Beginning in January, gas generators will be able to change their offers to reflect fluctuating fuel prices, under a proposal approved by the Operating Committee last week.
The proposal would allow generators to lock in their fuel prices three hours in advance of the operating hour.
The option would be available to resources that did not receive day-ahead commitments and were not picked up in the reliability assessment and commitment (RAC) run. Units with day-ahead commitments and those selected in the RAC run can switch prices after the end of their last committed hour. Units committed in real time will be unable to change their cost schedules until released.
“It’s not a perfect solution,” PJM’s Chantal Hendrzak acknowledged during a briefing of the Market Implementation Committee Friday. “For right now, we think this would be better than what we have today, where we lock prices at 1800 [the day before] and there’s no way to change.”
Hendrzak said PJM’s security constrained economic dispatch (SCED) engine does not recognize an end to a price schedule. The three-hour “lockout” is necessary to give the engine time to produce the dispatch stack.
The changes are the result of work by the Gas Unit Commitment Coordination (GUCC) group within the Operating Committee.
The Operating Committee approved the new policy Thursday despite abstentions from Dayton Power and Light and PPL, and objections from Dominion Resources and American Electric Power. Dominion’s Louis Slade said that while his company agrees with the increased offer flexibility, he objected because PJM had not given members advance notice of the Manual 11 changes involved.
The OC will hold a conference call at 3 p.m. Nov. 12 to discuss the changes in advance of a Nov. 20 vote by the Markets and Reliability Committee.
PJM’s vendor is expected to deliver the required software changes in December. PJM is planning to put the changes into production in January. The new procedures will be explained during the winter-weather procedure changes webinar Nov. 24.
For a long-term solution, Hendrzak said PJM is considering the technology used by ISO-NE. Beginning in December, the ISO will allow generators to change pricing by hour in the day-ahead market and change real-time offers until 30 minutes before the operating hour. “We know we’re not done yet,” Hendrzak said.
The MIC also received a briefing from Market Monitor Joe Bowring on how generators should submit their fuel cost policies through Monitoring Analytics’ new member-information-reporting application (MIRA) tool.
The Monitor uses the fuel cost policies to review cost-based offers submitted by generation owners. The policy must specify the source of the generator’s fuel cost input. Allowable sources are:
The staff of the Federal Energy Regulatory Commission last week accused a Canadian independent power producer of misrepresenting the output of its three New England generators and its cost of fuel in schemes that the staff says netted the company millions in inflated payments.
FERC issued a Staff Notice of Alleged Violations (NAV) last week naming Calgary-based Maxim Power Corp., its CEO, John Bobenic, and Kyle Mitton, director of corporate development, as the targets of its investigation.
The NAV indicates that FERC enforcement staff has completed its investigation. Most FERC enforcement cases that become public are quickly settled. If Maxim declines to settle, the next step may be a commission vote on whether to issue an Order to Show Cause.
In May, Maxim disclosed to investors that FERC had accused the company of receiving unjust gains of $23 million. The company said it repaid about $3 million in 2010 through “the ISO-NE mitigation program.”
FERC staff alleges that Maxim collected “millions of dollars of inflated make-whole payments” from ISO-NE between 2012 and 2013 by gaming an ISO rule intended to mitigate the market power of generators needed for reliability. The notice did not elaborate on how this was allegedly done.
In a second alleged scheme in July and August 2010, Maxim submitted offers it said were based on high oil prices because it couldn’t procure enough natural gas. FERC says the company collected make-whole payments based on the oil price but actually burned cheaper natural gas and pocketed the difference. “In many cases Maxim had already purchased gas when it submitted day-ahead offers based on oil prices,” FERC said.
In the third allegation, FERC said that Maxim collected inflated capacity payments between 2010 and 2013 by using “extraordinary measures” to boost the output of its three New England plants during testing. It said that the “extraordinary measures” were used only during the tests, and that Maxim never intended to use those methods during normal operations.
FERC offered no details on what those measures were. There are several ways of temporarily boosting the output of gas-fired generating plants, including disconnecting emissions controls and using different fuel-air mixtures.
Maxim officials did not respond to requests for comment yesterday. In a news release last week, the company said it is cooperating with FERC’s inquiry and stressed that a NAV “is not a determination by FERC that any violation has occurred.”
“Maxim intends to vigorously defend itself before FERC or a federal district court and is confident it can demonstrate that the conduct set forth in the notice did not violate FERC’s anti-manipulation rule or any other rule.”
ISO-NE spokeswoman Marcia Blomberg told RTO Insider “we support FERC investigations by providing information to the commission, but we don’t discuss market enforcement activities publicly.”
Maxim operates three plants in the ISO-NE region: CDECCA, a 62-MW cogeneration plant in Hartford, Conn.; Pawtucket Power, a 63.5-MW cogeneration plant in Pawtucket, R.I.; and a 181-MW natural gas-fired plant in Pittsfield, Mass.
In total, the company owns and operates 39 power plants in Alberta, the U.S. and France, with a combined 777 MW of capacity. Its other U.S. plants are the Basin Creek natural gas-fired plant in Montana and a simple cycle 87-MW plant in Forked River, N.J.
The company, which trades on the Toronto Stock Exchange, reported $10.6 million in net income on $173.7 million in revenue for 2013.
CEO John R. Bobenic, an accountant, joined Maxim in October 2000 after stints at Peat, Marwick, Mitchell & Co. and TransAlta. He is a past vice chair of the Independent Power Producers Society of Alberta.
New York/New England Correspondent William Opalka contributed to this article.
Consumers Energy plans to replace some of its “Classic Seven” capacity with the purchase of this 540-MW natural gas-fired plant in Jackson, Mich.
The Federal Energy Regulatory Commission last week denied Consumers Energy’s request for a waiver from MISO’s must-offer requirement, three weeks after approving a similar request by Indianapolis Power and Light.
Both utilities complained that there was no clear mechanism within MISO’s Tariff that would permit them to buy replacement capacity to cover a six-week gap in 2016 between when they planned to retire older coal units under the Environmental Protection Agency’s Mercury and Air Toxics Standards and the end of MISO’s planning year on May 31.
Michigan-based Consumers Energy plans to retire its “Classic Seven” coal units — three at the J.R. Whiting generation station near Luna Pier; two at the B.C. Cobb Generating Plant in Muskegon; and two at Karn/Weadock, near Bay City — on April 15, 2016.
Consumers said purchasing replacement power for the entire 2015-16 planning year would cost $5.8 million to $84.8 million.
The Michigan Public Service Commission told FERC it should approve Consumers’ request to minimize costs to ratepayers. Alliant also filed in support.
MISO opposed Consumers’ waiver request, saying that it could cause the ISO’s North and Central regions to fall below the Planning Reserve Margin, increasing the risk of a loss-of-load event.
MISO said that Consumers’ request for a waiver reinforced its resource adequacy concerns for the six-week period at issue “because the request implicates an additional 940.7 MW during the time period in which Indianapolis Power requests waiver of approximately 216 MW.”
Calpine, NRG Energy and Dynegy told FERC that MISO’s Tariff exempts resources that are retiring in the middle of a planning year from the must-offer requirement. FERC did not say whether or not it agreed with the companies’ reading of the Tariff.
Instead, the commission ruled that unlike with IPL, Consumers Energy hadn’t adequately demonstrated that a waiver would not cause undesirable consequences.
“We find it significant that the Classic Seven comprise 940.7 MW of generation in Michigan, which represents approximately 14.5% of Consumers Energy’s total capacity,” FERC said.
Consumers had not identified whether the utilities in MISO Zone 7 have coordinated to provide generation outage schedules for April-May 2016.
In contrast, Indiana utilities did provide MISO with their generation outage schedules far in advance so that MISO could conduct a maintenance margin study for future years, FERC said. MISO’s analysis showed that MISO Zone 6, in which IPL is located, has a sufficient planning reserve margin even after accounting for scheduled outages.
FERC Chairman Cheryl LaFleur seemed to invite Consumers to refile to address the deficiency, noting in a concurring opinion that the order was made without prejudice.
Consumers spokesman Dan Bishop said yesterday that the company was studying the ruling and hadn’t decided whether to refile.
Consumers plans to replace lost generation from the Classic Seven retirement in part with a 540-MW gas generating unit it will acquire in Jackson, Mich. The company will also make wholesale purchases, Bishop said.
Commissioner Norman Bay dissented on the IPL waiver request, saying a one-time waiver “creates an unfortunate precedent that erodes MISO’s capacity construct, undermines the bilateral market for capacity and blurs, unnecessarily, a line that had once been bright.”
American Electric Power has three transmission proposals before the Public Utilities Commission of Ohio, including one project aimed at meeting demand from the shale oil and gas industry.
The 19-mile Biers Run-Circleville 138-kV line, which is slated for completion in 2017, would cost $97 million. The transmission portion would cost $22 million. It serves southern Columbus, Chillicothe and Circleville.
Another 138-kV project, the Biers Run-Hopetown-Delano line, will run for 12 miles across Ross County and cost an estimated $17 million.
The $5.2 million Sparrow 138-kV loop is proposed to support the expansion of a natural gas processing facility north of Cadiz. The facility’s operator, MarkWest Utica EMG, asked for the 2-mile line. As a result of an expedited request before PUCO, AEP is expected to complete construction in June.
NRG Building 360-MW Plant Near Houston; More to Come
NRG Energy says it will build a 360-MW natural gas-fired peaking plant near Bacliff, southeast of Houston, on the site of the former PH Robinson Power Plant.
The plant will contain six GE 7E fast-start combustion turbines relocated from an existing plant in New Albany, Miss. The turbines require no water for cooling, an important attribute in water-starved Texas. The project is scheduled for completion late next year.
NRG says it is also nearly ready to file for permits for two other natural gas-fired plants in the Houston area, both 850-MW combined-cycle plants. It didn’t provide further detail on those projects.
Babcock & Wilcox Spinning Off Generation, Nuclear Ops Companies
Babcock & Wilcox is spinning off its power generation unit into a separate company from its government and nuclear operations.
The power generation business, which will operate under the Babcock & Wilcox name, will provide fossil and renewable generation equipment for projects. The company’s government and nuclear operations business will become BWX Technologies. It will supply nuclear components and fuel to government facilities and provide technical, management and on-site services to both government and commercial facilities.
SoCal Edison Announces Largest Energy Storage Project in US
Southern California Edison is entering into agreements with five companies to procure 261 MW of energy storage, more than five times the minimum required by state regulators.
SCE has applied to the California Public Utilities Commission for approval to go ahead with the plan to meet a state mandate for energy storage, which requires investor-owned utilities to have a total of 1.325 GW of energy storage by 2020.
“The fact that SCE far exceeded the minimum amount of energy storage they were ordered to purchase after comparing multiple solutions head to head demonstrates that energy storage can be competitive with other preferred resources on both performance and value, and that it’s now an integral part of the utility planning tool kit in California,” said Janice Lin, executive director of the California Energy Storage Alliance.
SCE chose the five companies after reviewing more than 1,800 proposals: NRG will provide 0.5 MW; Ice Energy Holdings 25.6 MW; Advanced Microgrid Solutions 50 MW; Stem 85 MW; and AES Energy Storage 100 MW.
Three other California investor-owned utilities will announce their energy storage purchases by Dec. 1, expected to be another 200 MW.
Sunoco Planning $2.5B Pipeline to Quadruple Shale Gas Capacity
Sunoco Logistics, the company repurposing a fuel pipeline to carry Marcellus Shale natural gas liquids to its terminal in Marcus Hook, Pa., announced a $2.5 billion expansion project that would quadruple capacity by the end of 2016.
The Mariner East 2 project, which would follow the path of the original Mariner East pipeline from western Pennsylvania to the Delaware River, would transport propane, butane and ethane from the shale gas fields. The 16-inch pipeline is expected to carry 275,000 barrels of natural gas liquids per day to the Marcus Hook port, compared to the first pipeline’s daily capacity of 70,000 barrels.
The Philadelphia company is rebuilding its closed Marcus Hook oil refinery to store, process and ship gas liquids. The company said it is exploring the possibility of building a manufacturing facility in Marcus Hook to process propane into propylene for petrochemical customers.
Southern Maryland Electric Coop. Named Utility of Year by Solar Group
The Solar Electric Power Association has named Southern Maryland Electric Cooperative the Electric Cooperative Utility of the Year.
The co-op won the award for its commitment to using locally generated solar power to meet its renewable targets. SMECO developed a 5.5-MW solar project on a tobacco farm and is building a 10-MW solar plant. The output will go toward meeting the renewable mandates through 2018.
“SMECO leveraged one of the advantages offered by solar — as well as being true to its co-op mission to bring value to the community it serves — when it chose to build solar within the co-op service area rather than purchase renewable credits from a distant resource,” said Julia Hamm, president and CEO of SEPA. “The co-op also gained valuable hands-on experience with a new resource, inspiring a commitment to continue to expand its investment in solar.”
Fishermen’s Energy Plans to Go Back to NJ BPU in December
Fishermen’s Energy of Cape May, N.J., says it will return to the state Board of Public Utilities once again to seek approval for its proposed 25-MW offshore wind project three miles off Atlantic City.
The BPU previously rejected the $188 million as too costly for ratepayers. But the Obama administration awarded it a $47 million Department of Energy grant, and Fishermen’s CEO Paul Gallagher said his company will give the state agency another go.
“I’ve been living with this for four years and I can’t speculate as to what motivates the BPU,” he said.
Some believe that Gov. Chris Christie has soured on offshore wind and is now focused on appealing to conservative supporters outside New Jersey for a 2016 presidential run. Environment New Jersey Director Doug O’Malley said there is “nothing holding back New Jersey now other than Gov. Christie’s intransigence and, sadly, even though offshore wind has bipartisan support in the state, the governor has his eyes on a different prize right now.”
Westinghouse CEO Sees Bright Future for Nuclear in US
Westinghouse Electric CEO Danny Roderick says the company’s nuclear business is doing very well in the United Kingdom, China and other countries — international markets make up 60% of the company’s business. But he also foresees domestic growth from new U.S. nuclear facilities, where Westinghouse’s AP1000 reactors are already being used at sites under construction in Georgia and South Carolina. “We still see new plants are going to be built in Florida; we see new plants that are going to come up in the Carolinas,” Roderick told the Pittsburgh Tribune-Review. “Those are all progressing right now.”
In the last year, Westinghouse has taken heart from an announcement that Georgia intends on building more than the Vogtle project that is now under construction. Florida Power and NextEra Energy have announced they’re going to start work on the Turkey Point project in South Florida. Duke has continued discussion about building another unit in the Carolinas. And a proposal for a plant using an earthquake-hardened version of the AP1000 is being discussed in Utah.
“So what you’re seeing is, the regulated market actually does give a valuation to 24/7 power and recognizes the need for long-term investments of infrastructure like a nuclear power plant,” he said.
Alliant Energy announced it will expand its Riverside Energy Center in Beloit, Wis., by building a 650-MW combustion turbine combined-cycle plant. The company said it will file for approval with the Wisconsin Public Service Commission early next year and begin construction in 2016. The gas-fueled plant, which will cost between $725 million and $775 million, is expected to go into operation in early 2019.
“Having access to reliable, flexible, around-the-clock power that a combined-cycle energy center offers will be a direct benefit to our customers,” said John Larsen, president of Alliant’s utility WPL. “As part of our long-term planning, the Riverside Energy Center will also be evaluated for the integration of solar energy as we continue to expand our renewables portfolio.”
Insufficient natural gas pipeline capacity is the top concern in ISO-NE’s 2014 Regional System Plan, which was released last week.
“The lack of pipeline infrastructure has raised fuel adequacy for natural gas generators to the top of the list of pressing concerns for New England’s power system,” said ISO-NE CEO Gordon van Welie in a statement announcing the plan.
New England is projected to lose 4,600 MW of generation by June 2017, further stressing a regional power system that barely maintained reliability during last winter’s polar vortex. Of the 8,300 MW of new generation proposed through November, 4,500 MW is natural gas while most of the remainder (3,700 MW) is wind.
Natural gas is projected to rise from 43% of capacity in 2013 to 48% by 2017. Gas produced 45% of the ISO’s energy last year, typically setting the marginal price.
ICF International projects the region will face natural gas shortfalls during winters through 2020. The ISO says it may face gas shortages on 24 to 34 days per winter by 2019/2020 — even more during a severe winter such as 2013/2014.
In addition to highlighting challenges faced by the region, the plan’s 10-year look forward takes note of the region’s increased reliance on energy efficiency and demand response in a climate of relatively flat load growth.
Load Flat but Capacity Short
Including energy efficiency — currently 2,100 MW — the ISO forecasts no growth in total electricity usage, while predicting a 0.7% annual increase in summer peak demand over the 10-year planning horizon.
A year ago, the ISO was predicting a surplus of capacity. But that forecast was undermined by plant retirement announcements that preceded the eighth Forward Capacity Auction in February. The auction fell short of the targeted resource acquisition for the 2018/2019 commitment period, resulting in higher capacity prices than the seven previous auctions.
Chief among the retirements are the 619-MW Vermont Yankee nuclear plant that went offline this year and the 1,517-MW Brayton Point coal-fired generator in Massachusetts, slated to be mothballed in 2017.
Beginning with FCA #9, the ISO will implement a sloped demand curve similar to that used in PJM. The sloped curve is intended to reduce price volatility when the market moves between excesses and shortages. New resources also will be able to lock in clearing prices for seven years, an effort to reduce developers’ risks.
Winter Preparation
For the second year, the ISO will employ a Winter Reliability Program, which includes incentives for oil and dual-fuel generators to increase their oil inventories and for plants to become dual-fuel generators.
The Federal Energy Regulatory Commission approved most of the ISO’s long-term “Pay for Performance” plan, which will reward capacity resources that exceed their commitments and penalize those that fall short beginning in 2018.
One achievement noted in the report is the ISO’s investment in transmission infrastructure. Since 2002, when transmission bottlenecks were seen as the greatest threats to system reliability, 559 transmission projects totaling $6.6 billion have been completed, all but eliminating congestion.
For 2013, real-time system-wide congestion costs totaled only $175,000, and payments for “must-run” generators totaled $54.6 million — representing only 0.6% of the $8.82 billion wholesale electric energy market.
Summer 2014 was the mildest in the last 10 years based on the peak day heat index. None of the five highest load days (blue bars) were above the 10th percentile of PJM’s forecast summer peak. For the first time since 2008, the RTO’s peak day was in June. (Source: PJM Interconnection LLC) (Click to zoom.)
Cooler summer weather took a toll on electric-utility earnings in the third quarter. While some companies, such as FirstEnergy, posted increased profits compared to Q3 last year, many noted a drop in operating earnings due to a dip in deliveries to residential, business and commercial customers.
PJM reported last week that Summer 2014 was the mildest in the last 10 years based on the peak day heat index. (See chart.)
FirstEnergy
Despite its weather-related reduction in operating earnings, FirstEnergy posted a 52.8% increase in profits for the quarter, with earnings of 79 cents a share on income of $333 million, compared to 52 cents on $218 million for the same period last year.
This time a year ago, the company reported a $254 million charge on a regulatory rider rejected by the Pennsylvania Public Utility Commission. It was also in the midst of reorganizing its business units, having decided to retreat from the competitive retail market to concentrate on generation and regulated businesses such as transmission.
CEO Anthony J. Alexander said the strategy is paying off. “We have continued to build positive momentum in our regulated businesses and limit risk at our competitive operations,” he said in a conference call. He also praised PJM’s Capacity Performance proposal. “This is a positive step and truly recognizing the role of base-load generation with firm fuel, the grid stability and reliability.”
Alexander said that one of its largest generating assets, the 2,400-MW Bruce Mansfield coal plant in Shippingport, Pa., failed to clear the most recent PJM capacity auction. That was one of the reasons the company is holding back on capital improvements to that plant “while we evaluate the strength of competitive markets.”
NRG
NRG Energy’s net income rose to $168 million, or 48 cents a share, compared to $119 million, or 36 cents a share, a year ago. While some of the increase was due to the success of its retail business, it was tempered by the mild summer.
“Under these weather circumstances, I think our financial results were as good as could be expected,” CEO David Crane said. “While NRG’s financial performance was constrained in the third quarter by an absence of summer weather events, NRG’s underlying performance across our wholesale and retail operations was quite strong.”
Crane highlighted successes in many areas of NRG’s wide-ranging business model, which includes retail operations, wholesale generation and an increasing amount of renewable energy, especially solar. He said the integration of the assets from its purchases of Edison Mission Energy and Dominion Energy Solutions’ retail operations were on track. He also announced a 440-MW generation contract with Southern California Edison.
The company will continue to build its solar business – especially home solar. “We now believe we have the premier one-stop shop for customers seeking a high-quality solar experience at their homes,” he said. “By the end of this year, we expect to have over 10,000 installations, which is about 70 MW. By the end of 2015, we expect to grow that amount by three times, with an objective of a total of 35,000 to 40,000 installations, or roughly 280 MW.”
Duke
Duke Energy reported earnings of $1.27 billion, compared with $1 billion a year ago, translating to $1.80 a share. About 43 cents of that was from the sale of Midwest power plants to Dynegy for $2.8 billion. Because it had expected to sell those plants for between $1.5 billion to $2.5 billion, the price paid by Dynegy represented an unexpected gain of about $475 million. Discounting that, earnings were about $1.40 a share, down 6 cents from a year earlier.
Earnings from its regulated utilities, which make up about 90% of its business, were nearly unchanged from a year ago despite a slight increase in the number of customers throughout its territories. “These results were impacted by milder than normal weather,” CEO Lynn Good said.
She said the company continues to invest in gas-fired generation, pointing to a proposed 1,640-MW plant in Citrus County, Fla., and uprates of 220 MW at an existing plant in Hines County, Fla. The company is eyeing the purchase of a Calpine facility in Florida and plans to add 320 MW to its Suwanee plant.
A major cost is on the horizon, however. Duke also announced last week that it estimates the cost of complying with North Carolina’s coal-ash law would be as much as $3.4 billion. Hundreds of tons of coal ash spilled from a Duke site on the Dan River in February, spurring a legislative effort to force the company to clean up all of its 32 coal-ash basins.
PSEG
Of the companies operating in the Mid-Atlantic region, Public Service Enterprise Group proved the exception to the mild summer, posting both net and operating earnings increases. Net income was $444 million, or 87 cents a share, up from $390 million and 77 cents a year ago. Operating earnings rose to $393 million, or 77 cents a share, from $385 million, or 76 cents, a year ago.
“PSEG performed well in the third quarter despite the impact on demand for electricity due to less favorable weather conditions,” CEO Ralph Izzo said. “Lower operating costs helped to offset the impact of mild weather on energy pricing and earnings. We’re in the midst of major change in the electricity market. An unprecedented amount of capacity is expected to retire over the next two years in response to environmental requirements and market economics.”
PSEG’s generation arm’s numbers drooped slightly, reporting earnings of $171 million, or 34 cents a share. Last year, it earned $221 million, or 43 cents a share. Power earned less this quarter, in part because of lower PJM capacity prices, “as well as lower market prices for energy,” said Caroline Dorsa, PSEG’s chief financial officer. PJM capacity prices dropped to an average level of $166/MW-day on June 1, 2014, from $242/MW-day in the prior capacity year.
But Izzo said its generating fleet is well positioned to earn in the changing market. “Power is well situated,” he said. “Its fleet of base-load intermediate and peaking generating assets benefits from access to low-cost gas in the summer and from price volatility in the winter.”
Izzo also announced plans for a 450-MW combined-cycle plant in the New England market, at its Bridgeport Harbor site, a $600 million investment. “The potential investment in Bridgeport Harbor would represent the latest of several opportunities for PSEG,” he said.
Calpine
With its wide-ranging assets and foothold in several markets, Calpine wasn’t hemmed in by the mild Mid-Atlantic summer. It reported profit of $614 million, or $1.52 a share, compared to $306 million, or 70 cents a share, a year ago. Operating revenue rose 6.7% to $2.19 billion.
“Calpine delivered another strong quarter both operationally and commercially, especially considering the mild summer weather in much of the country,” said Thad Hill, Calpine’s President and Chief Executive Officer. “Our hedging activity protected us from a very mild summer,” he said. Hill noted that Calpine continues to build business and gain customers in Texas and California, and sell its power from its Osprey plant in Florida to Duke Energy.
He said Calpine expects to close on the purchase of the Fore River plant in Weymouth, Mass., from Exelon any day, and is expanding its combined-cycle plant near Delta, Pa. Those two facilities illustrate Calpine’s reach in both the PJM and the New England markets.
“We believe that PJM and New England offer upside to strong operators willing to stand behind their operational performance, and that the new capacity and market structures under discussion will prove beneficial,” Hill said. “Unlike many of our peers who have pushed back against some of the proposed changes, we’re willing to take the downside risk when you can’t perform with the possibility of higher compensation if you can.”
AES
Weather was a big factor in the earnings for AES, parent company of Dayton Power and Light and Indianapolis Power and Light. But it wasn’t mild summer temperatures that hurt its bottom line; it was low rainfall in Central and South America.
AES reported earnings of $488 million, or 67 cents a share, compared to $175 million, or 23 cents, last year. Overall revenue rose to $4.44 billion from $4 billion last year. About $382 million was from asset sales, including $161 million for four wind projects in the United Kingdom and $125 million for its stake in a Turkish hydro and natural gas-fired generation joint venture. (Since 2011, AES has sold $2.4 billion worth of assets in nine countries.)
Adjusted for these and other transactions, earnings were 37 cents a share. Operating earnings were down 5.1% to 39 cents a share, primarily for “persistent drought” in Latin America, where CEO Andres Ricardo Gluski Weilert said conditions are the driest in 50 years. AES has many hydro-electric assets in Panama and Brazil. “Poor hydrology in Latin America has had a substantial impact on our earnings over the past two years,” he said.
In its U.S. operations, Weilert highlighted its plans to build 1,284 MW of gas-fired combined-cycle generation in California, and the recent awarding of a contract for 100 MW of battery-based energy storage, said to be the largest such energy storage contract in the U.S.
He also said the company is investing $332 million to convert its Harding Street plant in Indiana from coal to natural gas, and that it expected future contributions to earnings from DPL due to the ruling from the Public Utility Commission of Ohio allowing the utility to collect so-called “non-bypassable charges” on customer bills relating to transmission cost even if they have a third-party supplier. The charges were effective beginning in 2014.
Pennsylvania Governor-elect Tom Wolf speaks at his election night victory party in York. Wolf ran on a platform promising to reduce carbon emissions in the state. His election could mean Pennsylvania joining the RGGI. (Source: Tom Wolf campaign)
Having won control of the Senate and a wider margin in the House, Congressional Republicans last week threatened to use oversight hearings and appropriations bills to blunt the Obama administration’s proposed carbon emissions rule. But lacking a veto-proof majority, the GOP is unlikely to block the president’s signature environmental initiative.
The Environmental Protection Agency will be accepting comments until Dec. 1 on its proposed rule to reduce power sector carbon emissions 30% below 2005 levels by 2030. The agency will release its final rule June 1, signaling the beginning of all-but-certain legal challenges.
Some states may join those challenges rather than acquiesce and develop implementation plans for EPA approval. In Wisconsin, Republican Brad Schimel was elected attorney general after a campaign in which he vowed to sue the EPA over the rule. Republican Gov. Scott Walker, who opposes the regulation, won his reelection bid. Republicans also won gubernatorial elections in Maryland, Massachusetts, Michigan and Maine.
But Democrat Tom Wolf’s victory in Pennsylvania’s gubernatorial race gave cap-and-trade supporters hope that the state may join the Regional Greenhouse Gas Initiative — and perhaps bring in some of its neighbors as well.
Climate Change Skeptics
The EPA has had no shortage of critics in Congress since 2011, when House Energy and Commerce Chairman Fred Upton (R-Mich.) offered to give then-Administrator Lisa Jackson her own parking spot at the Capitol for her frequent appearances.
Republicans boosted their control of the House to 244-184 Tuesday; seven races are still too close to call or must be determined by a run-off election as of press time. House Majority Leader Kevin McCarthy (R-Calif.) said after the election that he will call for votes later this month on legislation that would require the EPA to make public additional scientific data to justify new regulations.
With Sen. Mitch McConnell (R-Ky.) the presumptive replacement for Nevada Democrat Harry Reid as Senate majority leader, Lisa Murkowski (R-Alaska) taking the chairmanship of the Energy and Natural Resources Committee and climate-change denier James Inhofe (R-Okla.) likely heading the Environment and Public Works Committee, “You’ll see a high level of pressure being put on the EPA,” said Joy Ditto, vice president of government relations at the American Public Power Association.
Republicans hold a 52-44 edge over Democrats in the Senate. (Two independents caucus with the Democrats; Mary Landrieu (D-La.) is facing a runoff election on Dec. 6; and Alaska Democrat Mark Begich is trailing in his race by about 8,000 votes, with an estimated 50,000 absentee and other ballots yet to be tallied.)
EPA’s Clean Power Plan “is the number one oversight target for these committees,” Scott Segal, who heads the Policy Resolution Group at Bracewell & Giuliani, said in a post-election presentation.
Inhofe, who would replace California Democrat Barbara Boxer, has compared the EPA to the Gestapo and is the author of a 2012 book “The Greatest Hoax: How the Global Warming Conspiracy Threatens Your Future.”
Murkowski has called Alaska “ground zero for climate change,” acknowledging the state is experiencing warmer temperatures and thinner ice. But she said she is unsure of the cause. On election night, Murkowski told National Public Radio that a volcano in Iceland was producing “a thousand years’ worth of emissions that would come from all of the vehicles, all of the manufacturing in Europe.”
Her statement brought a sigh from Princeton professor Michael Oppenheimer, who told NPR that Murkowski’s assertion — an apparent reference to Bardarbunga, a volcano that began erupting in August — is untrue. Oppenheimer says annual emissions from Europe are 10 times more than the annual emissions of all volcanoes put together.
Coal to Gas Switch
The EPA has won praise from even opponents of the carbon rule for its outreach efforts with states and the industry. On Oct. 28, the agency responded to criticism of the proposed rule by indicating it might consider a slower shift from coal to natural gas generation. The agency heard objections from coal-dependent states, which said the proposed interim goals might threaten electric reliability and require utilities to abandon coal generators that they recently retrofitted to meet previous EPA regulations. (See EPA Signals Flexibility on Interim Carbon Targets, Coal-Gas Shift.)
“It’s not like farm commodities, where you switch from pigs to chickens” quickly, said Patrick Kiely, CEO of the Indiana Manufacturers Association. Because manufacturing represents 30% of its gross state product — higher than all states — Indiana is particularly sensitive to electricity prices.
Segal said he anticipates tailored legislation such as riders on spending bills and use of the Congressional Review Act, which allows lawmakers to review and even block major rules by federal agencies before they take effect.
“The president would be confronted with a choice,” Segal said. “Do I essentially shut down the EPA or do I work with the Republicans in the House and in the Senate to reform my proposal?”
To nullify the EPA rule under the CRA, however, Republicans would need to win defections of about 46 Democrats in the House and 15 in the Senate to overcome a veto.
A veto override is more likely for legislation calling for approval of the Keystone XL pipeline.
New Senate Leadership
The switch in Senate control will reduce Reid’s influence over appointments to the Nuclear Regulatory Commission and Federal Energy Regulatory Commission. (See Norris Departure Opens Another FERC Seat.) It also will increase the stakes for wind power supporters hoping to win renewal of the Production Tax Credit for renewable energy during the lame duck session.
McConnell has called the administration’s quest to cut carbon dioxide emissions a major threat to Kentucky’s coal industry. But he acknowledged it will be difficult for Republicans to undo the rule.
“It will be hard because the only good tool to do that … is through the spending process, and if [Obama] feels strongly enough about it, he can veto the bill,” McConnell told the LexingtonHerald-Leader. “But I view it as a complete outrage that he could not get cap-and-trade through the Congress when he owned the place — owned the place — and decided to do it anyway.”
Although cap-and-trade is not required by the EPA rule, many experts say regional programs such as RGGI, a carbon-trading plan among the Northeast and Mid-Atlantic states, may provide states the cheapest path to compliance. The EPA estimates total compliance costs of $7.5 billion in 2020 (2011$) if states meet the requirements individually, versus $5.5 billion if all states take a regional approach. (See EPA Rule Boosts Regional Compliance, Cap-and-Trade.)
Pennsylvania’s Choice
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While the EPA will set the standards, it will be up to the states to figure out how to achieve them. The agency outlined four “building blocks” that could be part of a plan, including improving the efficiency of electric generators; increased reliance on renewables; less carbon-intensive generation; and improved energy efficiency.
Pennsylvania Governor-elect Tom Wolf won election after campaigning on a promise to reduce greenhouse gas emissions and promote development of clean energy in a state where coal and gas have reigned.
Wolf pledged to join RGGI but may face opposition from Pennsylvania’s Republican-dominated General Assembly.
Earlier this year, the legislature passed a bill that would require the state Department of Environmental Protection (DEP) to obtain legislators’ approval before submitting a state plan to the EPA. “Simply put, we cannot allow federal or state regulators the unilateral ability to make these terribly important decisions that will greatly influence our state,” state Rep. Pam Snyder, a Democrat, said last summer.
The Natural Resources Defense Council has dismissed the law as “political theater,” noting that it allows lawmakers to delay, but not block, the DEP from submitting a plan to the EPA.
The law at least gives the General Assembly an opportunity to review the plan and provide input rather than leave it to whims of state or federal regulators, said Adam Pancake, executive director of the Pennsylvania Senate’s Republican-controlled Environmental Resources and Energy Committee.
The state balked at joining RGGI several years ago over concerns that it would constrain future growth and that the state didn’t get enough credit for baseline emissions, said Derek Furstenwerth, senior director of environmental services at Calpine.
Pennsylvania’s decision to join or not will be “very influential,’’ Furstenwerth said last week during a panel discussion at the Energy Bar Association’s mid-year conference in Washington. “Without Pennsylvania, I’m not sure how you’d have Ohio or West Virginia or Virginia join,” he said.
Former DEP Secretary John Hanger, now an attorney at Eckert Seamans, said Wolf could reach an agreement with Republicans to join RGGI. Hanger noted bipartisan success in passing a number of environmental regulations over the years. The state is not only a “powerhouse” in coal and natural gas but also No. 2 in nuclear power and among the top 15 ranking for renewables, he said.
Fracking Votes
Fracking was also an issue on ballots in Pennsylvania — Wolf has called for a 5% severance tax on natural gas drilling in the state – and at least three other states. In Ohio, voters rejected three of four local fracking bans, while prohibitions were approved by Denton, Texas, and two California counties, San Benito and Mendocino.
Meanwhile, fracking advocates say Republican gains in New York’s Senate may put more pressure on Gov. Andrew Cuomo to end a moratorium on drilling.
Room for Bipartisanship?
Consultant Jeff Navin, onetime aide to former Sen. Tom Daschle, told Bloomberg News that Republicans will be under pressure to move beyond “message votes” and pass legislation that Obama can sign.
“There will be increased pressure on Republicans to legislate and to make Congress functional, especially given what’s at stake in 2016,” he said.
Some observers see the potential for agreement on a bill by New Hampshire Democrat Jeanne Shaheen and Ohio Republican Rob Portman, which seeks to boost energy efficiency for residential and commercial buildings.
Nuclear power also could find bipartisan backing. The resource, which has traditionally enjoyed Republican support, has gained some environmentalist allies because of its role as a baseload source of carbon-free generation.
And while many Republicans oppose subsidies for wind, others from rural areas that are home to wind farms have been supportive of the PTC.
Ditto said she hopes to see bipartisan support for provisions to help expand pipelines and storage to accommodate growing use of natural gas for power generation. That includes a favorable permitting climate needed to make such investments. “That’s one of our key concerns with the Clean Power Plan,” she said.
Rich Heidorn Jr. contributed to this article from Washington.
William R. Mayben will retire next year after serving seven years on the PJM Board of Managers. PJM announced last week that Mayben would remain in his position until a successor is named at the May 2015 PJM Annual Meeting.
The Nominating Committee will seek a successor to serve the remainder of Mayben’s term, which expires in 2016. Under the PJM Operating Agreement, the replacement must have “expertise and experience in the operation or concerns of Transmission Dependent Utilities.”
Mayben was president and CEO of the Nebraska Public Power District from 1995 to 2002. Before heading the Nebraska PPD, he spent more than 30 years at R.W. Beck & Associates, an engineering and management consulting firm, rising to managing partner and CEO.
A 1962 electrical engineering graduate of the University of Colorado, he is a former member of the board of directors for both the American Public Power Association and the Large Public Power Council.
The joint operating agreement between PJM and Duke Energy Progress should be revised to reflect the 2012 merger between Duke Energy and Progress Energy and eliminate Progress’ favored treatment on interchange pricing, according to the RTO’s Independent Market Monitor.
The Monitor filed a protest Oct. 24 urging the Federal Energy Regulatory Commission to reject PJM’s revisions to the agreement. The Monitor said PJM should terminate the existing agreement and negotiate a new one.
“The merger plainly creates material changes to the circumstances reflected in the PJM-Duke Progress JOA, yet there is no indication that any negotiation has occurred,” the Monitor said. “The assumptions reflected in the current PJM-Duke Progress JOA no longer apply, and the proposed revisions are not an adequate response.”
Progress Energy Carolinas (PEC) — now Duke Energy Progress — which serves the western portion of North Carolina, signed the JOA with PJM in 2005.
With the merger, Duke assumed control of most of North Carolina’s utility business, as its subsidiary Duke Energy Carolinas (DEC) already covered the state’s eastern portion. The two utilities signed a joint dispatch agreement as part of the merger.
This creates a conflict with PJM’s Operating Agreement, according to the Monitor.
PJM has a single pricing point for all transactions south of its territory that establishes default prices between the RTO and other balancing authorities. In 2010, however, PJM and Progress revised their JOA to allow for special dynamic pricing between them. PJM’s OA (Section 2.6A) allows dynamic pricing with a neighboring balancing authority as long the latter does not trade energy with other neighboring balancing authorities. The single pricing point was established to prevent market participants from gaming price differences between interface pricing points by scheduling transactions that do not reflect true system flows, the Monitor said.
“Because the [joint dispatch agreement] provides for joint optimization between the Duke Progress and DEC balancing authorities, there is, by definition, a continuous flow of energy transactions between the balancing authorities,” the Monitor said.
The Monitor urged FERC to direct PJM and Duke to create a new JOA and, in the meantime, apply OA rules concerning joint dispatch to transactions with the two utilities.
The Monitor’s complaint reprises an argument it has been making since at least 2010, when it criticized PJM for “singling out PEC for special treatment at the expense of movement forward to create a comprehensive approach to seams at PJM’s southern boundary.” (ER10-713) (See FERC Rebuff of Duke Could Mean Closer Ties with PJM.)
PJM’s revised JOA updates the name of Progress Energy Carolinas and adds an appendix that provides uniform transmission line identifiers for both parties, in compliance with a North American Electric Reliability Corp. reliability standard (TOP-002-2.1b, R18).
Jason Barker of Exelon (L) looks skeptical, James Wilson, a consultant to state consumer advocates (R), appears amused, as Tom Graves, of Burns & McDonnell speaks to the PJM Market Summit on the RTO’s response to extreme weather.
PHILADELPHIA — Operational challenges and costs may limit the ability of generators to obtain the level of reliability envisioned in PJM’s Capacity Performance proposal, power industry experts said last week.
At the PJM Market Summit in Philadelphia, industry officials cited a range of obstacles to PJM’s plan, which some called an overreaction to the generator outages of January:
Operators of advanced turbines are reluctant to add dual-fuel capacity because of higher maintenance costs and limited operating history.
Neither turbine manufacturers nor insurers are offering a way for generators to insulate themselves against nonperformance risk.
Dual-fuel generators lacking fuel storage tank farms would likely need to be connected to a fuel terminal.
Force majeure clauses common in the natural gas industry mean even generators with firm transportation contracts may be exposed to nonperformance penalties.
Megan Parsons, development section manager for engineering and construction management firm Burns & McDonnell, said PJM’s emphasis on backup fuel capabilities will benefit reciprocating engines and aeroderivative and E-class turbines. But owners of advanced F-, G-, H- and J-class turbines have been hesitant to employ dual-fuel capability because of higher maintenance costs and limited operating history.
“Because it’s expensive to test fuel oil, none of the OEMs [original equipment manufacturers] have lots of fuel oil test hours and don’t expect to get a lot of fuel oil test hours,” she said. “So it’s going to be a bit of time before the industry really knows what those long-term maintenance implications are. All of the OEMs have or are planning fuel oil testing. They have tested successfully, reliably. But inherently with higher firing temperatures there are higher maintenance implications.”
Combined-cycle “units are very, very large and use a lot of fuel,” added Parsons’ colleague, Tom Graves, senior project manager for Burns & McDonnell. “You’re looking — for 48 hours of operation — [at] a 5 million gallon tank. That’s a lot of money and capital sitting there unused.”
150-MW Peaker Analysis
Graves said an analysis he performed for a PJM generation owner found that retrofitting an F-class simple-cycle unit would cost $50 to $100/kW, or $7.5 million to $15 million for a 150-MW peaking unit. The 1 million gallons of fuel oil needed to run for 48 hours would cost about $4 million, he said.
“So you’re potentially $12 [million] to $20 million into this thing before you ever ran a single hour,” he said. “Forget the logistics of getting 7,500-gallon trucks to your facility to refill 300,000 gallons of usage over a single day. That’s 45 trucks a day. You have to be close to a terminal and you’re going to have to have a wholesaler or marketer that can provide 45 trucks worth of diesel in a very short period of time … so you really are probably looking at a pipeline connection to a terminal.”
In addition, generators may be able to operate on oil for only 40 or 50 hours annually without triggering the Environmental Protection Agency’s new source review rules, he said.
In comparison, Graves said, a firm gas contract for $8 to $16 per dekatherm-day would cost $2.5 million to $5 million annually.
Firm Gas Option
PJM’s Mike Bryson, executive director of system operations, acknowledged fuel storage is a big challenge.
“It’s one of the reasons that coming up with a firm gas alternative may still be financially better off,” he told the summit audience of about 60 at the Philadelphia Sheraton Downtown hotel. “We want to talk to the gas industry and say, ‘We need to figure this out. You may not have the product now but we need to come up with a product.’ Dual-fuel is very expensive.”
Force majeure provisions
Even generators with firm gas transportation contracts may be exposed to nonperformance penalties under PJM’s proposal because pipelines generally limit their liability with force majeure provisions.
Bryson said force majeure is one of the most contentious issues surrounding PJM’s proposal.
“I don’t even know if we have one staff position on force majeure. We might actually have three. So we haven’t figured it out,” he said. “We’re listening to people [on] this. That’s a big issue that the board needs to decide on in a couple of weeks.” (See related story, Coalitions Make Their Cases to PJM Board.)
Scott Harvey of FTI Consulting said gas generators are unlikely to contract for firm delivery.
“Go back and look at what [the Federal Energy Regulatory Commission] did after the gas crisis in California where there were gas-fired generators that had firm contracts for gas. And when FERC was looking for money to cushion the shock on the California ratepayers they took that money out of those contracts,” Harvey said. “No CEO in their right mind should ever sign a firm gas contract if they’re a merchant generator.”
Harvey said a cheaper alternative might be to offer industrial customers incentives to release their gas in a one-in-24-year weather event such as January’s polar vortex.
“How about once in 24 years we shut down 40 industrial plants for two days and make all that gas available? How does the economics of that lost production compare to the cost of building 12 new gas pipelines?” he asked. “There’s a lot of flexibility if you allow the market to work.”
Insurance, Warranties
Officials said neither turbine manufacturers’ warranties nor insurance offers enough coverage to protect generation owners from nonperformance penalties.
Parsons said turbine manufacturers offer some warranty coverage for unplanned events. “So I think there is an appetite for some of that. In general it gets to be: ‘Do the OEMS want to be an insurer?’ As of yet, fully, I think the answer has been ‘no.’”
Normal business interruption insurance comes with 30- or 60-day financial deductibles, said Jason Kahan, vice president with Energy Investors Funds of New York.
“I don’t think you’re going to be able to find an insurance product that’s going to [protect] you” if your plant is out of service for one or two peak days in winter or summer, he said. “What’s that number for a large combined-cycle facility? $100 million? I don’t think [coverage] exists and without a doubt the insurance market isn’t deep enough now.”
“With these complex types of products and these kinds of numbers, you’re buying a right to litigate. That’s what you’re buying,” said attorney John J. McAleese III, of McCarter & English in Philadelphia. “You’re not actually buying insurance. They’re in the premium-collection business. It pays for them to litigate before they pay” large claims.
Kahan said PJM’s rules will make financing new generation more complicated and expensive.
“Banks are going to require either higher interest rates or more equity as part of the overall capital structure. It’s going to further drive capacity prices up because if you want to build it you’re going to have a higher [rate of return] because of that risk premium.”
Overreaction?
Some summit speakers said PJM’s proposal is an unnecessarily expensive response to a very unusual weather event.
Graves called PJM’s proposal “a bit of a knee-jerk reaction,” saying he sees the locational value of Capacity Performance as similar to that for black start capacity.
He noted that gas-supply problems during January were limited to areas with insufficient pipeline capacity. Focusing on location-specific fuel-supply problems could improve reliability at a much lower cost, he said.
“There’s specific regions on the grid where black start generation is valuable and there are other locations where it provides no value. There are going to be specific places on the grid where [firm fuel] products are valuable and [others] where they aren’t. Six, eight months isn’t enough time to really understand the issue and plan for it.”
James Wilson, consultant to state consumer advocates, said PJM failed to exploit energy conservation measures that could have provided breathing room in January.
Wilson said PJM’s product will create “a private club with very strict eligibility and entrance requirements” and new market power problems that cannot be effectively mitigated.
“Sellers will have numerous reasons for not offering Capacity Performance, or only offering it including a lot of investment and risk in their offer. I really don’t think PJM or the Market Monitor is going to be in the position to go through and verify and critique and disagree with those reasons,” he said. “Only a small amount of Capacity Performance eligible — or potentially eligible capacity — really has to be withheld to [make] the Capacity Performance price very high.”
Beginning in January, gas generators will be able to change their offers to reflect fluctuating fuel prices, under a proposal approved by the Operating Committee last week.
