PJM’s regulation market is purchasing too much from fast-responding “RegD” resources, negatively affecting regulation and reliability, at the same time the RTO is incorrectly compensating those providers, the Independent Market Monitor said in a report presented last week to the Operating Committee.
Howard Haas of Monitoring Analytics said the root of the problem is an incorrectly defined marginal benefit factor that describes the relationship between RegD and traditional RegA resources.
While the MBF should be indicating when there is a diminishing return on the use of either resource, it has resulted in the over-procurement of RegD. In addition, it has led RegD resources to be alternately overpaid and underpaid. On average, Haas said, RegD resources have been undercompensated 46% from October 2012 through March using the current method.
“We never seem to be paying it the right amount,” Haas said. “It’s sending a strange signal to the market.”
PJM operators already had observed decreased market optimization during times when a large percentage of RegD is on the system. It provides more than 42% of response on average, shooting up as high as 70% during some events.
Last week, PJM presented the OC with a problem statement and issue charge to investigate the issue. The IMM wants to add to the inquiry an investigation into how the MBF is being defined and applied.
“If we follow it through, we’re going to correct more than one issue,” Haas said.
However, stakeholders agreed that the problem statement had been so substantially broadened since it was initially proposed that it was not ready for a vote. (See “Too Much of a Good Thing? PJM Concerned Fast Response Regulation Crowding Out Traditional Resources”, PJM Operating Committee Briefs.)
Instead, it will be reworked in a series of special OC meetings.
ISO-NE said a power plant owner facing millions in what it says are mistaken capacity charges had plenty of time to correct the record, and that amending auction results after the fact would undermine the market.
Canal Generating Plant
GenOn Energy Management, a unit of NRG Energy, asked the Federal Energy Regulatory Commission last month for relief from what it called an “anomalous, illogical and patently unfair circumstance.”
GenOn said ISO-NE credited its Canal 2 generator in Sandwich, Mass., with capacity of only 303 MW — rather than the plant’s actual 556.5-MW output — in the March annual reconfiguration auction (ARA) for the 2015-2016 capacity commitment period that begins June 1. (See ISO-NE Error Could Cost GenOn Millions.)
GenOn said the RTO mistakenly underestimated the plant’s capacity and then submitted a demand bid on GenOn’s behalf for the difference, forcing the company “to buy out of a capacity supply obligation that Canal 2 is fully capable of fulfilling.”
In an answer, ISO-NE said it was GenOn’s responsibility to correct the capacity values the RTO posted in October in preparation for the auction and that granting its request would set a dangerous precedent (EL15-57).
“The ISO is not in a position to discern the soundness of, or reasoning behind, the business-related actions (or inactions) of active and sophisticated market participants like GEM, much less to prevent them from making costly mistakes,” ISO-NE wrote.
“Granting the requested relief would undermine important principles of auction finality, eroding certainty and confidence in the markets and setting a possibly dangerous precedent,” ISO-NE continued. “Finally, the March 2015 ARA results are used as inputs to monthly bilateral arrangements and monthly reconfiguration auctions; these processes are already underway, and a change to the March 2015 ARA results could cause significant disruption.”
ISO-NE also said similar “corrections” could cause substantial harm to other parties. “If the March 2015 ARA had instead included more supply offers than demand bids, post hoc removal of the Canal 2 demand bid would have required a re-running of the auction and would have stripped some of the resources of the capacity supply obligations acquired in the first iteration.”
Increased electric infrastructure investments in Illinois helped boost Ameren’s first-quarter profits by 12.4%.
The St. Louis-based utility reported net income of $108 million ($0.45/share) compared to $96 million ($0.40/share) last year. The earnings-per-share results were 7-10 cents higher than analyst estimates.
Revenue was $1.56 billion compared with $1.59 billion a year earlier.
Ameren said it benefited from increased electric delivery and transmission infrastructure investments and from an order by the Illinois Commerce Commission approving recovery of additional costs, which added 4 cents to earnings.
The regulatory climate in Missouri was less favorable, reflecting a reduction in allowable cost recovery for vegetation management, infrastructure investment costs and certain storm costs. The state also reduced return on equity to 9.53% from 9.8%.
Even so, Ameren held firm on its estimated full-year diluted earnings per share of $2.45 to $2.65.
Weather, Integrys Merger Costs Bruise Wisconsin Energy Q1 Earnings
Wisconsin Energy said first-quarter profit fell 6%, citing a warmer winter than a year ago and the costs related to its proposed acquisition of Integrys Energy.
The company reported net income of $195.8 million ($0.86/share) compared with $207.6 million ($0.91/share) in the first quarter of 2014. Revenues fell 18% to $1.39 billion. The company said 2014 revenues were higher due to the polar vortex and higher spot market prices for natural gas.
The Federal Energy Regulatory Commission and the Michigan Public Service Commission have already approved the Integrys deal. The Wisconsin Public Service Commission last month indicated it will likely approve the deal, to the chagrin of industrial and consumer groups that want Wisconsin Energy to promise specific rate savings to customers as a result of the $9.1 billion merger. Regulators in Illinois and Minnesota have yet to sign off on the deal.
Nuke Charge Slams Xcel Energy’s Q1 Profit
Xcel Energy’s first-quarter net income fell 41% from a year earlier on a milder winter and a $129 million pre-tax loss related to a 2013 upgrade of its Monticello nuclear plant.
The Minneapolis-based company reported a profit of $152 million ($0.30/share) compared with $261.2 million ($0.52/share) in the first quarter of 2014.
Profits took a 16 cents-per-share hit due to the loss stemming from the Monticello project. In 2013, Northern States Power-Minnesota completed a project to uprate the Monticello nuclear facility to 671 MW from 600 MW, at a cost of $748 million.
That was more than a 2008 estimate of $320 million. The Minnesota Public Utilities Commission completed a prudence review in March, determining that $333 million of the costs must be recovered over the life of the project.
Revenues of $2.96 billion were down 7.5% from the same quarter last year, largely on milder winter weather that reduced consumption.
Xcel reaffirmed full-year earnings per share of $2 to $2.15.
If the Federal Energy Regulatory Commission keeps its word, virtual traders in PJM should have clarity by the end of October on whether up-to-congestion transactions will be subject to additional charges.
In opening a section 206 docket on the issue last year, the commission said it would rule within five months after it receives comments following a technical conference.
The technical conference was held Jan. 7. On April 29, the commission issued the request for follow-up comments, which are due May 29 (EL14-37).
In September, FERC ordered the 206 proceeding to determine whether PJM is improperly treating UTCs differently than incremental offers (INCs) and decrement bids (DECs). While INCs and DECs are charged uplift and subject to the financial transmission rights forfeiture rule, UTCs are exempt from both.
UTC trading volumes collapsed after Sept. 8, the refund-effective date set by FERC for any uplift assessments. Some financial traders have discussed an interim fee on UTCs in an effort to encourage trading pending resolution of the case. (See Cool Response to Proposed 7-Cent Fee on Virtual Transactions.)
Among the questions on which FERC solicited comment were:
How should the injection/withdrawal points for the virtual transaction be identified?
Should the defined “worst case” node be limited to the market participant’s own transactions?
Should the FTR forfeiture rule collectively assess the net impact of a market participant’s entire portfolio of INCs, DECs and UTCs instead of the current rule, which assesses virtual transactions one at a time?
Should counter-flow FTRs and bids that relieve congestion remain exempt from FTR forfeiture rule calculations? Should financial transactions that improve day-ahead and real-time market price convergence be exempt from the forfeiture rule?
Should UTCs be assessed uplift?
Do UTCs impact unit commitment decisions?
Should market participants be allowed to net INC and DEC transactions for the purpose of uplift allocations?
Extreme winter temperatures, while not as severe as last year, continue to play a major role in companies’ earnings results and business strategies.
PSEG
Public Service Enterprise Group reported 2015 first-quarter net income of $586 million ($1.15/share) compared to $386 million ($0.76/share) for the same period last year, a 52% increase.
While the company cited the strong performances of Public Service Electric & Gas and its generation business PSEG Power, operating earnings only increased slightly from the previous year and revenue dipped slightly. The biggest boon for the company was a $264 million settlement it reached with its insurers to recover losses due to Superstorm Sandy, $159 million of which is reflected in the first-quarter report.
PSEG had filed a lawsuit against the insurance companies in the summer of 2013, claiming they had denied it full coverage for its losses. A New Jersey Superior Court judge sided with the company in March. “The claims related to Superstorm Sandy insurance coverage are now fully resolved,” PSE&G spokeswoman Karen Johnson said.
Operating earnings for PSEG Power fell slightly by 5%, but due in part to the settlement, the business’s net income rose from $164 million to $335 million, a 105% increase. Most of the settlement money was for damages to the subsidiary’s plants.
“PSE&G is delivering on the promise of its expanded distribution and transmission investment program, while the reliable performance of PSEG Power’s generating assets and its gas market expertise during one of the coldest winters on record helped us deliver value for our customers,” CEO Ralph Izzo said.
Duke
Duke Energy reported 2015 first-quarter net income of $864 million ($1.22/share) on $6 billion in revenue.
While revenue fell from the nearly $6.3 billion it brought in a year ago, Duke’s earnings per share were well above analysts’ expectations of $1.14/share. A year ago, the company posted a first-quarter loss of $97 million after a $1.4 billion write-down of its Midwest Generation business. In March, Duke completed a $2.8 billion sale of the business to Dynegy.
Duke’s domestic utility businesses performed well despite the challenges of multiple winter storms, including Duke Energy Carolinas customers setting a record on Feb. 20 for peak use, CEO Lynn Good said. This offset weak international results, due in large part to an ongoing drought in Brazil that drove up the cost of purchased hydropower.
FirstEnergy
FirstEnergy’s first-quarter net income rose almost 7% to $222 million ($0.53/share) despite a 7% drop in revenue to $3.9 billion, the company said. Last year it reported earnings of $208 million ($0.49/share) on first-quarter revenue of $4.2 billion.
In an earnings call with analysts, CEO Charles Jones cited a revised strategy in the company’s competitive sales business as the primary driver of both the increased earnings and decreased revenue. FirstEnergy reduced its predicted annual load obligation to 68 million MWh, compared to 99 million last year, Jones said. The company also reduced the number of residential and small business customers it serves in weather-sensitive areas.
“This strategy, together with improved plant operations, helped to mitigate the potential downside from this year’s severe first-quarter weather and demand conditions, even though our region experienced four more below-zero days this February than last January,” Jones said. He also noted that PJM set a new winter demand peak in February. (See Cold Sends PJM to New Winter Record.)
The company also cited an increase in earnings from its regulated transmission segment, a result of prior investments, it said.
Dominion
Dominion Resources reported a 41% increase in net income for the first quarter, from $379 million ($0.65/share) last year to $536 million ($0.91/share) this year.
Operating earnings for the quarter, however, fell nearly 4%, and revenue fell 6%, from $3.63 billion last year to $3.41 billion this year. While earnings were largely the same from last year across most segments, Dominion noted a drop in its merchant generation business — earnings fell by nearly 9% — as one of the primary factors in the decrease in operating earnings.
CFO Mark McGettrick told investors that the drop was primarily due to poor power prices for its merchant generation in New England. Otherwise, weather conditions in the company’s service areas were “favorable,” which added 5 cents more per share in operating earnings than normal, he said.
PPL
PPL more than doubled its first-quarter profits, reporting earnings of $647 million ($0.96/share) versus $316 million ($0.49/share) in 2014.
Revenues were $3.17 billion, up from $1.19 billion in the first quarter of 2014, when it recorded $1.46 billion in losses on physical and financial commodity sales.
The company cited strong results from its regulated operations in the United Kingdom, Pennsylvania and Kentucky and earnings from infrastructure investments.
PPL expects to close the spinoff of its competitive generation business into Talen Energy on June 1.
“Moving forward as a purely regulated utility company, we remain confident in our ability to achieve annual earnings growth of 4 to 6% through at least 2017, based on the continued strong performance of our regulated businesses, the rate base growth expected from significant projected infrastructure investment and $75 million in targeted, corporate support cost savings that have been identified as part of our corporate restructuring,” CEO William Spence said.
Con Ed
Consolidated Edison reported first-quarter net income of $370 million ($1.26/share) compared with $361 million ($1.23/share) in 2014.
Revenue for the company’s regulated utilities fell by 4.4%, from $2.22 billion to $2.12 billion.
“The company experienced strong financial performance in the first quarter, and our workforce performed admirably during the challenges of a persistent, lingering winter,” said John McAvoy, chairman and CEO of Con Ed. “We are also very pleased with a proposed settlement with the New York State Public Service Commission that will keep electric delivery rates flat for our customers through 2016.”
MISO and SPP are considering $276 million in potential transmission upgrades under a joint model for identifying congested flowgates that could be relieved by economic projects.
Emerging from that joint process so far are four potential projects that could generate $438 million in benefits to the RTOs over 20 years, RTO officials said last week at a meeting of the SPP-MISO Interregional Planning Stakeholder Advisory Committee.
Four projects may not sound like much. But it’s progress considering the RTOs’ contentious relationship since December 2013 when New Orleans-based Entergy joined MISO rather than SPP, which had served as the Independent Coordinator of Transmission for Entergy’s system since 2006.
Most visible is a dispute over flows between MISO’s northern region and its new, southern region. MISO began limiting flows between the regions last spring after SPP complained that MISO had breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW physical contract path.
But that dispute seemed distant as staff from both RTOs convened last week in Little Rock, Ark. Some even joked that they’ve been talking so much with those at the other RTO that they’ve memorized their phone numbers.
“We’ve learned a great deal about each other’s processes,” said Clayton Mayfield, an economic planner at SPP.
Collaboration has also improved modeling practices and provided a better understanding of neighboring stakeholder groups, said Jenell McKay, a senior analyst at MISO.
Stakeholders and staff at SPP and MISO came up with 67 potential economic projects using a joint model based on each RTO’s regional model. It projected transmission needs for 2019 and 2024.
That was whittled down to seven projects with potential, but three of those didn’t provide a minimum 5% benefit set as a threshold under the joint model.
The four projects seen to have the most potential totaled $276 million. They include new and upgraded transmission lines and transformers in Louisiana, Kansas and Nebraska. Benefits range from a 21% congestion reduction to a complete reduction in congestion.
Still Fine-Tuning List
Mayfield cautioned that the project list is preliminary and that more projects will likely emerge from the ongoing collaborative effort.
He noted that some projects initially identified were dismissed, and others added, after assumptions changed about the future of the Tennessee Valley Authority’s Shawnee units. MISO’s 2014 Transmission Expansion Plan originally contemplated that Shawnee Units 1-10, totaling 1,369 MW, would be retired, but TVA has since decided to keep nine of the Shawnee units in service.
The IPSAC joint analysis is expected to result in final project recommendations by June 30. The committee also is looking at a handful of reliability projects to reduce overloads.
More Potential
Other joint studies may be underway. McKay said the RTOs have had discussions regarding a study involving the effects of the Environmental Protection Agency’s proposed Clean Power Plan.
Pat Hayes, senior transmission policy specialist at Ameren, told the committee it could be helpful if staff conducts a “post mortem” regarding what differences the RTOs ran into and how they could have impeded a project from going through.
Kip Fox, director of transmission strategy and grid development at American Electric Power, said his “personal observation” is that the RTOs are working better together. He noted, however, that MISO and PJM have not been able to get moving on a seams project after four years. “I don’t want the same thing to happen here,” he told the committee.
Warren Buffett’s energy businesses have been buying and building wind generation facilities in the Midwest and Great Plains for years.
But the Oracle of Omaha now has his eyes on bringing solar power to the central U.S., according to a recent filing with the Federal Energy Regulatory Commission.
Buffett’s Berkshire Hathaway Energy disclosed that it recently acquired a site for solar generation development in MISO’s central region. The “site” consists of 74 individual “locations” not to exceed 1 MW each, according to the company’s quarterly property acquisition report. (MidAmerican Energy Holdings changed its name to Berkshire Hathaway Energy in April 2014.)
The company did not disclose exactly where the site is located. The company is not ready to make an announcement on the project, spokesman David Caris said.
MISO is a new locale for the company’s solar portfolio.
Subsidiary BHE Renewables has more than 1,200 MW in existing solar generation, primarily in California and Arizona, including its 550-MW Topaz Solar Farms in San Luis Obispo County, Calif., which became fully operational in March. Berkshire Hathaway companies also operate 579 MW of solar generation in Los Angeles and Kern Counties and own 49% of a 290-MW solar generating site in Yuma County, Ariz.
Environmental Regulations Bring Opportunities
Berkshire Hathaway’s planned solar expansion in MISO’s coal-dependent central region — which includes Indiana, Michigan, Wisconsin and parts of Illinois — appears designed to take advantage of increased demand for renewables as a result of federal environmental regulations.
The company has also continued its investments in wind. In October, BHE announced its plans for a 160-MW wind farm in Adams County, Iowa, that could cost up to $280 million.
Late last month, the company filed plans with the Iowa Utilities Board to construct up to 552 MW of additional wind generation in the state at a cost of $900 million. The company said it would announce the location and other details later.
On April 30, BHE announced plans to build a 400-MW wind farm in Holt County, Neb., that would be the largest wind project in the state. The recent FERC filing said that Berkshire Hathaway acquired a site in SPP territory for up to 400 MW of wind-powered generation development. It wasn’t immediately clear whether it’s the same site.
BHE owns and operates more than 3,400 MW of wind, solar, geothermal and hydro generation.
At the Edison Electric Institute’s annual convention last June, Buffett said the company, which has already spent $15 billion on renewables, was prepared to double that investment.
ALBANY, N.Y. — Four former energy regulators who were in the middle of many of the electric industry’s watershed events of the past two decades reminisced — and expressed regrets for paths not chosen — at the Independent Power Producers of New York spring conference Wednesday.
From left to right: Massey, Wood, moderator and former NYPSC chair William Flynn, Brownell and Kelly.
Former Federal Energy Regulatory Commissioners William Massey (1993–2003), Nora Mead Brownell (2001–2006), Suedeen Kelly (2003–2009) and former chairman Pat Wood (2001-2005) expressed pride in the growth of wholesale competition and wistfulness over political compromises that prevented development of larger, more uniform markets.
In a later session, NYISO CEO Stephen Whitley (2008–present) and predecessors William Museler (1999–2005) and Mark Lynch (2005–2008) also shared war stories from the first 15 years of the ISO’s markets.
Open Access
Massey
Massey voted in 1996 for the landmark Order 888, which ordered transmission operators to open their lines to competition.
“We knew we would get pushback with everything we did, but if you’re going to be a regulator or run an RTO, you’ve got to have political courage,” said Massey, counsel to the COMPETE coalition, which represents more than 700 stakeholders in support of electricity competition.
And political courage failed him at the most crucial time, Massey admitted, recalling the California energy crisis of 2000-2001, which occurred after FERC’s misgivings about the poorly designed California market were cast aside.
Massey related how the 1996 utility restructuring law passed the California legislature unanimously. The entire California congressional delegation then wrote to FERC, saying that any tinkering by the agency would likely cause the plan to collapse “like a house of cards.”
FERC meekly went along. “We had the opportunity to vote yes or no,” Massey said. “That is the vote I’m most sorry about.”
California’s wholesale power market and customer-choice program began in 1998 and seemed to be working well until the summer of 2000, when electricity prices in southern California hit all-time highs, and generation shortages caused rolling blackouts in northern California. Escalating wholesale prices, combined with retail price caps, put the state’s three major investor-owned utilities in a vise, with Pacific Gas & Electric forced to declare bankruptcy.
In December 2000, FERC eliminated the requirement that the three IOUs purchase their power through the California Power Exchange. In June 2001, shortly after Wood and Brownell joined the commission, FERC expanded a price mitigation and market monitoring plan it had issued in April 2001.
The California price spikes and Enron’s implosion stopped restructuring dead in its tracks as a national policy, Wood recalled. “Years later we were still putting the pieces back together,” he said.
Wood
Wood, now chairman of the Dynegy Board of Directors, said the industry is still coping with the lessons from the California crisis, including the balancing of consumer interests and industry needs. “If you want to be an economic regulator, you’ve got to understand the economics [and] what it takes to incent investment,” he said.
What he most seemed to regret was how proposals to divide the country into four RTOs — the Northeast, Southeast, Midwest and West — were stymied. The country is still paying for the “balkanization” of the markets caused by the “hue and cry and pushback,” he said.
“I still think there’s a lot of enterprise that could occur between New York and New England. And the seams issues between PJM and MISO are just awful,” he said.
Present & former NYISO CEO’s: William Museler (1999-2005) (L), Mark Lynch (2005-2008) (M), and Stephen Whitley (2008-present) (R)
Former NYISO CEO Lynch said the vision of a larger, seamless market in the Eastern Interconnection is unlikely to be realized. “We may have missed our opportunity to get there,” he said.
Kelly, who worked on legislation to make restructured markets national policy as a Senate staffer before her FERC tenure, said its failure informed her tenure as a regulator. “Political courage is important, but even more important is political support,” she said. Kelly added that energy policy is one place where partisanship can melt away and consensus built.
Brownell
But Brownell and NYISO CEO Whitley said that consensus-building can be unwieldy — “herding cats,” Whitley called it.
“I think the stakeholder process has grown into a cottage industry,” Brownell said. “I have great respect for the work they do, but I can’t imagine the New York Stock Exchange being developed by 400 people over a three-year period. We need to focus on the larger picture,” she said.
The larger picture, Brownell said, is electric markets’ role in developing the economy. “Where we begin to redefine this industry as economic development, we’ll move away from state versus federal [jurisdiction]. This is really about our competitive position in the world and social well-being.”
A New York clean energy developer has challenged a three-state effort to bring more renewable energy to New England.
Allco Renewable Energy Group filed suit against Connecticut in U.S. District Court in New Haven, claiming the joint effort and Connecticut’s renewable energy subsidies violate the U.S. Constitution’s Interstate Commerce Clause (3:15-cv-00608-CSH). Allco is also asking for an injunction to stop the joint procurement plan by Connecticut, Massachusetts and Rhode Island.
Allco CEO Thomas Melone unsuccessfully sued over Connecticut’s previous clean power plan, claiming the state illegally excluded renewable energy credits (RECs) generated by his facilities in other states from participating in Connecticut’s programs. RECs represent the environmental attributes of a clean energy project and are sold and traded separately from the energy produced. That case is under appeal. The claims made in that suit under the dormant Commerce Clause and the Federal Power Act are repeated in the new lawsuit.
Connecticut counts RECs from other New England states, and from New York and Canada, under certain circumstances. Melone is seeking to have his solar facilities in Georgia and New York qualified. The determination should be made by the Federal Energy Regulatory Commission and not the states, the suit says.
“The dormant Commerce Clause prohibits a state from using its regulatory power to discriminate against out-of-state businesses,” according to the suit, filed on April 26.
Allco sued the Connecticut Department of Energy and Environmental Protection and the state’s Public Utility Regulatory Authority.
“The three-state procurement is an innovative approach to meeting our renewable energy goals and securing clean power at the lowest possible price for our families and businesses,” Dennis Schain, a spokesman for DEEP said in a written statement to the Hartford Courant. “We believe the procurement is legally sound and will meet court challenges.”
MISO and ISO-NE said last week they have sufficient resources to meet this summer’s demand, but they warned that their reserve margins are shrinking due to plant retirements.
Reserves Good — for Now
MISO estimates that summer demand in its territory will peak at 127.3 GW, with 23 GW of reserve capacity available. That amounts to an 18% reserve margin, above the target of 14.3%.
However, the RTO projects reserve margins will erode because of “current environmental and microeconomic pressures.” That could result in emergency operations, such as suspending planned generation maintenance and the curtailment of non-firm energy sales.
Coal-fired generators are being forced into retirement by cheap natural gas and current and pending emissions limits on mercury and carbon dioxide.
“Starting in the next few years, we are seeing a dramatic shift in the resources available to meet demand during the hottest days of the year,” said Todd Ramey, vice president of system operations and market services at MISO.
ISO-NE Expects Sufficient Resources
ISO-NE also said it will have enough electric generation and demand response resources to serve its forecasted summer peak.
Under normal weather conditions of about 90 F this summer, electricity demand is forecasted to peak at 26.71 GW. Extreme summer weather, such as an extended heat wave of about 94 F, could push demand up to 29 GW. These forecasts take into account the demand-reducing effect of 1,685 MW of energy-efficiency measures acquired through the Forward Capacity Market.
Last year’s retirement of the 615-MW Vermont Yankee nuclear power plant will reduce the region’s reserve margin. Last summer, demand for power peaked on July 2, 2014, at 24.44 GW. The all-time record for peak demand was set on Aug. 2, 2006, when demand reached 28.13 GW after a prolonged heat wave.
