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November 24, 2015

Wind Integration Costs at Issue in Oregon PURPA Dispute

For the past several years, Portland General Electric Company (PGE) has been battling with the developer of a remote supplier of wind power over who bears responsibility for the costs of integrating the supplier’s variable output into the grid. In two orders issued earlier this year,[1] the Federal Energy Regulatory Commission (FERC) sided with the developer, holding in effect that incurring those costs was incidental to PGE’s obligation under the Public Utility Regulatory Policies Act of 1978 (PURPA) to enable the developer to sell the entire net output of its facility to PGE.

On November 18, 2015, the dispute took a new turn when the developer filed a complaint with FERC asserting that PGE has been thwarting FERC’s Orders by refusing to cooperate in establishing a “pseudo-tie,” a specialized procedure for transferring energy between portions of the electric grid controlled by separate balancing authorities.[2] While PGE has yet to answer the complaint, it has taken the position in discussions with the developer that it has done all that the FERC Orders require, and that the pseudo-tie issue is a matter between the developer and the Bonneville Power Authority (BPA), the balancing authority where the wind project interconnects to the grid.

Given FERC’s position thus far, it seems likely that FERC will continue to side with the developer. However, both sides to the dispute have already filed petitions for review of the earlier orders,[3]and it is likely that the pseudo-tie issue will also end up in court, however FERC resolves it. If so, it may shed light on the application of PURPA to situations that could hardly have been imagined when the statute was enacted.

PURPA requires utilities to buy power from certain renewable resource-based generation facilities (Qualifying Facilities, or QFs) at rates designed to reflect the costs the utility would otherwise incur if it generated the power itself or acquired the power from another source (so-called avoided costs).[4]  State regulatory commissions have the responsibility to set avoided cost rates.[5] In April 2010, PGE and PáTu Wind Farm, LLC entered into the Oregon Commission’s Standard PURPA Contract for 10-MW or smaller off-system, intermittent resource QFs. Consistent with FERC regulations, the contract required PáTu to arrange (and pay) for transmission of the power to the PGE system. PáTu began selling power to PGE in December 2010.[6]

Shortly after the contract was signed, a dispute broke out between PáTu and PGE over PáTu’s right to use “dynamic scheduling” of its power deliveries. Dynamic Scheduling service, which BPA offered to PáTu, would have allowed scheduling and delivery to PGE of PáTu’s precise, instantaneous output, as it varied with wind conditions. Using that service would have allowed PáTu to avoid paying several charges that BPA otherwise imposed on wind generators to account for the costs to the grid of accommodating intermittent resources (wind integration costs).  However, availing itself of Dynamic Scheduling service required the cooperation of PGE, which the latter refused to provide. PGE relied on the fact that its contract with PáTu did not require dynamic scheduling, but rather provided for power deliveries to be scheduled in megawatt blocks on an hourly basis. Under that form of delivery, PáTu would have had to absorb the wind integration costs imposed by BPA.[7]

In 2011, PáTu filed a complaint with the Oregon PUC asking that PGE be ordered to accede to dynamic scheduling, both so that PáTu could sell the entire net output of its plant to PGE and so that PáTu did not have to incur wind integration costs. PáTu pointed out that in setting the avoided cost-based rates reflected in the Standard Contract, the Oregon Commission had expressly held that no adjustment to those rates was required to account for wind integration costs, and that QFs eligible for those rates were not required to pay for wind integration services.[8]  In denying PáTu’s request, the PUC found that the matter of dynamic scheduling was outside the scope of the contract:

The contract addresses scheduling coordination between PGE and PáTu, and requires PáTu to honor the prescheduled amount. The PPA does not specify how PáTu should honor the prescheduled amount, either by dynamic transfer, the purchase of imbalance and wind integration services, or in some other manner. …[T]he PPA is a standard contract not tailored to specific situations. One or both parties may decide to take certain actions to implement the PPA, such as setting up dynamic transfer or entering into a third party contract for imbalance and wind integration services, but such actions are not mandated by the contract, whether directly by its terms or indirectly by contractual principles such as good faith and fair dealing.[9]

The PUC further held that it lacked the authority to order dynamic scheduling on the ground that that issue related to interstate transmission, which was exclusively the domain of FERC.[10] The PUC added that “If it is PáTu’s position that a dynamic transfer arrangement is the only means to perform its duties under the contract—that is, for PáTu to schedule and deliver Net Output within a reasonable band—then the contract may be void or voidable…”[11]

PáTu’s next stop was the FERC where, in October 2014, it filed a complaint against PGE. PáTu challenged PGE’s refusal to cooperate with dynamic scheduling on several grounds, including that it amounted to undue discrimination by PGE in administering its Open Access Transmission Tariff (OATT) (since PGE allegedly required dynamic scheduling for generators bidding into RFPs to serve its native load) and violated PáTu’s PURPA rights. On the latter point, PáTu argued that PGE’s refusal resulted in PáTu having to pay wind integration costs, which dramatically reduced what it recovered under its avoided cost rates. In addition, it claimed that without dynamic scheduling, BPA absorbed energy generated by PáTu in excess of its hourly schedules without delivering that excess to PGE, which prevented PáTu from being paid the avoided cost rate for the excess.  PáTu also alleged that PGE violated its duty under PURPA to cooperate with QFs.[12]

PGE answered PáTu’s discrimination arguments in several ways. It asserted, first, that PáTu could not claim discrimination under PGE’s transmission tariff because PáTu, which was only obligated to arrange for transmission to the border of PGE’s system, was not a transmission customer under PGE’s OATT. Instead, PGE asserted, PGE’s merchant function (which managed PGE’s PPAs) was the transmission customer; and the merchant function had decided, for legitimate economic reasons, not to allow dynamic scheduling of PáTu’s output, since doing so would make the PPA less valuable for PGE (by freeing PáTu from the obligation to deliver power in megawatt blocks pursuant to hourly schedules) without any adjustment to the contract price.[13]

PGE also argued that its refusal to provide dynamic scheduling was consistent with the Oregon PUC’s ruling that the PPA did not address dynamic scheduling. PGE noted that under Oregon PURPA regulations, PáTu had been free to negotiate a contract that dealt with dynamic scheduling, but voluntarily chose instead to execute the Standard Contract, which did not. In addition, PGE pointed to Commission precedent for the proposition that a purchasing utility is not required to schedule QF power dynamically.[14]

In deciding the merits of the Complaint, the Commission largely sidestepped the arguments of the parties. “While the parties’ pleadings focus on dynamic scheduling,” the Commission stated, “the issue in this case is whether Portland General is fulfilling its obligations under PURPA and Commission regulations, as implemented by the Oregon Commission.”[15] While acknowledging that the PPA required PáTu to schedule hourly deliveries of contract power at least one day ahead of the actual deliveries, that requirement did not override other contract provisions and Commission regulations that required PGE to purchase the entire net output of the facility. The relevant PPA provisions were Sections 1.18, which defined “Net Output” as “all energy produced [by PáTu], less onsite uses and losses;” and 4.1, which stated that PáTu will sell its “entire Net Output delivered from the Facility at the Point of Delivery.”

The Commission cited policy reasons that argued against reaching a different result:

If… Portland General were permitted … to refuse to accept PáTu’s entire net output, Portland General and other electric utilities could routinely escape their PURPA mandatory purchase obligation, and indeed the Standard Contract-imposed purchase obligation, by imposing overly restrictive or un-meetable scheduling requirements, or by the purchasing electric utility’s failing to arrange the necessary transmission service to dispose of its purchase of the QF’s entire net output once it has been delivered to the utility.  Similarly, that the Commission has not in its regulations required the use of dynamic scheduling is not a basis to excuse Portland General from the separate obligation under PURPA and the Commission’s regulations, as relevant here, to purchase PáTu’s entire net output delivered to Portland General.[16]

The Commission went on to state that while it was up to PGE’s merchant function to choose how to deliver PáTu’s net output to PGE’s load, whether by dynamic scheduling or another method, PGE ”must take from PáTu its entire net output (all energy less onsite uses and losses) delivered and to [sic] do so at avoided cost rates.”[17]

Both PáTu and PGE filed requests for rehearing. PáTu’s request asked the Commission to make clear that (1) PGE must cooperate in allowing PáTu to deliver power through dynamic scheduling, since any other scheduling method would make it impossible for PáTu to deliver its entire net output; and (2) PGE cannot condition acceptance of dynamic scheduling on PáTu’s agreement to pay PGE for wind integration services, because PáTu’s forecasted avoided cost rates were specifically calculated so that no wind integration charges would be assessed to PáTu.[18]

In its request,[19] PGE asked the Commission to acknowledge that (1) PGE had honored the PPA by accepting and paying avoided costs for all power delivered to PGE in accordance with the PPA scheduling provisions; (2) FERC precedent and regulations require PáTu, as a QF, to bear all costs associated with delivering power to PGE, as the purchaser; and (3) PURPA does not require a purchasing utility to agree to dynamic scheduling. It also argued that the Commission’s interpretation of the PPA failed to give effect to the intent of the scheduling provisions, which were reasonably designed to ensure that the output of the facility was delivered to PGE. According to PGE, the PPA provided “a mix of cost and benefits, and selectively reading the contract to detach PáTu’s obligation to schedule from Portland General’s purchase obligation reshapes the contract in a manner not originally intended.”

In an Order issued June 18, 2015, the Commission essentially denied both parties’ rehearing requests. The Commission reiterated its holdings that PURPA required PGE to purchase the entire net output of PáTu, and was not free to impose scheduling requirements that impaired PáTu’s ability to deliver that output to PGE; and that the PPA, read as a whole, obligated PGE to accept and pay for the entire net output.[20] The Commission also dismissed PGE’s argument that allowing PáTu to insist on dynamic scheduling, with wind integration costs falling on PGE’s shoulders, upset the economics of the PPA. That argument, the Commission said, ignored the Oregon Commission’s holding that “under the Standard Contract pursuant to which PáTu sells to Portland General, small QFs such as PáTu are not responsible for additional wind integration costs because those costs were already taken into account in calculating the avoided cost rate.”[21]

While the Commission rejected all of PGE’s arguments, it also rejected PáTu’s request for clarification that PGE was obligated to participate in dynamic scheduling, finding the clarification unnecessary:

… PáTu has the responsibility to deliver its output to Portland General, and PáTu has demonstrated that BPA is willing to provide dynamic scheduling to PáTu so that PáTu can deliver its entire net output to Portland General.  Therefore, it is Portland General’s obligation to accept PáTu’s entire net output, whether by dynamic scheduling or some other method.  Regardless of the transmission or delivery service Portland General’s merchant function eventually decides to use to deliver PáTu’s net output … to Portland General’s load, PURPA and the Standard Contract require Portland General to purchase PáTu’s entire net output, including both the scheduled as well as the unscheduled net output delivered to Portland General’s system, at full avoided cost rates.  For this reason, PáTu’s request is unnecessary in order to provide PáTu relief under PURPA and the Standard Contract.[22]

Following issuance of the rehearing order, PáTu learned that BPA required the establishment of a pseudo-tie in order to allow dynamic scheduling of the output of PáTu’s facility.  When informed of this requirement, PGE took the position that while it would (under protest) participate in dynamic scheduling, it would not agree to a pseudo-tie. PGE noted that Standards of the North America Electric Reliability Council (NERC) and BPA business practices recognize a distinction between dynamic scheduling and pseudo-ties, and that “While it is unfortunate that BPA has taken this position [i.e., that it would require a pseudo-tie for dynamic scheduling], it appears that it is an issue between PáTu and BPA.”[23]

As noted, on November 18, 2015, PáTu filed another complaint at FERC, this time alleging that PGE was violating FERC’s two orders on its earlier complaint. While acknowledging that PGE was now willing to cooperate in dynamic scheduling, PáTu argued that PGE’s refusal to agree to a pseudo-tie violated FERC’s orders since BPA had now made clear that a pseudo-tie was necessary to permit delivery of the full net output of PáTu’s facility to PGE.[24] PGE’s argument in opposition to the pseudo-tie, said PáTu, was

old wine in new bottles. In response to PáTu’s [prior] complaint …, Portland General insisted that the Standard Contract under which it purchases PáTu’s output requires hourly scheduling in flat, whole-MW blocks, a stance it maintained even after the OPUC rejected its construction of the Standard Contract. The Commission properly rejected Portland General’s claims. In response, Portland General has changed tack, now insisting that it has no obligation to permit a pseudo-tie. But, because BPA requires a pseudo-tie for dynamic scheduling, the result is the same: Portland General continues to unilaterally dictate how PáTu delivers power to Portland General’s BAA, and continues to insist on a form of scheduling that necessarily prevents PáTu from delivering its entire net output to the Portland General BAA. But the Commission’s [prior] Orders make clear that Portland General may not “take actions and dictate scheduling requirements that  limit the deliverability of the QF’s net output…[25]

While PGE has not yet filed its Answer, it seems likely that if and when it does, it will continue to argue that it has met its obligation to permit the full delivery of the net output of the PáTu facility by agreeing to cooperate in dynamic scheduling, and that the pseudo-tie issue is a matter for PáTu to work out with BPA. Given that PGE has also maintained that it is cooperating under protest, it also seems likely that, however the Commission rules on PáTu’s latest complaint, the Commission will not have the final say in the matter.

In defending its decisions in court, the Commission routinely argues that its interpretations of the statutes and regulations it administers are entitled to deference.  How a reviewing court would respond in this case is, of course, a matter of speculation.  At a minimum, it will be interesting to see whether a reviewing court finds persuasive the Commission’s position that its interpretation of the statutes was necessary to prevent electric utilities from “routinely escap[ing] their PURPA mandatory purchase obligation, and indeed the Standard Contract-imposed purchase obligation, by imposing overly restrictive or un-meetable scheduling requirements, or by the purchasing electric utility’s failing to arrange the necessary transmission service to dispose of its purchase of the QF’s entire net output once it has been delivered to the utility.” [26] PGE may be expected to argue that its motivation was not to “escape its PURPA obligation,” but rather involved nothing more than invoking its scheduling rights under a contract imposed on it by the State of Oregon, and its right under FERC regulations to be free of the cost of delivering PURPA contract power to its system. Just as PáTu was not obligated to use the Standard Contract, other QFs can avoid having utilities “impose overly restrictive or un-meetable scheduling requirements” by raising those matters in PPA negotiations with utilities.

PURPA came into being in a far simpler era, when the grid was largely controlled by vertically integrated utilities and reliability was addressed through voluntary coordination. Concepts as ethereal as pseudo-ties and wind integration costs could hardly have been imagined, let alone predicted. With increasing competition, the need for PURPA has been questioned and, indeed, Congress has created procedures for utilities to avoid further PURPA obligations in certain circumstances.[27] Nonetheless, PURPA remains a vehicle for many developers of renewable power projects to require utilities to buy their power at state-administered costs. The PGE-PáTu litigation may shed additional light on the adaptability of PURPA to the evolving competitive marketplace.

[1] PáTu Wind Farm LLC v. Portland General Elec. Co., 150 FERC ¶61,032, reh. denied, 151 FERC ¶61,223 (2015).

[2] Docket No. EL16-16, Complaint of PáTu Wind Farm LLC (November 2015 Complaint). As FERC has explained, the term  “pseudo-tie” refers to a category of “dynamic transfers,” which in turn are arrangements to transfer energy or ancillary services between two separate balancing authority areas (BAAs):

A dynamic transfer is the transfer of energy or ancillary services from resources in one BAA into another BAA.  The two basic categories of dynamic transfers are dynamic schedules and pseudo-ties.  A dynamic transfer is considered a dynamic schedule when the resource supplying the energy or ancillary services remains under the control of the BAA where the resource is interconnected.  A dynamic transfer is a pseudo-tie when the BAA into which the energy or ancillary services are delivered performs the BAA functions for the resource (i.e., supplying the energy or ancillary services) even though that resource is interconnected to another BAA’s electric system.

California Independent Sys. Operator, 136 FERC ¶ 61,239 at P2 (2011).

[3] Docket Nos. 15-1237 and 15-1275 (D.C. Cir.), petitions filed July 22, 2105 (PGE) and August 12, 2015 (PáTu). PáTu has also filed an action in the U.S. District Court for the District of Oregon seeking contract damages and other relief against PGE. PáTu Wind Farms LLC v. Portland General Elec. Co., No. 3:15-cv-031373-br. That action is being held in abeyance pending the DC Circuit’s action on the pending appeals. November 2015 Complaint at 12 n. 40.

[4] 16 U.S.C. §824a-3 (2015); 18 C.F.R. §§ 292.303, 292.304 (2015); see generally Small Power Production and Cogeneration Facilities; Regulations Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, Order No. 69, FERC Stats. & Regs. ¶ 30,128, order on reh’g, Order No. 69-A, FERC Stats. & Regs. ¶ 30,160 (1980), aff’d in part & vacated in part on other grounds sub nom. Am. Elec. Power Serv. Corp. v. FERC, 675 F.2d 1226 (D.C. Cir. 1982), rev’d in part on other grounds sub nom. Am. Paper Inst. v. Am. Elec. Power Serv. Corp., 461 U.S. 402 (1983).

[5] 16 U.S.C. §824a-3(f) (2015); 18 C.F.R. § 292.302(e) (2015).

[6] 150 FERC ¶61,032 at P 5.

[7] 150 FERC ¶61,032 at P 11.

[8] 150 FERC ¶61,032 at P  6.

[9] Opinion 14-287 at 14.

[10] Ibid.

[11] Ibid. (italics in original).

[12] 150 FERC ¶61,032 at P21. PáTu’s FERC Complaint also alleged violations of the Commission’s requirements for nondiscriminatory treatment of wind generators in Integration of Variable Resources, Order No. 764, FERC Stats. & Regs. ¶31,331, order on reh’g and clarification, Order No. 764-A, 141 FERC ¶ 61,232 (2012), order on clarification and reh’g, Order No. 764-B, 144 FERC ¶ 61,222 (2013); and of FERC’s Standards of Conduct, 18 C.F.R. §§ 358.2(a), 358.2(b),  358.4, 358.5 (2014).

[13] 150 FERC ¶61,032 at PP 30-35.

[14] 150 FERC ¶61,032 at P 36, citing Connecticut Valley Elec. Co. v. Wheelabrator Claremont Co., 82 FERC ¶ 61,116 (Connecticut Valley), order on reh’g and clarification, 83 FERC ¶ 61,136 (1998).

[15] 150 FERC ¶61,032 at P 50.

[16] 150 FERC ¶61,032 at P 53.

[17] 150 FERC ¶61,032 at P 54 (footnote omitted; italics in original). The Commission also rejected PáTu’s claim that PGE violated the Commission’s Standards of Conduct. Id. at P 56.

[18] Docket No. EL15-6-001, PáTu Wind Farm LLC v. Portland General Elec. Co., Request of PáTu Wind Farm for Rehearing (Feb. 23, 2015).

[19] Docket No. EL15-6-001, PáTu Wind Farm LLC v. Portland General Elec. Co., Request of Portland General Electric Company for Rehearing (Feb. 23, 2015).

[20] 151 FERC ¶61,223 at PP 44-51.

[21] 151 FERC ¶61,223 at P 53.

[22] 151 FERC ¶61,223 at P 56 (footnote omitted). While the Commission did not say so, it is possible that the Oregon Commission’s statement that the PPA might be void or voidable if it could  only be implemented with dynamic scheduling factored into its reluctance to order PGE to cooperate with dynamic scheduling.

[23] PáTu November 2015 Complaint, Attachments 7, 10; see footnote 2, supra.

[24] PáTu also acknowledged that PGE had moved off of its earlier insistence that deliveries be scheduled on an hourly basis, and was now accepting 15-minute schedules. That was still unsatisfactory, PáTu claimed, because PáTu could not predict the output of its facility with certainty even on a 15-minute basis, and accordingly its output still would not match its schedules. November 2015 Complaint at 25.

[25] November 2015 Complaint at 13 (footnotes omitted).

[26] 150 FERC ¶61,032 at P 53.

[27] Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594, §1253(a); see generally New PURPA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration Facilities, Order No. 688, FERC Stats. & Regs. ¶ 31,233(2006), order on reh’g, Order No. 688-A, FERC Stats. & Regs. ¶ 31,250 (2007), appeal denied sub nom. American Forest and Paper Assoc. v. FERC, 550 F.3d 1179 (D.C. Cir. 2008).

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