A consensus that appeared to be coalescing for how to revise PJM’s Incremental Auction process and address replacement capacity issues seems to have dissipated.
Stakeholders had been combining ideas into joint packages, but PJM’s Jeff Bastian announced at last week’s meeting of the Incremental Auction Senior Task Force that the packages had separated back into five individual proposals.
The first proposal from PJM staff focused on giving Base Residual Auction sellers confidence that their commitment can be replaced in an IA “with little likelihood of economic loss and in fact a high likelihood of profit.”
“We changed our proposal around quite a bit as we thought through this,” Bastian said. “It’s not the objective of this package to force the Incremental Auction clearing prices toward the clearing price … but it is the intent to correct what we think are existing design flaws which force just the opposite to happen, especially when it comes to the PJM sellback of excess.”
GT Power Group’s Jeff Whitehead disagreed with PJM’s proposal to allocate excess commitment credits (ECCs) to load-serving entities.
“That logic ignores the fact that LSEs bear the risk of, and pay for, any excess capacity that underlies ECCs on behalf of their customers, and it is the terms of retail contracts with those customers that determine whether that excess capacity risk gets passed through to customers,” he said in an email to RTO Insider. “To the extent excess capacity risk is passed through by an LSE to its customers, then it follows that the proceeds associated with ECC sales should be passed through as well. If the excess capacity risk is not passed through to customers, and borne by the LSE, then it follows that the LSE would retain the proceeds of ECC sale. PJM’s proposal to not allocate ECCs to LSEs is unprecedented in that it incorrectly presumes the terms of retail contracts and deprives LSEs and their customers of the option to monetize the excess capacity for which they have paid.”
PJM argues that the current allocation system incents anyone looking to purchase replacement capacity to “hold out for a ‘better deal’ from a party that may be allocated ECC megawatts” rather than purchase PJM excess capacity during an IA.
Calpine’s David “Scarp” Scarpignato agreed with Whitehead’s argument, but pointed out that the allocations help the entire system. “When you get into individuals making decisions, that doesn’t work. It has to be a systemwide decision,” he said.
The Independent Market Monitor’s proposal is also focused on addressing IA clearing prices that are well below BRA clearing prices, but it differs on implementation. Both PJM and the Monitor envision just two IAs, with the RTO releasing capacity only in the final one. The current schedule has the BRA and three IAs for each delivery year. However, the Monitor would have the changes implemented with the third 2018/2019 IA, while PJM is targeting the 2021/2022 delivery year.
Direct Energy said it reintroduced its proposal based on concerns expressed at the IASTF’s last meeting. The package differs from PJM in that it puts a “collar” around the variable resource requirement (VRR) demand curve.
“With no collar, the possibility exists that all third-party suppliers sell at a price just below the BRA price, pushing any excess PJM [megawatts] out of the market,” Direct Energy’s proposal reads. “The result is that load still pays for the excess capacity and actually increases load’s scaling factors — increasing the overall cost of capacity.”
CPower’s Bruce Campbell offered a proposal “intended to maximize the benefit of Incremental Auctions to load interests with minimal changes to the current structure.” Described as “a compromise of stakeholder positions,” Campbell said it meets most of the preferences from initial polling, including maintaining three annual auctions between the BRA and the delivery year and having PJM sell excess capacity in each of them.
“My belief is that more supply will be coming from market participants than from PJM in future years. We’ve seen a lot of excess from PJM due to very high load forecasts in the BRA,” Campbell said. “I think PJM has taken substantive steps to address that, and I expect that most excess supply that’s available in Incremental Auctions will now come from market participants rather than PJM.”
The proposal offered by Gregory Pakela of DTE Energy Trading would set a different type of collar: a minimum sell offer at 50% of the BRA clearing price and a maximum at 100%. PJM would offer all its excess capacity in each of three IAs. Pakela offered research and analysis for his proposal, which led him to conclude, like Campbell, that PJM is unlikely to sell off a large quantity of commitments ever again. The corresponding reduction in sell offers will increase IA clearing prices, they say.
Scarp said the proposal neglected to account for the fact that capacity within a locational deliverability area must be replaced by other capacity in that LDA.
“PJM, I think, did a good job of addressing their sell offer, which everybody agrees is a major problem, probably the biggest problem,” Scarp said. “But there’s still other problems.”
FERC last week rejected SPP’s proposed Tariff revisions requiring load-responsible entities (LREs) to maintain sufficient capacity and planning reserves (ER17-1098).
The commission found SPP’s filing “inadequate in several respects” and said key elements must be addressed to help ensure successful implementation of a resource adequacy requirement (RAR).
FERC’s offices in Washington, D.C.
At the same time, the commission offered the RTO guidance to help it “fully develop its proposal” for future submission. A quorum-less FERC in May also found SPP’s initial Tariff revision to be deficient. (See Waiting on FERC, SPP Members Cut Reserve Margin.)
“We expect to work with our stakeholders in assessing FERC’s suggestions,” Lanny Nickell, SPP’s vice president of engineering, said Friday. “We will continue efforts to incorporate a comprehensive set of resource adequacy requirements in our Tariff.”
SPP submitted the Tariff revision in March under Section 205 of the Federal Power Act. Nearly two dozen SPP members intervened in the proceeding.
In January, the RTO’s board and stakeholders approved a package of policies that included reducing its planning reserve margin from 13.6% to 12%, which translates to a 10.7% capacity margin. A task force spent more than two years developing the package, which is projected to reduce SPP’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)
Included in the package was a proposed Tariff revision stipulating that an LRE — an asset owner serving load in SPP’s markets — maintain sufficient firm capacity to serve its peak load and maintain a predetermined planning reserve margin.
Under the revision, an LRE’s net peak demand is defined as the forecasted highest demand for energy, including transmission losses, plus the volume of megawatts subject to firm power sales contracts. The revision defines firm power as power sales and purchases deliverable with firm transmission service, where the seller assumes the obligation to serve the purchaser’s load with capacity, energy and planning reserves that must be continuously available in a manner comparable to power delivered to native load customers.
FERC noted that it has previously ruled that power purchase agreements be backed by verifiable capacity in order to serve as capacity resources. It pointed to a 2008 order in which it said it did not consider a market participant’s statements “to be sufficient to constitute verification” and required that MISO be given a copy of a PPA to verify the capacity backing the agreement. The commission said SPP’s proposal lacked such requirements.
“As such, SPP’s proposal fails to ensure that LREs that rely on power purchase agreements are providing sufficient capacity to meet their net peak demand plus planning reserve margin on the same basis as LREs that self-supply their own capacity, and therefore could result in unjust, unreasonable and unduly discriminatory determinations of deficiencies and assessments of deficiency payments,” FERC said.
The commission also said SPP’s proposed treatment of firm power purchases and sales in determining net peak demand could result in undue discrimination. It pointed to intervenors’ arguments that if the purchaser under the contract is an LRE located in SPP, but the seller is an entity located outside the footprint, then no entity would have the obligation to demonstrate to the RTO that there is sufficient capacity and planning reserves to meet the load in SPP served by the firm power contract. It said that LREs that purchase from an external seller should be responsible for meeting SPP’s RAR for the load served by the purchase.
FERC also found that SPP did not show that its proposal to post publicly which LREs have not met their RAR to be just and reasonable, and said that SPP failed to provide justification for “creating a new information asymmetry between deficient LREs and potential sellers of capacity.”
The commission noted that SPP’s market for bilateral capacity is “relatively net long” compared to the 12% reserve margin.
“As the amount of uncommitted capacity and the number of potential sellers shrink over this period, concerns over the potential exercise of market power could arise,” FERC said.
Berkshire Hathaway Energy subsidiaries PacifiCorp and NV Energy on Thursday asked FERC to lift bidding restrictions placed on them in the Western Energy Imbalance Market (EIM) and allow them to offer energy at market-based rates.
PacifiCorp and NV Energy Filed with FERC for Market-Based Rate Authority in the EIM
In a joint filing with FERC, the companies said the bid limits are “no longer appropriate” because they both meet criteria for EIM participation established in previous commission orders (ER17-2392, ER17-2394). Both utilities are currently restricted to using a cost-based default energy bid (DEB) when offering into the market, which they told FERC is “both contrary to organized market design and presents risks of unrecovered costs in some market intervals.”
A November 2015 FERC order found that the Berkshire companies’ request for EIM market-based rate authority had included a “deficient” analysis that failed to disprove their horizontal market power. The order also questioned CAISO’s ability to mitigate such power outside its own balancing area.
In establishing the bid limits, the commission pointed to potential intertie constraints between NVE and CAISO, as well as between the PacifiCorp West and PacifiCorp East balancing authorities. Arizona Public Service is also separately subject to the bid limits.
The commission last year denied the companies’ request for rehearing on that decision, saying that future market power studies must provide analysis of potential power in EIM submarkets stemming from transmission constraints, not just the market as a whole. (See Berkshire Denied Rehearing on Market Power.)
The companies’ latest filing relies on analysis performed by Charles River Associates (CRA) showing that, since the entry of NVE into the EIM, there has been little congestion between balancing authority areas, so they should not be considered “sub-markets,” and that the ability of third-party resources to balance the system mitigates market power concerns. CAISO has also implemented market measures that mitigate prices back to the DEB when competing supplies cannot reach a constrained area, the Berkshire companies said.
According to the filing, the companies “are not asking to charge market-based rates without mitigation. Rather, their bids will be subject to the CAISO tariff-based mitigation instead of the current blanket, seller-specific mitigation.”
PacifiCorp’s Assets Include The 762-MW Dave Johnston Coal-Fired Plant in Wyoming
The Berkshire companies said the CRA findings are backed by an assessment produced by CAISO’s own internal Market Monitor, which in July said transfer capacity in the EIM footprint is now sufficient to justify removing bid limits that are in effect for PacifiCorp, NVE and APS. (See CAISO Monitor Says EIM Bid Limits No Longer Needed.) The Department of Market Monitoring said it would support the companies’ request to FERC for market-based rates.
PacifiCorp was the first utility to participate in the EIM when the market became operational in November 2014. NVE applied to join the EIM in March 2015 and began participation in December 2015.
PacifiCorp operates 71 thermal, hydroelectric, wind-powered generating and geothermal facilities in California, Idaho, Wyoming, Washington, Utah and Oregon. NVE subsidiaries include vertically integrated utilities Nevada Power and Sierra Pacific Power.
Clean Line Energy Partners has filed a rehearing request with the Missouri Public Service Commission, which earlier this month rejected the company’s request for a certificate of convenience and necessity for a portion of its $2.3 billion Grain Belt Express transmission project.
The company said Friday the request is a procedural step necessary to preserve the right to appeal the PSC’s decision to the state courts. It is one of several options Clean Line mulled over following the PSC’s second rejection in three years. (See Clean Line Ponders Options After Grain Belt Rejection.)
| Clean Line Energy Partners
“Clean Line continues to believe that the Grain Belt Express project is too important not to pursue and is therefore exploring many options to move the project forward,” Clean Line spokesperson Sarah Bray told RTO Insider. “The Grain Belt Express would be the largest clean energy infrastructure project in Missouri’s history and would save Missouri ratepayers more than $10 million annually.”
Four of the commission’s five members said in a concurring opinion Aug. 16 that the project is needed, economically feasible and beneficial to the public. However, they referenced a March state appeals court ruling on an unrelated case involving Ameren Transmission Company of Illinois, which found that infrastructure projects must first secure approvals from each county it crosses.
The project developers said the PSC’s decision that it could not “lawfully issue a CCN” until they could prove they had obtained the necessary county assents was in error. In their filing, they asserted the appeals court ruling interprets a statutory provision that was never invoked in and is not relevant to this case, and that “there are particular legal and factual distinctions” between the two cases.
“The commission’s findings of fact and conclusions of law are not supported by substantial and competent evidence on the record as a whole and are grounded in legal error,” the filing contends.
Clean Line was unable to gain permission to construct the line through Caldwell County. However, the project has approvals from all other Missouri counties and from the neighboring states of Kansas and Illinois.
The project would deliver approximately 4,000 MW of wind power from western Kansas through Missouri and Illinois to the Indiana border over 780 miles of HVDC lines. Clean Line expects the Grain Belt Express to enable about $7 billion of new, renewable energy projects to be built.
VALLEY FORGE, Pa. — PJM appears headed toward implementing a capacity construct that would reprice auction results to address the influence of subsidized generation offers.
The RTO’s Capacity Construct/Public Policy Senior Task Force (CCPPSTF) met last week for the sixth time in August to focus on determining what circumstances would trigger auction repricing.
Repricing, which would filter subsidized offers out of auction results to mitigate suppression of the clearing price, is a key mechanism in five of the nine capacity redesign proposals. NRG Energy, LS Power, Exelon, PJM and Old Dominion Electric Cooperative all included it. (See Stakeholders Seek to Trim PJM Capacity Construct Options.)
CCPPSTF attendees have identified 18 components that the repricing trigger should address, including a subsidy’s financial significance in supporting a resource and the scale of a resource’s impact on the market. The discussion has delved into the details of how states could potentially issue subsidies, including through yearly allotments or a one-time lump-sum payment for performance over an expected lifespan.
Sorting the Details
Avangrid’s Kevin Kilgallen suggested that repricing should be triggered only by subsidies provided during an auction’s delivery year. Calpine’s David “Scarp” Scarpignato added that lump-sum subsidies that include the delivery year in their amortization should also be a trigger. The distinction was initially lost on some participants.
“There are two different issues here,” Kilgallen said. “I’m saying only subsidies that may or will be or are expected to be applicable during the delivery year should be considered. … I think [Scarp’s is] a separate issue, whether or not there’s a trigger for a resource that may or may not receive [in that year] a subsidy that it’s eligible for.”
Scarp later suggested that subsidies that incentivize the pricing of carbon emissions should be exempted. EnerNOC’s Katie Guerry questioned the suggestion as ostensibly supporting a controversial tenant of Exelon’s proposal that would effectively exempt nukes that are receiving subsidies from triggering repricing. Scarp clarified that his suggestion was specific to subsidies that would monetize emissions instead of subsidize units that have a related beneficial attribute, such as being emissions-free. His proposal wouldn’t exempt a unit that received a subsidy elsewhere, he said.
Guerry said carbon pricing creates an entirely separate market that’s not involved with the capacity market.
“Carbon pricing is something completely separate, and it’s in and of itself a solution … that would obviate the need to do anything in the capacity market,” she said. “If you have something like carbon pricing, there’s not a question of exempt or not exempt. It’s the solution that we pursued outside of the capacity market.”
Scarp pointed out that subsidies could affect either the capacity or the real-time energy markets, which introduced a new concept for the group as all discussion had previously focused only on subsidies in the capacity market.
“If PJM institutes carbon pricing, you don’t think it will affect your energy [market] revenues? It will,” Scarp said.
State Actions Only
Stakeholders also debated whether a resource that received a subsidy in the past should always be considered subsidized, and whether federal subsidy programs should remain outside the CCPPSTF’s scope.
While the task force’s charter is limited to state programs, Exelon’s Jason Barker asked if PJM’s eventual FERC filing on the issue would also remain limited to state programs. PJM’s Dave Anders, who facilitates the group’s meetings, declined to speculate about the RTO’s plans.
“The problem statement we’ve got is limited strictly to state actions. What happens at FERC, happens at FERC,” he said.
Direct Energy’s Marji Philips argued that federal actions weren’t the issue.
“The difference between a federal action is all states are impacted by it and have to price it in,” she said. “If it’s a state law, it only impacts — or should only impact — the citizens of that state, and that’s what this exercise is. It’s not to tell a state what it can or can’t do. It’s to make sure that other customers from other states don’t pay for what one state wants that another state might not want.”
Exelon’s Sharon Midgley responded that such programs can still impact auction prices. “While a federal program may have the same impact across the entire footprint, it still has the potential to suppress [prices, even if it does so] uniformly,” she said.
Stakeholders are also considering how to write rules that address potential future scenarios in which states decide to offer financial incentives for demand-side resources or certain existing programs expand to other states, such as the Illinois program offering zero-emissions credits to nuclear units.
“I think there are a number of parties who would say, ‘I’m OK with the status quo. My concern is what’s coming down the pike,’” Guerry said. “Preference for the status quo by some might be dictated by what happens or may not happen in the future.”
‘Non-repricing’ Alternatives
While the meeting focused on repricing, stakeholders have also suggested additional redesigns beyond the five repricing proposals. The Independent Market Monitor has proposed extending the existing minimum price offer rule indefinitely to any subsidized unit that doesn’t qualify for several specific exemptions.
Three “non-repricing” proposals would reduce the role of the auction in PJM’s capacity acquisition procedures. John Horstmann at Dayton Power & Light proposed to expand the RTO’s existing fixed resource requirement (FRR) option to allow utilities to meet capacity obligations with any combination of FRR and auction results.
A proposal by the Sustainable FERC Project would reduce the capacity requirement to off-peak season needs and allow seasonal resources to account for the additional demand during the peak season. American Municipal Power (AMP) is still finalizing the details of a proposal that would emphasize the use of long-term bilateral contracts over a single auction.
Polling Controversy
With his company’s proposal unfinished, AMP’s Ed Tatum expressed concern about a planned PJM poll to measure the relative popularity of the proposals. He was particularly displeased with an opening section that asked respondents to opine on how each proposal addressed specific issues.
“Is this something we’re going to do regardless of how people feel about it?” Tatum asked. “It looks like you’ve got 11 good questions. The first one is a bit broad and the categories elusive. … We need to make sure the poll results are meaningful and we’ll get something good and useful out of it.”
“We are trying valiantly to get some additional information out to people to see what people are thinking,” Anders said. “I feel like we’re in full attack mode against this poll before we’ve even seen it.”
Tatum was not alone in his concerns about the poll. Barker noted that the poll doesn’t address repricing triggers, “which is quite possibly the most important part, which is why we’ve registered our concerns.” As part of his instructions to stakeholders at the end of the meeting, Anders later asked those who submitted proposals to attend the next meeting prepared to define the triggers they plan to include in their proposal.
GT Power Group’s Tom Hyzinski requested adding to the first question whether each proposal “insulates other states or other jurisdictions against the actions of a state, because I think there’s only one that actually does that, and that’s the IMM’s proposal. Any of the others, there’s actions that can be taken in one small place that affect the pricing and market signal in every other section of PJM.”
Barker said that Hyzinski was “pretty shrewd” to provide his answer with the question.
“Similarly, we could ask for questions about whether or not the application [of the proposal] is discriminatory, much like the IMM’s proposal, where it proposes to exempt certain resources but not others that may have the same dollar-for-dollar impact,” Barker said.
Anders said that he is anticipating at least one more round of polling and feedback before moving to a recommendation vote. “We’ll just have to see how things mature after [the polling],” he said.
PJM staff planned to distribute the poll to the CCPPSTF task force list last week and differentiate between member and non-member responses. Staff are seeking to receive responses this week in order to prepare results for the next CCPPSTF meeting on Sept. 11.
FERC on Friday voted 2-1 to reject a CAISO proposal intended to prevent small transmission owners from shouldering the costs for network upgrades needed to interconnect generation serving load outside of their service territories.
The proposal was designed specifically to address the circumstances of Nevada-based Valley Electric Association, the California grid operator’s only out-of-state member. The electric cooperative serves 45,000 customers and peak demand of 135 MW within a 6,800-square-mile territory straddling the California-Nevada border.
| Valley Electric Association
FERC’s decision means Valley Electric’s ratepayers potentially face the cost of interconnecting almost 4,000 MW of solar resources that would help support California’s renewable portfolio standard. The cooperative has 25 requests totaling 3,952 MW of new capacity in its interconnection queue.
CAISO conducted a seven-month stakeholder process to develop the proposal to certify Valley Electric as a small participating transmission owner (PTO) and distribute its interconnection costs across the broader ISO. (See Board Approves CAISO Small TO Generator Interconnection Plan.)
The rule changes would have folded low-voltage generator interconnection costs into high-voltage transmission revenue requirements, spreading costs among the ISO’s entire ratepayer base. San Diego Gas & Electric had cited a concern that CAISO’s solution did not meet FERC cost allocation rules and Southern California Edison opposed the proposal.
“In the past, CAISO has justified its cost allocation methodology by explaining, with supporting evidence, that low-voltage facilities generally support local service and that the high-voltage transmission facilities perform a backbone function that supports regional flows of bulk energy,” FERC said (ER17-1432).
The ISO was now asserting “without supporting evidence” that low-voltage upgrades on Valley Electric’s system — but not those on the systems of Pacific Gas and Electric, SCE and SDG&E — benefit customers throughout the region, the commission said.
“CAISO’s proposal is inconsistent with the commission’s cost causation principles because it shifts costs from a single PTO to all load in CAISO without providing evidence that CAISO transmission system users being allocated such costs benefit from the network upgrades to Valley Electric’s low-voltage transmission system,” FERC said.
“Of additional concern is CAISO’s proposal to allow stakeholders to decide whether to grant alternative certified small PTO rate treatment; stakeholders are interested parties that may be impacted by the determination that a PTO should become a certified small PTO.”
Commissioner Cheryl LaFleur dissented in the ruling.
“It is simply unfair to require the 0.27% of CAISO’s customer base in Nevada to bear the costs of these interconnections, which are not remotely commensurate with the benefits they receive,” she said. “Rather, I believe the customers in California, whose policies are driving the costs, should largely bear the burden of these costs. The CAISO proposal achieves that objective in a pragmatic way.”
In June, FERC staff sent CAISO a deficiency letter asking for a better definition of CAISO’s criterion for designating a certified small PTO and how transmission customers will benefit from low-voltage interconnection network upgrades in Valley Electric’s service territory.
CAISO did not immediately respond to a request for comment. In comments previously filed with FERC, the ISO said Valley Electric faced the risk of being allocated all of the costs for network upgrades necessitated by other utilities’ procurement efforts, and that similarly situated small TOs potentially could face the same situation.
The Public Utility Commission of Texas last week gave preliminary approval to Oncor’s and Sharyland Utilities’ proposed swap of $400 million in assets.
The order lists a set of 27 issues to be discussed before the PUC renders a decision, which is due by Feb. 1, 2018 (Docket 47469).
Oncor and Sharyland filed a settlement agreement early last month, asking the PUC to expedite the case by deciding it without referring it to the State Office of Administrative Hearings (SOAH). The companies said Sharyland’s current retail customers will receive “substantial rate relief” under the transaction, in which Sharyland will take over 258 miles of 345-kV transmission from Oncor in exchange for Sharyland’s distribution network and retail delivery customers.
“The hard work that’s gone into this is going to significantly change people’s lives,” said Commissioner Brandy Marty Marquez. “I’m happy this is all proceeding.”
Among those signing on to the settlement agreement are commission staff, the Office of Public Utility Counsel (OPUC), the Steering Committee of Cities Served by Oncor, the Alliance of Oncor Cities, numerous other Texas cities and various electric retailers. The Texas Industrial Energy Consumers (TIEC), the Targa Pipeline Mid-Continent WestTex and Golden Spread Electric Cooperative chose not to oppose the settlement.
An administrative law judge set Tuesday as the deadline to request a hearing in the docket.
The settlement would also resolve Sharyland’s separate applications to deploy an advanced metering system (Docket 44361) and requests for rate relief and a certificate of convenience and necessity (Docket 45414), and Oncor’s application to change its rates (Docket 46957).
“This will ultimately solve a lot of problems for a lot of folks,” said Commissioner Ken Anderson.
Commissioners Undecided on LP&L’s Contested-Rate Case Request
The PUC postponed a decision on how to process Lubbock Power & Light’s request to move 430 MW of its load from SPP into ERCOT. The commission is considering whether to treat the request as a contested case or refer it to SOAH, where it would be heard before an ALJ.
The commissioners will announce their decision during their Sept. 28 meeting, after reviewing a draft preliminary order (Docket 45633).
“I’m fine going to SOAH,” Anderson said. “The other tradeoff, in terms of time, is SOAH may be able to handle getting the facts. It handles much of discovery anyway.”
“If we send it to SOAH, the judge won’t do much of anything until the preliminary order comes out,” Marquez said.
LP&L is hoping for a decision before March 2018, which will enable it to maintain its plan to integrate with ERCOT by June 2021. The municipality announced its intention in 2015 to disconnect its load from SPP and join ERCOT in June 2019. That that date has since slipped, but LP&L extended a power purchase agreement with Southwestern Public Service through May 2021.
The preliminary order will allow the PUC to decide policy questions over load migrations “by putting a framework around what needs to be decided,” Anderson said.
“A ‘Hotel California’ clause in the order might be appropriate,” he said, referring to the Eagles’ lyric, “You can check out any time you like, but you can never leave!”
“Going back and forth between ERCOT and other regions is, at best, disruptive, not to mention expensive,” Anderson said.
ERCOT, SPP Agree to Rayburn Country Migration Studies
Rayburn Country Electric Cooperative representatives told the commissioners they are comfortable with ERCOT’s and SPP’s proposed scope and timeline for their studies of the East Texas co-op’s proposed transfer of much of its SPP transmission facilities and load into ERCOT (Docket 47342).
The grid operators said they would conduct individual studies using a common scope and assumptions, including an analysis of system impacts, expected changes in production costs and avoided projects. ERCOT and SPP also plan to conduct a reliability review of the transfer using power flow and system contingency analysis.
ERCOT and SPP said they expect to complete their studies on the move by February.
“It’s time to get started,” Marquez said.
Rayburn Country is an SPP member, but only about 150 MW (less than 20% of its load) and 160 miles of its transmission sit in the Eastern Interconnection. ERCOT has said it will cost $38 million to connect the SPP load with the Texas grid.
SWEPCO Seeks to Reduce Wind Catcher Costs
The commissioners consented to a list of 36 issues to be contested before an ALJ related to Southwestern Electric Power Co.’s costs associated with parent American Electric Power’s massive Wind Catcher project. (See AEP to Spend $4.5B on Largest Wind Farm in US.)
| AEP
SWEPCO has filed a request with the PUC (Docket 47461) that its costs associated with the Oklahoma wind farm and EHV transmission line — $2 billion and $1.1 billion, respectively — be treated as an eligible fuel expense, and that the federal production tax credit be treated as a credit against it. The utility has estimated $1.1 billion is jurisdictional, and it wants to credit the PTC’s value against its fuel expenses, until the project can be included in base rates.
SWEPCO also wants to defer for ratemaking purposes a portion of the PTC into a regulatory liability that would be credited back to ratepayers 11 years after Wind Catcher’s planned 2020 in-service date. This would avoid a large increase in rates once the PTC expires, the company said.
The PUC referred SWEPCO’s request to SOAH early last month. OPUC, TIEC and Golden Spread have filed motions to intervene and contributed to the list of issues. That list includes accounting and cost allocation questions and whether SWEPCO needs the additional capacity.
AEP plans to build 350 miles of 765-kV lines to connect the 2,000-MW wind farm in the Oklahoma Panhandle to its SWEPCO and Public Service Company of Oklahoma subsidiaries. SWEPCO services northeastern Texas. The wind farm would be the largest in the nation.
IRVING, Texas — The Gulf Coast Power Association’s fourth annual SPP Regional Conference last week drew more than 130 registrations, but most from the Houston area and those involved in Hurricane Harvey restoration efforts were unable to attend, cutting the audience by almost 20%. GCPA Executive Director Tom Foreman said the organization refunded registration fees to those from Houston.
“My heart, prayers and concerns go out to all of our friends, family and colleagues in Houston and South Central Texas,” said Foreman, a Houston native. “They are still in the midst of a truly historic and devastating event. Please know that all of us at GCPA wish you well and hope you remain safe.”
Referring to the SPP region as the “Saudi Arabia” of wind, SPP Board Chair Jim Eckelberger focused his keynote presentation on the RTO’s ample wind and solar resources, and the challenges they present.
He pointed to slides that listed the 17.9 GW of wind capacity currently in service and the 43.8 GW of additional capacity in all stages of development. That includes 36.8 GW in the generation-interconnection queue and 7.1 GW with signed interconnection agreements. SPP’s queue also has 7.7 GW of solar projects.
But that’s not all. Eckelberger said the Great Plains states of Kansas, Nebraska, New Mexico and Oklahoma, along with the Texas Panhandle, may produce up to 90 GW of wind capacity — almost double SPP’s current peak demand of 52 GW.
On April 24, Kansas wind farms generated more energy (3,712 MW) than the state’s load (3,507 MW). Oklahoma came close that same day, producing 5,054 MW of wind energy while the state’s load was 5,682 MW.
“There’s a future that’s really unknown. That unknown future is a dilemma for what this green revolution is,” Eckelberger said. “All this is happening, not because of the Clean Power Plan, and not because of government-subsidized wind and solar. It’s about science moving forward, technology moving forward and the market itself. That’s what pricing does.”
The wind revolution has resulted in more than 20,000 industry-related jobs, more than $23 billion in capital investments and more than $40 million in annual lease payments to landowners within SPP’s footprint, Eckelberger said.
“This is why governors say, ‘Don’t export wind to my state. I want that development to myself and bring those jobs to my state,’” Eckelberger said. “What a national energy policy would do is have us move this immense wind energy from west to the east. It would really make sense to be in that mode, but we don’t have a national energy policy. It’s not going to happen, at least in the foreseeable future.”
Asked why he is so pessimistic about a national energy policy, Eckelberger told RTO Insider some of the blame lies with “parochial [state] governors” protecting their states’ interests.
“I sense from the states they feel the same way,” he said. “There’s not a lot of oomph for a national energy policy. Of course, not much is getting done in Washington anyway.”
Bruce Rew, SPP’s vice president of operations, said wind energy is fast replacing natural gas as the RTO’s No. 2 fuel resource, and surpasses coal at times as the No. 1 fuel source.
“Gas is pretty much a secondary resource,” Rew said. “It’s still important for short-term reliability commitments.”
Khai Le, senior vice president for energy software provider Power Costs Inc., noted that SPP’s Integrated Marketplace has pushed almost 5 GW of less efficient capacity out of the dispatch stack most days, which has resulted in lower production costs. Le said the market’s prices “are rational and consistent with gas costs.”
However, he also said no market has more negative day-ahead and real-time LMPs than SPP. The Integrated Marketplace cleared about 160 negative five-minute intervals in 2016.
“With greater wind output and low gas prices, 70 to 80% of coal units are offered as must-run resources, so 20 to 30% of coal is out of the money,” Le said. “SPP will need more quick-start peakers, but under current SPP protocols, peakers do not receive sufficient reliability unit commitment make-whole payments to cover their full production costs.”
Still, Le said, he has yet to come across a market participant who wants to leave the SPP market. “If you talk to most market participants, they give a fairly high score to SPP,” he said. “Somewhere between an A- to an A.”
Golden Spread Electric Cooperative’s Mike Wise, the company’s senior vice president of regulatory and market strategy, said the region will have to decide what to do with the potential wind energy to come, given SPP’s lack of load growth.
“SPP is the renewable breadbasket of energy for the U.S., but we’re an island,” Wise said. “We’re throwing more and more renewable energy into this island, with very little capability to push this out. Can a market consistently continue with negative pricing long-term? This problem, or opportunity, is going to get deeper and deeper as you go on.
“[Our] congested areas have a large amount of renewable energy in those pockets and significantly high amounts of negative pricing. We need units able to operate and provide services necessary to support a reliable grid. Coal plants are paying to put coal-fired energy in the market. With that in mind, we need flexible units and the ability for market signals to encourage and bring on those units with short, quick-start capability.”
Improvements to SPP-MISO Interregional Process
SPP members offered recommendations to improve the interregional transmission planning process with MISO, which has yet to result in a project between the two organizations. MISO last month told stakeholders it was no longer considering the first transmission project to result from a coordinated study with SPP. (See SPP Glum as MISO Axes Last Interregional Project.)
American Electric Power’s Jim Jacoby said the RTOs should align their study processes and timelines, noting that MISO only allocates costs for 345 kV or higher, while SPP allocates down to the 115-kV level. He also pointed to a 2,500-MW export capability with MISO, “which isn’t much when SPP has a 50-GW system and MISO a 150-GW system.”
“AEP thinks that’s a problem. It thinks lower-level kV projects can be valuable,” Jacoby said. “[Aligning the study requirements] might help incent some of these projects get built.”
“We classify projects as purely reliability or purely economic or public policy, but it’s very unusual to see a project selected for reliability that doesn’t have economic benefits as well,” said ITC Holdings’ Alan Myers. “We need to be less limiting in our thinking.
“Bottom line, our traditional planning has focused on reliability and incremental fixes to the detriment of the overall system,” he said, emphasizing that ITC is not advocating less focus on reliability. “We’re in the midst of a green revolution and a rapidly evolving shift in load. All of this calls for, and demands, a new approach to the planning system, and bigger picture things across the seams.”
Jesse Moser, MISO’s director of transmission planning, promised his audience changes are coming. He said the two RTOs are working to resolve the differences in cost allocation and expect a FERC filing next year with an effective date for the 2019 planning cycle.
“We did get a push from FERC as a result of a complaint on the MISO-PJM seam,” said Moser, referring to the commission’s 2016 order on a complaint by Northern Indiana Public Service Co. (See FERC Signals Bulk of NIPSCO Order Work Complete.)
“If we don’t make those changes, we’ll probably get a complaint on the other side. We’re trying to get in front of that and be the masters of our own destiny.”
“If there’s an interregional solution to a regional problem, that’s what we think is very important,” said Missouri Public Service Commissioner Steve Stoll, who chairs SPP’s Regional State Committee. “So far, we haven’t come up with any [interregional solutions], but that doesn’t mean there won’t be any in the future.”
Political Uncertainty Cast Cloud over Market
Wise set the stage for a discussion of Lubbock Power & Light’s intended migration of 430 MW of load from SPP to ERCOT by asking what compels a load to switch grid operators.
“They’ve been served reliably [by SPP] for many, many years,” he said. “It’s not really a reliability issue. It’s purely economics. What are those compelling reasons loads would seek to move?”
Wise answered the question himself, saying that unlike SPP, ERCOT does not have capacity or firm transmission requirements. Transmission costs also are allocated differently in the SPP system. The Texas grid regionally allocates costs of service equally under “less intrusive” requirements than SPP in its base plan funding and highway/byway processes, he said.
“Those are the facts, and they’re undisputed,” Wise said, paraphrasing a line from the movie “A Few Good Men.” “Now we’ll have to spend time with what those facts mean. [The Public Utility Commission of Texas] will be dealing with those facts extensively over the next few months.” (See “Commissioners Undecided on LP&L’s Contested-Rate Case Request,” Public Utility Commission of Texas Briefs: Aug. 31, 2017.)
Asked by Wise why ERCOT didn’t simply build a DC tie as a cheaper option to connect Lubbock’s load, Jeff Billo, the ISO’s senior manager of transmission planning, said the alternative was never studied. ERCOT and SPP have determined in separate joint studies that LP&L’s proposed transition would cost the two nearly $370 million. (See Load Migrations Put SPP’s Focus on Retention.)
“Their request seemed to be, ‘We want to be in the ERCOT market and ERCOT regulatory construct,’” Billo said.
The studies considered the differences between the two grids’ market and regulatory structures.
“At the end of the day, the study results would not be apples to oranges, but apples to apples,” Billo said. “More like Jonathan apples to Gala apples.”
Texas regulators last week praised the response of the state’s utilities, ERCOT and first responders during discussion of a preliminary report on restoration efforts in the wake of Hurricane Harvey.
Speaking during an Aug. 31 open meeting of the Public Utility Commission of Texas, Commissioner Ken Anderson noted the “remarkable” restoration effort in flood-stricken Houston, especially when compared to Hurricane Ike’s aftermath in 2008.
Brandy Marty Marquez, the PUC’s other commissioner, described a road trip she took a day earlier to the deep-sea fishing community of Port Aransas. Port A, as South Texans refer to the beach town, was devastated by Harvey’s 130-mph winds.
“I saw linemen with all different uniforms [on the way]. It was very inspiring,” Marquez said. “We have a long way to go, but you can’t mess with Texas. We’ll be fine. This is a big test for us, but everyone’s risen to the occasion.”
ERCOT’s Brian Lloyd
PUC Executive Director Brian Lloyd became visibly emotional as he talked about the 10,000 utility workers from around the country who have descended to help Texas with the restoration.
Taking a few seconds to regain his composure, Lloyd told the commissioners, “It’s great to see that work.”
NRG’s Bill Barnes
“As an industry, we should be very proud of what has happened in the response,” said NRG Energy Director of Regulatory Affairs Bill Barnes. “We have a lot of friends to thank across this industry.”
American Electric Power, CenterPoint Energy, Entergy Texas and Texas-New Mexico Power reported just more than 200,000 combined customer outages Aug. 31, down from about 278,000 the day before. That number had dropped to almost 78,000 by Sunday afternoon.
“Other than the areas with extensive damage and flooding, a good chunk of this will be back online this weekend,” Lloyd said.
‘This is Personal’
ERCOT filed a status report with the commission Aug. 30 indicating that two of the six 345-kV lines that Harvey knocked out of service have yet to be restored. Another 55 high-voltage transmission lines in the storm-affected areas were still out of service as of Friday morning, the ISO said.
Most of those outages are in the Coastal Bend area between Corpus Christi and Houston, which took the full brunt of high winds when Harvey made landfall as a Category 4 storm. AEP Texas said Thursday that more than 4,600 workers have spent 14- to 16-hour days restoring power.
The bulk of those without power — about 40,000 — are in the Rockport-Victoria-Aransas Pass area. AEP Texas estimates it will take until Sept. 8 to complete its restoration work in the region.
Barnes offered a note of caution to the PUC: Just because it’s stopped raining doesn’t mean Harvey’s damage is over.
“What we’re dealing with is something that is very devastating and will have a lasting impact,” he said. “This is going to take a significant amount of time to recover from. A lot of people have had their lives changed forever as a result of this. That includes our employees, our families, our friends.
“The Corpus Christi-Victoria area is our backyard; Houston is our home. So this is personal.”
Barnes told the commissioners that NRG and its retail electric providers would halt disconnect notices through Sept. 30 for its customers in affected areas, and provide “direct financial relief” in the form of payment extensions, late fee and deposit alternatives or waivers, and increased funding of bill payment assistance programs.
The companies will also provide more than $2 million in disaster relief resources, including donating money to relief agencies and deploying a mobile generation station and disaster relief command center for affected communities, according to a filing with the PUC.
TXU Energy said it would also be waiving late fees through Sept. 30, along with extending payment due dates with no down payment required, and reducing down payments and deferring balances over five equal installments.
Anderson commended the retailers for their actions, saying, “It’s a good example for the rest of the retail industry.”
Generation, Demand Down
ERCOT also reported Friday that 7,500 MW of generation remains unavailable or operating at reduced capacity. The loss does not represent a reliability concern, and the ISO expects to have sufficient generation for the “foreseeable future.”
System demand has been down significantly since shortly before the storm made landfall Aug. 25, ranging between 41 and 48 GW, approximately 15 to 20 GW lower than normal. Demand has started to increase as service is restored and temperatures begin to rise, with projected peaks over the weekend of 56 GW. (ERCOT had predicted a peak of 73 GW this summer.)
The South Texas Project nuclear plant in Bay City, 90 miles southwest of Houston, remained online during the storm. Like other plants in the area, operators at the 2,760-MW double-unit facility were “literally locked in [the] plant for days,” Marquez said.
Barnes agreed. “Road access was flooded,” he said, referring to the situation at other NRG plants. The company is one of STP’s co-owners.
CAISO is moving forward with a proceeding that could result in changes to how it allocates transmission costs to participants in its wholesale markets, meant to better reflect increased adoption of distributed generation and other factors.
The grid operator is considering a proposal to replace its current method, which utilizes end-use metered load to bill a volumetric transmission access charge (TAC). That method does not reflect the role of DG in reducing transmission costs.
CAISO is analyzing whether to reduce TAC charges in transmission owner service areas for load that is offset by DG output, and how best to do so. It also is considering a demand-based charge instead of — or in addition to — its volumetric charge, or one based on time-of-use pricing.
The ISO on Tuesday held a stakeholder working group on the proposed TAC changes outlined in a June 30 issue paper. Neil Millar, CAISO executive director of infrastructure development, said during the meeting that because transmission charges are applied both to energy provided from central stations and DG, the cost of delivering energy is ignored, creating an inefficient market.
“It distorts cost allocation, distorts energy markets [and] costs money,” Millar said. Transmission costs are also rising, making dealing with the issue a “political necessity.”
Graph of Declining Load Factor of California Investor-Owned Utilities | Energy Policy Initiatives Center; California Energy Commission
CAISO also considered changing another settlement process that uses a volumetric rate for wheeling power to loads off the ISO-controlled grid, but it put it on hold after talking with stakeholders and deciding the initiative had “a number of complex and controversial issues.”
Moving the point where transmission usage is measured would solve a lot of the issues, according to Millar. To address the issue, the ISO is considering a Clean Coalition proposal that would rely on gauging hourly net load at each transmission-distribution interface substation, referred to as “transmission energy downflow.”
In an effort to place some boundaries on the proposal, CAISO plans to remove some other topics that are broad in scope regarding the TAC. Among those initiatives were an assessment of current regional and local transmission charges that are recovered through a postage-stamp rate and an analysis of the ISO’s role in collecting the TAC. Other topics to be postponed are alternative types of transmission service. CAISO said it would study other regions and some other proposals put forth by stakeholders.
CAISO plans to issue a straw proposal on the TAC changes by Oct. 31, followed by a Nov. 15 stakeholder call. A final proposal will be submitted to the ISO Board of Governors sometime in 2018.
The grid operator earlier developed a proposal to allocate transmission costs over an expanded balancing area if the ISO integrates new members such as PacifiCorp. (See CAISO Floats Latest Cost Allocation Plan for Expanded Balancing Area.) That proposal has been shelved until CAISO expands into other regions of the West.
