Competitive Power Ventures plans to begin major construction next month on its 661-MW combined-cycle plant in Maryland despite an unfavorable ruling last week from the Federal Energy Regulatory Commission.
FERC rejected CPV’s request that it declare the company’s contracts with regulated utilities in New Jersey and Maryland “just and reasonable.” CPV filed the request in early June, believing that FERC’s approval would nullify appellate courts’ determinations that the contracts violated FERC’s ratemaking powers. (See Rebuffed By Courts, CPV Seeks FERC End-Around.)
Instead, FERC said, “In considering whether the rates, terms, and conditions in a contract are just, reasonable and not unduly preferential or discriminatory under the FPA, the contract must first be a valid contract.” As the contracts had already been found invalid by the courts, FERC rejected the filing.
CPV announced Friday that it has obtained financing from 15 lenders, led by GE Energy Financial Services, for the $775 million St. Charles Energy Center in the Southern Maryland community of Waldorf.
CPV Chief Financial Officer Paul Buckovich told The Baltimore Sun that the costs are much higher than if the company had come to lenders with the original contracts. “The financing is much more expensive and less beneficial to sponsors and ultimately to the ratepayers,” he said.
CPV has already begun preliminary site work on the Waldorf site. The plant will be built under a “medium-term contract financing” that will require CPV to refinance five years after starting operations. The arrangement is similar to that used to build CPV’s Woodbridge, N.J., plant, which is also under construction.
CPV had sought to build two plants supported by contracts with utilities in Maryland and New Jersey. Each contract was based on a benchmark amount; if CPV’s capacity revenue was less than this amount, the utilities would pay CPV the difference. If the revenue was more, CPV would pay the utilities.
The utilities were forced to sign the contracts by each state’s public utilities commission, which led to them filing lawsuits.
If PJM overestimates the Tier 1 resources available, it won’t procure enough Tier 2 reserves.
PJM last week proposed eliminating some generators from the calculation of Tier 1 synchronized reserves, along with an unintended “windfall” the Market Monitor says those units receive in compensation.
Under a proposal outlined to the Market Implementation Committee last week, PJM’s market clearing engine would assume no synchronized reserve contribution from nuclear, wind, solar, batteries and certain hydro units that PJM says cannot be counted on to provide the service.
Although the clearing engine would set those resources’ synchronized reserve contribution to 0 MW, the generators would be credited for reserves they do provide in a spinning event.
The rule change also would eliminate a rule that requires PJM to pay Tier 1 resources when the non-synchronized reserve price rises above zero. Under the revision, only those resources that can “reliably provide” synchronized reserve service would receive that compensation.
“We’re paying Tier 1 a lot of money — in fact, a huge amount of money” for unresponsive resources, Market Monitor Joe Bowring said. “There’s no reason to do it.”
PJM’s 1,375-MW synchronized reserve requirement is equal to the largest contingency in the RTO. Tier 1 resources — online units following economic dispatch that are only partially loaded and thus able to increase output within 10 minutes — provide most of the needed reserves.
Tier 2 resources such as demand response and combustion turbines — which are capable of providing reserves within 10 minutes and have cleared the synchronized reserve market — make up any shortfall.
Realistic Estimates
PJM currently estimates Tier 1 resources based on the difference between units’ bid-in parameters (EcoMax) and economic dispatch points, rather than on explicit offers from resources, making it prone to errors. If PJM overestimates the Tier 1 resources available, it won’t procure enough Tier 2 resources.
“We have to make sure we have realistic estimates of what resources can increase output and what couldn’t be relied on,” explained Stu Bresler, vice president of market operations.
Wind units typically operate at their maximum capacity — but that is dependent on weather conditions, Bowring noted. “You have to be able to know [the extra output is] there, and you can’t do that with wind, because the wind may be blowing. It may not be.”
Synchronized Reserve Windfall
In addition, PJM’s synchronized reserve costs are higher than necessary because of the unintended consequence of its shortage pricing rules, which require that Tier 1 reserves be paid the Tier 2 synchronized reserve clearing price any time the non-synchronized reserve clearing price is above $0.
“This rule significantly increases the cost of Tier 1 synchronized reserves with no operational or economic reason to do so,” the Monitor said in the 2013 State of the Market report. “PJM is not actually reserving any Tier 1 but simply paying substantially more for the same product without any additional performance requirements.”
Although the rule doesn’t apply in most hours, when it does, it’s expensive. In 2013, the Monitor said, 40% of payments for Tier 1 reserves were paid when they were not needed. “This is a windfall payment to Tier 1 reserves,” the Monitor said.
Bowring said PJM’s proposal will not eliminate the problem. The RTO would still pay some Tier 1 resources the Tier 2 price when the non-synchronized reserve price is greater than zero, he said.
Ohio electricity consumers paid FirstEnergy $6.9 billion to compensate the company for generation assets “stranded” when its monopoly over energy sales was eliminated in 1999.
Now, FE is asking them to pay again to prop up nuclear and coal generating plants the company says are at risk of closing due to low energy and capacity prices.
While the economics of the proposal aren’t convincing to consumer advocates and environmentalists, the company seems to be betting on its appeal to state lawmakers eager to save the plants’ jobs and tax revenues.
Under a proposal dubbed “Powering Ohio’s Progress,” the company asked the state Public Utility Commission last week to order three of its regulated utilities to sign 15-year purchase-power agreements with the Davis-Besse nuclear plant, the mammoth coal-fired W.H. Sammis plant and two Ohio Valley Electric Corp. (OVEC) units — located in Gallipolis, Ohio, and Madison, Ind. — in which it owns a 105-MW interest.
FirstEnergy Assumptions
In effect, FE wants distribution customers of Toledo Edison, Ohio Edison and The Illuminating Company to subsidize the plants in at least the short term in return for the potential upside in the later years. FE projects market revenue will begin exceeding costs in 2019 and continue to do so throughout the remainder of the program, saving retail customers $2 billion (nominal) or $800 million in net present value — an average of $360 (nominal) per customer — over the 15-year term.
The projected savings are based on layers upon layers of assumptions, including future fuel prices, economic growth and operating expenses. Some of the assumptions, such as an ICF International projection on future electricity prices, have been redacted and cannot be inspected by the public (though the numbers will be available to Ohio PUC analysts).
UBS Securities said the PPA was priced to begin at about $65/MWh — $26 above current market prices —and increase by $2/MWh annually.
FE said the plan will “help mitigate rising retail prices and help ensure that vital baseload power plants built to serve Ohio customers remain available to support the state’s electric consumers and businesses.”
“Ohio’s economic security and quality of life is highly dependent on maintaining a diverse mix of baseload coal and nuclear power plants,” FirstEnergy CEO Anthony Alexander said in a statement. “Powering Ohio’s Progress helps ensure these vital facilities continue powering the state’s energy-intensive economy, helps protect customers against volatility as future prices rise, and preserves $1 billion in annual statewide economic benefits, vital tax revenues for local communities and an estimated 3,000 direct and indirect jobs created by these plants.”
Deja Vu
The proposal makes no sense to the Office of the Ohio Consumers’ Counsel.
“1.9 million consumers paid billions of dollars to FirstEnergy for its transition to deregulated power plants under a 1999 Ohio law,” OCC spokesman Scott Gerfen said. “Fifteen years later, FirstEnergy is again asking consumers to pay charges related to the power plants. FirstEnergy’s requests include asking the government to guarantee profits for what are deregulated power plants whose profits should instead be determined by the electricity market.”
The Sierra Club also was critical.
FE “is essentially asking for a blank check to bail out their dirty, aging coal plants at the expense of customers, the environment and public health,” said Daniel Sawmiller, senior campaign representative for the Sierra Club’s Beyond Coal campaign. “We are urging the PUCO and Gov. [John] Kasich not to make Ohioans pay more every month for dirty coal plants.”
“The fact is,” Sawmiller said, “Ohio is a de-regulated state. They just want to go back to rate base. That is not what the law is in Ohio.”
Volatility Protection
That’s not how FE sees it. Company spokesman Douglas G. Colafella said Friday that the plan is aimed, in part, at preserving the reliability of regional power grid, and protecting FE customers from weather-related price spikes.
“Recent weather events, such as last winter’s polar vortex and September 2013’s unseasonable heat wave, have exposed potential vulnerabilities on the electrical grid serving Ohio and surrounding areas — in some cases resulting in severe retail price spikes,” he said. “In addition, a significant number of baseload power plants are being prematurely retired due to a variety of factors. Together, these issues are putting Ohio’s energy future at risk by challenging the reliability and affordability of electricity in our region.”
Under the plan, FE’s regulated Ohio utilities will buy the plants’ output from unregulated FirstEnergy Solutions, the power plant owners, and then sell it into PJM’s capacity, energy and ancillary services markets from June 2016 through May 2031.
The regulated utilities would pay all of the plants’ expenses, including fuel, operations and maintenance, depreciation and taxes, plus a “reasonable” return on invested capital of 11.15%.
The three utilities would net the revenues against costs, with the difference being passed along to customers through a “retail rate stability rider” that would act as a charge or credit on their monthly bills based on the fortunes of the plants in PJM’s markets. The utilities would freeze distribution rates, which they say have increased only 1% since 2009, through 2019.
“As power prices increase as projected over time, proceeds from the market sales that exceed costs from the purchased power agreement will be applied as credits on customers’ electric bills to mitigate volatility and address rising retail prices,” FE said in a press release.
The company predicts that its regulated utility customers in Ohio would pay higher prices for the first three years — about $3.50 per month for the first year — and then the market prices would increase and the surcharge would transform into a credit. None of it, however, is guaranteed.
Tough Sell
UBS analysts, who last month changed their outlook on FE from “hold” to “sell,” issued a report last week expressing skepticism that the company will win commission approval for the proposal, although a smaller, less expensive plan might pass muster.
“Given the PUCO staff’s rejection of AEP’s proposal to add just its OVEC ownership into a PPA rider, we suspect a similar reaction from staff,” UBS said. “The fundamental question for Ohio remains how politically palatable will it be to continue to allow substantial coal and nuclear retirements?”
FE is portraying the plan as an attempt to save two of its largest generation assets — the 2.2-GW Sammis plant and the 908-MW Davis-Besse nuclear plant. But UBS said the company’s leverage with state officials was reduced by the disclosure that the two plants cleared PJM’s Base Residual Auction in May.
In its quarterly earnings filing last week, FE reported that it cleared 8,930 MW in the capacity auction, up from 7,440 in the 2013 auction but down from the more than 10,000 MW that cleared in the prior three auctions.
Mansfield Retirement Risk
FE officials said that because its 2.4-GW Bruce Mansfield coal-fired plant had not cleared the auction, it would delay spending on a dewatering facility it needs to continue operation beyond the end of 2016, when the plant’s coal ash waste impoundment must close. The plant is Pennsylvania’s largest generator.
The Ohio PUC has not yet set a hearing date on the 1,000-page filing; the company has requested a decision by next April.
There are certain to be many eyes on the plan going forward.
“Needless to say, we are concerned for consumers,” OCC’s Gerfen said. “We are analyzing FirstEnergy’s new request, including its claim that there will be future cost savings. We then will make recommendations on behalf of consumers to the PUCO.”
PJM has created a new emergency procedure and is testing a software fix following poor generator response to a minimum generation event July 5, officials told the Operating Committee last week.
Extremely mild temperatures and a holiday weekend resulted in an RTO peak of 61,300 MW — unusually light but in line with PJM’s forecast — forcing PJM officials to curtail 2,000 MW of imports and order cuts of 100% of reducible generation.
Of about 200 generation owners, only 31 (16%) responded to the eDart minimum generation report. Of those that responded, only half reported an emergency reducible value greater than 0 MW.
But only 1,458 MW of the 1,665 MW of reducibles — units that said they were willing to go below their economic minimum — responded, PJM’s Chris Pilong told the committee.
Among combined-cycle owners that responded, all reported economic minimum ratings — the lowest level a unit can achieve while following economic dispatch — equal to their emergency minimum — the minimum generation that can be produced by a unit while maintaining stability.
“We only know what the generation operators, owners tell us,” said Mike Bryson, executive director of system operations.
Pilong said the responses indicate the need for additional training. “We really need to be sure we have the right rules in place so that people are reporting the real emergency min and not the eco min.”
Low Prices
Pilong said many generators entered low-priced offers for the weekend, wanting to keep running over the holiday to capitalize on hot weather forecast for the following week. Pilong said operators also were stressed by the inability of PJM’s dispatch engine to set proper price signals for wind units bidding below $0/MWh.
The RTO is testing a software fix to allow prices as low as -$60/MWh, which should help incent wind units to respond automatically via automatic generation control (AGC). Currently, some wind operators do not respond to AGC signals, requiring phone calls from PJM operators.
In addition, PJM has created a new minimum generation advisory procedure that it can issue one or two days in advance of anticipated light load days.
Minimum Generation Event Chronology
PJM declared a minimum generation alert at 10:25 p.m. July 4, saying the RTO was within 3,286 MW of normal minimum energy limits.
At 12:25 a.m. July 5, a Saturday, operators issued a minimum generation emergency declaration, reducing prices to $0/MWh and indicating a need to cut generation at 3 a.m.
Shortly before 3 a.m., operators declared a minimum generation event, ordering a 50% cut in reducible generation. Generators were encouraged to sell energy outside the control area.
Thirty-five minutes later, operators upped the call for reducible generation cuts to 100%. It remained there until shortly before 8 a.m., when it was reduced to 50%.
Before then, at 3:30 a.m., operators manually ordered all remaining wind (1,000 MW) to zero and ordered three other generators offline. All hydro was either offline or pumping into storage.
Hot Water Heaters
John Farber of the Delaware Public Service Commission said the incident illustrated why PJM should create a resource category for thermal storage, such as hot water heaters, that can provide load. “PJM could help [the Department of Energy] move off the dime,” Farber said.
Farber was referring to DOE’s pending decision on whether to exempt large capacity grid-interactive water heaters from current energy efficiency standards or regulate them under a separate category.
A federal judge approved a $27.8 million settlement between the Tennessee Valley Authority and property owners harmed by the utility’s massive coal ash spill in 2008. The spill occurred when a dike burst at TVA’s Kingston Fossil Plant and released more than 5 million cubic yards of toxic ash sludge from a containment pond. The sludge flowed into a river and fouled hundreds of acres along the river about 35 miles west of Knoxville, affecting about 800 property owners. U.S. District Court Judge Thomas Varian found TVA at fault in 2012.
The Federal Energy Regulatory Commission last week approved a consent agreement that its Office of Enforcement and the North American Electric Reliability Corporation reached with the Imperial Irrigation District relating to a Sept. 8, 2011 blackout that left more than 5 million in the dark. NERC and FERC found that the IID violated four Reliability Standards in its operations leading up to the blackout that spread from Southern California to Arizona and Baja California, Mexico. The settlement mandates that the IID spend at least $9 million on system reliability improvements, with the remaining $3 million going to the U.S. Treasury and NERC.
The Department of Energy has developed an Internet-based portal to a trove of its scholarly publications and research data. The Public Access Gateway for Energy and Science – PAGES – provides free access to manuscripts and published scientific journal articles within a year of publication.
“Increasing access to the results of research … will enable researchers and entrepreneurs to capitalize on our substantial research and development investments,” Secretary of Energy Ernest Moniz said. PAGES already contains a collection of accepted manuscripts and journal articles, and more data and links to articles and accepted manuscripts will be added as they are submitted. DOE hopes it grows by up to 30,000 articles and manuscripts a year.
The Environmental Protection Agency last week named Lisa Feldt as acting deputy administrator, the second highest position in the agency. She replaces Bob Perciasepe, who served in the position since 2009. Perciasepe is leaving to become director of the Center for Climate and Energy Solutions, an advocacy group. Feldt’s appointment was among several staffing announcements at the agency.
EPA Chief: Climate Change Should Be Taught in Schools
Gina McCarthy
Environmental Protection Agency Director Gina McCarthy said in an interview she thinks the science behind climate change should be taught in the nation’s schools. “I think part of the challenge of explaining climate change is that it requires a level of science and a level of forward thinking and you’ve got to teach that to kids,” McCarthy said in an interview published last Friday in the magazine Irish American. Observersbelieve her remarks will generate controversy, especially among Republican lawmakers who remain skeptical of the idea of man-caused climate change.
The Nuclear Regulatory Commission is expected to issue the final rule governing storage of nuclear waste, a rule that has impacted nuclear generating stations’ ability to store used fuel on site. The U.S. Court of Appeals for the D.C. Circuit in 2012 found that the NRC rule allowing on-site storage for up to 60 years violated the National Environmental Policy Act and ordered the NRC to come up with a new rule. The new rule is expected to be released within a month and will be named “Environmental Impacts of Continued Storage of Spent Nuclear Fuel Beyond the Licensed Life for Operation of a Reactor.”
The Nuclear Regulatory Commission last week cited Exelon, operator of the Calvert Cliffs nuclear station in Lusby, Md., for a miscalculation that could have led to an unnecessary evacuation. Radiation detectors at the plant were accidentally set to trigger an alarm at radiation levels 100 times lower than what would have posed a safety threat. The alarm was never activated, and workers discovered the mistake and corrected it four months later.
NRC inspectors said the mistake could have caused an unnecessary evacuation and deemed it a safety violation. “Ideally, we want them to be in the right zone if they have an emergency event,” NRC spokesman Neil Sheehan said, “not under-classifying it but not over-classifying it, either.” The violation could result in increased NRC scrutiny of the plant.
PJM received 106 proposals to fix about 50 reliability problems in the first Regional Transmission Expansion Plan window for 2014.
Fifteen companies made proposals in the window that closed July 28. PPL was the most ambitious, offering 16 projects totaling almost $3 billion.
It was the first full-scale reliability window opened by PJM under the Federal Energy Regulatory Commission’s Order 1000. Last year, PJM opened a window for a single reliability problem at Artificial Island and one for “market efficiency” proposals intended to reduce congestion.
The PPL projects include the reliability portion of a 725-mile, 500-kV transmission line that would run from Western Pennsylvania into New York and New Jersey, with a spur running south into Maryland, at an estimated cost of $4 billion to $6 billion. PPL said the line would address reliability problems on three 230-kV lines, as well as relieve congestion and move power from planned generators fueled by shale gas in northern Pennsylvania.
Four other companies – Public Service Enterprise Group, Transource Energy, ITC Holdings and LS Power’s Northeast Transmission Development – each proposed projects totaling more than $500 million.
They include 61 greenfield projects (total $5.7 billion) and 45 transmission owner upgrades totaling $522 million. Targeted were 18 transmission zones in 10 states, with Atlantic City Electric (AE), PPL, American Electric Power and American Transmission Systems Inc. each attracting 10 or more proposals.
The proposals are intended to address reliability violations that would occur through 2019. Some problems may be moot by that time, however, according to Paul McGlynn, general manager of system planning. Some violations in the AEP transmission zone, for example, will be eliminated by the planned retirement of AEP’s Tanners Creek generators, scheduled for mid-2015.
“We may not act on [all of] these issues,” McGlynn said. “There’s a lot of failings that won’t actually be problems.”
Conversely, problems identified in the AE zone because of capacity injection rights for the BL England generator may not manifest if the plant retires and is not replaced, planners said.
PJM plans to open a “long-term” window in November for market efficiency and reliability proposals addressing problems over a 15-year horizon.
Artificial Island Update
Meanwhile, McGlynn told the Transmission Expansion Advisory Committee that PJM will be sending Artificial Island project finalists Public Service Electric & Gas, Dominion Resources and Transource letters next week asking them whether they will join finalist LS Power in agreeing to cap the costs of their proposals.
McGlynn said the finalists would have no more than two weeks to respond and that PJM is still planning to make a selection by year’s end. “The answers we get back from the finalists may lead to more questions,” he said, promising an “open and transparent” process for comparing any revised proposals.
The allocation was split 50/50 based on load-ratio share and a distribution factor (DFAX) analysis. Planners said the original DFAX analysis assumed flows for a new 500-kV line between Artificial Island in New Jersey and Red Lion, Del., would be predominantly west to east when they are actually the reverse.
Although revised calculations have not been completed, planners said they expect allocations for transmission zones west of Artificial Island to increase.
The original allocation would have assigned costs to among two dozen transmission zones and merchants with the Jersey Central Power & Light zone responsible for about 27% of the project and the AE zone picking up almost 20%.
The error did not affect the cost allocation for LS Power’s proposed 230-kV line between Artificial Island and Cedar Creek, Del., all of which would be allocated to the Delmarva Power & Light zone, according to PJM.
PJM dropped a proposal to consider changes to the regulation market after receiving a cool reaction from stakeholders and the Market Monitor.
PJM officials drafted a proposed problem statement in response to the polar vortex in early January, when regulation market prices spiked to 4.5 times normal levels.
Regulation prices hit $3,296/MWh at the peak of the polar vortex as real-time energy prices rose above $1,800/MWh. Including lost opportunity costs — for example forgone revenue in the energy market — PJM rang up a $65 million bill for regulation in January.
PJM’s Jeff Schmidt said the jump was due in part to the fact that high-performing generators were being used for energy and reserves instead of regulation, leaving the RTO to rely on poorer-performing generators to maintain system frequency at 60 hertz. Regulation market prices can be influenced by poorer-performing resources because the calculation uses a “historic performance score” in the denominator.
The issue was first raised in PJM’s analysis of the system’s performance during January’s cold. PJM said stakeholders should consider whether the division by the performance score is appropriate and whether the minimum participation requirements are high enough. It also said they should consider whether to go short on regulation during system peaks.
But the 4x jump in regulation prices was actually far below the increases in operating reserve (10x) and synchronized reserve (9x) costs for the same period.
“I don’t understand why it’s a problem,” Market Monitor Joe Bowring said during a discussion before the Market Implementation Committee last week. “Poor-performing resources raised the prices. That’s exactly the way it’s supposed to work.”
Brock Ondayko of American Electric Power Energy Supply agreed with Bowring. “If we start weeding out the slower performers I guess you would end up with no regulation resources,” he said.
“That certainly could happen,” Schmidt acknowledged.
Public Service Enterprise Group’s John Citrolo said it was improper for PJM to take an “administrative role” in controlling volatility “rather than letting the market handle it.” He said load-serving entities can hedge against such risks.
John Webster of Icetec said increasing the performance requirement for regulation resources might actually increase prices.
After an extended discussion, MIC Chair Adrien Ford said she would table the matter, though PJM may bring it back at a later meeting.
Performance-Based Pricing
In response to the Federal Energy Regulatory Commission’s Order 755, PJM switched in October 2012 to performance-based regulation, which is intended to pay resources based on the accuracy, speed and precision of their response.
In the 2013 State of the Market report, the Monitor said that the changes had improved the regulation market, but that the market’s design remained “flawed,” including an incorrect definition of opportunity cost and an inconsistent implementation of the marginal benefit factor — a conversion calculation — in optimization, pricing and settlement.
DELAWARE Lawmaker Proposes Study for Power Aggregation
Colin Bonini
A Delaware lawmaker included a proposal for an electricity aggregation study into the state’s capital budget this year in a move that could lead to lower electricity prices for local governments and their residents. The measure, penned by state Sen. Colin Bonini (R-Dover South), calls for the assessment of local conditions and a study of best practices in other states. Aggregation programs allow for large groups to buy power in blocks, with the idea that the group could negotiate a better deal than the standard offer from utilities. Delmarva Power & Light officials said they were studying the proposal.
Wisconsin Energy Promises Rate Freeze in Acquisition
Wisconsin Energy is promising to freeze rates and guarantee jobs for at least two years in an attempt to convince the Illinois Commerce Commission to OK its proposed acquisition of Integrys Energy Group. Wisconsin Energy is trying to buy Integrys, parent company of Peoples Gas and North Shore Gas of Illinois. The company said if it obtained ICC approval, it would freeze rates for Illinois customers and keep the same number of Illinois employees – about 2,000 – for at least two years, in addition to honoring all labor contracts. The ICC is only one of several state and federal approvals necessary for the acquisition.
NRG Energy said it has a plan to cut emissions at four of its coal-fired stations in the state that would bring the state more than halfway toward meeting new Environmental Protection Agency-mandated emissions limits. The company said it would stop burning coal at one of its Romeoville plant units, convert its Joliet plant to burn natural gas and upgrade the Pekin and Waukegan plants with new emissions-control technology. About 250 jobs would also be cut. NRG said the plan would cut about 16 million tons of carbon dioxide emissions a year. The plan would cost about $567 million, the company said.
The Indiana Association for Community Economic Development received a $400,000 grant to help start up small solar energy projects in the Indiana Michigan Power service territory. The grant, which came from a legal settlement between American Electric Power and the U.S. Environmental Protection Agency, will be used to start Solar Uniting Neighbors (SUN). The economic development association said the grant would be enough to provide funding for 10 to 17 solar installations.
Small-scale solar- and wind-power installations in the state have increased their energy production by 18% since 2012, according to a Public Service Commission report. Since a state-mandated metering system went into effect in 2008, the state has seen 1,527 customers enter the net metering program.Under a net metering program, when customers produce more electric energy than they consume, the excess is sent back to the grid and the customer gets a credit. The PSC report noted that the number of net metering customers increased from 1,330 in 2012 to 1,527 in 2013.
Clean energy and environmental advocates urged state officials to rejoin the Regional Greenhouse Gas Initiative during a court-ordered hearing last week. Two years after Gov. Chris Christie withdrew from the RGGI, a state appeals court ruled that the administration and the state Department of Environmental Protection didn’t follow the proper rules, and ordered a hearing to reconsider the move.
While it is unclear whether the court-ordered hearing would have an effect on the decision, many speakers took the opportunity to urge state leaders to rejoin the regional effort.Doug O’Malley, the director of Environment New Jersey, which filed the lawsuit along with the Natural Resources Defense Council, said he hoped the legislature would invalidate the repeal. “Gov. Christie is on the wrong side of public opinion on his decision to pull New Jersey out of this landmark climate program,” O’Malley said.
The state Division of Rate Counsel is again asking the Board of Public Utilities to tighten rules governing third-party energy suppliers. The consumer advocate’s efforts were spurred by a tough winter, skyrocketing energy prices and widespread accusations of misleading or fraudulent business practices.
Rate Counsel Director Stefanie Brand said her new petition was produced after consultation with the Retail Energy Suppliers Association. “The most important improvement is increased disclosure, in clear and plain language, of all contract terms,’’ one part of the petition explains.
Some of the proposed rules mirror those being considered in the state legislature.
Wind energy developer Fishermen’s Energy signed an agreement with the Department of Energy last week, giving it access to almost $47 million to develop a 25-MW wind project off Atlantic City. The project seems to be going forward, even though the New Jersey Board of Public Utilities has denied it ratepayer subsidies and said the project is too expensive and risky. Fishermen’s is appealing that ruling.
One of the terms of the DOE grant is that the project have a customer for its energy one year from now. But the developers are optimistic. “Our goal here in Atlantic City is to build a commercially operational wind farm that demonstrates job creation and specifically to show that these types of projects create benefits that far exceed their costs,” said Chris Wissemann, Fishermen’s CEO.
While North Carolina ranks fourth in the nation for overall solar capacity, it is only 10th per capita, behind cloudier states such as New Jersey and Massachusetts, according to a report by an environmental group calling for more solar-friendly state policies.
Environment North Carolina said the state has benefited from the rise of large-scale solar farms but lagged in residential and commercial rooftop systems. The report recommends the state enable third-party sales of electricity, improve net metering laws and expand renewable energy standards.
The state Department of Natural Resources said the 1,000th Utica Shale well will be drilled as early as this week. Through last week 997 horizontal wells had been drilled out of 1,428 permits issued since the shale boom started in 2010.
The Ohio Supreme Court will be called on to determine how much net metering customers should be paid for electricity they feed back into the grid in a case pitting the Public Utility Commission of Ohio against several large utilities.
PUCO ruled recently that net metering customers are entitled to full value of the electricity, including capacity. FirstEnergy and American Electric Power have argued that their compensation should be based only on the energy portion of their bills. AEP appealed PUCO’s latest ruling, in July, to the state Supreme Court.
The Public Utility Commission is considering a rule that would limit the amount of solar energy customers can sell back to the grid. “By customer-generators producing more electricity and selling it back to the grid and the utility, this could actually be passed through and affect the rates for other customers,” PUC spokeswoman Robin Tilley said. The proposed rule would limit energy production for households and businesses to 110% of annual consumption. The solar industry opposes the rule.
State Department of Environmental Protection filings show that Chesapeake Energy, one of the largest shale gas energy players in the Midwest, is looking at the state as its next gas frontier. Chesapeake was one of the first companies to start drilling into Ohio’s Utica Shale Field. The Point Pleasant formation, in West Virginia, could be the scene of the next rush for shale gas production. State Department of Environmental Protection files show that Chesapeake is outlining plans to drill wells in the Point Pleasant formation.
It’s time for President Obama to start reviewing resumes again.
Just days after Norman Bay was sworn in as the Federal Energy Regulatory Commission’s fifth member, Democrat John Norris announced he will resign his position almost three years early, creating yet another opening on the panel.
Bay was sworn in Monday after taking a swipe at the PJM energy traders who had dogged him through his confirmation process.
On Friday, Norris confirmed long-standing rumors of his departure by announcing he will leave FERC Aug. 20 to take a post as the Minister-Counselor for the U.S. Department of Agriculture in Rome.
In between, newly promoted Chairman Cheryl LaFleur asserted her authority by filling the General Counsel’s post.
All in all, just another week at 888 First St. NE.
In one of his last acts as director of the FERC Office of Enforcement, Bay authorized the issuance of a Staff Notice of Alleged Violations against a group of investors over what staff said was illegal “wash” trades intended to capitalize on transmission line-loss rebates in PJM.
The notice, issued Tuesday, targets Kevin and Richard Gates, who launched a publicity campaign and lobbied against Bay’s nomination to highlight their complaints over FERC’s investigation. (See related story, PJM UTC Case Likely Headed to Court.)
Obama had indicated his intent to make Bay chairman immediately after his confirmation. But in order to win crucial votes in the Senate, the White House agreed to delay Bay’s promotion until April 15.
Cheryl LaFleur Flexes
That makes LaFleur, who had served as acting chair since November, kind of a Cinderella chairman.
But, apparently emboldened by Obama’s decision July 30 to remove her “acting” title, she asserted her authority Thursday by doing the same for former acting General Counsel David Morenoff, who has been doing that job since October 2012.
Meanwhile, Norris announced he would leave — not to return to his home in Iowa, as some had expected, but to Italy, thanks to Secretary of Agriculture Tom Vilsack.
Norris had served as Vilsack’s chief of staff, both in the Agriculture Department and before, when Vilsack was Iowa’s governor.
Norris issued a statement praising his FERC colleagues before heading off to a camping trip in Maine with his family. He was unavailable for comment yesterday.
Colette Honorable Next?
Colette Honorable
With Norris departing, speculation on his replacement has focused on Arkansas Public Service Commission Chair Colette Honorable. She was named chair of the Arkansas commission by Gov. Mike Beebe, whom she previously served as chief of staff when he was attorney general. Her six-year term expires in 2017. Honorable is also three-quarters through her one-year term as president of the National Association of Regulatory Utility Commissioners (NARUC).
A lawyer and native of Little Rock, she previously served as executive director of the Arkansas Workforce Investment Board and as an attorney in the Attorney General’s Office, where she worked on Medicaid fraud cases. She has also worked as an attorney at the Center for Arkansas Legal Services, a law clerk in the Arkansas Court of Appeals and as an assistant public defender.
She did not return a request for comment yesterday.
Lame Duck
Norris’ departure was widely expected after he told a conference in June that he would not seek renomination when his term ended in 2017. Norris said industry stakeholders had told him he could not win Senate confirmation if he was reappointed because he is too “pro-consumer.”
Last year, Norris blasted Senate Majority Leader Harry Reid (D-Nev.) for blocking his bid to become FERC chair. Norris said Reid had opposed his elevation to chairman because the majority leader thought he was “too pro-coal” during his time on the Iowa Utilities Board.
Since last year, Norris has increasingly forged his own path. After issuing 11 dissents or concurring statements in 2010, and 11 in 2011, he issued 19 last year and 11 through the first six months of 2014.
Norris’ wife Jackie ran the 2008 Obama campaign in Iowa and briefly served as Michelle Obama’s chief of staff; she is now executive director of the Points of Light Corporate Institute, an organization that helps companies develop employee-volunteer programs, in D.C.
Before Norris’ announcement last week, an editorial in The Storm Lake Times urged him to return home to run for office, suggesting he was one of the few Democrats who could oust Rep. Steve King or Gov. Terry Branstad. He had run unsuccessfully for the House in 2002.
The Work Goes On
Republican Commissioner Tony Clark said yesterday he will miss working with Norris, who he has known since they were both state regulators.
Clark said while it would be nice to have a full panel, there haven’t been many occasions when the panel locked in 2-2 ties.
While Bay may emphasize new initiatives when he becomes chair, Clark said, much of the commission’s day-to day activities will be unchanged. “A lot of the work is just driven by the filings themselves,” he said.
PJM officials last week defended their practice of creating interfaces to capture operator actions in response to voltage problems, saying they can’t guarantee the constraints will be modeled in Financial Transmission Right auctions.
In the last year, PJM has created “closed loop” interfaces in at least four locations so that operator actions — such as sub-zonal dispatch of demand response — are captured in Locational Marginal Prices rather than uplift. PJM said it must use the interfaces to set prices because its modeling software can only set prices for thermal constraints, not voltage problems.
But in its effort to reduce uplift, PJM is exacerbating FTR underfunding, DC Energy’s Bruce Bleiweis told the Market Implementation Committee during a discussion last week.
PJM has promised to provide notice of any new interfaces at least one day before implementing them. But that’s not enough time for FTR holders to react, said Bleiweis, who noted that the RTO requires 90 days’ notice before implementing special protective schemes (SPS).
He proposed PJM provide notice of the potential need for a new constraint as soon as it has identified one and discuss the results of their analysis at the next meeting of the MIC or Markets and Reliability Committee. Interfaces should be announced prior to the next FTR or Balance of Planning Period auction and not implemented until the beginning of the next month, Bleiweis said.
PJM “shouldn’t be in the position of choosing who will gain and who will lose,” he said.
PJM officials said Bleiweis’ proposal was unworkable.
“A lot of those things come up quicker than the time that Bruce would want,” said Adam Keech, director of wholesale market operations. “We might know two days before we need it, not 45 days. Forty-five days later we may not need it. We’re just printing uplift in between.”
