FERC has accepted SPP’s Tariff revisions to clarify and consolidate the RTO’s out-of-merit energy (OOME) processes, scotching objections by several wind energy companies.
The order is effective as of Aug. 10, 2016 (ER16-1912). In a Nov. 9 compliance filing, SPP revised the new OOME definition to clarify the term’s scope, saying it would allow the RTO to issue an out-of-merit instruction to address either an emergency condition or a reliability issue that had not yet risen to an emergency condition.
In June, the RTO filed proposed revisions to clarify OOME dispatch instructions to dispatchable variable energy resources (DVERs) and non-dispatchable variable energy resources (NDVERs). It also said it was improving the Tariff terminology related to operational dispatch instructions by consolidating terms with “no necessary functional distinction,” saying the revisions would mitigate overlap and potentially confusing or conflicting requirements with the NERC communication reliability standards’ (COM) use of “operating instruction.”
The commission accepted SPP’s proposed revisions, noting the Tariff “uses a variety of terms to describe out-of-merit and manual dispatch instructions and, at times, erroneously refers to out-of-merit and manual dispatch instructions in the commitment context.” It said the proposed Tariff revisions “should reduce possible ambiguity within the Tariff and potential conflicts with NERC terminology.”
| Theodore Scott, Creative Commons
SPP’s filing was opposed by EDF Renewable Energy, E.ON Climate & Renewables North America and Invenergy, known collectively as the Wind Generation Group.
The Wind Generation Group said the revisions were not needed to avoid confusion or comply with NERC COM-002-4. It also said the proposal would change the OOME term’s scope. The group argued that SPP’s proposal will result in “confusion, financial harm and opportunities for increased litigation,” as well as “a loss of information that will negatively affect wind developers.”
The group also said that in SPP’s Integrated Marketplace, variable wind energy resources are bifurcated into DVERs and NDVERs, noting that the RTO issues automated dispatch instructions through its security-constrained economic dispatch (SCED) for DVERs and issues OOME instructions as needed. The group said “NDVERs are incapable of responding to automated dispatch directives and are thus only subject to manual dispatch instructions.” Manual instructions are issued “only when there is a reliability need that remains after automated SCED dispatch occurs,” it added.
FERC disagreed, saying its review of SPP’s current Tariff “confirms that SPP has used the term out-of-merit energy in the emergency and reliability contexts; thus, the Tariff already allows for out-of-merit energy instructions arising from manual or automated means.” It said the proposed Tariff revisions are not intended to change SPP’s existing practice for OOME instructions, and noted SPP said the processes “will continue to include both manual and automated SCED components.”
The commission dismissed the wind group’s concerns that its members will lose the ability to distinguish between the reasons for manual curtailments (economic, reliability or emergency in nature). It said SPP has confirmed it issues OOME instructions “to respond to reliability issues only.”
FERC said if SPP develops communication protocols outside of the Tariff that wind developers find problematic, the wind generators can raise those issues in the RTO’s stakeholder process. The commission found the wind group’s concerns regarding the differences between NDVERs and DVERs to be outside the proceeding’s scope.
WASHINGTON — The U.S. just elected a president who has said he will tear up the Paris Agreement, block the Obama administration’s Clean Power Plan, “save the coal industry” and loosen the regulatory reins on the energy industry.
Like the entire country, the electric industry is still trying to get its head around how President-elect Donald Trump will convert his rhetoric into policy.
Trump offered little detail on the energy policies he would pursue beyond vowing to revoke EPA’s climate rule and supporting Republican calls to ease restrictions on oil and gas exploration and fuel pipelines.
There were some obvious winners and losers as a result of the Republicans’ capture of the White House and their continued control of the House and Senate, however.
In addition to the Clean Power Plan, other losers are likely FERC Chairman Norman Bay, Commissioner Colette Honorable and the Department of Energy.
One other likelihood, based on the defiant responses from environmental groups Wednesday: protests and litigation over Trump attempts to roll back environmental rules.
Edison Electric Institute President Tom Kuhn issued an anodyne statement Wednesday that nonetheless betrayed the industry’s uncertainty about what a Trump administration means to utilities. The trade group said it is looking forward to working with the new administration to “navigate the many challenges and opportunities facing our industry.”
“We want to ensure that we are communicating with the incoming administration, policymakers and key stakeholders about the investments our members are making and the projects they are undertaking to benefit their customers and our energy future.”
Reshuffle at FERC
Bay, a Democrat, will presumably lose the FERC chairmanship, and Commissioner Colette Honorable, whose term expires next June, will likely be replaced by a Republican.
Although the commission has not traditionally been marked by partisan divisions, the president gets to appoint members of his party to three of the five seats and pick the chairmanship. Since Republicans Philip Moeller and Tony Clark left, the five-member panel has been all Democrats: Honorable, Bay (whose term expires in June 2018) and Cheryl LaFleur (June 2019).
Donald Trump will get to fill two Republican vacancies on FERC and replace Democrat Colette Honorable when her term expires in June 2017. Chairman Norman Bay, a Democrat, will have to hand the gavel to one of the three Republican commissioners. | FERC
Because Republicans maintained their control of the Senate, Sen. Lisa Murkowski (Alaska) will remain chair of the Energy and Natural Resources Committee, the gatekeeper for FERC nominees.
A subdued Bay, who made an appearance at FERC’s technical conference on energy storage Wednesday, declined to comment when asked by RTO Insider for his thoughts on his future.
Paris Agreement, Clean Power Plan
Neither the U.S. participation in the Paris Agreement nor the CPP were approved by Congress, so President Obama’s target of reducing U.S. greenhouse emissions by up to 30% by 2025 is clearly in peril.
Trump — who has called climate change a hoax created “by the Chinese in order to make U.S. manufacturing noncompetitive” — has promised to “cancel” the agreement, which aims to limit global warming to 1.5 degrees Celsius above preindustrial levels and went into effect Nov. 4. Trump also promised to stop U.S. payments to the U.N.’s Green Climate Fund.
According to an analysis by Climate Central, an organization of scientists and journalists whose mission is to communicate the effects of climate change, Trump would have three ways of withdrawing the U.S. from the Paris Agreement. The first is to invoke an article to withdraw from the agreement a year after it takes effect by declaring the abandonment of a 1992 treaty — the United Nations Framework Convention on Climate Change, on which it is partly built.
Another section of the agreement allows a signatory to withdraw three years after it is signed, with an additional one-year waiting period after that.
Or, in what many see is the most likely scenario, he could just abandon any of the voluntary rules and incentives to reduce emissions.
Most in the industry and regulatory bodies overseeing it believe the goals set by the agreement would not be obtainable without slashing greenhouse gas emissions from electric utilities’ use of coal.
Trump will appoint a new EPA administrator. He also could order the Justice Department to stop defending the Clean Power Plan in court should the D.C. Circuit Court of Appeals overturn it — preventing the possibility of the order being reversed by the Supreme Court (for which Trump will nominate a replacement for the late Justice Antonin Scalia). (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)
If the rule is upheld by the D.C. Circuit, Trump’s EPA would need to establish another rule revoking the CPP.
“It’s virtually certain that the Clean Power Plan will be revoked. The question is how,” Jeff Holmstead, a partner at the law firm Bracewell and a former assistant administrator at the EPA, speaking at a post-election conference call.
“I’m quite confident that they do intend to make good on that promise. The question is how they will do it — and will they do it in a way that will withstand legal scrutiny,” he said. “Any action to revoke the plan will also be litigated, just like the plan itself.”
Congress attempted to kill the CPP last year through the Congressional Review Act, which allows Congress to disapprove regulations that have an economic impact of more than $100 million. Those disapprovals, however, must be signed by the president or his veto overridden by a two-thirds majority. President Obama vetoed Congress’ CRA rejection of the EPA rule last December.
The GOP will retain control of the Senate by 51-48, with a December runoff election in Louisiana. Republicans will control the House by 239-193, with three races (two in California and one in Louisiana) still undecided.
Environmental Groups Vow Resistance
The reaction from environmental organizations was a mix of shock and defiance.
350.org came out of the blocks with a message calling Trump’s election “a disaster.”
“But it cannot be the end of the international climate process. We’re not giving up the fight and neither should the international community,” the group said in a statement attributed to Executive Director May Boeve. “In the United States, the climate movement will put everything on the line to protect the progress we’ve made and continue to push for bold action. Our work becomes much harder now, but it’s not impossible, and we refuse to give up hope.”
The Environmental Defense Fund’s political arm, EDF Action, said in a statement Wednesday that Trump’s positions are “in complete contradiction to the realities of climate science. Mr. Trump should listen to the scientific experts on climate change and recognize that a clean energy transition is already underway. America’s economic future depends on embracing this trend,” EDF said.
The Sierra Club called it “a deeply disappointing day for the United States, and the world.”
“For people all over the country, the pain, anger and fear at the prospect of a Trump presidency are very real,” Executive Director Michael Brune said in a statement that was nearly a call to man the barricades.
“What we know is that it would be extraordinarily difficult for Trump to remove the U.S. from the Paris Agreement,” Brune said. “His position is already causing international blowback abroad, and in very pointed ways that are in some respects unprecedented. If Trump does try to undermine climate action, he will run headlong into an organized mass of people who will fight him in the courts, in the states, in the marketplace and in the streets.”
Earthjustice, a nonprofit environmental law organization, said Trump “might be the most anti-environment president in history” and suggested that Trump’s EPA may face court fights from environmentalists akin to those the Obama administration had to fend off from industry and coal states.
“He has publicly stated that he does not believe in the overwhelming amount of evidence supporting climate change and his record on all matters involving justice, equity and human rights is troubling,” Earthjustice President Trip Van Noppen said in a statement. “Therefore, Earthjustice will be working overtime in the courts to hold President-elect Trump and his administration accountable under our nation’s laws, which protect Americans’ right to a clean and healthy environment.”
Wind
Trump has called wind turbines expensive eyesores and decried their impact on bird populations.
Nevertheless, the American Wind Energy Association proclaimed itself “ready to work with President-elect Donald Trump and his administration to assure that wind power continues to be a vibrant part of the U.S. economy.”
“An unstoppable shift to a cleaner energy economy is underway, and the fundamentals of wind energy in America are strong,” AWEA said in a statement, in which it noted that the wind industry has 88,000 jobs, “a quarter of them made-in-the-USA manufacturing jobs.”
“In his victory speech early this morning, the President-elect said, ‘We’re going to rebuild our infrastructure, which will become, by the way, second to none. And we will put millions of our people to work as we rebuild it.’ Wind power is some of the best infrastructure America has ever built and we are on track to doubling it from today’s levels by 2020.”
Coal
In his campaign visits to coal country, Trump promised to put miners back to work. Regardless of what happens to the CPP, however, it’s hard to imagine any utility board of directors authorizing construction of a new coal-fired plant when existing plants are having trouble competing with natural gas.
“Forget the Clean Power Plan. You cannot build a coal plant that meets existing regulation today that can compete with $5 gas,” Charles Patton, president of Charleston-based Appalachian Power, told a state energy conference earlier this year, as reported by American Public Media’s Marketplace. “It just cannot happen.”
The Labor Department reported coal mining jobs have declined from about 84,600 in March 2009, after Obama took office, to 56,700 in March. At least six publicly traded U.S. coal companies have entered Chapter 11 bankruptcy proceedings since 2015.
Goldman Sachs issued a report in February saying that declining demand for thermal coal is “irreversible.”
Trump
It followed a report last year that concluded “The industry does not require new investment given the ability of existing assets to satisfy flat demand, so prices will remain under pressure as the deflationary cycle continues.”
The investment bank’s conclusion contradicts the International Energy Agency, which predicted last year that coal consumption would rise by about 2.1% annually through 2019.
“This is a great day for America,” Murray Energy CEO Robert Murray said in a statement. “I have personally spent time with Mr. Trump, and I know that he will surround himself with the very best people to fix the many problems facing our country. Indeed, Mr. Trump will finally implement a national energy policy whereby all energy sources will compete on a level playing field.”
One of those people could be Myron Ebell, a climate skeptic and executive at the Competitive Enterprise Institute. Trump has vowed to take away EPA’s regulatory powers and make it an advisory council. Ebell has been running the EPA working group for the Trump transition team and is seen as a contender for the EPA administrator post.
Trump has also said he wants to open federal lands to oil and natural gas drilling and coal mining. Forrest Lucas, cofounder of Lucas Oil, has been mentioned as a candidate for secretary of the Interior Department.
Nuclear Power
Despite Trump’s opposition to the CPP — which could provide support for the carbon-free generation of nuclear power — the Nuclear Energy Institute said his election is good news for the industry.
“Despite a tepid economy, the Department of Energy forecasts a 23% growth in electricity demand by 2040, the equivalent of more than 200 large power plants,” said Maria Korsnick, NEI’s incoming CEO. “Couple this with Mr. Trump’s all-in approach to energy and it’s apparent that the low-carbon, reliable electricity that nuclear energy facilities provide must continue to be a key part of the nation’s energy portfolio.
“Throughout the presidential campaign, nuclear energy was a bipartisan issue and one of the few areas of general agreement between the candidates. Additionally, public polling shows that the importance of nuclear energy to this nation’s energy mix is one thing voters could agree on, irrespective of their candidate preference.”
Department of Energy
Trump’s appointee to head the Department of Energy is sure to be less enamored than the Obama administration in investments in renewables and energy efficiency.
“Off the bat, it’s likely to be a fairly antagonistic transition given the overall dynamics in the election and given his stances on energy,” Teryn Norris, a former special adviser to the department, told Greentech Media. “Trump has repeatedly expressed disdain for renewables, and seems likely to gut those programs in” the Office of Energy Efficiency and Renewable Energy.
VALLEY FORGE, Pa. — Members endorsed PJM’s 2016/17 winter weekly reserve targets, but not without first questioning if they could be reduced.
Part of PJM’s reserve requirement study, the winter targets are used by the Operations Department to coordinate generator maintenance outages in the cold months. (See “IRM Study Approved but Criticized for Lack of Winter Analysis,” PJM Markets and Reliability and Members Committees Briefs.)
Stakeholders asked why the winter loss-of-load expectation needs to be near zero given that few zones within PJM are winter peaking. PJM’s Patricio Rocha-Garrido explained to the Operating Committee that the annual LOLE target of 0.1 — one day every 10 years — is cumulative throughout the year, so maintaining a near-zero level in the winter provides more leeway in the summer when load is higher.
“If we were to allow for a large risk in the winter, we would need a lower risk in the summer, which would require a larger reserve margin,” Rocha-Garrido said.
The targets will leave PJM with between 24 and 30% of its available reserves between December and February.
PJM Considering Changes to System Operations Report
After walking through the operations report for October, staff outlined ideas for redesigning the report to address additional topics. Among the subjects being considered for inclusion are topology changes, weather trends and seasonal comparisons.
Topology changes considered in the Operations Assessment Task Force’s winter 2016/17 preparedness study. | PJM
Stakeholders requested PJM increase its focus on reducing load-forecasting errors by providing more granularity about what factors are driving errors, such as how many and how often generating units are brought online in response to specific reliability contingencies. Staff said their ability to release information on specific units is limited because of the need to protect market-sensitive data.
“We’re talking about that internally,” PJM’s Joe Ciabattoni said.
Committee Endorsements and Recommendations
The OC made the following endorsements without objections or abstentions:
The 2017 day-ahead scheduling reserve requirement, which will be incorporated into Manual 13.
Updates to the TO/TOP matrix, an index between the PJM manuals and NERC reliability standards that specifies assigned and shared tasks for PJM and transmission owners. The changes, which the OC recommended be approved by the Transmission Owners Agreement-Administrative Committee, add new standards and delete inactive ones.
‘Cover to Cover’ Manual 13 Changes Better Reflect Reserve Requirements
PJM’s Chris Pilong presented a first read of extensive changes to Manual 13: Emergency Operations, on which the RTO will seek endorsement at the December committee meeting. Many of the changes are to clean up and streamline language regarding capacity and transmission emergency procedures.
“There are a lot of changes in here,” he said, but he acknowledged that many aren’t substantive. The biggest changes were the inclusion of more accurate Mid-Atlantic Dominion (MAD) reserve requirements. “The obligation can be met with non-MAD resources … if they’re deliverable,” he said.
Manual 14D Changes to Facilitate Periodic Surveys
PJM will be seeking endorsement at the December committee meeting on changes to Manual 14D: Generator Operational Requirements. The changes include the renaming of the section on fuel limitation reporting — now fuel and emissions reporting — a new section on periodic reporting and updates to the provisions on seasonal reporting. PJM’s Augustine Caven said the intention is to begin doing generating-unit surveys more often. “We definitely utilize [the survey] pretty heavily for operations purposes as we head into the winter,” he said.
Audit Goes Well
NERC and ReliabilityFirst Corp.’s planning and operations audit, which reviewed PJM’s compliance with 21 reliability standards and 48 requirements, concluded with no violations, two areas of concern and nine recommendations. There also were two open enforcement actions, PJM’s Srinivas Kappagantula said.
PJM is awaiting a draft audit report and will let stakeholders know about any changes it decides to make.
Kappagantula commended the transmission owners for their assistance in the process. “I wanted to think the TOs because we’ve reached out to you … for some of the data-sampling evidence that we requested,” he said. “That kind of reduced the onsite burden for us and the audit team … because they didn’t have to go through a bunch of documents onsite.”
OATF Study Finds No Major Concerns
While several major generation additions are coming online this winter, the Operations Assessment Task Force’s preparedness study found no significant concerns from its base case and N-1 analyses.
It found that off-cost generation redispatch and switching will be required to control local thermal or voltage violations in some areas. Networked transmission voltage violations were controlled by capacitors and all other voltage violations were caused by radial load, PJM officials said.
Stakeholders were concerned, however, that the study used hypothetical values in its calculations rather than real-world results.
Calpine’s David “Scarp” Scarpignato noted that units with dual-fuel capabilities weren’t differentiated from those without for pipeline failure contingencies. “This thing has a point to it, and I think you [should] set up the base case as accurate as possible,” he said.
PPL improved its third-quarter performance by 20%, reporting $473 million($0.69/share) in earnings, compared to $393 million ($0.58/share) for the same period last year. The company attributed the increase to higher rates for its Pennsylvania and U.K. operations and warm weather, which boosted demand.
PPL raised the bottom end of its 2016 earnings guidance by 5 cents to $2.30-$2.45/share based on slightly stronger-than-expected performance at its Pennsylvania and Kentucky utilities. The company, whose Pennsylvania utility benefited from a rate increase in January, intends to file rate hike requests in November for Kentucky Utilities and Louisville Gas and Electric.
With the exchange rate for the British pound falling in the wake of the U.K.’s decision to leave the European Union, PPL mitigated the financial impact on its U.K. operations by restriking its currency hedges.
“We remain confident in our ability to deliver on our long-term growth projections,” PPL CEO Bill Spence said during a conference call. “We expect to achieve 5% to 6% compound annual earnings growth from 2017 to 2020 and are targeting annual dividend growth of about 4% over the same period.”
Lagging Coal Units Drag down PSEG
Public Service Enterprise Group’s third-quarter earnings of $327 million ($0.64/share) were down 26% compared to the same period last year, when it reported $439 million ($0.87/share) in 2015. However, the company’s adjusted operating earnings of $444 million ($0.88/share) were up 10% year-over-year from $403 million ($0.80/share) in 2015.
The retirement of two coal-fired plants in New Jersey, a reduction in the value of its lease of two coal-fired plants in Illinois and lower hedges accounted for the difference, the company said.
“Net income was impacted by our decision to retire the Hudson and Mercer coal-fired generating stations in 2017,” said PSEG CEO Ralph Izzo.
Mercer Generating Station | PSEG
Warm summer weather staved off an even greater drop in the company’s performance, but it wasn’t enough to offset poor performance year-to-date thanks to unfavorably warm conditions during the winter. Izzo announced the company was shaving the top end of its 2016 guidance by 5 cents to $2.80-$2.95/share.
Its Public Service Electric and Gas subsidiary has reached a settlement with key parties for an extension of its existing landfill/brownfield solar program. The settlement provides for an investment of approximately $80 million to construct 33 MW of grid-connected solar generation over three years.
The PSEG Power generation subsidiary incurred $67 million ($0.13/share) in one-time charges related to the early retirement of the Hudson and Mercer generators.
Reduced energy hedges caused by lower fuel prices were partially offset by lower load-serving costs, but they still reduced net income by $0.02/share, the company reported.
The PSEG Enterprise/Other business group reported a net loss of $67 million ($0.13/share) after recalculating the residual values of its leases of two coal-fired plants in Illinois. The company recorded an after-tax impairment of $86 million on the leases “as a result of current and expected future market conditions.”
Unit Retirements, Tax Ruling Dampen Exelon’s Performance
Exelon’s third-quarter earnings fell 22% to $490 million ($0.53/share), down from $629 million ($0.69/share) in 2015. Adjusted earnings were up 11% year-over-year to $841 million ($0.91/share) from $757 million ($0.83/share).
While the company benefited from substantially better hedging and reduced nuclear decommissioning trust fund payments, those positives were outweighed by an unfavorable tax ruling, costs from the Pepco Holdings Inc. merger and plant retirements.
In September, the U.S. Tax Court ruled against the company in a $1.45 billion tax-shielding dispute with the Internal Revenue Service that stemmed from Exelon’s $4.8 billion sale in 1999 of six coal-fired plants in Illinois. The buyer, Edison Mission Energy, eventually sold four of the plants out of bankruptcy to NRG Energy, which leases two of them to PSEG.
While Exelon hasn’t decided whether to appeal the ruling, it is required to post a bond for the payment anyway. The company accounted for $199 million of the bill in the third quarter.
The quarter saw a shuffling of Exelon’s nuclear fleet as well, with the company announcing the early retirement of the Clinton and Quad Cities facilities and the purchase — pending regulatory approval — of Entergy’s James A. FitzPatrick station in New York.
Overall, earnings were bolstered by regulatory rate increases and favorable weather but partially offset by decreased capacity revenue, increased income taxes from a decrease in the domestic production activities deduction and increased nuclear decommissioning amortization, the company said.
Even with the write-downs, CEO Christopher Crane was bullish, announcing that the company was raising its 2016 guidance from $2.55/share to $2.75/share. The revision was based on improved performance of its Commonwealth Edison and recently acquired PHI utility subsidiaries.
Dominion Improves Finances
Dominion Resources had a good Monday last week, announcing both strong third-quarter results and the redistribution of its Questar acquisition that allowed the parent company to retire debt.
The company earned $690 million ($1.10/share) for the third quarter, compared with $593 million ($1/share) for the same period in 2015. It amounted to a 16% increase that the company partially attributed to favorable weather, lower capacity expenses, revenues from regulated growth projects and a lower tax rate. The performance was offset by share dilution and the absence of a farmout transaction, the assignment of part or all of a natural gas interest to a third party, which contributed $27 million to earnings a year earlier, the company said.
Dominion reported an operating earnings increase of 17% to $716 million ($1.14/share), compared to $611 million ($1.03/share) last year. The principal difference in the adjusted earnings was related to transaction costs associated with its acquisition in February of the pipeline company Questar.
The deal expanded Dominion’s service territory to Utah, where the natural gas deliverer has about 1 million customers. The sale closed in September, and by the end of October, Dominion had “dropped down” Questar to Dominion Midstream Partners, its master limited partnership, in a $1.7 billion deal that will allow the company to retire debt.
A federal appeals court has halted the award of clean energy contracts sought by three New England states while it considers an appeal filed by a New York-based clean energy developer (16-2946).
The 2nd U.S. Circuit Court of Appeals issued a temporary injunction on Nov. 2 in response to Allco Renewable Finance’s emergency petition.
Connecticut, Massachusetts and Rhode Island last month announced they would commence negotiations with developers of solar and wind projects totaling 460 MW. (See New England States Move Toward Renewables Contracts.)
Solar Energy Project Schematic | Allco
“Defendants-appellees are enjoined from awarding, entering into, executing or approving any wholesale electricity contracts in connection with the current energy solicitation during the pendency of this appeal,” the court said.
The three-judge panel expedited the appeal, set up a briefing schedule and ordered oral arguments in New York City as soon as the week of Dec. 5.
In its motion for the injunction, Allco tried to establish parallels with the U.S. Supreme Court ruling earlier this year in Hughes v. Talen, in which the court invalidated a contract between Maryland and a natural gas generator. Allco said the Maryland contract was “just like what Connecticut plans to do here.” (See Supreme Court Rejects MD Subsidy for CPV Plant.)
In the schedule set up by the states, negotiations are supposed to be completed by mid-January. The solicitation imposed a 20-MW minimum on the contracts that could be considered.
Allco said the 20-MW minimum is arbitrary and violates the Public Utility Regulatory Policies Act and the Federal Power Act. The company develops small solar qualifying facilities under PURPA.
The company filed a lawsuit against Connecticut officials after the multistate solicitation was announced last year. (See Allco Challenges New England’s Renewable Procurement Plan.) A U.S. District Court dismissed Allco’s challenge over the summer, saying the company lacked standing. The company appealed to the 2nd Circuit and then filed its emergency motion last month as the states’ solicitation process was ending.
Edison International will continue upgrading its transmission and distribution networks to take advantage of recently enacted legislation requiring California to reduce greenhouse gas emissions to 40% below 1990 levels by 2030, company officials said during their third-quarter earnings call with analysts last week.
Through its primary utility subsidiary Southern California Edison, the company is seeking to become a “key enabler” of California’s goals by facilitating the adoption of rooftop solar, energy storage and electric vehicle charging, CEO Pedro Pizarro said.
| Edison International
“Grid modernization, which, by the [California Public Utilities Commission’s] estimate, will be an ongoing effort into the middle part of the next decade, is a very significant part of the needed solution” for reducing emissions, Pizarro said. Edison’s quarterly profit increased by 11.1% to $419 million partly on higher revenues stemming from a revenue escalation mechanism included in a rate case approved late last year.
Pizarro noted that state officials are turning their GHG reduction efforts from the power industry — accounting for about 20% of current emissions — to the transportation sector, which is responsible for more than a third.
“We believe the significant new efforts across all sectors of the economy will be needed and many of these efforts will require significant electrification of sectors that today rely on fossil fuels,” Pizarro said.
Edison anticipates about $4 billion in yearly capital spending and $2 billion in annual rate base growth next year and into “the foreseeable future,” with nearly all of the investment on the “wire side” of the business, according to CFO Maria Rigatti.
“We believe it has lower investment opportunity risk as compared to utilities with a high percentage of growth tied to generation investment,” Rigatti said.
Edison is seeking regulatory approval to roll $200 million of “early-stage” grid modernization into its 2016-2017 rates, but the company might have to delay that investment until 2018 if it does not receive a timely decision from the CPUC. The spending would focus on replacing aging infrastructure, adding new customer connections, upgrading information technology, maintaining SoCalEd’s generators and modernizing the utility’s distribution system to accommodate the growth of distributed energy resources.
The company’s $1.1 billion West of Devers transmission project — which will upgrade existing 220-kV lines to double-circuit lines — was approved by the CPUC in August but has been challenged on environmental grounds.
Edison has also proposed alternative designs — which require “significant re-engineering” — in the CPUC’s review of the company’s $600 million Mesa substation project, which would upgrade the existing facility in the western Los Angeles Basin from 220 kV to 500 kV.
“These permitting and approval challenges are increasingly typical of transmission planning and part of the process, although the need for these projects is not affected by the regulatory delays that impact initial timing,” Rigatti said.
Edison continues to engage with Mitsubishi Heavy Industries in arbitration over steam generator design flaws that forced the permanent closure of San Onofre nuclear generating station in 2013. Edison shares ownership of the plant with San Diego Gas and Electric.
In the event of a favorable outcome for the plant’s owners, SoCalEd will refund to its ratepayers 50% of any proceeds that exceed legal expenses, Pizarro said. The rest of the money would be used to pay down or reduce the short-term debt associated with the utility’s capital spending program.
Edison anticipates receiving a decision on the matter later this year or early next year.
ERCOT’s latest seasonal forecasts indicate the ISO will continue to have more than enough generation capacity to meet demand into next summer, continuing a recent pattern of rosy forecasts.
ERCOT Control Room | ERCOT
According to the winter Seasonal Assessment of Resource Adequacy (SARA), ERCOT expects to have almost 82,000 MW available December to February, more than enough to meet an anticipated winter peak of 58,000 MW. That would exceed the ISO’s winter peak record of 57,265 MW, set in February 2011.
The preliminary spring SARA (March-May) also projects nearly 82,000 MW of available capacity and a seasonal peak of 58,000 MW in May. The assessment takes into account the expected spring generation outages for routine maintenance; the final spring SARA report will be released in March.
Asked about the recent positive forecasts, ERCOT Senior Director of System Planning Warren Lasher said, “I believe we’re in a period right now where we have adequate resources. The emphasis here is proving that assessment back to consumers.”
“We’ve added resources, but we’ve also modified our load forecast methodology,” said Pete Warnken, ERCOT’s manager of resource adequacy. “I believe it’s a more accurate, more on-target forecast.”
Lasher and Warnken both cautioned that continued congestion in the Lower Rio Grande Valley, which resulted in conservation calls in early October, remains a subject of concern. The 524-MW Frontera combined cycle plant’s withdrawal from the ERCOT system Oct. 1 to dispatch into the Mexican market has complicated the task of meeting demand along the U.S.-Mexico border.
“Our current expectation is we won’t have a similar call for conservation,” Lasher said.
Weather is not expected to play a factor this winter. Senior Meteorologist Chris Coleman said Texas hasn’t seen an extremely cold day since Feb. 2, 2011, and its coldest month in recent history came in December 1989. Lasher warned a few very cold days could drive up demand during early morning and evening hours.
ERCOT serves about 24 million customers and 90% of Texas’ load. The ISO has added 600 MW of new capacity since the preliminary winter SARA was released Sept. 1, and an additional 800 MW are expected to be in operation by December. New natural gas, wind and solar resources are expected to provide another 1,700 MW of capacity for the spring.
VALLEY FORGE, Pa. — PJM has determined that it must keep a loop flow in place with NYISO when the Con Ed-PSEG “wheel” ends next year, but that by 2021 that “operational baseflow” will be reduced to zero.
Presenting at the Market Implementation, Operating and Planning committees last week, PJM staff explained that anything less than a 400-MW loop flow on the current system would “impact” system reliability and minimize transfer capability across the seam.
The baseflow is “allowing us the flexibility to operate the system until we get some experience operating without the wheel in place,” PJM’s Ken Seiler said.
Staff also said they don’t expect “widespread congestion impacts” outside of the northern New Jersey and southern New York area.
Dave Pratzon of GT Power Group asked that PJM provide an annual review to see if maintaining the 400-MW operational baseflow assumption was necessary for reliable, economic system operation.
At the Planning Committee meeting, Citigroup Energy’s Barry Trayers said NYISO has been explaining that the 400-MW loop is necessary to keep PSEG North’s territory from “voltage collapse” and asked if that was accurate.
“We’re going to have to circle back with New York,” PJM’s Paul McGlynn said. “We haven’t seen anything like that in our analyses.”
He said they would also check with PJM’s Operations Department to determine if they’re seeing “anything close to that.”
Manual Updates Endorsed
The Planning Committee endorsed updates to three manuals.
In Manual 21: Rules and Procedures for Determination of Generating Capability, an acceptance test is now required for newly constructed units for which a summer/winter verification test after the unit is in service previously was sufficient. “Not many people are doing this so what we have to do is go back and look at your verification tests,” PJM’s Jerry Bell said. “You have to do this before you can cap-mod your unit up,” he added, using the shorthand for a notice of a capacity modification.
In addition to an administrative cleanup, the changes add detail to the testing requirements, including an expanded section on capacity interconnection rights. It also adds rules for non-hydro storage and removes class average information for wind and solar resources that will instead be posted to the planning resource page on PJM’s website.
Manual 14B: PJM Region Transmission Planning Process is being amended to remove from the capacity import limit (CIL) procedure references to the Reliability Pricing Model, PJM’s capacity market design. Starting with the 2020/21 delivery year, the CIL will not be applied as part of the capacity process. Instead, the limits will be considered during interconnection studies for new transmission service requests, part of new study procedures approved in early 2016.
PJM’s Michael Herman explained how the CIL will be calculated and used to determine that the import capacity is sufficient to support PJM’s capacity benefit margin (CBM), the portion of the RTO’s emergency import capability that is deducted from total transfer capability to determine available transfer capability (ATC). CBM is reserved to import capacity assistance from external areas under emergency conditions.
Section G.11 states that the CIL “is used to confirm that import capability into the PJM system is sufficient to support the PJM [CBM] as well as confirmed long-term firm transmission service.”
American Municipal Power’s Ed Tatum questioned how “sufficient” is determined. McGlynn explained there is an annual study in accordance with NERC reliability standards. Stakeholders endorsed the intent of the manual changes but asked that that explanation be written into the revisions. Herman confirmed that they will be.
In Manual 14A: Generation and Transmission Interconnection Process, the word “interconnection” is being replaced with “new service” to ensure cost allocation will occur for all projects. The change addressed needs identified at special PC sessions regarding new service request cost allocation and study methods.
Too Soon to Include CO2 Pricing in Market Efficiency Analyses
PJM staff have decided not to incorporate CO2 prices into their analysis of market efficiency transmission projects, saying that accurately projecting the likely price depends heavily on how — or whether — states comply with EPA’s Clean Power Plan.
| PJM
“States have seven different compliance pathways and their choices will have very different impacts on resource entry and exit,” PJM said in a presentation.
“Right now, there’s not a clear driver that could be built into the market efficiency scenario,” PJM’s Muhsin Abdur-Rahman told the PC.
Load Voices Concern over Transmission Repair Costs
During a review of immediate-need projects, members of the Transmission Expansion Advisory Committee questioned the proposed solutions for the loss of the South Butler-Collingwood 345-kV line in American Electric Power’s transmission zone, which would result in a loss of more than 300 MW of load.
AEP Transmission Zone | PJM
The region, an industrial zone in which continued growth is expected, is partially served by local 69-kV lines built in the 1950s with wood poles and distribution-class cross arms. A wholesale distribution cooperative served by such 69-kV lines has experienced multiple forced and momentary outages recently, planners said.
One option, which was estimated to cost $76.5 million, would add a new 345-kV switching station near Steel Dynamics Inc. (SDI) in Butler, Ind., a tap of the Rob Park–Allen 345-kV line and the addition of about 17 miles of a double-circuit 345-kV line.
PJM recommended a second option, estimated to cost $108 million. It would add new 138-kV and 345/138-kV stations and reconstruct sections of the Butler-North Hicksville and Auburn-Butler 69-kV lines as 138-kV double-circuit lines. In addition, the 138-kV circuit between Dunton Lake and the SDI Wilmington substation would be reconductored.
When AMP’s Tatum asked why the project was needed immediately and could not be included in a competitive window, McGlynn explained that a data error had recently been found in the modeling, revealing that there is an overload on the line currently.
Tatum said AMP “has a problem moving forward with this.”
Carl Johnson of the PJM Public Power Coalition pointed out that this project is “exactly the kind of issue” that caused the formation of the Transmission Replacement Processes Senior Task Force. “You’re probably making the right choice, but … you couldn’t have handed us a better example,” he said.
Reimbursement through this process would distribute the costs throughout the RTO, despite the fact that part of project would replace aging infrastructure, which should stay with AEP, Johnson said.
“We’re seeing more and more examples of this,” he said.
Looking over all of the projects, Tatum commented that, “It looks like we have $520 million of projects that are immediate need. … I don’t know what we can do in the planning process to get out in front of that.”
“If we were all doing our jobs perfectly and properly, we wouldn’t have any immediate need projects,” McGlynn conceded.
Tatum then pointed out seven projects whose cost estimates had ballooned from $205 million originally to $372 million, about an 82% increase.
“We might need to do better than an 82% increase, and I’d like to see if PJM could help us with that,” he said. “I hope that as we move forward and continue enhancing our planning process and ability that our cost estimates might be a little bit more robust at the initiation of a project.”
SPP’s recent trend of sending market-to-market payments to MISO continued in September, but that trend figures to reverse itself in the months that follow.
SPP’s Gerardo Ugalde told the Seams Steering Committee on Wednesday that the RTO sent $1.66 million to MISO as a result of temporary and permanent flowgates with the ISO. It was the third straight month the M2M process has resulted in a payment from SPP to MISO.
| SPP
“We don’t foresee this showing up in November,” Ugalde said. “This seems to be a seasonal change, where the flows flip.”
Temporary flowgates resulted in 591 hours of binding M2M and $1.14 million in charges from SPP to MISO; permanent flowgates added another $517,000 in M2M charges to the RTO as a result of 441 hours binding.
SPP Interregional Coordinator Adam Bell reminded stakeholders of a Nov. 30 deadline to submit projects they would like to see included in a potential joint study with the ISO as part of the 2016 Coordinated System Plan. (See “SPP, MISO Shared Joint Study Needs List,” SPP Briefs.)
Bell said initial discussions have been held with MISO to use the targeted study as the “foundation” for a “much broader study” next year. He said progress has been slow in developing coordinated system plans with both the ISO and Missouri-based Associated Electric Cooperative Inc.
CenterPoint Energy continues to focus on its gas business even as its regulated electric business contributed to a strong third-quarter earnings report.
The Houston-based company, which owns electric transmission and distribution and natural gas distribution, sales and services subsidiaries, on Friday reported a third-quarter profit of $179 million ($0.41/share), beating a Zacks Investment Research consensus of $0.37/share.
| CenterPoint Energy
It was a marked reversal from the same period last year, when CenterPoint reported a $391 million loss after a taking an $862 million impairment charge due to its investment in struggling Enable Midstream Partners.
CenterPoint’s revenues for the quarter rose 16% to $1.9 billion, including $908 million from its electric transmission and distribution segment, an almost 10% increase over a year earlier. The company attributed the rise to customer growth and higher rates.
Earlier last week, CenterPoint announced its CenterPoint Energy Services had reached an agreement to acquire Atmos Energy Marketing for $40 million. Atmos, which manages assets for utilities, power plants and local distribution companies, will add six states to the 26 in which CenterPoint Energy Services already markets its energy packages.
“This deal will allow us to grow our customer base and revenues while maintaining a low operating model and a cost-effective organization,” Joe McGoldrick, president of CenterPoint’s gas division, said during a conference call with analysts Friday. “This deal will increase our scale, geographic reach and expand our capabilities.”
CenterPoint is also continuing to evaluate “strategic alternatives” for its Midstream partnership with Oklahoma-based OGE Energy, including a sale or spinoff, to “reduce exposure to commodity price influences,” CEO Scott Prochazka said.
CFO Bill Rogers told analysts the company is continuing its discussions with interested parties. If no deal is reached by mid-January, CenterPoint will be required to submit a right-of-first-offer to OGE — allowing OGE to buy out CenterPoint’s interest — before continuing discussions with other prospects, Rogers said. (See CenterPoint Abandons REIT Plan; Offers Stake in Gas Partnership to OGE.)
