Puget Sound Energy (PSE) and Talen Energy reached an agreement with environmentalists to shut down Units 1 and 2 at the coal-fired Colstrip power plant in Montana by July 2022.
Under the July 12 settlement filed in the U.S. District Court in Missoula, the Sierra Club and the Montana Environmental Information Center (MEIC) agree to dismiss their lawsuit against the plant’s owners for alleged violations of the federal Clean Air Act. PSE and Talen will also be required to reduce sulfur dioxide and nitrous oxide emissions from the units ahead of retirement (Case 1:13-cv-00032-DLC-JCL).
The agreement also stipulates that the environmental groups will drop legal action against Colstrip Units 3 and 4, which are jointly owned by PSE, Talen, Portland General Electric, Avista, PacifiCorp and NorthWestern Energy. Those coal-fired units were built in the mid-1980s and have a combined net generating capacity of 1,480 MW.
“PSE believes this settlement is in the best interest of our customers by avoiding the potential need for the installation of additional pollution control equipment for Units 1 and 2 due to future regulatory requirements,” the company said in a statement.
Environmental Rules, Competitive Pressures
Competitive pressures stemming from low natural gas prices factored into PSE’s decision to close the units. The company also cited “shifting policies and regulations on the federal and state levels,” EPA’s regional haze rule and the Clean Power Plan as additional reasons.
“Our customers expect PSE to be good stewards of the environment and to keep energy costs reasonable,” CEO Kimberly Harris said. “The eventual closure of Units 1 and 2 at Colstrip without the risk of further legal proceedings or additional significant investments in the units to meet regulatory requirements enables us to accomplish both of these goals.”
Colstrip Power Plant Source: Talen Energy
Built in the mid-1970s, the two units can produce 614 MW of electricity, most of which is supplied to consumers in Washington and Oregon. Earlier this year, Washington lawmakers passed a bill that would enable PSE to recover its share of the costs for shutting down the units from ratepayers, while Oregon established a mandate requiring PacifiCorp and PGE to become coal-free by 2030 and 2035, respectively.
In May, Pennsylvania-based Talen notified Colstrip’s other five owners that it planned to cease functioning as the plant’s operator in May 2018. As the plant’s only merchant owner, the company is unable to recover its costs from a rate base and is especially exposed to low power prices on the open market.
The move was part of a broader strategy to withdraw from Montana by the company, which last month agreed to be acquired by Riverstone Holdings. (See Riverstone to Acquire Talen in $1.8 Billion Deal.)
Opportunity for Wind?
Colstrip’s owners collectively own the two 250-mile, 500-kV transmission lines that connect the plant with the Bonneville Power Administration’s transmission network and load centers in the Pacific Northwest. Renewable energy advocates have eyed Colstrip’s transmission as a possible boon for wind development in Montana, a state that the American Wind Energy Association ranks as third in the U.S. for wind potential.
“[The] decision [by PSE and Talen] marks an opportunity to use Colstrip’s existing transmission system to build out more clean energy and export it to Washington and other states,” the Sierra Club said in a statement.
“We want to work with the power plant owners, the community of Colstrip and Montana to plan for a transition that maximizes employment in clean-up, remediation and new renewable energy development in the Colstrip area,” said Mike Scott, a Sierra Club senior organizer.
Montana Gov. Steve Bullock (D), who faces a re-election campaign this fall, was less enthusiastic about the immediate prospects for the region.
“I stand with the workers and the community of Colstrip in being angry about this settlement outcome,” Bullock said. “The parties of this lawsuit took care of themselves. I am going to work to take care of the employees and their families.”
CAISO’s expansion into a multistate, regional electricity market could save California ratepayers as much as $1.5 billion annually while helping the state to meet or exceed its 2030 emission-reduction goals, according to a study commissioned by the ISO.
California’s Clean Energy and Pollution Reduction Act — the 2015 law that established the state’s 50% by 2030 renewable portfolio standard — required CAISO to perform an analysis of the economic, environmental and reliability impact of regionalizing the Western grid.
The study modeled three 2030 scenarios: one in which California meets its RPS without expansion and ones with a regionalized market with state- and regionally focused procurements. The last scenario offered the most significant benefits, according to the analysis, which was conducted by The Brattle Group, Energy and Environmental Economics, Berkeley Economic Advising and Research and the Aspen Environmental Group.
‘Compelling Message’
The benefits estimated in the study are in addition to those expected from CAISO’s expanded Energy Imbalance Market.
Development of a regional market could generate up to 19,300 new jobs for the state by 2030, more than half of which would be related to construction of renewables, the study found. Other jobs would be the indirect result of realigned consumer spending based on reduced energy costs.
Real income in California is expected to increase by $4.1 billion to $7.9 billion annually, while state tax revenues would rise by $600 million to $1.6 billion.
The study’s findings provide a “pretty compelling and simple message,” CAISO CEO Steve Berberich said.
“The electric industry in California is at an inflection point,” Berberich told reporters during a call Tuesday to discuss the report. “I think the state has the ability to enable a new paradigm where clean energy and economic growth become one.”
The study analyzed two regional market footprints: one including only CAISO and PacifiCorp and a second including all of the U.S. portion of the Western Electricity Coordinating Council except the two federal power marketing agencies there, the Bonneville Power Administration and the Western Area Power Administration. “These footprints are hypothetical and are designed to capture a plausible range of impacts,” the study notes. “We understand that the individual utilities and states will have to conduct their own evaluations of the benefits and trade-offs of joining a regional entity and to decide whether or not to join one.”
Regionalization would provide the ISO the ability to optimize generation over a larger footprint, allowing California “to go beyond” its 50% RPS, Berberich said. The study included the costs of storage and transmission needed to integrate renewables.
Fear of Curtailments
Without expansion, the ISO predicts periodic renewable curtailments of up to 13,000 MW — even with the expected closure of Pacific Gas and Electric’s Diablo Canyon nuclear power plant in 2025.
“Absent a regional market, we’re very concerned that we could see a lot of renewable energy curtailed because there isn’t an adequate market to sink the power,” said Keith Casey, ISO vice president for market and infrastructure development.
Casey noted that other RTOs in the U.S. are facilitating the development of “non-RPS” renewables — renewable projects built based on cost-competitiveness rather than in response to mandates. “For example, since 2000, wind generation accounted for 80% of 44,000 MW of non-RPS-related renewable generation additions nationwide, and 80% of these non-RPS-related wind generation investments (over 28,000 MW) took place in six states (Texas, Iowa, Oklahoma, Kansas, Illinois and Indiana), all of which are in ISO-operated market areas,” the report said.
CAISO’s study found that a regional market could eventually save California ratepayers as much as $1.5 billion a year.
“We think this [expanded CAISO] market will provide a platform for renewable development to flourish,” Casey said.
Other highlights of the study:
By 2030, the market would help California reduce electric sector CO2 emissions by 4 million to 5 million metric tons per year — 8 to 10% below a scenario with no regional market. That would represent a 58% decline from 1990 levels.
Land use for building new wind and solar developments to meet California’s RPS would be reduced by up to 71,300 acres inside the state and 31,900 acres elsewhere in the West because of more efficient resource expansion. The study projects increased transmission construction outside California to support out-of-state projects.
A regional market would reduce water use by combined-cycle gas units in California and gas and coal plants in other areas of the West as a result of the more efficient dispatch of renewable resources.
The market’s larger operational footprint would allow for improved renewable integration through centralized control and increased awareness of neighboring areas. Lower requirements for load-following resources, operating reserves and planning reserves would lower costs for maintaining reliability.
WASHINGTON — The Senate voted overwhelmingly last week to enter conference committee negotiations on energy legislation after Republicans agreed to drop provisions in a House bill that President Obama has promised to veto.
Sen. Lisa Murkowski (R-Alaska), chairwoman of the Energy and Natural Resources Committee, speaks before the Senate approved a conference committee on energy legislation. Source: C-SPAN
“I will reiterate my personal commitment to a final bill that can pass both chambers and be signed into law by the president,” Sen. Lisa Murkowski (R-Alaska), chairwoman of the Energy and Natural Resources Committee, said on the Senate floor July 12 before the upper chamber voted 84-3 to name conferees.
“It can’t be the House product necessarily, or the Senate product necessarily,” she added. “It has to be something that both chambers can agree on and that the president can sign into law.”
Sen. Maria Cantwell (D-Wash.), the committee’s ranking member, said the Republicans’ promise was enough to keep Democrats working toward a compromise.
“What we were most concerned about was pursuing an agenda that definitely couldn’t get past the White House, and veto threats, and certainly wanted to look constructively at how we got a package on some issues that we knew if we couldn’t get resolved, it wouldn’t get resolved,” Cantwell told reporters.
The Senate passed its bipartisan Energy Policy Modernization Act of 2016 (S.2012) in April, with support of all but a handful of Republicans. It authorizes increased spending on energy research, improves cybersecurity protections and encourages more efficient buildings and vehicles. It also adds taxpayer protections to the Energy Department’s loan guarantee program and streamlines federal approvals of electric transmission, pipeline, hydropower and LNG facilities.
Obama, who has expressed support for most provisions in the Senate bill, singled out several House proposals as nonstarters, including ones that would limit funding for the National Science Foundation and the federal government’s influence over local building codes. The administration also objected to measures that would halt implementation of an efficiency rule for gas furnaces and reverse existing law phasing out fossil fuels from federal buildings. (See Energy Bill Faces Tight Calendar, Partisan Divide in House.)
House Republicans have balked at the Senate bill’s permanent reauthorization of the Land and Water Conservation Fund.
The Senate acted before Congress began a seven-week recess, during which staffers are expected to work toward a bill both houses can approve. If enacted, it would be the first major energy law in almost a decade.
In addition to Murkowski and Cantwell, the Senate conferees are Sens. John Barrasso (R-Wyo.), Jim Risch (R-Idaho), John Cornyn (R-Texas), Ron Wyden (D-Ore.) and Bernie Sanders (I-Vt.). The House has named 24 Republicans and 16 Democrats to the committee.
Interest Groups React
Alliance to Save Energy President Kateri Callahan said that while reaching agreement will be difficult, “focusing first on those pieces — like the energy efficiency provisions that have strong bipartisan support and broad public appeal — will help the conferees to move together.”
Senator Maria Cantwell Source: C-SPAN
The League of Conservation Voters praised Murkowski and Cantwell for reaching a compromise to ensure negotiations continue. “However, we are concerned that many controversial items still remain in the scope of the energy bill conference and that the measures being debated will not amount to the true overhaul our energy sector needs,” Vice President of Government Affairs Sara Chieffo said in a statement.
The American Petroleum Institute praised the Senate’s action, saying its bill would ensure “that American natural gas has a dominant place on the world market.”
The Union of Concerned Scientists said the conferees could produce a bill that is a “modest step in the right direction on issues such as energy efficiency and clean energy infrastructure.”
“Both parties have a lot invested and aren’t interested in wasting their time,” Rob Cowin, director of government affairs for UCS’s Climate and Energy Program, said in a statement.
“Although much better than the partisan House bill, the bipartisan Senate bill contains a worrisome provision categorizing the burning of biomass for electricity as carbon-neutral. This is not only scientifically inaccurate but could also undercut EPA’s current efforts to determine the proper role for biomass in the Clean Power Plan and potentially lead to increased carbon pollution.”
Entergy said Wednesday it may sell its troubled James A. FitzPatrick nuclear plant to Exelon if New York approves the proposed Clean Energy Standard, which would provide large subsidies to nuclear stations.
If New York cannot agree on those subsidies, Entergy said, it will go forward with its plans to cease operations by January.
“In keeping with our corporate strategy to move away from merchant power markets and toward a company operating exclusively as a utility in regulated markets, we are working with Exelon to come to commercial terms on a sale transaction that depends largely on the final terms and timeliness of the New York State Clean Energy Standard,” Entergy Wholesale Commodities President Bill Mohl said. “We thank New York Gov. Andrew Cuomo for his leadership in promoting the Clean Energy Standard.”
Cuomo called the possible sale “welcome news.”
“My administration has been working closely with both companies to find a way to keep this vital energy resource operating,” Cuomo said in a statement. “While there remains much work to be done, I am pleased that significant progress is being made.
Fitzpatrick Nuclear Plant Source Entergy
“I have directed various state entities to continue working with the parties involved to finish the job. I am hopeful that a definitive agreement will be reached to ensure these benefits to New Yorkers are realized.”
The proposed nuclear subsidies are a recent addition to the state’s Clean Energy Standard. The clean energy blueprint would mandate use of renewable energy for half of the state’s electricity by 2030.
According to a July 8 report by the staff of the New York Public Service Commission, the nuclear subsidies would total $965 million over the first two years while providing economic and environmental benefits through carbon reductions, supply cost savings and property tax benefits of about $5 billion (Case 15-E-0302).
Initial cost estimates for the nuclear subsidies were $59 million to $658 million through 2023, with net benefits of about $1 billion. (See NYPSC: Minimal Cost to Meet 50% Renewable Goal.)
Three plants in the state — FitzPatrick and Exelon’s Nine Mile Point and R.E. Ginna — would be eligible for the subsidies. Cuomo wants to exclude Entergy’s Indian Point, which he wants shut down because of its proximity to New York City.
When the nuclear subsidies in the Clean Energy Standard were first announced, Entergy said they would have no effect on its plans to close FitzPatrick. But the company said Wednesday that its decision to seek a sale to Exelon is “consistent with Entergy’s commitment to consider any viable option that would allow FitzPatrick to remain in operation.”
Exelon spokeswoman Lacey Dean confirmed the talks on Wednesday, saying a deal would be “subject to several firm conditions.”
In addition to approval of the Clean Energy Standard, Dean said, the conditions were a guaranteed long-term revenue stream for the plant and an immediate positive impact on Exelon’s earnings.
She declined to say how long the talks had been in progress or if a purchase price had been discussed.
Fighting a PJM proposal to impose uplift costs on up-to-congestion trades, the Financial Marketers Coalition last week enlisted one of the intellectual pioneers of electricity markets in its defense.
Presenting the conclusions from his white paper on virtual trading, Harvard economist William Hogan told the Energy Market Uplift Senior Task Force that PJM should eliminate uplift costs from all financial transactions rather than extending them to UTCs.
Hogan said PJM’s October 2015 paper, which recommended charging UTCs, was too narrowly focused and failed to acknowledge some of virtual transactions’ benefits, including countering market power, improving market efficiency and hedging real-time market risks.
“Uplift can arise for many reasons. … The focus on deviations, which are used for allocating uplift costs, do not go hand in hand with added uplift costs,” said Hogan, the Raymond Plank Professor of Global Energy Policy at Harvard’s John F. Kennedy School of Government. “We want to be careful about using [deviations] as a measure of failure of the system and then using that to allocate a subcategory of the costs.”
He suggested exempting virtual trading from uplift charges and allocating the costs instead to the “real-time gluttons” — consumers who won’t respond to even the most extreme price signals.
It’s “foolish,” he said, to think that the costs could be allocated anywhere other than consumers. “In the end, in equilibrium, the load’s gotta pay,” he said. “Aggregate efficiency should be the standard.”
‘Reversal of the Conventional Wisdom’
Hogan’s stature — Public Utilities Fortnightly has called him “the chief architect of wholesale electric market design in the United States” — makes him a valuable ally. Among his other clients have been numerous utilities, MISO, ISO-NE and the Electric Power Supply Association, which enlisted him in its unsuccessful bid to eliminate FERC oversight of demand response. He was also among the experts who defended Richard and Kevin Gates’ Powhatan Energy Fund in their high profile campaign against FERC market manipulation charges.
Hogan conceded that his position on virtual trading represents a “reversal of the conventional wisdom.” He rejected arguments by those who contend that virtual bidding provides no significant benefits and thus extracts money via what a 2015 paper by Massachusetts Institute of Technology economist John E. Parsons and three FERC analysts termed “parasitic” profits.
At this year’s EBA Annual Meeting left to right: Greg Lawrence, William Hogan, David Patton, Sam Newell and Joe Bowring
He highlighted two studies — one focused on California and the other on ISO-NE — that concluded virtual transactions increased price convergence between the day-ahead and real-time markets and reduced dispatch costs. While “not a dramatic number — a single-digit percentage of improvement” — the studies showed how virtual transactions help smooth out the “lumpiness” of unit commitment costs, Hogan said.
“The inclusion of the convergence bidding and the virtual bidding made the whole system operate more efficiently,” he said. “Neither of these studies go all the way, but they are very suggestive.”
Hogan also took on PJM Independent Market Monitor Joe Bowring, who contends that UTC transactions are increasing shortfalls in FTR funding and that PJM should consider NYISO’s model, which limits virtual transactions to zones or hubs. (See PJM Ponders Changes to Virtual Trades, DA Market.)
Hogan said new recommendations contained in Bowring’s 2015 State of the Market report would result in the “undoing [of] financial transmission rights.”
“Forgetting … the larger context linking the market design economics to engineering principles can result in analyses and recommendations that can neglect the requirements of efficient electricity market design and recreate problems already solved,” Hogan wrote. (See “Financial Transmission Rights,” Bowring Urges Return to ‘Fundamentals’.)
Hogan was more conciliatory toward PJM’s 2015 paper, which he credited as “generally supportive of the contribution of virtual transactions as improving overall market performance” despite being issued “in a context where virtual bidding is under attack.” (See PJM Suggests Changes to Virtual Transactions.)
But he said the examples cited in PJM’s report “do not provide a framework for evaluating the overall cost and benefits of virtual transactions,” a task he acknowledged “is not easy.”
“The limited available analyses from other regions indicate that the benefits are material and outweigh the costs, but no available studies cover all the relevant issues.”
Focus on Deviations
PJM’s uplift charges totaled $314.2 million in 2015, down from $960.5 million in 2014, when costs spiked as a result of the polar vortex.
PJM UTC trading volumes fell by 85% after FERC said it might make the transactions liable for uplift assessments.
Because LMPs do not cover all production costs, uplift payments — or “residual” charges — are required to make generators whole. The biggest component of PJM’s uplift charges is the balancing operating reserve (BOR), the costs of which are allocated based on real-time deviations from day-ahead schedules.
Hogan said allocating uplift costs according to the deviations is inappropriate and “particularly problematic for virtual transactions, which by design involve a 100% deviation.”
He also said PJM’s cost allocation “does not arise from any fundamental model … [implying] that the allocation method is more an administrative compromise than the product of a principled analysis.”
Some deviations are expected and inevitable, Hogan said, citing the “lumpiness” of unit commitment costs. As an example, he described a generator being priced too high to clear the day-ahead market but clearing during the later reliability run.
Because uplift is a result of residual costs, attempting to figure out the cost causation “is a fool’s errand,” Hogan said.
“The important question is the aggregate net benefit of virtual transactions, not the residual cost. If virtual transactions increase the net benefits in the market, then there is no incentive-based reason to assign additional costs to virtual transactions.
“Allocating the uplift costs to network connection charges would be better than adding to a so-called ‘uplift’ charge on load billed per megawatt-hour,” he continued. “If an uplift charge is necessary, it should be allocated to the least price-responsive loads. If a nondiscriminatory uplift charge is required, it should be spread across the widest possible base of loads that cannot bypass or avoid the charge.”
Hogan said the “principal problem” PJM identified with virtual transactions is a “computational burden that would be only indirectly affected by uplift allocations and could be addressed through other means with fewer negative consequences for the broader market design, such as by continuation of bidding budgets that allowed flexibility in the choice of virtual transactions.”
Recommendations, FERC Action
In addition to calling for an end to uplift charges, Hogan identified two other recommendations that differed from PJM’s:
Analyze the impact of virtual trading on unit-commitment decisions rather than assume differences between day-ahead and real-time conditions. “The PJM analysis refers to the importance of commitment decisions throughout the report but does no explicit analysis of those commitment decisions,” Hogan said. “The absence of the analysis undermines the PJM conclusions.”
Increase the number of locations at which virtual transactions may be placed.
FERC is long overdue to issue a ruling in its Section 206 inquiry. In opening the docket, FERC said it would rule within five months after it receives comments following a technical conference. The conference was held in January 2015 with follow-up comments due at the end of May.
However, the commission may be delaying action to see what emerges from PJM’s stakeholder process. The task force, which has been discussing the issues since July 2013, is scheduled to meet next on Sept. 1.
Environmental groups and others have asked the D.C. Circuit Court of Appeals to review FERC’s approval of PJM’s Capacity Performance model, saying the rules unfairly limit participation by renewables and demand response.
The new rules, created in response to the high number of forced outages during 2014’s polar vortex, aim to improve reliability by increasing the rewards for capacity resources that provide power when called on during times of high demand and increasing the penalties on those that fail to do so.
One of the challenges was submitted by the Natural Resources Defense Council, the Sierra Club, Union of Concerned Scientists and Earthjustice. Another was filed by the Advanced Energy Management Alliance, a trade association representing DR providers and their customers. American Municipal Power, an organization of municipal utilities, filed a third challenge July 6. The court consolidated those petitions.
Then on July 8, another challenge was submitted by American Public Power Association, National Rural Electric Cooperative Association, New Jersey Board of Public Utilities and the Public Power Association of New Jersey.
The environmentalists said that ruling, and FERC’s June 2015 order approving CP, conflict with the Federal Power Act (ER15-623, EL15-41, EL15-29).
“In addition, the new rules will funnel billions of dollars from electricity consumers to fossil and nuclear power plants while severely limiting clean energy participation in PJM’s capacity market,” said Jennifer Chen, an attorney for the Sustainable FERC Project, which is housed within the NRDC.
Competition from more and diverse resources reduces energy prices, Chen wrote in a blog post. The new model will limit the participation of clean energy sources such as wind, solar and DR, driving up costs, she said.
While the new rules allow summer and winter resources to aggregate a single capacity offer, no aggregate offers were submitted in the first Base Residual Auction with CP for delivery year 2018/19.
In the second auction under the new rules in May, only 6% of cleared DR resources qualified as CP, compared with 9% of wind and one-tenth of 1% of solar.
Base capacity resources, which are not held to CP standards, will be eliminated for the delivery year 2020/21.
In addition to increasing prices, the CP rules will “punish the same clean energy and demand response resources that helped keep the lights on during the extreme weather events of the last couple of years,” said Casey Roberts, staff attorney with the Sierra Club.
The impact of CP on capacity prices is not yet clear, however.
PJM’s first auction under CP last August saw prices rise 37% to $165/MW-day in most of the RTO, while the ComEd and Eastern MAAC regions cleared at more than $200.
But in the second auction, prices dropped to $100/MW-day in most of the RTO. Eastern MAAC fell to $120 while the ComEd zone cleared at $203. (See PJM Capacity Prices Fall Sharply.)
The subject of accommodating seasonal resources in the new model has been the subject of much debate.
At PJM’s annual meeting in May, state consumer advocates urged the Board of Managers to change the new rules to allow more participation by DR, energy efficiency and solar resources by procuring capacity seasonally. (See Consumer Advocates, Enviros Press PJM on Seasonal Capacity.)
Also in May, the Markets and Reliability Committee approved a charter for the new Seasonal Capacity Resource Senior Task Force. The motion passed with 68% of a sector-weighted vote, with some members voicing concern over its potential to undermine the CP product. (See MRC Approves Charter for Seasonal Capacity Effort.)
NextEra Energy is said to have offered Energy Future Holdings a combination of cash and debt for its Oncor subsidiary and leads the list of potential suitors for Texas’ largest transmission and distribution utility, according to a Bloombergreport.
Bloomberg quoted “people familiar with the talks” as saying Florida-based NextEra, which had made an unsuccessful bid last year for Oncor, “is closest to reaching a deal” among at least seven companies that have expressed an interest. The sources said an agreement could be reach by early July.
Bloomberg also said Warren Buffet’s Berkshire Hathaway and Edison International are among the other companies eyeing Oncor. Spokespersons for the various companies either declined comment or didn’t respond to requests for comment last week.
Dallas-based Hunt Consolidated in May withdrew its year-long application to buy Oncor but filed a lawsuit last month against the Public Utility Commission of Texas asking it to reverse a March order that set conditions on the deal. (See Hunt Reopens Oncor Bid in Lawsuit Against PUCT.)
Bloomberg’s sources said NextEra’s proposal is higher than the Hunt bid.
Oncor is EFH’s regulated subsidiary and said to be valued at $17 billion to $18 billion. EFH, which has been working to emerge from bankruptcy for two years, has a July 8 deadline to file an amended reorganization plan.
Whoever comes up with a new deal for Oncor would have to seek approval from the Delaware bankruptcy court hearing EFH’s case and the Texas PUC, among others.
NextEra is also involved in an attempted acquisition of Hawaiian Electric, a deal announced in December 2014 and valued at $4.3 billion. A state representative told a Hawaii TV station last week that NextEra’s pursuit of Oncor does raise some concerns.
“Clearly some of the financial [analysts] have speculated that if the company is going to be investing there significantly, that it may change the kind of investment and the plans they make out here,” Rep. Chris Lee said.
Coal’s share of SPP’s energy production continues to slide in the face of low gas prices and increased wind generation, according to the RTO’s latest State of the Market report.
The SPP Market Monitoring Unit’s spring report says coal-fired generation accounted for just 41% of the RTO’s energy production between March and May, its lowest percentage ever and a stunning 31% drop from spring 2014, when coal resources provided 59% of the RTO’s energy. Coal generation accounted for more than 65% of total generation in 2007, SPP’s first year as an organized market.
Coal’s diminished market share is largely attributed to the continuing drop in gas prices. Prices at the Panhandle Hub have dropped 64% since spring 2014, from $4.66/MMBtu to $1.68/MMBtu, and 32% since spring 2015, when the price was $2.46/MMBtu.
That contributed to average real-time LMPs of $17.37/MWh (compared to $34.72/MWh in 2014) and day-ahead LMPs of $17.07/MWh (versus $37.03/MWh in 2014). The Monitor said it is the first time since the Integrated Marketplace opened in March 2014 that day-ahead prices were below real-time.
Coal-fired resources were also backed down by the ready availability of wind energy, which accounted for 21.5% of all energy produced this spring, compared to 15% last year. SPP’s wind penetration has risen from the 30% range to a new high of 49.17% of total generation this year.
The Monitor also said cleared virtual transactions are approaching the levels of other RTOs, at about 10% of reported load. It said gross virtual profits for the Integrated Marketplace’s most recent 12 months totaled nearly $78 million, with gross virtual losses totaling nearly $58 million.
Virtual trades have shown net profits every month since the Integrated Marketplace began, with the exception of May 2014.
The Public Utility Commission of Texas said it will invite stakeholder comments as it takes a cautious approach to Lubbock Power & Light’s planned integration into the ERCOT grid.
“I think this is an incredibly complicated situation. I’m not sure it’s even clear how … we evaluate it,” PUC Chair Donna Nelson said during the commission’s June 29 open meeting. “I do have concerns about the FERC jurisdiction aspect of it … I’m concerned about [Lubbock] having generation that flows outside of Texas.”
“We need to be mindful of the precedent it sets,” Commissioner Ken Anderson agreed. “I believe there might be other entities in Texas — other regions, groups — that look with envy on ERCOT, and for good reason.”
LP&L announced last September it planned to disconnect from SPP and join ERCOT by 2019. Xcel Energy, whose Southwestern Public Service subsidiary serves LP&L’s load, asked FERC in May for an $88.7 million interconnection switching fee should the municipal utility proceed with its plan. (See Xcel Asks for $88.7M Fee for Lubbock Switch to ERCOT.)
Nelson, Anderson and Commissioner Brandy Marty Marquez all said they would like to see LP&L’s integration turned into two separate cases, one involving the move from SPP’s grid to ERCOT’s, and the other involving a cost-benefit analysis of the transfer on ratepayers. Nelson said she would issue a memo outlining the parameters on further studies before the PUC’s next open meeting July 20 (Docket No. 45633).
An ERCOT study completed in June indicated it would cost $364 million and take 141 miles of new 345-kV right of way to incorporate LP&L into ERCOT. (See “LP&L Integration Could Unlock More Panhandle Wind Energy,” ERCOT Board of Directors Briefs.)
The City of Lubbock has told the PUC it would prepare an impact analysis of the LP&L load that would migrate to ERCOT, using the Texas grid operator’s report as a starting point. It said its report will be “holistically framed around three key areas of study”: the effects on existing ERCOT stakeholders, on existing SPP stakeholders and on Lubbock customers.
“I think it’s appropriate to allow people to file responses to the ERCOT filing and to what Lubbock has filed,” Nelson said. “We have to make sure ERCOT [and] the ratepayers of Texas are treated fairly. I think SPP and the ratepayers in SPP should be treated fairly too.”
Marquez said one of her concerns is “what happens to the communities that are left behind, and what kind of rates do they absorb?”
Anderson said he wants more “clarity” from ERCOT on the available integration options, saying the ISO’s preferred option “seems to be predicated on the assumption that most of what they are recommending will be needed anyway.”
“If two years later we have to go back and approve what ERCOT recommended,” Anderson said, “by then, we may have way overpaid.”
The municipality has said it faces time constraints in meeting its 2019 timeline, but the commissioners said that wasn’t their primary concern.
“I’m not going to take on that responsibility,” Nelson said. “We need to avoid putting ourselves in a position where we’re there to rescue the day if people have put themselves in that position.”
“These are Texans, but these are Texans that didn’t want us,” Marquez said. The SPS region opted out of Texas’ competitive market before it opened in 2002.
Municipal utilities Austin Energy and CPS Energy of San Antonio, both ERCOT members, also opted out of competition.
The Public Utilities Commission of Ohio staff has proposed a new rider for FirstEnergy that would allow the recovery of $131 million annually from ratepayers for three to five years in order to maintain the company’s investment-grade credit rating.
“Staff believes the long-term financial health of FE will have benefits for the Ohio regulated distribution facilities, as well as the state of Ohio in general,” PUCO’s Joseph Buckley testified Wednesday (Case No. 14-1297-EL-SSO).
FirstEnergy’s Davis Besse Power Plant Source: Wikimedia
Buckley cited Moody’s Jan. 20 credit opinion saying that the company could receive a rating downgrade without an increase in revenues allowing it to generate cash flow from operations equal to at least 14% of its debt. He said staff believes that three years is enough time for FirstEnergy to address its finances, and that it could request an extension of the rider if necessary.
The Distribution Modernization Rider would require FirstEnergy to maintain its corporate headquarters and most of its operations in Akron or forego the credit. The agreement also would be terminated if the company or its subsidiaries were to undergo a change in ownership.
Critics of FirstEnergy’s attempts to win subsidies from Ohio regulators objected.
“While the staff frame their proposal in terms of grid modernization, the apparent absence of any requirement that FirstEnergy invest the money on modernizing the grid means that this new proposal is effectively just another corporate bailout,” Earthjustice, representing the Sierra Club, said in a statement.
Dick Munson of Environmental Defense Fund called it “an unnecessary subsidy.”
PUCO staff said last week that modified proposal should be rejected in favor of the recommended rider.
Doug Colafella, a spokesman for FirstEnergy, said Friday, “The filing of staff’s testimony is another step in the regulatory process. We will continue to work with the commission and other parties to achieve an outcome that will protect our customers and communities.”
On Thursday, FERC Chairman Norman Bay responded to a letter from U.S. Sen. Joseph Manchin (D-W.Va.) explaining the commission’s role in the dispute (EL16-33, EL16-34). Manchin, a staunch supporter of his state’s coal mining industry, had asked FERC on April 20 to “allow [Ohio’s] prudent action to stand.”
