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william j. evans (5276)

Vicki M. Baldwin (8532)



One Utah Center
201 South Main Street, Suite 1800
Post Office Box 45898
Salt Lake City, UT 84145-0898

Telephone: (801) 532-1234

Facsimile: (801) 536-6111

Attorneys for Kennecott Utah Copper, LLC and

Tesoro Refining and Marketing Company


In the Matter of the Application of Rocky Mountain Power for Approval of Changes to Renewable Avoided Cost Methodology for Qualifying Facilities Projects Larger than Three Megawatts

post-hearing brief

Docket No. 12-035-100

Qualifying Facility generators, Kennecott Utah Copper, LLC (“Kennecott”) and Tesoro Refining and Marketing Company (“Tesoro”), by and through their attorneys, hereby submit this Post-Hearing Brief to summarize the facts and evidence established by the record and to identify principles of law that will control the disposition of this case.


Rocky Mountain Power (“RMP” or “Company”) has requested that the Commission approve in this docket its proposed avoided cost methodology for setting the price the company must pay for purchasing power from qualifying facilities (“QF”). Kennecott and Tesoro have not taken a position on the details of how the avoided cost should be determined, except to say that the Proxy/PDDRR method is generally the correct approach.

Kennecott and Tesoro have, however, recommended that the Company include certain informational requirements when it provides indicative pricing in response to a request from a QF owner. The assumptions, inputs and methodology used to determine the price that the Company will pay for QF power should be open and transparent, and readily verifiable by the QF owner. See Direct Testimony of Maurice Brubaker (KUC/Tesoro Exh. 1) at pp. 5-6. RMP has stated that it is not appropriate in this docket for the Commission to consider potential changes to Schedule 38. Rebuttal Testimony of Greg Duvall at p. 20. Nevertheless, at the hearing, both Mr. Duvall and RMP witness, Paul Clements, testified that the Company would cooperate with Kennecott and Tesoro to timely provide all of the information necessary for them to verify RMP’s proposed pricing. Duvall, Transcript of Hearing Proceedings, (“Tr.”) June 6, 2013, at (Tr. 99:14-100:22); Clements, Tr. at 138:13–140:13. Accordingly, while Kennecott and Tesoro understand that it may not be appropriate in this docket for the Commission to revise Schedule 38 to include informational requirements, they request that the Commission acknowledge that the Company has pledged to timely provide the required information.

With respect to the issue now before the Commission on the ownership of renewable energy credits (“RECs”), the Company has proposed that whenever it is compelled to purchase power from a QF, the REC associated with the QF power should be transferred from the QF owner to the Company at no additional cost to the Company. Kennecott and Tesoro oppose this proposal and, for the reasons discussed below, urge the Commission to reject it. The better course of action, and the one the Commission already has taken in previous dockets, is for the Commission to conclude that, when the Company purchases power from a QF, the REC remains with the QF owner unless the Company and the QF owner voluntarily agree otherwise by contract.

UNDER THE RELEVANT STATUTES, KENNECOTT’s AND TESORO’S RECS ARE NOT “bundled” with THE POWER the company acquires in a QF purchase.

There seems to be no disagreement from the Company that the creation and disposition of RECs is entirely a matter of state law. Clements, Tr. 11:13-16. The statute at Section 54-17-603 requires the Commission to “establish a process for issuance or recognition of a renewable energy certificate.” Utah Code Ann. § 54-17-603. It describes certain characteristics of RECs. They may be bundled or unbundled, they do not expire, and they may be “banked, traded, sold, transferred or otherwise used to satisfy another state’s renewable energy requirement.” Id. at § 54-17-601(5), (7).

Kennecott and Tesoro generate unbundled RECs, which are not acquired by the utility in a QF power purchase. The statute defines an unbundled REC as:

a renewable energy certificate associated with:

(a) qualifying electricity that is acquired by an electrical corporation or other person by trade, purchase, or other transfer without acquiring the electricity for which the certificate was issued; or

(b) activities listed in Subsection (10)(e).”

Utah Code Ann. § 54-17-601 (11) (emphasis added).1 Subsection 11(a) quoted above describes the nature of an unbundled REC as one that is acquired without also acquiring the electricity. Subsection 11(b) refers to certain activities described in subsection (10)(e) that result in the production of unbundled RECs. Subsection (10)(e), in turn, describes activities and facilities which, when “located in the state and owned by a user of energy,” qualify as “renewable energy sources.” Among them, is:

a waste or waste heat capture or recovery system, other than from a combined cycle combustion turbine that does not use waste gas or waste heat, with the quantity of renewable energy certificates to which the user is entitled determined by the total production of the system, except to the extent the commission determines otherwise with respect to net-metered energy.

Id. at § 54-17-601(e)(10)(v). Both Kennecott and Tesoro operate facilities in Utah of the kind described in this subsection, and both are users of energy from the output of their own QFs as well as under service agreements with RMP. Thus, both Kennecott and Tesoro own and operate “renewable energy sources” that produce unbundled RECs under Section 601(11)(b). That means that Kennecott and Tesoro may consume some or all of the energy they generate and still retain the associated RECs to bank, sell, trade or otherwise monetize as a benefit of having made the investment in a renewable energy source. It also means that in a QF purchase from those facilities, RMP acquires the electricity, but not the corresponding REC. The REC, which comes into existence when the power is generated, is owned by the QF owner “without [the QF owner also] acquiring the electricity for which the certificate was issued.” Id. Consequently, unless the parties to the QF contract voluntarily agree otherwise, the statute holds that the RECs are owned by the commercial or industrial entities that produce them by engaging in the activities listed in Section 54-17-601(10)(e).

In sum, Kennecott and Tesoro (and other owners of the types of renewable energy sources described in Section 54-17-601(10)(e)), create only unbundled RECs, which are not acquired along with the electricity in a QF purchase. Therefore, the Commission appears to be prohibited by the statute from ruling that the REC is automatically acquired by RMP in a purchase from these kinds of QF facilities. As with RECs from all QF owners, the Commission should continue to hold, as it has in the past, that RECs from QF owners do not go to the public utility in a QF power purchase unless the parties agree otherwise in a voluntarily negotiated contract.

UNDER FEDERAL AND state LAW, the rec SHOULD REMAIN with the qf owner

In applying Utah law, the Commission must follow ordinary rules of statutory interpretation and therefore, it must construe all of its provisions, so far as consistent with the rules of construction, and apply them in harmony with, and in furtherance of, those purposes. U.S. Smelting, Refining & Milling Co. v. Utah Power & Light Co., 58 Utah 168, 197 P. 902, 905 (1921). All of the provisions must be considered together, within the purview of the act. Public Util. Comm’n of Utah v. Garviloch, 54 Utah 406, 181 P. 272, 275 (1919). Thus, to the extent the Commission has discretion in the interpretation or application of a statute, it must also look to statements of legislative policy codified in the statute. In this case, the purposes of both federal and state law are better served by a Commission decision that RECs should not be transferred to the Company in a QF purchase without the Company paying separate compensation to the QF owner under a contract with the QF owner. Without a voluntary agreement and adequate consideration to support the agreement, the RECs remain with the QF owner.

A.Under PURPA, the REC is Not Acquired by the Utility in a Purchase of QF Power Absent an Voluntary Agreement.

The Company claims that it is the intent of the Public Utility Regulatory Policies Act (“PURPA”) that “any power purchase agreement securing power from an eligible renewable energy resource should assign ownership of the associated RECs to the Purchasing Utility.” Clements Direct Testimony, at 5:103-5. The Company claims that if it does not receive the REC in a QF purchase it is “not receiving the very characteristic that enabled the facility to achieve its QF status” under PURPA. Clements Direct at 5:93-94. This is clearly incorrect. The Company acknowledged at the hearing that, at the time of PURPA’s enactment, there were no renewable energy credits, so it could not have been the intention of PURPA that the environmental attribute of QF output was to go along with the power in a QF purchase for the avoided cost of the power. Tr. at 143:1-9; 145:12-17.

PURPA was enacted in 1978 to encourage “the conservation of electric energy, increased efficiency in the use of facilities and resources by electric utilities, equitable retail rates for electric consumers,” and “to improve the wholesale distribution of electric energy.” 16 U.S.C. § 2601(2). As part of a broader plan, Congress enacted a purchase obligation, the policy for which is stated as follows:

The Commission [FERC] shall prescribe, and from time to time thereafter revise such rules as it determines necessary to encourage cogeneration and small power production, and to encourage geothermal small power production facilities at not more than 80 megawatts capacity, which rules require electric utilities to offer to

  1. Sell electric energy to qualifying co-generation facilities and qualifying small power production facilities and

  2. Purchase electric energy from such facilities.”

16 U.S.C. § 824a-3(a) (emphasis added). The purchase obligation was imposed expressly to “encourage co-generation and small power production.”

The purchase obligation was part of the larger purpose of PURPA to counteract, to some extent, the difficulties that faced developers of small renewable power generators in finding a wholesale market for their power. While some larger projects might be able to negotiate power purchase agreements for their output, generators less than 80 megawatts were at a disadvantage. To remove barriers to market entry and thereby stimulate development of small generators, Congress required that, upon the request of a QF owner, the public utility must purchase the entirety of the output from these small QFs. 16 U.S.C. § 824a-3(a). And, to ensure that the purchasing utility, as well as its ratepayers, remained indifferent to the purchase obligation, Congress provided that the price paid could not exceed the cost that the utility would avoid by purchasing the power instead of generating it itself. See 16 U.S.C. § 824a-3(b) (“No such rule prescribed under subsection (a) shall provide for a rate which exceeds the incremental cost to the electric utility of alternative electric energy.”).

The Federal Energy Regulatory Commission’s [“FERC”] regulations at 18 C.F.R. § 292.304(e) set forth the factors to be considered to calculate PURPA’s avoided cost rate. These factors do not include environmental attributes because, under PURPA and FERC’s implementing regulations, avoided costs were intended to put the utility in the same position when purchasing QF capacity and energy as if the utility either had generated the energy itself or purchased the energy from another source. American Ref-Fuel Co., et al. 105 FERC 61, 004, p. 15 (2003), Order on Reh'g, 107 FERC 61, 016, p. 5 (2004). Avoided cost rates are not intended to compensate the QF for more than capacity and energy. Id. In a more recent decision involving two cases, City of New Martinsville and Morgantown Energy Associates, FERC followed its decision in American Ref-Fuel Company, to reaffirm that the avoided cost rate does not compensate a QF for RECs or other environmental attributes and “[t]o the extent that the West Virginia Order finds that avoided-cost rates under PURPA also compensate for RECs, the West Virginia Order is inconsistent with PURPA.” Morgantown Energy Assoc., 140 FERC ¶ 61,223 (2012) (emphasis added). Consequently, the FERC orders directly hold that RECs are not included in the avoided cost paid by the utilities and that to require that they go with the power is “inconsistent with PURPA.” Regardless of what the value of the REC is, if it is greater than zero, the utility is not paying for capacity and energy at the avoided cost and therefore, RECs cannot go with the power according to these cases. Consistent with this Commission’s prior orders, these FERC decisions leave the parties in a position to voluntarily negotiate, through their QF contract, whether the utility will acquire the REC and if so, at what price.

B.Utah’s Policy Requires that the QF Owner Retain the REC in a QF Purchase.

Utah’s statute implementing the PURPA purchase obligation states a policy similar to that of PURPA:

It is the policy of this State to encourage the development of independent and power production and co-generation facilities, to promote a diverse array of economical and permanently sustainable energy resources in an environmentally acceptable manner, and to conserve our finite and expensive energy resources and provide for their most efficient economic utilization.

Utah Code Ann. § 54-12-1(2) (emphasis added). Thus, under both state and federal law, the utility’s purchase obligation is meant to encourage the development of renewable generation and other kinds of QF resources that may invoke the purchase obligation. For the Commission’s decision in this case to reflect the policy of both federal and state law, it must ask itself one question: Which better serves that policy – to allow RMP to take the REC in a QF purchase at the avoided cost, or to allow the QF owner to keep the REC? Obviously, the latter acts as an incentive to developers of renewable projects, while leaving ratepayers indifferent to the QF purchase.

C.The Commission has Already Decided that RECs Remain with the QF Owner Unless the Parties Agree Otherwise by Voluntary Contract.

This is not the first time that the Utah Commission has had to consider whether the REC goes to the utility or stays with the QF owner on a QF purchase. In the 2003 Large QF Avoided Cost Case, PacifiCorp’s 2004 IRP attributed a value of $5/MWh to the RECs associated with wind projects. Report and Order, Docket No. 03-035-14 at 24 (Oct. 31, 2005). Because the Commission adopted the RFP market-based price proxy, it determined that “PacifiCorp paid for the REC and therefore owns the RECs and the price includes the value of the RECs.” Id. at 15. But, the Commission also determined that the ownership of RECs was a contractual matter between the QF owner and the Company, and approved the request of the QF owner that it be allowed to buy back the REC at the IRP value. Id.

On reconsideration, the Company argued that the avoided cost pricing for wind was tied to the value of the REC, and that a QF could only obtain avoided cost pricing if the Company retained ownership of the REC. Order on Reconsideration and Clarification, Docket No. 03-035-14 at 15 (Feb. 6, 2006).2 The Commission disagreed. It affirmed the right of the QF “to purchase [buy back] the REC at the IRP value if the REC is included in the market-based proxy for calculating avoided costs for wind QFs up to the IRP target amount of wind.” Id. at 15. Even though the Company had paid for the REC in the avoided cost price, the Commission found that it was separable from the electricity, had a separate value, which in that case had been recognized in the IRP. The Commission, stated:

Ratepayers are indifferent to whether the Company contractually acquires ownership of the REC and then sells the REC to reduce the net cost of the resource or whether the Company contractually pays a price net of the REC to begin with. We are unaware of any Utah or federal law that eliminates the IRP described value of wind generation to ratepayers once the REC is sold. Indeed, our understanding of the RECs’ value is to offset some of the cost of wind resource development, thus, promoting it relative to other alternatives.

Id. at 16 (emphasis added).

In the present case, under the Company’s proposed pricing method, the IRP value of a REC is $0. Thus, under the Commission’s reasoning in the 2003 Avoided Cost case, since the Company proposes not to pay for the REC, it remains with the QF without any need for the QF to “buy it back.” The Commission’s reasoning embraced a sound policy consistent with federal and state law, finding that the value of the REC is to offset the cost of development of renewable energy and “to promote it relative to other alternatives.” Id.

The Commission reached a similar decision in the matter of Cottonwood Hydro, LLC v. Rocky Mountain Power, Docket No. 10-035-15 (May 27, 2010). In that case, RMP and Cottonwood Hydro (“Cottonwood”) entered into a power purchase agreement (“PPA”) for Cottonwood’s output that did not assign ownership of RECs, and apparently did not include any value for them in the avoided cost price. Cottonwood petitioned the Commission for a declaration of which party owned them. The Company advanced the same argument it is making in the present case – that unless it acquired RECs, it would not acquire “the very characteristic that triggered the utility’s obligation to purchase Cottonwood’s output.” Id. at 4. The Commission disagreed, and concluded as follows:

(1) The output of a generator of renewable energy contains two distinct commodities: (i) the bracket generated by the facility itself, and (ii) the environmental attributes of that power, i.e. RECs. Those commodities can be severed;

(2) Unless provided for otherwise in a contract, the RECs remain with the generator of renewable energy, and may be sold and valued separately from the energy produced or retained by the generator of the REC.

Id. at 11.

There is nothing in the Utah law that would compel any different result. The Commission’s decision was entirely consistent with Utah statutes in light of Utah’s stated policy. Leaving the REC with the QF owner encourages “the development of independent and qualifying power production and cogeneration facilities.” Id. at 54-12-1(2). Recognizing that RECs have value, the Commission wisely left it to the parties to negotiate whether the utility would acquire the REC and, if so, at what price.

The Company’s testimony urges the Commission to look to recent decisions of the public service commissions of Wyoming, Idaho and California as a model for setting policy in Utah. This is an invitation to error. Indeed, Wyoming and Idaho should have looked to the Utah Commission, which had already correctly determined the REC ownership issue before either of these states issued their recent orders. In its avoided cost docket, the Wyoming commission decided that it would not depart from Wyoming’s prior practice of bundling the REC with the power in a QF purchase. Memorandum Opinion, Findings and Conclusions, Docket No. 20000-388-EA-11 (Nov. 4, 2011). But, Wyoming has no statute creating RECs, specifying who owns them, declaring that certain RECs are unbundled, and no statement of legislative policy encouraging renewable development. The Wyoming commission focused on the extra revenue the Company would realize if it acquired RECs along with QF power, finding that RECs “represent tangible value for the ratepayer,” and that REC revenues are a “key component used to mitigate, to an extent, the effects on customers of the ongoing series of rate increases filed by RMP.” Id. at 18, ¶ 63.

This is not a decision that the Utah Commission can or should look to for support. The Wyoming commission was under no statutory constraint, as the Utah Commission is. It did not need to consider, as the Utah Commission must, how to best achieve the policy of encouraging development of renewable resources in applying the QF purchase obligation.3 And it did not apply sound reasoning, like this Commission should, to reject the specious arguments that the Company advances to retain the REC without paying for it.4

Likewise, contrary to the Company’s assertions, the Idaho commission’s recent decision addressing the treatment of RECs cannot provide any support for this Commission to decide the REC should go to RMP. The Idaho commission recognized that “the Idaho Legislature has not implemented a RPS program nor has it enacted any statute addressing the ownership or allocation of RECs.” In the Matter of the Commission’s Review of PURPA QF Contract Provisions including the Surrogate Avoided Resource (SAR) and Integrated Resource Planning (IRP) Methodologies for Calculating Avoided Cost Rates, Case No. GNR-E-11-03, Idaho Public Utilities Commission Order No. 32802 at 9-10 (May 6, 2013). In the absence of any statutory or legislative guidance, the Idaho commission looked to “Idaho common law [that] does not vest RECs exclusively in either the QF or the utility.” Id. at 19. It, therefore, attempted to “balance” the objective of encouraging renewable development against the obligation of the utility to purchase QF power, and affirmed its earlier decision that the REC “should be divided equally between the QF and the utility.” Id.

Unlike the Idaho commission, the Utah Commission must apply Utah statutes, not the common law. There is nothing in Utah law to suggest the Commission can divide a REC between the QF owner and the utility or, at least with respect to cogeneration QFs, decide that the utility acquires the REC when the QF power is generated. And, there is no counter-balancing policy in this state that would justify a decision compensating the utility for the purchase obligation by giving it free RECs along with the purchased power. The decision of the Idaho commission cannot guide the Utah Commission’s decision on this issue. 5

Having reached the right decision in its previous IRP orders and in the Cottonwood Hydro case, the Commission has established precedent with respect to the treatment of RECs. It must not depart from that precedent “unless [it] justifies the inconsistency by giving facts and reasons that demonstrate a fair and rational basis for the inconsistency.” Utah Code Ann. § 63G-4-403(h)(iii) (2008). The Company has not presented facts or offered any argument to demonstrate why it would be fair and rational for the Commission to reverse course and hold that the Company should receive RECs in a QF purchase without paying for them.

D.It is Unfair and Probably Unconstitutional to Allow the Utility to Take RECs in a QF Purchase Without Paying Additional Value for the REC.

RECs have independent value for which the QF owner would not be compensated if it were compelled to transfer the REC along with the QF power for no additional payment. Because the value of a REC represents an important revenue stream to developers of renewable sources of energy, the underlying policy for requiring the utility to purchase QF power would be defeated by a ruling that requires the REC to be transferred to the purchasing utility for only the avoided cost of the power.

The Company acknowledges that RECs have value. (E.g., Clements, Tr. 145:1). There is no evidence in this record of what that value might be today, other than it is not zero. But, the evidence indicates that the interstate market for RECs is becoming more robust and more liquid each year. As of early 2012, twenty-nine states and the District of Columbia had implemented a mandatory RPS and an additional eight states have voluntary goals. (Kennecott – Tesoro Exhibit 1.1.SR, at 3). This infrastructure provides a market for RECs to be bought, sold and transferred from one account to another. Id. Furthermore, the size of the REC market is expected to continue growing. Id.6

Like other commodities, there are currently a number of ways that RECs can be bought and sold. RECs can be bought and sold through formal exchanges or “over-the-counter.”7 Id. at 5. “Solar aggregators,” like stock brokers, may buy up solar RECs at a fixed price, and negotiate the sale of that portfolio with a load-serving entity. Id. Requests for proposals for the procurement of RECs, are not infrequent, and may vary from anywhere between once a year to every few months. Id. at 6. RECs may be auctioned through trading channels, which a few companies run online on a regular basis. Id.

A recent decision from the Seventh Circuit Court of Appeals may result in further expansion of the market for trading RECs by removing barriers that currently prevent one state’s RECs from being recognized in other states. In Illinois Commerce Commission v. Federal Energy Regulatory Commission, Case Nos.11-3421, 11-3430, 11-3584, slip op. (7th Cir., June 7, 2013), the court considered a state law that prohibited Michigan from crediting out-of-state wind power8 against the state’s renewable portfolio requirements. The court observed that the law “trips over an insurmountable constitutional objection” and that “Michigan cannot, without violating the commerce clause of Article 1 of the Constitution, discriminate against out-of-state renewable energy.” Id. By the same rationale, it could be argued that states cannot impose regulations that discriminate against out-of-state RECs. The removal of barriers to interstate trading of RECs would allow for the REC market to continue growing at an even faster pace.

The fact that the parties are even having this dispute about the ownership of RECs confirms that their value is significant. If the price of the power paid by a utility on a compelled QF purchase is set at the utility’s avoided cost, then a decision by this Commission that the associated RECs are bundled with the QF power would mean that the utility gets the REC without paying any value for it or, as Maurice Brubaker put it, “these QFs would be compensated at a level less than avoided cost.” Tr. 273:5-6. On its face, that result would be unfair to QF developers, who have risked their capital and credit to build renewable energy sources. At the same time, the Company’s witness could articulate no reason why it would be good policy under Utah law to require that result. Tr. 159:5–160:9.

Finally, The Commission has characterized RECs as “commodities.” Cottonwood Hydro, at 11. To the extent they can also be characterized as intangible property,9 a Commission decision compelling a private QF owner to convey the REC to the utility without just compensation would amount to an unconstitutional taking of private property in violation of the Fifth and Fourteenth Amendments to the U.S. Constitution, and would obligate the state to compensate the QFs for the value of their RECs. U.S. Const. art. 1, §§ 5, 14; Utah Const. art. 1, §22.


The Commission should reject the Company’s proposal to establish a policy that RECs are acquired by the utility upon the purchase of QF power at the avoided cost. Such a policy is contrary to Utah statutes and prior Commission decisions, inconsistent with FERC orders applying PURPA, inimical to the stated legislative purposes of both PURPA and Utah’s statute, unfair to developers of renewable energy sources, and probably unconstitutional. It is rare, in fact, that the Commission ever encounters a more ill-conceived proposal. The Commission should instead stay the course on which it has already embarked and affirm its previous orders that, in a QF purchase by the utility, the RECs remain with the QF owner unless the parties agree otherwise through a voluntary contract.

Finally, Kennecott and Tesoro respectfully request that the Commission acknowledge RMP’s pledge to timely provide to any party who requests it, all of the information necessary to verify the avoided cost price offered by the Company for QF power.

DATED this 27th day of June, 2013.

/s/ William J. Evans

F. Robert Reeder

William j. evans

Vicki M. Baldwin


Attorneys for Kennecott Utah Copper, LLC and Tesoro Refining and Marketing Company


(Docket No. 12-035-100)

I hereby certify that on this 27th day of June 2013, I caused to be e-mailed, a true and correct copy of the foregoing POST-HEARING BRIEF to:

Patricia Schmidt
Assistant Attorneys General
500 Heber Wells Building
160 East 300 South
Salt Lake City, UT 84111
David L. Taylor
Yvonne R. Hogle
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, UT 84111
Paul Proctor
Assistant Attorneys General
500 Heber Wells Building
160 East 300 South
Salt Lake City, UT 84111
Michele Beck
Executive Director
Committee of Consumer Services
500 Heber Wells Building
160 East 300 South, 2nd Floor
Salt Lake City, UT 84111
William Powell
Dennis Miller

Chris Parker

Division of Public Utilities
500 Heber Wells Building
160 East 300 South, 4th Floor
Salt Lake City, UT 84111

Cheryl Murray

Dan Gimble

Utah Committee of Consumer Services

160 East 300 South, 2nd Floor

Salt Lake City, UT 84111
Sophie Hayes

Utah Clean Energy

1014 2nd Avenue

Salt Lake City, UT 84111
Ros Roca Vrba

Energy of Utah LLC

P.O. Box 900083

Sandy, UT 84090-0083
Robert Millsap

Renewable Energy Advisors

P.O. Box 900036

Sandy, UT 84090
Gary A. Dodge


10 West Broadway, Suite 400

Salt Lake City, UT 84101

Christine Mikell

Wasatch Wind

4525 S. Wasatch Blvd., Suite 120

Salt Lake City, UT 84124

Brian W. Burnett

Callister Nebeker & McCullough

10 East South Temple, Suite 900

Salt Lake City, UT 84133
Ellis-Hall Consultants, LLC

P.O. Box 572098

Murray, UT 84107-6764

Steven S. Michel

Western Resource Advocates

409 E. Palace Ave. Unit 2

Santa Fe, NM 87501
Nancy Kelly

Western Resource Advocates

9463 N. Swallow Rd.

Pocatello, ID 83201
Charles R. Dubuc

Western Resource Advocates

150 South 600 East, Suite 2AB
Salt Lake City, UT 84102

Cynthia Schut

Western Resource Advocates

150 South 600 East, Suite 2AB

Salt Lake City, UT 84102
Maura Yates

Sun Edison, LLC

201 Lavaca, Ste #302

Austin, TX 78701
Mike Ostermiller

Kyler, Kohler, Ostermiller & Sorenson

1833 W. Royal Hunte Drive, Suite 200
Cedar City, UT 84720

Chris Kyler

Kyler, Kohler, Ostermiller & Sorenson

PO Box 599

Salt Lake City, UT 84110
Jerold G. Oldroyd

Tesia N. Stanley


One Utah Center, Suite 600

201 South Main Street

Salt Lake City, Utah 84111-2221

/s/ Colette V. Dubois

1 By contrast, a “bundled REC” is “a renewable energy certificate for qualifying electricity that is acquired:

(a) by an electrical corporation by a trade, purchase, or other transfer of electricity that includes the renewable energy attributes of, or certificate that is issued for, the electricity; or

(b) by an electrical corporation by generating the electricity for which the renewable energy certificate is issued.

Utah Code Ann. § 54-17-601(4) (emphasis added). Because an “‘Electrical corporation’ … does not include a person generating electricity that is not for sale to the public,” no QF owner generates a bundled REC unless it also generates electricity “for sale to the public.”

2 One QF pointed out in rebuttal that the Company recognizes the separate value of RECs when it purchases RECs to fulfill purchases of renewable wind power under its “Blue Sky” program. Id.

3 The Wyoming Commission was apparently under the mistaken impression that the “intent” of Section 210 of PURPA supported “retention of the RECs by the utility.” See Mem. Op. at 7, ¶ 30 (discussing Paul Clements’ testimony on the “intent” of PURPA); and see discussion supra at section II.A of this Post Hearing Brief.

4 This is the Wyoming commission’s entire explanation of the reason for crediting Paul Clements’ testimony on the REC issue:

The Commission finds the testimony of RMP witness Clements more persuasive on this issue. In his rebuttal testimony, Clements gives two reasons why RECs should be retained by the utility (RMP Exhibit 4, pp. 2-3.) The Commission finds his second argument, i.e., “Wyoming customers should not have to pay something extra for – or be deprived of the right to truthfully claim – something that is actually taking place, which is PacifiCorp’s purchase of energy from a particular QF” to be more persuasive.

Mem. Op. at 18, ¶ 63.

5 As an example of why the Utah Commission should decline to follow the policies implemented by the Idaho Public Utilities Commission, it should be noted that in March 2013, the FERC brought an enforcement action against the Idaho PUC, alleging that its "requirement that, in the absence of a fully executed contract, a QF must file a meritorious formal complaint with the Idaho commission in order to security a legally enforceable obligation, is inconsistent with and therefore violates PURPA and FERC's PURPA regulations." Grouse Creek Wind Park, LLC, 142 FERC 61,187 (2013).

6 In 2011, RPS rules required 133 million MWh of electricity from renewable facilities, a 22-fold increase over a decade earlier. Id. RPS requirements are forecast to grow to 210 million MWh by 2015. Id. Similarly, one report estimated the voluntary demand reaching between 63 million and 157 million MWh by 2015, up from 35 million MWh in 2010. Id.

7 There are currently active REC markets in New England, the PJM Interconnection (Ohio, Pennsylvania, New Jersey, Delaware, Maryland and the District of Columbia), Texas and California, among others. Id. at 8.

8 While this case does not deal specifically with RECs, the principle of law may be equally applicable to the present discussion.

9 See, e.g., Wheelabrator Lisbon v. Connecticut Dept. Pub. Util. Control, 531 F.3d 183, 186 (2d Cir. 2008) (“RECs are inventions of state property law whereby the renewable energy attributes are ‘unbundled’ from the energy itself and sold separately.”) (emphasis added).


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