Page 1652 – RTO Insider

February 25, 2014

EPA Regs, Low Prices Raise Reliability Concerns at NARUC

WASHINGTON — PJM and other grid operators will face unprecedented reliability challenges in the next several years as federal environmental regulations and low energy and capacity prices threaten to sideline baseload coal and nuclear capacity, federal and PJM officials told state regulators.

“The next two, three years, I just hope energy is not on the front page every single day,” Federal Energy Regulatory Commissioner Philip Moeller told the National Association of Regulatory Utility Commissioners winter meeting, shaking his head. “If you’re up for excitement, the next two, three years will be very exciting.”

MATS, Coal Ash, GHG, Cooling Water Rules

Moeller cited the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) and pending EPA rules on coal ash and greenhouse gas emissions. More than 30 GW of coal-fired capacity retirements have been announced nationwide, with about three-quarters expected by 2015, when MATS takes full effect. (See sidebar: State Regulators Await GHG Rules.)

PJM CEO Terry Boston and others also cited EPA’s pending regulations on cooling water intakes, which will affect nuclear and fossil steam generating units representing more than 80% of U.S. generation, according to the North American Electric Reliability Corp. The greatest impact will be on more than 1,200 generators with once‐through cooling water systems, NERC said.

Boston said he was most concerned about the impact of the rules on the nuclear fleet, citing an estimated cost of $400 million to $500 million per plant to install closed-cycle cooling systems.

David Owens, executive vice president of the Edison Electric Institute, said it could cost the industry as much as $100 billion to comply with the regulations.

“I hope that the [EPA] air division is talking to the water division,” Moeller said. “There are so many [regulations] coming. I’m fuel neutral … but we can’t be reliability neutral.”

John Shelk, CEO of the Electric Power Supply Association, echoed Moeller’s concerns, saying, “I worry a lot about the next five to 10 years.”

Markets’ Impact on Reliability

Several speakers also voiced concerns that energy and capacity markets in PJM and other RTOs aren’t providing enough revenue to sustain nuclear generation, which is unaffected by most of the new EPA regulations.

“Right now competitive markets are not working and that’s why we’re losing nuclear plants,” said Marvin Feitel, president and CEO of the Nuclear Energy Institute.

EEI’s Owens agreed. “I think it would be a travesty if we lost a large number of nuclear plants because we don’t have sustainable price signals,” he said.

Owens said the markets’ treatment of demand response was partly at fault. “I think [DR] gets paid too high a price because I don’t think it’s the same as steel in the ground,” he said. “Right now we’re shutting down plants that [should remain operating] because of market distortions.”

FirstEnergy CEO Tony Alexander said competitive markets are flawed because they encourage excess capacity.

“Those of you in regulated states would never put your states at risk the way we are in PJM and other competitive markets,” he said.

PJM’s Boston defended the RTO’s market rules but conceded that the current low prices are “not sustainable.”

“The markets aren’t broken, but furiously competitive,” he said.

Gas-Electric Dependencies

FirstEnergy’s Alexander also called for changes in the relationship between the electric grid and natural gas pipeline system.

“You can’t have the electric system at the tail being wagged by the pipeline system. That’s what we’re building today,” he said.

Commissioner Moeller said two consecutive warm winters “masked our vulnerability” to gas supply shortages, vulnerabilities that were exposed during last month’s arctic cold. FERC will hold a technical conference April 1 to discuss operational and market issues raised by the grid’s response to this winter’s cold. (See related story: Technical Conference Set on Winter Reliability.)

February 25, 2014

NYISO Scheduling Product Wins FERC OK

The Federal Energy Regulatory Commission approved a new product designed to reduce uneconomic power flows between PJM and NYISO.

The commission’s orders (ER14-623 and ER14-552) allows Coordinated Transaction Scheduling (CTS) to begin as soon as November if stakeholders are satisfied with the accuracy of the forecasts the product will use.

According to PJM, power often flows into NYISO even when prices are higher in PJM. CTS, which is based on a price projection algorithm, will allow traders to submit bids that would clear only when the price difference between New York and PJM exceed a threshold set by the bidder. (See New NYISO Product OK’d.)

Before beginning to use the product, PJM will be required to post monthly price forecasts from its Intermediate Term Security Constrained Economic Dispatch (IT SCED) application from November 2013 through April 2014 and win a stakeholder vote approving the tool’s accuracy.

CTS trades will be in addition to two current options: hourly evaluations of traditional wheel-through transactions and intra-hour evaluations of traditional LMP bids and offers.

February 25, 2014

Senators Weigh in on Bay Nomination, PTC, Nuclear Waste

WASHINGTON — Senators told state regulators they had little hope of passing comprehensive cybersecurity legislation or finding a solution for the nuclear waste stalemate this year.

Four members of the Senate Energy and Natural Resources Committee gave the National Association of Regulatory Utility Commissioners an update on the prospects for legislation affecting the grid and made their cases on subjects including the wind Production Tax Credit, greenhouse gas rules and Norman Bay, President Obama’s nominee for the Federal Energy Regulatory Commission chairmanship. (See sidebar: Senators Cite PJM in Reliability Concerns.)

Senator Mary Landrieu — Sen. Mary Landrieu (D-La.)

Sen. Mary Landrieu (D-La.), who replaced Oregon Democrat Ron Wyden as chair of the energy panel, promised “a very balanced and common sense” approach that she said reflects her state’s role as both a big producer and — due to its industrial production — consumer of energy.

Also speaking was Arkansas Democratic Sen. Mark Pryor, a mentor to NARUC president Colette Honorable.

Pryor, who serves on the Communications, Technology and the Internet Subcommittee, said he no longer expects Congress to pass a single, comprehensive cybersecurity bill. “I think it’s more likely we’ll do it section by section, committee by committee,” he said, referring to committees with jurisdiction over energy, banking and telecommunications. “I’m hoping we can get some of that done this year.”

Sen. Lamar Alexander (R-Tenn.) spoke out against extending the PTC, which expired Jan. 1, saying it contributed to negative energy prices, which undercut the viability of nuclear power. “It props up renewable energy at the expense of reliable energy,” Alexander said.

Carbon Capture

Senator Lamar Alexander — Sen. Lamar Alexander (R-Tenn.)

Alexander also called for simplifying the tax code, eliminating fuel-specific energy subsidies and doubling spending on energy research, which he said could make carbon capture and sequestration (CCS) cost competitive.

Sen. Joseph Manchin (D-W.Va.) touted a bill he sponsored with North Dakota Republican Sen. John Hoeven that would essentially bar the Environmental Protection Agency from requiring CCS in new coal-fired generators. The bill would instead base emission standards on those achieved by the six cleanest coal plants currently operating. “If [the standard is] not obtainable it’s not reasonable,” Manchin said.

Norman Bay Nomination

Senator Joseph Manchin — Sen. Joseph Manchin (D-W.Va.)

Manchin and Alaska Republican Sen. Lisa Murkowski — who helped sink Ron Binz’ FERC nomination last year — said they were keeping an open mind on the new nominee, FERC enforcement director Norman Bay. (See FERC Pick a Blank Slate.)

“Don’t know much about him. We’re going to look him up pretty good,” Manchin told reporters after his speech.

He offered unsolicited support for Honorable, the Arkansas regulator whose name had circulated in the capital earlier as a potential FERC candidate. “She has the chops to get it done,” he said, adding, “There’s a lot of good candidates.”

Murkowski, the ranking Republican on the energy panel, told reporters she was surprised Obama nominated Bay to the FERC chairmanship rather than promoting a current commissioner. “It didn’t work out so well for Mr. Binz,” she said.

She said she also has “a little concern” about Bay having to recuse himself in commission votes because of his involvement in enforcement cases.

Nuclear Waste

Senator Lisa Murkowski — Sen. Lisa Murkowski (R-Alaska)

Murkowski expressed frustration that energy efficiency legislation, which she thought would be “low-hanging fruit,” instead “has gotten caught up in the process.”

Members are awaiting a Congressional Budget Office cost estimate on a bipartisan bill co-sponsored by Murkowski and Alexander that would create a new nuclear waste administration and a consent-based process for siting waste facilities.

Alexander said the bill has reached near consensus, with “one or two things we don’t agree on.”

But Murkowski said she wasn’t optimistic it would move quickly. “It’s probably up against the clock in this 113^th Congress,” she said.

Alexander said the Obama administration should also renew work on Nevada’s Yucca Mountain. But Energy Secretary Ernest Moniz, speaking to the conference later, said the administration believes Yucca is “not a workable solution.” The proposed waste site, 100 miles north of Las Vegas, is opposed by many in the state, including Senate Majority Leader Harry Reid (D-Nev.).

February 25, 2014

Company Briefs

Ameren Chairman and CEO Thomas Voss will wind down his career by July 1, and is being succeeded by Warner Baxter, president and CEO of Ameren Missouri. Baxter has succeeded Voss as president of Ameren and on April 24 he will become CEO as Voss becomes executive chairman. When Voss retires from the board July 1, Baxter will succeed him as chairman.

More: Ameren

Calpine Still Plans to Sell Southeast Power Plants

Calpine still plans to sell some of its 10 Southeast plants, though its sale plans have gone more slowly than expected. Pending Environmental Protection Agency regulations should spur interest in the 5,236 MW portfolio, CEO Jack Fusco told analysts in an earnings call. The company may sell other plants, too. Now, Calpine is focusing on PJM. “I like where they’re headed, with transparency and competition in trying to level the playing field there, and I think you should expect that to be a real focus of ours,” Fusco said.

More: Utility Dive

Duke Explores New Model As ‘Trusted Energy Adviser’

Duke Energy aims to create a “trusted energy adviser” business model as new challenges face the industry. The company is exploring new business areas, Denis Garman, leader of Duke’s energy management and information solutions group in Charlotte, N.C., said. “We’re really trying to rethink our value proposition. … There are no apathetic customers – we just haven’t figured out how to deliver value to them in a way that resonates,” he said.

More: Utility Dive

FirstEnergy Closes on Sale Of Hydro Plants to LS Unit

FirstEnergy completed the sale of 11 hydropower stations to Harbor Hydro Holdings, a subsidiary of LS Power Equity Partners, for about $395 million. The plants, totaling 527 MW, are in Pennsylvania, West Virginia and Virginia.

More: FirstEnergy

February 25, 2014

Contrarian View: CERA Sees Higher Load Growth

WASHINGTON — For generators buffeted by low energy prices and unreliable capacity revenues, PJM’s General Session Feb. 12 provided something of a tonic.

Larry Makovich, vice president and senior advisor for global power at consulting firm IHS CERA, provided a bullish forecast for load growth for the more than 75 stakeholders and PJM officials who attended the session at the Hyatt Regency Washington near the Capitol. Another 55 — some perhaps dissuaded from attending in person by snowstorm forecasts — watched via webcast.

The low- or no-growth forecast of many analysts “is probably far too bearish,” Makovich said. “The fundamentals suggest we ought to be running 1.5 to 1.7% per year” load growth.

EIA, PJM More Bearish

That is substantially above the Energy Information Administration’s projection that U.S. power demand will grow by only 0.9% annually through 2040. EIA’s 2013 Annual Energy Outlook predicted increasing demand would be largely “offset by efficiency gains from new appliance standards and investments in energy-efficient equipment.”

PJM is projecting summer peak load growth of 1.0% annually over the next 10 years, and 0.9% over the next 15 years with winter peaks growing at 0.9% and 0.8% respectively. (The projection was revised this month to reflect a 120 MW reduction in the 2014/15 forecast peak for the BGE zone.)

While the “conventional wisdom” is that electric efficiency gains will result in little or no load growth, Makovich noted that after steadily improving between 1950 and 1970, U.S. electric efficiency stalled at about $3 of real GDP per kWh for the next 20 years. Since 1990, efficiency has declined, to about $3.50 of GDP per kWh.

Meanwhile, ratepayer spending on electric efficiency, which grew steadily from less than $1.5 billion in 2000 to about $6 billion in 2011, has been flat since then.

More spending in the future will be to keep the gains of the past, Makovich said. “The cost of increasing efficiency and the cost of supply are getting kind of close to each other.”

Load Growth by Sector

Similarly, electric use per customer is virtually unchanged over the past decade. Residential load growth has averaged 1.6% to 2.2% per year over the last decade while commercial load had grown by 2.4% to 3.4% annually. “What’s been going down is industrial” use, he said.

And that could change as a result of what Makovich called the U.S.’ “dramatically improved competitive position.” Since 2001, the U.S.’s industrial electricity prices have declined substantially relative to trading partners such as Mexico, China and Canada. Germany, which was at parity with the U.S. in 2001 now has rates that are more than twice as high.

Meanwhile, demand response, which has roiled the PJM capacity market, is nearing “saturation” in the U.S., said Julien Dumoulin-Smith, a UBS Investment Research analyst who also spoke at the session.

Distributed Generation

Makovich also challenged predictions that distributed generation will increasingly displace large generators owned by utilities and independent power producers.

While the growth of rooftop solar has generated much buzz, he noted, utility-scale solar is 50% cheaper and thus likely to dwarf residential applications. One-third of worldwide rooftop solar is in Germany, which Makovich noted has “the sunlight intensity of Anchorage, Alaska.”

Wind power is not well suited to distributed generation because of siting limitations and economies of scale. Manufacturers have obtained substantially greater efficiency as they have increased the average rotor diameter to 330 feet from less than 50 in 1980.

The costs of fuel cells and other storage technologies haven’t dropped enough to make a major difference, he said.

Makovich said fuel diversity is undervalued and being lost because wholesale power prices are too low. The low natural gas prices the U.S. has enjoyed as a result of shale gas shouldn’t obscure the fuel’s historic price volatility.

“Natural gas will remain cyclical and prone to periodic volatility as transportation becomes challenging,” Makovich said.

February 25, 2014

MRC/MC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage. RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM MANUALS (9:10-9:30)

The committee will be asked to endorse the following manual changes:

A. Manual 21: Rules and Procedures for Determination of Generating Capability — Revises rules and procedures regarding seasonal verification tests for steam generators. This includes the addition of a transition mechanism for generators that haven’t been conducting proper seasonal verifications. (See Transition Period OKd for Seasonal Verification Rules.)
B. Manual 7: PJM Protection Standards — Revises relay design parameters for line and substation transformer protection.
C. Manual 13: Emergency Operations — Revisions to demand response include new guidelines for pre-emergency and emergency DR.
D. Manual 11: Energy & Ancillary Services Market Operations — Clarifies tariff provisions regarding economic demand response settlements in energy market for load reductions that occur as part of normal operations.
E. Manual 40: Training and Certification Requirements — Revisions to update system operator training requirements in order to comply with NERC standards.

3. ENHANCED INVERTER CAPABILITIES (9:30-9:45)

The committee will be asked to approve a problem statement and issue charge to explore whether to require renewables such as solar PV to install “smart” inverters that can produce and absorb reactive power. With the increased use of renewable generation and retirement of many large traditional generation units, the need for reactive support is becoming increasingly important. (See `Smart’ Inverters May Give Solar Reactive Capability.)

4. GAS/ELECTRIC SYSTEM OPERATOR COMMUNICATIONS (9:45-10:00)

The committee will be asked to endorse proposed Operating Agreement revisions related to sharing of information between gas pipeline providers and electric transmission providers. (See FERC OKs Gas-Electric Talk.) This issue will also be considered for approval by the Members Committee (agenda item #5).

5. SYSTEM RESTORATION STRATEGY SENIOR TASK FORCE (SRSTF) (10:00-10:45)

The committee will be asked to endorse proposed revisions to Black Start compensation developed by the SRSTF. This includes the minimum incentive compensation proposal, which would replace the incentive factor in the black start base formula rate from 10% to the greater of 10% or $25,000. (See Black Start Unis to See More Green.)

6. REPLACEMENT CAPACITY (10:45-11:30)

The committee will be asked to endorse proposed Tariff and Reliability Assurance Agreement revisions related to replacement capacity. These changes will help eliminate arbitrage opportunities between the base residual and incremental capacity auctions. This issue will be considered for endorsement by the Members Committee (agenda item #6). (See Stakeholders Back PJM on Arbitrage Fix.)

7. COORDINATED TRANSACTION SCHEDULES (CTS)/EXPORT CREDIT REQUIREMENTS (11:30-11:45)

The committee will be asked to endorse proposed Tariff revisions associated with CTS and export transactions. CTS, a new product designed to reduce uneconomic power flows between PJM and NYISO, was conditionally approved by FERC on Feb. 20 and will not be available to traders until at least November. (See New NYISO Product OK’d.)

February 25, 2014

Federal Briefs

U.S. Supreme Court West Facade (Source: Wikimedia Commons)

The Supreme Court appeared divided Monday over whether the Environmental Protection Agency had gone too far in trying to regulate power plant and factory emissions of gases blamed for global warming. But the justices acknowledged their ruling would have little impact.

They agreed that the EPA has the power to regulate greenhouse gases. And even if the government loses the case, some justices said, it would make only a small difference in the number of facilities that could be regulated.

More: The Washington Post

Senators to CFTC: Share Trading data with FERC

Before he moved from the Energy and Natural Resources Committee chair to the Finance Committee chair, Sen. Ron Wyden (D-Ore.) and seven other Democrats asked the Commodity Futures Trading Commission to start sharing energy trading data on futures and swaps with the Federal Energy Regulatory Commission “expeditiously.”

More: Senate Energy Committee

CCS Could Raise Power Costs as Much as 80%

Use of carbon capture and storage technologies at coal-fired plants could raise the cost of electricity 70% to 80%, the Department of Energy’s deputy assistant secretary for clean coal told a House of Representatives energy subcommittee. A second generation of CCS technologies could lower that increase to between 40% and 50%, he said. “It is in fact a substantial percentage increase in the cost of electricity, but in part, that’s because the current price of coal is so low.”

More: BloombergBNA

Senate Seen Taking Up Efficiency Bill This Week

The Energy Savings and Industrial Competitiveness Act is slated to come up for a Senate vote this week. Better known as the Shaheen-Portman bill, the measure was sidelined last fall when Sen. David Vitter, R-La., attempted to use it as a vehicle for delaying Obamacare. The bill addresses building codes, research and incentives for using efficient products.

More: Huffington Post

USGS Interactive Map Shows 47,000 Turbines

The U.S. Geological Survey released an interactive map of more than 47,000 wind turbines installed in the U.S. as of July 2013. The data came from federal sources as well as state and local agencies, and the locations were verified using high-resolution imagery. “In addition to informing siting decisions for future wind energy projects, this fundamental, nationwide data will support research on wind generation efficiency, economic impacts and applied science for reducing wildlife impacts,” Assistant Interior Secretary Anne Castle said.

More: Interior Department

NRC Staff: Fuel Pools Safe; 34 Groups Differ

A study of a hypothetical earthquake’s impact on a nuclear plant led the Nuclear Regulatory Commission staff to conclude there is little risk that spent fuel pools at plant sites would be damaged. The study, conducted at Peach Bottom 3 in Pennsylvania, was part of the commission’s ongoing look into questions raised by the 2011 earthquake and tsunami disaster at Japan’s Fukushima plant.

Environmental groups, however, contend the study shows that the NRC should not license any more plants until reactor pool fire risks are studied more deeply. A petition by 34 environmental groups asks the NRC to require uranium fuel assemblies in spent fuel pools be moved quickly to above-ground storage.

More: LancasterOnline

February 25, 2014

Merchant Generation Remains Bumpy

Following the merchant generation industry can be confusing. Consider Orion Power Holdings, which went through four ownership changes in 12 years.

Orion was an upstart merchant generator formed in 1998. By 2001, it had 81 plants and drew the eye of Reliant Resources, a unit of Reliant Energy of Houston, which purchased it for $2.9 billion.

Reliant added merchant generator Mirant in 2010 to form GenOn Energy, Inc. GenOn, in turn, was acquired by NRG energy, a merchant generator which had clawed its way out of bankruptcy protection in 2003.

Musical Chairs in Boston

Another illustration of how dynamic the merchant generation business can be is the convoluted history of some plants in the Boston area.

In 1997, Boston Edison, deciding it didn’t want to be a merchant generator, sold six power plants to a startup merchant generation company called Sithe Energies. Sithe lined up financing to build large gas-fired combined cycle generators at two of the sites.

While Sithe’s plants were still under construction, the company was swallowed up by Exelon in 2002.

But in 2003, with construction deadlines long past without the plants coming on line, and natural gas price spikes making the projects less attractive, Exelon decided to call it quits.

“When investments do not work out as planned, we will not make it worse by throwing good money after bad,” said Exelon chairman and CEO John Rowe.

Upon Exelon’s exit, the plants came under the ownership of EBG Holdings in 2004.

EBG Holdings merged with Astoria Generating Co. to become U.S. Power Generating Co. in 2007. The Boston-area plants operated under the name of Boston Generating.

Bankruptcy

After Boston Generating fell into financial trouble in 2010, Constellation Energy Group bought the Boston-area plants for $1.1 billion at a bankruptcy auction.

By this time, natural gas prices had plummeted, power prices had surged, and the Boston plants were looking good. “We’re very pleased to have been named the winner in the auction for these well-managed natural gas assets, which will significantly expand our generation presence in a key competitive market,” Constellation said at the time.

Meanwhile, Exelon was casting about for ever-larger numbers of regulated retail customers in order to expand. A proposed takeover of PSEG collapsed in 2006 in the face of regulatory resistance in New Jersey. A year later, Exelon abandoned a hostile takeover of NRG Energy.

But in 2012, Exelon successfully completed the purchase of Constellation.

And once again, the Boston plants found themselves in the Exelon stable.

— Ted Caddell

February 25, 2014

‘Free’ Ride Over for UTCs? – Update

Financial marketers are pleased with PJM’s proposal to change the way uplift charges are assessed on virtual trades but aren’t convinced by a PJM analysis that the RTO says justifies extending the charges to up-to congestion trades (UTCs).

PJM told the Energy Market Uplift Senior Task Force (EMUSTF) last week it wants to change the way virtual trades pay for uplift, replacing the current unpredictable charges with a flat per megawatt fee and assessing them for the first time on UTCs.

PJM UTC Transactions Total Volume: Jan 2010 - Dec 2013 (Source: PJM Interconnection, LLC) — PJM UTC Transactions Total Volume: Jan 2010 – Dec 2013 (Source: PJM Interconnection, LLC)

The changes would create new dynamics for financial marketers, who have increased their trading in UTCs eight-fold since 2010 while increment offers (INCs) and decrement bids (DECs) have dropped by two-thirds. (See sidebar: Virtual Trading 101: INCs, DECs, UTCs.)

“We like the idea of a fixed fee. The volatility and unpredictability of the operating reserve charge has had a huge impact on the viability of INCs and DECs,” Ruta Skucas, counsel to the Financial Marketers Coalition, said in an interview. “I would assume that people would resume trading INCs and DECs” if the change is approved.

She said she was uncertain whether trading in UTCs would decline. “It’s also possible that some people may just increase their trading volume,” she said.

Monitoring Analytics, PJM’s Independent Market Monitor, called for assessing uplift charges on UTCs in its 2012 State of the Markets Report. But PJM told FERC last year that its analysis of the issue found that UTCs “have a significantly smaller impact on day-ahead unit commitment and dispatch than other virtual transactions.”

Under orders from the Federal Energy Regulatory Commission, PJM conducted a new analysis that concluded that UTCs — like INCs and DECs — affect generating unit commitments and thus can contribute to uplift costs.

PJM Analysis

PJM re-cleared its day-ahead energy market for four days in December and concluded that INCs and DECs resulted in a change of 3.1% in total unit commitments while UTCs were responsible for a change of 2.3%.

PJM said the virtual transactions should be assessed charges although it is impossible to quantify their exact impact on those charges.

“Similar to INCs and DECs, whether or not UTCs drive a more optimal solution in the Day-Ahead Energy Market will change on a daily basis and a precise determination of the direction and impact on resource commitment and dispatch by UTCs is virtually impossible due to the complexity of the Day-Ahead Energy Market and the interactions of the various different types of transactions,” PJM wrote in a report filed with FERC (ER13-1654).

The analysis found that INCs and DECs resulted in increased unit commitments. UTCs caused the de-commitment of certain units and their replacement with other units, “consistent with the energy neutrality of UTCs,” PJM said.

“However, there is not always a one-to-one tradeoff between committed and de-committed units when UTCs are removed, and the cost of the units being swapped are not always identical,” PJM wrote. “In some cases UTCs may be driving the commitment of lower cost resources in the day-ahead energy market because they are in the counterflow direction of transmission constraints and are therefore relieving congestion. In other cases the opposite will occur, and UTCs will impose forward flow on a facility in the day-ahead energy market and cause increased congestion and out-of-merit commitment and dispatch for constraint management.”

Market Monitor Analysis

In September, Market Monitor Joseph Bowring released an analysis that he said proved UTCs increase shortfalls in Financial Transmission Rights funding and disproved UTC supporters’ contention that the trades help price convergence.

While PJM says it is impossible to quantify the impact of UTCs on uplift, Bowring provided precise figures.

Over a five-day sample in May, Bowring said, FTR funding had a deficit of $4.4 million with UTCs versus a surplus of $22,000 with UTCs removed — a difference of $4.6 million.

In its 2012 State of the Market report, the monitor called for eliminating UTC transactions or making them responsible for day-ahead and balancing operating reserve charges.

The monitor said the RTO deviation rate for 2012 would have been reduced by 59% percent if UTC transactions had been included in the calculation of operating reserve charges.

PJM’s Plans

At Wednesday’s EMUSTF meeting, PJM Vice President of Market Operations Stu Bresler said the RTO will propose a flat per megawatt charge for all virtual transactions and eliminate the current variable allocation on INCs and DECs, “taking away the risk of unknown and volatile charges on the back end.”

PJM’s Dave Anders said the RTO will begin discussing the specifics of a future cost allocation with stakeholders in “Phase 2” of the task force’s work, which he said should begin in the “next month or two.”

Shake-up to Virtual Market?

PJM’s proposed change — which will face close scrutiny by financial marketers — would change the dynamics of virtual trading. (See MRC Defines UTCs; Adds Bid Limit and FTR Forfeiture Rule.)

Deviation charges per cleared MWh for INCs and DECs (Source: PJM Interconnection, LLC)

UTCs’ use has exploded since late 2010, when PJM removed the requirement that UTCs make transmission service reservations — thus removing them from a share of uplift charges. Trading in INCs and DECs declined over the same period because of what PJM called the “strong disincentive” caused by the unpredictable uplift charges they are assessed.

In 2013, INC and DEC transactions in eastern PJM paid a rate of $0.02/MWh to $33.02/MWh for deviations between the Day Ahead and Real-Time energy markets, with a mean of $3.20/MWh. Such trades in the west paid $0.02/MWh to $16.43.MWh, with a mean of $1.56/MWh. (See chart.)

“At the time rules for INCs and DECs were put in place, UTCs were not used in the speculative manner in which they are today and therefore were not included in the allocation of such charges,” PJM wrote. “However, given how the use of UTCs has evolved, it is evident, based on the fact that UTCs can shift the flow of power on the system, that they also can impact the resource commitment and dispatch of the system and consequently should be allocated a share of the applicable costs in addition to INCs, DECs and other bid and offer types that have similar impacts on the power system.”

Some stakeholders at last week’s meeting protested PJM’s reference to UTCs in the report as a “free transaction,” noting that they do pay administrative charges.

Independent Review Sought

Market Monitor Joseph Bowring pressed for PJM to institute uplift charges on UTCs immediately and not wait for the conclusion of stakeholder deliberations on a fixed-fee charge. “They’ve been getting a free ride for too long,” he said in an interview.

Skucas, however, said she would like an independent review of the analysis PJM cited in calling for uplift charges on UTCs. “We’re basing all this off five days in May and five days in December. Nobody else has had a crack at those numbers,” she said. “I would like to see a broader study… We have asked PJM to release the data so they can be analyzed by outside experts. They will not. They told us it’s a confidentiality issue.”

If uplift charges are assessed on UTCs, they must be small enough to preserve the thin profit margins on the trades, she said.

Previous Effort Failed

Financial marketers beat back an earlier attempt to assess uplift on UTCs when the Market Implementation Committee voted in September 2012 to terminate a task force to study the issue. The coalition cited a study by William Hogan, research director of the Harvard Electricity Policy Group that concluded there was no evidence UTCs caused uplift.

February 25, 2014

Duke Merchant Exit Signals `De-Integration’: Analysts

By Ted Caddell

The short history of merchant generation in the U.S. is strewn with the fragments of once high-flying Wall Street darlings that crashed and burned. Remember Sithe? Boston Generating? Orion?

And it’s not just small, under-capitalized operations or industry newcomers that have found the merchant generator model perilous.

Miami Fort Station (Source: Duke Energy)

Duke Energy Corp., the largest U.S. utility owner, announced last week that it no longer wants to be in the merchant generation business in the Midwest, and is selling its interest in 13 power plants in Ohio, Illinois and Pennsylvania.

Duke’s decision to sell 6,600 MW of generation — the bulk of its merchant fleet — came just days after the Ohio PUC refused the company’s request to bill regulated customers $729 million to make up for a shortfall between generation power costs and plunging wholesale power prices. The company said that it expects to take a charge of $1 billion to $2 billion from the sale, which they expect to close in 12 to 18 months.

Its decision to take a loss to get out of that part of the business came not just because of the shortfall.

Too Volatile

“Our merchant power plants have delivered volatile returns in the challenging competitive market in the Midwest,” said Duke Energy President and CEO Lynn Good. “This earnings profile is not a strategic fit for Duke Energy.”

Companies like to give investors what they want, and investors value certainty. A market that swings on fuel prices, volatile markets and weather is not certain.

It’s not just Duke that finds itself in the vise of high generation costs and low wholesale prices on the power market.

St. Louis-based Ameren Corp. exited the merchant generation business entirely late last year when it sold its five coal-fired plants in Illinois to Dynegy. It cited, in part, a desire to concentrate on its regulated – read more predictable – electric, natural gas and transmission operations.

FirstEnergy last month cut its dividend by more than one-third and announced a renewed focus on regulated operations after a year in which the company’s stock fell 20% on weak earnings from its unregulated unit. (See Reboot for FirstEnergy.)

Exelon, which cut its dividend by more than 40% a year ago, announced last month that it might mothball some of its nuclear stations in the face of what it says is unfairly subsidized renewable power and stiff competition from gas-fired generation. “Despite our best ever year in generation some of our nuclear units are unprofitable at this point in the current environment due to the low prices and bad energy policy,” Exelon CEO Chris Crane said. (See Exelon May Close Nukes.)

Julien Dumoulin-Smith, an analyst for UBS Investment Research, told the PJM General Session Feb. 12 that locational marginal prices at Exelon’s Quad Cities nuclear plant on the wind-rich Illinois-Iowa border were negative in more than 1% of the hours in 2013, with an average negative prices of -$15.35/MWh. For all hours, average LMPs were less than $26/MWh.

De-Integration

Dumoulin-Smith said the Duke announcement is further evidence of what he called the “gradual de-integration” of the industry, and predicted other publicly traded utilities will also withdraw from the merchant generation business to concentrate on their regulated businesses.

Paul Fremont, analyst with Jeffries & Company, wouldn’t draw industry-wide conclusions in the wake of Duke’s announcement, but said some companies have already indicated a strategy that doesn’t concentrate on merchant generation. “Dominion not going to increase exposure” in merchant generation, he said, “and I think PPL has indicated it may exit.”

Dominion is among the utilities that have scaled back their non-regulated businesses. It announced at the end of January that it was selling its retail electric business, perhaps by the end of this quarter. “The margins in the electric side of business have been shrinking,” Dominion CEO Tom Farrell said during an earnings conference call. “And you see increased volatility happening.”

Shrinkage Among IPPs?

The stresses faced by merchant arms of integrated utilities also face pure-play independent power producers. Before long, suggested Dumoulin-Smith, “there’s going to be three or four IPPs left…Maybe two?”

He said it’s conceivable that a merchant nuclear portfolio could drop below investment grade, suggesting a roll-up by an IPP would obtain a single B credit rating. But with debt so cheap, he said, “I’m not sure it matters a heck of a lot.”

Impact on Midwest Capacity

Duke’s exit plan, and Exelon’s warnings, comes on top of a wave of coal plant closures resulting from environmental regulations and low natural gas prices.

MISO late last year predicted a shortfall of 5 to 7 gigawatts of capacity in 2016-17 due to loss of coal-fired generation. A survey released this month, however, suggested the shortfall might be only 2 GW or less.

(See sidebar: Merchant Generation Remains Bumpy.)