UPDATED: FERC Action Awaited Following PUCO OK on PPAs

By Ted Caddell and Rich Heidorn Jr.

Having won Ohio regulators’ approval of their controversial power purchase agreements, American Electric Power and FirstEnergy now are hoping the PPAs will pass muster with FERC.

The Public Utilities Commission of Ohio on Thursday unanimously approved modified versions of two PPAs, which the companies said are crucial to keeping some of their underperforming plants running in the state (14-1297-EL-SSO and 14-1693-EL-RDR).

On Monday, AEP and FirstEnergy formally notified FERC of the approvals.

Competing merchant generators have asked FERC to revoke the waivers it granted AEP and FirstEnergy regarding affiliate power sales to ensure a Section 205 review of the above-market deals (EL16-33, EL16-34). (See PJM Joins EPSA’s Call for FERC Review of Ohio PPAs.)

In addition, 11 generating companies, including Calpine, Dynegy and NRG Energy, asked FERC on March 21 to expand PJM’s minimum offer price rule to prevent state subsidized plants from making below-cost offers that would suppress capacity prices (EL16-49). (See Generators to FERC: Expand MOPR for Subsidized FE, AEP Plants.)

The companies have asked FERC to rule before PJM’s next Base Residual Auction, which begins May 11.

Since PUCO’s ruling, seven organizations, including the Pennsylvania Public Utility Commission, the PJM Power Providers Group and CPV Power Holdings, have filed to intervene in the cases. On Monday, FERC denied AEP and FirstEnergy’s request for more time to respond to the MOPR filing, leaving the April 11 comment deadline intact.

Sale Likely?

Guggenheim Securities analyst Shahriar Pourreza said in a research note Thursday that he expects AEP to sell the remaining 5 GW of generation not covered by the PPAs, “a path for the company to move toward a fully regulated business profile.”

“We estimate the sale could generate $1.9 [billion to] $2.3 billion, which we expect to be redeployed into transmission to offset lost earnings,” Pourreza wrote.

For FirstEnergy, Pourreza said, the PPAs will strengthen its balance sheet without requiring the issuance of additional equity. “We see FE as a turnaround story with the PPAs approved,” he wrote.

The analyst said FERC is unlikely to change PJM’s MOPR “to apply specifically to AEP and FE’s plants.” The MOPR plaintiffs have asked FERC to order PJM to develop a long-term solution by Nov. 1.

PUCO’s approval appears to have had little effect on Wall Street. AEP has risen just 53 cents (0.8%) from Thursday’s open, closing Monday night at $66.58. FirstEnergy has dropped 37 cents (1%), closing at $35.68.

‘Rate Stability’

In approving the eight-year PPAs, Ohio regulators said they were striving for “rate stability” by building in safeguards intended to protect consumers, modifying the plans to limit bill increases. The commission also added provisions meant to “encourage” grid modernization and retail competition.

“The commission’s order strikes an appropriate balance between consumers’ interests in cost-effective electric service and diverse stakeholder interests,” Chairman Andre Porter said. “Today’s opinion and order affirms Ohio’s commitment to encourage a modernized grid and retail competition.”

Although the PPAs guarantee the generators receive revenue streams above current market prices, AEP and FirstEnergy contend the deals will save customers money if natural gas prices increase.

“The Public Utilities Commission of Ohio recognized the significant benefits of this plan for Ohio consumers. This plan will ensure more stable electricity prices in Ohio and promote the development of new, renewable generation to support the state’s economy,” AEP CEO Nick Akins said in a statement.

“Today’s decision will help protect our customers against rising electric prices and volatility in the years ahead, while helping to preserve vital baseload power plants that serve Ohio customers and provide thousands of family-sustaining jobs in the state,” FirstEnergy CEO Charles E. Jones said in a statement.

Opponents Denounce PUCO Ruling

Opponents of the plan were quick to respond to the decision.

“Today the PUCO failed more than 100,000 Ohioans who opposed the multi-billion dollar FirstEnergy and American Electric Power bailouts,” said Rachael Belz, executive director of Ohio Citizen Action. “Ohioans don’t want utilities raiding their pockets to prop up 18th-century technology in a 21st-century world.”

“The Alliance for Energy Choice is dismayed that the PUCO did not reject outright FirstEnergy’s and AEP’s demands to force consumers to pay unnecessary, additional electric charges of at least $6 billion over eight years,” the competitive energy supplier group said in a prepared statement.

“Anything short of rejection damages markets and competition,” tweeted former Pennsylvania PUC Commissioner John Hanger, now a private energy industry attorney. “Good for crony capitalism.”

Rate Freeze

The two utilities sought the long-term PPAs to provide guaranteed income for plants facing competition from cheaper gas-burning plants. Both companies had earlier reached settlements with PUCO’s staff and others, leading to Thursday’s rulings by the commission.

AEP’s plan calls for guaranteed income for the company’s 2,671-MW ownership share of nine plants, as well as a 423-MW contractual share of Ohio Valley Electric’s generating fleet, until May 2024.

FirstEnergy’s agreement provides similar guarantees for its 908-MW Davis-Besse Nuclear Power Station, the 2.2-GW W.H. Sammis coal-fired plant and the company’s 105-MW share of Ohio Valley Electric’s generation.

In both cases, ratepayers would make the generating units whole if capacity and energy sales in the competitive market were not sufficiently profitable. While the companies testified that the market would eventually prove profitable for their plants, the Ohio Consumers’ Counsel said the plans left consumers open to excess costs that could top $8 billion over the life of the deals.

“FirstEnergy’s Ohio utilities expect to file new rates with the PUCO by May 2, following the completion of a competitive auction process to buy electric generation supply for their non-shopping customers,” FirstEnergy said in a press release. “FirstEnergy expects that the vast majority of its Ohio utility customers will see lower total bills after these auctions.”

But Todd Snitchler, former PUCO chairman and now with The Alliance for Energy Choice, said FirstEnergy’s claim of static or lower bills is disingenuous.

“It’s not out of the goodness of their hearts,” he scoffed. “It’s because that’s what the commission said.”

PUCO’s order freezes FirstEnergy’s base distribution rates during the PPA and ensures that average customer bills will not increase for the first two years.

PUCO’s order on AEP limits rate increases to 5% during the first two years of the PPA. The company also promised $100 million in rate credits to reduce increases during the final four years.

Both companies originally requested 15-year PPAs, but they scaled back those requests in the face of opposition from consumer advocates and other merchant generators. The companies worked behind the scenes to construct settlements with some of the opposition, adding environmental incentives and consumer protections in exchange for their approval.

AEP won over the Sierra Club with a promise to double the state’s wind generation and nearly quintuple its solar capacity — translating into 900 MW of new renewable energy.

Criticism from All Sides

Critics see the agreements as an attempt at re-regulation in a deregulated Ohio electricity market, coming after the generating companies were already provided stranded cost compensation to give up their monopolies. FirstEnergy, for instance, was compensated for $6.9 billion in stranded costs in 1999.

But the companies say that times have changed and that the PPAs are crucial for keeping the plants operating and Ohioans employed.

The companies’ proposals were immediately met with protests from environmentalists, ratepayer advocates and rival generators in PJM, with Dynegy and Talen Energy threatening litigation to block the agreements. (See Merchant Generators Lead Opposition to FirstEnergy-Ohio Settlement.)

Even Exelon, which is seeking a similar deal for its own nuclear stations in Illinois, came out against FirstEnergy, and upped the ante by offering its own offer to Ohio. It called on PUCO to reject the FirstEnergy plan as “grossly lopsided” and offered to supply the 3,000 MW covered in the PPA with its own generation, at a proposed $2 billion savings to Ohio consumers.

March 29, 2016

Maryland PSC Member Scrutinized over Contacts with Governor

By Rich Heidorn Jr.

A newly appointed member of the Maryland Public Service Commission insisted Monday there was nothing improper about his emails with Gov. Larry Hogan’s administration, communications that critics say raise questions about his independence.

Richard Source: Maryland PSC — Richard *Source: Maryland PSC*

Hogan named Michael T. Richard, his former deputy chief of staff, to the PSC in a recess appointment in late January. Richard, a former director of the Maryland Energy Administration (MEA), is seeking Senate confirmation to a full term.

Shortly after his appointment, according to emails obtained through a public records request, Richard shared non-public information with Hogan’s administration regarding an offshore wind application and discussed strategy with the governor’s office on energy efficiency and community solar programs.

The emails were obtained by Public Citizen and the Energy and Policy Institute, which said the records showed Richard had engaged in improper ex parte communications and should not be confirmed.

At a hearing of the Senate Executive Nominations Committee on Monday night, Chairman Jamie Raskin expressed concern that Richard was “coordinating strategy” with Hogan’s administration.

Richard said his communications were merely an effort to brief members of the governor’s office on energy issues they were taking over from the “portfolio” he held before his PSC appointment. Richard did offer a mea culpa. “I am sorry that I created a doubt about my independence,” he said.

After an hour of questioning, Raskin adjourned without calling for a vote on the nominee, saying he would schedule another meeting next week.

Offshore Wind Application

On Jan. 29, Richard sent Hogan’s director of policy, Adam Dubitsky, an email regarding an application for offshore wind renewable energy credits (OREC). “This is NOT yet public information, but I wanted you to be aware,” he wrote.

Dubitsky responded by asking whether the filing preempts “our taking action to protect ratepayers from a potentially $1.7B rate increase as indicated in OREC’s fiscal note?”

Richard had been informed of the application in an email from an advisor to PSC Chair Kevin Hughes. The email noted that the application is supposed to be confidential during a 30-day internal administrative review and a 180-day period in which other developers can apply for the credits.

“It was designed this way because the application window is supposed to be equivalent to a closed bid process,” the advisor wrote.

At the hearing Monday, however, Richard said the information was not confidential and that PSC General Counsel Robert Irwin had approved his communication. “It was discoverable. It was available,” he said.

EmPower Maryland

A second communication that concerned some committee members came on Feb. 11, when Richard sent Mary Beth Tung, deputy secretary of the state Department of the Environment, an email discussing the administration’s position in upcoming hearings on the EmPower Maryland energy efficiency program.

The governor’s office is a party to the EmPower hearings through the MEA. The agency intervened in PSC dockets involving the program, noting that the state’s utilities are required to consult with the agency regarding the “design and adequacy” of their plans to achieve the electricity savings and demand reduction targets set by the 2008 legislation creating the program. The act requires that the PSC consider MEA’s comments on the utilities plans.

Richard wrote Tung regarding hearings scheduled for May to review the utilities’ performance in the second half of 2015.

“This will begin our first potential opportunity to begin putting our imprint on this significant energy tax policy,” Richard wrote. “This will be a significant and very public PSC action, so early governor’s office direction, planning and executive [branch] coordination on related policies will be important.”

Richard also offered Tung “policy advice” on the state community solar program, suggesting a shift from “grant-based” to “financing-based” energy efficiency and renewable energy incentive programs.

Business as Usual?

Like Hogan, Richard is a Republican. The Senate is controlled by Democrats.

Republicans on the committee said Richard’s communications were similar to those Hughes and then-Commissioner Kelly Speakes-Backman had in 2012 with the administration of former Gov. Martin O’Malley, a Democrat. Hughes was O’Malley’s deputy legislative officer before joining the commission.

“We’re beating a dead horse,” said Republican Sen. George Edwards.

But Democratic Sen. James Brochin told Richard the communications created “a reasonable question of who’s team you’re on.”

“I can assure you that I understand very well what it means to be a Public Service Commissioner and that it demands independence,” Richard responded.

March 28, 2016

MISO Markets Committee of the Board of Directors Briefs

NEW ORLEANS — MISO energy prices declined this winter along with loads and natural gas costs in the face of above-normal temperatures, RTO staff said during a March 22 Board of Directors meeting.

Real-time prices in the MISO footprint averaged $21.80/MWh, down 13% from the prior quarter and 29% from the same period a year ago. Average system-wide load fell 2.7% compared with last winter, with seasonal load peaking at 98.2 GW on Jan. 19, well below January 2014’s all-time winter peak of 109.3 GW.

“Part of the ease in making our way through the winter was the relatively mild temperature conditions,” said Jeff Bladen, MISO’s executive director of market design.

Bladen said the higher temperatures and historically low gas prices also reduced revenue sufficiency guarantee payments to “some of the lowest market uplift charges since 2012.” Uplift charges averaged $0.09/MWh, down from $0.23/MWh last winter and $0.46/MWh in 2014.

Natural gas costs should stay low in the near term, said Michael Wander, of MISO Independent Market Monitor Potomac Economics. Prices at both the Chicago City Gate and Henry Hub ended February under $2/MMBtu.

Other winter highlights:

MISO set an all-time wind output record of 13.1 GW on Feb. 19, surpassing the previous peak of 12.7 GW set a month earlier. For an hour, more than one-fifth of MISO’s power came from wind resources.
Coal generated 47.7% of electric production, down 25% since 2014. Most retired coal generation has been replaced by gas.

MISO board member Michael Curran said he wanted a review of MISO’s metrics, as so many “boil down to a dollar amount.” He worried that low gas prices could be “masking” uneconomic activity.

MISO Prepped for Summer Demand

MISO Markets Committee of the BoD — At the meeting *© RTO Insider*

MISO officials are concerned about tightening reserve margins despite a preliminary assessment showing that the RTO is comfortably positioned to meet demand this summer.

MISO is projecting an 18.2% reserve margin this summer, exceeding the 15.2% requirement and a slight increase from last year’s 18% margin.

Available supply, however, dropped to 149 GW from 150.3 GW.

MISO CEO John Bear said declining demand contributed to this year’s slightly higher reserve margin. He added that retirements driven by EPA’s Mercury and Air Toxics Standards were on par with the RTO’s predictions.

A final summer analysis will be presented at MISO’s Summer Readiness Workshop in May.

– Amanda Durish Cook

March 28, 2016

CAISO Seeks Rapid Response to SoCal Gas Restrictions

By Robert Mullin

CAISO has kicked off an “expedited” stakeholder process to help Southern California’s gas-fired generators mitigate the financial impact of proposed pipeline restrictions stemming from the closure of the Aliso Canyon gas storage facility.

The initiative seeks to identify what measures the ISO can implement to allow those generators to recover — or avoid — penalties for violating new daily balancing requirements that SoCalGas has proposed for the region’s pipeline system.

Under the requirements, any customer whose daily gas burn deviates from nominated pipeline flows by more than 5% would face per-unit penalties as high as 150% of daily gas indices. Generators say those penalty costs would put them out of the money in instances when the grid operator’s dispatch instructions force their units to burn more or less gas than scheduled.

Leak Forced Closure

SoCalGas and San Diego Gas & Electric asked state regulators to approve the requirements ahead of summer to support reliable gas delivery during the region’s peak season for electricity consumption. SoCalGas said it needs more precise scheduling to ensure proper pipeline pressure without the ability to backfill from Aliso Canyon.

The storage facility north of Los Angeles was closed following a leak that spewed massive amounts of methane between October and February.

Aliso Canyon Relief Well Source: SoCalGas (CAISO, gas restrictions) — Aliso Canyon Relief Well *Source: SoCalGas*

The new requirements are expected to take effect May 1, pending approval by the California Public Utilities Commission. That makes a rapid response essential for CAISO’s most exposed market participants, who worry about the costs they will incur in the period between that date and the implementation of any necessary ISO market mechanisms.

“The gap [in time] could be disastrous for us,” said NRG Energy Director of Market Affairs Brian Theaker during a March 23 teleconference to discuss CAISO’s response. “We’re very concerned about our exposure in that gap.”

For its part, CAISO supports the tighter balancing requirements as a way to prevent last-minute gas curtailments to generators called on to respond to unpredictable summer cooling loads.

“Depending on the scope of curtailment, the ISO’s ability to redispatch might be hindered,” said Mark Rothleder, CAISO vice president of market quality and renewable integration.

But CAISO also recognizes the reliability risks that come with the balancing penalties, which could deter some gas-fired units from committing to the short-term market when most needed.

“When it comes to commitment, that’s where we see the disconnect,” said Erik Johnson, principal energy trader with the city of Pasadena. “It’s not the hardest thing to figure out when a unit is going to be out of compliance with SoCalGas.”

Better Gas-Electric Coordination

CAISO is taking a twofold strategy in response, considering both ways to prevent pipeline penalties and revised rules to allow generators to recover the fines. Cathleen Colbert, CAISO senior market design and regulatory policy developer, said any solutions will be “interim” — lasting until Aliso Canyon reopens.

The first approach would seek to prevent pipeline penalties through improved coordination of ISO market instructions with gas balancing requirements. That could entail posting a “two-day-ahead” forecast to inform gas procurements as early as possible or moving the day-ahead market to earlier in the day in advance of the timely gas nomination cycle, when supplies are most liquid.

Market participants are skeptical about the effectiveness of those measures.

“The idea of doing a two-day-ahead forecast is appealing,” said NRG’s Theaker. “But in summer, when loads can get blown pretty high, that could leave you exposed.”

Generator participants also point out that earlier gas procurements — even in the day-ahead cycle — would incur additional costs that might not be recovered under current market rules.

“Does the ISO understand that Intra-day Cycle 3 [day-ahead evening gas procurement] requires storage?” said Pasadena’s Johnson. “We have the ability to procure for day-ahead, but we’ll be paying a premium.”

Johnson also noted that, under the new balancing requirements, it will be impossible to economically cover last-minute gas needs in light of a CAISO Tariff provision that caps gas cost recovery at 125% of daily gas indices.

“Get into the second half of tomorrow [real-time], and it’s going to be impossible to get gas,” Johnson said. “Any dispatch you force on us is going to put us outside the 5%. The 125% [cost cap] doesn’t give enough room.”

David Francis, vice president of West power for EDF, said it is difficult to obtain gas close to real-time operation, a potential strategy to avoid incurring overscheduling penalties. “The amount of volumes that are traded in the cycles after the daily are fairly limited,” he said. “It becomes more challenging to get more [gas] into the [Los Angeles] basin as you get into the cycle.”

Market Changes on the Table

CAISO’s second approach to the new requirements would require revising market rules, both to make dispatch more predictable and to allow generators to recover the cost of the penalties after the fact. Among the multiple options CAISO is putting on the table for stakeholder consideration:

Enforcing day-ahead commitments for all resource types as binding in the real-time market;
Constraining dispatch decisions around day-ahead market schedules;
Limiting real-time market instructions to exceptional dispatches (manually issued orders used when reliability requirements cannot be resolved through market software); and
Allowing resources to request outages to manage their fuel constraints.

Market-based solutions include allowing energy bids to reflect intraday gas prices and including the gas balancing penalties in bid cost estimates, both of which would likely require Tariff revisions. CAISO said it could ask FERC for a waiver of 50-day notice to expedite any such changes.

“Including these costs in the market optimization is great,” said NRG’s Theaker. “Not just including it in the market, but allowing generators to recover it [after the fact].”

Pasadena’s Johnson concurred: “After-the-fact recovery through [bid cost recovery] resettlement sounds more appropriate.”

Whatever the solutions, CAISO has set an ambitious schedule to arrive at an outcome. The ISO plans to issue a straw proposal on the subject April 1, with a draft final proposal scheduled for April 15. Final stakeholder written comments are due April 29. But even that aggressive timeframe is causing some discomfort among market participants.

“At the risk of stating the obvious, SoCalGas has asked for the daily balancing to be implemented May 1, and the stakeholder process runs right up to that,” Theaker said. “What does CAISO plan to do?”

“This timeline could be compressed even further,” said CAISO’s Colbert.

March 28, 2016

DOE Agrees to Join Clean Line’s Plains Eastern Project

By Tom Kleckner

The dream of transporting wind energy east from the Great Plains took a major step toward reality Friday with the U.S. Department of Energy’s approval of Clean Line Energy Partners’ Plains & Eastern project.

The Energy Department issued a record of decision, saying it would “participate in the development” of the 700-mile, HVDC transmission project and designated a preferred route through Oklahoma and Arkansas. The decision caps nearly six years of study and evaluation by the department.

Clean Line says the $2.5 billion, privately funded project will deliver 4,000 MW of wind power — enough to power more than 1 million homes — from the Oklahoma Panhandle through Arkansas to the Mississippi River. The Plains & Eastern line would interconnect with the Tennessee Valley Authority near Memphis after first dropping off 500 MW at a converter station in central Arkansas.

DOE: Need for Transmission

The Energy Department said development of the panhandle’s “consistent and lowest-cost [wind resources] in the nation” has been constrained by a lack of “cost-effective transmission capacity to major load centers.”

“The project would, therefore, unlock the potential for significant new development of wind energy and deliver that energy to a region of the United States that has seen relatively scarce wind development,” the department said. “By increasing the availability of renewable energy from the Panhandle region across a wide geographic area, the project will facilitate market competition that will ultimately benefit consumers and the renewable energy industry as a whole.”

Clean Line President Michael Skelly welcomed DOE’s participation. “The Department of Energy’s decision shows that great things are happening in America today,” he said, calling Plains & Eastern the “largest clean-energy infrastructure project in the nation.”

DOE RFP

Clean Line proposed the project in response to the Energy Department’s 2010 request for proposals for transmission projects under Section 1222 of the Energy Policy Act of 2005, which authorizes the department to participate in “designing, developing, constructing, operating, maintaining or owning” new transmission.

With major regulatory approvals in hand, Clean Line says construction can begin in 2017.

The department’s involvement could help Clean Line in acquiring the right of way for the line, although it said the company will need to demonstrate the commercial viability of the project by executing “significant” firm transmission service agreements before obtaining land through eminent domain. It will also need to complete technical studies required by SPP, MISO and TVA.

Clean Line says the project “will support thousands of jobs in Oklahoma, Arkansas and Tennessee, including hundreds of manufacturing jobs.” Clean Line has a $300 million contract with Pelco Structural, of Oklahoma, to build the project’s tubular steel transmission towers and has selected three Arkansas companies to build related infrastructure such as transmission conductors and glass insulators.

The American Wind Energy Association said the project will “create the opportunity” for $7 billion in new wind farm development. “The project supports economic opportunity, often in rural areas that need it most, and potential energy bill savings for Americans,” said AWEA CEO Tom Kiernan. “Over 99% of all installed utility-scale wind capacity is located in rural areas.”

Opposition to Project

As a condition for its approval, the department required Clean Line use environmental-protection measures during the development, construction and operation of the project “to minimize impacts to landowners and the environment.”

Still, the project has drawn opposition from landowners and political figures. (See DOE Issues Favorable EIS on Plains & Eastern Project and Plains & Eastern Tx Line Foes Cry Foul over DOE Review.)

The Arkansas congressional delegation issued a statement lamenting the Energy Department’s involvement. “Today marks a new page in an era of unprecedented executive overreach, as the Department of Energy seeks to usurp the will of Arkansans and form a partnership with a private company — the same private company previously denied rights to operate in our state by the Arkansas Public Service Commission,” the legislators said. “Despite years of pushback on the local level and continuous communications between our delegation and Secretary [Ernest] Moniz, DOE has decided to forgo the will of the Natural State and take over the historic ability of state-level transmission control through this announcement.”

Although Clean Line won public utility status in Oklahoma and Tennessee, its request was rejected by Arkansas. “They couldn’t find a way to regulate [an] interstate transmission provider,” Clean Line General Counsel Cary Kottler said in an interview. The department’s imprimatur allows the company to overcome that hurdle, he said.

The department will participate in the project through the Southwestern Power Administration, a federal agency that markets hydroelectric power from 24 dams in six states.

It will not make any financial contribution. Instead, Clean Line will pay any Energy Department costs in advance, as spelled out in a participation agreement that also obligates the developer to contribute 2% of its revenues to federal hydropower-infrastructure improvements.

March 28, 2016

Generators to FERC: Expand MOPR for Subsidized FE, AEP Plants

By Suzanne Herel

Eleven generating companies, including Calpine, Dynegy and NRG, have asked FERC to expand PJM’s minimum offer price rule in time for May’s 2019/20 Base Residual Auction, as the Public Utilities Commission of Ohio is poised to rule on power purchase agreements for FirstEnergy and American Electric Power.

ohio ppas — Sammis power plant *Source: Chris Dilts via Creative Commons*

“Complainants respectfully request that the commission expand the MOPR to prevent the artificial suppression of prices in the Reliability Pricing Model (RPM) market by below-cost offers for existing resources whose continued operation is being subsidized by state-approved out-of-market payments,” the companies said (EL16-49).

The companies also voiced support for related complaints asking FERC to void the waivers it granted AEP and FirstEnergy regarding affiliate power sales to ensure commission review of the proposed eight-year agreements, which are supported by PUCO staff. The Ohio commission is expected to rule on the requests in the coming weeks. (See PJM Joins EPSA’s Call for FERC Review of Ohio PPAs.)

Similarly, the complainants have asked that FERC address the waiver issue in time for the May BRA.

Currently, the MOPR applies only to certain new resources.

Recently, the generators argue, “a new threat has emerged in the form of subsidies to existing resources that create incentives for noncompetitive offers and that may prevent the exit of uneconomic resources.”

The proposals from AEP and FE would have “just that effect with respect to over 6 GW of capacity in PJM,” they said.

The companies said they recognized that PJM stakeholders have not had a chance to discuss changes to the MOPR and that Tariff revisions addressing the upcoming BRA might not be an appropriate permanent remedy. Therefore, they are requesting narrowly tailored revisions and a directive to PJM to develop a long-term solution by Nov. 1.

Regardless of whether the PPAs are approved, PJM should initiate a stakeholder process to expand the MOPR, the generators said.

The companies invoked testimony to PUCO by Independent Market Monitor Joe Bowring saying the PPA proposals “highlight the fact that the MOPR needs to be expanded to address all cases where subsidies create an incentive to offer capacity into the PJM capacity market at less than an unsubsidized, competitive offer. This would include offers from all new and existing units that receive subsidies.”

Other parties to the filing are Eastern Generation, Homer City Generation, Carroll County Energy, C.P. Crane, the Essential Power PJM Companies, GDF SUEZ Energy Marketing, Oregon Clean Energy and Panda Power Generation Infrastructure Fund.

March 28, 2016

ISO-NE Forecast for 2024 Boosts Solar 30%

By William Opalka

WESTBOROUGH, Mass. — Load growth remains low in New England while solar power generation is expected to grow even faster than previously predicted, according to a draft study of the region’s power trends.

ISO-NE staff presented the draft of its annual Capacity, Energy, Loads and Transmission forecast at the Planning Advisory Committee meeting on Tuesday.

“The draft forecast [for solar] is 30% higher than last year’s final forecast,” said Jon Black, ISO-NE’s manager of load forecasting. He cited increased state support for the resource along with Congress’ unexpected extension of the investment tax credit last year.

The 2015 forecast predicted 1,620 MW of solar PV at the end of this year, rising through 2024 to 2,449 MW. In the preliminary 2016 draft, the forecast for the end of this year is essentially flat but rises to 3,092 MW at the end of 2024, an increase of 26%.

The new forecast extends a year further, through 2025, when 3,214 MW of solar is predicted, 31% above the final year in last year’s forecast.

Black said the forecast has been refined to include more comprehensive data from distributed asset owners, as well as policy changes. For example, Connecticut’s renewable energy credit program is expected to encourage the development of 300 MW of solar and Vermont’s renewable portfolio standard has a carve-out for 25 MW of PV, Black said.

This year’s forecast, which includes behind-the-meter PV for the first time, also reduces load forecasts and net energy use.

The new study forecasts a 50/50 summer peak of 28,966 MW for 2016, a slight reduction from last year’s forecast for the year. It forecasts a 2024 summer peak of 31,493 MW, a 2% reduction from last year’s study and a 1.1% compound annual growth rate over 2016.

(The 50/50 estimate represents the mean value in a normal probability distribution, meaning there is a 50% chance the load will be higher than the forecast and an equal chance of being lower.)

Net of passive demand response and behind-the-meter solar, the 50/50 peak for 2024 is forecast at 27,060 MW, down almost 3% from last year’s study and a compound annual growth rate of 0.1%.

Energy efficiency, as reported by state utility commissions, is expected to remain stable. Minor increases of its use in some areas were offset by decreases in other parts of the region, according to ISO-NE.

The final CELT report for 2016 will be published on May 1.

March 28, 2016

IPL, MidAmerican: MISO Misallocating Upgrade Costs in GIA

By Michael Brooks

Two Midwest load-serving entities are challenging a generator interconnection agreement filed by MISO that they say would result in one company paying too much for $5.7 million in transmission upgrades because the RTO is misapplying a provision in its Tariff.

Interstate Power and Light (IPL), which is building the 650-MW Marshalltown Generating Station in Iowa, joined MidAmerican Energy last week in protesting the GIA that MISO filed for the combined cycle plant. The companies told FERC that MidAmerican would end up paying the majority of costs for the transmission upgrades in the agreement, while IPL would only pay the installed cost of capital of the shared network upgrades and not its full portion of the monthly facilities charges contained in MidAmerican’s facility service agreements with transmission owner ITC Midwest (EL16-1083).

The upgrades in the Marshalltown agreement were previously included in GIAs filed for two MidAmerican wind farms. ITC had elected to fund the upgrades itself and agreed with MidAmerican that if they became shared upgrades, ITC would determine each interconnection customer’s cost responsibility for them.

Instead, the companies said, MISO believes that Attachment FF of its Tariff requires IPL to make a one-time cost of capital payment to MidAmerican. The companies argued that Attachment FF only applies to when an interconnection customer, not the TO, is funding the upgrades.

“The MISO Tariff language is silent regarding the instant situation, where ITC Midwest as the transmission owner elected to self-fund the network upgrades,” IPL and MidAmerican said. “MISO has refused to recognize the difference between a situation where the first interconnection customer funded the shared network upgrades and the situation here where the transmission owner self-funded” them.

“The distinction is important because … MISO’s requirement that the second interconnection customer simply make a one-time payment for the cost of the shared network upgrades to the first interconnection customer results in unequal and inequitable treatment of the two interconnection customers for the same upgrades,” the companies said.

The companies said IPL should pay 32% of the costs for a $2 million transformer upgrade and 51.4% for a $3.72 million line rebuild. They asked FERC to order MISO to revise the Marshalltown GIA to reflect these cost allocations.

“Parties should be paying their fair share,” Cortlandt C. Choate Jr., senior attorney for IPL parent company Alliant Energy, said in an interview.

They also asked that MISO be required to revise its Tariff to clarify interconnection customers’ cost responsibilities for upgrades funded by the TO.

March 28, 2016

SPP Briefs: New Trustee Chairman, Wind Record

The SPP Regional Entity trustees elected Dave Christiano as their new chairman during a special board meeting last week, replacing the resigned John Meyer.

Meyer announced his resignation the week before, during the SPP RE’s spring workshop in Little Rock, Ark. Because there are only three RE trustees, Christiano and Gerry Burrows moved quickly to “expedite” Meyer’s replacement, they said in an email to members.

During the March 22 call, Burrows nominated Christiano for chairman, then joined him in a 2-0 vote.

Christiano told members the RE doesn’t expect to fill Meyer’s vacancy until July at the earliest. The Russell Reynolds Associates executive search firm has been contracted to help.

“Gerry and I decided we couldn’t go four months without a chairman,” Christiano said.

Alluding to Meyer’s nine years as chair of the RE trustees, Christiano told members they will see little change.

“I will pledge, and I’m sure Gerry will pledge too, that we’re not going to change any directions,” said Christiano, who has been a trustee alongside Meyer since the RE’s inception in 2007.

The RE trustees operate separately from SPP’s Board of Directors, providing oversight of RE decisions on regional standards, compliance enforcement and penalties. Only the trustees and certain RE staff members have the authority to make compliance and enforcement decisions.

An electrical engineering graduate from Clarkson College in New York, Christiano began his industry career with Consolidated Edison in New York City in 1971 and took part in an analysis of the 1977 blackout. He spent 28 years with City Utilities of Springfield in Missouri before becoming an RE trustee. Christiano has served on numerous SPP and NERC boards and committees.

Meyer resigned from the RE because of a conflict with the bylaws of Western Interconnection reliability coordinator Peak Reliability, where he is vice chair. The Western Area Power Administration, which joined SPP last year, is partly in the Western Interconnection, requiring SPP to register with the Western Electricity Coordinating Council as a planning authority and transmission-service provider.

To ensure independence, Peak’s bylaws prohibit its board members from serving on other boards in the WECC.

Christiano said Meyer chose to stay with Peak, where he only has two years of service. “He felt he had a lot more to offer there,” Christiano told RTO Insider.

SPP Sets New Wind Peak Record

The RTO set a new wind peak at 6 a.m. March 21, relying on about 87% of the wind capacity in its footprint to generate 10,783 MW. The previous record of 10,280 MW was set Feb. 17.

The RTO has 12,397 MW of installed and available wind capacity in its footprint, with another 33,819 MW of capacity in various stages of development.

Brown Honored with International Award

SPP CEO Nick Brown will be honored by the University of Arkansas at Little Rock’s (UALR) College of Business for his recent Business Achievement Award from the Beta Gamma Sigma.

The society annually recognizes achievement in business and ethical leadership. The UALR College of Business nominated Brown for the award and will hold an invitation-only reception in his honor in Little Rock. Brown said he was “humbled” by the award and thanked SPPs employees, “who are the foundation of our corporate success.”

Beta Gamma Sigma is an international honor society serving business programs accredited by the Association to Advance Collegiate Schools of Business.

– Tom Kleckner

March 28, 2016

Texas Commission Approves Oncor REIT Structure

By Tom Kleckner

The Public Utility Commission of Texas on Thursday approved Hunt Consolidated’s proposed acquisition of Oncor, the state’s largest transmission and distribution utility and the most valuable remaining piece of troubled Energy Future Holdings (Docket # 45188).

The PUC’s March 24 order would split Oncor into two companies, one of which would operate as a real estate investment trust (REIT) under the state Public Utility Regulatory Act. The commission gave the parties a Nov. 30 deadline to complete the transaction.

As a REIT, Oncor AssetCo would own the transmission and distribution facilities, while Oncor Electric Delivery Co. (OEDC) would rent the facilities to provide electric delivery services. OEDC would house most of Oncor’s management and employees and the remainder of the assets.

Oncor AssetCo would avoid paying federal income taxes as part of the transaction if it derives at least 75% of the its gross income from property rents. Hunt has taken a similar tack with its Sharyland Utilities, which provides services to 53,000 customers, primarily in West Texas and the Rio Grande Valley.

The commission agreed with the proposal, saying “payments received from OEDC, as the lessee and operator of the assets, will constitute rents from real property under the meaning of the Internal Revenue Code.”

The plan has drawn criticism from a disparate group that includes former Texas Gov. Rick Perry, a coalition of cities served by Oncor, the AARP and PUC staff. Much of the criticism centers on the REIT conversion and whether it would provide a windfall for the company at the expense of ratepayers.

Two Texas state senators, Kelly Hancock and Royce West, called into the meeting to add their objections, saying the REIT should not be able to collect taxes in its rate structure if it doesn’t intend to pay them. The tax benefit is worth about $250 million, and the Hunt group had been looking for a guarantee it could take full advantage of the benefit.

“I am not against the acquisition,” West said from China through heavy static. “I understand a REIT has to distribute [funds to shareholders]. The question in my mind is should [the REIT] be allowed to use dollars earmarked for taxes … to shareholders.”

The commissioners discussed whether to add a separate accounting treatment for the taxes, with one proposal to immediately credit ratepayers $100 million. However, Chair Donna Nelson stepped in to say adding too many restrictions to the deal might make it unmanageable.

“It sounds like you’re punishing them now,” she said. “If we’re going to deny it, why don’t we just deny it? If you’re going to keep attaching these things to it, it’s going to die anyway. All we’re doing is wasting time.”

In the end, the PUC’s order said the tax-savings issue will be “addressed by commission staff and intervenors in the next rate proceeding of Oncor AssetCo and OEDC.”

While siding with Anderson and Commissioner Brandy Marquez on the order, Nelson dissented from the majority’s decision “regarding the timing and treatment of the income tax expense.” Nelson’s position throughout the Hunt-Oncor process has been to oppose customer refunds.

Geoffrey Gay, legal counsel for about 150 cities served by Oncor, said he expects his clients to file rate cases by the end of April, bringing about the rate case a year earlier than the current schedule.

Oncor expects the proposed transaction, “if funded by investors,” to close on or before year-end.

“While there are a number of hurdles left to clear, we look forward to working with the parties involved to reach a conclusion in this change-in-control proceeding,” said Geoff Bailey, Oncor’s director of communications, in a statement.

Hunt did not respond to a request for comment on the order. However, a Hunt representative issued a statement after the PUC meeting saying it would “continue to work with all parties in the EFH bankruptcy proceeding over the coming months to reach a successful closure of the transaction consistent with the order approved today.” The company is a Dallas-based oil and gas, real estate and power company, owned by the wealthy Hunt family.

Oncor delivers power to more than 3 million homes and businesses over about 119,000 miles of transmission and distribution lines in North and West Texas. Determining its fate is central to resolving EFH’s Chapter 11 bankruptcy reorganization, which was filed in April 2014.

EFH was the result of a $48 billion leveraged buyout of TXU Corp. in 2007, when the utility faced strong public opposition to its plan to build 11 coal plants in Texas. Private investors led by KKR and TPG Capital bet on rising energy prices but found themselves instead saddled with $42 billion in debt following the 2008 global financial crisis and plunging gas prices due to the fracking boom.

A U.S. bankruptcy judge in December approved EFH’s plan to split into two separate companies — Oncor and the unregulated power generation and retail arms, Luminant and TXU Energy, respectively — wiping out the LBO sponsors’ equity. The Luminant-TXU Energy businesses would go to senior lenders owed about $24 billion.

The decision assumes creditors would not incur a multibillion-dollar tax bill. The IRS is reviewing whether the transfer of assets to creditors represents a taxable sale.