Portland General Electric (PGE) and the Bonneville Power Administration said Wednesday they have signed two agreements that will help PGE avert a generation shortage after it shuts down its coal-fired Boardman Generating Station in 2020.
PGE in 2010 agreed to close the 550-MW Boardman plant to avoid investing the $470 million in pollution controls needed to keep Oregon’s last coal-fired generator running until its original 2040 retirement date. The utility last year halted efforts to build two new gas-fired plants at the Boardman site, saying it was instead pursuing talks to obtain existing resources.
Wednesday’s announcement revealed those resources will be supplied by BPA, which will sell the Oregon utility up to 200 MW of surplus hydropower from the Federal Columbia River Power System under two concurrent five-year power purchase agreements for two different energy products, starting in January 2021. BPA told RTO Insider it could divulge only limited details about the contracts because they are subject to a non-disclosure agreement.
“That said, we can say that the two products are an advance notice right to power, each with different notification timeframes,” BPA spokesman David Wilson said. “Each product also carries asset-controlling supplier status,” which allows the associated energy to be exported to California with a low emissions factor for the purpose of greenhouse gas reporting under that state’s cap-and-trade program.
BPA said there were benefits to both parties in the deal, with PGE gaining access to fast-ramping resources while the federal power marketing agency pursues one plank of its recently announced strategic plan, which includes the marketing of “competitive products and services.”
“In addition to allowing BPA to take advantage of a new opportunity to market its clean, flexible hydropower and generate direct revenue as part of a broadening portfolio of power products, the contracts allow PGE more time for new dispatchable resource technologies to mature to help the company integrate increasing amounts of renewable power onto its system,” BPA said.
“These agreements are a great opportunity for us to collaborate with BPA to achieve shared goals in the region,” said PGE CEO Maria Pope.
The deal also has found support among key ratepayer and environmental advocates in the region.
“This is a great deal for the region. It’s a value-added product for the federal power system and a good alternative for PGE. It puts off big new investments in gas that would have locked PGE and its customers into fossil fuels for decades,” said Bob Jenks, executive director of the Oregon Citizens’ Utility Board.
“Instead of building new carbon-emitting resources, PGE is able to take advantage of existing clean hydropower, and BPA is able to lock in a future sale to help strengthen its financial health,” said Wendy Gerlitz, policy director with the NW Energy Coalition.
The power that PGE acquires under the BPA contracts will not count toward Oregon’s 50%-by-2040 renewable portfolio standard, which bars facilities that began operating before 1995. But it will contribute to the utility’s efforts to meet an Oregon requirement to reduce emissions to 80% below 1990 levels by 2050.
PGE earlier this month circulated a draft request for proposals seeking 100 MW of renewable power to help meet both those mandates. The utility expects to bring those resources into its portfolio by 2021.
The utility last October joined Western Energy Imbalance Market (EIM), drawing $2.8 million in net benefits during its first three months of participation, according to CAISO.
FERC on Tuesday rejected separate complaints by the Nebraska Public Power District and Xcel Energy over billed charges under Attachment Z2 of SPP’s Tariff.
Filing on behalf of its Southwestern Public Service affiliate, Xcel alleged SPP’s assignment of $12.8 million in credit payment obligations under Z2 and $485,000 in zonal charges violated service agreements with SPS, and that the filed rate doctrine and the RTO’s implementation of Z2 violated the Tariff’s “but for” test (EL18-9).
NPPD complained SPP misinterpreted its Tariff and improperly billed the utility for 86 Z2 revenue credit obligations and said the misinterpretation will subject it to future monthly charges under regionwide and zonal rates eligible for recovery (EL17-86).
Attachment Z2 assigns financial credits and obligations for sponsored transmission upgrades. The RTO last year completed a resettlement of the Z2 revenue, crediting amounts for March 2008 to August 2016, a move made necessary because of corrections and true-ups to the data that were identified before the first settlement of the charges. (See “More Z2 Woes; SPP to Resettle 9 Years of Data,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
SPP’s headquarters in Little Rock, AR | WER Architects
FERC has consistently sided with SPP in member complaints to the commission. It denied requests by several members to rehear FERC’s 2016 order waiving the one-year limit for adjusting Z2 payment obligations and revenue distributions for transmission projects. It also partially granted Kansas Electric Power Cooperative’s complaint in a separate transmission dispute with SPP, denying some claims and setting settlement judge procedures on others. (See FERC Rejects SPP Change on Network Resource Upgrades.)
FERC: Xcel Should Have Been Aware of Z2 Costs
The commission dismissed Xcel’s argument that SPS’ service agreements with SPP resulted from the RTO’s aggregate transmission service study process, were accepted by the commission and should have reflected SPS’ final cost responsibility as part of the filed rate. Xcel asserted that when SPS executed the resulting service agreements with SPP, the agreements should have contained all of the final responsible upgrade costs.
But FERC found the aggregate study reports alerted Xcel to the potential for SPS to be directly assigned costs for upgrades later determined to be necessary to support the transmission service request (TSR) in SPS’ agreements. It noted SPP was developing the Z2 revenue crediting mechanism when it provided Xcel with study reports and, “therefore, could not provide accurate estimates.”
The commission also rejected Xcel’s allegation that SPP’s assignment of costs violated Attachment Z2 and the filed rate doctrine, finding that Xcel misinterpreted the RTO’s application of the “but for” test. FERC found SPP’s methodology to be “reasonable” in determining whether a TSR makes subsequent use of creditable upgrades and that the “but for” test to determine credits under Attachment Z2 was a “reasonable and practical application.”
SPP’s Tariff Interpretation Correct
FERC also found SPP correctly interpreted its Tariff by classifying more than $860,000 in upgrades identified in NPPD’s complaint as service upgrades eligible for base plan funding cost allocation. The commission said the upgrades were initially determined to be necessary for generator interconnection requests, and the costs were directly assigned to customers “consistent” with interconnection procedures and the Tariff’s pro forma interconnection agreement, making them creditable upgrades.
| Aristotle-Buzz
The directly assigned upgrade costs became eligible to be recovered through revenue credit payments that made “subsequent use of the upgrades,” the commission said. In implementing the Z2 crediting process, SPP identified additional creditable upgrades subsequently used by previously studied TSRs and associated credit payment obligations, FERC said.
The commission said those obligations became eligible for base plan funding under the Tariff’s cost allocation rules and were included in the rolled-in allocation of costs to transmission customers through the regionwide and zonal rates.
“Therefore … these costs were properly allocated under base plan funding,” FERC said, in rejecting NPPD’s assertions that SPP should allocate the costs differently.
Entergy will not have to issue refunds in a decades-long rate dispute with the Louisiana Public Service Commission, the D.C. Circuit Court of Appeals ruled Tuesday.
In denying the PSC’s petition for review, the court upheld FERC’s decision not to order the refunds, acknowledging that the federal commission does not have a “generally applicable policy of granting refunds,” something the court did not understand when it originally remanded the rate case (16-1382).
Galvez Building housing the Louisiana Public Service Commission | LA.gov
The issue dates back to 1995, when the PSC and the New Orleans City Council filed a successful complaint with FERC, arguing that Entergy’s formula for determining peak load responsibility in its multistate system agreement was unfair because it included interruptible load in addition to firm load.
In a 2004 order, FERC found that certain aspects of Entergy’s rates were unreasonable. And while the commission required Entergy to remove all interruptible load from its cost allocation, it declined to order refunds, concluding that the utility did not over-collect despite relying on an inequitable cost allocation.
FERC does not historically order refunds when “the company collected the proper level of revenues, but it is later determined that those revenues should have been allocated differently,” the court noted.
The court said that in 2016 it was initially convinced by the PSC’s argument that FERC had failed to “‘reasonably explain the departure’ from its ‘general policy’ of ordering refunds when consumers have paid unjust and unreasonable rates” and remanded the case to FERC. Last year, the PSC was still arguing at FERC that refunds to Entergy Louisiana could be possible. (See FERCAccepts Entergy Revision on ‘Moot’ Settlement.)
But, on remand, FERC told the court that it “actually has no general policy of ordering refunds in cases of rate design.”
FERC acknowledged that throughout the case it had referred to “a ‘general policy’ in favor of refunds” but said that the phrase was a mischaracterization and that it has no such policy.
The court accepted the explanation, saying FERC had clarified its “previously muddled position.”
“Now that the commission has corrected its characterization of its own precedent, we find that the commission’s denial of refunds accords with its usual practice in cost allocation cases such as this one. We also find that the commission adequately explained its conclusion that it would be inequitable to award refunds in this case. The commission did not abuse its discretion. … We find that the commission has made its historic practice clear and justified its application of that practice here,” the court said.
California Public Utilities Commission President Michael Picker on Tuesday asked state lawmakers for guidance on the increasingly precarious financial health of the state’s investor-owned utilities, which face growing risks stemming from wildfires.
That topic — and reliability concerns surrounding the Aliso Canyon gas storage facility — dominated discussion at a hearing of the State Senate Energy, Utilities and Communications Committee in Sacramento.
Committee Chairman Ben Hueso (D) said that “there has been one issue over another” affecting utility planning and operations, including earthquakes, floods and wildfires.
“There has always been something that complicates the ability of the state of California to provide energy to the people of the state,” Hueso said.
Picker noted that analysts had recently downgraded the credit rating of a solar project owned by an independent power producer because it holds a contract with a utility, showing the ripple effect of utility credit downgrades that have occurred recently over wildfire risk. The trend could make it more difficult for California to meet its greenhouse gas reduction goals, he said.
“If this continues, we will probably have a hard time saying to the rest of the world that we could accelerate the process of greening the grid,” Picker said.
Several IOUs have recently been downgraded or placed on credit watch by ratings agencies, leading to worries in Sacramento about a repeat of the California energy crisis of 2000-2001 and IOU bankruptcies. The State Assembly recently held its own hearing on the issue, at which Picker also spoke. (See Wildfire Costs Ignite Worry at CPUC,Legislature.)
“I see the exact same pattern with respect to the investor-owned utilities that we have seen before,” said Sen. Robert Hertzberg (D), adding that credit downgrades can cause “cross-defaults” and other complications.
“The rate at which this thing falls apart is extraordinary,” Hertzberg said. “The house of cards is impacted in a way that is not quite positive.”
Picker has repeatedly asked lawmakers for direction on the issue.
“I am not here to tell the legislature what to do,” Picker said Tuesday. “I agree that it is urgent, but I do tend to work at the direction of the legislature.”
Elected officials have publicly discussed new legislation on the issue of “inverse condemnation,” a legal provision that allows utilities to seek recovery of wildfire-related costs in regulatory proceedings. The state’s three IOUs have banded together to challenge a recent CPUC decision denying cost recovery for San Diego Gas & Electric for damages from a 2007 fire, despite the utility’s reliance on the provision. (See Sempra Joins ‘Three-Pronged’ Wildfire Front.)
Stern Objects to Aliso Canyon Decision
During the hearing, Sen. Henry Stern (D) vocalized his displeasure with a March 3 decision by CPUC Energy Division Director Edward Randolph that the legislator said “secretly granted” a Southern California Gas request for “immediate, seemingly open-ended utilization of the Aliso Canyon underground storage facility.”
In a March 5 letter to the commission, Stern asked questions about the status of gas pipelines taken out of service this winter and how those decisions were made. Stern, whose district includes Porter Ranch, the site of numerous local health complaints attributed to the facility, has called for Aliso Canyon’s closure.
Stern said when there is a “Saturday night letter from Ed Randolph” that becomes public, “it starts to corrode that public trust.”
“We want to see this public trust restored, and it’s just not there right now,” Stern said. “People are going to assume the worst.”
Picker responded that he had recently proposed a moratorium on new commercial gas hookups in the Los Angeles County area that met heavy resistance from the business community. At its most recent meeting, the commission withdrew the proposed agenda item.
Picker said that “there is a core denial” of gas supply concerns and that “I need your help to get through that.” The real need for gas units is peaking power, he said.
“I completely agree there is plenty of blame to spread around here,” Stern said.
Picker also briefly sparred with Sen. Mike McGuire (D), who objected to Picker’s recent public suggestion that ratepayers in high-risk fire zones pay more for electricity. Picker used the example of homeowner’s insurance premiums in those areas that are higher based on fire risk.
McGuire, a Democrat from the North Coast district, which includes Marin County, replied that many of the fires occurred in areas without heavy tree growth.
“I will fight it with every bone in my body,” McGuire said of Picker’s proposal.
Picker and CPUC staff recently sent the commission’s 2017 annual report to the legislature, along with the Office of Ratepayer Advocates report.
FERC adequately explained why it limited Duke Energy Carolinas to a 40-year extension on the Catawba-Wateree hydro project, the D.C. Circuit Court of Appeals ruled Tuesday.
Duke had sought a new 50-year license for the project, which includes 11 developments on hundreds of miles of the Catawba and Wateree Rivers in North Carolina and South Carolina; its original 50-year license expired in 2008. The commission issued the 40-year license in 2015, concluding that construction and environmental measures under the new license were “moderate” (Project 2232-522).
Lake 16A | Catawba Wateree Water Management Group
The company asked the court to overturn the ruling, arguing it was similarly situated to applicants that had received 50-year extensions, making the commission’s order “arbitrary and capricious.”
The court declined to second guess the commission, noting the “narrowly circumscribed” role for the courts in ruling on hydro matters. “According due deference to the commission’s expertise in determining whether measures under a license are moderate or extensive and to its interpretation of its precedent and policy choices, we deny the petition for review,” it wrote (16-1296).
Lake Norman 2A | Catawba Wateree Water Management Group
The commission generally issues a 30-year license for projects with “little or no” new development, capacity, or environmental mitigation; a 40-year license for projects requiring “moderate” investments; and a 50-year license for projects involving “extensive” measures.
Duke applied for a new license after reaching an agreement with 70 entities that specified measures it would take under a renewal.
Catawba Wateree Project Map | FERC
In its request for rehearing, Duke argued that FERC had failed to consider the costs of its investments, saying it had spent about $54 million on construction required by the agreement and $111 million in other relicensing costs.
FERC responded it does not rely on a “a strictly quantitative analysis” because “cost estimates can fluctuate widely over time.” It also said Duke’s cost data were “not reliable.”
“In response to commission staff’s request to simply update the cost estimates … Duke Energy instead filed new estimates — unsupported by any explanation,” the commission said, noting the company included a $40 million gate instead of the $10 million bladder dam called for in the license order.
The court cited FERC’s observation that Duke had not claimed it could not recoup its costs within 40 years.
“Further, the commission noted that some of Duke Energy’s cost estimates were not fully supported, or were inconsistent with the new license, because it was unclear that all the enhancement and mitigation measures are new measures. Duke Energy’s effort to avoid the plain meaning of the staff request to update the cost estimates is unpersuasive; as license applicant it had every incentive to explain the basis for its cost estimates and it cannot prevail by shifting the burden of clarification to the commission,” the court said.
ISO-NE power prices last year climbed from record lows, but they didn’t recover by much.
The RTO said Tuesday that cheap natural gas and declining regional demand left 2017 average wholesale prices at the second-lowest level on record.
In 2016, prices dropped to their lowest levels since New England’s current competitive electricity markets were established in 2003, according to ISO-NE.
Prices averaged $33.94/MWh in 2017, up 17.3% from the previous year but nearly 35% under 2004 levels. Last year’s wholesale market value of $4.5 billion was also the second-lowest on record, compared with 2016’s record low of $4.1 billion.
| ISO-NE
ISO-NE attributed the soft market to the second-lowest natural gas prices since 2003 ($3.72/MMBtu) and mild weather throughout much of the year. Gas prices averaged $3.09/MMBtu in 2016.
Gas-fired generation last year accounted for 48% of the power produced within New England and 41% of the region’s total energy mix, including imports.
The RTO said the extreme cold that arrived the last week of December constrained gas supplies and drove up prices, yielding $396 million of the month’s total electricity sales of $856 million.
But aside from December, consumer electricity demand remained light, averaging 121 GWh in 2017, down 2.7% for the year, according to preliminary numbers, ISO-NE said.
“Wholesale power prices were low in 2017 because of low fuel costs and relatively low consumer demand for power during most of the year,” ISO-NE CEO Gordon van Welie said in a release. “However, the last week of December illustrates the impact of constrained natural gas supplies on electricity prices. The challenging operating conditions also highlighted a growing need for competitive markets to more transparently signal the potential costs of inadequate fuel security, which creates the potential for significant reliability risks to the region.”
| ISO-NE
August and June of last year saw the seventh and eighth lowest monthly price averages on record, at $23.77/MWh and $23.93/MWh, respectively. ISO-NE’s nine lowest-priced months all occurred in 2015, 2016 and 2017. The RTO’s highest prices occurred in January 2014 during that winter’s “polar vortex,” when prices averaged $162.88/MWh.
The RTO also said consistently improving transmission congestion played in role in keeping 2017 prices low. ISO-NE said that about $10 billion in transmission upgrades since 2002 has dropped congestion and reliability-related costs from more than $700 million in 2006 to about $57 million in 2017.
A coalition of consumer advocates, environmentalists, wind and solar developers and public power laid down a marker in FERC’s resilience docket Tuesday, calling on the commission to “review the design of organized wholesale electricity markets, particularly capacity constructs.”
The group — the American Public Power Association, Large Public Power Council, National Rural Electric Cooperative Association and the Transmission Access Policy Study Group from public power; the Electricity Consumers Resource Council (ELCON) and National Association of State Utility Consumer Advocates, representing load; and green energy proponents Natural Resources Defense Council, American Council on Renewable Energy, American Wind Energy Association and Solar Energy Industries Association — sent a letter to the commission listing five “principles” it said FERC should embrace in future rulings.
The principles: technology-neutral market rules; wholesale market rules that respect state and local resource choices and don’t make customers pay twice; allowing self-supply without RTO “second guessing”; no guaranteed recovery of investment costs for particular resources or technologies; and allowing markets “to function and stabilize before new solutions are deemed necessary to be implemented.”
“The capacity constructs include design features that may limit choice, create conflicts with state and local policy objectives, over-procure or unnecessarily retain capacity, and raise costs for customers,” the letter says, calling for avoiding “costly over-procurement.”
“We as a group are committed to contributing to solutions,” the letter continued. “We emphasize that solving this challenge directly and holistically, rather than layering costly Band-Aids on top of organized wholesale markets, will benefit customers most in the long run.”
FERC may ultimately rule that the coalition’s effort to inject a review of the capacity markets in PJM, ISO-NE and NYISO is out of the scope it set in the resiliency docket. The commission directed all RTOs and ISOs to identify their resilience risks; whether they should assess their resource portfolios against contingencies from the loss of key infrastructure; and the bulk power system attributes that contribute to resilience.
But the breadth of the coalition indicates that disenchantment with mandatory capacity markets — which public power has questioned since their inception — has grown as state officials attempt to execute climate policies in the face of markets that ignore carbon emissions.
The group’s letter, however, noted the limits of the alliance, saying, “These design principles work together; individual signatories do not necessarily support every principle if other principles are not also honored.”
FERC last week accepted MISO’s plan to allocate Michigan ratepayers $24.6 million in refunds for overcharges stemming from RTO-ordered system support resource agreements imposed on a Wisconsin Electric Power Co. coal-fired plant.
The commission directed MISO to execute the reallocation — which includes interest — over a 10-month period beginning Feb. 28 (ER14-2952-005).
FERC ruled in late October that WEPCo overcharged ratepayers on Michigan’s Upper Peninsula by almost $23 million for agreements that kept the 344-MW Presque Isle coal plant in Marquette, Mich., running in 2014 and early 2015 for reliability purposes. The commission directed MISO to calculate the refunds over the RTO’s objections that it did not provide clear guidance on how to do that. (See $23 Million Owed to Ratepayers in Presque Isle SSR Case.)
Presque Isle power plant | WEPCo
Now, Constellation Energy Group owes the largest share of SSR costs at $13.6 million, followed by Cloverland Electric Cooperative ($6.3 million), Upper Peninsula Power Co. ($4.9 million) and the city of Escanaba ($1.1 million). WPPI Energy is owed $3 million from Michigan LSEs. MISO redacted the monthly refund report in a public version of its filing because it would reveal “insight into monthly load patterns,” according to the RTO.
MISO had proposed to invoice the resettlements as a lump sum on Dec. 19, instead of over the original 14-month timeline. FERC determined that a 10-month distribution was more appropriate because it corresponded with the established April 3, 2014, refund effective date through the Jan. 31, 2015, termination of Presque Isle’s second SSR agreement.
AUSTIN, Texas — Infocast’s annual ERCOT Market Summit once again drew ISO staff, market participants and others for panel discussions on market reform, grid resiliency, resource adequacy, transmission constraints, wholesale price volatility, and integrating utility-scale solar power and battery storage.
Participants Caution Against Market Changes Before Summer
Some of ERCOT’s more vocal members urged caution as the market approaches a summer with projected record demand but with almost 8 GW less in generation after a wave of retirements and delays in planned projects.
The Public Utility Commission of Texas is considering withdrawing reliability unit commitments (RUCs) and reliability-must-run capacity from the operating reserve demand curve (ORDC), a real-time price adder that reflects the value of available reserves and is intended to incentivize resources to produce more energy and reserves. PUC staff said this would ensure that scarcity pricing is accurate and reflective of market dynamics. (See “Commissioners Delay Action on Removing RUCs from ORDC,” Texas PUC Briefs: Feb. 15, 2018.)
But that would be a mistake, said Katie Coleman, legal counsel for Texas Industrial Energy Consumers. “Since 2012, we have spent a lot of time and effort designing the ORDC. We specifically discussed including RMR and RUC capacity. Ideally, the ORDC values should reflect the actual amount of reserves, which accurately reflects the likelihood of load shed. We did a bunch of other things instead, to try and put more money in the market,” she said, referring to RUC’s $1,500 price floor — “which is higher than any unit’s actual cost” — and pricing RMR at the $9,000/MWh cap.
“We’ve built this machine, and we’re about to have a summer where it’s tested. Let’s see how it goes, then come back, and see if there are areas that really need refinement.”
“Part of the problem the last five years is we have never really defined what we are solving for from a reliability point of view,” said Barksdale English, Austin Energy’s interim chief of staff. “What is important to us? Is it short-term interval-to-interval reliability? Is it long-term five-, 10- or 15-year reliability? Until we figure out what we are solving for, having proposed solutions sort of seems like having the cart before the horse.”
English jokingly referred to his “multiple personality disorder” as a generation-owning municipality competing in ERCOT’s wholesale market. “I can get really excited about $9,000/MWh for wholesale generation, but then — oh my gosh — what about my consumers? Then, my City Council gets mad at me because I’m paying too much money.”
Beth Garza, director of the ERCOT Independent Market Monitor, cautioned against blurring the difference between a load-shed event and a blackout. “That’s a very important difference. Those loads are being paid to provide a service,” she said.
“I fully expect many of those services will be called on this summer that have never been called on before. If those services are called on, they’ve been curtailed or are no longer consuming, but they’re being paid for providing a service,” Garza said.
“At what levels does ERCOT take emergency actions? When does load shed begin?” asked Strasburger & Price’s Mark Walker, before answering his own question (when operating reserves reach 1,000 MW). “Hitting the offer cap with only 2,000 MW of available capacity left is sensible. If you look at actual prices when RUC resources are deployed by ERCOT under pressure from load, congestion and intermittent resources swings, the prices today really don’t reflect that we’re in an emergency situation or a serious reliability condition.”
Role-playing Reveals Markets Concerns
In a discussion on how low power prices are affecting the strategies of plant owners in ERCOT, summit organizers asked the panelists to role-play the different aspects of generation investment.
Federal Power Co. CEO Steve Gilliland, filled his natural role as a developer, and Tom Rose, CEO of Clean Energy Technology Association, played the investor. That left Cratylus Advisors’ Mark Bruce, who represents Southern Cross Transmission in its bid to become the ISO’s first DC tie operator, to play the regulator.
Asked what kind of signals the ORDC was giving investors, Gilliland said, “It’s not giving signals big enough and substantial enough.”
“What drives the financier and developer is cash and cash flow,” he said. “I don’t believe that system is giving a clear enough signal for a long enough period of time that convinces me new generation is warranted. I don’t believe it will be allowed to be a significant enough number. It’s going to like moving the deck chairs around on the Titanic.”
“As the regulator, that statement scares me because that ship didn’t make it,” Bruce deadpanned. “The ORDC was not intended to be a substitute for scarcity pricing. It is a construct intended to correct the anomalies in pricing that result from out-of-market actions of the grid operator.
“I applaud the Texas commission for resisting the call to pad the ORDC,” Bruce continued. “That doesn’t help the fundamentals. We’ve had significant periods of time where the system is overbuilt, and the prices will be, and should be, in the dirt during those periods. And that’s the rub, a political rub. The economically optimal reserve margin is quite a bit smaller than the official, cushy planning reserve margin. We’re about to live in the gap between the two, and the political leadership of the state is going to have to decide whether to let the market speak. The economics will reveal in themselves, and then the politics will play catch-up.”
Rose, reminding the audience that he was playing the financier, said, “All this is fairly interesting. Existing generators are going to have a great Christmas this August, but I am going to hold off on new investment until we see how the summer works out.
“I don’t think anyone will argue we’re moving into unchartered waters. That excites me. It might be a risk to some, but it’s a reward to me. If there are involuntary disconnections or if prices go up or down, you’re going to see a governmental reaction,” Rose said. “Reliability the last 10 years has been taken for granted. I already hear people talking about reregulating the market. Mark and I know that’s not going to happen. As he said, ‘There is no Plan B.’”
Generators: ORDC Won’t Incent New Generation
Generation owners in ERCOT debated the effectiveness of the ORDC, one of several pricing mechanisms the ISO says will help respond to tightening reserve margins this summer. (See ERCOT: Tight Summer Margins No Cause for Alarm.)
RTO Insider’s Tom Kleckner moderates a panel on ERCOT wholesale price volatility during Infocast’s ERCOT Market Summit. Panelists include (l-r) Skylar Resources’ Gerald Balboa, Citigroup’s Yashar Barut, ERCOT’s Kenan Ögelman and Engie Resources’ Andrew Elliott. | Infocast
“The ORDC, which is a scarcity pricing mechanism, is absolutely working as designed,” said Dynegy’s Bob Helton during a panel discussion on resource adequacy. “The question is, is it getting us to where we want to be, which is reliability equilibrium and economic equilibrium?”
The Lower Colorado River Authority’s Randa Stephenson said the ORDC should not be seen as a signal for additional generation development. Continued growth in wind generation is expected to pick up much of the slack for recent retirements of baseload generation, and while 2018 futures are trading around $140/MWh, the market has already considered the plant closings by Vistra Energy and others. (See Vistra Energy to Close 2 More Coal Plants.)
“Is there enough scarcity to signal a generation buildout? No, not even a peaker,” Stephenson said. “If you look out into the future, the market knew Vistra was going to happen. Summer of 19, 20 prices didn’t move up that much. I don’t think the signals are out there to justify new build.”
Stephenson said demand response mechanisms are having a greater effect on the market.
“As a generation owner … ORDC is icing on the cake,” she said. “You see a lot of demand response looking at chasing those high-demand periods. You see a drop of 2,000 MW, and that takes away the scarcity prices you were anticipating.”
“ORDC was never introduced, never is and never will be a resource adequacy tool,” Helton said. “It’s for scarcity pricing, a poor man’s co-optimization. It does help with missing money and equilibrium in the market. The correct place for reserves to be is an economically optimal reserve margin. You will likely have load-shed events, but that’s the economical thing to do.”
Susan Pope, managing director of FTI Consulting’s economic practice, told attendees during her keynote address that she and her coauthor on a report recommending ERCOT market reforms believe that the state’s transmission planning policies have “materially” raised costs.
Pope said Texas’ Competitive Renewable Energy Zones (CREZ) initiatives, a $7 billion program that built 2,800 miles of new transmission to deliver West Texas wind energy to the state’s urban centers, was an out-of-market investment “not being made by at-risk investors who need to recover the full costs of their investment.”
CREZ was part of more than $10 billion in transmission investments that have been added to total system costs over the past five years, she said.
“ERCOT regional transmission planning favors transmission for reliability problems, using very conservative assumptions for new generation,” Pope said. “The analysis only includes resources that have committed to construction. Transmission investments will be identified and will pre-empt market-based generation solutions driven by energy-only prices, that could be alternatives to solving reliability problems.
“The over-investment in transmission is partly because of the long lead times to build transmission,” she said. “Those planning can end up with extremely expensive solutions to solve reliability. Continuing to build this transmission reduces energy prices because it resolves all the congestion before it has a significant effect on prices.”
NRG Energy and Calpine commissioned Pope and William Hogan, research director of the Harvard Electricity Policy Group, to write a report assessing ERCOT’s energy-only design. The report asserts that subsidized renewable resources, socialized transmission costs and the lack of local scarcity pricing have “exposed areas where there is a need for adjustments” to ERCOT’s pricing rules. The Texas PUC held two workshops last year to discuss the report and other potential market reforms. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
During a discussion on transmission congestion constraints and how to address them, Brad Schwarz, Hunt Power’s director of system planning, described the CREZ initiative’s unintended consequences.
“CREZ was building transmission ahead of the generation, in the hopes the generation would come. It has happened,” Schwarz said. Then came the state’s oil and gas boom in recent years, he said.
“We would have been struggling to serve those loads without the CREZ,” Schwarz said. “We were able to serve more oil and gas load and bring more economic development to the state of Texas. You never really undervalue a transmission line. Once it’s out there, it finds value.”
Energy Storage Offers Solution to Congestion Issues
Kip Fox didn’t hide his disappointment over Texas regulators’ recent rejection of an American Electric Power request to connect a pair of utility-scale battery facilities to the ERCOT grid. AEP’s application ran into opposition from consumer organizations and market participants who argued that allowing the assets to be included in the regulatory base would harm competition. (See “Staff Opens Battery-Storage Rulemaking,” Texas PUC Briefs: Feb. 15, 2018.)
“We had an alternative to building a long distribution line. It was a $1.6 million solution to a $12 million problem,” said Fox, president of Electric Transmission Texas, a joint venture between AEP and Berkshire Hathaway Energy subsidiaries. “Unfortunately, since those [applications] were denied, without prejudice, we’re kind of back to square one.”
He said with batteries’ ability to provide frequency support and resolve overloading problems, “it makes more sense to run a battery eight to 10 times a year, rather than building a line.” Fox suggested Fluence Energy’s use of a portable battery in downtown Indianapolis presents a possible solution to congestion issues.
“We would like to move a battery around and solve that problem,” he said. “When the congestion is gone in five years because a transmission line hasn’t been built, we will have saved the ratepayers a lot of money.”
Tim Ash, Fluence’s market director for the eastern U.S., said other RTOs are wrestling with the same concerns over battery storage ownership and its effect on markets.
“There’s a much, much bigger market for energy storage,” Ash said. “It solves a reliability issue, which occurs maybe 10 times a year. The economic benefits are there today. The question is how to get the rules to unlock those benefits.”
FERC last month directed RTOs and ISOs to allow energy storage resources full access to their markets, an order that does not apply to ERCOT (RM16-23). (See FERC Rules to Boost Storage Role in Markets.) Asked if FERC’s directive might influence the PUC, which regulates ERCOT, to follow suit, Fox said, “Hell, yeah!”
“I’ve seen many times where the commission defaults to where FERC opens up the rules,” Fox said. “I find those rules are sometimes a little behind, sometimes a little ahead. There will be some pressure at all levels of the [state] government.”
Jack Farley, CEO of Apex Compressed Air Energy Storage, pointed to a 2012 PUC order that allows energy storage resources in ERCOT to pay wholesale prices for recharging, with no retail or transmission or distribution fees. “The energy market averages 40,000 MW and the ancillary services market is about 5,000 MW. In terms of participating in ERCOT energy and ancillary service products, I don’t think there are barriers today for energy storage resources,” he said.
“We will see energy storage adopted early,” said a more optimistic John Bonnin, vice president of energy supply and market operations for San Antonio’s CPS Energy. “As the technology improves, we will see it displace other applications in other parts of the market. If we meet again in five years, every one of us around here will have some sort of storage on their system. We all have to get smarter about the effect all that capacity will have on pricing, fuel and dispatch. It’s going to be disruptive.”
Developers See Bright Future for Texas Solar
A panel of solar developers gave high marks to the Texas market, which could see up to 8 GW of solar growth over the next few years.
“Texas is attractive because of low pricing. Wind is the headline, but at the same time, if the load continues to grow, we can make the case that there’s a match there for solar too,” said Andrew Fay, origination manager for First Solar.
Shalini Ramanathan, vice president of origination for RES Americas, said price pressure “is the reason we’re seeing so much development in West Texas and with large projects. If we can be competitive, we can do more 20-MW projects in other parts of the state. I think there’s a bias to larger West Texas solar.”
Spivey Paup, Recurrent Energy’s development director, said even West Texas, with its oil and gas infrastructure, can pose challenges.
“But once you get out of the Permian Basin, that complication goes away,” Paup said, referring to Texas’ rich petroleum fields. “We need to find a balance between strong resources and development complications. Renewables and solar were born and bred in California, but we can blow them up to scale and send California packing.”
Charlie Hemmeline, executive director of the Texas Solar Power Association, said current rules have resulted in “steady interest” in sun-powered generation in the state.
“We’re not going to ask for new polices or mandates or incentives,” he said. “We want it to work the way Texas wants it to work. ‘Don’t do anything bad to us’ is the primary policy ask.”
EVs, With or Without Drivers, are Coming
During a discussion of changing perspectives among end-use customers, Rob Threlkeld, General Motors’ global manager for renewable energy, noted he had driven from Detroit to Lansing, Mich., without once touching the steering wheel of his Cadillac CT6, thanks to its Super Cruise semi-autonomous driver-assistance system. The car comes in a plug-in version in addition to four- and six-cylinder engine models.
“In a year, the driver will touch the steering wheel much less,” Threlkeld predicted.
He had a believer in Champion Energy Services CEO Michael Sullivan, who owns a Tesla. He said the more mainstream CT6, which starts at about $85,300, will be more broadly available and easier to purchase than the special-order Tesla models.
“When you order Tesla, it’s like ordering an Italian shoe from a cobbler in Milan,” he said.
Both Threlkeld and Sullivan agreed that electric vehicles pose a sea change for the electric industry.
“We have been working closely with a lot of utilities, especially those progressive ones that are really interested in this space. It’s load growth, and that interests them,” Threlkeld said.
“If the projections are right, my teenage kids will never drive an internal-combustion car,” Sullivan said. “If everybody’s driving an electric car, that’s a major change to the industry, especially if somebody can capture storage in a really dense way.”
In two orders issued on the same day last week, FERC both vacated and reinstated MISO’s entire resource adequacy construct, ultimately leaving the RTO’s current capacity auction format — and past auction results — undisturbed.
FERC’s two Feb. 28 decisions concurrently reversed its 2012 acceptance of MISO’s resource adequacy rules (ER11-4081) and accepted the RTO’s refiling of the rules (ER18-462).
To protect its market from “potential disruptions,” MISO in December pre-emptively refiled its entire resource adequacy construct in response to the D.C. Circuit of Appeals’ ruling that FERC overstepped its “passive and reactive” role when it prescribed revisions to PJM’s minimum offer price rule. MISO was concerned about the impact of that decision on some of the resource adequacy rules that had been guided by FERC’s recommendations. (See MISO Seeks FERC Reapproval to Keep RA Rules Intact.)
Following the PJM decision, the D.C. Circuit granted FERC a voluntary remand to once again consider MISO’s 2011 market revisions.
In the order on remand, FERC said in light of the court’s PJM decision, “the modifications set out in the [resource adequacy orders] could be considered to be major modifications to MISO’s 2011 filing. Accordingly, because we cannot find MISO’s 2011 filing to be just and reasonable without our modifications, we reverse the commission’s conditional acceptance of MISO 2011 filing, and we reject MISO’s 2011 filing in its entirety.”
FERC at that time rejected MISO’s proposed mandatory auction requirement and minimum offer price rule and ordered the RTO to phase out grandmother agreement provisions after the 2014/15 auction. Taken together, the revisions “would likely be considered to result in an ‘entirely different rate design’ than both MISO’s proposal and MISO’s prior rate scheme,” FERC said, acknowledging it had exceeded its authority under the Federal Power Act, “notwithstanding that MISO consented to those revisions.”
No Auction Do-Overs
However, FERC found that rerunning the last five years of MISO’s Planning Resource Auction under the pre-2011 monthly auction rules would be infeasible and unnecessary.
“Such a remedy would be extremely complex, subject to controversy and further litigation, and cause significant disruptions and burdens,” the commission said. “It would be highly difficult, if not impossible, for the commission or MISO to reasonably provide retroactive relief, by rerunning the auction for the 2013/14 planning year through the present.”
The commission then addressed MISO’s refiling, determining that the RTO’s current auction format should remain unchanged.
MISO Independent Market Monitor David Patton used the refiling as an opportunity to again urge FERC to order the RTO to employ a sloped demand curve in its capacity auction in order to produce more efficient pricing. (See MISO Monitor to FERC: Order Sloped Demand Curve.)
But the commission said MISO’s vertical curve was just and reasonable, noting that 90% of load is served by vertically integrated utilities. It said that, at any rate, pricing takes a backseat to the main objective: maintaining reliability.
“We … disagree with the Market Monitor’s contention that a vertical demand curve leads to prices that are not just and reasonable by failing to recognize the diminishing marginal benefits of excess capacity. MISO’s resource adequacy construct was developed to ensure that [load-serving entities] in MISO acquired sufficient capacity each year to maintain the one-day-in-10-year reliability standard. Although certain constructs may value capacity beyond that amount, doing so is not essential to MISO’s construct fulfilling this principal objective,” the commission said.
MISO maintains that its vertical demand curve and its annual resource adequacy survey with the Organization of MISO States “combine to provide just and reasonable signals.”
MISO potential GW additions according to 2017 OMS MISO annual survey | MISO
The commission also dismissed several other protests from stakeholders, including complaints that supply offers above $25/MW-day (about 10% of MISO’s cost of new entry) are read as an attempt to exercise market power under current capacity auction rules and that LSEs participated in price suppression in the 2017/18 auction.
FERC instead said that 2017/18’s low clearing price of $1.50/MW-day should be taken as the simple effect of supply and demand in MISO.
“The low capacity prices, where they have arisen in MISO, accurately reflect MISO’s capacity surplus. The fact that prices have not signaled to independent generators a need to build, retrofit or even simply maintain existing resources is more indicative of a well-functioning capacity procurement construct than it is of an unjust and unreasonable construct,” the commission said.
