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
(Click to zoom)
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.”
PHILADELPHIA — Calpine’s Joe Kerecman rarely speaks at PJM stakeholder meetings, but he was full of questions at last week’s PJM Market Summit. One issue he raised in at least two sessions concerned the 8% after-tax weighted average cost of capital (ATWACC) the PJM Board of Managers submitted following stakeholders’ Triennial Review of capacity auction rules.
The board filed proposed revisions to the capacity market parameters in September (ER14-2940) despite a lack of consensus among stakeholders. Members voted in August on five proposals, none of which won a supermajority. (See PJM Board Orders Filing on Capacity Parameter Changes.)
The filing has prompted protests from both load, which doesn’t like the proposed changes to the demand curve, and suppliers, which oppose PJM’s labor calculations and cost of capital.
Leading the opposition on cost of capital is the PJM Power Providers (P3) group, which told the Federal Energy Regulatory Commission it should use a 10.8% ATWACC, based on an analysis by PA Consulting, rather than the 8% recommended by PJM’s consultants, The Brattle Group.
The P3 group asked FERC to order a hearing to resolve this “disputed issue of material fact.” The Electric Power Supply Association endorsed P3’s filing. Calpine is a member of both groups.
Kerecman noted that the board used a capital asset pricing model (CAPM) based on the cost of capital for NRG, Dynegy and Calpine. “But Calpine is the only company of the three that’s actually building something in PJM. So of the 10 to 12 projects that are happening [in PJM], they’re all private equity, structured finance-type projects” with higher costs of capital, he said.
Eight percent is “certainly low,” responded Jason Kahan, vice president with Energy Investors Funds of New York. “Debt right now is still cheap even if you’re doing it on an individual project. A lot of projects are getting financed at LIBOR plus 350 [basis points]. All-in debt lending rates are around 6%. But do you want take risk from an equity perspective to build a new plant at 10%? I certainly don’t. That’s a pretty thin margin with all … that you can get wrong in terms of how your plant is going to get built and how it’s going to operate.”
“I think 8% for an [independent power producer is] relatively low,” agreed Jonathon Kaufman, managing director of investment banking at Credit Suisse. “Certainly 8% for a private equity sponsor is dramatically low.”
So why, Kerecman asked, have investors and bankers been silent on this debate?
Unlike a utility rooted in a region, “we’re more opportunistic,” Kahan responded. “If we don’t like what we’re seeing in PJM, we’re going to shift our attention to other parts of the country. … We have historically stayed out of those fights. You are right.”
Delaware City Refinery Drops Expansion Plan, Looking at NGLs Port Possibility
PBF Energy, owner of the Delaware City Refinery, has dropped plans for a $1 billion project to expand low-sulfur fuel production. But it is considering a $100 million investment to support cleaner fuel production and to export natural gas liquids such as propane.
PBF, in its quarterly earnings announcement, said the $1 billion hydrotreater project to produce low-sulfur fuels would have needed extensive permits. The company said it had already largely achieved production targets with improvements at its Delaware City and Paulsboro, N.J., refineries. It wrote off the value of $28 million in studies it had done to lay the groundwork for the project.
The idea of building a terminal to export NGLs at its Delaware River property, south of Wilmington, is in the early stages. There is a growing overseas demand for natural gas liquids, produced from shale-gas formations as well as refineries.
“We have a significant amount of property,” a PBF official said. “We’ve had some discussions with the state on it. I wouldn’t say they stood up and said, ‘This is the greatest idea we’ve ever heard.’” But he added that some parties are “very interested in doing it.”
Fuel cell producer Bloom Energy, a key part of Gov. Jack Markell’s economic development plan, fell short of hitting the workforce benchmarks it had agreed to under a $16.5 million state incentive grant.
Company filings from the end of September disclosed Bloom has 208 employees and an annual payroll of $9.55 million. The state grant called for 300 employees and a $12 million payroll. The company’s incentive payments are generated from a surcharge on Delmarva Power & Light bills that amount to about $5.84 a month for a typical residential customer.
Penalties won’t kick in until 2017 if the company continues to fall short, said Alan Levin, state economic development director. “While I’m disappointed they didn’t hit their number, I am not discouraged because I see them making steady progress,” he said.
Commission to Probe IPL’s Underground Network Failure
The Indiana Utility Regulatory Commission held a public meeting Monday to review reports examining the failure of Indianapolis Power and Light’s underground network in August.
IPL experienced a number of underground transformer explosions on Aug. 13, causing smoke to billow from street-level grates and forcing the evacuation of several downtown Indianapolis buildings. There were no injuries, but large parts of the downtown district went dark.
At a Monday hearing, the commission reviewed reports prepared by IPL and an independent consultant. IPL was investigated for similar blasts in 2010 and 2011.
The Board on Electric Generation and Transmission Siting is reviewing a proposal by SunCoke Energy South Shore to build a 90-MW power plant that would be fueled by gases from its proposed coke plant on the Ohio Rver near South Shore, Ky.
Coke, which is used in steelmaking, is produced by heating coal to burn off the volatile compounds. SunCoke proposes to capture the gases and use them to generate power.
Electricity would be fed to the grid through a 1-mile transmission line across the Ohio River to an American Electric Power substation in New Boston, Ohio.
Chesapeake Bay Cleanup Plan Needs to Include Conowingo
A report from the Maryland Public Policy Institute says that Maryland’s $14.4 billion plan to clean up the Chesapeake Bay to meet federal mandates ignores the effect of the single largest source of sediment flowing into the bay – Exelon’s Conowingo Dam.
The report says that most of the funds will be spent on reducing nitrogen pollution from sewage plants, septic systems and storm water outfalls, which account for only 7% of pollution. “If you decide that nitrogen is the bad guy,” and you wanted “to get rid of nitrogen in the most cost-effective way, why would you want to focus on only 7% of Maryland’s [nitrogen] source?” MPPI member James Simpson said.
The state’s plan was devised in response to a 2010 federal mandate to meet Clean Water Act standards.
U.P. Generation Shortfall, Rates Draws Crowd at Energy Summit
A looming energy crisis for the Upper Peninsula attracted an unusually large audience to Michigan’s annual Energy Summit.
More than 300 people came to Northern Michigan University in Marquette to hear about potential solutions to the crisis, which was triggered when We Energies proposed shutting down its Presque Isle plant after large industrial customers switched to different suppliers. MISO ordered the plant to stay open to protect system reliability. Michigan retail customers would foot the bill — up to $15 more a month per customer.
“I want people to understand that the problem is serious and avoidable, but in order to avoid it we need the participation of an awful lot of people … and [to] always [keep] in mind the impact on the residential ratepayers as well as the business,” said Valerie Brader, a senior policy advisor to Gov. Rick Snyder.
We Energies, based in Wisconsin, has said it would be willing to construct a new power plant if the Presque Isle plant closes. Other solutions include load control and energy efficiency.
BPU Offering Up to $3 Million for Energy Storage Projects
The Board of Public Utilities is offering $3 million in incentives to developers of energy storage systems associated with renewable-energy projects that provide on-site power to facilities.
The grants, up to $500,000 each, will spur power generators to develop energy storage capacity that builds up the state’s resiliency to blackouts. Such storage facilities are also seen as critical to resolving the issue of matching up consumer demand to the intermittent production from renewable-power generators.
The money comes out of the state Clean Energy Fund, which is financed by a surcharge on utility customers’ bills.
Piedmont Gas Granted Approval for Affiliate Agreements by State
The Utilities Commission approved agreements by Piedmont Natural Gas affiliates to sign up for a proposed natural gas pipeline that would run to the state from West Virginia. The Atlantic Coast Pipeline is a proposed 550-mile natural gas pipeline that would carry gas from the shale regions of West Virginia, Ohio and Pennsylvania.
The pipeline itself still needs regulatory approval from all the states on the route, as well as from the Federal Energy Regulatory Commission. Piedmont needed state approval because it is both a partner in the pipeline project and a proposed customer.
A pipeline carrying condensate from shale-gas wells in the state’s east to a gas processing facility in West Virginia burst and caught fire last week, burning for several hours before being brought under control.
The 8-inch pipeline carries natural gas condensate to Dominion Transmission’s Natrium Natural Gas Processing and Fractionation Facility. Condensates are valuable liquids likened to “natural gasoline” that are produced from some oil and gas wells. The accident caused no injuries or property damage, and the state Environmental Protection Agency said there was no sign of leakage into waterways.
The number of pipeline accidents has increased as the fracking boom has taken off in Ohio. There were 13 accidents last year, up from four in 2010. There have been 11 so far this year.
Future of PGW to be Addressed in Wake of Deal Collapse
The collapse of a deal to sell aging Philadelphia Gas Works to UIL Holdings has spurred the state Public Utility Commission to hold a session to address plans on what to do next with the nation’s largest municipal gas utility.
The one-day session will be on Nov. 14 at Drexel University and will focus on what to do about PGW’s high rates, crumbling infrastructure and programs for low-income customers.
The contentious $1.86 billion deal to sell PGW was engineered by Mayor Michael Nutter but scuttled by the city council last week. Nutter said the council’s killing of the deal without holding hearings or a vote was the “biggest cop-out in recent legislative history in Philadelphia.”
Corbett Vows to Protect Coal Industry if Re-Elected
Gov. Tom Corbett, trailing Democratic challenger Tom Wolf, promised voters in his state’s coal region that he will protect the coal industry if re-elected.
Corbett, in a speech in Plumcreek Township, said federal government regulation is hurting the state’s economy. “We need to get Washington and the [Environmental Protection Agency] out of our way so we can do more with the industry and continue to keep and grow our coal jobs that President Obama and his supporters are trying to kill in Pennsylvania,” he said.
Corbett also criticized his Democratic challenger for supporting a 5% severance tax on natural gas production.
“We’ve grown the natural gas industry from the fifth largest in the country to the second largest,” Corbett said. “We reduced unemployment from 8.1% to 5.7%, and we produced a balanced budget on time each of the four years I’ve been in office. When we didn’t have the money to spend, we didn’t do it. That’s what [Wolf] wants to do — tax and spend.”
Co-Op Wins Against Comcast in Pole Attachment Case
The State Corporation Commission ruled in favor of Northern Virginia Electric Cooperative, which was fighting attempts by cable giant Comcast to cut the rate it pays to use the co-op’s utility poles.
Comcast had sought to pay NOVEC according to the same formula used to compensate investor-owned utilities, but the SCC set a higher rate for the co-op. Comcast wanted to pay $7.16 a year for each NOVEC pole it used. A commission hearing examiner set the rate at $20.60. NOVEC has 52,000 poles.
“We asked to be fully compensated for providing space on our pole infrastructure to Comcast, and the rate determined by the hearing examiner, and affirmed by the commissioners, achieved most of what we were seeking,” said Stan Feuerberg, NOVEC president and CEO. Comcast said the higher cost would inhibit its ability to deliver broadband service in rural areas.
The Markets and Reliability Committee approved an initiative to ensure that generation fleet owners are properly compensated for reactive power and voltage control services as they add or retire generators.
The effort was prompted by the Federal Energy Regulatory Commission, which said there was no mechanism for obtaining refunds from fleet owners that may be collecting payments for retired plants.
“I think FERC wanted to make clear that the obligation was on the generator to” ensure it has filed updated rate schedules, MRC Chairman Mike Kormos said.
Members approved a revised problem statement including language suggested by Public Service Enterprise Group. PSEG’s Ken Carretta said the original statement assumed that fleet owners that haven’t filed revised cost schedules with FERC after plant retirements are being overpaid.
Carretta said when PSEG updated its rate schedule in 2008, its payments increased to $27 million from $9 million. “We built new units [and] made capital improvements. So it doesn’t necessarily follow that rates should go down,” he said.
PJM officials said they did not know how much ratepayers might be overpaying. “There have been a couple of occasions where this occurred,” PJM’s James Burlew said. “We know units have retired. We don’t know if these units are [still] being compensated.”
Carl Johnson, representing the PJM Public Power Coalition, wasn’t happy with PJM’s inability to answer the question. “It’s hard for me to explain to my members that we don’t know what we’re paying for,” he said.
The Markets and Reliability and Members committees approved the following Thursday with little discussion or opposition.
Markets and Reliability Committee
Manual Changes
Revisions to Manual 11: Energy & Ancillary Services Market Operations and Manual 28: Operating Agreement Accounting that will set the default Tier 1 synchronized reserves estimates to zero MW for nuclear, wind, solar, batteries and hydro generators. The change means those resources will not receive compensation unless they actually provide reserves during a spinning event.
Changes to Manual 1 to comply with a revised reliability standard given preliminary approval by the Federal Energy Regulatory Commission in September. COM-002-4 (Operating Personnel Communications Protocols) requires the use of a three-part communications process when issuing operating instructions. (See FERC Backs NERC, NAESB Standards.)
Revisions to Manual 14A: Generation and Transmission Interconnection Process that create a pre-application process for new and existing generation resource additions of 20 MW or less in compliance with FERC Order 792. Potential interconnection customers will have to submit a formal written request and a $300 processing fee. PJM is requesting these changes be effective beginning Nov. 1. (See PC Starts Work on Small Generator Interconnection Changes.)
Revisions to Manual 19: Load Forecasting and Analysis clarifying process for adjusting load forecasts due to significant load changes.
Conforming changes to Manual 18: PJM Capacity Market in response to members’ requests for details of the process for requesting and cancelling demand response maintenance outages and a FERC order allowing Annual, Extended and Limited products for DR (ER11-2288).
Transmission Owner Data Feed
Members approved Operating Agreement and manual changes to make it easier for transmission owners to access real-time generator data. The changes are intended to improve situational awareness and emergency response.
Winter Generator Testing
Members approved rules for voluntary winter testing of seldom-used generators. The tests would be limited to generators that haven’t run in the prior eight weeks and days when temperatures are below 35 degrees Fahrenheit. (See Winter Testing Could Cost $15.9M.)
IRM Set at 15.7% for 2018/19
Members approved a recommendation to leave PJM’s Installed Reserve Margin at 15.7% for planning year 2018/19, unchanged from 2017/18.
Manual 29 Revisions – Billing Adjustments
The committee approved a problem statement and issue charge on first read regarding revisions to Manual 29: Billing. The changes are intended to prevent cost shifting when miscellaneous items or special adjustments are underpaid.
Members Committee
Manual, Operating Agreement Changes
The MC endorsed revisions to Manual 11: Energy & Ancillary Services Market Operations and Manual 15: Cost Development Guidelines to correct a typographical error. The words “mileage ratio” will be replaced with “mileage” in Section 3.2.7 of Manual 11 and Section 2.8 of Manual 15, where the calculation of adjusted regulation performance cost is described.
Members revised the conflict of interest policy in the Operating Agreement to reflect the increasing number of consumer product companies, manufacturers and technology companies becoming involved in the electric industry. (See PJM Revising Policy on Prohibited Investments.)
Nominating Committee Elected
The MC elected the following to one-year terms as members of the Nominating Committee, which recommends candidates for the Board of Managers:
Electric Distributors: Steve Lieberman, ODEC
End Use Customers: Jackie Roberts, West Virginia Consumer Advocate Division
Generation Owners: Ken Foladare, IMG Midstream
Other Suppliers: Pati Esposito, American Wind Connection
Transmission Owners: Hertzel Shamash, Dayton Power and Light
Insufficient natural gas pipeline capacity is the top concern in ISO-NE’s 2014 Regional System Plan, which was released last week.
