The Federal Energy Regulatory Commission on Thursday approved a rule to improve coordination of the wholesale natural gas and electric market schedules, adopting two gas scheduling changes but declining to move the start of the gas day to 4 a.m. CT from 9 a.m. CT (RM14-2).
Order 809 revises the interstate gas nomination timeline, moving the timely nomination cycle deadline for scheduling gas transportation to 1 p.m. CT from 11:30 a.m. CT. It also adds a third intraday nomination cycle, which should allow shippers to better adjust to changes in demand.
Thursday’s order was a win for the Natural Gas Council, which last year rejected an earlier start time, saying it would cause safety and contractual problems. The group represents nearly all the companies that produce and deliver gas, including members of the American Gas Association, America’s Natural Gas Alliance, the Independent Petroleum Association of America, the Interstate Natural Gas Association of America and the Natural Gas Supply Association.
The failure to reach consensus between the electric and natural gas industries was noted in a FERC staff presentation at the commission’s open meeting Thursday. “The … final rule finds that there has not been a showing that the benefits of changing the nationwide gas day from 9 a.m. CT to 4 a.m. CT sufficiently outweigh the potential adverse operational and safety impacts and costs of making such a change,” staff said.
Growing Pains
Facing opposition from pipeline operators, FERC retreated from its earlier proposal to move up the start of the gas day.
The growth in natural gas-fired generation has strained pipeline capacities and provided operational challenges to grid operators. Two issues were spotlighted: communications between generators and natural gas transmission operators, and gas-electric scheduling.
In November 2013, the commission approved a rule allowing gas pipeline operators to exchange non-public operational information with RTOs. (See FERC OKs Gas-Electric Talk.)
A 2013 report by the North American Electric Reliability Corp. said that the disparity in schedules meant that “electric generator nominations, with their relatively large gas loads, are based upon estimates by the individual fuel planners of each Generator Owner (GO) between 24 and 36 hours in advance. The issue could be magnified when scheduling on a Friday, since gas markets are closed for the weekend.”
The new rule “illustrates how the commission can engage with industry and stakeholders in a collaborative process to offer real improvements in our natural gas and electricity markets,” Commissioner Cheryl LaFleur said in a statement.
The American Gas Association, which represents more than 200 local distribution companies, praised the ruling.
“I am pleased to see that FERC will maintain the 9 a.m. CT start time, a positive step that recognizes what is in the best interest of both gas and electric customers,” CEO Dave McCurdy said. “We appreciate FERC’s attention to the coordination between gas and electric systems, and believe this is a critical issue that needs attention, but changing the gas day was not a step that would have ultimately improved this coordination.”
Retreat
But Thursday’s order was a retreat from the commission’s March 2014 Notice of Proposed Rulemaking, which proposed the 4 a.m. start time. (See FERC: Six Months to Move Gas, Electric Schedules.)
The commission approved the NOPR on a 3-1 vote with LaFleur, Commissioner Philip Moeller and former Commissioner John Norris in support. Commissioner Tony Clark dissented, saying he wanted to give the industries more time to reach consensus. Since then, the commission has added Commissioners Norman Bay and Colette Honorable.
The rule becomes effective 75 days after publication in the Federal Register. Each ISO and RTO must come up with tariff revisions to either coordinate its day-ahead market with gas pipeline scheduling changes or show why changes shouldn’t be implemented.
The Federal Energy Regulatory Commission on Tuesday rejected the rate schedule proposed for a struggling nuclear power plant needed for reliability in western New York and ordered hearing and settlement proceedings (ER15-1047).
The commission approved only part of the reliability support services agreement for the R.E. Ginna nuclear plant between Rochester Gas & Electric and Exelon’s Constellation Energy Nuclear Group, the plant’s owner, which is also under review by the New York Public Service Commission.
The commission rejected the proposal that Ginna receive 15% of its NYISO market revenues, saying it “does not comport with the general principle that rates under [a reliability-must-run] agreement must be cost-based.”
“A compensation structure that provides for both a cost-based monthly fixed rate (whether going-forward costs at the low end, or a full cost of service at the upper end) and a share of market revenues does not meet this principle, as the revenue-sharing provision is not cost-based and may allow for Ginna to earn more than its full cost of service,” FERC wrote.
The commission approved a provision that would require Ginna to repay capital investment costs it recovers under the RSSA if it were to return to the market after the agreement’s expiration.
The capital recovery balance would range between $20.1 million and $65.3 million depending on when it was invoked, “a sufficient disincentive” to dissuade Ginna from “toggling” between compensation under the RSSA and the NYISO markets, the commission said.
FERC thus excluded the issue of toggling from the hearing but said it may address whether the amounts in the capital recovery balance are just and reasonable.
FERC said it would allow about 45 days for settlement discussions before scheduling a hearing.
The RSSA was ordered by state officials and is scheduled to be retroactive to April 1, once approved by regulators. The agreement would cost about $175 million a year and be effective through late 2018. Ginna says it lost more than $150 million between 2011 and 2013.
The immediate effect of FERC’s order is that a procedural case before administrative law judges of the PSC has been slightly delayed. The PSC ordered initial “issue statements” by April 15 in a review of the rate impact on consumers, but that has been pushed back until April 22. (See NYPSC Rejects Opponents’ Request for More Time in Ginna Rate Review.)
As a result, Tuesday’s order also struck a provision allowing an extension of the agreement beyond 2018. “If there is a future reliability need for the RSSA beyond its initial term, Ginna will be subject to the procedures that NYISO establishes, and the commission approves, in response to the NYISO RMR order,” FERC wrote.
MISO completed its third annual Planning Resource Auction on Tuesday, with prices falling in most zones, while the Illinois zone saw a large jump that will boost revenues for Dynegy’s coal fleet and Exelon’s Clinton nuclear plant.
With 136,359 MW committed, MISO said it has adequate capacity for the 2015/16 planning year beginning June 1 but acknowledged that the 2016/17 period could see capacity shortfalls amid the ongoing retirement of coal-fired generation.
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Most of that — 122,965 MW — was generation resources. The remainder consists of 5,938 MW of demand resources, 3,986 MW of behind-the-meter generation and 3,469 MW of external resources.
The auction resulted in a slight increase in Zone 1, big drops in Zones 2-3 and 5-9 and a nine-fold increase in Zone 4:
Zones 1-3 and 5-7, consisting of MISO North/Central but excluding Illinois, cleared at $3.48/MW-day. That compares with $3.29 in Zone 1 and $16.75 in Zones 2-3 and 5-7 in 2014/15.
Zone 4, comprising much of Illinois, cleared at $150/MW-day, compared with $16.75 a year earlier.
Zones 8-9, comprising MISO South, cleared at $3.29/MW-day, compared with $16.44 a year earlier.
“While Dynegy is clearly the largest beneficiary of the MISO capacity auctions results, Exelon also gains via ownership of its Clinton nuclear asset,” UBS analyst Julien Dumoulin-Smith said in a report last week.
Dynegy said in a press release that its 4 GW coal-fired Illinois Power Holdings fleet cleared 1,864 MW at $150/MW-day, including 1,709 MW to cover retail load obligations. Its separate 2,980-MW “coal segment” also cleared 398 MW at that price.
Exelon spokesman Paul Elsberg confirmed that the Clinton plant cleared the auction but said the increase was insufficient to make the plant profitable. Exelon has been pushing legislation that would charge Illinois electricity users a fee to ensure the continued operation of Clinton and two other unprofitable nuclear generators. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.)
“The auction results reduce Clinton’s economic losses, but the plant remains uneconomic and may prematurely shut down absent Illinois legislative changes to outdated policies that do not allow nuclear energy to compete on a level playing field with other zero-carbon resources,” Elsberg said in a statement.
“The wholesale price increases from the auction are small compared to the price spikes that would occur if Clinton is forced out of the market. According to the Illinois Commerce Commission and grid operators, closing the Clinton plant alone would cause wholesale energy prices to rise by $240 million to $340 million annually.”
Clinton would earn $58 million in capacity revenue if it bid and cleared all of its 1,065 MW capacity. Elsberg declined to say how much capacity Clinton cleared.
MISO said market participants lowered offers in most zones as a result of small changes in the balance of resources and load and an increase in Fixed Resource Adequacy Plans (FRAPs).
Zone 4’s $150 clearing price resulted from less self-scheduling and the submission of “more economic, price-sensitive offers,” MISO said.
Although total offers exceeded the zone’s local clearing requirement of 8,852 MW by 2,300 MW, only 838 MW was offered through FRAPs, 9% of the LCR.
In contrast, FRAPs represented more than 90% of LCRs in Zones 1 (Minnesota, North Dakota and western Wisconsin) and 2 (eastern Wisconsin, and Upper Michigan).
Richard Doying, MISO’s executive vice president of operations and corporate services, said the voluntary auction’s “certainty and transparency” is “vital given the challenges we face with potential capacity shortfalls starting in the 2016/17 planning year.”
MISO is facing a reduction in coal-fired capacity due to retirements of aging coal plants squeezed by the Environmental Protection Agency’s tightening Mercury and Air Toxics Standards and low-cost gas-fired generation.
Coal-fired generation in MISO is expected to decrease from 46% of total installed capacity in 2013 to 36% in 2020, according to a whitepaper MISO released in March. EPA’s proposed Clean Power Plan, which would require a 30% reduction in CO2 emissions from existing generators, is expected to further thin coal fleets.
Late last month MISO underscored the problems that coal plant retirements will cause in its 15-state region. Launching its first in a series of stakeholder workshops during the next 18 months dedicated to improving resource adequacy, MISO said its planning reserve margin requirement — peak demand plus the planning reserve margin — could dip below its target as early as 2016.
As the reserve margin declines, MISO may have to dispatch seldom-used capacity. That could include greater use of load-modifying resources, such as factories that can reduce usage by adjusting production schedules and commercial buildings that reduce air conditioning.
MISO has not called on those resources since 2006.
SPP’s Market Monitoring Unit asked the Federal Energy Regulatory Commission last week to reject a proposal that would bar the RTO from canceling commitments of gas-fired generators if they are not needed.
SPP’s proposal would result in “an inefficient transfer of gas market risks to SPP’s load,” wrote Catherine Tyler Mooney, the MMU’s manager of market analytics (ER15-1293). “… This commitment may impose uneconomic production on the market, impacting market prices, uplift, congestion, transmission congestion rights payments or market-to-market settlements.”
At issue is SPP’s March 16 proposal to codify its historical practice of not de-committing generators committed out of its multi-day reliability assessment during emergency operations. The Tariff change would bar SPP from decommitting such units unless they presented a reliability risk.
SPP proposed the change after some gas-fired generators in PJM complained that they suffered “stranded gas” losses in 2014 when they bought fuel at high prices in response to transmission operators’ directions that were not needed by the market later. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)
SPP said it filed the Tariff revisions in response to “stakeholders’ request for clarity on whether and how resources may be committed” under its multi-day reliability assessment if SPP has implemented conservative operations under its emergency operating plan. The proposal was approved by the RTO’s Members Committee and Board of Directors in January.
The MMU said the proposed change was problematic for several reasons. “First, it may be difficult for SPP to verify the legitimacy of unused fuel cost claims. Second, generator operators are in the best position to effectively minimize fuel costs.”
The MMU said that SPP should have the ability to reevaluate its need for generation during emergencies — if, for example, weather forecasts change.
“Avoidable adverse consequences should not be imposed on the market to lessen the predetermined cost exposure of individual generators,” the MMU said. “It is not a cost-minimizing market outcome. If SPP staff, its members and the commission believe that an uplift payment for unused fuel is necessary to preserve system reliability during emergencies, SPP should pursue that particular issue.”
VALLEY FORGE, Pa. — PJM planners said last week they will announce their revised recommendation to address stability problems at the Artificial Island nuclear complex at a special Transmission Expansion Advisory Committee meeting April 28.
Planners recommended Public Service Electric & Gas for the project last June, but the Board of Managers reopened the bidding to finalists Transource Energy, Dominion Resources and LS Power after criticism from environmentalists, New Jersey officials and spurned bidders.
All of the potential solutions involve new transmission lines connecting Artificial Island to Delaware. LS Power and Transource have proposed a southern crossing of the Delaware River. Dominion and PSE&G offered a northern route with an overhead crossing.
Planners had hoped to announce their revised selection in January but delayed their decision to allow consultants to investigate concerns that Dominion’s proposed use of thyristor controlled series compensation (TCSC) could threaten reliability at the island, home to the Salem-Hope Creek nuclear complex. (See Further Study Delays PJM’s Artificial Island Decision.)
PSEG Nuclear, which operates the nuclear plants, contends Dominion’s proposal would use unproven technology that could result in damage to turbine generator shafts.
Planners told TEAC members last week Siemens Power Technology International had completed its sub-synchronous resonance analysis of Dominion’s proposal and found that the TCSC could result in “negative damping” for several resonant frequencies.
However, Exponent, an engineering and science consulting firm that reviewed the Siemens study at PJM’s request, said it was “inconclusive” because of limits in the data available.
Exponent expressed its own concerns with the Dominion proposal. It said Dominion is proposing a 90% post-contingency TCSC compensation — well above the 70 to 80% compensation used by others in the industry.
Responding to questions from stakeholders who suggested more study might be needed to verify the feasibility of the Dominion proposal, Steve Herling, vice president of planning, said Siemens had identified the “potential for an issue.”
“It’s not a fatal flaw,” he said.
“[I]t’s an issue going forward,” said Thomas Leeming, director of transmission operations and planning for Exelon’s Commonwealth Edison. Not “having wrestled this to the ground could be an issue.”
“We understand what needs to be done if we go that way,” Herling responded. “We recognize that if we go with this solution there’s more work to be done. We’ve already talked to a number of manufacturers about all these issues.”
Planners said their current schedule would result in a recommendation to the Board of Managers’ Reliability Committee on May 19.
SPP could meet the Environmental Protection Agency’s 30% carbon dioxide reduction target by 2030 through a $45/ton carbon adder and 7.8 GW of additional generation, most of it wind, according to a report issued last week by the RTO.
The analysis, the RTO’s second on the potential impacts of EPA’s Clean Power Plan, estimates the cost of those measures at $2.9 billion per year, not including additional transmission or gas pipelines that will be needed.
SPP’s first study, released in October, concluded that EPA’s implementation timeline — particularly its 2020 interim goals — did not allow enough time to build needed generation and transmission to replace coal plant retirements and deliver wind power to population centers. It predicted SPP’s transmission system could face severe overloads, increasing the potential for cascading outages.
“This second analysis does not alter our earlier conclusion that additional infrastructure — and time — is needed to meet the CPP’s proposed CO2 emission goals,” Lanny Nickell, vice president of engineering, said in a statement.
During a series of technical conferences convened by the Federal Energy Regulatory Commission, and at meetings with state regulators, EPA officials suggested the final rule due this summer may relax the 2020 goals, which have been widely criticized as unworkable. (See EPA on Carbon Rule: We’re Listening.)
Methodology
SPP said its analysis found that the region could meet the EPA goal with a carbon adder — essentially a tax on a unit’s carbon emissions — of $60/ton of carbon emissions. But it said an adder cost of $30-$45 per ton would be most cost-effective.
The report’s conclusions are based on a $45/ton adder and the addition of 5.6 GW of wind and 1.2 GW of natural gas generation above that currently planned.
The $2.9 billion in annual costs is the result of $600 million in increased annual energy costs and $13.3 billion in capital spending. The study did not evaluate infrastructure needs and thus did not include costs of transmission or gas pipeline that would be needed.
The study assumed a 70% capacity factor for combined-cycle gas generators and 47% for new wind. The added wind generation would allow that resource to meet 25% of the non-coincident peak-load obligations in the region. SPP’s minimum 12% capacity margin was preserved in each load zone.
Unduly Pessimistic
The tone of SPP’s second analysis is less gloomy than that of the first, which warned of the possibility of rolling blackouts. But critics said the new report is still unduly pessimistic.
The American Wind Energy Association said SPP’s analysis overestimates compliance costs because it “arbitrarily” limited the region’s options.
Michael Goggin, AWEA’s senior director of research, said SPP’s assumption for the cost of new wind generation is about 40% higher than current wind in the region, a nearly $1 billion difference. “Those costs would be even lower if SPP accounted for how wind energy costs continue to fall drastically, dropping by more than 50% over the last five years,” he wrote in a blog post.
Goggin said SPP’s analysis also did not include energy efficiency as a compliance option and assumed almost no new gas generation would be built.
“SPP’s study essentially examines what would happen if the region tried to comply with one arm tied behind its back,” he said. “If the region had been allowed to fully utilize its abundant and low-cost resources of wind, natural gas, and energy efficiency, the cost of achieving the Clean Power Plan would have been far lower.”
SPP acknowledged it did not analyze each of the EPA’s proposed “building blocks.” Unlike the RTO’s Integrated Transmission Plan, the study also did not consider economic interchange with other regions. The RTO said it made this choice to minimize “the uncertainty associated with trying to determine how SPP’s neighbors will operate under their own compliance with the CPP.”
In an interview, Nickell said the AWEA critique failed to “recognize that the study was meant to be indicative as opposed to definitive.” Nickell said some potential compliance options were excluded to provide an apples-to-apples comparison for a third, state-by-state analysis, which is expected in early June.
“This isn’t the only way to solve the problem,” he acknowledged. “Clearly [energy efficiency] could reduce costs. It’s a matter of what could be done.”
While the study assumes only 1.2 GW of incremental gas-fired generation, that is in addition to 22 GW of new gas capacity already planned, he added.
Retirements
SPP’s scenario assumed about 2.2 GW of coal retirements “incremental to those retirements already planned,” based on those generators running below a 30% capacity factor after adding a $45/ton adder.
As much as 13.9 GW of generation could be at risk of retirement in addition to what is included in SPP’s current transmission planning models, SPP said.
“This assumption may be conservative considering that SPP’s analysis indicates nearly all existing coal-fired generation in the region would operate above 80% capacity factor without a carbon cost adder but approximately 12,200 MW of coal-fired generation would operate below 80% capacity factor with a $45/ton cost adder.”
The analysis does not take into account transmission constraints or interchange with adjacent pools, SPP said.
AWEA also criticized the report’s claim that 13.9 GW of coal is “at risk” of retirement.
“SPP gets to the extremely unrealistic 13.9 GW number by considering coal plants ‘at risk’ for retirement if they fall below an 80% capacity factor. An 80% capacity factor is an extremely high and unrealistic threshold for considering a plant at risk of retirement; in fact, the national average coal plant capacity factor is currently 60%. Almost all of SPP’s ‘at risk’ coal plants would actually just be operating at average capacity factors.”
From Crisis to Inevitability
Late last year, SPP and MISO warned of a reliability crisis if the Clean Power Plan isn’t eased to account for up to 134 GW of generation retirements by 2020, most of them coal-fired units. (See MISO, SPP: EPA Clean Power Plan Threatens Reliability.)
SPP’s first study assumed new generation was added without additional transmission infrastructure. The model showed that portions of the system in the Texas panhandle, western Kansas and northern Arkansas “were so severely overloaded that cascading outages and voltage collapse would occur and would result in violations of [North American Electric Reliability Corp.] reliability standards,” SPP CEO Nick Brown said in his comments to EPA.
But the initial alarm about the Clean Power Plan has given way to compliance strategy contemplation. In addition to the third study that will analyze the cost of state-by-state compliance, the RTO is beginning work on a transmission planning study. That analysis is targeted for January 2017, Nickell said.
FERC issued the order in February, accusing the company of billing ISO-NE for oil at its 181-MW plant in Pittsfield, Mass., while actually burning cheaper natural gas during a July 2010 heat wave. In dispute are a series of emails between Maxim employee Kyle Mitton and the Internal Market Monitor.
“Staff’s reply contains no credible evidence that Maxim or Mr. Mitton omitted any material fact in any of their communications with the IMM which left the IMM with any false impressions about what fuel actually was burned at Pittsfield,” Maxim said.
In its reply, Enforcement said Maxim “made a series of carefully managed statements about pipeline restrictions and the theoretical possibility of losses from offering gas and burning oil, and said nothing about what was actually happening at Pittsfield.”
In addition to the Pittsfield plant, Maxim operates two other plants in ISO-NE: CDECCA, a 62-MW cogeneration plant in Hartford, Conn., and Pawtucket Power, a 63.5-MW cogeneration plant in Pawtucket, R.I.
Transmission planners are considering additional changes to their light-load studies based on a reevaluation of three years of data that showed coal- and natural gas-fired generation are operating at higher capacity factors than previously assumed. Planners already had concluded that maximum wind capacity factors should be increased in the studies.
The analysis showed that capacity factors for coal generators during light-load periods — 1 to 5 a.m. from Nov. 1 through April 30 — have been trending up, in large part because retiring units are leaving more electricity to be generated by those remaining.
Planners are considering increasing the maximum ramping of coal plants 500 MW and larger above the current 60% and boosting the assumptions for coal plants below 500 MW above the current 45% maximum. PJM also is weighing an increase in assumptions for natural gas plants; planners currently assume they are not dispatched at all during light-load periods.
The analysis found large plants operated above the 60% capacity factor in about two-thirds of light-load hours RTO-wide during delivery year 2013-14, with the APS and AEP zones above that level about 80% of the time. Smaller coal units operated above their assumed capacity factor in about half of the hours RTO-wide. In APS, small coal ramped above the assumption in all light-load hours for the year, Mark Sims, manager of transmission planning, told the Planning Committee last week.
“A significant amount of coal has retired. What’s left is running more often because it’s more efficient and competitive,” Sims said.
Capacity factors also have been increasing during light-load hours for natural gas combined-cycle units as the fuel has become cheaper. RTO-wide, they operated in about one-quarter of light-load hours, with units in the AEP zone running in 86% of hours. When they are operating, they are generally doing so at capacity factors of 80% or higher.
No changes in assumptions are proposed for oil (assumed at 0%) and nuclear units (assumed at 100%).
PJM last month announced its intention to increase the maximum wind capacity factor from 80% to 100%, consistent with the modeling in MISO. (See Changes Proposed for Light Load, Wind Modeling.)
Sims said staff will conduct sensitivity analyses after finalizing their recommended changes and report back to the PC.
PJM Looks to Tweak Peak Load Forecast
PJM plans to recommend changes to improve its peak load forecasts by the end of June, officials told the PC. The revised model is an effort to better reflect customer usage, energy efficiency, weather and the impacts of “behind the meter” solar generation. (See PJM Seeking Improved Load Forecasts.)
PJM’s John Reynolds said efficiency in heating is continuing to climb, though not as dramatically in recent years. Meanwhile, cooling efficiency has leveled off and overall energy usage for cooling is expected to begin increasing by 2020.
PJM also is investigating the impact of distributed solar energy on demand. More than 1,700 MW of photovoltaic solar generation not registered as capacity resources is now receiving solar renewable energy credits in the PJM region, up from zero in 2005. Reynolds said most of the generation is in New Jersey, which has generous solar subsidies.
Planners expect to identify improvements to the model by the end of the second quarter, with revised manual language brought to stakeholders for endorsement by the end of the third quarter. Any changes would be implemented in the 2016 load forecast.
Long-Term Firm Transmission Study Endorsed
Members unanimously endorsed creating a Planning Committee sub-group to consider changes in how it studies long-term firm transmission service requests. The effort, initiated with a problem statement approved in March, is intended to ensure that individual requesters share in the cost of transmission upgrades required to serve them. (See Change Would Shift Baseline Upgrades to Network Customers.)
“PJM’s process, tools and thresholds have been established based around a local generation or transmission injection projects’ impacts and not around remote origination of energy,” according to the issue charge approved by members.
The group is expected to complete its deliberations by the end of the third quarter.
Committee Endorses Reserve Requirement Study
The PC approved revised assumptions for the 2015 PJM reserve requirement study that are expected to have a minor impact.
The study will determine the installed reserve margin, forecast pool requirement and demand resource factor for future delivery years and will look at the period from June 1, 2015, through May 31, 2026.
The two changes of note regard the computation of demand response and PJM’s proposed Capacity Performance product.
The study will use PJM’s new method of modeling demand response, which takes the average of the final amount of committed DR for the most recent three years. Previously, forecasters used the amount that cleared the last Base Residual Auction. (See Members Endorse Change to Demand Response Modeling.)
And, because the RTO’s Capacity Performance plan is in limbo as it awaits a ruling from the Federal Energy Regulatory Commission, the study will report using two sets of parameters — one with the CP product and one under the status quo. The forecast pool requirement values that ultimately will be applied will depend on whether FERC approves PJM’s plan. (See related story, PJM Responds to FERC Queries on Capacity Performance, Requests Approval.)
Order 1000 Problem Statement Approved
The PC approved a problem statement formalizing its work on process improvements as a result of Order 1000 “lessons learned.”
Although PJM already has begun incorporating the lessons — for example, introducing an improved method for receiving document submissions from transmission developers — officials said they decided a problem statement was needed because the issue would be a “standing agenda item” for the committee in the future.
PJM’s first project under the order, soliciting a fix for stability issues at New Jersey’s Artificial Island nuclear complex, has been beset by numerous delays and controversy. Planners expect to recommend a proposal to the Board of Managers next month — more than two years after the competitive window opened. (See related story, Planners Set April 28 for Artificial Island Recommendation.)
Republican Gov. Bruce Rauner has approved a bill allowing Commonwealth Edison and Ameren Illinois to avoid legislative review of a sweeping grid modernization program until 2019 instead of 2017.
Critics, including the Citizens Utility Board, worry that the move will allow the utilities to increase electric rates without being held accountable enough for their performance.
The bill passed both houses last year with bipartisan support, and Senate President John Cullerton (D-Chicago) waited to send it to the governor’s office until outgoing Democratic Gov. Pat Quinn, historically a utility antagonist, left office.
The Corporation Commission has ordered a reduction in the amount of drilling wastewater injected into deep disposal wells in light of a report linking the injections with earthquakes. The order relates to two counties bordering Oklahoma, which has experienced an increase in seismic activity apparently related to the disposal of wastewater produced from oil and gas wells.
“Because individual earthquakes cannot be linked to individual injection wells, this order reduces injection volumes in areas experiencing increased seismic activity,” the order states. “The commission finds increased seismic activity constitutes an immediate danger to the public health, safety and welfare. The commission finds damage may result if immediate action is not taken.”
The commission cited a study by the U.S. Geological Survey that showed an increase in the number of earthquakes corresponded with an increase in wastewater disposal. There were 30 earthquakes in Kansas between 1981 and 2000. In the first three months of this year, there have been 51 recorded earthquakes.
A Somerset County wind project has been scrapped after the developer tired of opponents who feared the wind turbine towers would endanger Naval Air Station Patauxent River. Pioneer Green Energy notified county authorities that it was withdrawing the plan, which would have built 25 turbines producing up to 150 MW.
State lawmakers pushed through a 15-month moratorium on the $200 million development, which then-Gov. Martin O’Malley vetoed. U.S. Sen. Barbara A. Mikulski pushed through a measure halting the project amid concerns that the turbine towers would interfere with the air station’s radar system. More legislation blocking wind development across the Chesapeake Bay on the Eastern Shore is brewing, with opposition growing against a planned 130-MW wind project near Kennedyville in Kent County. In view of the opposition, Adam Cohen, vice president of Pioneer Green Energy, decided to surrender. “We are truly saddened we cannot bring new investment, jobs and tax base” to Somerset County, he wrote to county officials.
Minnesota Power, State Reach Agreement on SO2 Releases
Minnesota Power reached an agreement with the Pollution Control Agency concerning sulfur dioxide emissions at its Taconite Harbor Energy Center in Schroeder. The 225-MW, coal-fired plant was the focus of attempts by environmental groups to force Minnesota Power to reduce emissions. The plant has been operating under a decade-old permit.
Minnesota Power has struggled to bring the plant into compliance and announced the closing of one of the three boilers this year. It also installed emissions-control technology, but it has not performed as expected. In addition to retiring one unit, the company will also pay a $1.4 million fine and spend $4.2 million on community projects. It will also need to submit a plan to the Public Utilities Commission that will outline what steps are being taken to reduce emissions further.
Supreme Court Rules Empire Must Offer Solar Rebates to All
Empire District Electric must offer all eligible customers solar rebates, the state Supreme Court has ruled. The court found that a state law exempting Empire from Missouri Clean Energy Act requirements was unconstitutional. The ruling spurred Renew Missouri, a clean energy advocacy group, to file a motion with the Public Service Commission to compel Empire to file an official tariff offering solar rebates by April 15. “Our hope is that Empire responds by immediately offering rebates,” said P.J. Wilson of Renew Missouri. “Their customers have been waiting since January 2010, the date Empire was required by law to start offering solar rebates. Today, the waiting should finally be over.”
The case came to the state’s high court as a result of developments dating back to 2007, when the state’s Renewable Energy Standard was passed. That standard called for utilities to get 15% of their energy from renewable sources by 2021 and to offer rebates to customers who wanted to install solar panels. But in 2008, lawmakers passed H.B. 1181, which exempted Empire from solar requirements. Renewable proponents challenged the law in court.
BPU Considering Request by New Jersey Natural Gas for Pipeline
New Jersey Natural Gas has filed a proposal with the Board of Public Utilities to build a 28-mile natural gas pipeline through three counties. If approved, the 30-inch pipline would start in Burlington County and run through Monmouth and Ocean counties. The proposed $130-million project, called the Southern Reliability Link, is designed to be a redundant line in the event an existing pipeline in Middlesex County is disrupted.
Already the plan is attracting opponents, who have previously organized against another project the company is involved with, the PennEast project. That proposed pipeline, which would run 110 miles from eastern Pennsylvania to Mercer County, has been the focal point of major opposition from community and environmental groups in both states. Some environmentalists note that the Southern Reliability Link is routed to go through federally protected pinelands. The first public hearings on the project have not yet been scheduled by the BPU.
Bill Would Allow Third-Party Leasing for Solar Installations
A Republican-backed bill would allow independent third-party energy companies to sell directly to homes and businesses. While the bill will likely attract opposition from utilities, the legislation would benefit solar developers. Major corporations are being enlisted to support the bill, which would allow independent companies to lease solar installations to home and business owners, and then sell the power produced directly to the owners, cutting out the utilities entirely. Wal-Mart, Target and Lowe’s have contacted House Speaker Tim Moore to support the bill, called the Energy Freedom Act.
“I’m coming at this from a Republican viewpoint,” said bill sponsor Rep. John Szoka of Fayetteville. “I believe in free markets and I believe in property rights. This allows property owners to use their property as they see fit.”
The state is already the nation’s fourth largest solar producer.
While the U.S. Environmental Protection Agency has released studies showing the probable impact of the rules of the Clean Power Plan on the nation, none of those studies get down to the state and local level. North Dakota hopes to change that by ordering a study that will examine the expected effects of the Clean Power Plan on natural gas prices, electricity rates and renewable energy production in the state. Gov. Jack Dalrymple signed a bill authorizing a study of the rules, which are expected to take effect this summer. Jason Bohrer, president of the Lignite Energy Council, said the study will look at the financial implications of the federal rules.
The Public Utilities Commission turned down Duke Energy’s request that it receive a ratepayer-guaranteed return for its share in two older coal-fired generation plants, rejecting the company’s argument that the arrangement would have provided long-term price stability for customers. PUCO in February denied a similar request by American Electric Power.
FirstEnergy has a similar request pending before the commission, and AEP has a request concerning other plants it says are at risk of closing if they are not guaranteed prices. The most recent decision involved the coal-fired plants owned by the Ohio Valley Electric Corp. OVEC’s shares are owned by Duke, AEP and FirstEnergy, among other companies. If PUCO had approved Duke’s request, its Ohio utilities would have purchased power from the plants at a long-term contract and then passed that price on to customers. Opponents have called the arrangements bailouts for the generating companies.
Andre Porter, a 35-year-old Republican and former member of the Public Utilities Commission who stepped down from the state Department of Commerce to rejoin it, was named PUCO chairman by Gov. John Kasich. Porter’s five-year term begins this week. He replaces Tom Johnson, who announced his resignation as chairman earlier this month. Johnson will fill out his term as one of the five members of the commission. Porter was widely seen to be Kasich’s choice when Johnson resigned.
AG Urges OCC to Drop Mustang Replacement from OG&E’s Plan
The state Attorney General’s office said Oklahoma Gas and Electric has not provided enough information about its planned replacement of the aging Mustang power plant to justify its request for $344 million in replacement costs. An assistant attorney general requested that the Corporation Commission drop the Mustang replacement request from the company’s $1 billion rate case. The company, however, disagrees. “There is a huge record in this case, and much of it is related to Mustang,” said Bill Bullard, an attorney for OG&E. If all of OG&E’s rate case is approved, it would increase the average residential customer’s bill by about 15%. The plan would replace the aging units with seven 40-MW combustion turbines.
PECO, PPL Ask PUC Approval to Boost Fixed Customer Charges
PECO and PPL Electric have filed requests with the Public Utility Commission that include substantial increases in the basic monthly customer charges. PECO asked to increase its monthly customer charge 68%, from $7.13/month to $12. PPL wants to increase its monthly rate from $14.13/month to $20, a 42% increase. The charges remain the same no matter how much electricity the customer uses. Both companies say they want to raise the charges to fund maintenance and upgrade costs for their electric distribution systems. In PECO’s case, the new charges would result in $84.5 million in revenue, almost half of the $190 million of its overall rate hike request.
Consumer advocates are crying foul, though. “It’s poor public policy,” said Bill Malcolm, a senior legislative representative for AARP. “Raising the fixed monthly charge lowers the variable per-kilowatt charge, which creates a disincentive for conservation and energy efficiency and gives consumers less control of their bill.” Others say the fixed rates strip away any incentive to reduce power usage. “It gives consumers less control of their bill because more of their bill is fixed and not based upon their usage,” acting Consumer Advocate Tanya McCloskey said.
Customers of Pennsylvania Electric and Pennsylvania Power will pay more for electricity beginning next month — about 13% more for Penelec customers and 7% for Penn Power customers.
The increases are part of rate settlements approved last week by the Public Utility Commission for FirstEnergy’s four state subsidiaries: Penelec, Penn Power, West Penn Power and Met-Ed.
The rate hikes are lower than what FirstEnergy originally requested last August. The increases in the base distribution rates are effective May 19 and are the first for each of the four subsidiaries in at least 20 years, according to the PUC.
Duke Agrees to $2.5M Settlement over Dan River Ash Spill
Duke Energy has agreed to a $2.5 million settlement with state environmental officials to offset damage caused when 39,000 tons of toxic coal ash from a retired power plant spilled into the Dan River. The company has reached a $102 million settlement with federal authorities and was fined $25 million by North Carolina in connection with the spill, which fouled 70 miles of the Dan River. The Department of Environmental Quality said $2.25 million will fund environmental projects in communities affected by the spill, and the remaining $250,000 will be retained for a DEQ environmental emergency fund. Danville, perhaps the hardest hit of the communities, is still negotiating with Duke over the spill.
The three-member Board of Commissioners of Public Lands has enacted a state ban on its employees using the term “climate change.” The reasoning, according to State Treasurer and Republican Matt Adamczyk: Climate change is “not part of our sole mission, which is to make money for our beneficiaries. That’s what I want our employees working on. That’s it. Managing our trust funds.”
The term “climate change” must not enter into that specific conversation, Adamczyk and Attorney General Brad Schimel, the other Republican sitting on the board.
“Having been on this board for close to 30 years, I’ve never seen such nonsense,” said the third member, Democrat and Wisconsin Secretary of State Doug La Follette, who voted against the measure. “We’ve reached the point now where we’re going to try to gag employees from talking about issues. In this case, climate change. That’s as bad as the governor of Florida recently telling his staff that they could not use the words ‘climate change.’”
Wind Capital Group said it is selling its last two U.S. wind farms to a California company. Wind Capital said it will sell the 150-MW Lost Creek wind farm in Missouri and the 210-MW Post Rock facility in Kansas to San Francisco-based Pattern Energy Group. Wind Capital said the sales, for a reported $244 million, will allow it to focus on its wind developments in the United Kingdom and Ireland.
Entergy Spending $62.2M on 24-mile Tx Line in Arkansas
Entergy Arkansas said it is spending $62.2 million to build a transmission line and a new substation to improve grid reliability in Drew and Desha counties. The company said it is part of a $2.4 billion investment through 2017 on system upgrades. It is already constructing another 27-mile transmission line that will end at the same new substation. That project is estimated at $25 million.
Duke Finds Hairline Crack on Reactor Head at Harris Plant
Duke Energy Progress discovered a hairline crack in the reactor pressure head of Shearon Harris nuclear generating station, but the company told the Nuclear Regulatory Commission that the crack poses no danger. The crack will be repaired during the current refueling outage, the company said. “The unit is in a safe and stable condition,” Duke told NRC. “The flaw and repair have no impact to the health or safety of the public.”
The crack, measuring about a quarter-inch, is near a nozzle that penetrates the reactor head. It is similar to a crack that was missed during a 2012 refueling inspection and caught later during a data review. After that incident, NRC ordered Duke to ensure such an incident didn’t happen again.
NextEra Energy Resources is investing $640 million on two more wind farms in Colorado. The company already has invested about $2 billion on seven Colorado wind farms generating about 1,175 MW. The company said the two new wind farms should be ready to come online by the end of the year.
The first facility, a $240 million 150-MW wind project in Kit Carson County, has a 25-year contract to sell its output to Tri-State Generation and Transmission Association. The second facility, the $400 million 250-MW Golden West Wind energy Project, will be in El Paso County and will sell its output to Xcel Energy.
NextEra is the largest wind farm operator in the U.S., with 10 GW of turbines.
E.ON Starting Asset Management, Repair Businesses in US
E.ON, the world’s largest investor-owned utility, is branching out into the asset management and facility repair business in the United States. The company owns or operates nearly 3 GW of generation in North America, and now it’s starting up E.ON Energy Services. The new business will offer on-site repair and asset management operations for plants it does not own. “As we transitioned to an operations-focused company several years ago, we saw a large growing demand for qualified service providers,” E.ON’s North American chairman Patrick Woodson said. He pointed to the continent’s growing wind and solar industries as an area where the company could expand.
Advanced Power Gets Funding for $899M Combined-Cycle Plant
Advanced Power, based in Switzerland, has closed financing for an $899 million combined-cycle plant it will build in northeastern Ohio. The 700-MW natural gas-fired plant will sell energy, capacity and ancillary services into the PJM market. Advanced Power secured $411 million in funding from TIAA-CREF, Ullico and Prudential Capital Group, and a further $488 million from BNP Paribas, Credit Agricole and eight other banks. The Carroll County Energy Project will be in Carrollton, Ohio, close to both the Utica and Marcellus shale gas fields, as well as American Electric Power’s 345-kV transmission line.
The company did not say when construction would begin.
Duke Appeals $25 Million Ash Fine, Calls it Excessive
Duke Energy is appealing a $25.1 million fine levied by North Carolina environmental officials in connection with groundwater pollution from ash piles at a retired power plant. Duke says the fine is excessive and that it has taken corrective action.
The state Department of Environment and Natural Resources fined the Charlotte, N.C.-based company in March for failing to control ground water leaching from the coal ash lagoons at the now-retired L.V. Sutton Steam Electric Plant near Wilmington, N.C.
The fine is separate from a $102 million settlement the company agreed to pay federal authorities for the damage caused by a massive leak of toxic coal ash from another retired plant, near the Dan River. That event last year caused pollution in two states — Virginia and North Carolina — after a broken pipe allowed coal ash slurry to flow into the river. The company still faces litigation from Virginia and private property owners as a result of that leak. North Carolina, in response, enacted coal-ash legislation and formed a formal oversight committee.
Duke’s appeal of the Sutton fine notes that the company had already taken corrective actions to stop and remediate the leakage from the retired plant. It also claims that state environmental officials erred in fining the company for 1,822 days of violations, despite only taking samples for 27 days, using a new way of calculating the fine, making it $24 million higher than fines for earlier, similar events, and failing to take into account the possibility of other sources of contamination.
