ERCOT set a new record for wind generation last week, just two days after breaking its mark for penetration.
Wind turbine locations in Texas | Matt Crawford, Texas A&M Natural Resources Institute
Wind generators in ERCOT territory — about 90% of Texas — produced 19.7 GW at 7:19 p.m. on Jan. 21, breaking the old mark of 19.2 GW set on Dec. 14, according to market reports. Wind energy accounted for 46.89% of ERCOT’s production at the time.
The grid operator also set a new record for wind penetration at 56.16% on Jan. 19. The new mark came at 3:10 a.m., when wind produced 17.4 GW of energy.
The previous high for wind penetration was 54.64%, set Dec. 27.
A Northern California Native American tribe scored a key victory Friday after a federal appeals court ruled that FERC must act on a long-delayed licensing review for a series of aging hydroelectric dams that straddle the California-Oregon border (14-1271).
The D.C. Circuit Court of Appeals ruling in favor of the Hoopa Valley Tribe could force PacifiCorp to proceed with plans to decommission four of the seven dams that make up its 169-MW Klamath Hydroelectric Project before the utility is in a position to transfer the assets to a new owner.
In 2012, the Hoopa petitioned for a declaratory order asking FERC to find that PacifiCorp had “failed to diligently pursue relicensing” of the Klamath project. The tribe asked the commission to dismiss the utility’s relicense application and direct it to file a plan for decommissioning.
FERC rejected that petition in June 2014 and denied a request for rehearing a month later (P-2082-058).
The D.C. Circuit’s Jan. 25 ruling vacated both 2014 orders and remanded the issue back to the commission.
“FERC shall proceed with its review of, and licensing determination for, the Klamath Hydroelectric Project,” the court ordered.
J.C. Boyle Dam and fish ladder, one of four Klamath dams slated for removal in 2020 | U.S. Fish and Wildlife Service
In Limbo
The four dams at issue in the dispute are slated for removal in 2020, pending FERC approval. But a complex set of developments over the last decade has prompted the commission to postpone any action on relicensing the facility until a consortium of interested parties in the region can hash out more details about the decommissioning.
PacifiCorp decided to remove the four dams 15 years ago following a long-running dispute over water rights and the health of salmon runs in the Klamath Basin.
Two years before the project’s license was set to expire in 2006, the utility filed a proposal with FERC to relicense the three upper dams while decommissioning four lower dams deemed too costly to modernize. Since then, the project has been operating under a series of annual interim licenses while approval of the broader license sits in limbo, largely because of PacifiCorp’s own efforts.
The cause for that delay is embedded in the 2010 Klamath Hydroelectric Settlement Agreement (KHSA) reached by the consortium, which includes California, Oregon, area tribes, farmers, ranchers, fisherman, environmental groups and PacifiCorp.
The KHSA imposed a set of interim environmental measures and funding obligations on PacifiCorp ahead of the targeted 2020 decommissioning date. It also contained a provision that California, Oregon and PacifiCorp would agree to sidestep the one-year statutory limit for states to issue water quality certifications under Section 401 of the federal Clean Water Act (CWA) — a prerequisite for FERC’s licensing review — until decommissioning details were worked out.
To circumvent the CWA’s requirement that a state waive its certification authority if it fails to respond within a year (allowing FERC to proceed with relicensing without certification), PacifiCorp has annually withdrawn and resubmitted its certification requests. That measure was intended to provide cover for California and Oregon over its response time requirements while also buying the company time to secure federal funding to remove the dams before having to obtain new licenses from them.
After the funding effort fell through, a subset of the KHSA parties in 2016 signed an amended agreement that would transfer the licenses for the four dams to a newly formed Klamath River Renewal Corp. (KRRC). FERC last March approved PacifiCorp’s request to split the lower dams into a separate license, but it declined to rule on transferring the license until the KRRC could prove that it was capable of managing decommissioning (P-2082-062).
“Transferring a project to a newly formed entity for the sole purpose of decommissioning and dam removal raises unique public interest concerns, specifically whether the transferee will have the legal, technical and financial capacity to safely remove project facilities and adequately restore project lands,” FERC said in the ruling.
Single Issue
The Hoopa tribe, which lives downstream from the dams, was never a party to the KHSA. Instead, it petitioned FERC for the declaratory order in 2012 in an effort to jump-start the process of restoring the salmon that have traditionally fed its people. After the FERC’s rejections of its petition and rehearing request, the tribe asked for a review by the D.C. Circuit.
The court said its Jan. 25 ruling pivoted on a single issue: “whether a state waives its Section 401 authority when, pursuant to an agreement between the state and applicant, an applicant repeatedly withdraws and resubmits its request for water quality certification over a period of time greater than one year.”
The judges authoring the decision found the language of Section 401 clearly demonstrates that states must make their water quality determinations within “reasonable time” not to exceed one year.
“The pendency of the requests for state certification in this case has far exceeded the one-year maximum,” the court said. “PacifiCorp first filed its requests with the California Water Resources Control Board and the Oregon Department of Environmental Quality in 2006. Now, more than a decade later, the states still have not rendered certification decisions.”
The court said PacifiCorp entered into an agreement with the reviewing states to delay certification and never intended to submit a “new request” each year.
“Indeed, as agreed, before each calendar year had passed, PacifiCorp sent a letter indicating withdrawal of its water quality certification request and resubmission of the very same … in the same one-page letter … for more than a decade,” the court said. “Such an arrangement does not exploit a statutory loophole; it serves to circumvent a congressionally granted authority over the licensing, conditioning and developing of a hydropower project.”
The court pointed out that while the CWA does not define “failure to act” or “refusal to act,” the states’ actions as directed by the KHSA “constitute such failure and refusal within the plain meaning of these phrases.”
“Thus, if allowed, the withdrawal-and-resubmission scheme could be used to indefinitely delay federal licensing proceedings and undermine FERC’s jurisdiction to regulate such matters,” the court found.
Seat at the Table
The court also rebuffed FERC’s contention that finding the states had waived their review rights would set off a cycle of “futility,” requiring the commission to deny PacifiCorp’s license, which would force the utility to file a decommissioning plan subject to its own set of “oft-delayed” state certifications.
“However, such practical concerns do not trump express statutory directives. … Had FERC properly interpreted Section 401 and found waiver when it first manifested more than a decade ago, decommissioning of the project might very well be underway,” the court said.
The judges also pointed to FERC’s “critical role” in protecting the public interest with respect to hydropower projects, including soliciting input from affected parties and performing in an “advisory role” in settlement discussions for the development or decommissioning of hydro projects.
“Here, it did neither,” the court found. “Hoopa’s interests are not protected directly as it is not a party to the KHSA or amended KHSA, nor are its interests protected indirectly through any participation by FERC in those same settlement agreements. Therefore, we disagree that a finding of waiver is futile because, at a minimum, it provides Hoopa and FERC an opportunity to rejoin the bargaining table.”
PacifiCorp spokesman Bob Gravely told RTO Insider that the company is still reviewing the D.C. Circuit ruling to “fully understand its implications.”
“In the meantime, we’re continuing to operate under the settlement agreement that is in place,” he said.
NextEra Energy’s quarterly and year-end earnings surpassed 2017 but came up short of analysts’ quarterly expectations, the company revealed Friday.
The Florida-based company reported fourth-quarter GAAP earnings of $422 million ($0.88/share), compared to $2.16 billion ($4.55/share) the year prior. Adjusted earnings came in at $718 million ($1.49/share) for the period, a nickel short of analysts’ projections of $1.54/share, according to Thomson Reuters.
For the year, NextEra’s 2018 earnings were $6.64 billion ($13.88/share), compared to $5.38 billion ($11.39/share) in 2017.
Clean energy is key to NextEra’s growth, according to the company. | NextEra
Investors reacted to the results by driving the company’s stock price down by almost 3.5% from Thursday’s close of $180.41. Shares closed at $174.17, and gained only 3 cents in after-hours trading.
CEO Jim Robo called 2018 a “terrific year” for the company. Ticking off a list of achievements during a call with financial analysts, he said the company was able to reach its 2018 adjusted earnings-per-share target of $7.70, about a 15% increase over 2017’s results.
Robo said he would be disappointed if NextEra is unable to deliver financial results at or near the top end of its 6 to 8% adjusted EPS compound annual growth rate range through 2021.
Wholesale electricity supplier NextEra Energy Resources (NEER) nearly doubled the amount of megawatts it originated the year before, adding 6.5 GW of renewable projects to its backlog, including energy storage and repowering. The NextEra subsidiary commissioned nearly 2.7 GW of wind and solar projects in the U.S. last year and expects to have as much at 16.5 GW in operation through 2020.
More than 40% of those solar projects included a battery storage component, which Robo said is the beginning of the next play in renewable development — pairing low-cost wind and solar energy with low-cost storage solutions. The company expects wind to be a 2- to 2.5-cent/kWh product, and solar to be 2.5 to 3 cents/kWh, within the next three to four years.
“We continue to believe that this will be massively disruptive to the nation’s generation fleet and create significant opportunities for renewable growth well into the next decade,” Robo said.
Before the call began, NextEra announced the retirement of Armando Pimentel as CEO of NEER, among several other organizational changes.
NextEra CFO John Ketchum will replace Pimentel. Rebecca Kujawa, vice president of business management for NEER, has been promoted to replace Ketchum.
RENSSELAER, N.Y. — NYISO stakeholders last week discussed how pricing carbon in the wholesale market will impact the ISO’s Tariff, while additional materials posted by the ISO provided insight into how it will handle residual allocations stemming from carbon charges.
“Tariff revisions will be necessary to effectuate carbon pricing in the ISO’s markets,” Ethan D. Avallone, NYISO senior energy market design specialist, told the Market Issues Working Group (MIWG) on Jan. 22.
Avallone provided an overview of the Tariff sections impacted by a carbon charge and that will be reviewed over the coming months, mainly related to the social cost of carbon (SCC), emissions data reporting, emission rates in reference levels, credit requirements and the carbon component of locational-based marginal prices (LBMPc).
Stakeholders will begin discussions on revisions to credit rules, if necessary, this fall, Avallone said. To avoid delays, any related Tariff changes will be separate from the second-quarter vote on implementing the carbon charge.
The above chart shows the results of allocating the carbon residual to load using consumer impact analysis data, after considering the impact to the LBMP from dynamic effects brought about by carbon pricing. | NYISO
Several stakeholders said that if there’s a chance that a carbon charge will have a material impact on suppliers’ credit requirements, they have a right to know ahead of time what that impact will be.
“Our approach here is to assess the credit impact once we know the market design,” Avallone said.
Sheri Prevratil, NYISO manager of corporate credit, said that while carbon pricing “will affect the LBMP, we don’t see any changes in the credit methodology as it relates to energy credit requirements. … Where we see a possible change is in the projected true-up exposure credit requirement. Based on what we understand the market design to be right now, those are the only changes we currently foresee.”
New York’s Implementing Public Policy Task Force (IPPTF) last month turned its carbon pricing proposal over to the ISO’s stakeholder process through the MIWG, which began its work earlier this month. (See Imports/Exports Top Talk at NYISO Carbon Pricing Kick-off.)
The MIWG has scheduled meetings to review the carbon pricing Tariff revisions for Jan. 31, Feb. 15 and March 18.
Allocating Residuals
NYISO is recommending that the carbon charge residual resulting from levying suppliers for their emissions be allocated proportionally to consumers across all zones to ensure an equitable impact, consistent with the current allocation of renewable energy credit costs, Avallone noted in slides not presented to the MIWG because of time constraints.
The carbon residual is the total dollar amount of carbon charges collected by the ISO from suppliers and allocated to load.
At an Oct. 29 meeting of the IPPTF, the ISO revised its proposal on carbon residual allocation after a Brattle Group analysis showed that the proportional allocation methodology minimizes cost shifts among consumers. (See NY Task Force Talks LBMPc, Residuals, Hedge Effects.)
The above example assumes a positive carbon residual. | NYISO
According to Avallone’s presentation, load-serving entities would pay the full LBMPc to suppliers, who would then pay NYISO the carbon component. The ISO would then allocate the carbon residual to each zone based on its LBMPc.
The allocation would use the LBMPc from the binding real-time interval (nominally five minutes) to calculate the time-weighted integrated (TWI) LBMPc, according to the presentation.
Supplier emissions would be reported on an hourly basis, so the carbon residual would therefore be on an hourly basis, and the ISO would use TWI LBMPc, the hourly carbon residual and real-time actual internal load to determine the allocation.
NYISO is considering how to calculate the carbon residual allocation under two scenarios thought to be unlikely, according to the presentation: if the LBMPc for a given zone is less than zero, and if the carbon residual is less than zero.
The ISO expects the LBMP to increase slightly under carbon pricing to reflect the emissions of the marginal unit, and carbon-free opportunity cost resource bids are likely to increase as a result of carbon pricing in some hours.
Opportunity cost resources represent those carbon-free resources able to store energy and structure their bids to achieve delivery schedules during the most economic periods of the day. In periods of the day with lower prices, the bids of such resources therefore reflect the estimated opportunity cost of profit from periods of the day with higher prices. (See NYISO Plan Revises Treatment of Carbon-Free Resources.)
The MIWG will discuss calculating the LBMPc and identifying the marginal units on Feb. 15, and on March 4 will cover carbon bid adjustment for opportunity cost resources.
The Western Energy Imbalance Market Governing Body heard from stakeholders Thursday about proposals to increase the market’s say over its existing interstate real-time market and an expanded day-ahead market (EDAM), if it’s eventually established.
The Energy Imbalance Market currently has seven participants in addition to CAISO. | CAISO
The discussion was part of a governance review, required by the EIM’s charter, that began in December with a straw proposal and issue paper drafted by CAISO staff. The main issues are the delegation of authority between the EIM and CAISO and the process and criteria for selecting body members.
“The ISO and the EIM Governing Body are hoping for robust stakeholder comments on all these issues,” the straw proposal says.
On Thursday, EIM Governing Body members got an earful of comments from a half-dozen stakeholders at CAISO headquarters in Folsom, Calif.
Laura Trolese, a senior policy analyst with the Pacific Northwest’s Public Generating Pool, recommended that the EIM Regional Issues Forum be given a more formal role, including being able to discuss and advise the Governing Body on CAISO stakeholder initiatives, which it currently isn’t allowed to do.
Laura Trolese | Public Generating Pool
Lea Fisher, representing Seattle City Light, called for public power providers to play more of a role in EIM governance, saying they are currently underrepresented.
And Jennifer Gardner, an attorney with Western Resource Advocates, said public interest lawyers and consumer advocates should also have more of a presence in the EIM.
Idaho Public Utilities Commissioner Kristine Raper briefed the Governing Body on the activities of the EIM’s Body of State Regulators (BOSR). She said the BOSR recommends a governance revamp that “simplifies and shares [authority] more equitably” between the EIM and CAISO.
Altogether, the EIM had received more than 20 sets of comments from stakeholders on the governance review by a Jan. 11 deadline. Thursday’s briefing was meant to give Governing Body members an overview of those comments and take comments over the phone and in person.
CAISO’s Tariff delegates certain responsibilities to the EIM, including parceling out its decision-making and advisory duties. The EIM’s Governing Body now has primary authority over market rules that are EIM-specific, meaning they apply uniquely to the EIM balancing area or apply differently within that area than in the ISO’s California territory. The EIM can play an advisory role on a broader range of issues. (See EIM Leaders OK Governance ‘Guidance’ Proposal.)
The straw proposal would expand the EIM’s decisional authority to Tariff amendments where it is the “primary driver,” even if it is not solely affected by the changes under consideration. That piece could be approved separately as soon as this spring, CAISO staff told the Governing Body.
Jennifer Gardner | Western Resource Advocates
Commenters were divided over whether EIM governance changes should be adopted incrementally or all at once, and how the proposed EDAM should be factored into that decision.
“‘The improvements that you’re asking for are all absolutely valid,” Governing Body member Kristine Schmidt told the speakers.
Another member, John Prescott, said his takeaway from the comments was that staff should move forward quickly with the recommendation to expand the EIM’s decisional authority.
Prescott’s colleague, Travis Kavulla, said that before any changes are made, he’d like to see a clearer delineation of authority between the EIM and ISO than the subjective process the straw proposal recommends.
“It shouldn’t be like a priest asking in the confessional, ‘What is in your heart?’” when deciding if a sin is venial or mortal, Kavulla said. “It serves everyone better when the lines of authority are drawn more clearly.”
WILMINGTON, Del. — PJM members were unable to reach consensus on any of five proposals to improve price formation for energy and reserves Thursday, leaving the Board of Managers to decide itself on what will be included in its planned FERC filing.
A proposal by Calpine, which received a 73% support Wednesday in a vote by the Energy Price Formation Senior Task Force vote, garnered less than 42% support in a sector-weighted vote of the Markets and Reliability Committee on Thursday. Calpine’s proposal was a modification of PJM staff’s proposal, which won little more than 30% support Thursday.
The top-ranked vote was for a proposal by the Independent Market Monitor, which won 52% support — still well below the 66.7% threshold needed for approval.
Also failing was a compromise package by the D.C. Office of the People’s Counsel (less than 12%) and a proposal by Vistra Energy that largely borrowed from PJM’s proposal (44%).
The votes followed about three and a half hours of debate and parliamentary maneuvering by members and was observed by O.H. Dean Oskvig and Terry Blackwell, two members of PJM’s board, which had set a Jan. 31 date for stakeholder action.
PJM CEO Andy Ott said after the MRC meeting that the board will decide on its path forward at its Feb. 12 meeting, based on input from Thursday’s debate and a Feb. 11 Liaison Committee meeting.
Although none of the proposals won consensus at the MRC meeting, Calpine’s David “Scarp” Scarpignato still held out hope that an agreement could be reached before the board meeting. In a meeting later Thursday, the Members Committee agreed to hold a special conference call no later than Feb. 8 if additional discussions yield a potential compromise.
PJM Board’s To-Do List
Before the votes, Adam Keech, executive director of market operations, outlined PJM’s proposal, which sought to address six issues identified by the board:
Consolidating Tier 1 and Tier 2 synchronized reserve products;
Improving use of existing capability for locational reserve needs;
Aligning market-based reserve products in day-ahead and real-time energy markets;
Setting operating reserve demand curves (ORDCs) for all reserve products;
Increasing penalty factors to ORDCs to ensure utilization of all supply prior to a reserve shortage; and
A transitional mechanism to the capacity market’s energy and ancillary services (E&AS) revenue offset to reflect expected changes in revenues in the determination of the net cost of new entry (CONE).
PJM’s proposal replaces the current stepped ORDC with a sloped curve; the first horizontal segment would represent the minimum reserve requirement, with the downward sloping curve based on the probability of reserves falling below the minimum reserve requirement (PBMRR) in real time based on uncertainties. The PJM proposal would increase the price for the initial horizontal segment of the curve to $2,000/MWh, up from the current $850.
Calpine’s proposal was identical to PJM’s except that it excluded the transitional E&AS offset.
The Calpine and PJM proposals won no votes from the End-Use Customer segment and only 3% of Electric Distributors. Ninety percent of Generation Owners supported the Calpine plan.
Monitor’s Alternative Plan
In contrast, End-Use Customers and Electric Distributors unanimously supported the Monitor’s proposal, which won only 11% of Generation Owners’ votes.
The Monitor’s proposal would replace the current two-step penalty factor ($850 and $300) with a single penalty factor equaling the safety net energy offer cap of $1,000/MWh. If PJM approves a cost-based offer above that price, the penalty factor could increase in $250/MWh increments to a maximum of $2,000/MWh. It also combines the Tier 1 and Tier 2 synchronized reserve products.
Monitor Joe Bowring contends the IMM’s proposal addresses PJM’s concern over operators’ real-time actions suppressing prices better than the RTO’s proposal.
He also says his plan would protect consumers from overpaying during the three-year transition period through a true-up mechanism for already-cleared capacity auctions and modify the capacity demand curve to ensure the efficiency of the energy offset.
It does not include an ORDC for 30-minute reserves unless operators define a need for them. Unlike the PJM proposal, it does not limit the provision of reserves by demand-side resources.
Bowring also has been critical of PJM’s proposal for a new five-minute uplift payment for buying back day-ahead reserve positions, saying it will inflate uplift payments. Moreover, he said, PJM is unable to accurately determine when units are following dispatch, raising questions about uplift calculations.
Load interests expressed most support for the Monitor’s proposal. But Erik Heinle of the D.C. OPC also offered a proposal that he said was a compromise including elements from both the PJM and IMM plans.
After the initial four proposals failed in their MRC votes, members also considered a proposal by Vistra Energy based on the PJM plan. It was similar to the Calpine proposal in not adjusting the E&AS offset. It also differed from the RTO’s proposal in limiting the top penalty factor to $1,000/MWh for all products except during hot or cold weather alerts, when the cap would be $2,000/MWh. It would have used a phased approach, with the penalty factor remaining at $850/MWh for the first two years following FERC approval, reflecting PJM’s three-year forward capacity auctions.
In a Dec. 5 letter to members, PJM’s board said action was needed to minimize out-of-market payments resulting in uplift and ensure that energy and reserve prices accurately reflect RTO operator reliability actions during stressed conditions.
The board said the current reserve market rules “do not accurately align the procurement of reserves with their reliability value or incentivize consistent response when deployed. The lack of alignment in the reserve markets mutes price transparency, shifts costs unfairly to consumers who have prudently hedged, and limits competition to secure reserves at the least cost to consumers.”
But load interests are not convinced. In a letter to the board on Wednesday, the Organization of PJM States Inc. (OPSI) asked PJM to delay action until stakeholders have time to evaluate additional data.
“PJM has detailed its concerns with current energy and operating reserve pricing mechanisms but has not justified the urgency of resolving these concerns, established the operational and cost effectiveness of its solutions, or adequately evaluated the risks and rewards of its proposed reforms,” wrote OPSI President Michael Richard, of the Maryland Public Service Commission. “It seeks to institute new market structures under an unnecessarily rushed timeline, allowing little opportunity for its staff to generate the analyses necessary for stakeholders to fully understand the potential impacts these proposals will have on market sellers and consumers, gauge the reasonableness of the proposals or develop alternatives.”
Procedural Skirmishes
Under PJM’s “truncated voting” rules in the MRC, only the top-ranked proposal from the EPFSTF — Calpine’s — was guaranteed a vote. If it had received a two-thirds vote, the other three proposals would not have been considered.
As a result, several members called for suspending the rules to allow votes on all four plans, saying it would provide more information to the board. Bruce Campbell of CPower said it was important that every proposal receive a vote at the MRC, noting that the task force votes weren’t sector weighted.
John Horstmann of Dayton Power & Light protested, saying it was “unfortunate” to allow circumventing the voting rules in Manual 34, which he said resulted from an “incredibly complicated series of compromises.”
Bob O’Connell, representing Panda Power Funds, unsuccessfully challenged a procedural ruling by Chair Suzanne Daugherty, contending that only the MC could suspend the rules.
Members supported Daugherty’s interpretation, but in a second vote rejected suspending the rules. As it turned out, the point was moot: Because none of the four proposals won a supermajority, each of them was voted on in turn.
Before the votes, Heinle made an unsuccessful motion to defer votes on any of the proposals and hold a special MRC meeting before Feb. 12.
Exelon’s Jason Barker opposed the delay, saying “we’ve been at this for more than a year” and that further discussions were unlikely to change any minds. “PJM has put forward a just and reasonable proposal,” he said. “The time is now to move forward.”
Data Sought
Several members reiterated their call for more simulation data on the potential impact of the rules, saying PJM had failed to provide enough modeling to ensure the new rules would not result in excessive costs.
OPSI Executive Director Gregory Carmean asked whether PJM would produce simulations on the impact of “cascading” penalty factors for multiple reserve products.
Susan Bruce, attorney for the PJM Industrial Customer Coalition, asked whether the RTO planned to simulate the impact of the new rules on the 2014 polar vortex.
Keech’s answer to both was “no.”
He said PJM could not replicate the polar vortex because it occurred before the current Capacity Performance rules. For example, he said, although the RTO had about 9,000 MW of demand response then, only about 3,000 MW of DR “showed up,” because, unlike under CP, it wasn’t required to deploy.
Any simulation would show higher energy prices than were experienced in 2014, Keech acknowledged.
Direct Energy, one of the largest retail suppliers in PJM, had opposed the RTO’s initiative but has since been convinced of the need to move revenues into the energy market, the company’s Marji Philips said.
Although Direct is concerned about PJM’s proposed handling of DR, and it would like the RTO to share Tariff language with members before filing, Philips said it was “disingenuous” for stakeholders to request more data, calling it a delay tactic. “I’m hard on PJM, but they have been more than forthcoming with data,” she said.
“Just say you disagree” with PJM’s plan, she said. “It’s going to increase prices, no question.”
$1.92 Billion
PJM’s last simulation, included in a paper published earlier this month, projected a net increase in energy and reserve market revenues of $1.92 billion annually, resulting from increasing annual energy revenues by $1.8 billion (increasing average LMPs by $2.27/MWh) and reserves by $190 million, while trimming $70 million in uplift (up to 42%).
The RTO expects the additional costs will be at least partially offset by reduced capacity costs. In addition to a $280 million reduction in the net CONE value that is the basis for the variable resource requirement (VRR) curve, PJM said the increases in energy and reserve revenues should reduce capacity market offers. But it acknowledged the savings “will be dependent on bidding behavior.”
Including projected reductions in retail providers’ risk premiums, PJM said the most optimistic case — which assumes capacity resources reduce their offers by $30/MW-day — would result in annual cost savings to consumers of $350 million.
“A potentially more realistic outcome is that these changes will increase costs to loads in the range of $700 million,” the RTO said. “PJM believes these changes are justified because much of the reserve capability PJM has today is either undercompensated or not compensated at all.”
Campbell said CPower, which aggregates DR resources, would not support any of the proposals and urged the board to start over.
He said PJM’s deadline would result in an “incomplete market design” in which DR was an “afterthought,” as he said it was in the CP design. Because they are rarely deployed, DR resources obtain most of their revenues through the capacity market.
“While increases to energy and AS revenues are expected to be offset by decreases to RPM [Reliability Pricing Model] costs, only in PJM’s most optimistic scenarios are the cost increases to load fully offset,” Campbell said. “Moreover, the RPM benefits to load are overstated because PJM has incorrectly assumed that all reduced capacity revenues will reduce revenues only to generators — thus ignoring the substantial portions of load that provide capacity via demand response and overstating the benefit of the changes to load.
“The effect of the changes is to increase consumer costs, and to transfer revenues from a moderately competitive capacity market to an administrative energy scarcity construct for the benefit of generators.”
Bruce said PJM’s initiative must be viewed along with other rule changes pending before FERC on fast-start pricing (EL18-34) and expanding the generators that can include variable operations and maintenance costs in cost-based offers (EL19-8, ER19-210). “That adds up to about a 25% increase in LMPs,” she said.
She criticized PJM’s “unduly conservative” ORDC, citing an analysis by the Monitor that suggested the RTO was overestimating outage risks.
Carl Johnson, of the PJM Public Power Coalition, noted that the RTO is also proposing fuel security compensation, which will further increase prices. “It’s not like this is the last 3.5% or 4, 5 or 6% increase,” he said. (See Full PJM Study Makes Case for Fuel Security Payments.)
Scarp promoted Calpine’s proposal as a “compromise,” saying PJM’s $2,000/MWh maximum penalty factor is far below the value of lost load.
He said Calpine could not support PJM’s capacity transition plan, saying the recently completed quadrennial review will reduce net CONE by 25% (ER19-105).
“That is a major, major shock” to the capacity market, he said. “We are very uncomfortable with reducing capacity revenues based on what you think [energy and ancillary services] prices are going to be.”
Old Dominion Electric Cooperative and American Municipal Power backed the Monitor’s proposal.
“We think the IMM’s proposal addresses the concerns of PJM and does so while preserving the equity of other stakeholders,” ODEC’s Mike Cocco said.
He said PJM’s proposed ORDC curve “is way above the value to consumers.”
Greg Poulos, executive director of the Consumer Advocates of PJM States (CAPS), said the Monitor proposed only changes that had broad agreement “and goes no further.”
5th Proposal
After the four proposals that the task force reviewed failed to win a supermajority, GT Power Group’s Tom Hysinski moved for a vote on a proposal by Vistra Energy that would eliminate the E&AS offset (like Calpine) while using a $2,000 penalty factor during hot and cold weather alerts and $1,000 at other times.
Monitor Bowring said the Vistra proposal had “all the negative aspects” of the PJM proposal and fails to address excessive payments to generators.
It was backed by more than 80% of Generation Owners and Transmission Owners and about half of Other Suppliers, but it found little support with customer representatives and distributors.
Although members agreed to continue talking, most appeared resigned that PJM will make a unilateral Section 206 filing with FERC.
“If you’re looking for a [Section] 205 filing, it would [require] an ORDC that’s not so generous,” Bruce said.
California fire investigators on Thursday said Pacific Gas and Electric was not responsible for the Tubbs Fire, a catastrophic blaze that leveled parts of the city of Santa Rosa in October 2017.
The blaze was a major source of the utility’s anticipated $30 billion in wildfire liability that led it to announce it would file for bankruptcy by Tuesday.
Cal Fire cleared PG&E of starting the 2017 Tubbs Fire, the second most destructive wildfire in California history. | Cal Fire
The news came as PG&E continued to fight proposed new probation requirements stemming from the San Bruno gas line explosion in 2010 and came under fire from shareholders who said it doesn’t need to seek Chapter 11 reorganization.
“The news from Cal Fire [the California Department of Forestry and Fire Protection] that PG&E did not cause the devastating 2017 Tubbs fire is yet another example of why the company shouldn’t be rushing to file for bankruptcy, which would be totally unnecessary and bad for all stakeholders,” BlueMountain Capital Management, a major PG&E shareholder, said in a news release Thursday afternoon.
BlueMountain has argued in open letters to PG&E that the company is not insolvent and should postpone its bankruptcy plans. Shareholders would likely lose out to creditors in a bankruptcy proceeding. The firm said Thursday it was planning to run a slate of candidates to replace PG&E’s current board members in May.
PG&E’s battered stock price shot up after Cal Fire’s announcement, going from around $7/share to $14/share in trading Thursday, but the utility remained wary about its prospects.
“Regardless of today’s announcement, PG&E still faces extensive litigation, significant potential liabilities and a deteriorating financial situation, which was further impaired by the recent credit agency downgrades to below investment grade,” the utility said Thursday. “Resolving the legal liabilities and financial challenges stemming from the 2017 and 2018 wildfires will be enormously complex and will require us to address multiple stakeholder interests, including thousands of wildfire victims and others who have already made claims and likely thousands of others we expect to make claims.”
California Gov. Gavin Newsom held a press conference in the state Capitol on Thursday to address the finding.
PG&E may not be liable for the Tubbs fire, Newsom said, but “it was found liable for 17 other fires in 2017.” (Cal Fire found PG&E equipment was a cause of 17 major Northern California fires in October 2017.)
“This obviously begs the question, ‘Now what?’” the governor said. “Do we anticipate that PG&E will move forward … as they previewed this next week to file bankruptcy? That is an open-ended question, and that’s a question for PG&E.”
No Violations
Cal Fire said a private landowner’s electrical equipment had sparked the Tubbs Fire, which killed 22 people, destroyed 5,636 structures and burned 36,807 acres. The fire was one of 21 major wildfires that tore through Northern California during days when high winds whipped the blazes into fast-moving infernos.
“After an extensive and thorough investigation, Cal Fire has determined the Tubbs Fire, which occurred during the October 2017 fire siege, was caused by a private electrical system adjacent to a residential structure,” the agency said. “Cal Fire investigators did not identify any violations of state law … related to the cause of this fire.”
That was not the case for the San Bruno gas explosion and fire, which killed eight residents and wrecked a neighborhood in suburban San Francisco. Jurors in 2016 convicted PG&E of six felony counts for violating safety regulations and obstructing an investigation. The company has been on probation, with a federal judge and a monitor overseeing it, since January 2017.
The judge in the case recently pressed PG&E and federal officials for information on whether the utility may have violated the terms of its probation by sparking other wine country fires. The utility is also suspected of causing the Camp Fire, the deadliest fire in state history, which killed 86 people and wiped out the town of Paradise in November.
On Jan. 9, Judge William Alsup, of the U.S. District Court in San Francisco, ordered PG&E and federal prosecutors to show cause why he should not impose sweeping new probation conditions on PG&E. (See Judge, Gov., CPUC and Protesters Weigh in on PG&E Mess.) The proposed conditions include requiring the utility to inspect its entire grid, to trim trees and branches encroaching on wires, and to fix problematic lines, poles and transformers — all before the start of the 2019 fire season this summer.
PG&E could only deliver electricity through parts of its system deemed safe under the judge’s plan, which Alsup said is intended to “reduce to zero” the number of wildfires sparked by PG&E equipment during the coming fire season.
Last week, Alsup asked PG&E and government prosecutors to comment on his tentative finding that the “single most recurring cause of the large 2017 and 2018 wildfires attributable to PG&E equipment has been the susceptibility of PG&E’s distribution lines to trees or limbs falling on them during high-wind events.”
That has often happened in rural areas where uninsulated power conductors are pushed together by falling trees or limbs, dropping electrical sparks on the vegetation below. During California’s dry wildfire season, “these electrical sparks pose an extreme danger of igniting a wildfire,” the judge wrote.
Alsup scheduled a hearing for Jan. 30 to weigh the matters and required the parties to file their briefs by Wednesday.
Overlapping Oversight
In its response filing with the court, PG&E argued it has more than 100,000 miles of overhead lines, making Alsup’s plan virtually impossible to comply with and extremely expensive, even if it could. Inspections, repairs and extensive tree clearing could cost between $75 billion and $150 billion, requiring PG&E to quintuple for one year the rates it charges its 16 million California customers, the utility contended.
The judge’s plan could also undermine the regulatory authority of FERC and the California Public Utilities Commission, PG&E argued.
“The proposed modifications involve a host of policy decisions about how to address safety, reliability and cost, and, in particular, how to do so against the backdrop of both drastic climate change and a complex state and federal regulatory framework that requires the delivery of electricity to everyone in California through an interconnected grid,” the utility’s lawyers wrote. “The court’s proposal would make these policy decisions in the context of a probation hearing, even though regulators are currently grappling with these very same issues.
“And the proposed modifications would do so by giving PG&E only two options: either remove an extraordinary number of trees across every segment of its electric grid within six months, or instead de-energize transmission and distribution lines, shutting off power across Northern California and potentially beyond.”
Government lawyers said they too were worried about the court impinging on federal and state authority and did not support the proposed probation changes.
“While the United States shares the court’s interest in imposing conditions of probation aimed at ensuring that the inhabitants of the Northern District are protected from the death and destruction caused by wildfires, on this record, the United States is not in a position to address the feasibility of implementing the conditions and the chance that they will effectuate that goal,” lawyers from the U.S. Attorney’s office wrote.
“As a threshold matter, the government does not believe the record supports imposition of the proposed conditions as they are currently drafted. Moreover, as drafted, the court’s proposed conditions may overlap with state and federal regulations (e.g., the Federal Power Act and the California Public Utilities Code) and touch on the province of state and federal regulators (e.g., California Public Utilities Commission and the Federal Energy Regulatory Commission).”
They recommended that the judge ask the federal monitor overseeing PG&E to review and evaluate the proposed conditions.
BOSTON — The offshore wind industry is poised for a wave of growth in the Northeast with expanding solicitations, falling contract prices and increasingly competitive auctions for new project sites, Massachusetts officials and wind developers shared Wednesday.
“We’re seeing more action in the industry, and we’re seeing more projects being developed in the multiple lease areas that we have,” Massachusetts Energy and Environmental Affairs Secretary Matthew Beaton said at a meeting of the Environmental Business Council of New England.
Beaton said he was excited to see New York expand its offshore wind target to 9,000 MW and joked that his state would now have to go for 50,000 MW. (See New York Boosts Zero-carbon, Renewable Goals.)
The state does want to solicit an additional 1,600 MW of offshore wind energy, and “we will be doing our additional procurement [800 MW] at least by June, and could be sooner,” Beaton said. (See Mass. Looks to Double Down on OSW, Clean Goals.)
The partial federal government shutdown forced James Bennett, chief of renewable energy at the U.S. Bureau of Ocean Energy Management, to cancel his speech about federal oversight of offshore wind leasing and regulation, said meeting chair Michael Ernst, executive adviser at energy consultancy Power Advisory.
However, Ernst showed slides of lease areas off the East Coast held by different developers and highlighted the December auction by BOEM that brought in $405 million for three wind energy sites off the Massachusetts coast — about six times the revenue from all previous auctions combined. (See Mass. Offshore Lease Auction Nets Record $405 Million.)
“We’re reaching the crest of that giant Hawaiian wave and heading for shore,” Ernst said.
Jobs, Tx and Wildlife
The Massachusetts Clean Energy Center will next month announce its first workforce solicitation awards for several training programs, said Bruce Carlisle, the center’s senior director for offshore wind.
The state estimates that deploying 1,600 MW of offshore wind will create up to 317 jobs during construction and indirectly support up to 985 jobs over the next 10 years.
The CEC also worked to “get the lay of the land in terms of where potential interconnection transmission landfall might be in order to inform state siting processes and what the basic grid was looking like,” Carlisle said. The center is “looking at where there were 345-kV high-voltage substations available for tie-in … stepping up from increments of 500 MW and looking at upgrades and what estimates of cost might be.”
Asked about expanding the target, Carlisle said authorization for an additional 1,600 MW requires the state’s Department of Energy Resources to look at the benefits and tradeoffs. Eric Steltzer, deputy director of DOER’s renewables division, noted his agency was aware that the offshore wind report had a legislative deadline of July, and also that Gov. Charlie Baker had made a pledge during the recent election campaign for it to be published in May.
Rachel Pachter, vice president of permitting affairs for Vineyard Wind, announced the company’s agreement with the Conservation Law Foundation, National Wildlife Federation and Natural Resources Defense Council to protect the right whales off Nantucket and Martha’s Vineyard.
A partnership between Avangrid Renewables and Copenhagen Infrastructure Partners, Vineyard last May won the contract to supply Massachusetts with 800 MW of offshore wind energy. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)
“I personally spend about 50% of my time on fisheries issues,” Pachter said.
The company will base its operations in the Port of New Bedford but is looking at other ports as well.
“We’ve been working very hard to do our operations and maintenance on Martha’s Vineyard, particularly in Vineyard Haven, as … year-round jobs are a big thing for folks on the Vineyard,” she said.
“Stakeholder engagement is very important,” said Matthew Morrissey, head of New England markets for Deepwater Wind, which was acquired by Ørsted US Offshore Wind last year. “As it relates to commercial fishing, I am a fifth-generation New Bedford resident, and I represented the commercial fishing industry for a long time … which has legitimate concerns.
Morrissey said some of this engagement, however, is becoming taxing for the fishermen: “They just can’t show up,” so several different organizations have emerged to represent them. He cited the Responsible Offshore Development Alliance having “emerged as a true representative of many constituencies.”
Vineyard in October signed an agreement with the town of Barnstable to bring its power onshore there, and in November it signed an agreement with MHI Vestas for 9.5-MW turbines, “which was the largest commercially available turbine last time I checked a week ago,” Pachter said.
Ruth Perry, marine science and regulatory policy specialist for Shell Exploration and Production, said subsidiary Mayflower Wind is looking to set up a joint venture office with EDP Renewables.
Competitive Pricing
The hot competition for offshore wind contracts has “led to strikingly low prices in the first rounds,” Morrissey said.
Vineyard’s 800-MW contract with Massachusetts runs 20 years and has two 400-MW tranches. The first tranche starts at $74/MWh and the second at $65/MWh, with the prices increasing by 2.5% per year. Partially redacted contract summaries from the state’s Department of Public Utilities show an average nominal price of $64.97/MWh in 2017 dollars.
“Those low prices will further embolden state leaders along the Atlantic seaboard to push forward on increasing levels of commitment and as a result it will be a cyclical dynamic,” Morrissey said.
The combination of Deepwater Wind and Ørsted has a substantial footprint in the wind energy lease areas, he said, pointing out the “extremely exciting” wind targets in the region.
“We anticipate Connecticut coming forward in this legislative session with 2,000 MW or thereabouts,” Morrissey said. The company also expects Virginia to raise its target to 3,200 MW, which follows New Jersey’s 3,500 MW and New York’s new commitment to 9,000 MW.
“We’re seeing now the confidence in the industry build as a result of these procurements,” he said. “The challenges of today are nothing compared to the challenges five years ago when there was no marketplace.”
CARMEL, Ind. — MISO’s Steering Committee will retain its current membership structure despite the lack of a sector diversity guarantee among representatives.
During a Wednesday conference call, committee members took no action to change the membership structure in a way that would enforce more equitable representation across MISO’s 10 stakeholder sectors.
Chair Tia Elliott said the committee received comments from six member entities that all supported no change. After reviewing comments, the membership considered the item closed.
In advocating for broader representation late last year, Rhonda Peters with Clean Grid Alliance pointed out that the Steering Committee currently has voting members from just four MISO sectors, but it could feasibly have as little as two stakeholder sectors represented in committee votes.
Peters contended that MISO and the committee should work to ensure at least six sectors are represented in voting, calling it a “gatekeeper” of stakeholder issue assignment and subsequent discussion in other stakeholder groups.
Committee members bristled at the “gatekeeper” characterization, with some noting that members represent the stakeholder groups that they were elected to lead, not their individual sectors. Steering Committee membership comprises the chairs of MISO’s main committees and is charged with administrative stakeholder duties — not policy decisions — which include routing new policy discussions to the appropriate stakeholder group for discussion.
Peters called for a special nomination process when a majority of stakeholder sectors are not represented on the Steering Committee, where the full RTO membership would vote to add more voting members to the committee.
“There are now more players than the traditionally integrated utilities,” Peters said during a November committee meeting. “We’re seeing changes in stakeholders, and we’re seeing more changes in the grid. There are more voices now.”
However, multiple companies emphasized that Steering Committee membership merely reflects MISO committee chairs, who can come from any sector and are themselves elected by a vote open to all members.
“Each chair and vice chair position is freely elected by the stakeholders within each respective sector,” Duke Energy’s Jay Rasmussen said. “If a stakeholder does not like the representation within the sector, they should get involved more in the nomination process and campaigning process within their sector. The individual is also free to throw their name into the nominating process. The current process works well, and there is no need to change it.”
However, MISO’s load-serving entity coalition said it was “supportive of diversity in MISO stakeholder entity leadership” and suggested that the RTO make sure chair elections for stakeholder groups are held within the same month so members have the opportunity to factor sector diversity into their votes.
NYISO on Tuesday released a Strategic Plan outlining how it will incorporate market and regulatory trends into its planning processes for 2019 to 2023.
“Our updated Strategic Plan is a living document that embraces the challenges and opportunities of the grid’s ongoing transformation,” interim President and CEO Robert Fernandez said in a statement. “The plan reflects the NYISO’s essential role in harmonizing public policy with technological innovation in a manner that delivers economically efficient and reliable energy to consumers.”
| NYISO
The document identifies key strategic initiatives in addition to the ISO’s core responsibilities and ongoing project plans.
To address its changing resource mix, NYISO said it will review market products and operational and planning practices. Taking “a deeper dive into evolving focus areas” will require significant study work, it says.
New York’s Clean Energy Standard and other policy initiatives, such as Reforming the Energy Vision, are ramping up adoption of renewable and distributed energy resources, creating a need to balance intermittent generation with other resources such as storage.
“Incenting resource flexibility, which includes the ability to respond rapidly to dynamic system conditions, providing controllable ramp with fast response rates and providing frequent start-up/shutdown capability, will be key to future market enhancements,” the plan says.
The plan also highlighted steps to harmonize the wholesale market design with state public policy goals, particularly the task force created by the state’s Public Service Commission and NYISO that last month produced a proposal to price carbon into the wholesale energy market. The ISO and its stakeholders are now refining the proposal. (See Imports/Exports Top Talk at NYISO Carbon Pricing Kick-off.)
