The Federal Energy Regulatory Commission said Tuesday that PJM should not have included a 10% adder in its calculation of make-whole payments to generators whose costs exceeded the $1,000/MWh offer cap last winter.
FERC granted a rehearing request to PJM’s Independent Market Monitor, agreeing that including the adder — typically included in cost-based offers to account for the uncertainty of calculating operating costs for combustion turbines under changing ambient conditions — was a mistake.
FERC said that the generators subject to their Jan. 24 waiver of the offer cap would still “receive make-whole payments by documenting the cost and volumes of natural gas needed to generate electricity.”
But the commission said that because the generators’ actual costs are now known, including an adder meant to cover uncertainty was inappropriate.
“This type of ex post determination does not contain any inherent uncertainty that would warrant an adder whose purpose in ex ante offers is solely to enable resources to recover uncertain or difficult-to-quantify costs,” FERC said.
The Monitor had argued in a March report that the adder portion was “not an actual cost and the generation owners did not pay it.” (See Stakeholders Preview Offer-Cap Debate.)
Denied
In its rehearing request, the Monitor also argued that non-capacity natural gas-fired generation resources should receive relief so as not to deter them from participating with PJM. FERC, however, disagreed.
“PJM’s filing requested a temporary waiver only for generation capacity resources and, therefore, we will not extend the waiver to other generators,” FERC said. “Further, no party in this proceeding has presented evidence that natural gas-fired generators other than generation capacity resources had documented costs above the market-clearing price.”
FERC also denied requests for rehearing from the Maryland Public Service Commission and the PJM Industrial Customer Coalition.
The coalition said customers shouldn’t be forced to pay higher prices due to generators’ decisions not to hedge against price spikes in the natural gas market. The coalition also said the waiver should have been limited in scope to specific PJM zones rather than the entire footprint.
FERC countered that the events of late January amounted to an emergency that harmed confidence in the wholesale markets and threatened reliability. “Delaying the issuance of the order could have threatened reliability by discouraging generators from making their units available,” FERC said, adding that its broad waiver was consistent with past orders during emergencies.
FERC’s denial of the PSC’s request was mostly procedural: the PSC had requested a detailed report from the Monitor explaining the basis for determining make-whole payments. The PSC filed its request on Feb. 21; one month later, the Monitor filed its report.
PJM officials are developing contingency plans for their 2015 capacity auctions in the wake of last week’s stay of the D.C. Circuit Court of Appeals’ EPSA ruling.
PJM General Counsel Vince Duane said it will be at least next spring before the Supreme Court decides whether to review the D.C. Circuit’s ruling (Electric Power Supply Association v. Federal Energy Regulatory Commission) throwing out the Federal Energy Regulatory Commission’s Order 745.
On Monday, the D.C. Circuit granted a stay until Dec. 16 on its ruling in order to give U.S. Solicitor General Donald B. Verrilli Jr. time to file a petition for certiorari on FERC’s behalf. If Verrilli files the petition, the stay will remain in effect until the Supreme Court rejects the request, or accepts it and decides the case on its merits.
Although the D.C. Circuit’s May 23 ruling explicitly concerned FERC’s jurisdiction over demand response in energy markets, some believe it also jeopardizes the inclusion of DR in FERC-regulated capacity markets. To avoid legal vulnerabilities, PJM on Oct. 7 proposed eliminating DR as a capacity supply resource and instead having load-serving entities offer DR and energy efficiency to reduce their capacity obligations.
Duane said the stay does nothing to provide additional certainty regarding the May 2015 Base Residual Auction.
“If [the Supreme Court justices] take the case, you have another year of not knowing what the rules for DR participation are,” Duane said in an interview last week.
“If cert isn’t granted, that’s the walk-off home run. That’s the end of it. There’s no more appeals,” he added. “And we are right on the eve of a capacity auction and the question then is what rules can apply now that EPSA is the law of the land and we have Tariff sheets that are kind of antiquated.”
Electric Power Supply Association CEO John Shelk responded to the stay with a statement calling on PJM to assume the D.C. Circuit’s ruling stands.
“EPSA remains confident that the D.C. Circuit’s decision will stand and that Order 745 will eventually be vacated,” Shelk said. “The key now is moving forward on plans for an orderly transition that take into account not only what the decision requires with respect to demand response participation as supply in the energy markets but also its implications for the capacity markets. Even lawyers who disagree with the court’s conclusion that FERC lacks jurisdiction agree that the ruling’s legal rationale logically means that demand response cannot be a supply-side resource in capacity markets.”
ISO-NE Response
ISO-NE spokeswoman Marcia Blomberg said Friday that the ISO is continuing with its plans to seek FERC approval for rules allowing DR to provide operating reserves and participate in the Forward Reserve Market effective June 2017.
“However, given the legal uncertainty regarding the future of Order 745, and the fact that the full integration of demand response into energy and reserve markets will require two years of work to modify software and system infrastructure, the ISO will decide in early 2015 whether to begin devoting resources to meet the June 1, 2017, implementation date, or to ask for a delay until the legal questions are resolved,” Blomberg said.
FirstEnergy Complaint
The court ruled that Order 745, which required PJM and other RTOs to pay DR resources market-clearing prices, violates state ratemaking authority.
FirstEnergy Solutions filed a complaint with FERC within hours of the May 23 ruling, demanding that PJM throw out the DR that cleared in the May BRA for delivery year 2017/18.
On Wednesday, PJM filed a response in opposition to the FE complaint, saying that FE’s demand that PJM recalculate the 2014 auction results without DR would be “extremely damaging to the market certainty that is critical to sustaining investment in electricity infrastructure.” (EL14-55)
Instead, PJM said it will submit Tariff revisions around New Year’s that will seek to minimize litigation risk by proposing that:
Load-serving entities be permitted to submit price-responsive bids into the capacity auction beginning with the May 2015 BRA, as outlined in the white paper;
Demand response capacity commitments already made for the 2014/15 through 2017/18 delivery years be honored “subject to an orderly, voluntary exit path for capacity demand resources that anticipate losing their energy market compensation as a result of EPSA”; and
Changes be made to incremental capacity auction rules to support a transition, including a provision precluding any new demand resource offers in RPM auctions by retail end users or by aggregators of retail customers.
“PJM expects to ask the commission to accept these changes to serve at least as a ‘stop-gap measure,’” the RTO wrote, “perhaps to be effective only until such time as the commission and industry stakeholders have had an opportunity, once jurisdictional questions are finally resolved, to consider and develop generic and more considered options for demand response participation in organized wholesale electricity markets.”
In its own response, PJM’s Independent Market Monitor told FERC it opposed recalculating the 2014 auction but “generally supports the objective of” the FE complaint.
“Granting this objective as it pertains to future [capacity] auctions would permit the correction of faulty rules that have interfered with the efficient performance of the PJM capacity market design,” the Monitor wrote.
Praise from LaFleur
Because FERC’s direct authority to initiate legal action ends at the D.C. Circuit, FERC Chairman Cheryl LaFleur said that the decision whether to seek a Supreme Court hearing will be made by Verrilli. “That office has the exclusive authority to make that decision for the U.S. government — all the agencies. As with other agencies, we work behind the scenes with them,” she said during a keynote address at PJM’s Grid 20/20 conference Tuesday.
LaFleur said she was unable to talk about the pending FirstEnergy complaint. But she praised PJM’s “very thoughtful” white paper.
“I appreciate your contributing to the discourse on this,” she said. “Because we have a pending complaint before us on how we treat demand response in the markets right now, I haven’t been able to be a part of that discourse, but I’m glad it’s going on.”
Wisconsin Energy Corp.’s proposed $9.1 billion acquisition of Integrys Energy Group has generated some notable opposition — including Michigan Gov. Rick Snyder.
On Oct. 17, Snyder and Michigan Attorney General Bill Schuette asked the Federal Energy Regulatory Commission to reject the merger, which would create one of the Midwest’s largest electric and natural gas utilities (EC14-126).
Wisconsin Energy and its subsidiaries already control most of the generation in Michigan’s Upper Peninsula. Michigan officials say the merger would give Wisconsin Energy a 60% ownership interest in the area’s only transmission system operator, American Transmission Co. (ATC).
“The level of concentration in both generation and transmission in the Upper Peninsula by one company as a result of this merger is a major concern for Michigan. This concentration will provide the [utilities] market power in the region that could negatively affect competition and rates,” Snyder and Schuette wrote.
Milwaukee-based Wisconsin Energy, parent of We Energies, and Chicago-based Integrys, whose holdings include Wisconsin Public Service and Michigan Gas Utilities, announced the merger June 23.
If the merger is approved, the combined companies will serve more than 4.3 million gas and electric customers in Wisconsin, Illinois, Michigan and Minnesota.
Most of the merging utilities’ generation is in the so-called Wisconsin and Upper Michigan region, or WUMS.
In their request to intervene, the Michigan officials said Wisconsin Energy and Integrys failed to analyze the relevant geographic market in determining market power, significantly understating “both the horizontal and vertical market power that the merged utility will have,” including the adverse impact such market power could have on rates and competition in Michigan’s Upper Peninsula.
Wrong Market Studied
The officials assert that the relevant geographic market is not the entire MISO footprint but WUMS, which includes the Upper Peninsula.
“Michigan contends that it is completely inappropriate to use MISO’s footprint, which includes parts of 16 states and one Canadian province, as the geographic market for assessing market concentration,” the state wrote.
Michigan pointed to findings by MISO’s Independent Market Monitor, as of the start of energy markets in April 2005, as identifying WUMS and North WUMS as narrow constraint areas (NCAs). “In designating submarkets as NCAs, the commission has effectively recognized these areas as separate and distinct geographical markets,” Michigan said.
Michigan says the merger could shift 93% of the cost of retiring the Presque Isle generating plant — $90.2 million — from Wisconsin ratepayers to a “much smaller set” of ratepayers in Michigan’s Upper Peninsula.
Great Lakes Utilities Protest
The proposed merger is also problematic for some utilities, including Wisconsin-based Great Lakes Utilities.
GLU’s members include municipal electric utilities in 12 Wisconsin and Michigan cities that are neighboring utilities to Wisconsin Energy and Integrys. GLU is a wholesale power customer of both.
GLU’s protest complains that the merger is likely to result in “substantial” increases to the cost of wholesale power. GLU also asserts that the merger will “strengthen Wisconsin Energy’s hand in transmission planning and cost allocation issues at the expense of other entities.”
In particular, GLU said the acquisition of Integrys will consolidate the ownership of ATC. Wisconsin Energy controls 26% of the voting shares in ATC while Integrys controls 34%.
“Without diversity of opinion and perspective, ATC’s function as an independent entity will be less certain,” GLU said.
A spokeswoman for Wisconsin Energy, Cathy Schulze, said the utility will respond to the protests soon.
[Editor’s Note: This article was amended Oct. 28 to put FERC Chairman Cheryl LaFleur’s comments in context. See clarification below.]
PJM’s proposed Capacity Performance product would cost ratepayers as much as $6 billion over the next four years, with long-term costs of as much as $700 million annually, the RTO and Independent Market Monitor Joe Bowring said in a joint paper Thursday.
The cost-benefit analysis was released two days after Federal Energy Regulatory Commission Chairman Cheryl LaFleur indicated support for PJM’s efforts in a speech at PJM’s Grid 20/20 conference in Washington and stakeholders announced 15 coalitions that will argue for changes in the plan.
Almost 80 stakeholders joined at least one of the coalitions, which include two load groups and seven representing generators (including gas, hydro, renewables and independent power producers). Other groups represent project finance interests, storage developers and companies specializing in energy efficiency and demand response.
The largest group is the Transition Coalition, with 19 members led by Michelle Gardner, director of regulatory affairs for NextEra Energy Power Marketing. It is concerned with rules that will apply for delivery years 2015/16 through 2017/18.
PJM Gains Allies
The release of the joint cost-benefit paper indicates that PJM will have the Market Monitor on its side in the debate before FERC. Bowring, who had expressed skepticism about PJM’s original proposal, said the RTO’s amended Oct. 7 plan addressed his major concerns. (See Revised Capacity Performance Plan Wins Bowring’s Support.)
The proposal also received an unofficial boost from LaFleur in her keynote address Tuesday at the Grid 20/20 conference. LaFleur said she agreed with PJM’s goals of finding a way to “value base load properly without losing sight of the other resources and how to assure that the fuel will be there for reliability.”
“We certainly will look closely at any proposal that comes in. But I think the purpose of understanding what it is we want the market to do and really trying to refine the definition — while not easy — is exactly what we should be doing,” she said.
[Clarification: FERC spokesman Craig Cano said Oct. 28 that while LaFleur “is supportive of [PJM’s] goals,” she wants to make clear that she has not prejudged the proposal.]
Cost-Benefit Analysis
The analysis released by PJM and the IMM projects both the increased capacity costs and energy market savings based on an assumption that the new Capacity Performance product, with its higher expectations and penalties for non-performance, will reduce outage rates by 6 percentage points in winter and 3 percentage points in summer.
Had the product been in place in 2014, it would have reduced energy load payments by 8.7% in January and February ($975 million) and 8.5% in June-August ($725 million), according to the analysis.
The proposal’s requirement that generator dispatch parameters reflect their physical characteristics during Hot and Cold Weather Alerts would have reduced January’s uplift payments by 83% ($500 million), the analysis says, resulting in total energy cost savings for the year of $2.2 billion.
The analysis uses the $2.2 billion savings in future projections, beginning with delivery year 2016/17.
Over the long term, PJM and the Monitor say, the changes will have a net cost of $300 million to $700 million, with net savings in years with extreme weather.
Next Steps
The coalitions have until 5 p.m. Oct. 28 to submit briefing papers to the Board of Managers, which will decide on the final proposal submitted to FERC.
The coalitions will make oral presentations to the board at an “Enhanced” Liaison Committee meeting at the Cira Centre in Philadelphia Nov. 4. The meeting will be teleconferenced for PJM members and state commission and FERC representatives, but no members of the media will be permitted.
Less than 3% of generation capacity constructed in 2013 was developed solely for sale into organized electricity markets, with the majority of projects supported by long-term bilateral contracts or built by vertically integrated utilities to serve their own loads, according to a study released last week by the American Public Power Association.
Of the 14.7 GW of new generation covered in the study, two-thirds were built with purchased power agreements and about 32% were constructed by utilities or customers. APPA said the study, Power Plants Are Not Built on Spec, validates its contention that the mandatory capacity markets in PJM, ISO-NE and NYISO “do not support the stable long-term financial arrangements required to build new power plants.”
APPA wants the Federal Energy Regulatory Commission to replace the mandatory capacity markets with voluntary residual markets, where states and local public power and cooperatives can procure their capacity through bilateral contracts.
APPA released the report last week as panelists at the Organization of PJM States Inc. annual meeting were in the middle of a discussion on the future of PJM’s capacity market.
PJM Market Monitor Joe Bowring told the meeting he didn’t need to review the study to respond to it.
“We have heard these claims before,” he said. “The notion that one-off bilateral contracts are better for customers I think has been disproven time and time again. It actually gives market power to sellers. This is the same APPA that had complained it can’t get prices low enough in bilateral contracts.”
Panelist Neal Fitch, senior director of regulatory affairs for NRG Power Marketing, noted that the study did not consider how much capacity the markets retained that might have otherwise retired.
James Wilson, a consultant to the consumer advocates for New Jersey, Pennsylvania, Delaware, Maryland and D.C., said he agreed with APPA that capacity markets are a “very expensive and very administrative and very inefficient way to” ensure resource adequacy.
“The capacity market is one way to go,” Wilson said. “The other way is what ERCOT is doing. ERCOT’s got an energy-only market and every few weeks you read about another new power plant.”
WASHINGTON — The Federal Energy Regulatory Commission has opened three investigations into questionable activity from last winter but has not found evidence that “widespread or sustained market manipulation” contributed to high natural gas and power prices.
Staffers from FERC’s Office of Enforcement (OE) announced the probes at the commission’s monthly meeting Thursday.
One of the investigations focuses on an allegation that a market participant attempted to suppress a monthly natural gas index to benefit short financial derivative positions.
The other two probes are seeking to determine whether generators may have profiteered “through offer behavior that resulted in increased uplift payments,” FERC said. All three investigations are at an “early stage,” FERC said.
Screens Tripped
OE’s Division of Analytics and Surveillance conducts regular monitoring of the natural gas and electric markets, including automated screens to detect anomalous trading activity that may indicate market manipulation.
To determine the causes of the extreme price spikes in January, OE supplemented its screenings with interviews with market participants and analyses of non-public market data from RTOs and ISOs, including physical and virtual bids and offers, market awards, marginal cost estimates and uplift payments. Staff compared the physical trading with financial derivative positions, using its newly granted access to the Commodity Future Trading Commission’s Large Trader Database. OE’s Division of Energy Market Oversight and Division of Investigations also took part.
The focus included the gas price spikes at the Transco New York trading hub, where prices rose to $120/MMBtu on Jan. 22, as well as the $40 price at the Chicago trading hub in late January.
Alerts from the commission’s natural gas surveillance screens resulted in conference calls with companies to obtain explanations for their physical trading and financial positions. “With one exception, which has resulted in an ongoing investigation, staff concluded that the companies contacted had valid explanations for their trading,” staff said in a presentation to the commissioners.
The consensus among those interviewed was that the high gas prices resulted from the “extreme and universal nature of the cold weather,” staff said.
“Also, market participants reported that less hedging of natural gas at the first of month price had occurred in light of certain additions of new delivery capacity into the New York area and forecasts of warmer weather than actually occurred,” staff continued. “The reduced hedges left many entities exposed to very volatile daily prices that occurred during January and February and may have increased price volatility as entities covered short positions. The depletion of natural gas storage was also a factor. Market psychology was also important as the price spikes were unprecedented. For example, market participants feared significant price premiums and lack of adequate counterparties.”
Gas demand was increased by conservative operator actions resulting from the mismatch between gas and electric operations, such as PJM’s decision to commit some gas generators over the Martin Luther King Jr. holiday weekend to ensure their availability the following Tuesday.
Because of the high level of generator outages, OE also searched for patterns of outages across generator fleets and conducted discussions with RTO market monitors to identify potential economic withholding.
Staff also investigated allegations of improper behavior it received through the enforcement hotline but determined that none of the allegations had merit.
Concept art of IPL’s new natural gas plant that will replace Eagle Valley. (Source: IPL)
The Federal Energy Regulatory Commission last week approved Indianapolis Power & Light’s request for a limited waiver from MISO’s must-offer requirement, relieving the company of having to purchase replacement capacity after its coal-fired Eagle Valley units retire in 2016.
The commission emphasized its decision (EL14-70) related to “an unfortunate timing mismatch” between the compliance deadline for the Environmental Protection Agency’s mercury rule and MISO’s planning year. It “in no way ties our hands to granting waivers under a different set of circumstances,” Commissioners Tony Clark and Philip Moeller said in a concurring statement.
Commissioner Norman Bay dissented, saying the one-time waiver “creates an unfortunate precedent that erodes MISO’s capacity construct, undermines the bilateral market for capacity and blurs, unnecessarily, a line that had once been bright.”
Timing Mismatch
IPL said it needed the waiver because it plans to retire Eagle Valley’s 216-MW Units 3-6 just ahead of the April 16, 2016, extended deadline on compliance with EPA’s Mercury and Air Toxics Standards (MATS), which falls six weeks before the end of MISO’s planning year on May 31.
IPL complained that there was no clear mechanism within MISO’s Tariff that would permit it to buy replacement capacity to cover the six-week gap.
Otherwise, IPL said it might be forced to retire the plant in mid-2015 and purchase capacity to meet its planning resource margin requirements. IPL told the commission it would need to spend up to $22 million to purchase replacement capacity for the entire year. IPL said capacity prices in the bilateral market had tripled recently as a result of the timing dilemma.
New Generation in 2016
The utility is building a 650-MW gas generator to replace the six 1950s–era Eagle Valley units in Martinsville, Ind., but the new generation isn’t expected to be on-line until late 2016.
“Our customers should not be made to pay for the ongoing costs of operating these units for 10 ½ months going forward plus the cost of procuring an additional full year of capacity in order to fill a capacity hole that is for a six-week period,” the company said.
MISO opposed IPL’s request, telling FERC on July 25 that such waivers “anytime during the last five months of a planning year could result in a substantial deficit in resources needed to meet demand.”
MISO noted that the five-month period would include the winter, “and as we learned during the polar vortex events of this past winter, winter demand can be significant even in a summer-peaking region.”
Not Needed for Reliability
But Clark and Moeller said MISO informed IPL that its units were not needed for reliability beyond April 16, 2016. They also said IPL indicated it would have abundant reserve margins of 47% and 20%, respectively, in April and May 2016.
Clark and Moeller said the waiver “avoids unnecessary costs for Indiana ratepayers and does not create reliability issues that would cause undesirable consequences for third parties.”
The commissioners also cited testimony by IPL that Indiana utilities had provided MISO with their generation outage schedules far in advance, so that MISO could conduct a maintenance margin study for future years. MISO’s analysis demonstrates that MISO Zone 6, in which IPL is located, has a sufficient planning reserve margin even after accounting for scheduled outages, the commissioners added.
“While we appreciate MISO’s concern for resource adequacy, it is clear that MISO’s reservations are based more broadly on resource adequacy concerns in the MISO region as a whole and not on concerns directly related to Indianapolis Power’s request for waiver of the Eagle Valley units.”
Bay’s Dissent
In his dissent, Bay noted that IPL had offered to purchase replacement capacity for the six weeks on the condition that it be available at a just and reasonable rate. “Under the circumstances of this case, I would take up Indianapolis Power on its offer,” Bay said. “This approach is effective and pragmatic, all but ensuring that MISO will receive the necessary capacity, while providing Indianapolis Power with one form of its requested relief.”
MISO is still reviewing the FERC order, MISO spokesman Andy Schonert said Thursday. “Our chief goal is ensuring reliability across our footprint, and we will continue to work with stakeholders to address solutions that meet reliability needs today and in the future.”
No Precedent
Addressing the potential of other utilities retiring coal plans in the same time frame to also seek waivers, the commissioners stressed the IPL decision was based on facts and circumstances “in this specific case,” signaling it would evaluate other such waiver requests on a case-by-case basis.
Alliant Energy, MidAmerican Energy, Xcel Energy Services and Consumers Energy were among utilities that made filings in support of IPL’s request.
In a filing last August, Consumers Energy said it’s in the same boat as IPL, with plans to shutter its 940-MW Classic Seven units on April 15, 2016, due to MATS.
Consumers said that it, too, would have to essentially “over-procure” capacity for 10 ½ months to meet MISO resource adequacy requirements — or potentially be exposed to replacement costs or a deficiency charge for the six-and-a-half-week period.
But MISO downplayed the idea that other generators beyond IPL are grappling with the six-and-a-half-week gap between the MATS deadline and the end of the MISO planning year. “MISO is not aware that any other market participants believe their circumstances would necessitate early retirement to comply with MISO’s tariff provisions,” the ISO said.
Also protesting IPL’s request was NRG Power Marketing and GenOn Energy Management, providers of bilateral capacity. NRG said IPL “correctly” notes that there’s no guarantee that bilateral capacity will be available, but “it is highly likely that such capacity will be available on a bilateral basis — and at far less than the cost of new entry.”
NRG also contends that requiring IPL to pay the market price for capacity during a period of scarcity “should not be considered a ‘problem.’ It is the market at work.”
The Federal Energy Regulatory Commission last week affirmed its June order reducing the return on equity (ROE) for the New England Transmission Owners (NETOs), ordering the companies to provide refunds from Oct. 1, 2011.
The commission decided in June that it would begin using a two-step discounted cash flow methodology for electric utility ROEs, similar to that used for natural gas and oil pipelines. Ruling in the New England case, the commission said the new “zone of reasonableness” for ROEs was 7.03-11.74%. (See FERC Splits over ROE.)
The commission said in the June order that it lacked the evidence needed to decide one of the inputs to the two-step DCF methodology: the appropriate long-term growth rate to use.
In the “paper hearing” that followed, FERC said all parties agreed that gross domestic product (GDP) is the appropriate long-term growth rate and that the commission properly calculated the GDP growth rate in this case at 4.39%.
The commission last week unanimously agreed, finalizing the tentative ROE of 10.57% it had assigned.
The NETOs, which include Northeast Utilities, Central Maine Power, National Grid and NextEra, were ordered to provide refunds, with interest, within 30 days for the 15-month period.
The refunds represent all excess revenues the NETOs received since the complaint was filed in October 2011, a period in which the utilities were getting paid an ROE of 11.14%.
The case resulted from a 2011 complaint by state consumer advocates and attorneys general throughout New England, which alleged that the NETOs’ 11.14% base ROE was unjust and unreasonable because capital market conditions had changed since the base ROE was established in 2006.
FERC split 3-1 over its first application of the new formula, tentatively setting the ROE for New England transmission owners at three-quarters of the top of the “zone of reasonableness,” a departure from the prior practice that used the midpoint in the range.
The previous zone ranged from 7.3% to 13.1%. Thus, although the commission chose a higher position within the range, the reduced top end resulted in a decrease from the NETOs’ previous ROE.
Public Advocate Warns About Risk of Third-Party Contracts
Bonar
Public Advocate Dave Bonar is warning Delmarva Power & Light customers to check their contracts with third-party electricity suppliers to make sure they’re not at risk for winter price spikes. “It’s important people don’t get trapped into paying variable rate at the time of year when they use the most electricity,” he said.
Bonar is concerned that many customers with fixed-rate agreements are unaware the contracts may convert to variable-rate deals without notice at the end of their terms. The Public Service Commission is considering a new rule that calls for suppliers to notify customers no fewer than 30 calendar days before a fixed-price contract ends. Other rules under consideration call for simpler marketing language.
“We were really hoping to have this wrapped up before winter gets here,” Bonar said. The commission hasn’t acted on the proposed rules yet. New Jersey’s Board of Public Utilities recently approved stricter rules for generation suppliers after an onslaught of customer complaints last winter.
DNR Chief: No Fracking Permits Issued Unless Ordered by Court
Miller
Department of Natural Resources Director Marc Miller said his office won’t issue any permits for oil and gas drilling until the legislature approves new fracking rules.
The state legislature’s Joint Committee on Administrative Rules said it won’t act on a proposed set of fracking regulations until Nov. 6. If no action is taken by a Nov. 15 deadline, the rulemaking process must start from the beginning.
The DNR drafted the rules after holding months of hearings and receiving more than 30,000 public comments. The legislative committee has had the rules since August. Miller said that without approved rules, his office will issue no permits without a court order.
Brad Richards, executive vice president of the Illinois Oil and Gas Association, said mineral owners are growing impatient and may sue to force the state to act. “We’ve already lost some companies to all these delays and undoubtedly we’ve got some folks who are at the breaking point,” he said.
Indiana should place a renewed focus on energy-efficiency programs to help reduce growing demands for power, according to a Utility Regulatory Commission report.
The report, issued at the request of Gov. Mike Pence, outlined the state’s future energy needs and estimated that the state faced a short-term need for 1,450 MW of new generation and 3,600 MW in the long term.
Pence said he requested the report to help lawmakers draw up energy efficiency standards and mandates.
Environment Secretary Says State Not Resisting EPA
The state has accepted a $300,000 Energy Department grant to help it meet the Environmental Protection Agency’s new carbon emissions regulations at the same time as the attorney general has joined a lawsuit fighting the rules.
Kentucky is one of 12 states that have joined in a lawsuit objecting to the EPA’s regulations proposed in June. At the same time, the state accepted the DOE grant to help it set up a way to monitor methods to meet the EPA goals.
Energy and Environment Secretary Len Peters said the attorney general, and not Gov. Steve Beshear, is waging the legal battle. Peters said the state has been working to reduce carbon emissions for years and is using energy-efficiency programs to help. “That’s one of the reasons we wanted the additional dollars, to help us do those sorts of things,” he said.
Michigan utilities are on track to meet the state’s 10% renewable portfolio standard by the end of next year, but three lawmakers have introduced legislation to repeal the standard.
House Bill 5872 was passed in 2008 and has garnered strong support among residents, according to recent polls. Some studies suggest that renewables could provide up to 30% of the state’s energy needs in the near future.
The bill comes after Ohio has frozen its renewable mandates to allow further review. The sponsors of the Michigan bill – Rep. Tom McMillan, Rep. Ken Goike and Rep. Ray Franz, all Republicans – were part of a group that unsuccessfully attempted to repeal the state’s RPS in 2012.
Renewable energy advocates are outraged.
“I think this is bad news for Michigan,” said Michigan Environmental Council Policy Director James Clift. “If you look at the economic development boost we’ve gotten from renewables and the new interest we’re seeing, it really is a step backwards.”
“It’s another example of the conservative lawmakers being grossly out of touch with not only the Michigan public, but with their own base as well,” said Nic Clark, state director for the Michigan chapter of Clean Water Action.
The Senate Environment and Energy Committee is considering a bill that calls for 80% of New Jersey’s electricity supply to come from renewable sources by 2050.
Senate Bill 2444 calls for 3,000 MW of offshore wind energy supply by 2030 and 4,500 MW by 2050. The current target is 1,100 MW by 2020. But offshore wind projects are currently at a standstill because the Board of Public Utilities hasn’t set ratepayer subsidies. One small offshore wind farm has received federal support.
Proponents of the bill say they hope it will spur more support from future administrations. “We are talking about policy over the next 36 years,’’ said David Pringle, campaign director of New Jersey Clean Water Action. Renewable power advocates say the Garden State has reliable wind resources off its coastline.
The Public Utilities Commission ruled 4-3 that utilities can continue to charge customers a 6.9% tax, even though the state legislature recently cut the corporate tax from 6.9% to 5%. The commission’s vote was down party lines, with the three dissents coming from its Democratic members.
“There is no set end to this over-collection, which will continue indefinitely each year until each utility’s next general rate case,” the three Democrats wrote in their dissent. “Even then, ratepayers will never be refunded the over-collected funds; the utilities have simply been afforded an unearned gain at the expense of North Carolina ratepayers.”
The ruling gives utilities the option to adjust rates and sets an Oct. 24 deadline for them to decide. Republican commission members said the over-collections are negligible for individual bills, but the Democrats said the state’s four utilities would generate an additional $21 million a year.
“The overall effect of these changes represents a substantial increase in consumers’ bills,” the Democrats wrote. “For those who struggle to pay utility bills in a challenging economy, every cent counts.”
PUCO Asks Supreme Court to Dismiss AEP’s Net Metering Suit
AEP Ohio wants the state Supreme Court to release it from rules requiring it to pay for power fed back into the grid by net metering customers who are enrolled with competitive power suppliers. The Public Utilities Commission has asked the court to dismiss the suit.
PUCO’s net metering rules mandate that AEP pay all customers for their surplus power, typically generated by small solar or wind setups. But AEP has argued that if those customers are served by third-party suppliers, and not AEP’s own generation, then AEP shouldn’t be bound by the rules.
AEP argues that the rate they must credit customers can be higher than its costs, including capacity charges. “The reality is that the energy delivered back to the grid by a customer-generator may not necessarily offset the peak demand that the utility has to meet or reduce the costs associated with serving the customer-generator,” the company argues.
PUCO argues that the rule, though passed by the commission, hasn’t been approved by a legislative committee and is not yet final, so a court challenge is premature.
Fracking Triggered Earthquakes Months Before State Notice
A new study suggests hydraulic fracturing triggered hundreds of small, unnoticeable earthquakes in eastern Ohio late last year, months before the state first linked seismic activity to the much-debated oil-and-gas extraction technique.
The report, which appears in the November issue of Seismological Research Letters, identified nearly 400 tremors on a previously unmapped fault. That included 10 quakes of magnitudes of 1.7 to 2.2 – intense enough to have temporarily halted activity under the state’s new drilling permit rules had they been in place at the time, but still considered minor.
The legislature is taking steps to renew a provision in the pubic utilities code that makes it easier for gas and electric companies to disconnect service for non-payment during the winter.
The law called Chapter 14, passed in 2004, relaxed state rules prohibiting winter shutoffs by allowing utilities to disconnect nonpaying customers whose incomes are 250% higher than the federal poverty level. The law is set to expire next year. The bill is expected to be returned to the House this month to consider modifications made by the Senate.
Customer advocates think extending the law is a bad idea. “Instead of targeting the bad actors, Chapter 14 has ensnared vulnerable low-income households that are simply too poor to afford to pay their utility bills on time every month,” Community Legal Services of Philadelphia said in a statement.
Governor’s Energy Plan: More Solar, Wind, Natural Gas
McAuliffe
Gov. Terry McAuliffe formally unveiled his energy plan for Virginia last week, advocating more renewable sources such as solar and wind, as well as traditional resources including natural gas.
McAuliffe said the state’s economy can’t rely on the continued flow of federal defense dollars that have sustained Northern Virginia and Hampton Roads. But an energy-based economy could be the solution.
“Folks, those days are over,” McAuliffe told an audience of energy entrepreneurs, business representatives and environmentalists. “We need to build a new Virginia economy.”
The energy plan, which goes to the General Assembly, was filed with the Virginia Department of Mines, Minerals and Energy two weeks ago.
Exelon Generation is joining with two other companies to build what they are calling an emission-free natural gas-fired power plant.
Exelon is partnering on the project with CB&I, an energy infrastructure company in The Woodlands, Texas, and technology commercialization firm 8 Rivers Capital of Durham, N.C., under the name NET Power. The $140 million, 50-MW plant, which will incorporate carbon-capture technology, will be built in an undisclosed location in Texas.
Using an 8 Rivers technology called Allam Cycle, the new plant will be radically different from conventional combined-cycle plants, which use waste heat to make steam that turns a turbine. Much of the steam’s energy potential is lost when it is condensed.
Pure Oxygen
The Allam Cycle uses natural gas as a fuel. But instead of using air as part of the combustion process, it uses pure oxygen, which eliminates emissions such as nitrogen oxides.
The Allam Cycle uses another byproduct of typical combustion, carbon dioxide, as a type of fuel itself. Rather than having to expend energy to capture CO2 as in other carbon-capture processes, the Allam Cycle collects the CO2, pressurizes it into a liquid and uses it to turn a Toshiba-designed CO2 fluid turbine, instead of a steam turbine. When the power plant is done with the CO2, it is pipeline-grade material ready either for sequestration or to be sold off for industrial uses.
“The by-products of combustion in this system are high pressure CO2 and a small amount of water,” NET Power Spokesman Walker Dimmig said.
“This technology is a potential game-changer in reducing carbon emissions from power generation,” Exelon President and CEO Chris Crane said.
The consortium can’t look to other models of this technology. “This is a true, first-of-a-kind demonstration of a brand new technology,” Dimmig said in an interview Friday. “The first commercial facility, which will be 295 MW, is in the planning stages. Following successful demonstration at this small-scale plant, we of course hope to build many, many more of these.”
Dimmig said he anticipates the Texas plant to be commissioned in 2016.
Holy Grail
Carbon capture is the Holy Grail in low-emissions power generation, but previous attempts have been over budget and behind schedule. Perhaps the most well-known is the FutureGen project, a coal-fired plant using integrated gasification combined-cycle technology, combined with carbon capture and storage. After funding battles and significant cost overruns, FutureGen, which was announced in 2003, is still not operational.
Another carbon-capture project is being built by Southern Co. with engineering and construction firm KBR Inc., in Kemper County, Miss. Originally estimated to cost $2.4 billion, latest estimates for the plant are $5.5 billion. Construction began in 2010. It is projected to go operational in May 2015, a year behind schedule.
How will NET Power avoid these pitfalls?
“First, FutureGen and Kemper are full-scale commercial facilities of a much larger size than this 50-MW facility,” Dimmig said. “Second, this plant has been under design for nearly four years, and we believe we have a very strong handle on costs. Finally, while novel, this is a far simpler process that uses far less piping and exotic alloy as compared to those other projects.”
Dimmig wouldn’t say if the plant must be sited near oil and gas wells, the typical sequestration sites used in carbon-capture plans, to be economically viable. Exelon, too, declined comment on where it planned to site similar plants if the NET Power plant turns out to be a success.
