, and nuclear power. Fuels vary widely in cost. Energy cost is a function of the price of the fuel used by a particular generating unit and that unit's heat rate.

72 One British Thermal Unit (Btu) is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.

73 The capacity of a generating unit is measured in thousands of watts called Kilowatts (Kw) or in millions of watts called Megawatts (Mw). It is a rating given to a generator by the manufacturer or by the utility and measures a generating unit's ability to produce a given amount of electricity at an instant in time. See LEONARD S. HYMAN, supra note 63 at 15. Actual electrical production is measured in Kilowatt-hours (Kwh). A kilowatt-hour is the amount of electricity produced in one hour by a generator that is one kilowatt in size. Id. at 4. A unit with a capacity of 1,000 Kw that operates for twenty-four hours has an output of 24,000 Kwh. Id. at 16.

¶ 40 As stated earlier, the quantity of power a utility produces varies hourly and seasonally depending on demand. In order to produce the quantities of electricity necessary to meet variations in demand, a utility uses different combinations of fuel and equipment. When demand for electricity is low a utility can "dispatch", or operate, its lowest operating-cost units and back down, or turn off, its higher cost units. As demand increases, a utility dispatches its more costly units, beginning with the least costly and moving to the most costly. When load is at its highest, a utility must use units with the highest operating costs. Each increase in the use of a higher cost unit increases the marginal or incremental cost of producing electricity. Proper dispatch decisions result in lower incremental energy costs. Dispatch decisions are made on an hourly and daily basis.

¶ 41 In making dispatch decisions, a utility considers not only the economics of using its own generating units, but also whether to purchase electricity produced by other producers who may be willing to sell electricity for less than what it would cost the utility to operate its less efficient, more expensive generating units. These purchases, known as "economy energy purchases," are another way a utility can lower its incremental cost of producing electricity.

¶ 42 The Commission's order establishes two heat rates for the determination of PSO's avoided energy costs: 10,800 Btu/kWh for Summer On-Peak Hours and 10,460 Btu/kWh for all other hours of the year.⁷⁴ In support of its decision, the Commission states:

74 The term "Summer On-Peak Hours" is defined in the PSA. It includes most of the hours from June 1 — September 30 in each year. A total of 1,462 hours per year fall into the Summer On-Peak category; 7,298 hours per year are off-peak.

"These avoided heat rates are lower than information from the Oak Ridge National Laboratory and the Department of Energy's Energy Information Administration regarding expected CT [combustion turbine] peaking heat rates, and therefore, is a conservative calculation. These heat rates are also close to AEP's current year round system average gas heat rate and will make Lawton the third most efficient unit out of all of AEP's total gas fired generation in terms of efficiency, which will benefit AEP's customers significantly."

¶ 43 The Commission notes that none of the parties in this case gave it much help in determining the avoided heat rate.

"The real challenge in determining the proper heat rate stems from the parties' reluctance to submit evidence relating to how Lawton's facility would be dispatched in the absence of uncommitted short-term purchases. The `avoided heat rate' depends on the point in time at which Lawton's unit would be dispatched, and the heat rate of the units that Lawton's facility would be displacing. Such information is necessary when evaluating PSO's resource options and the type of unit being avoided in order to establish avoided costs. PSO so focused on using market purchases to meet its future capacity and energy needs that it offered little evidence in the way of avoided proxy unit costs in the absence of short term market purchases."

¶ 44 The Commission nevertheless contends that its dual heat rates apply principles of economic dispatch by ordering different heat rates for summer on-peak hours and all other hours. The Commission explains that by differentiating between summer on-peak hours and all other hours, its decision reflects "the variability of the cost of producing electricity during different hours of the day and seasons of the year."

¶ 45 Appellants argue that the Commission-ordered heat rates do not apply economic dispatch principles in any meaningful way. PSO agrees that it cannot physically dispatch Lawton to run only the number of hours it would run under economic dispatch principles,⁷⁵ but it argues that Lawton's energy should be priced as if the QF were dispatchable. The utility contends that if it economically dispatched Lawton based on the Commission-ordered heat rate, Lawton would run no more than 15% of the time.⁷⁶

75 All parties agree that PURPA requires a utility to purchase the net electrical output of qualifying facilities. It is about the price at which the purchase is to be made that the parties disagree.

76 Under the terms of the power sales agreement approved by the Commission, PSO must purchase power from Lawton 92% of the hours in each year, or 8,146 hours. PSO claims that the only type of plant that would be operated at or near a 92% capacity factor would be a baseload plant that would have a heat rate significantly lower than either of the peaking unit heat rates assigned to Lawton by the Commission. PSO asserts that a plant with the heat rate of a peaking unit would not be operated more than ten to fifteen percent of the hours of a year. PSO says that the Commission has in effect created a proxy generating unit with a combination of characteristics that do not exist in the real world: a unit with the high energy costs of a peaking unit, but operated (i.e., dispatched) around the clock like a baseload unit. PSO insists that it could generate its own power or purchase economy energy at heat rates associated with more efficient baseload units.

The Commission counters that the heat rates it ordered are in fact the heat rates of a dispatchable peaking unit.

¶ 46 The Commission's order moves seamlessly from finding that a peaking unit would be the most appropriate capacity addition to PSO's system to using the heat rates of a peaking unit as the basis for calculating energy payments. There seems to be an underlying assumption in the Commission's order, the basis of which is neither expressed nor evident to the court, that if a peaking unit is used for capacity payments, then a peaking unit's heat rate must serve as the basis for energy payments. Utilizing a single proxy unit for both calculations makes sense if the utility's energy needs match the cogenerator's energy output, but where as here the cogenerator will supply a great deal more than the utility's capacity requirements, the rationale for using a unit specific approach to both capacity and energy payments is not clear. Hence, while the record does indeed contain evidence that the non-dispatchable heat rate of a peaking unit is 10,456 Btu/kWh at non-summer conditions and 10,800 Btu/kWh at summer conditions, we fail to see how these ratings relate to the actual generation mix and the resulting incremental costs that would arise from the addition of Lawton's power to PSO's system.

¶ 47 The Commission also says that the heat rates it ordered are "close to AEP's current year round system average gas heat rate and will make Lawton the third most efficient unit out of all of AEP's total gas fired generation in terms of efficiency, . . ." This argument at least has the benefit of looking at the operation of PSO's system, but it too falls short of producing conviction that the ordered heat rates are sustainable. First, the Commission neither provides the number representing PSO's actual historical system average gas heat rate for the court to use as a comparison with the ordered heat rates nor does the Commission identify where in the record that information can be found. Second, even if the Commission determined what PSO's historical system average annual gas heat rate was, it failed to explain how that historical figure relates to the avoided incremental heat rate that PSO will experience by Lawton's displacement of PSO generation.

¶ 48 Lawton argues that the Commission-ordered heat rates should be affirmed because they are lower than the average avoided incremental heat rate produced by the cogenerator's computer simulation of PSO's system. Lawton's computer modeling was rejected by the Commission along with the computer modeling done by PSO. The Commission found that both parties had skewed the inputs into the computer modeling in ways that made them unreliable guides to avoided costs. We have no reason to second-guess the Commission's assessment of the parties' computer models. Hence the fact that the Commission-ordered heat rates are lower than the heat rate Lawton produced in its computer modeling does not convince us that the Commission's heat rates are appropriate.

¶ 49 Finally, although the record does show that both a Commission staff witness and a PSO witness proposed using a heat rate of 10,500 Btu/kWh, we do not believe that their testimony supports the conclusion that the Commission-ordered heat rates comply with the PURPA standard. This is so because the former used that heat rate only in conjunction with a 10% capacity factor and the latter for just a 13-day peaking capacity purchase. Their testimony does not compel the conclusion that a heat rate in the neighborhood of 10,500 Btu/kWh reflects PSO's incremental avoided heat rate for the Lawton purchase.

¶ 50 In reviewing the Commission-ordered heat rates, we are confronted with the task of assessing a Commission decision on a technical matter involving terminology, concepts, and data commonly used by electrical engineers and economists, but not easily understood by those outside those professions. Yet in the final analysis, it is a judicial decision that we are called upon to make, not a decision as engineers or economists. The engineers and economists in this case had widely diverging views. Our task is to determine whether the Commission's decision is supported by substantial record evidence. It may be that the Commission-ordered heat rates would result in avoided energy payments in line with the requirements of PURPA, but from the record provided we are unable to ascertain that this is so. On remand of this cause, it is imperative that the Commission identify in its order the evidence that serves as the factual basis for the heat rate or heat rates chosen and specify how its decision reflects the incremental energy costs PSO will avoid.

¶ 51 With respect to the avoided fuel, the Commission found that gas is the only fuel that would be avoided by the addition of a peaking unit to PSO's system and ordered the cost of gas to be derived from PSO's weighted average cost of gas ("WACOG") as shown on its monthly Fuel Adjustment Clause filings with the Commission.⁷⁷ In support of this decision, the Commission states:

77 Utilities make monthly fuel adjustment clause filings pursuant to Commission rules. See OAC 165:50-5-2. The terms of 17 O.S. 2001 250 (5) provide:

"`Fuel adjustment clause' means any mechanism which allows a public utility or electric generating cooperative to automatically adjust its charges above or below the base amount included in its rates, based upon changes in costs of fuel for generation of electricity, purchased power or purchased gas; . . ."

"The Commission finds that the use of WACOG to set the avoided price for fuel is a very conservative and customer protective approach that will result in energy payments below AEP's full avoided cost, i.e. below AEP's incremental highest priced gas avoided by AEP for its gas purchases."

¶ 52 PSO asserts that natural gas is not the only fuel avoided by a round-the-clock purchase from Lawton and that the weighted average cost of that fuel is not an accurate measurement of PSO's incremental cost. Post-remand reconsideration of PSO's avoided energy costs will necessitate a reconsideration of the avoided fuel. Accordingly, we decline to review this matter until the Commission has completed the further inquiry required by today's pronouncement.

IX

THE ABSENCE OF A PROVISION IN THE PSA CORRESPONDING TO 18 C.F.R. § 292.304(f) DOES NOT VIOLATE PURPA OR THE FERC REGULATIONS IMPLEMENTING IT

¶ 53 PSO argues that the Commission's order violates PURPA by approving a power sales agreement that does not include a clause corresponding to the provisions of 18 C.F.R. § 292.304(f). The provisions of § 292.304(f)(1) permit an electric utility to suspend purchases of energy or capacity from a qualifying facility when "operational circumstances" make such purchases more expensive than generating the electricity itself.⁷⁸ The provisions of § 292.304(f)(2) require a utility exercising its rights under § 292.304(f)(1) to notify the affected QF of its decision in time for the QF to cease delivering power.⁷⁹ This provision would be of no use unless utilities could actually cease purchasing QF power during "operational circumstance" periods. The regulation is hence an exception to the PURPA requirement that electric utilities purchase the entire output of qualifying facilities.⁸⁰

78 The provisions of 18 C.F.R. § 292.304(f)(1) state in pertinent part:

"Any electric utility which gives notice pursuant to paragraph (f)(2) of this section will not be required to purchase electric energy or capacity during any period during which, due to operational circumstances, purchases from qualifying facilities will result in costs greater than those which the utility would incur if it did not make such purchases, but instead generated an equivalent amount of energy itself."

The FERC explains the purpose behind this regulation as follows:

"This section was intended to deal with a certain condition which can occur during light loading periods. If a utility operating only base load units during these periods were forced to cut back output from the units in order to accommodate purchases from qualifying facilities, these base load units might not be able to increase their output level rapidly when the system demand later increased. As a result the utility would be required to utilize less efficient, higher cost units with faster start-up to meet the demand that would have been supplied by the less expensive base load unit had it been permitted to operate at a constant output." See 45 Fed.Reg. 12214, 12227 (February 25, 1980).

79 The provisions of 18 C.F.R. § 292.304(f)(2) provide:

"Any electric utility seeking to invoke paragraph (f)(1) of this section must notify, in accordance with applicable State law or regulation, each affected qualifying facility in time for the qualifying facility to cease the delivery of energy or capacity to the electric utility."

80 FERC's commentary to 18 C.F.R. § 292.303 states that § 292.304(f) is an exception to a utility's obligation to purchase the net electrical output of a qualifying facility:

"The Commission interprets [section 210(a) of PURPA] to impose on electric utilities an obligation to purchase all electric energy and capacity made available from qualifying facilities with which the electric utility is directly or indirectly interconnected, except during periods described in § 292.304(f) or during system emergencies."

¶ 54 We disagree with PSO that a provision incorporating the terms of § 292.304(f) must be included in a QF contract. Extant applicable law is a part of every contract in this state as if it were expressly cited or its terms incorporated in the contract.⁸¹ An intent to modify applicable law by contract is not effective unless the power is expressly exercised.⁸² A contractual adjustment of rights contrary to law must be clearly expressed in the agreement if applicable law is not to be applied.⁸³ Hence, the provisions of § 292.304(f) remain available to PSO regardless of whether they are explicitly included in the contract.

81 Welty v. Martinaire of Oklahoma, Inc., 1994 OK 10, ¶ 11, 867 P.2d 1273, 1276.

82 Dickason v. Dickason, 1980 OK 24, ¶ 10, 607 P.2d 674, 677.

83 Heiman v. Atlantic Richfield Co., 1995 OK 19, ¶ 5, n. 5, 891 P.2d 1252, 1258, n. 5.

¶ 55 The Commission advocates an alternate basis for upholding its decision. We ordinarily would not consider this argument, having just affirmed the Commission's decision on other grounds. Yet in this case we choose to address the Commission's argument because the post-remand inquiry we order today will necessarily entail the Commission's reconsideration of how best to account for the operational circumstance periods covered by § 292.304(f). We deem it prudent to offer some guidance to the Commission on this point.

¶ 56 The Commission argues that the power sales agreement under review does not have to contain a provision corresponding to § 292.304(f) because the Commission made that regulation moot by taking operational circumstances into account through the prescribed heat rates.⁸⁴ PSO counters that the record contains no evidence to support the Commission's contention that the prescribed heat rates reflect an adjustment to account for the periods of operational circumstances contemplated by 292.304(f). While we agree with the Commission that purchase rates may take periods of operational circumstances into account, thereby rendering moot the provisions of § 292.304(f),⁸⁵ we agree with PSO that the record in this case does not provide substantial evidentiary support for the Commission's contention.

84 The order states:

"The Commission, after considering and weighing all the evidence presented by the parties on this issue, including full consideration of the factors set forth in 18 C.F.R. § 292.304(f), finds the costs described [in this order] are consistent with the requirements of PURPA." (emphasis added)

85 See 45 Fed.Reg. 12214, 12227 (February 25, 1980) ("The Commission does not intend that this paragraph [§ 292.304(f)] override contractual or other legally enforceable obligations incurred by the electric utility to purchase from a qualifying facility. In such arrangements, the established rate is based on the recognition that the value of the purchase will vary with the changes in the utility's operating costs. These variations ordinarily are taken into account, and the resulting rate represents the average value of the purchase over the duration of the obligation. The occurrence of such periods [i.e. periods of `operational circumstances'] may similarly be taken into account in determining rates for purchases.") (emphasis added)

¶ 57 To summarize, the provisions of § 292.304(f) remain available to a utility even if its terms are not expressly included in the power sales agreement, but its provisions may not be utilized by the utility if operational circumstances have already been taken into account in calculating the utility's avoided costs. Thus, should PSO ever invoke the provisions of § 292.304(f), its availability will depend on whether the purchase rates ordered by the Commission already take into account periods of operational circumstances. To avoid confusion and prevent future litigation over this issue, we urge that, on remand, if it takes operational circumstances into account through the avoided cost rate structure, the Commission specify on remand what adjustment was made and where in the record evidentiary support for the decision can be found.

X

THE CONTRACT TERM ORDERED BY THE COMMISSION IS SUPPORTED BY SUBSTANTIAL EVIDENCE AND IS CONSISTENT WITH FEDERAL LAW

¶ 58 Lawton asked the Commission to set the term of the PSA at twenty-five years. The Commission rejected this request and set the term at twenty years. PSO argues that the Commission-ordered contract term merely exacerbates the contract's substantive inequities and inefficiencies in violation of PURPA and the FERC's regulations. The Attorney General argues that ratepayers will be harmed by a contract of twenty years duration that reduces PSO's flexibility to rely on market purchases because market purchases will provide electricity to consumers at a lower cost than the PSA. OIEC argues that in today's market a long-term contract is a contract of three to five years duration. Lawton responds that the twenty year term ordered by the Commission is supported by substantial evidence and is consistent with PURPA and the FERC rules implementing it. Lawton points to testimony from Commission Staff that a short-term contract would discourage cogeneration in Oklahoma and that a long-term contract is desirable to protect ratepayers from the volatility of the electricity market.

¶ 59 In Smith,⁸⁶ we held that a qualifying facility is entitled to full avoided costs set for the duration of a long-term contract,⁸⁷ but did not address what constitutes a long term contract. Neither PURPA nor the FERC rules require any particular contract length, leaving the decision on this issue to the discretion of the state regulatory authority to be resolved on a case-by-case basis. Evidence was introduced in this case that in light of market forecasts, five years constitutes the long term, but the Commission, relying on other evidence, was unwilling to rely on predictions of future market conditions. Instead, the Commission concluded that the ability of PSO to purchase power at a known, set price for twenty years would provide greater protection to ratepayers while at the same time promoting the goal of PURPA to encourage cogeneration. The Commission's choice of a twenty-year term does not violate PURPA or the FERC rules implementing it and is supported by the record.

86 1993 OK 147, 863 P.2d 1227.

87 Id. at ¶ 26, at 1241-42.

XI

THE COMMISSION HAS EXTENSIVE AUTHORITY UNDER PURPA TO DETERMINE THE TERMS AND CONDITIONS OF QF CONTRACTS, BUT CERTAIN PARTS OF ITS ORDER EXCEED THAT AUTHORITY

¶ 60 PSO argues that certain provisions of the PSA approved by the Commission impermissibly interfere with the utility's internal business decisions. Such interference has on more than one occasion met with this court's disapproval. As early as 1934, in Lone Star Gas Company v. Corporation Commission,⁸⁸ we said of the powers of the Commission:

88 1934 OK 396, 39 P.2d 547.

The powers of the Commission are to regulate, supervise, and control the public service companies in their services and rates, but these powers do not extend to an invasion of the discretion vested in the corporate management. It does not include the power to approve or disapprove contracts about to be entered into, nor to the approval or veto of expenditures proposed.⁸⁹

89 Id. at ¶ 23, at 553.

89 Id. at ¶ 23, at 553.

In Oklahoma Gas Electric Company v. Corporation Commission,⁹⁰ we held that the Constitution does not clothe the Commission with the general power of internal management and control of the utilities it regulates.⁹¹ In Public Service Company v. State,⁹² the Commission sought to prevent a utility's construction of a plant by refusing to permit the issuance of securities. We held that this was an impermissible interference with the utility's internal business decisions.⁹³

90 1975 OK 15, 543 P.2d 546.

91 Id. at ¶ 30, at 551.

92 1982 OK 6, 645 P.2d 465.

93 Id. at ¶ 5, at 466.

¶ 61 In each of these decisions the power asserted by the Commission and rejected by the court originated in state constitutional or statutory law. These cases are inapplicable to the Commission's exercise of authority under PURPA to order a utility to enter into a contract with a qualifying facility. We recognized this distinction in Smith. ⁹⁴ The utility in that case argued that the amount of its generating capacity and associated costs is an internal management decision beyond the jurisdictional reach of the Commission. We disagreed, holding that the Commission had subject matter jurisdiction to set reserve margins and establish capacity needs insofar as doing so was for the purpose of furthering the federal policy objectives of PURPA.

94 Supra note 13.

¶ 62 By filing an application with the Commission pursuant to PURPA and submitting a proposed contract, Lawton invoked the full power and duty of the Commission to examine all of the contract's terms and conditions for compliance with PURPA and the FERC regulations implementing it. FERC has recognized that the States have this authority. In rejecting a utility's challenge to a state regulatory authority's determination that a legally enforceable obligation had been incurred, the FERC noted that the specific provisions of QF contracts are up to the States to determine:

"It is up to the States, not this Commission, to determine the specific parameters of individual QF power purchase agreements, including the date at which a legally enforceable obligation is incurred under State law. Similarly, whether the particular facts applicable to an individual QF necessitate modifications of other terms and conditions of the QF's contract with the purchasing utility is a matter for the States to determine. This Commission does not intend to adjudicate the specific provisions of individual QF contracts."⁹⁵ (emphasis added)

95 Metropolitan Edison Co. and Pennsylvania Electric Co., supra note 61 at 61,050.

95 Metropolitan Edison Co. and Pennsylvania Electric Co., supra note 61 at 61,050.

Cogenerators have the right to have disputes settled by the Commission.⁹⁶ The Commission did not exceed its authority under PURPA or under statlaw and regulation in reviewing the entire proposed contract and determining the provisions that would be included in the final version.

96 See the provisions of OAC 165:35-29-1(f), which state:

"A cogenerator or small power producer has the right:

* * * * *

(6) To bring complaint or dispute to the Commission for mediation, hearing or other resolution."

¶ 63 PSO also contends that the Commission's order that PSO treat Lawton as a "network resource" not only interferes with management discretion, but also exceeds the Commission's jurisdiction because network service is part of PSO's FERC-approved Open Access Transmission Tariff.⁹⁷ Lawton says that the Commission's directive merely ensures "that AEP-PSO will not be able to impair the operation of the Lawton Facility (including the right to produce and deliver its energy) and that the Facility will be treated fairly by AEP-PSO." The Commission's appeal briefs fail to specifically address this issue, instead including it within its general defense of its decisions as not encroaching upon management discretion.

97 The Federal Power Act grants jurisdiction to FERC to regulate the transmission of electric energy in interstate commerce. See 16 U.S.C. §§ 824, 824d, and 824e. Responding to evidence of pervasive discrimination in the transmission of electric power, the FERC in 1996 issued Order No. 888 ["Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities."], a comprehensive regulatory scheme designed to remedy that discrimination. See FERC Stats. Regs. ¶ 31,036 (1996), 61 Fed.Reg. 21,540-01, on reh'g, Order No. 888-A, FERC Stats. Regs. ¶ 31,048, 62 Fed.Reg. 64,688 (1997), on reh'g, Order No. 888-B, 81 FERC ¶ 61,248, 1997 WL 833250 (1997), on reh'g, Order No. 888-C, 82 FERC ¶ 61,046, 1998 WL 18148 (1998), aff'd, Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom., New York v. FERC, 535 U.S. 1, 122 S.Ct. 1012, 152 L.Ed.2d 47 (2002). Among its directives, Order No. 888 requires all public utilities that own, operate or control interstate transmission facilities ("transmission provider") to offer network and point-to-point transmission services (and ancillary services) to all eligible buyers and sellers in wholesale bulk power markets, and to take transmission service for their own uses under the same rates, terms and conditions offered to others. To implement this open-access transmission regulatory scheme, the FERC issued a pro forma Open Access Transmission Tariff ("OATT") that sets out the minimum terms and conditions under which transmission providers may offer service. All transmission providers must have on file with the FERC the pro forma OATT or "such other open access tariff as may be approved by the FERC consistent with Order No. 888." See the provisions of 18 C.F.R. § 35.28(c)(1).

¶ 64 Network service is a type of relationship a transmission provider may have with a customer for either interconnection services or transmission services or both. Network Resource Interconnection Service requires the transmission provider to build the network upgrades which will allow an interconnection customer to designate a generating facility as a network resource and obtain Network Integration Transmission Service.⁹⁸ When an electric utility purchases a QF's total output, it is obligated to interconnect under the provisions of 18 C.F.R. § 292.303 and the relevant state agency exercises authority over the interconnection and the allocation of interconnection costs.⁹⁹ Network Integration Transmission Service is a transmission or delivery service that places network customers on a footing comparable to that of the transmission provider on the transmission provider's transmission system.¹⁰⁰ Network resource status for interconnection service does not convey transmission service.¹⁰¹ The interstate transmission of electricity within the jurisdictional boundaries of the FERC.¹⁰²

98 See Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003-A 106 FERC P 61,220, 2004 WL 436282, *79 (March 5, 2004).

99 See Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, 104 FERC P 61,103, 2003 WL 21725988, *146 (July 24, 2003).

100 See Promoting Wholesale Competition, supra note 97 at 21717.

101 See Standardization of Generator Interconnection Agreements, supra note 98 at *78.

102 As explained by the Supreme Court in New York v. FERC, 535 U.S. 1, 6, 122 S.Ct. 1012, 1017-18, 152 L.Ed.2d 47 (2002), in almost all cases, electricity today flows in interstate commerce. "[U]nlike the local power networks of the past, electricity is now delivered over three major networks, or `grids,' in the continental United States. Two of these grids — the `Eastern Interconnect' and the `Western Interconnect' — are connected to each other. It is only in Hawaii and Alaska and on the `Texas Interconnect' — which covers most of that State — that electricity is distributed entirely within a single State. In the rest of the country, any electricity that enters the grid immediately becomes a part of a vast pool of energy that is constantly moving in interstate commerce."

¶ 65 The Commission's directive that PSO treat Lawton as a network resource occurs within a discussion of matters relating to interconnection but under a general heading referring to both transmission and interconnection. It is unclear to the court precisely what the Commission is ordering PSO to do. The Commission's order does not delineate the nature and scope of the Commission's directive or point to anything in the record supporting its decision. Its appeal briefs, too, shed no light on the issue. The Commission must convey in the order enough information that the court can determine whether the findings are supported by the law and substantial evidence.¹⁰³ Findings made in general terms are insufficient.¹⁰⁴ The Commission's finding that PSO must treat Lawton as a network resource does not meet this standard.

103 Id.

104 Southwestern Public Service Co. v. State, 1981 OK 136, ¶ 30, 637 P.2d 92, 101.

¶ 66 Finally, PSO argues that the Commission exceeded its authority by ordering PSO's parent company, AEP, to execute the power sales agreement along with PSO. PSO points out that both PURPA and the FERC's implementing regulations limit the QF purchase obligation to electric utilities.¹⁰⁵ PSO argues that while AEP may be its parent company, that does not make it an electric utility.

105 See the provisions of 16 U.S.C.A. § 2602, which state:

"As used in this Act, except as otherwise specifically provided —

The term "electric utility" means any person, State agency, or Federal agency, which sells electric energy."

The provisions of 18 C.F.R. 292.101 state:

"(a) General rule. Terms defined in the Public Utility Regulatory Policies Act of 1978 (PURPA) shall have the same meaning for purposes of this part as they have under PURPA, unless further defined in this part.

(b) Definitions. The following definitions apply for purposes of this part.

(2) Purchase means the purchase of electric energy or capacity or both from a qualifying facility by an electric utility."

¶ 67 The Commission argues in its brief that the power sales agreement can only be fully implemented if another AEP subsidiary, American Electric Power Service Corporation, carries out some of its provisions. The Commission contends that for the latter's cooperation to be assured it is necessary to require AEP, the parent of both PSO and American Electric Power Service Corporation, to join in the agreement. The order makes no findings of fact and points out nothing in the record that supports this contention. Further, PURPA and the FERC implementing regulations clearly assign the QF purchase obligation to electric utilities. The order contains no finding that AEP is an electric utility rather than a company that owns electric utilities, that AEP and PSO are not separate entities, or that they should not be treated as separate entities. On this record, the Commission's order to AEP to execute the agreement cannot be sustained.

XII

THE COMMISSION DID NOT UNILATERALLY CHANGE THE POWER SALES AGREEMENT IN VIOLATION OF THE LAW

¶ 68 PSO argues that the Commission added a new definition to the final version of the PSA and altered another provision without giving the constitutionally required notice to PSO¹⁰⁶ and without substantial support in the record. In the version of the PSA originally tendered by Lawton, PSO was allowed to reduce capacity payments if Lawton did not perform at a 92.3% capacity factor during the summer on-peak hours. PSO argues that the Commission altered this provision in the final version of the PSA to give Lawton the entire year in which to meet this capacity factor, permitting Lawton to receive full capacity payments even if capacity is unavailable when PSO most needs it — during the summer when it experiences peak load.¹⁰⁷

106 The pertinent portion of the Okla. Const. Art. 9 § 18 states:

"Before the Commission shall prescribe or fix any rate, charge or classification of traffic, and before it shall make any order, rule, regulation, or requirement directed against any one or more companies by name, the company or companies to be affected by such rate, charge, classification, order, rule, regulation, or requirement, shall first be given, by the Commission, at least ten days' notice of the time and place, when and where the contemplated action in the premises will be considered and disposed of, and shall be afforded a reasonable opportunity to introduce evidence and to be heard thereon, to the end that justice may be done, and shall have process to enforce the attendance of witnesses; . . ."

107 The new definition is of the term "Total Annual Hours," which is defined as the entire year.

¶ 69 We disagree that the PSA was changed without notice to PSO. Inherent in the regulatory authority the Commission has over avoided cost determinations is the authority to determine related terms and conditions to be included in power sales agreements. PSO had notice of the nature of the proceeding before the Commission and fully participated in it. Its contention that it did not have notice that this particular provision would be subject to the Commission's authority to approve QF contract terms is without merit.

¶ 70 The change in the testing temperature ordered by the Commission is matched in the final version of the PSA by a corresponding increase in the QF's net electrical generating capacity. That capacity must be made available to PSO year round. The Commission hence required capacity testing to be based on total annual hours rather than on summer hours. The Commission has authority under PURPA to make decisions of this nature and so long as they are supported by substantial evidence, they will not be disturbed on appeal.

XIII SUMMARY

¶ 71 The Commission's order stands on firm legal support as to issues resolved in Parts IV, VI, VII, IX, X, and XII and is affirmed insofar as it determines the issues discussed in these parts. Because the Commission failed to provide substantial record support of its calculation of avoided energy costs, and because certain of its directives are not sufficiently detailed to provide a basis for determining their conformity to PURPA and FERC regulations, the order is vacated as to the issues addressed in parts VIII and XI. The proceeding is remanded to the Commission for further inquiry to be conducted, and findings to be made, in a manner conformable to directions given in this pronouncement.

¶ 72 ORDER AFFIRMED IN PART AND VACATED IN PART; PROCEEDING REMANDED WITH DIRECTIONS TO CONDUCT FURTHER INQUIRY AND MAKE ADDITIONAL FINDINGS.

¶ 73 LAVENDER, HARGRAVE, KAUGER, EDMONDSON and COLBERT, JJ., concur.

¶ 74 WATT, C.J., WINCHESTER, V.C.J. and TAYLOR, J., concur in part and dissent in part.

TAYLOR, J., with whom WATT, C.J. and WINCHESTER, V.C.J., join, concur in part and dissent in part:

¶ 1 I dissent to the imposition of a twenty year contract term. I understand that the Corporation Commission has discretion on this issue. However, this contract is forced upon PSO due to the requirements of the 1978 federal law. It is not an arms-length contract. In view of all the law, evidence and circumstances of this case, I would hold that setting this contract term at twenty years is an abuse of discretion. A proper exercise of discretion would result in a contract being set at a much shorter term, subject to later review of the Commission.