EX-99.1 2 exhibit991.htm WUTC ORDER Exhibit99.1

[Service Date May 13, 2004]

BEFORE THE WASHINGTON STATE
UTILITIES AND TRANSPORTATION COMMISSION


WASHINGTON UTILITIES AND	)
TRANSPORTATION COMMISSION,	)	DOCKET NO. UE-031725
	)
Complainant,	)	ORDER NO. 14
	)
v.	)
	)	REJECTING TARIFF FILING,
PUGET SOUND ENERGY, INC.,	)	AUTHORIZING AND REQUIRING
	)	COMPLIANCE FILING, AND
Respondent.	)	REQUIRING PCA ACCOUNT
.............................................................................	)	ADJUSTMENT

SYNOPSIS: PSE’s as-filed rates in this docket are rejected and the Company is required to file revised tariff sheets that reflect a revenue deficiency of $44,112,960. The Commission determines that recovery of Tenaska costs is not subject to a fixed cap of original 1992 allowed contract costs. The Commission determines PSE did not prudently manage Tenaska gas costs PSE is required to adjust the PCA deferral account to reflect a one-time disallowance of $16,648,873 (grossed up for taxes to $25,613,650). Clear guidelines are established for recovery of future Tenaska costs. Commissioner Patrick J. Oshie concurs in part and dissents in part.

DOCKET NO. UE-031725	PAGE 2
ORDER NO. 14

TABLE OF CONTENTS
SUMMARY..................................................................................................3
MEMORANDUM...............................................................................................5
I. Background and Procedural History.............................................................5
II. Discussion and Decisions......................................................................6
A. Undisputed Issues.................................................................................6
B. Should there be an adjustment to the amounts PSE proposes to recover for power costs incurred in
connection with its Tenaska and Encogen assets?...................................................7
1. Tenaska Contract..........................................................................7
a. Staff's argument for disallowance of Tenaska costs that exceed what PSE was authorized to
recover under the original contract...................................................10
b. PSE's argument that there is no cap on costs recoverable under the Tenaska contract...12
c. Commission analysis and decisions.....................................................15
2. Should the Commission disallow Tenaska and Encogen costs based on imprudently managed gas supply
for Tenaska and Encogen.................................................................17
a. Tenaska Contract Restructuring........................................................17
b. Encogen Contract and Contract Restructuring...........................................21
c. Arguments by Staff, Public Counsel, and ICNU that PSE has imprudently managed gas supply for
Tenaska and Encogen...................................................................24
d. PSE's Argument that is has prudently managed gas supply for Tenaska and Encogen.......30
e. Commission Analysis and Decisions.....................................................34
i. Standards and Regulatory Principles...............................................34
ii. Tenaska...........................................................................36
iii. Encogen...........................................................................48
III. Conclusion...................................................................................49
FINDINGS OF FACT........................................................................................50
CONCLUSIONS OF LAW......................................................................................52
ORDER...................................................................................................54
COMMISSIONER PATRICK J. OSHIE, Concurring and Dissenting:...............................................55
APPENDIX 1.............................................................................................61
APPENDIX 2..............................................................................................62
APPENDIX 3..............................................................................................64

DOCKET NO. UE-031725	PAGE 3
ORDER NO. 14

SUMMARY

PROCEEDINGS: On October 24, 2003, Puget Sound Energy, Inc., filed revisions to its currently effective Tariff WN U-60. The filing proposed changes to PSE’s rates recovering the cost of power, as a result of its decision to purchase a new generating resource, and for other reasons. PSE requested expedited treatment of its filing, consistent with the terms of the Settlement Stipulation.

The Commission entered its Complaint and Order Suspending Tariff Revisions; Instituting Investigation; and Authorizing Discovery on October 29, 2004. The Commission conducted evidentiary hearings before Chairwoman Marilyn Showalter, Commissioner Richard Hemstad, Commissioner Patrick J. Oshie, and Administrative Law Judge Dennis J. Moss on February 23-26, 2004. The parties filed initial briefs on March 12, 2004, and reply briefs on March 19, 2004.

The Commission entered an order resolving all issues concerning the Company’s pending acquisition of a 49.85 percent interest in the Fredrickson I generating asset on April 7, 2004.¹ In that Order, the Commission expressly reserved its determination of the remaining issues that are unrelated to that acquisition—issues concerning costs associated with the Company’s Tenaska and Encogen assets. This Order determines those issues.

PARTY REPRESENTATIVES: Todd G. Glass, Heller Ehrman White & McAuliffe LLP, Seattle, Washington, represents PSE. S. Bradley Van Cleve and Matthew W. Perkins, Davison Van Cleve, Portland, Oregon, represent the Industrial Customers of Northwest Utilities. Norman Furuta, Department of the Navy, represents the Federal Executive Agencies. Michael Alcantar and Donald Brookhyser, Alcantar & Kahl LLP, Portland, Oregon, represent the Cogeneration Coalition of Washington (CCW). Simon ffitch, Assistant Attorney General, Seattle, Washington, represents the Public Counsel Section of the Washington Office of Attorney General. Robert D. Cedarbaum, Senior Assistant Attorney General, Olympia, Washington, represents the Commission’s regulatory staff.²

¹	WUTC v. Puget Sound Energy, Inc., Order No. 12: Granting Regulatory Approvals For Fredrickson I Acquisition; Resolving Disputed Gas Price Issue, Docket No. UE-031725 (April 7, 2004).

In formal proceedings, such as this case, the Commission's regulatory staff functions as an independent party with the same rights, privileges, and responsibilities as any other party to the proceeding. There is an "ex parte wall" separating the Commissioners, the presiding ALJ, and the Commissioners' policy and accounting advisors from all parties, including Staff. RCW 34.05.455.

DOCKET NO. UE-031725	PAGE 4
ORDER NO. 14

COMMISSION DETERMINATIONS: The Commission determines that recovery of Tenaska costs is not bound by an upper limit of original contract costs allowed in 1992. The Commission determines that PSE’s management of the Tenaska regulatory asset has been imprudent and that the full costs incurred during the July 2002 through June 2003 period are not reasonable. The Commission orders PSE to adjust its Purchase Cost Adjustment (PCA) deferral account balance established via partial settlement in Docket No. UE-031389 to reflect a disallowance of costs unreasonably incurred during the PCA period in the amount of $16,648,873 (grossed up for taxes to $25,613,650). The Commission establishes guidelines for recovery of future prudent Tenaska costs, including full recovery of return of the asset and equitable sharing of return on the asset if total costs exceed a historically based benchmark. The Commission disallows $9,921,067 of Tenaska related costs in determining the Company’s revenue deficiency for purposes of establishing rates in Docket No. UE-031725. The Commission allows full recovery of Encogen-related costs in determining the Company’s revenue deficiency for purposes of establishing rates in Docket No. UE-031725. The Commission determines a revenue deficiency of $44,112,960 and orders PSE to make a compliance filing to implement Schedule 95 rates designed to recover this amount.

DOCKET NO. UE-031725	PAGE 5
ORDER NO. 14

MEMORANDUM

Background and Procedural History³

On October 24, 2003, PSE filed revisions to its currently effective Tariff WN U-60, designated as Twenty Fifth Revised Sheet No. 95, and Original Sheet Nos. 95-a through 95-e. On October 29, 2003, the Commission suspended the effect of the proposed tariff sheets pending hearings in this proceeding.⁴

This filing, which PSE refers to as a PCORC Application, ⁵ proposes to change PSE’s rates recovering power costs. PSE has calculated a new Power Cost Rate that, in the Company’s view, accounts for the Fredrickson I acquisition, updates expenses to account for current power costs (only some of which are attributable to the acquisition), and corrects the allocation for production-related costs.

On January 14, 2004, the Commission entered its Order No. 04 Accepting and Adopting Settlement in Docket No. UE-031389, PSE’s first annual true-up of actual power costs under the Power Cost Adjustment mechanism (PCA), as required by Commission Order in PSE’s most recently completed general rate proceeding.⁶ This was a partial settlement. The settling parties were unable to agree in Docket No. UE-031389 on a methodology to determine the costs of power for the Tenaska and Encogen generating resources. The parties agreed that power cost issues related to those resources would be determined in this proceeding.

³	The Commission discussed the full procedural history in Order No. 12, see, supra note 1.

⁴	PSE, as noted in the Commission's suspension order, bears the burden of proof to show that the increases it proposes are fair, just and reasonable. RCW 80.04.130(2).

⁵	PCORC is an acronym for "Power Cost Only Rate Case."

⁶

Washington Utilities and Transportation Commission v. Puget Sound Energy, Inc., Docket Nos. UE-011570 and UG-011571 (consolidated), Twelfth Supplemental Order: Rejecting Tariff Filing; Approving And Adopting Settlement Stipulation Subject To Modifications, Clarifications, And Conditions; Authorizing And Requiring Compliance Filing (June 20, 2002).

DOCKET NO. UE-031725	PAGE 6
ORDER NO. 14

Following evidentiary proceedings on February 23-26, 2004, and briefing, the Commission entered its Order No. 12 in this proceeding, granting all of the regulatory approvals that PSE requested for the Fredrickson I acquisition to be consummated. The Commission found the acquisition prudent and found reasonable the associated costs that PSE proposed to include in rates.

We expressly reserved for determination in a separate order the disputed issues in this proceeding that are wholly unrelated to the Fredrickson I acquisition. Those issues raise the question: Should there be an adjustment to the amounts PSE proposes to recover for power costs incurred in connection with its Tenaska and Encogen assets? Bifurcating our decision process in this fashion cleared the way for PSE to move forward with the Fredrickson I acquisition, yet afforded the Commission additional time necessary to deliberate fully on the Tenaska and Encogen issues. We have now completed our deliberations.

II.

Discussion and Decisions

Undisputed Issues

The Commission, in its Order No. 12, found and concluded that PSE’s acquisition of an interest in Fredrickson I is prudent and that the associated costs PSE seeks to include in rates are reasonable. Other adjustments the Company proposed to its power cost baseline either were initially uncontested or are now uncontested. The Commission approved a stipulation between PSE and Staff on the issue of a weather normalization adjustment in Order No. 10, entered on February 11, 2004. Other adjustments, set out in Table I, were resolved by informal agreements between PSE and Staff, and are uncontested by any other party.

DOCKET NO. UE-031725	PAGE 7
ORDER NO. 14

TABLE I: Uncontested Adjustments

PCA Baseline Costs	Amount

Per Books (test year)	$ 862,035,357

Adj - 1 Power Costs	(156,165,127	)

Adj - 2 Sales for Resale	152,198,362

Adj - 3 New Plant (Frederickson 1)	42,368,805

Adj - 4 Transmission Income	3,253,602

Adj - 5 Prod. Plant Deprec./Amort	(65,231	)

Adj - 6 Property Taxes	152,265

Adj - 7 Montana Energy Tax	86,743

Adj - 8 Property Insurance	126,210

Adj - 9 White River	208,049

Adj - 10 Reg. Assets/ Acq. Adj	(3,521,669	)

Adj - 11 Production Adjustment	(1,353,716	)

We find these proposed adjustments reasonable. They should be authorized for recovery in rates, subject to any adjustments that may be required in light of our decisions here.⁷

Should there be an adjustment to the amounts PSE proposes to recover for power costs incurred in connection with its Tenaska and Encogen assets?

Tenaska Contract

⁷	We acknowledged the possibility that such adjustments might be required in Order No. 13, entered in this proceeding on April 19, 2004. The Commission, by separate notice issued today, has scheduled an order conference to ensure that PSE's compliance filing can be accurately prepared and presented.

In 1991, PSE⁸ entered into a 20-year contract to purchase power from Tenaska Washington Partners, L.P.‘s 245 MW natural gas-fired cogeneration facility in Whatcom County. The contract provided for definite prices for power over the contract term with price escalations at fixed amounts to occur on an annual basis.⁹ PSE filed a general rate case in 1992 seeking, among other things, to recover in its rates the costs of various new power supply resources. In its 11th Supplemental Order in that proceeding, the Commission found that PSE had failed to carry its burden to prove that these acquisitions were prudent.¹⁰ However, the Commission allowed PSE an opportunity to submit additional evidence on prudence and included the Tenaska contract in its subsequent review.¹¹

In 1994, in its 19th Supplemental Order in Docket No. UE-921262 the Commission held, among other things, that PSE’s decision to enter into the Tenaska contract was imprudent.¹² PSE argues here on brief that the sole basis for this determination was the Commission’s finding that “Puget paid too much for the Tenaska Agreement because it should have ‘factor[ed] in the value of dispatchability.’"¹³ Although dispatchability was a factor in the Commission’s determination of imprudence, it was not the sole factor. As Staff argues, “the Commission’s holding was directed to the fundamental nature of Puget’s decision-making and management.”¹⁴ Indeed, the Commission’s Prudence Order includes extensive discussion of PSE’s mismanagement of its new resource acquisitions, including Tenaska, which the Commission summarized briefly in its Finding of Fact No. 5 as follows:

⁸	PSE was then known as Puget Sound Power& Light Company.

⁹	Exhibit Nos. 5C (pp. 16-17) and 283C (pp. 14-15), which are, respectively, copies of Exhibit B to PSE's Revised and Original Accounting Petitions in Docket No. UE-971619, show in lines 2 and 4, respectively, the escalating power and gas prices under the original contract for the 1998-2011 period..

¹⁰	WUTC v. Puget Sound Power & Light Company, 11th Supplemental Order, Docket Nos. UE-921262, et al. (1993).

¹¹	WUTC v. Puget Sound Power& Light Company, 18th Supplemental Order, Docket Nos. UE-921262, et al. (1994).

¹²	We refer to the 19th Supplemental Order in Docket No. UE-921262 as the "Prudence Order."

¹³	PSE Initial Brief at 19; see also Id. at 21.

¹⁴	Staff Initial Brief at 4.

Puget has not carried the burden to demonstrate that its new resource acquisitions were prudent. Puget mismanaged its contract selection and evaluation. Puget was imprudent in its failure to move from the flexible planning process to a rigorous, specific evaluation of the merits of resources at the time their acquisition was being considered. The company’s decision-making process was not adequate and was not adequately documented.

The Commission concluded as a matter of law that “Puget failed to carry its burden of proof to demonstrate its new power purchases were prudent. Puget’s mismanagement of its resource acquisition process was imprudent.”¹⁵

14	The fundamental basis for the Commission’s determination that PSE was imprudent in its resource acquisitions was that the Company:

paid too much for the Tenaska and March Point Phase II contracts. These resources were not purchased through a competitive bid; the clear standard applied to them as qualifying facilities is that they must cost less than Puget’s avoided cost. Puget’s general avoided cost must be properly adjusted to review the price of the purchased resources. As discussed in the following sections, the properly adjusted avoided cost is lower than the price Puget paid for the contracts.¹⁶

The value of dispatchability, which the Commission found PSE had imprudently failed to take into account in assessing avoided costs, became a useful measure in the Commission’s analysis of what disallowance should be ordered given the range of possible remedies proposed by various parties to the proceeding. In its final analysis, the Commission concluded that the Tenaska contract price, among others, “should be adjusted for ratemaking purposes to disallow the excessive costs caused by the company’s imprudent actions.”¹⁷ The Commission’s remedy, selected from a range of options proposed by the parties, was to exclude a portion of the costs it found associated with dispatchability. The Commission required that in future ratemaking there would be a disallowance of 1.2 percent of the “net cost of the [Tenaska] contract.”¹⁸

¹⁵	WUTC v. Puget Sound Power & Light Company, 19th Supplemental Order, Docket Nos. UE-921262, et al. (1994).

¹⁶	Id. at 25 (emphasis supplied).

¹⁷	Id. at 47.

¹⁸	Id. at 45-46; WUTC v. Puget Sound Power& Light Company, 20th Supplemental Order, Docket Nos. UE-921262, et al. (1994) at 22.

In 1997, PSE filed a petition with the Commission seeking authority to buy out the gas supply contract that established part of the Company’s fixed-payment obligations over the life of the contract. PSE proposed that the contract buyout costs would be treated as a regulatory asset on the Company’s books for recovery in rates over the remaining contract term. PSE assumed responsibility to manage prudently the acquisition of gas to fuel Tenaska to meet the Company’s energy supply needs. The Commission approved PSE’s petition. We discuss this contract restructuring in more detail below in connection with the dispute concerning whether PSE prudently managed its obligations after 1997 and through the test year. First, however, we will resolve the issue of whether the original contract and the Commission’s Prudence Order established a “cap” on the costs PSE could be authorized to recover.

Staff’s argument for disallowance of Tenaska costs that exceed what PSE was authorized to recover under the original contract.

Staff argues that the effect of the Prudence Order was to establish an upper limit, or cap, on the amount PSE was authorized to recover over the life of the Tenaska contract.¹⁹ This concept is grounded in three points, taken together: (1) the Commission concluded in the Prudence Order that the Tenaska contract prices “should be adjusted for ratemaking purposes to disallow the excessive costs caused by the company’s imprudent actions,”²⁰ (2) the Commission’s Prudence Order established a disallowance from the fixed amounts provided under the Tenaska contract over its full term, and (3) the Tenaska contract was a “‘take and pay’ agreement at a constant escalating price for energy.”²¹

Staff states that the disallowance ordered in Docket No. UE-921262 “was based upon a comparison of the cost of the plant to the Company’s avoided cost, the latter setting the ceiling for recoverable Tenaska power supply costs.”²² Staff argues that the Commission focused on avoided costs as a measure of prudent decision making in connection with the Company’s acquisition of power from qualifying facilities under PURPA, and quotes the Commission’s observation in its Prudence Order that “the clear standard applied to [the Tenaska and March Point Phase II contracts] is that they must cost less than Puget’s avoided cost.”²³

Measured against the actual costs PSE seeks to recover for Tenaska during the relevant periods, Staff recommends under its contract cap theory that the Commission disallow $22,089,509 for the PCA period ended June 30, 2003,²⁴ and $19,842,000 for the 12-month PCORC rate period ending April 2005.²⁵ The result in the PCORC proceeding would be to reduce the $54,481,144 revenue requirement that PSE requests to $33,725,505. The Power Cost Rate established through the PCA proceeding would be adjusted to $47.763 per MW, compared to $48.840 per MW that would result from taking into account the adjustments to which PSE agreed during the course of this proceeding.²⁶

¹⁹	Public Counsel and ICNU support Staff's contract-cap argument, though these parties focus their briefs on recommendations for alternative forms of relief grounded in the restructuring of the Tenaska contract in 1997. The restructuring theory of the case and proposed remedies are discussed below.

²⁰	19th Supplemental Order, Docket Nos. UE-921262, et al., supra., at 47; Staff Initial Brief at 5.

²¹	Staff Initial Brief at 7 (citing TR. 374).

²²

Id.

²³	Id. at 8 (quoting from WUTC v. Puget Sound Power & Light Company, 19th Supplemental Order, Docket Nos. UE-921262, et al. (1994) at 24-25 with emphasis added).

²⁴

This is the time period covered by the Company's Power Cost Adjustment annual review in Docket No. UE-031389. Issues related to Tenaska and Encogen were carved out of the settlement adopted by the Commission in that proceeding and set for hearing in this proceeding. In the Matter of the Petition of Puget Sound Energy, Inc. for approval of its 2003 Power Cost Adjustment Mechanism Report, Order No. 4 (January 14, 2004).

²⁵	Id. at 1-2 (citing Exhibit Nos. 301HC at 9-15; 303HC; 304HC; and 312 at 2, column entitled "New Adjustment 12--UE-921262 Adjustment").

²⁶	The Commission's calculations of these amounts are based on adjustments to Exhibit No. 318.

PSE’s argument that there is no cap on costs recoverable under the Tenaska contract.

PSE proffers three lines of argument on this issue in its Initial Brief. First, PSE argues that Staff has “reinterpreted the Prudence Order in a manner that is inconsistent with that Order’s plain language.”²⁷ PSE argues that because the Commission did not express “the disallowance in terms of such a cap,” but rather expressed it in terms of a percentage of costs, Staff’s interpretation should be rejected.²⁸

Second, PSE argues that it “has consistently interpreted the Prudence Order to require a straightforward 1.2% disallowance of the net contract charge,” and “the Commission has consistently accepted PSE’s calculation.”²⁹ Two of the three cases PSE cites to support this argument, however, were the so-called PRAM 4 and PRAM 5 proceedings. These proceedings were concluded prior to any change in the original Tenaska contract. The PRAM 4 and PRAM 5 proceedings included PSE’s costs under the original Tenaska contract, adjusted in accordance with the 1994 Prudence Order. It follows that the Tenaska costs considered in PRAM 4 and PRAM 5 proceedings were at or below the level Staff identifies in this proceeding as the “contract cap.” Thus, there simply would have been no basis for anyone to advocate a disallowance of some portion of the Tenaska costs in the PRAM proceedings under the contract-cap theory Staff advances in this proceeding.

The third proceeding PSE cites is its most recently completed general rate proceeding in consolidated Docket Nos. UE-011570 and UG-011571. That proceeding came after the time when the original Tenaska contract was restructured in 1997, and at the end of the merger Rate Plan period during which PSE was barred from general rate filings that might have sought to recover Tenaska costs that exceeded those fixed by the original contract, as adjusted by the Prudence Order. If PSE sought to include Tenaska costs that exceeded what it would have recovered under the original contract, as adjusted, a challenge under a contract cap theory arguably could have been made by Staff, or others, as PSE implies. However, while it is true that costs associated with Tenaska were not challenged under a contract cap theory in the general rate case, our record in this proceeding does not disclose whether the as-filed Tenaska costs in Docket No. UE-011570 exceeded those the Company would have incurred under the original contract, as adjusted.

Docket No. UE-011570 was resolved by the Commission’s approval and adoption of a settlement agreement. PSE argues that “Staff and other parties audited the power cost calculations in PSE’s baseline power costs, which included the 1.2% disallowance, and agreed that the costs were properly calculated.”³⁰ Again, this does not tell us, and PSE cites us to nothing in our record that tells us, whether the Tenaska costs exceeded those that would have been allowed under the original contract, as adjusted. Moreover, because the case was resolved via a Commission-approved settlement, we cannot draw any necessary inference relevant here from the fact that no one expressly challenged Tenaska-related costs under a contract cap theory.

²⁷	PSE Initial Brief at 21.

²⁸	Id. at 22.

²⁹

Id.

³⁰	Id. at 22-23.

23	PSE's third argument is that:

Even if the 1994 Prudence Order had imposed a cost cap, the 1997 restructuring of the Tenaska Agreement fundamentally reformed the facility’s fuel supply and accounting treatment – and, in so doing, eliminated any possible basis for thereafter applying such a cap.³¹

The significance of this argument lies in the fact that after PSE bought out the Tenaska fuel supply contract, the prices PSE would pay for power under the contract were no longer fixed. Thus, one of the three facts upon which Staff’s argument relies ceased to be true after restructuring.

PSE cites to Mr. Schooley’s testimony in response to questions from the Bench for the proposition that such contract restructuring could be a basis upon which “the matter of the cost cap ‘can be reopened.’"³² PSE acknowledges that it has not previously petitioned the Commission to reopen the issue, but explains this by arguing that the Company simply did not know until now that anyone would argue “that the Prudence Order imposed a cost cap that would be applied to the restructured Tenaska contract.”³³ PSE argues:

A similar conclusion should be reached in this proceeding. Even assuming for the sake of argument that the Prudence Order may have imposed a cost cap at one time, the 1997 reformation and the Company’s amendment of the contract to move from fixed to variable fuel pricing eliminated any basis for thereafter applying such a cap. Indeed, had PSE known in 1997 that any party would later assert that the Prudence Order imposed a cost cap that would be applied to the restructured Tenaska contract, including the regulatory asset created at the time of the buyout, it presumably would have petitioned the Commission to reopen that issue at the time it filed its accounting petition.³⁴

Commission analysis and decisions

³¹	Id. at 23.

³²	Id. at 23-24..

³³	Id. at 24.

³⁴

Id.

The matter of the relationship between the original contract, which arguably imposed a cap at 1.2 percent below PSE’s net contract costs within fixed parameters, and the relevance of that fact after the restructuring of the contract in 1997, are matters squarely before us today. It is not essential to our decision, however, to determine whether our Prudence Order established an absolute cap or merely a 1.2% disallowance on future Tenaska costs, whatever they might be. Once the fixed cost parameters were removed under the restructuring proposal that the Commission approved in 1997, an essential element supporting Staff’s contract-cap theory was eliminated. Thus, we reject Staff’s contention that the original contract prices, adjusted per the Prudence Order in 1994, establish an absolute cap on PSE’s recovery of costs related to Tenaska.

This does not mean that the original contract loses all meaning for the post-restructuring period. The rationale for creating the Tenaska regulatory asset, advanced by PSE and accepted by the Commission, was that the restructuring costs to be borne by future ratepayers would be more than offset by savings relative to what those customers would have to pay under the original contracts.

PSE and the Commission understood that there were risks associated with this rationale. As PSE explained during the Commission’s Open Meeting at which the Company presented its petition for the Tenaska accounting order, PSE did not intend to lock in then-available long-term gas prices. Responding to questions from the Commission, the Company said it intended to “go to market” which might result, at a given point in time, in savings greater or less than those projected. Nevertheless, the Company certainly should have understood that achieving savings for customers, as well as providing benefits to shareholders, had to be one of its key goals in prudently managing gas supply.

Indeed, the amortization schedule established via restructuring to allow for PSE’s recovery of the contract buyout costs was designed to spread projected savings, relative to the original contract prices, equitably over the life of the contract.³⁵ That is, the amortization schedule was set up to effect a match between anticipated benefits and known costs. Customers paying rates during periods when PSE projected steadily increasing savings would pay steadily increasing parts of the investment. As we elaborate below, it is appropriate to consider the original contract prices as a benchmark in the context of periodic PCA, PCORC, or other rate proceedings.

We find that the original contract establishes an equitable benchmark of which we are mindful as we evaluate Staff and other parties’ arguments that PSE has not prudently managed the acquisition of gas supply, resulting in no savings to customers (compared to original expectations) during the PCA and PCORC periods. We return to this point in our analysis below concerning whether the Company has prudently managed its fuel acquisition for Tenaska through the PCA period and the PCORC test period, and, if not, whether to disallow some part of PSE’s Tenaska-related costs.

³⁵	Exhibit No. 301HC (Schooley) at 8:14-16.

Should the Commission disallow Tenaska and Encogen costs based on imprudently managed gas supply for Tenaska and Encogen.

Staff’s alternative recommendation, supported by ICNU and Public Counsel, is that the Commission should disallow certain “excess” costs in the PCA period, and certain fuel costs in the PCORC rate period, based on assertions that PSE has imprudently managed fuel acquisition for Tenaska and Encogen since the restructuring of contracts associated with those projects in 1997 and 1999, respectively. Insofar as Staff is concerned, this is an alternative proposal that would make the Tenaska adjustment discussed above unnecessary.³⁶ ICNU supports a fuel cost disallowance for Tenaska, but its primary request for relief is to eliminate (i.e., write off) the regulatory asset.

Because it provides important context, we discuss in some detail the background of the Tenaska restructuring in subsection II.A.2.a., below, and the Encogen restructuring in subsection II.A.2.b. In subsection II.A.2.c., we discuss the arguments made by Staff, ICNU, and Public Counsel that PSE has not managed Tenaska and Encogen fuel acquisition prudently, has failed to achieve any of the savings projected at the time those contracts were restructured, and should not be allowed full recovery of those costs for purposes of PCA accounting and PCROC rates. In subsection II.A.2.d., we discuss PSE’s arguments on these issues. Our analysis and determination of the issues is in section II.A.2.e.

Tenaska Contract Restructuring

On November 10, 1997, PSE filed in Docket No. UE-971619 its Petition for an Order Regarding the Accounting Treatment for the Purchase of a Gas Sales Contract. The Petition concerned PSE’s proposal to buy out the gas supply contract under which the Tenaska cogeneration facility procured fuel for a term coincident with PSE’s power purchase agreement (i.e., through 2011).

³⁶	Staff Initial Brief at 3, fn. 4 (citing Exhibit No. 281 at 5 (Elgin); TR. 526-28 (Elgin).

Reduced to its essence, PSE’s proposal was that it would pay $215 million to buy out the gas supply contract and thereafter manage the acquisition of gas supply for Tenaska on its own. As described in PSE’s Petition, “The transaction, which is scheduled to close on or before December 31, 1997, provides the Company with the opportunity to achieve a restructuring of the power purchase agreement for the cogeneration project that will produce significant savings for customers.”³⁷

34	According to its revised Petition, PSE proposed that the Company be allowed, for accounting and ratemaking purposes, to:

(a)	Capitalize, for recovery in rates, the purchase price paid by the Company for the gas supply contract;

(b)	Earn a return, at a debt rate, on one half the deferred balance for the first five years;

(c)

Commence amortization of the deferred balance (including the debt return and the capitalized purchase price) in the first year based on the proportionate amount of gas cost savings less interest expense in each year as compared to the total amount in all years as set forth in Exhibit H. The unamortized balance will be included for ratemaking purposes for recovery in any future proceedings;

(d)	Flow through, for tax purposes, the straight-line tax amortization of the purchase price.³⁸

³⁷	Exhibit No. 5C (revised Petition, Docket No. 971619) at 2; Exhibit No. 283 (original Petition, Docket No. 971619) at 2.

³⁸	Exhibit No. 5C at 40.

It is important to understand the context for this proposal. Earlier in 1997, the Commission had approved PSE’s merger with Washington Energy Company and Washington Natural Gas Company, a natural gas distribution company.³⁹ In its order approving the merger, the Commission also approved a 5-year Rate Plan (1997-2001) under which it was anticipated PSE would not file a general rate case for general tariff revisions to be effective until after December 31, 2001.⁴⁰Thus, it was anticipated at the time of the proposed restructuring in 1997 that PSE’s rates would continue to reflect recovery of costs for Tenaska based on the original 1991 contract and the Commission’s 1994 Prudence Order until PSE’s next general rate proceeding established rates for service effective sometime after December 31, 2001.

Any cost savings PSE could achieve during the Rate Plan period after restructuring the Tenaska contract would immediately benefit the Company’s shareholders, but not its customers. On the other hand, PSE’s shareholders would absorb amortization costs (i.e., return of the asset) during the Rate Plan period, and would capitalize a debt return on one-half of the capitalized purchase price instead of recovering in rates a return on the full balance. Amortization, however, was structured so that it would escalate over time, as would the projected cost savings.

³⁹	In the Matter of the Application of Puget Sound Power & Light Company and Washington Natural Gas Company, 14th Supplemental Order Accepting Stipulation; Approving Merger, Docket No. UE-960195 (February 5, 1997).

⁴⁰	PSE, in fact, did not make its next general rate filing for electric or gas service until November 26, 2001, in Docket Nos. UE-011570 and UG-011571 (consolidated), with a stated effective date of December 27, 2001.

Because there would be a relatively small amount of amortization during the first five years, the capitalized costs that would be included on PSE’s books for ratemaking purposes at the end of the Rate Plan period would actually be greater than the initial buyout costs. In other words, as a practical matter, PSE ultimately would have the opportunity for full recovery of amounts that equaled—and slightly exceeded—its capitalized buyout costs, though it would not have the opportunity for full recovery on those capitalized costs as part of its rate base until after 2001. ⁴¹

PSE’s Petition came before the Commission as an Open Meeting item on December 10, 1997. Although Staff expressed its belief that “it is inadvisable for the Commission to authorize new regulatory assets,” Staff supported PSE’s Petition because “the savings in gas costs more than offset the regulatory asset.”⁴² The Commission granted PSE’s Petition.⁴³ The Commission’s Order included the following in its ordering paragraphs:

The Company’s actions in purchasing the gas sales contract, managing the cost of gas, and restructuring the power purchase agreement is [sic] subject to review in future rate proceedings; the Company bears the burden of proof in any such proceeding regarding these matters. Any costs determined to be unreasonable or imprudent in such proceedings are subject to disallowance.

The Commission’s approval of the instant petition does not in any manner modify or affect the Commission’s prior orders regarding standards or burden of proof in determining whether costs of a utility were imprudent or unreasonable, e.g., Washington Utilities and Transportation Commission v. Puget Sound Power & Light Company, Docket Nos. UE-920499, UE-921262 (September 27, 1994).⁴⁴

⁴¹

Although it is not entirely clear from our record, it appears that the settlement the Commission approved in 2002 to resolve Docket No. UE-011570 reflects actual costs PSE incurred in connection with Tenaska during the test year considered in that proceeding, adjusted for the 1.2 percent disallowance ordered in Docket No. UE-921262; return of the Tenaska regulatory asset as provided under the accounting order approved in Docket No. UE-971619; and return on the regulatory asset at 7.30 percent, the overall return provided for in the Commission-approved settlement in Docket No. UE-011570. PSE Initial Brief at 22-23; Exhibit No. 5C at 1, 47.

⁴²	Exhibit No. 283C at 18.

⁴³	In the Matter of the Petition of Puget Sound Energy, Inc., for an Order Regarding the Accounting Treatment for the Purchase of a Gas Sales Contract, Order, Docket No. UE-971619 (December 15, 1997).

⁴⁴	Id. at 6.

Encogen Contract and Contract Restructuring

In connection with its active participation in the Commission’s undertaking in 1989 to revise rules implementing PURPA, PSE used a Commission-approved pilot bid process to test the efficacy of certain proposed rules. At the end of the process, PSE selected a bid from Encogen Northwest, L.P., owner of a cogeneration project in Whatcom County, and executed a contract in September 1990 to purchase the cogeneration facilities’ electric output. Encogen, like Tenaska, was among the resource acquisitions the Commission reviewed under the prudence standard in Docket No. UE-921262. The Commission, for various reasons articulated in its Prudence Order, determined that it would not disallow any of the costs of the Encogen project.⁴⁵

On September 29, 1999, PSE filed a petition for an order regarding accounting and ratemaking treatment in connection with PSE’s purchase of the Encogen cogeneration project. According to the Petition, the transaction was scheduled to close on or before November 1, 1999, and would provide PSE with the opportunity to reduce the effective cost of purchases and produce savings with a net present value of approximately $27 million in revenue requirement over the then-remaining 23-year useful life of the cogeneration project. The Commission granted PSE’s petition in Docket No. UE-991498 by order entered on October 27, 1999. ⁴⁶ However, the Commission’s third and fourth ordering paragraphs state:

⁴⁵

Id. at 19. The Commission's ultimate findings of fact and conclusions of law do not expressly distinguish PSE's contract with Encogen when finding and concluding that PSE failed to carry its burden to demonstrate its new power purchases were prudent, and that its mismanagement of its resource acquisition process was imprudent.

⁴⁶

Petition of Puget Sound Energy, Inc. For an Order (1) Approving Proposed Accounting Treatment for the Purchase of a Cogeneration Project, and (2) Authorizing Assumption of Securities Under RCW 80.08.130, Order Approving Accounting Treatment And Securities Assumption Authorization, Docket No. UE-991498 (October 27, 1999).

3.	The Company’s actions in purchasing the cogeneration project are subject to review in future rate proceedings. Any costs determined to be unreasonable or imprudent in such proceedings are subject to disallowance.

The Commission’s approval of the instant petition does not in any manner modify or affect the Commission’s prior orders regarding standards or burden of proof in determining whether costs of the utility were imprudent or unreasonable, e.g., Washington Utilities and Transportation Commission v. Puget Sound Power & Light Company, Docket Nos. UE-920499, UE-921262 (September 27, 1994).

In December 1999, following its acquisition of the Encogen cogeneration facility, PSE filed another petition for an accounting order. This petition concerned the Company’s proposal to accept assignment of a gas purchase agreement from Cabot Oil & Gas Marketing Corporation, which had a long-term contract to furnish a significant part of Encogen’s fuel requirements. According to PSE’s Petition, the proposed assignment would allow PSE to reduce purchased gas costs at the facility, resulting in net savings over the remaining term of the gas purchase agreement, through 2008. PSE agreed to pay Cabot $12 million for the assignment and expected to incur expenses of approximately $906,000 in connection with the transaction.

The restructuring of the Encogen gas contract requires our focus in this proceeding. As in the case of the Tenaska contract restructuring, PSE’s buyout of the Cabot contract meant that the Company would be responsible for managing the cost of gas on a prospective basis. The idea was that over the remaining term of the contract PSE would obtain fuel for Encogen at a sufficient savings to offset, or more than offset, the return of and return on the regulatory asset. PSE estimated the net savings to customers to be $7.5 million.

42	The Commission approved PSE’s Petition by order entered in Docket No. UE-991918 on December 29, 1999.⁴⁷ Under the terms of the Commission’s order, PSE would:

(a)	Capitalize, for recovery in rates, the purchase price paid by the Company for the Gas Purchase Agreement (including transaction costs incurred by the Company);

(b)	Commence amortization of the purchase price immediately;

(c)	Capitalize the interest costs at a rate of 8% on the net regulatory assets for three years;

(d)

Commence amortization of the deferred balance (including capitalized interest and the capitalized purchase price) based on the gas cost savings less interest expense in each of the remaining years as set forth above.⁴⁸ The unamortized balance will be included for rate making purposes for recovery in any future proceedings at the then-authorized rate of return.

Again, as in the case of Tenaska, the Commission’s approval of PSE’s Petition was grounded in the Company’s representation that significant cost savings could be obtained. In this connection, the Commission’s order stated in its third and fourth ordering paragraphs:

⁴⁷	Petition of Puget Sound Energy, Inc. For an Order Regarding the Accounting Treatment for the Assignment of a Gas Purchase Agreement from Cabot Oil&Gas Marketing Corporation, Order Approving Accounting Treatment, Docket No. UE-991918 (December 29, 1999).

⁴⁸	The amortization schedule was stated as follows: 2000--2.06%; 2001--4.97%; 2002--7.20%; 2003--9.52%; 2004--11.98%; 2005--14.68%; 2006--17.78%; 2007--20.96%; and 2008--10.85%.

As in the case of Tenaska, PSE committed to take over management of fuel supply for Encogen on a prospective basis for the benefit of the Company and its customers. Staff argues that imprudent management by PSE of the underlying fuel gas costs has resulted in customers not benefiting from the savings projected by PSE in 1999 in support of its petition to restructure the Encogen fuel supply contract. We discuss these arguments, and PSE’s arguments to the contrary, in the next two sections of our Order.

Arguments by Staff, Public Counsel, and ICNU that PSE has imprudently managed gas supply for Tenaska and Encogen.

Relying on Mr. Gaines’s statements on cross-examination, Staff asserts that “The Company agrees that the fundamental basis for the Tenaska restructuring was the expectation that the transaction would save substantial money for ratepayers.”⁴⁹ Staff says PSE’s Tenaska restructuring petition was unambiguous in stating that approval of the creation of the proposed regulatory asset would allow the Company to significantly reduce the cost of fuel for the benefit of ratepayers. This assertion was grounded in an economic analysis of fuel supply savings based on “then available forward market price quotes for a long-term supply of replacement gas.”⁵⁰ The projected savings were more than sufficient to offset PSE’s recovery of the return of and on the regulatory asset over time. According to Staff, it was on this basis that Staff supported and the Commission approved the proposed restructuring.⁵¹ Staff cites confidential information from PSE’s Risk Management Committee (RMC) meetings to show that the Company understood that it had created expectations of savings based on long-term forward prices presented in support of the restructuring petition.⁵²

⁴⁹	Staff Initial Brief at 15 (citing TR. 232 and 296-97).

⁵⁰	Id. at 15-16 (citing Exhibit No. 283C at 19P. 8 and 25-27).

⁵¹	Id. at 17-18.

⁵²	Id. at 18-19.

Staff makes similar arguments with respect to PSE’s buyout of the gas supply contract for Encogen late in 1999. As in the case of Tenaska, in its petition for an accounting order, the Company asked the Commission to approve creation of a regulatory asset that would be recovered from future ratepayers on a schedule tied to projected savings based on long-term contract prices then available to the Company. Again, however, the Company did not commit to secure immediately a locked-in supply, but rather to take on the responsibility for prudent management of the gas supply following the buyout.

Staff argues, considering the Commission’s prudence standard, that it is reasonable to expect PSE to have developed “a long-term strategy for gas procurement that would reasonably have met the economic analyses the Company presented” to justify the restructuring petitions.⁵³ Staff argues PSE was imprudent in managing its fuel supply for Tenaska and Encogen by failing to adopt a strategy to protect long-term benefits to ratepayers, relying instead on spot and near-term markets so as to maximize earnings for shareholders during the 1997 – 2001 Rate Plan period.⁵⁴ The evidence that PSE, in fact, managed Tenaska gas supply relying exclusively on spot and short-term purchases is not disputed. PSE’s management of gas supply for Encogen, on the other hand, included early implementation of an approach that included acquiring some long-term supply shortly after the contract buyout was approved.⁵⁵

The Tenaska and Encogen contracts were restructured in 1997 and 1999, respectively. Yet, Staff argues, “As late as 2000, the Company did not comprehend the risk of managing the fuel supply for those facilities.”⁵⁶ Staff cites to a series of quotations from confidential RMC meeting minutes that support this argument, at least with respect to Tenaska, and demonstrate that PSE did not, in fact, have an effective risk management strategy in place as of mid-year 2000.⁵⁷

Beginning in mid-2000, PSE sought assistance in developing a risk management strategy, employing the consulting services of Merchant Energy Group of the Americas, Inc. (MEGA). “Unfortunately,” Staff states, “the Company ignored MEGA’s advice.”⁵⁸ MEGA’s analyses, as reflected in confidential RMC meeting minutes, focus on the risks associated with market volatility, over-reliance on any single market element (i.e., short, intermediate, or long term), and trying to time the market.⁵⁹ Staff argues that PSE failed to develop a strategy that reflected the concerns MEGA expressed and continued to procure gas only in spot and near-term markets. Staff states:

⁵³	Staff Initial Brief at 23.

⁵⁴

Id. at 12, 23, 26-28. Staff states that the Company's early management of the fuel supply following restructuring is relevant today because it "eliminated then-present and later opportunities for the Company to reduce ratepayers' exposure to rising fuel prices after the rate plan." Id. at 12-13.

⁵⁵	Exhibit No. 77C at 50-52.

⁵⁶	Id. at 28.

⁵⁷	Id. at 28-31. (citing to excerpts from Exhibit No. 77C).

⁵⁸	Id. at 31.

⁵⁹	Id. at 31-32 (citing to excerpts from Exhibit Nos. 63C and 77C).

As late as December 13, 2001, the [RMC] recommended long-term hedges for the entire gas requirement for Tenaska (50,000 MMBtu/day) for the entire period 2003-2011. . . Despite analysis that showed that long-term hedges could be obtained at prices that would result in internal rates of return [that were positive], the Company declined to adopt that recommendation.⁶⁰

The “strategy” discussed at the December 13, 2001, RMC meeting with respect to what MEGA recommended for Tenaska, assumed a bearish market that would allow the Company to better the then-market price by 10 percent. It is unclear whether PSE actually implemented this strategy.⁶¹ In any event, PSE’s assumption about the market did not materialize. Thus, while PSE was advised to go long on gas for Tenaska, the approach it adopted reflected continued complete reliance on market timing. Given the dramatic demonstration during the mid-2000 through early 2001 period of the enormous risk of a gas purchase program that relies on market timing, PSE’s decision to consider following MEGA’s advice only if it could beat the market by a significant margin was, according to Staff, not prudent.

⁶⁰

Id. at 33 (The omission at the third line and the insertion at the fifth line of this excerpt from Staff's Brief are necessary to protect confidential information Staff quotes from Exhibit No. 77C; Staff also cites to confidential TR. 135-36, 187, 283-84, and 405). Staff notes Mr. Gaines's testimony (TR. 314:9-12) that positive internal rate of return, in this connection, means results that benefit ratepayers even taking into account return on and of the Tenaska regulatory asset.

⁶¹	See infra.P. 62.

Staff’s proposed remedy under its imprudence theory, presented principally through Mr. Elgin’s testimony and supported by Mr. Schooley’s calculations, is to disallow all costs associated with Tenaska and Encogen that exceed the projected savings presented in connection with the respective restructuring petitions. This would result in a fuel cost adjustment during the PCORC period of approximately $38,500,000 for Tenaska and $7,200,000 for Encogen.⁶²

ICNU argues in a vein similar to Staff, pointing to evidence showing that the effective cost of power from Tenaska as of the PCORC period is significantly higher than the cost would have been under the original contract that was restructured in 1997.⁶³ The higher costs, ICNU argues, are “a direct result of a repeated gamble by PSE on the short-term market to meet its Tenaska gas requirements.”⁶⁴ ICNU contends that PSE’s restructuring petition and supporting study based on long-term markets has the attributes of a “firm commitment” or guarantee.⁶⁵ However, ICNU acknowledges “PSE was not required to enter into long-term fixed price gas commitments after the buyout.”⁶⁶ Nevertheless, ICNU argues, PSE must demonstrate that the Tenaska gas costs at issue in this proceeding are reasonable, “taking into account the projections that were used to justify creation of the regulatory asset.”⁶⁷

ICNU’s arguments that PSE was imprudent in managing the Tenaska contract in the first several years after contract restructuring mirror Staff’s. ICNU argues that PSE managed the Tenaska gas supply to improve short-term earnings, without regard to achieving the goal of long-term savings for customers.⁶⁸

⁶²	Exhibit No. 281HC at 11:11-15. These amounts are grossed up for taxes.

⁶³	ICNU Initial Brief at 18. ICNU does not address the issue of PSE's management of fuel costs for Encogen, nor does it address the Encogen regulatory asset.

⁶⁴	Id. at 19.

⁶⁵	Id. at 21-22.

⁶⁶	Id. at 24.

⁶⁷

Id.

⁶⁸	Id. at 25.

ICNU cites much of the same confidential information cited by Staff concerning PSE’s risk management through 2000. While acknowledging that PSE “worked on developing more effective risk management strategies,” during this period, ICNU argues that the Company “continued to ignore the advice of its risk management consultants.”⁶⁹

ICNU also focuses on PSE’s management of Tenaska gas supply during 2001 and 2002 following the Western energy crisis, which was characterized by extreme volatility and unprecedented prices. As prices dropped and market conditions stabilized, PSE considered securing longer term gas supplies, but did not do so because its plan to “beat the market” failed, according to ICNU.⁷⁰ICNU argues that “Prudence must be demonstrated by a ‘reasoned analysis,’” yet, “PSE has provided no reasoned analysis why its decision to rely on short-term gas markets was prudent.”⁷¹ ICNU argues in conclusion that:

Since 1997, PSE has had several opportunities to secure gas for Tenaska during periods of low market prices. Each time the Company has foregone potential savings in the hopes of achieving greater returns or maximizing short–term margins. Regardless of whether PSE’s reliance on the short–term market prior to the Western power crisis is understandable, the Company’s subsequent bet that it could beat the prices in that market was not. Customers should not be responsible for PSE’s repeated gambles with the short–term market. PSE had the obligation to pursue a Tenaska gas supply strategy that would deliver as much of the projected savings as possible. PSE intentionally chose to go short. Since the Company voluntarily undertook the risk of going short, it should bear the consequences.⁷²

⁶⁹	Id. at 26.

⁷⁰	Id. at 28 (citing to Exhibit No. 45 at 29:23-25 (Gaines); Exhibit No. 77C; Exhibit No. 92 at 1; Exhibit No. 209C at 10, 28; and TR. 137:24; 138:2-3; 139:19-20 (Ryan)).

⁷¹	Id. at 30 (citing to Exhibit No. Exh. No. 82 (Prudence Order) at 15-16).

⁷²

Id.

ICNU’s primary prayer for relief is that the Commission remove the Tenaska regulatory asset from PSE’s books because it has provided no benefits to customers. This would reduce PSE’s revenue requirement during the PCORC Rate Period by approximately $40.3 million, according to ICNU.⁷³ In the alternative, ICNU would support either the adjustment proposed by Staff under Staff’s contract cap theory (i.e., $19.8 million), or an adjustment based on PSE’s analysis in support of its restructuring petition in 1997 (i.e., approximately $40 million).⁷⁴

PSE’s Argument that is has prudently managed gas supply for Tenaska and Encogen.

PSE argues that the Commission’s approval of restructuring, including the creation of the Tenaska regulatory asset “was never founded upon a promise or guarantee by PSE that it would lock in fuel prices or that power cost savings would necessarily follow from the Company’s actions.”⁷⁵ The Company quotes from the Commission’s consideration of PSE’s restructuring proposal at the December 10, 1997, Open Meeting in support of the first part of this argument.⁷⁶In addition, PSE cites to Mr. Gaines’s testimony at hearing that PSE did not guarantee the level of savings projected in support of the accounting petition would actually be achieved.⁷⁷ Finally, and presumably in support of its second argument, PSE refers to a Company response to a Commission Staff data request in the contract restructuring docket in which PSE stated: “If the Company can better these prices in the market, the savings will be greater. Conversely, if prices go up, there will be less savings.”⁷⁸

⁷³	Id. at 31.

⁷⁴	Mr. Schoenbeck proposed a fourth alternative at hearing. Despite allowing for additional development of the alternative, and hearing from other witnesses who opposed it, the matter simply was not fully developed enough on our record to permit its consideration.

⁷⁵	PSE Initial Brief at 30.

⁷⁶	Id. (citing Exhibit No. 52 at 4).

⁷⁷	Id. at 31 (citing TR. 296:14-21.

⁷⁸	Id. at 30 (citing Exhibit No. 53 (emphasis added by PSE)).

PSE determined that a long-term, fixed-price supply contract was inadvisable for Tenaska at the time of the 1997 buyout. Instead, the Company elected to acquire fuel via spot market purchases and near-term hedging. According to PSE, this decision was driven by three factors: “(1) the state of the natural gas and electric industries at the time; (2) the market conditions that existed at the time; and (3) the Tenaska facility’s margin position within PSE’s resource stack.”⁷⁹

With respect to the first factor, PSE refers specifically to deregulation of the natural gas industry during the 1990‘s. With that process all but completed by the middle of the decade, FERC, various states, and some market participants “were pushing toward deregulation in the electric industry as well.”⁸⁰ Puget states that it was concerned about stranded costs. PSE accordingly “sought to reduce its dependence upon long-term, fixed-price natural gas supplies under [its] PURPA contracts.”⁸¹ PSE argues that it was positioning itself to take advantage of gas prices in the short-term gas market, and acquire flexibility to address “uncertain industry circumstances.”⁸²

Turning to market conditions at the time of restructuring the contract in 1997, PSE argues “the Sumas gas market had been exhibiting very low spot prices for quite some time—including periods of falling prices.”⁸³ According to PSE, the long-term price quotes it received at the time carried “significant premiums over then-current and forecasted prices.” ⁸⁴ PSE argues that, given the circumstances, “it did not appear advisable for the Company to lock into the same sort of supply arrangement for Tenaska that had existed previously – i.e., a fixed-price, escalating contract.”⁸⁵ Acknowledging that gas “prices had at times spiked or been volatile,” PSE argues that prices “had generally settled down to levels such that the commodity price risk exposure and potential for market volatility” did not justify paying premiums for longer term supply contracts or losing flexibility.⁸⁶

⁷⁹	Id. at 31.

⁸⁰	Id. at 32.

⁸¹	Id. at 33.

⁸²

Id.

⁸³	Id. at 34.

⁸⁴

Id.

⁸⁵

Id.

⁸⁶	Id. at 36.

On the point of maintaining flexibility, PSE argues that it was prudent for the Company to rely on the short-term market because Tenaska was a marginal resource on an operating-cost basis. Power from Tenaska was likely to be displaced as a power source for native load if the relationship between power prices and gas prices meant the Company could save money by purchasing power and not running Tenaska, or could make money on the wholesale power market considering the relative prices of power and natural gas.⁸⁷

With respect to the early management of the Encogen gas supply after restructuring, PSE states that prior to the onset of the Western power market crisis, in early 2000, the Company secured a long-term hedge of 10,000 MMBtu/day.⁸⁸ This represented approximately one-half of the restructured gas volume associated with the original Cabot gas supply agreement that PSE bought out in 1999. When prices were at lower levels toward the end of 2001 and in early 2002, PSE again adopted a strategy to go long for the balance of the Encogen fuel supply through 2008. However, Mr. Gaines testified that “traders were unable to find opportunities to lock in a long term price within the target limits” set by the RMC.⁸⁹

PSE states that the Company “made similar attempts during this time to hedge the Tenaska fuel supply, based upon certain target prices” that, as it turned out, could not be achieved in the market. It is unclear whether PSE actually implemented this strategy for Tenaska. Mr. Gaines testified on rebuttal that the Company decided to put the plan into effect, but it could not be executed due to the target price point not being achievable in the market.⁹⁰ At hearing, however, Mr. Gaines stated that his recollection had become vague, that he was uncertain whether the plan became policy, and that a search of PSE’s files produced no evidence that the Company, in fact, had implemented any specific plan to go long in the market as advised by its risk management consultants.⁹¹

PSE argues that its continued reliance exclusively on the short term market “as the Western Power Market Crisis abated, and gas prices began to moderate” was prudent because it found market prices for long-term supply “too high relative to fundamental analysis and market signals.”⁹² PSE believed prices would moderate in the longer term.

⁸⁷	Id. at 34-35.

⁸⁸	Id. at 37.

⁸⁹	Exhibit No. 45 at 29:24-25.

⁹⁰	Id. at 29:13 - 30:2.

⁹¹	TR. 282C:3-21.

⁹²	PSE Initial Brief at 38.

Since 2002, PSE has upgraded its risk management tools and capabilities “to reduce its exposure to spot market uncertainty.”⁹³ PSE states that “In early 2003 the Company developed a dollar-cost averaging strategy that helps the Company protect against volatility in wholesale markets.”⁹⁴ PSE has considered locking in long-term supply but argues it has not been able to do so “at fixed prices that justify such a step.”⁹⁵

Commission Analysis and Decisions

Standards and Regulatory Principles

65	Historically, the Commission has followed the widely adopted standard for evaluating prudence whereby:

It is generally conceded that one cannot use the advantage of hindsight. The test this Commission applies to measure prudence is what would a reasonable board of directors and company management have decided given what they knew or reasonably should have known to be true at the time they made a decision. This test applies both to the question of need and the appropriateness of the expenditures.⁹⁶

The Commission applied this standard in its original consideration of PSE’s Tenaska and Encogen contracts, has consistently applied it in other proceedings, and will apply it here.⁹⁷ The Company must establish that it adequately studied the questions relevant to management of the costs of gas and made prudent decisions in light of the contract restructuring approved by the Commission in 1997 and 1999, using the data and methods that a reasonable management would have used at the time the decisions were made. This requires evaluation of the Company’s decisions not just from the perspective of management for the benefit of shareholders, but also for the benefit of customers. “The fundamental question for decision is whether management acted reasonably in the public interest, not merely in the interest of the company.”⁹⁸

⁹³	Id. at 39.

⁹⁴

Id.

⁹⁵	Id. at 40.

⁹⁶	WUTC v. Puget Sound Power & Light Co., Cause No. U-83-54, Fourth Supplemental Order (September 28, 1984) at 32; See Goodman, The Process of Ratemaking, at 856-57.

⁹⁷

WUTC v. Puget Sound Power & Light Co., Docket No. UE-921262, et al., Nineteenth Supplemental Order (September 27, 1994) at 10 (citing WUTC v. Puget Sound Power& Light Co., Cause No. U-85-53, Second Supplemental Order (May 16, 1986) and WUTC v. Washington Water Power Co., Cause No. U-83-26, Fifth Supplemental Order (January 19, 1984)).

⁹⁸	Goodman, The Process of Ratemaking, at 857.

PSE argues that Staff and ICNU have not made “specific allegations that PSE acted unreasonably at a particular point in time,” but rather rely on “the mere assertion that PSE failed to show prudence.”⁹⁹ We reject PSE’s arguments. As illustrated in our summary of the parties’ arguments above, it simply is not true that the parties have not made specific allegations supported by specific evidence.

PSE expresses appropriate concern that we must evaluate the prudence of past decisions on the basis of what the Company “knew or should have known at the time” the decisions were made.¹⁰⁰ The Commission fully understands its own standard, including the point that the prudence of decisions must not be evaluated on the basis of hindsight. We find the record adequate to our evaluation of the prudence of PSE’s management decisions on the basis of what the Company knew or should have known at the time the decisions were made.

In addition to prudence, the parties’ respective theories also touch on, or at least are analogous to, principles of regulatory ratemaking generally characterized as the “used and useful”theory, and the principle of “matching” costs and benefits. All of PSE’s opponents propose remedies grounded in the concept that to the extent costs incurred do not match expected benefits in the periods at issue, those costs should be disallowed. ICNU makes this argument most forcefully, and takes it a step further, advocating removal of the Tenaska regulatory asset from PSE’s books and a complete write-off of the asset. This, of course, would decisively affect both the current period, and future periods during the life of the Tenaska regulatory asset.¹⁰¹

Staff and Public Counsel take a different tack, arguing that the regulatory asset can remain on PSE’s books for recovery, including return of and on the asset, but these parties would disallow PSE’s gas costs by an amount that matches the savings PSE projected for the PCA and PCORC periods at the time of contract restructuring. Public Counsel’s witness, Mr. Lazar, proposes through his testimony an alternative remedy that recommends disallowance of “carrying costs” (i.e., return of and return on) associated with the regulatory asset. He testified that the effect from a cost recovery perspective would be about the same under either remedy.

70	As we discuss below, we find that the rate regulation concepts in which these various recommendations are grounded provide useful guidance (but not a straitjacket) for considering the evidence.

ii.

Tenaska

This is a complex case. Insofar as Tenaska is concerned, PSE’s acquisition and management of this asset has a twelve-year history and a future that extends through 2011. It is important for the Commission to consider all relevant regulatory principles and facts, in the context of this history and with an eye to the future. We have already determined, above, that while the Commission’s Prudence Order in 1994 arguably established a cap on recoverable costs, the viability of any such cap as a legal barrier to recovery of costs higher than those expected under the original contract ceased to exist once the Commission approved contract restructuring. We now consider whether other “caps” proposed by the parties should limit recovery and whether PSE’s alleged imprudence should limit recovery.

⁹⁹

Id.

¹⁰⁰	Id. at 27-29, 42; PSE Reply Brief at 2, 9-10, 13-14, 16, 17-18, 27.

¹⁰¹	ICNU advocates this remedy with respect to Tenaska, but not Encogen.

The Tenaska buyout contract was not challenged as imprudent in 1997, and we reserved the issue of prudence in our decision approving contract restructuring. It appears that everyone, at that time, expected that lower future gas costs (compared to the original Tenaska purchase amounts) would enable the Company to save money for the ratepayers, who would be asked in the future to pay a return of and on the regulatory asset that was created.

The transcript of the Commission’s Open Meeting discussion of PSE’s petition to restructure the Tenaska contract touched on the concern that things might not work out as projected. PSE stated then in response to questions from the Commission that the Company did not intend to lock-in long-term contracts at the prices available in 1997. PSE stated that it intended to “go to market” to obtain gas to meet the plant’s requirements. No one present provided any analysis of what might happen under scenarios where gas costs might rise significantly above those PSE presented in support of its petition. Thus, expectations of significant benefits were raised, but the risk that they might not be realized was not explored.

As we have learned through the course of several proceedings over the past three years, the failure of parties adequately to consider alternative futures has unfortunately characterized several arrangements brought to the Commission for regulatory approval. For example, in 1996, the Commission approved an agreement between ICNU and PSE that resulted in Schedule 48. Schedule 48 provided PSE’s largest industrial customers indirect access to the market, via market-based rates, as a transition mechanism to direct market access that some thought would soon be legislated into existence. Schedule 48 did not provide for any return by the large customers to regulated rates, either during or after the 5-year term of the agreement, under the assumption that the electricity system would be restructured to a retail open-access regime. That did not occur in Washington. Moreover, a few years later, the wholesale electricity markets to which the industrial customers agreed to tie their fortunes took a very different—and unexpected—turn. Both gas and electric prices rose to unprecedented levels with unprecedented volatility. Following extensive and hotly contested hearings, the Commission approved new arrangements that eliminated Schedule 48, afforded balanced relief for the customers and the Company, and promoted the public interest.¹⁰²

The Commission, in recent years, has had to review and modify several other agreements, rate plans, and deferral accounts in light of significant perturbations in the electricity and gas markets. Some of these events either could not reasonably have been anticipated, or were not anticipated, by industry participants. Some of these events involved unlawful and potentially criminal manipulation of the wholesale markets. In all such cases presented thus far, the Commission has allowed some leeway to address the effects of these extraordinary dynamics. The Commission notes that some parties have been on both sides of the relief question, depending on where the financial consequences might fall: seeking relief from their own unexpected costs, but opposing relief for others.

76	In the context of this general historical setting, we turn to our central task in this proceeding: to weigh all interests, theories, historical facts, and scenarios of the future, such that the end result is fair, just, reasonable and sufficient rates.

¹⁰²	Air Liquide America Corp., et al. v. Puget Sound Energy, Inc., Eleventh Supplemental Order Approving and Adopting Settlement Agreement, Subject to Conditions; Dismissing Proceedings; and Granting Other Relief, Docket No. UE-001952 (April 5, 2001).

This case has both backward-looking and forward-looking elements. In general, Staff, Public Counsel, and ICNU urge that we limit recovery of the full fuel costs, including recovery of and on the regulatory asset, based on some historical measuring rod or cap, as well as on the argued imprudence of past decisions that have led to the current state of affairs. These parties see little or no prospect for future benefits to customers, whether or not PSE makes prudent decisions going forward. In general, PSE urges us to focus only on its actual costs, including return of and on the regulatory asset, and to view the prudence of its decisions only insofar as they tie directly to the PCA and PCORC periods. PSE suggests, however, at least the possibility that the benefits from restructuring projected in 1997 may yet be achieved.

Although they do not expressly argue for the direct application of the used and useful theory of rate regulation, the various caps urged by the opposing parties are based on principles that relate to that theory of cost disallowance. This theory posits that there should be no recovery of certain amounts (return of the asset, and/or return on the asset) that exceed the original benefit for which the asset was established. Put differently, if an asset is not providing benefits during a given rate period under review that are commensurate with those that originally justified the inclusion of the asset’s costs in rates, the corresponding costs should be disallowed going forward because the asset is not useful. This type of standard—that costs allowed should be roughly commensurate with benefits conferred—as a standard for recovery of the Tenaska contract buyout costs, was not expressly articulated when the regulatory asset was created, yet it does have some merit.

In the classic application of the used and useful concept, a regulatory asset is created to recover the costs of a plant. In that context, as long as the plant is prudently maintained and operated to capacity for the benefit of the ratepayers, the company should be authorized to recover the full return of and on the asset.

In this case, however, the regulatory asset was created to recover the costs of buying out a gas contract. The result of the contract buyout was to create for PSE a new and on-going obligation to purchase gas over the life of the original contract. Every day, month, or year, PSE must make new purchases. While it is possible to measure these decisions against the standard of long-term contracts available in 1997, such a measuring rod, if strictly applied, is unforgiving; if the Company’s purchasing choices lead to costs that exceed the standard, they are disallowed even if those purchasing choices are prudent. Thus, using a cap approach, standing alone, had gas prices risen immediately after contract restructuring and stayed high, and had the Company made prudent but expensive purchasing choices, costs would still be disallowed.

81	Other commissions and courts in other circumstances have recognized the drawbacks of the “used and useful”theory, if too rigidly applied. Conversely, the theory has considerable merit when applied flexibly within constitutional limits.¹⁰³

Under the unusual facts of this case, we think that strict application of a cap approach to evaluate whether there should be full recovery of costs affected by PSE’s on-going purchasing choices is too rigid. Such an approach does not adequately provide for future changes in the environment in which the company must navigate, and places too much risk on the company.

All parties couch their arguments in terms of prudence, but the Company argues that prudence is independent of the various “benefit-caps” urged by the other parties to limit recovery. We think prudence matters, obviously, but is not dispositive on a stand-alone basis, either. Using prudence alone, at least as articulated by the Company in this instance, would completely sever the present from the past, giving no weight to the underlying reason and expectations around which the regulatory asset was created. The Company would have us look only at whether its decisions were prudent during the test period. If they were, then all costs would be allowed—gas costs, return of the regulatory asset, and return on the regulatory asset (all, however, subject to other mechanisms such as the PCA) regardless of whether the costs produce the benefits intended, or any benefits at all. This approach places too much risk on the ratepayers, under the specific facts of this case.

¹⁰³	See Jersey Central Power & Light Co. v. Federal Energy Regulatory Commission, 810 F.2d 1168 (D.C. Cir. 1987)

PSE’s opponents would have us use a double screen. Costs would be disallowed either if exceeding a historically based cap, or if imprudent. If costs fail either test, the parties present a range of ideas about what costs should be disallowed. ICNU would disallow all return of and return on the regulatory asset by requiring that it be removed from rate base and written off. Public Counsel’s witness suggested through his testimony that “carrying costs” be disallowed, unless and until PSE could demonstrate benefits commensurate with those projected in 1997. Staff proposes the disallowance of gas costs that would effectively offset the costs of the regulatory asset during the rate year. These ideas, however, are decoupled from what costs prudent decisions might have yielded in a market environment not anticipated by any party.

We think that the regulatory concepts grounded in both “used and useful” and “prudence” theories have merit, but that neither should dominate exclusively in this particular case, where the regulatory asset gave rise to on-going purchasing obligations, and where the environment has changed substantially from the time the asset was created. Thus, we will use a hybrid analysis to determine recovery in rates that are fair, just, reasonable, and sufficient.

86	Looking forward, at paragraph 95 of this Order, we set forth a clear methodology for determining recovery of Tenaska costs incurred after the effective date of this Order.¹⁰⁴ But first we will look backward, and address the test period.¹⁰⁵

We consider first the prudence of PSE’s management of gas supply acquisition since the contract buyout. As we have already recounted, all parties have advocated vigorously on this subject. PSE’s opponents assert that in 1997, PSE could have bought a long-term contract that would have guaranteed the projected savings that were the basis for executing the contract buyout and creating the regulatory asset. However, the evidence shows that PSE did not commit to such a plan and, indeed, clarified to the Commission in 1997 that the Company intended to “go to market” where it believed it could achieve savings through careful planning and purchasing. PSE certainly created an expectation of savings, but did not guarantee a specific level of savings. Moreover, we do not believe that prudence required PSE, under the circumstances, to enter into another long-term contract for the full amount, even if, in hindsight (which cannot be our guide) such a contract would have produced the intended savings.

The evidence does show, however, that PSE managed gas acquisition primarily for the short-term bottom line for shareholders. PSE failed to develop and implement a gas-purchasing plan that took into account the Company’s obligation to manage its gas supply with an eye to securing savings for customers over the longer term.

The Commission allows that in 1997 everyone’s appreciation of the future turned out to be inaccurate, and that some leeway should be given to accommodate the effects of the very different future that actually unfolded. Instead of downward-trending gas prices and a restructured retail electricity market, gas increased in price and volatility, and the retail and wholesale markets reeled from the effects of the Western energy calamity.

¹⁰⁴	The costs incurred between July 1, 2003, and the date of this Order remain subject to review in an appropriate proceeding.

¹⁰⁵	The PCA period and PCORC test period cover the same 12-month period, July 1, 2002 - June 30, 2003

However, even in the wake of that calamity, when prices returned to more normal levels PSE failed to follow the advice it paid for, which counseled PSE to spread the risk of price volatility, and especially not to get caught “short.” PSE did consider going long on Tenaska gas following the extraordinary price levels reached during late 2000 and early 2001. But PSE was unwilling to pay what the market demanded, despite the advantages the Company’s own analyses demonstrated. The Company developed a “plan” that would require its gas traders to better the then-market price by 10 percent.

By the time of the test-year, it was obvious in the marketplace, and should have been clear to PSE, that any prudent policy for gas acquisition must spread the risk of price volatility to significantly dampen its potential effects on total costs. This was evident from the advice PSE received from experts it employed, from its own review of its gas-purchasing practices, and from other cases at the Commission. It is clear to us that during the test year PSE did not have a prudent purchasing strategy in place. Instead of developing a comprehensive strategy and a balanced approach considering opportunities in short-term, intermediate-term, and long-term gas markets, PSE simply continued its practice of buying in the short-term market. Even though the Company recognized the need for an alternative strategy, it did not develop and implement one.¹⁰⁶

¹⁰⁶	We note that the record includes some encouraging evidence that PSE is more actively working at this time toward development of a comprehensive strategy that works.

PSE failed to demonstrate that it followed prudent practices to mitigate risk even following the events of late 2000 and early 2001. We do not know, nor can we know, exactly where costs would be today had PSE prudently managed the Tenaska gas supply. We do know that these imprudently managed costs for Tenaska during the PCA period and the PCORC test period exceed the benchmark of the original (i.e., 1991 ) contract costs. This is illustrated in Figure I, which shows approximate total costs, including gas costs set at the PCORC baseline of $4.35/MMBtu, return of, and return on the Tenaska regulatory asset relative to what ratepayers would have paid under the original contract. As illustrated, all of the return on the regulatory asset is above the benchmark during the PCA period and the PCORC test year.

Figure I

PSE’s purchasing strategy developed, or failed to develop, over many years, up to and including recent periods. It is not possible to pinpoint either the precise consequences to gas costs that resulted from PSE’s failure to manage prudently or the precise consequences to the regulatory investment that should follow. Accordingly, we will make a single adjustment to the deferral account, approximating an appropriate disallowance of return on the asset. We will disallow an amount equal to the return on the asset and associated taxes for the PCA period. It appears from Exhibit No. 5, page 47, line 21, that the return amount is $16,648,873. The associated taxes are $8,964,777. Thus, we require PSE to remove $25,613,650 from power costs for the PCA period.¹⁰⁷

We emphasize that this adjustment is not a change to the PCA mechanism itself. Rather, it is a one-time disallowance of costs on which the mechanism operates—costs tied to an arrangement that pre-dates the creation of the PCA and not fully resolved at its creation. Because this adjustment may have consequences in later PCA periods, we will take it into account when reviewing those periods. We also observe that this disallowance is a consequence of practices and policies undertaken by a prior management. We have confidence in the new management, and expect that it will be able to demonstrate in future proceedings that it has developed prudent gas purchasing practices.

95	Looking forward, for purposes of determining rates in the PCORC proceeding, and in future rate proceedings, we establish the following rules for recovery consistent with the hybrid, balanced approach we have previously articulated:¹⁰⁸

(A)

First determine if PSE’s gas purchasing plan and gas purchases for Tenaska are prudent.¹⁰⁹

¹⁰⁷	We confirmed the total amount by multiplying by 12 the amount shown in Exhibit No. 5, page 47, line 21, under the column identified as "Monthly Return Pre-tax Jul 02-Jun 03." The result is $25,613,652. We attribute the slight difference in the total to rounding.

¹⁰⁸	See supra,P.P. 78 - 86.

¹⁰⁹	See supra,P. 65 for guidance.

(1)

If so, and if net Tenaska costs (including gas costs, return of, and return on the Tenaska regulatory asset, contract displacement charges, and the cost of replacement energy) fall at or below the benchmark (based on the original costs of the Tenaska contract adjusted to reflect the 1.2 percent disallowance established in 1994 under the Prudence Order entered in Docket No. UE-921262),¹¹⁰ then PSE will recover fully its Tenaska-related costs. All costs are subject to the operation of the PCA mechanism.

(2)

If PSE’s gas purchasing plan and gas purchases for Tenaska are prudent, but net Tenaska costs exceed the benchmark, PSE will receive 50 percent of any portion of return on the asset that is above the benchmark (return on the asset should be added last—to all other relevant Tenaska costs). PSE will recover fully its actual costs of gas and return of the regulatory asset even if the benchmark is exceeded. All costs are subject to operation of the PCA mechanism.

(B)

If PSE’s gas purchasing plan or gas purchases are found to be imprudent in a future proceeding, PSE risks disallowance of any and all costs (gas, return of, and return on), as appropriate, and in light of risks to ratepayers and the Company.

We think this approach achieves an appropriate balance of shareholder and ratepayer concerns, and of historical and future (i.e., unknown) conditions. In effect, treatment of Tenaska’s costs must be a “mechanism within” the PCA mechanism, made necessary in order to accommodate a unique asset created in 1997, long before the PCA mechanism was established. We have tried, insofar as possible, not to disturb the operation or purposes of the PCA and PCORC mechanisms, which are designed to promptly and fairly resolve cost-recovery issues affecting ratepayers and shareholders. As the long-running difficulties concerning the Tenaska dispute demonstrate, a more contemporaneous review of costs and rules for recovery is clearly desirable. And that is what the PCA and PCORC are designed to do. Thus, we do not expect to be creating more Tenaska-like sagas. Indeed, the Company’s presentation and the Commission’s approval of Fredrickson offer a successful model for the future.

¹¹⁰	Appendix 2 to this Order portrays the details of the benchmark mechanism. Appendix 3 provides examples.

Applied to the PCORC rate period, these rules for recovery, and assuming prudent practices, result in a power cost disallowance of $9,921,067.111 This disallowance results from the combination of assumed gas costs plus the return of and on the asset (and other costs). In the near-future years some portion of the return on the asset will exceed the benchmark, and so only one-half of that portion will be included in the Company’s revenue requirement. Of course, if PSE’s actual prudent costs are entirely below the benchmark, PSE will be credited with the full return on the asset. Thus, PSE has an incentive to strive for lower gas costs, which also benefits the ratepayers.

98	The adjustment we order here, considered with all other adjustments for the PCORC period, results in a revenue requirement deficiency of $44,112,960. The resulting power cost rate (grossed up) is $48.301 per MWH, a $2.29 increase in the PCA rate.¹¹²

¹¹¹	This amount is derived from Mr. Schooley's calculations that show total costs, including return of and on the Tenaska regulatory asset, exceed our benchmark by $19,842,134. One-half of this figure is $9,921,067.

¹¹²	These calculations are based on Exhibit No. 318, adjusted for the Tenaska-related disallowance that we order here. Appendix 1 shows all of the adjustments we approve in this proceeding, and our calculation of the resulting revenue deficiency and power cost rate.

iii.

Encogen

The total costs for Encogen—including fuel costs that are higher than those the Company would have incurred under the fuel supply contract that it bought out in 1999, return of, and return on the resulting regulatory asset—do not produce the savings PSE projected in support of restructuring. However, the evidence shows that in the case of Encogen the Company recognized the importance of managing gas supply to achieve savings for ratepayers immediately following contract restructuring in 1999, and on a forward basis. PSE conducted a “Business Case Analysis” of the Encogen gas contract buyout approximately six months after the transaction closed.¹¹³ The analysis shows that after the Commission approved PSE’s contract buyout proposal, PSE took immediate steps to implement a strategy expressly aimed at mitigating the risks that its future acquisition of gas might not produce the savings projected. The Company succeeded in negotiating long-term and short-term transactions that produced savings during the first year after contract restructuring, and mitigated future risks by locking in relatively low prices for one-half of Encogen’s fuel requirements through 2008. Gas prices rose sharply beginning in mid-2000, however, and have remained high during most periods since then. Despite having implemented a risk-reducing strategy early on, PSE has not been able to achieve the savings it projected at the time it bought out the Encogen gas contract.

100

Compared to the massive quantity of evidence regarding Tenaska, the evidence concerning PSE’s management of the Encogen gas supply through the test period is relatively less. We find, on balance, that the evidence presented weighs in the direction of prudence. Accordingly, we find the Company has established prudent costs. We will not require any disallowance of the Encogen costs for the PCA period, nor will we require any adjustment for purposes of setting rates in the PCORC proceeding. We do expect that the incentives operating on the much-larger Tenaska costs will also have a salutory effect on the management of Encogen costs.

¹¹³	Exhibit No. 77C at 50-52.

III.

Conclusion

101

Our action today, considered together with our prior orders in this proceeding, resolves and clarifies important issues affecting the Company’s power costs. We previously approved a method (i.e., a PCORC proceeding) whereby the Company could receive prompt review of proposed major new power acquisitions. In a successful first use of this new type of proceeding, we approved the Company’s acquisition for the Frederickson power plant. We here approve a $44,112,960 adjustment to PSE’s power costs, including Frederickson and other costs, as appropriate and reasonable to determine PSE’s Schedule 95 rates.

102

In past orders we have approved a Power Cost Adjustment (PCA) mechanism, designed to fairly share risks and rewards between ratepayers and shareholders for power costs. Here, we have tried to disturb that mechanism as little as possible, but the lingering dispute over the Company’s past practices (under a different management) regarding Tenaska, which predates the PCA, had finally to be resolved and reconciled with the PCA. Today, we resolve it through a one-time disallowance of $16,648,873 (grossed up for taxes to $25,613,650) in deferred costs associated with that plant, to account for the Company’s imprudent management through the test period. On a going-forward basis, including adjustments for the PCORC rate period, we expect the Company will be prudent, and the revenue requirement we set is based on needs for prudent expenditures. We also establish through this Order clear rules for PSE’s future recovery of costs related to the Tenaska power plant. We find that recovery of these costs is not limited by original 1992 allowed contract amounts.

103

In combination, our orders address the new Fredrickson plant, old Tenaska disputes, and new mechanisms for promptly and fairly sharing risks between ratepayers and shareholders. These actions clear the way for the Company to manage its power supply to provide customers with reliable service at rates that are fair, just, reasonable, and sufficient.

FINDINGS OF FACT

104

Having discussed above all matters material to our decision, and having stated general findings, the Commission now makes the following summary findings of fact. Those portions of the preceding discussion that include findings pertaining to the Commission’s ultimate decisions are incorporated by this reference.

105

(1)

The Washington Utilities and Transportation Commission is an agency of the State of Washington, vested by statute with authority to regulate rates, rules, regulations, practices, and accounts of public service companies, including electric companies.

106

(2)

Puget Sound Energy, Inc., (“PSE”) is a “public service company” and an “electrical company” as those terms are defined in RCW 80.04.010, and as those terms otherwise may be used in Title 80 RCW. PSE is engaged in Washington State in the business of supplying utility services and commodities to the public for compensation.

107

(3)

On October 24, 2003, PSE filed with the Commission revisions to its currently effective Tariff WN U-60, designated as Twenty-Fifth Revised Sheet No. 95, and Original Sheet Nos. 95-a through 95-e. On October 29, 2003, the Commission entered its Complaint And Order Suspending Tariff Revisions; Instituting Investigation; Authorizing Discovery in this proceeding.

108

(4)

The contested issues set for determination in this proceeding with respect to both establishing Schedule 95 rates and finalizing the PCA deferral account balance established via the Commission’s approval and adoption of a partial settlement in Docket No. UE-031389 are whether PSE has prudently managed gas acquisition to fuel the Tenaska and Encogen generation from which PSE derives power to serve its customers in Washington and whether the costs incurred are reasonable.

109

(5)

PSE failed to carry its burden of proof to demonstrate its management of fuel gas acquisition for Tenaska was prudent through the PCA and PCORC periods under consideration in this proceeding. Puget’s mismanagement of gas purchases for Tenaska was imprudent resulting in the incurrence of costs that are not reasonable considering the total costs of gas, return of, and return on the Tenaska regulatory asset.

110

(6)

PSE carried its burden to show its management of fuel gas acquisition for Encogen was prudent through the PCA and PCORC periods under consideration in this proceeding.

111

(7)

(7) The rates proposed by tariff revisions PSE filed on October 24, 2003, which were suspended by prior Commission order, are not fair, just, or reasonable.

112

(8)

Considering all uncontested and contested costs shown in this proceeding to be appropriate for the determination of Schedule 95 rates, we find a revenue deficiency of $44,112,960.

113

(9)

The existing rates for electric service PSE provides in are insufficient to yield reasonable compensation for the service rendered. PSE requires prospective relief with respect to the rates it charges for electric service provided in Washington State.

114

(10)

Rates determined on the basis of the revenue deficiency we identify in this Order are fair, just, reasonable, and sufficient.

115

(11)

Rates determined on the basis of the revenue deficiency we identify in this Order are neither unduly preferential nor discriminatory.

116

(12)

Considering the contested costs that must be determined in this proceeding to address the issues reserved under the Commission’s approval and adoption of a partial settlement in Docket No. UE-031389, we find that the PCA deferral account balance established via that partial settlement includes costs unreasonably incurred in the amount of $25,613,650.

CONCLUSIONS OF LAW

117

Having discussed above in detail all matters material to our decision, and having stated general findings and conclusions, the Commission now makes the following summary conclusions of law. Those portions of the preceding detailed discussion that state conclusions pertaining to the Commission’s ultimate decisions are incorporated by this reference.

118

(1)

The Washington Utilities and Transportation Commission has jurisdiction over the subject matter of, and parties to, these proceedings. Title 80 RCW.

119

(2)

The rates proposed by tariff revisions PSE filed on October 24, 2003, and suspended by prior Commission order, are not just, fair, or reasonable and should be rejected. RCW 80.28.010.

120

(3)

The existing rates for electric service PSE provides in Washington State are insufficient to yield reasonable compensation for the service rendered. RCW 80.28.010; RCW 80.28.020.

121

(4)

Puget Sound Energy, Inc., requires relief with respect to the rates it charges for electric service provided in Washington State. RCW 80.01.040; RCW 80.28.060.

122

(5)

The Commission must determine the fair, just, reasonable, and sufficient rates to be observed and in force under PSE’s tariffs that govern its rates, terms, and conditions of service for providing electricity to customers in Washington State. RCW 80.28.020.

123

(6)

PSE should be authorized and required to make a compliance filing in this docket to implement through revised and original tariff sheets for Schedule 95, as appropriate, rates designed to recover $44,112,960, the revenue deficiency we determine here taking into account our Order No. 12—Granting Regulatory Approvals For Fredrickson I AcquisitionResolving Disputed Gas Price Issue, entered in this proceeding on April 7, 2004, all uncontested costs, and our determination of the contested costs.

124

(7)

The balance of the PCA deferral account established via partial settlement in Docket No. UE-031389 should be adjusted to reflect a disallowance of costs unreasonably incurred during the PCA period in the amount of $25,613,650.

125

(8)

The Commission should retain jurisdiction to effectuate the terms of this Order. Title 80 RCW.

ORDER

THE COMMISSION ORDERS THAT:

126

(1)

The proposed tariff revisions PSE filed in this Docket on October 24, 2004, and suspended by prior Commission order, are rejected.

127

(2)

PSE is authorized and required to file tariff sheets following the effective date of this Order that are necessary and sufficient to effectuate its terms, with rates designed to recover a revenue deficiency of $44,112,960. The required tariff sheets shall bear an effective date to be determined at an order conference the Commission sets by separate notice issued today for May 17, 2004, at 3:30 p.m. in the Commission’s Hearing Room.

128

(3)

PSE is required to adjust the balance of the PCA deferral account established via partial settlement in Docket No. UE-031389 to reflect a disallowance of costs unreasonably incurred during the PCA period in the amount of $25,613,650, and to make any filing that is required under the PCA reporting requirements, or otherwise, to reflect this adjustment.

129

(4)

The Commission Secretary is authorized to accept by letter, with copies to all parties to this proceeding, such filings as PSE may make to comply with the terms of this Order.

130

(5)

The Commission retains jurisdiction to effectuate the terms of this Order.

DATED at Olympia, Washington, and effective this 13th day of May 2004.

WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION


	MARILYN SHOWALTER, Chairwoman



	RICHARD HEMSTAD, Commissioner

131

COMMISSIONER PATRICK J. OSHIE, Concurring and Dissenting:

132

I concur with the majority’s opinion and order finding that Puget Sound Energy (PSE or Company) failed to meet its burden to demonstrate prudence with regard to its management of fuel supply for the Tenaska facility. I further concur with the majority’s decision to reduce PSE’s Purchase Cost Adjustment (PCA) deferral account balance by $25,613,650 ¹¹⁴ to reflect a disallowance of PSE’s return on the regulatory asset created in 1997, and associated taxes.

¹¹⁴	This reflects a disallowance of 100 percent of the return on equity for the Tenaska regulatory asset for the July 2002 through June 2003 period in the amount of $16,648,873, grossed up for taxes to $25,613,650.

133

However, I respectfully dissent from the majority’s decision to allow the Company, on a prospective basis, to earn a partial return on the Tenaska regulatory asset without first showing that the regulatory asset is conferring some benefit to the ratepayers.

134

This case presents issues of equity and fundamental fairness. To correctly balance the equities presented and to restore fundamental fairness to the treatment of the regulatory asset, I would allow PSE to continue to recover its return of the regulatory asset, but would deny the Company any return on the regulatory asset until such time as it can demonstrate that the actual net cost¹¹⁵ is less than the benchmark discussed in the majority opinion ¹¹⁶ during any rate period under consideration.

135

To briefly summarize the facts set forth in the majority opinion, the Company entered into a 20-year purchase power agreement with Tenaska Washington Partners (TWP) in 1991. Essentially, PSE agreed to take the output from TWP’s natural gas-fired cogeneration facility in Whatcom County. The contract provided for definite prices for power over the contract term with price escalations at fixed amounts to occur on an annual basis. In 1994, the Commission found PSE’s decision to enter into the Tenaska contract to be imprudent, and concluded that the appropriate remedy was to disallow 1.2 percent of the “net cost of the [Tenaska] contract” for ratemaking purposes.¹¹⁷

¹¹⁵

As described in majority's opinion, the actual net cost is the total cost of power from Tenaska including: actual fuel cost, all other contract charges and replacement power, and recovery of and on the Regulatory Asset. The Actual Net Cost is also reduced by the 1.2% prudence disallowance ordered in Docket No. UE-921262. Actual Cost is "grossed up" as a revenue requirement.

¹¹⁶	The Benchmark cost for any given year is the net costs that would have been paid under the original Tenaska contract less the 1.2% disallowance of net contract costs established under the Commission's Prudence Order in Docket No. UE-921262.

¹¹⁷	WUTC v. Puget Sound Power & Light Company, 19th Supplemental Order, Docket Nos. UE-921262, et al. (1994) at 45-46, and 20th Supplemental Order, at 22.

136

Among the costs PSE incurred under the Tenaska contract were the costs of a fuel supply contract that effectively obligated the Company to pay steadily increasing prices for gas over the life of the contract. In 1997, PSE sought and received Commission approval to buy out Tenaska’s gas supply contract. PSE was allowed to treat the contract buyout costs as a regulatory asset on the Company’s books for recovery in rates over the remaining contract term.¹¹⁸ PSE assumed responsibility from that point forward to prudently manage the acquisition of natural gas to fuel the Tenaska facility.

137

PSE’s original cost to buy out the long-term fixed price gas contract associated with the Tenaska facility was $215 million. Under the approved accounting treatment, the per books balance increased during the first five years after contract restructuring to $229 million.¹¹⁹ During this period the Company remained subject to a Rate Plan that precluded adjustments to rates that would reflect recovery of and on the regulatory asset.

138

In this PCORC proceeding, the Company seeks rates that include return of and on the regulatory asset that total approximately $39 million for the rate period (April 2004 – March 2005).¹²⁰ These amounts reflect the amortization schedule approved by the Commission in 1997 and return on the regulatory asset account balance at an equity rate of 7.30 percent, as agreed to by the Company in settlement of its most recently completed general rate proceeding (i.e., Docket No. UE-011570). In addition, PSE seeks to include in rates full recovery of Tenaska gas costs.

¹¹⁸	The reasonableness and prudency of PSE's purchase of the gas sales contract, management of gas costs, and restructure of the power purchase agreement were subject to further Commission review.

¹¹⁹	Exhibit No. 281HC (Elgin) at 14:5-6; Exhibit No. 5 at 47:21.

¹²⁰	120 Exhibit No. 5 at 47:22-24.

139

In future rate periods, the approved amortization schedule would allow the Company to fully recover the per books value of the regulatory asset (return of) from ratepayers plus earn a return on the unamortized remainder, assuming reasonableness and prudence, through 2011 — the end of the original contract period.¹²¹ The regulatory asset balance would be adjusted on PSE’s books from period to period to reflect increasing return of (amortization) the regulatory asset over time. Return on the regulatory would be expected to decrease from period to period due to the declining balance on the Company’s books upon which PSE would be entitled to earn a return.

¹²¹	The approved amortization schedule tied the return of and return on the regulatory asset to the increasing level of savings set forth in the Company's accounting petition, relative to the original contract prices.

140

The Commission’s approval of the restructuring of the Tenaska gas contract in 1997, including the creation of the regulatory asset and its accounting treatment, was based on the Company’s representations that ratepayers would realize significant cost savings from the deal. The Company presented projections of future gas cost savings that would more than offset the return of and on the regulatory asset that future ratepayers would be expected to pay in rates. The sharing of benefits set forth in the accounting order reflected the Commission's belief that the Company and ratepayers should equitably share the gains to be generated by the restructured agreement.¹²²

141

Regrettably, the savings anticipated have not been realized for reasons directly related to the Company’s failure to react reasonably to a rapidly changing and volatile natural gas market and the risks attendant. In short, the natural gas market changed dramatically between 1997 and 2003, yet the Company’s purchasing strategy unabatedly trod the same path, as if the changing world would have no affect upon it.

142

The current situation, whereby the regulatory asset is not producing the savings upon which its creation was predicated, has resulted in part from the Company’s imprudent management of fuel acquisition since the energy crisis in 2000 and 2001. Because the Company did not develop and implement a fuel acquisition strategy for Tenaska to protect against the known risks of exclusive reliance on short-term markets after market prices abated in the second half of 2001, it lost the opportunity to mitigate the gas prices it faces in the market today, which again are high and may go higher yet. Indeed, the facts of this case show a persistent failure on PSE’s part, even after the energy crisis, to recognize the need for a balanced approach to gas acquisition for Tenaska including taking advantage of opportunities in the long-term market, as well as in the short-term market.

143

In my opinion, these circumstances support a denial of the Company’s return on the regulatory asset so long as and to the extent the cost of Tenaska’s fuel supply, including the return of and on the asset exceed the benchmark described in the majority’s opinion.

144

Insofar as PSE’s imprudent management is concerned, and looking back to the PCA period, I am satisfied with the majority’s determination that all return on the Tenaska regulatory asset should be removed from the PCA deferral account for the period July 2002 through June 2003. Going forward, in the PCORC rate period and beyond, I find the “used and useful”principle, which provides an alternative legal basis for adjusting what a company recovers for its investments, more relevant and compelling.

145

Although the concept of used and useful has seen its fullest development in connection with investments in physical plant, the basic precepts of the theory should be seen to apply with equal force to any investment for which ratepayers are expected to compensate the utility. If the utility expects to earn a profit on its investment, the investment must provide benefits commensurate with its known cost and intended benefits. If an asset does not produce any of its intended benefits, it is not used and useful in the public service and may be excluded from rate base. The effect of such removal, of course, is to eliminate from rates any return on the investment. Thus, the shareholders bear the risk for return on the asset while the ratepayers continue to bear the risk for the return of the asset.

¹²²	Ex. 283C at 34.

146

In other words, so long as the ratepayers receive no benefit in terms of cost savings relative to the benchmark, PSE should not receive the benefit of a return on the investment, the approval of which turned entirely on the promise of significant savings for customers. This result more equitably shares the benefits and risks associated with PSE’s management of Tenaska’s gas supply than does the majority’s determination.

147

Again, I would not deny the Company the right to recover the full amount of the regulatory asset. Nor would I deny the Company the right to its return on the asset; so long as the costs of operating Tenaska, including fuel costs, and the return on and of the asset fall below the benchmark.

148

In summary, this difficult case should be decided by balancing the benefits and burdens equitably and fairly between the Company and its customers. I find the correct balance by denying the Company a return on the regulatory asset, which to this point in our review has provided no benefit to the ratepayers. At the same time, I would require the customers to continue to pay return of the regulatory asset. To the extent PSE can demonstrate a real benefit to ratepayers in a future proceeding I would allow the Company to recover a return on the asset. If a benefit cannot be shown, then a return on the regulatory asset should continue to be denied.

DATED at Olympia, Washington, and effective this 13th day of May 2004.


	PATRICK J. OSHIE, Commissioner
	APPENDIX 1

APPENDIX 2



PUGET SOUND ENERGY POWER COST ONLY RATE CASE FOR THE 12 MONTHS ENDED JUNE 30, 2003 COMMISSION'S DECISION	Docket No. UE-031725



Ln #	DESCRIPTION	PSE REBUTTAL	COMMISSION DECISION

	(A)	(B)	(C)

1	PCA Costs
2	Per Books (test year)	$862,035,354	$862,035,354

3	Adj - 1 Power Costs	-156,165,127	-156,165,127
4	Adj - 2 Sales For Resale	152,198,362	152,198,362
5	Adj - 3 New Plant (Fredrickson I)	42,368,806	42,368,806
6	Adj - 4 Transmission Income	3,253,602	3,253,602
7	Adj - 5 Prod. Plant Deprec. &Amort.	-65,231	-65,231
8	Adj - 6 Property Taxes	152,265	152,265
9	Adj - 7 Montana Energy Tax	86,743	86,743
10	Adj - 8 Property Insurance	126,210	126,210
11	Adj - 9 White River	208,049	208,049
12	Adj - 10 Reg. Assets / Acq. Adj.	-3,521,669	-3,521,669
13	Adj - 11 Production Adjustment	-1,353,716	-1,353,716
14	Adj - 12 UE-921262 Tenaska Adj.	0	0
15	Adj - 13 Encogen/Tenaska Fuel	0	0
16	Commission Adjustment for Tenaska		-9,921,067
17	Total Pro Forma Costs	$899,323,648	$889,402,581
18	MWh	19,271,717	19,271,717
19	Proposed Power Cost Rate	$ 46.665	$ 46.151
20	Revenue Sensitive Factor	0.9554723	0.9554723
21	Proposed Power Cost Rate (grossed up)	$ 48.840	$ 48.301
22	Current Power Cost Rate (grossed up)	$ 46.013	$ 46.013
23	Change in PCA Rate	$ 2.827	$ 2.289
24	MWh	19,271,717	19,271,717
25	Revenue Deficiency (Excess)	$ 54,481,144	$ 44,112,960

Tenaska Benchmark Mechanism

Benchmark:

The Benchmark cost for any given year is the net costs that would have been paid under the original Tenaska contract less the 1.2% disallowance of net contract costs established under the Commission’s Prudence Order in Docket No. UE-921262. The formula for calculating the Benchmark assumes no displacement, no displacement charges, and no replacement power costs. The Benchmark is “grossed up” as a revenue requirement.

Benchmark = Contract Cost of Delivered Power x .988

where:

Cost of Delivered Power = Original contract cost as stated in Exhibit No. 5, pages 16-17, line 3.

Actual Net Cost:

The Actual Net Cost is the total cost of power from Tenaska including: actual fuel cost, all other contract charges and replacement power, and recovery of and on the Regulatory Asset. The Actual Net Cost is also reduced by the 1.2% prudence disallowance ordered in Docket No. UE-921262. Actual Cost is “grossed up” as a revenue requirement.

Actual Net Cost = [(Cost of Delivered Power) + (Displacement Payments) + (Cost of Replacement Power) + (Recovery “of” and “on” the Regulatory Asset)] x .988

where:

Cost of Delivered Power = cost of energy delivered to PSE from Tenaska based on Tenaska production, heat rate, fuel costs, and any other contract charges not related to displacement. Use average cost of power plant natural gas in portfolio if purchases not made specifically for Tenaska.

Displacement Payments = payments made to Tenaska under the contract’s displacement provisions

Replacement Power = the amount paid for replacement power when economic dispatch occurs

Regulatory Asset = recovery of and on the Regulatory Asset and associated taxes

Allowed Costs:

Those costs subject to the PCA sharing mechanism. See appendix 3 for examples of the derivation of allowed costs.

APPENDIX 3

Examples of Tenaska Benchmarking

(Examples apply if actual net costs determined to be prudent and recoverable in rates (through PCA deferral or new PCORC baseline power rate). Figures are only illustrations. Based on “grossed up” values)

Formula: Allowed Cost = Actual Net Cost -	(Part of Return "on" > Benchmark)
	2

Example No. 1: Actual Net Cost Greater than Benchmark and the Excess is Greater than Return "on" the TenaskaRegulatory Asset.


Benchmark	$150 Million
Actual Net Cost	$180 Million
Return "on" Reg. Asset	$ 20 Million
Amount over the Benchmark	180 - 150 = 30

Actual Net Cost exceeds the Benchmark and the excess exceeds the Return “on.” One-half of the return “on” is included in allowed costs.

Total allowed cost is: $180 Million - (.50 x $20 Million) = $170 Million

Example No. 2: Actual Net Cost Greater than Benchmark and the Excess is Less than Return "on" the Tenaska Regulatory Asset.


Benchmark	$150 Million
Actual Net Cost	$160 Million
Return "on" Reg. Asset	$20 Million
Amount over the Benchmark	160 - 150 = 10

Actual Net Cost exceeds the Benchmark but by an amount less than the return “on.” All of the return “on” that falls under the Benchmark and half of the return “on” that exceeds the Benchmark is included in allowed costs.

Total allowed cost is: $160 Million - (.50 x $10 Million) = $155 Million

Example No. 3: Actual Net Cost Less than or Equal to the Benchmark.


Benchmark	$150 Million
Actual Net Cost	$140 Million
Return "on" Reg. Asset	$20 Million
Amount over the Benchmark	$ 0 (140-150=0)

Actual Net Cost is below the Benchmark so full return “on” is included in allowed costs.

Total allowed cost is $140 Million.

NOTICE TO PARTIES: This is a final order of the Commission with respect to certain issues resolved. In addition to judicial review, administrative relief may be available through a petition for reconsideration, filed within 10 days of the service of this order pursuant to RCW 34.05.470 and WAC 480-07-850, or a petition for rehearing pursuant to RCW 80.04.200 and WAC 480-07-870.