The Commodity Futures Trading Commission (CFTC) proposed Monday that electric capacity purchases and natural gas peaking supply contracts be exempt from regulation as swaps.
GE Energy Financial Services’ Linden, N.J. cogeneration plant is among those using peaking supply contracts to ensure natural gas supplies. Source: GE Energy Financial Services
The commission unanimously approved proposed guidance that said such contracts should not be considered swaps under the Commodity Exchange Act because they are “customary commercial arrangements” intended to meet regulatory commitments. The commission will accept comments on its proposal for 30 days.
“These contracts are entered into to assure availability of a commodity, not to hedge against risks arising from a future change in price of that commodity or for speculative or investment purposes,” Chairman Timothy Massad said in a statement supporting the guidance. “They are typically entered into in response to regulatory requirements, the need to maintain reliable energy supplies and practical considerations of storage or transport.”
The exemptions apply to:
Load-serving entities’ contracts to purchase electric capacity to comply with state or federal resource adequacy rules; and
Peaking supply contracts that allow an electric utility to purchase natural gas from another provider if its local distribution company curtails its delivery in order to preserve fuel for heating customers.
Massad said the proposed guidance, which complements the commission’s final rule regarding trade options, “will reduce burdens on end users and allow them to better address commercial risk.”
Avangrid is working with the MIT Energy Initiative to create a model to simulate the integration of distributed energy resources into the grid.
The model could support New York’s Reforming the Energy Vision plan by simulating how distributed resources, such as solar arrays and battery storage systems, might impact the power system. This model seeks to identify the scale at which distributed resources become beneficial to the grid while taking into account potential impacts on electricity prices, grid reliability and the environment.
The collaboration is part of MITEI’s broader Utility of the Future Study. Avangrid is the newly formed affiliate of the Iberdrola Group that operates New York State Electric and Gas, Rochester Gas and Electric, Central Maine Power and United Illuminating.
The average price of wholesale electricity, pushed lower by depressed natural gas prices, last year dropped to the second-lowest level in 12 years in New England, according to preliminary figures from ISO-NE.
The lowest and second-lowest average monthly power prices were in June at $19.61/MWh and December at $21.35/MWh. The second-lowest annual average price of wholesale electric energy was set last year at $41/MWh, with the lowest annual average price at $36.09/MWh in 2012.
For most of the year, natural gas prices in New England and much of the nation were at their lowest levels in nearly two decades.
Northern Indiana Public Service Co. has reached a settlement agreement that would allow it to proceed with a $1.25 billion seven-year infrastructure-upgrade plan. The utility originally sought $1.33 billion.
NIPSCO reached the settlement with its industrial customers, the Office of Utility Consumer Counselor, the LaPorte County Board of Commissioners and the Indiana Municipal Utility Group. Infrastructure upgrades include pole replacement, installation of underground cables and replacement of substation transformers and breakers. NIPSCO has also committed to retrofitting utility-owned streetlights with LED bulbs and splitting the cost between customers and municipalities.
The company has filed the settlement with the Utility Regulatory Commission.
The Public Service Commission reversed itself and voted to permit the $4.9 billion sale of Cleco to a consortium led by foreign investors. Cleco agreed not to raise its rates until 2020, and the utility’s 286,000 customers also would receive credits averaging $500 each for the next few years.
“I think we did a pretty good deal,” said Commissioner Foster Campbell, who flipped his position after negotiating from the dais during the hearing. The PSC had rejected the transaction in February, but the purchase will now close sometime in this month.
Three of the five elected PSC members were needed to approve the sale to a group led by Macquarie Infrastructure and Real Assets and British Columbia Investment Management Corp. In the end, four of the commissioners voted to approve the transaction.
A proposed law aimed at saving the state’s ailing biomass energy plants would save logging industry jobs but could add millions of dollars to electricity bills.
The bill would require the Public Utilities Commission to seek competitive bids and negotiate contracts for 80 MW of renewable energy for five years. Central Maine Power said the measure could add up to $48 million to ratepayers’ bills. The utility said that biomass plants have received more than $2.6 billion in ratepayer subsidies over the past 20 years, and despite that, half of them have closed since the 1990s because they weren’t competitive.
A logger group has estimated that the complete loss of the biomass industry in the state would cost 400 jobs at the biomass plants and at least another 900 related jobs. Total economic losses to the state could be as high as $300 million per year, the group says.
2 Large Solar Projects Headed for Delmarva Peninsula
Seattle-based Longview Solar has proposed building two solar projects on Worcester County farm land that together would generate up to 35 MW.
Longview, a partnership between Elemental Energy and Tuusso Energy, says one of the projects, estimated at $20 million, would involve 63,000 solar panels on 125 acres east of Snow Hill. The other would be located west of Berlin, cost $30 million and feature 85,000 panels on 190 acres.
Landowners last week complained to the Department of Public Utilities at a public hearing about Kinder Morgan’s proposal to take rights of way by eminent domain along the proposed route of its Northeast Energy Direct natural gas pipeline.
Kinder Morgan has identified 39 Berkshire County properties for compulsory land surveying because owners have refused access.
“This is about corporate greed at its most despicable; it is not about the greater good,” said landowner Williams Spaulding, who said he has filed numerous “no trespass” orders against the company but has still had to chase employees off his land.
A Marion Township moratorium to delay wind projects won’t impede the proposed wind farm that inspired the moratorium in the first place.
Opponents of Exelon’s proposed 68-turbine project in Marion, Bridgehampton and Custer townships had persuaded the Marion Township Board of Trustees last week to approve the moratorium that will halt all future wind development projects. But the 150-MW Exelon project was not included in the moratorium, officials said, because it already had been approved.
“I feel the board lied to and misled the citizens of Marion Township,” said Jennie Schumacher, a wind farm opponent who organized a protest at the local board meeting.
Industrial air pollution is imposing health risks on low-income and minority residents in Southwest Detroit and the surrounding areas, Newsweek reported. The region does not comply with federal sulfur dioxide standards under the Clean Air Act. More than 15% of adult Detroiters have asthma, 29% more than the statewide average, recent state data shows.
DTE Energy operates two coal-fired power plants that are the biggest sulfur dioxide emitters in the area. A Marathon Oil refinery also contributes emissions, and the Michigan Department of Environmental Quality is close to granting the refinery a new permit that will allow it to emit an additional 22 tons of sulfur dioxide annually.
Lynn Fiedler, a MDEQ spokeswoman, says the department has been working with companies to bring emissions down, but it’s a “difficult negotiation” because they will likely need to install costly carbon-reducing equipment. Fiedler added that DTE is “reluctant” to take steps in emissions-reduction.
PSC Staff Official Blasts Proposed Ameren Rate Scheme
Public Service Commission Staff Director Natelle Dietrich disparaged a proposal that would make it easier for Ameren to raise rates to pay for grid upgrades, calling it a “radical departure” from the current rate-setting procedure.
In testimony before the House Energy and the Environment Committee, Dietrich said the plan could increase residential rates by 62.1% over 10 years and boost industrial rates up to 94%. The rate scheme would also give Ameren’s biggest customer, Noranda Aluminum, power to negotiate rates in order to keep the troubled smelter afloat.
A group of large industrial customers, including Nestlé-Purina, Doe Run, Ford, General Motors, Monsanto and Anheuser-Busch, urged the state to stay with the current rate system. “Toss this bill on the scrap heap,” said Steve Spinner, representing the industrials.
PSC Orders Northwestern to Refund State’s Customers $8.2M
State regulators last week ordered NorthWestern Energy to refund $8.24 million that it charged to buy electricity on the open market during a six-month outage in 2013 at the Colstrip coal plant. The Public Service Commission said that NorthWestern failed to take prudent actions to protect customers against the financial exposure from such a massive outage.
The majority of commissioners said the utility should have taken out insurance or pursued legal action against the plant operator to recover some of the costs incurred during the outage, which occurred when equipment malfunctioned following maintenance work at one of Colstrip’s four units.
Despite National Trends, Coal Still No. 1 in State
Pope
Federal forecasters anticipate that natural gas will surpass coal in 2016 as the nation’s largest fuel source for power generation, but coal remains king in the state. Coal fueled 61.5% of electricity produced last year while natural gas made up 1%.
“It really does boil down to dollars and cents,” said Nebraska Public Power District CEO Pat Pope. The average cost of coal delivered for power generation in the state was $1.34/MMBtu in December, making it the cheapest in the nation and about 30% less than the national average. Natural gas delivered in the state cost $3.44/MMBtu, more than 2.5 times more than coal.
NYISO has selected Jane Sadowsky and Bernard Dan to fill vacancies on its Board of Directors, effective this month.
Sadowsky is the managing partner at Gardener Advisory, which provides consulting and advisory services predominately in the electricity power sector. Dan is the former CEO of Sun Holdings, a proprietary trading company that focuses on electronic trading of U.S. and European shares as well as currencies.
“Jane Sadowsky and Bernard Dan bring a wealth of talent and experience to our board,” said Michael Bemis, board chairman. “Their proven leadership and combined expertise in the areas of energy finance, financial markets and business strategy will be instrumental in guiding the NYISO Board of Directors as we continue to advance the efficiency of our markets while reliably meeting consumers’ energy needs.”
More than 150 people gathered for a 12-hour Public Service Commission hearing about the controversial, 87-turbine Brady Wind Energy Center in Stark County.
For the bulk of the day, attorneys for both Brady Wind, a subsidiary of NextEra Energy, and the grassroots Concerned Citizens of Stark County group, questioned witnesses about the wind farm and the effects on the area. Public commenters pushed the hearing into the evening. Commissioner Brian Kalk said it was the longest hearing he’s experienced in his eight years on the commission.
The PSC may take up to two months to make the final decision on the 150-MW wind farm, which was first proposed in late 2015.
The Corporation Commission says distributed generation and its effect on the grid should be explored in Oklahoma Gas & Electric’s pending $92.5 million rate case.
OG&E included a distributed generation tariff in its rate filing to comply with a 2014 law that requires utilities to establish a separate class for distributed generation customers if they can show those customers are not paying their fair share of grid-connection costs. The utility wants to establish a $2.68/kW demand charge for residential and small commercial customers. With the average peak demand for a residential customer at 6 to 8 kW, the demand charge could be $16-21 per month.
A hearing in the rate case is expected to begin May 3.
Oklahoma Gas & Electric next month will make a third attempt to win regulatory approval for a $500 million scrubber project at its Sooner coal-fired plant.
The Corporation Commission last year rejected a more comprehensive, $1.1 billion case and a pared-down modification of the utility’s environmental compliance plan. OG&E has asked for a rehearing and says it needs a decision by May 2 to meet a series of engineering and construction deadlines if the scrubbers are to be installed.
The utility is arguing for coal generation to remain a significant part of its fuel portfolio, while critics question why OG&E wants to keep a 35-year-old coal plant running for another 30 years when market and environmental forces are turning against the fuel.
A company that had planned to build a $360 million, 90-MW plant to generate electricity from old tires instead will partner with a high-tech firm to develop a facility to make diesel fuel and other products from the material.
Crawford Renewable Energy said it changed tack because a drop in the wholesale price of electricity made the Greenwood Township power plant proposal “economically unfeasible.”
The newly proposed non-combustion facility would recycle the tires into carbon black, a component in photocopier toner, and into the type of low-sulfur diesel required by the federal government for trucks and other heavy vehicles.
National Grid has started construction on a new substation that will improve electricity delivery to downtown Providence and the South Street Landing project.
The new substation will replace one dating to 1919. It is expected to be completed late in 2017.
“This facility will meet the electric demands of a major portion of the city for the immediate future and beyond,” said National Grid Rhode Island President Timothy F. Horan.
A Brown University professor is arguing that the construction of a new natural gas-fired power plant in Burrillville would make it impossible for the state to meet its target for reducing carbon emissions in the coming decades.
J. Timmons Roberts, who helped write the state’s climate change regulations, says building the 900-MW Clear River Energy Center conflicts with the Resilient Rhode Island Act, the 2014 law that set a non-mandatory goal of reducing state greenhouse gas emissions 80% below 1990 levels by 2050.
Roberts is submitting the testimony on behalf of the Conservation Law Foundation, a regional environmental group that is opposed to the power plant, which was proposed last year by Invenergy.
Opponents of a proposed electricity-producing manure digester in St. Albans say the project would jeopardize the wetlands that it ostensibly is designed to protect.
Green Mountain Power has applied to the Public Service Board for a Certificate of Public Good for the digester, which supporters say is a proven agricultural technology for improving water quality and reducing emissions of methane from dairy farms and compost operations. Green Mountain says its digester is the only one in the state that includes advanced systems for removing phosphorus from manure slurry.
But a vocal critic, Tim Camisa, co-owner of St. Albans-based Vermont Organics Reclamation, says the project would be located only 200 feet from a stream, too close to protect the streambank and wetlands from accidents.
The State Corporation Commission has approved Dominion Virginia Power’s plan to build a natural gas-fired power plant in Greensville County.
Construction is expected to begin this year on the $1.3 billion plant, which would generate 1,588 MW and be situated on 55 acres.
The company said customers will save $2.1 billion over the life of the plant through fuel savings compared with the cost of buying power on the open market.
State tax revenues from wind energy fell by 15% in 2015, coming at a time when the state is already suffering the effects of a pronounced downturn in the oil, natural gas and coal sectors. The reason for the 2015 tax decline was not immediately apparent.
The Cowboy State became the first in the nation to tax wind production when it approved a $1/MWh levy in 2010. Tax collections have varied between $2.6 million in 2012, the first year the levy was imposed, to $4.4 million in 2014. Last year, the state collected $3.7 million.
The state’s wind production capacity has remained unchanged since 2010. A lack of transmission capacity has stymied further development in the state.
AUSTIN, Texas — Technical Advisory Committee Chair Randa Stephenson and Kenan Ögelman, ERCOT’s vice president of commercial operations, last week suggested a workshop to discuss how ERCOT and its market participants exchange data and handle changes to data reports.
Denton Municipal Electric’s Lance Cunningham raised the issue by noting that staff told the Market Data Working Group it was issuing a 30-day notice — as required by ERCOT’s protocols — to change an existing wind-projection data report. Cunningham said that change would require an estimated 30 person-hours to make changes to the muni’s systems.
Several stakeholders sided with Cunningham, pointing out modest software changes can cost tens of thousands of dollars.
“Multiply that cost by the number of [market participants] that have to do it, and you’re in the millions pretty quickly,” The Wind Coalition’s Walter Reid said. “We need to be aware of what we’re doing.”
“[ERCOT’s] ability to unilaterally change reports has been a concern of mine,” said Calpine’s Randy Jones, representing independent generators. “I realize there are passages in the protocols to provide data to ERCOT upon [its] request, but the time may be ripe for a discussion that we start putting criteria around that … and mitigate the huge impact it has.”
Ögelman, while noting the change will actually take place June 30, did agree with Cunningham that such changes create inconveniences.
“It can be burdensome to adjust to [changes],” he said. “Long term, do we need to start thinking about another way we exchange data, rather than people scraping it off a report? Right now, this is the only way certain people can get this data. I think it’s very important to consider whole systemwide impact of changes.”
“You need a report you can input and utilize,” said Sharyland Utilities’ B.J. Flowers. “Maybe you utilize the workshop as business-requirement gathering, and hand it over to the market data group to work on the details.”
Stephenson told stakeholders she is working with ERCOT to schedule the workshop.
NPRRs Approved, NOGRRs Tabled
TAC members approved five Nodal Protocol Revision Requests:
NPRR 741: Clarifications to estimated aggregate liability (EAL) and total potential exposure (TPE) credit exposure calculations.
NPRR 744: Reliability unit commitment trigger for the reliability deployment price adder and alignment with RUC settlement.
NPRR 745: Change emergency response system availability from an hourly to 15-minute interval evaluation, plus other minor changes.
NPRR 748: Revisions associated with NERC reliability standard COM-002-4 and other clarifications associated with dispatch instructions.
Luminant’s Amanda Frazier, chair of the Protocol Revisions Subcommittee, said NPRR 744 exceeded ERCOT’s $100,000 impact-analysis threshold, but she noted staff filed comments that determined the ISO would have saved more than $9 million “over the last several months” if the revisions had been in place.
“We at PRS felt that was adequate justification for approving this process,” Frazier said.
The committee also tabled a Nodal Operating Guide Revision Request and an appeal of a second NOGRR:
NOGRR 151: Alignment with NPRR 748, revisions associated with COM-002-4 and other clarifications associated with dispatch instructions.
NOGRR 149 would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission operator services from a third-party provider if their annual peak is less than 25 MW. Jones expressed sympathy for the small municipalities most affected. “On the other hand,” he said, “it doesn’t seem to be fair to the market. Small entities are not carrying their obligations.”
Staff Share Reports, Updates
Staff shared the Emergency Response Service (ERS) report that is filed annually with the Public Utility Commission of Texas. ERCOT procures ERS three times during the year for four-month terms. Participants can provide the service for one or more of four time periods, which are designed to allow flexibility for customers during traditional business hours.
ERS expenditures are capped at $50 million. Staff said expenditures for last year were $48.8 million.
TAC also approved the Retail Market Subcommittee’s goals for 2016 and discussed staff updates on ERCOT’s debt strategy and changes to ERCOT’s antitrust admonition and guidelines.
ERCOT Treasurer Leslie Wiley shared feedback from her recent report to the Finance and Audit Committee. She said the ISO uses congestion revenue rights (CRRs) auction receipts — with a limit of $100 million — along with debt and revenue to fund its liquidity. Wiley said the committee encouraged her to use CRRs when available to fund long-term projects, but there are questions about how to pay for significant unbudgeted initiatives.
The ISO currently has an Aa3 credit rating. “We want to maintain that,” Wiley said.
ERCOT’s legal department is revising the antitrust guidelines to be a position statement. Nathan Bigbee, ERCOT’s senior corporate counsel, said there shouldn’t be any cause for concern, “as long as actions ERCOT takes fall within [its] authority under federal or state laws.”
FERC last week granted Missouri River Energy Services (MRES) an extension to comment on a series of “zonal agreements” submitted by ALLETE and Great River Energy to resolve revenue-sharing and cost recovery disputes (ER16-1107, et al.).
The commission extended the commenting deadline to April 5, a week short of MRES’ request but four days longer than what ALLETE and GRE were willing to concede.
The agreements would resolve the two companies’ disputes over revenue-sharing and cost recovery for transmission projects in MISO’s Minnesota Power (MP) pricing zone — including the proposed Great Northern Transmission Line linking the region with hydro resources in Manitoba.
ALLETE and GRE filed a joint answer urging the commission to disregard the protest by MRES, which contends the agreements were negotiated “outside of commission processes” and could be inconsistent with MISO’s Tariff.
“These complex, interrelated agreements proposed by the applicants as a black box settlement that implicitly cannot be ‘pried apart,’ present a challenge of analysis because of their complexity and lack of transparency,” MRES wrote in a March 24 filing.
“All of MRES’ claims are either procedurally improper or unfounded and should not delay the commission’s approval of the zonal agreements,” the two companies countered.
MRES’ concerns have less to do with the revenue-sharing portion of agreements than with their possible implications for transmission cost allocation within the MP pricing zone. Chief among of those concerns is whether ambiguous language in the settlement opens the door for ALLETE to eventually roll costs related to the 500-kV Great Northern line into its revenue requirement, a move MRES said should be prohibited under MISO’s Tariff because the project is participant-funded.
ALLETE and GRE counter that MRES is pursuing its concerns under the wrong proceeding — that the revenue-sharing methodology under the zonal agreements represents a separate issue from Great Northern’s cost allocation. The companies say MRES should raise allocation concerns under the Tariff’s Attachment O protocol, which deals with project cost recovery.
The two companies also defended the settlement process and its outcome, saying their agreements “worked within the context” of MISO’s Transmission Owner Agreement, which spells out how transmission revenue should be distributed in pricing zones with multiple transmission owners.
“MRES’ protest, at best, reflects a misunderstanding of the process used to negotiate the zonal agreements as well as such agreements’ fundamental purpose,” the companies said.
ALLETE and Great River insist that if they “had not resolved their differences, they would have been forced to litigate complex and fact-intensive issues” regarding MISO pricing zone boundaries, asset classification for cost allocation purposes and revenue sharing for select facilities and load within the MP pricing zone.
“This litigation likely would have taken years and resources away from all parties (including MISO and commission staff), who all may prefer to focus on other areas,” the companies said.
MISO’s day-ahead market schedules may continue to use Eastern Standard Time instead of Eastern Prevailing Time even as the RTO alters scheduling deadlines to comply with updated gas nomination cycles, FERC said (ER15-2256).
The commission last week ruled that MISO could persist in having its day-ahead market become effective at 12 a.m. EST, despite using EPT for other scheduling deadlines.
In a Jan. 19 compliance filing related to gas-electric coordination, MISO sought permission to continue using EST because “accommodating transitions to and from daylight saving time would require significant implementation costs to MISO and its market participants, while providing little, if any, quantifiable benefits.” MISO explained that moving to EPT would “divert resources and funding from higher priority initiatives.”
FERC agreed that MISO “sufficiently explained the discrepancy between its using EST for establishing when its day-ahead market schedules become effective and its using EPT for all other scheduling deadlines.”
The commission also approved MISO’s request to begin posting day-ahead market results by 1:30 p.m. EPT (12:30 p.m. CT), saying the new deadline provides natural gas-fired generators sufficient time to procure fuel and secure pipeline transportation ahead of the 1 p.m. CT timely nomination cycle. FERC additionally accepted a related MISO provision to move the day-ahead market trading and interchange scheduling deadlines to 10:30 a.m. EPT (9:30 a.m. CT) in order to meet the new posting time. (See FERC Orders MISO to Shift Electric Schedule.)
The schedule changes become effective Nov. 5 for the Nov. 6 operating day.
A MISO proposal to hold a separate forward capacity procurement auction for deregulated areas is meeting with skepticism from some RTO members.
Dynegy’s Baldwin Energy Complex in southern Illinois. Some generators in retail choice regions of MISO such as southern Illinois have exported their power to PJM, where capacity prices have been higher Source: MISO
MISO stakeholders raised their concerns at a March 28 Competitive Retail Solution Task Team discussion focusing on the Forward Local Requirements Auction (FLRA) proposed last month. (See MISO Proposes Adding Forward Auction for Retail Choice Zones.) The task team plans to turn the proposal over to the Resource Adequacy Subcommittee (RASC) this month.
Zone 4 an ‘Island’
Much attention was focused on the fully deregulated Zone 4 in southern Illinois — MISO’s only fully deregulated zone.
Aaron Patterson with The NorthBridge Group pointed out that Zone 4’s local clearing requirement of about 5 GW during the 2016/17 planning year would leave more than half the zone’s supply unused in a forward auction.
“What I’m wrestling with is — we have 10 to 11 GW of supply [in Zone 4] and sort of structurally only 5 GW” under the local clearing requirement, Patterson said. “The supply that doesn’t clear is getting a price signal that it’s not needed.”
Jeff Bladen, MISO executive director of market design, responded that leftover supply would be applied to the planning reserve margin requirement.
“A lack of a forward signal is not lack of a need,” Bladen said. “It is a lack of need for it to be a local resource.”
Others said the FLRA would make Zone 4 even more of an “island.”
Bladen said MISO would not introduce a new import constraint for the auction. Instead, the RTO plans to examine system-wide import capability. And while the grid operator does not intend to impose a minimum offer price rule, it would update its Tariff with a bright line reliability test for forward procurement.
Multiple stakeholders asked what data and forecasting methods MISO would use to calculate local clearing requirements three years into the future, questions that Bladen deferred to the April RASC. “We’ll need to discuss that with stakeholders in a little more detail,” he said.
Bladen also said the RASC could best address the concerns of stakeholders who think the FLRA will produce extremely low prices and want MISO to run simulations and present the results. Price formation is “something we’ve given extraordinary amounts of attention to,” he said.
“This might work for a partially deregulated zone, but this won’t work for a zone that’s been fully deregulated,” said Exelon’s Marka Shaw, who asked for another CRSTT meeting specifically focused on affected Illinois customers. “I don’t like the idea of this rolling into the RASC and this getting shortchanged given the tight timeline.”
David Sapper of Customized Energy Solutions wanted to know how generators could use the five-year FLRA opt-in to participate, but Bladen clarified that the opt-in applies only to load-serving entities, not generators.
In response to a question about how MISO’s new two-season construct would align with forward procurement, Bladen said seasonal constructs — currently scheduled to be enacted in the 2018/19 planning year — would apply to the FLRA as well.
“These filings are effectively being looked at in parallel,” Bladen said.
Jim Dauphinais, counsel for Illinois Industrial Energy Consumers, asked how the downward sloping demand curve would apply to market supply. Bladen stressed the curve is only applicable to the demand — not the supply — side of the auction.
“It is very feasible to have different purchase price sensitivities for different consumers, if you will, in the same market,” Bladen said.
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.
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
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.
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 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.
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
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.
The model could support New York’s Reforming the Energy Vision plan by simulating how distributed resources, such as solar arrays and battery storage systems, might impact the power system. This model seeks to identify the scale at which distributed resources become beneficial to the grid while taking into account potential impacts on electricity prices, grid reliability and the environment.
The average price of wholesale electricity, pushed lower by depressed natural gas prices, last year dropped to the second-lowest level in 12 years in New England, according to preliminary figures from ISO-NE.
Northern Indiana Public Service Co. has reached a settlement agreement that would allow it to proceed with a $1.25 billion seven-year infrastructure-upgrade plan. The utility originally sought $1.33 billion.
The Public Service Commission reversed itself and voted to permit the $4.9 billion sale of Cleco to a consortium led by foreign investors. Cleco agreed not to raise its rates until 2020, and the utility’s 286,000 customers also would receive credits averaging $500 each for the next few years.
A proposed law aimed at saving the state’s ailing biomass energy plants would save logging industry jobs but could add millions of dollars to electricity bills.
Landowners last week complained to the Department of Public Utilities at a public hearing about Kinder Morgan’s proposal to take rights of way by eminent domain along the proposed route of its Northeast Energy Direct natural gas pipeline.
A Marion Township moratorium to delay wind projects won’t impede the proposed wind farm that inspired the moratorium in the first place.
Public Service Commission Staff Director Natelle Dietrich disparaged a proposal that would make it easier for Ameren to raise rates to pay for grid upgrades, calling it a “radical departure” from the current rate-setting procedure.
State regulators last week ordered NorthWestern Energy to refund $8.24 million that it charged to buy electricity on the open market during a six-month outage in 2013 at the Colstrip coal plant. The Public Service Commission said that NorthWestern failed to take prudent actions to protect customers against the financial exposure from such a massive outage.
NYISO has selected Jane Sadowsky and Bernard Dan to fill vacancies on its Board of Directors, effective this month.
More than 150 people gathered for a 12-hour Public Service Commission hearing about the controversial, 87-turbine Brady Wind Energy Center in Stark County.
The Corporation Commission says distributed generation and its effect on the grid should be explored in Oklahoma Gas & Electric’s pending $92.5 million rate case.
A company that had planned to build a $360 million, 90-MW plant to generate electricity from old tires instead will partner with a high-tech firm to develop a facility to make diesel fuel and other products from the material.
National Grid has started construction on a new substation that will improve electricity delivery to downtown Providence and the South Street Landing project.
A Brown University professor is arguing that the construction of a new natural gas-fired power plant in Burrillville would make it impossible for the state to meet its target for reducing carbon emissions in the coming decades.
Opponents of a proposed electricity-producing manure digester in St. Albans say the project would jeopardize the wetlands that it ostensibly is designed to protect.
The State Corporation Commission has approved Dominion Virginia Power’s plan to build a natural gas-fired power plant in Greensville County.
The commission extended the commenting deadline to April 5, a week short of MRES’ request but four days longer than what ALLETE and GRE were willing to concede.
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.