The New York Public Service Commission staff has accepted seven proposed demonstration projects for the Reforming the Energy Vision initiative while asking for more refinements on four others.
The projects, filed July 1, are a component of the state’s REV program for utility-sponsored projects that offer collaboration with third parties. (See REV Proposals Seek to Increase Conservation.)
In letters to the state’s utilities, PSC staff said seven demonstration projects met criteria set out in the REV order. Staff said it would meet with sponsors of the remaining projects to discuss additional information needed to complete its review:
Three proposals by National Grid: a smart grid project in Clifton Park to give customers fixed-rate options based on energy consumption, its Buffalo Niagara Medical Campus engagement platform and its microgrid partnership with Clarkson University and the State University of New York at Potsdam;
Consolidated Edison’s CONnectED Home Platform that would connect homeowners with efficiency programs; and
Iberdrola’s proposed Energy Marketplace e-commerce website.
LITTLE ROCK, Ark. — While SPP says it is continuing to analyze the 1,500 pages in the Environmental Protection Agency’s Clean Power Plan, some stakeholders in the RTO’s 14-state footprint wasted no time taking action.
Arkansas Department of Environmental Quality Director Becky Keogh listens as Public Service Commission Chairman Ted Thomas speaks at press conference Monday.
In the first of several expected legal challenges, state attorneys general from half of SPP’s states and six of MISO’s were among 15 who last week asked a federal court in D.C. to block the rules. Arkansas, Kansas, Louisiana, Nebraska, Oklahoma, South Dakota and Wyoming joined West Virginia in filing a petition seeking a stay of the plan pending the outcome of expected legal challenges.
Also joining the petition were Wisconsin (MISO), Ohio (PJM) and Indiana and Kentucky (MISO and PJM). Alabama and Florida, outside of any organized markets, also joined.
But even as elected officials’ rhetoric remains hot, there were signs that the behind-the-scenes work toward compliance has already begun.
Opposition from Okla., Ark.
Oklahoma Attorney General Scott Pruitt, who had filed an unsuccessful legal challenge even before the final rule was issued, continues to argue that the EPA rule is unlawful. EPA’s rules “[force] Oklahoma into fundamentally restructuring the generation, transmission, and regulation of electricity in such a manner that would threaten the reliability and affordability of power in the state,” he said.
Arkansas Gov. Asa Hutchinson also came out guns blazing. “It is clear that the Obama administration’s Clean Power Plan could still result in significant electric rate increases for middle class ratepayers while having a minimal impact on global temperatures,” he said. “My administration will do everything it can to protect ratepayers.”
Hutchinson has directed the leadership of the state’s Department of Environmental Quality (ADEQ) and Public Service Commission “to discuss the details of the rule and the stakeholder process.”
In a press conference Monday, ADEQ Director Becky Keogh and Ted Thomas, chairman of the Public Service Commission, said they have been told to seek the lowest-cost option and will explore strategies that meet the Clean Power Plan while planning for the state’s future and allowing for growth.
Arkansas would need to reduce its emissions by 36.5% from its 2012 levels to meet the rule. Keogh said the state would begin gathering stakeholder input in early October as it decides whether to submit a plan to EPA by the September 2016 deadline or ask for a two-year extension.
“We have a lot more time,” Thomas said, “which is important when you’re making decisions that affect the citizens of the state.”
But Keogh said that while Arkansas has joined litigation against the Clean Power Plan, ADEQ and the PSC will still need to work quickly.
“We feel it’s prudent for the state to begin a deliberative process to evaluate our options and the potential impacts of those options,” she said. “Should the rule become final — and the deadline will be upon us very soon — it’s too important to wait for a final rule and then determine a path forward.”
SPP Analyses
SPP has taken a broader approach when analyzing the Clean Power Plan and its impact on the footprint’s reliability and economics. In an emailed statement, Lanny Nickell, the RTO’s vice president of engineering, noted SPP’s highest priority is maintaining the Bulk Electric System’s reliability in the central U.S.
“Compliance with the Clean Power Plan is best facilitated through SPP’s regional transmission planning process and energy market administration,” Nickell said. “Transmission planning requires analysis of many variables and takes considerable time.”
SPP’s planning process currently operates on near-term and 10- and 20-year cycles. Several stakeholder-driven initiatives are evaluating how to improve the planning process and best take into account Clean Power Plan impacts.
“I imagine there will be modeling based on the new rule,” Thomas said. “We don’t know yet what that’s going to be, but SPP, MISO and other groups we work with have extensive access to modeling, where you can put in price impacts and see the result.”
SPP has issued three reports on the Clean Power Plan since last October.
The first, a transmission-system impact evaluation, warned of rolling blackouts or cascading outages “unless the proposed CPP is modified significantly.” SPP said the original 2020 date for interim goals was unworkable and did not allow enough time to build the needed generation and transmission to accommodate coal plant retirements and deliver wind energy to population centers. (See MISO, SPP: EPA Clean Power Plan Threatens Reliability, Needs Longer Compliance Schedule.)
In April, SPP released a second analysis that indicated a regional-compliance approach with the 2030 deadline would cost an estimated $2.9 billion per year in capital investment and energy production costs. (See SPP: $45/ton Adder, Wind, Gas Meets EPA Carbon Rule.)
SPP issued a third study last month that concluded a state-by-state compliance approach would be a 40% increase over the regional plan. The latest assessment analyzed the EPA rule’s impact on existing generation and resource-expansion plans, without including the cost of new transmission needed to maintain reliability, gas-infrastructure expansion, market-design changes or transmission congestion. (See SPP: State-by-State Compliance Would Hike Carbon Reduction Costs by 40%.)
VALLEY FORGE, Pa. — The Market Implementation Committee last week approved rule changes that will help the Illinois Municipal Electric Agency to meet its capacity requirements with historic resources.
IMEA is among the load-serving entities that procured capacity resources outside of their locational deliverability areas to serve a portion of their load.
PJM’s Reliability Pricing Model capacity construct, which launched after IMEA obtained its external capacity, does not provide a way to allocate and maintain the benefits of historical resource and transmission service agreements — an issue that can increase an LSE’s costs if its LDA becomes modeled separately and binds in an auction.
The Independent Market Monitor had expressed concern that PJM’s initial proposed solution was overly broad. But it agreed with the revised solution, which covered only LSEs subject to fixed resource requirements (FRR).
FRR entities such as IMEA are subject to a percentage internal resource requirement (PIRR) if their zone is modeled separately, voiding the use of their historic capacity resources.
The solution approved by members makes three rule changes:
The PIRR is enforced only if the LDA has been separately modeled due to certain triggers;
An FRR Entity would be permitted to terminate its FRR alternative election prior to meeting the minimum five-year commitment period requirement under certain conditions; and
First-time elections of the FRR alternative would be due four months prior to a Base Residual Auction instead of the current two-month deadline.
PJM Asked to Consider Masking FTR Ownership
PJM would consider masking ownership of financial transmission rights under a problem statement presented by DC Energy’s Bruce Bleiweis at the MIC last week.
Currently, all RTOs publish the identities of FTR holders when posting auction results. By contrast, in all other market transactions, such as capacity auctions and daily energy auctions, PJM does not disclose the ownership, Bleiweis said.
“I think the inequity is transparent to everyone here,” Bleiweis said. “We don’t see any reason FTRs should be treated differently” than any other power product.
FERC initially allowed the current transparency to spur a secondary FTR market. Now that this market is established, this disclosure is no longer necessary, Bleiweis argued. He said that knowing another company’s position could lead to unfair competitive advantages.
There was some confusion as to what exactly is disclosed in other products, however. Carl Johnson of the PJM Public Power Coalition said he thought PJM published capacity positions of companies once the delivery year began.
PJM’s Tom Zadlo answered that only a list of cleared units is posted. Bleiweis said that if the problem statement is approved at next month’s MIC meeting, he would work with PJM to generate a simple list showing exactly what is posted for each product.
Marji Philips of Direct Energy said she “remains very concerned” by the proposal. In the past, she said, market participants have identified “mischief” in the FTR markets that the Independent Market Monitor and PJM did not catch, based on the increased transparency.
Bleiweis said PJM’s effort would be consistent with ISO-NE, which approved a move to aggregate FTR ownership at its November 2014 Markets Committee meeting.
The Nuclear Regulatory Commission has determined that NextEra Energy’s Seabrook Station could operate for another 20 years beyond 2030 without negative impact on the environment. NRC published its final report on the environmental impacts of renewing Seabrook’s operating license and gave the plant’s owners the green light to move to the next step in the re-licensing process.
“The NRC’s preliminary recommendation is that the adverse environmental impacts of license renewal for Seabrook are not great enough to deny the option of license renewal,” according to NRC, which based its findings on an environmental report submitted by NextEra Energy, consultation with federal, state and local agencies and NRC staff’s independent review and public comments.
A Safety Evaluation Report, the last step in the license renewal process, is scheduled for release in May. NextEra has been working through the renewal application since 2010.
Mass. Mayor to Ask FERC to Extend Meetings for Tennessee Gas Pipeline
The mayor of Peabody, Mass., wants FERC to add a special meeting near the city to allow the public to comment on Kinder Morgan’s plan to build a lateral from its Tennessee Gas Pipeline.
Mayor Ted Bettencourt said he would seek the additional meeting after he met with the Northeast Municipal Pipeline Coalition, a group opposing the pipeline. Kinder Morgan has said it wants to build the pipeline to provide fuel for power plants. The Northeast has experienced a shortage in natural gas during times of peak demand, such as frigid winter days and nights.
Several meetings have already been held concerning the pipeline, which is to run from Dracut, through Peabody and connect to an existing line in Danvers.
Ninth Circuit Throws out Suit Against FERC Curtailment Order
A panel of judges from the Ninth Circuit Court of Appeals has ruled that a group of wholesale electricity customers has no standing to sue FERC for requiring it to pay for curtailing wind generation in times of unusually high hydro generation.
The customers had argued that the dispatch-curtailment mandate — originally put into place as a result of high expected hydro generation on the Columbia River — meant that increased generation prices would be passed on to them. FERC issued the curtailment policy to cover incidents of “last resort” when high water levels forced Bonneville Power Administration to generate electricity that exceeded demand. In order to preserve system integrity, FERC decided it could mandate curtailment by other generators.
The plaintiffs argued that the mandate exceeded FERC’s area of responsibility, as it dealt with generation rather than transmission. The judges noted that the plaintiffs may suffer harm from the rule but that they had no statutory standing under FERC rules.
Report: Wind Could Replace Coal, Gas as Dominant Resources
The National Renewable Energy Laboratory released a report that shows that wind power’s capacity factor could reach 65%, exceeding both coal and natural gas.
The Department of Energy’s lab data indicates that increasing to a 65% capacity factor could reduce wind’s cost, improve transmission line efficiency and provide necessary power at times of peak demand. The report shows that if “near-term” technology and enough appropriate sites are used, the capacity factor of wind turbines could exceed both coal and natural gas. The report also indicated that new wind power technology on the horizon would mean that wind alone would be able to power the U.S. demand.
NRC: Beaver Valley Nuclear Station Has Enough Staff for Emergencies
The Nuclear Regulatory Commission has determined that the emergency plan of the Beaver Valley Nuclear Power Station in Pennsylvania is adequate to meet the needs for any large-scale emergencies. The commission reviewed the new safety guidelines put into place following the 2011 Fukushima nuclear disaster in Japan.
All of the nation’s nuclear stations are undergoing a commission review of plans updated after the disaster.
A report issued by the Nuclear Regulatory Commission found that a nuclear waste repository at Yucca Mountain would pose “only a negligible increase” in health risk from radioactivity leaking into groundwater. The study is one of the final products of the funding for the Yucca Mountain project, which President Obama mothballed in 2010.
The report will be presented next month in Washington and Nevada.
New Mexico Site Eyed for Storing Spent Nuclear Fuel
Holtec International has submitted documents showing its intent to file for a license to store spent nuclear fuel at a site in southeast New Mexico. The company said the facility would retain spent fuel from stations that are shutdown or in the process of decommissioning — Connecticut Yankee, Humboldt Bay, Kewaunee, La Crosse, Maine Yankee, Millstone Unit 1, Oyster Creek, Rancho Seco, Trojan, Yankee Rowe and Zion stations.
The letter of intent says that the site is 35 miles from any large population center. Holtec is asking the Nuclear Regulatory Commission for permission to store the fuel underground with the same system being used at Callaway and San Onofre stations.
Holtec said it is planning on filing its complete license application by June 2016.
NRC Dismisses Complaint Against San Onofre Station as Moot
The Nuclear Regulatory Commission has dismissed a complaint filed by an anti-nuclear organization against San Onofre nuclear generating station as moot because the station is being decommissioned. The Friends of the Earth filed the complaint against San Onofre owner Southern California Edison, alleging it failed to get approval for new steam generators before installing them.
The commission noted that fuel has been removed from the station and it is permanently closed, and so the complaint is unnecessary.
VALLEY FORGE, Pa. — PJM stakeholders last week launched another bid to change the $1,000/MWh energy offer cap, but consumer advocates said they were not optimistic about reaching consensus in time for next winter.
Marji Philips of Direct Energy proposed raising the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers — 50% more than the highest offers reported by PJM last winter.
“Everybody likes a piece of it and nobody likes the whole thing,” she said of those with whom she shared the proposal before the meeting. “So that means it must be pretty good.”
PJM’s Board of Managers asked stakeholders to make another attempt to reach consensus after efforts last year fell short. (See Members Deadlock on Change to $1,000 Offer Cap.) Philips and other PJM veterans said the $1,000 cap, which has been in effect for about 18 years, was set as a multiple of the highest prices seen at that time.
In January, PJM won FERC approval for a temporary waiver that allowed prices to rise as high as $1,800/MWh, but the RTO made it through last winter without having to invoke it. In the 75 days that the waiver was in effect, there were 54 cost-based offers between $1,000/MWh and $1,800/MWh, but none cleared.
PJM said the waiver was necessary to allow some gas-fired generators to cover marginal costs that hit $1,200/MWh in late January, as spot gas prices spiked as high as $140/mmBtu.
Higher Cap Better for LSEs
Philips said raising the cap is better for load-serving entities such as her company, because higher LMPs can be hedged while uplift cannot. She said it would also reduce capacity prices because increased energy market revenue would cause a drop in the net cost of new entry (CONE). “Here’s an opportunity to control our destiny,” she said. “We’d rather see [stakeholders] filing [a change] than PJM.”
Philips said she had been reluctant to back a change to the cap on day-ahead offers but was convinced by PJM that it was needed to enable price convergence with the real-time market.
The proposal also would require changes to scarcity pricing rules to ensure that generation dispatched for reserves receives lost opportunity costs — which could be higher than the existing $1,000 cap — she said.
Philips said her goal was “incenting the market to do the right thing. We’re trying to keep PJM as a market and not as a cost-based system.”
PJM Endorses Proposal
PJM officials — who proposed a $2,700 cap on price-based offers and removing the cap on cost-based offers in a FERC docket on price formation in March (AD14-14) — said they would accept the proposal. “It is something we would consider to be acceptable,” said Stu Bresler, senior vice president of market services.
Jim Benchek of FirstEnergy thanked Philips for the proposal, calling it “a good starting point.”
Consumer Reps Wary
But consumer representatives were not quick to embrace it.
Carl Johnson, representing the PJM Public Power Coalition, said he did not think consensus could be reached in time for an Oct. 1 FERC filing — the deadline PJM officials have said is necessary to ensure new rules are in place for winter 2015/16.
Johnson noted that stakeholders were unable to reach agreement last year despite months of debate. “Even though the pope will be in [Philadelphia], I don’t think that’s going to be enough time to give us the miracle we need to come up with consensus,” he said.
“There’s a lot here that we will need to digest,” said Dan Griffiths, executive director of the Consumer Advocates of PJM States.
Griffiths said while consumer advocates are willing to consider lifting the offer cap for generators that can demonstrate costs above $1,000/MWh, they continue to have concerns about letting those offers set LMPs for the entire market.
Philips responded that while stakeholders can debate whether the cap should be lower than $2,700, not allowing high marginal prices to set LMPs is “antithetical to the entire market structure.”
Griffiths said later that his members are willing to consider market clearing prices above $1,000/MWh but that PJM had not demonstrated a spirit of compromise in last year’s efforts, saying the RTO’s unwillingness to consider a cap below $1,800 was “insulting.”
David Mabry, representing the PJM Industrial Customer Coalition, said any change in the cap should be accompanied by broader market power protections than current rules, which test only local market power. He cited the Independent Market Monitor’s charge in the 2014 State of the Market report that some generators appeared to engage in economic withholding during high demand hours in January 2014. (See Monitor: Winter Prices Boosted PJM Prices, Raise Withholding Concerns.) Mabry said cost-based offers should be limited to short-run marginal costs.
Consultant Roy Shanker called market power concerns a “red herring,” saying existing rules are sufficient. “If you misrepresent your costs, you’re in big trouble,” he said.
Entergy has proposed closing one of its two largest Arkansas coal plants by 2028 and making modifications to the other to comply with the Environmental Protection Agency’s Regional Haze rule.
Entergy filed the proposal with EPA on Aug. 7, describing it as a “more reasonable, long-term, multi-unit approach” than the agency’s recently published federal implementation plan (FIP) for controlling the utility’s emissions. Entergy said its plan would achieve “virtually identical visibility benefits” as the EPA proposal but cost more than $2 billion less.
The company told EPA it would end coal-fired operations at its White Bluff plant by 2028, accept lower sulfur dioxide (SO2) emission rates at its White Bluff and Independence plants and install nitrogen oxide (NOx) control technology on its coal units within three years of the final FIP’s effective date — likely in 2016.
The EPA’s proposed FIP required installation of scrubbers and low-NOx burners on the four units at White Bluff and Independence, and NOx controls at Entergy’s gas/oil-fired Lake Catherine plant. The Regional Haze rule seeks to improve visibility in parks and wildlife areas by reducing particulate matter emissions.
White Bluff coal plant
The New Orleans-based company said its modeling — which it said “EPA should have conducted but failed to undertake” — indicates it does not need to invest more than $2 billion in scrubber technology at the plants and asked the EPA to amend the FIP accordingly.
Entergy said it would not be able to install dry scrubbers at White Bluff — which it shares with several other entities — until at least 2021, leaving only a few years to recover the approximately $1 billion investment. It said the EPA’s analysis incorrectly classified Independence as a best-available retrofit technology (BART)-eligible resource under the Clean Air Act and said the plant is well below EPA’s haze standards.
“Scrubbers at Independence are simply not necessary to ensure that visibility … nor are they justifiable based on EPA’s own analysis of the visibility benefits resulting from such a huge investment,” Entergy said, citing costs of as much as $1.53 billion to install scrubbers.
The utility also disagreed with the EPA’s analysis that proposed NOx BART controls at Lake Catherine. Referring to its own study, Entergy said the NOx controls would result in “inconsequential” visibility improvements.
Entergy said its approach “would ensure superior, long-term visibility benefits than would the proposed FIP” and a “dramatic decrease in [greenhouse gas] emissions, large reductions in SO2 emissions … and large reductions in … NOx emissions.”
White Bluff and Independence are both two-unit baseload coal plants capable of generating more than 1,600 MW each. The two plants date back to 1980 and 1983, respectively, and are ranked among the top 45 dirtiest coal plants by Environment America.
Lake Catherine is a 45-year-old, single-unit, gas/oil-fired plant capable of 750 MW. It is used primarily for peaking purposes.
Glen Hooks, director of the Sierra Club’s Arkansas chapter, praised Entergy for the decision to close White Bluffs but said the company should go further. “Although we’re excited about the announcement, we hope that it also spurs the company to take a hard look at its dirty and outdated Independence coal plant,” he said in a statement.
Competitive developers expressed reservations last week about a PJM proposal to exclude transmission projects below 200 kV from competition.
PJM said projects below 200 kV are almost always allocated to one zone and thus automatically assigned to the incumbent transmission owner.
PJM’s Suzanne Glatz said the “voltage floor” would allow the RTO to eliminate the cost of evaluating competitive proposals in cases where the likely solution is a transmission owner upgrade. The voltage threshold would not apply to market efficiency projects.
Of 1,523 projects approved by the PJM Board of Managers under the Regional Transmission Expansion Plan, 104 (7%) were greenfield projects, of which only 13 (less than 1%) were allocated to more than one zone and thus open to competition, Glatz said.
In 2014, only two of 55 projects selected to correct violations below 200 kV resulted in solutions above 200 kV. Both projects were transmission owner upgrades.
“There’s very few that are coming out as potential greenfield [competitive] projects,” Glatz said.
“Is 15 years really a sufficient baseline for what the future may hold?” asked Sharon Segner of LS Power, citing technology changes affecting demand response and energy efficiency. Segner also questioned why PJM’s analysis failed to include 2015 submissions, which included dozens of lower voltage submissions from the marketplace.
Brenda Prokop of ITC Holdings said her company doesn’t favor a voltage floor but that PJM’s criteria for excluding projects (see table) “gives us a little more comfort.”
“We appreciate PJM’s effort to balance interests” of developers and efficiency, she said.
Vice President of Planning Steve Herling said PJM would like to implement the changes in 2016.
Climate Change Impact? Higher Highs has PJM Adjusting Weather Forecasts
PJM is planning to change the way it forecasts weather in its planning studies due to a trend of higher peak temperatures.
The RTO has based its forecasts on temperature and humidity data from 26 weather stations dating back to 1973. But a new analysis revealed that peak readings for 1993-2013 were higher than those for 1973-1993.
Twenty of 26 weather stations had higher maximum temperature humidity index readings in the last 20 years than the earlier period, PJM’s Andrew Gledhill said.
As a result, Gledhill said, the RTO plans to exclude the earlier data and rely on that from 1994/95. It will reevaluate the historical base on a regular schedule — perhaps every five years — going forward.
Gledhill said a survey of North American forecasters indicated that most use samples of 20 years or less. “The fact that PJM uses 40 years — we’re kind of an outlier,” he said.
The change would suggest higher load forecasts, countering factors such as lackluster economic growth and energy efficiency that are likely to mute projected load growth. Herling said PJM will offer stakeholders a look at the combined impact of all of the load forecast changes at the Planning Committee’s September meeting.
Exelon’s Rebecca Stadelmeyer and FirstEnergy’s Jim Benchek asked for more discussion of the weather forecasting at the Load Analysis Subcommittee.
“This is a drastic change to what we’re used to,” Stadelmeyer said. “We want to be comfortable [with the change]. We’re not now.”
“We’re very uncomfortable at this time,” Benchek said.
Consolidated Edison reported second-quarter net income of $219 million ($0.75/share), compared with $212 million ($0.73/share) a year ago.
The company said results reflected changes in the rate plans of its utility subsidiaries, including growth in its gas delivery service related to oil-to-gas conversions, and lower operations and maintenance expenses, offset in part by higher interest expenses.
Adjusted earnings, excluding a gain on the sale of solar electric production projects, leasing transactions and the mark-to-market effects of the competitive energy businesses, were $228 million ($0.78/share) in 2015 compared with $189 million ($0.65/share) in 2014.
“Con Edison’s operating and financial performance continues to be strong,” CEO John McAvoy said. “We are embarking on a new era of energy delivery and customer choice. We are proposing new demonstration projects that will showcase energy efficiency tools, demand response and the usage information customers need to make choices, promoting solar power, energy storage and other distributed energy resources.”
Operations and maintenance expenses for Con Ed of New York were lower, reflecting lower electric operating costs and lower costs for support and protection of underground facilities to accommodate municipal projects. (See related story, NYPSC Accepts 7 REV Demos, Rejects 5.)
— William Opalka
Duke Q2 Earnings Drop; 2015 Still on Track
Duke Energy reported lower-than-expected second-quarter earnings Aug. 6, but the company said it remains on track to meet its 2015 goals.
Although adjusted earnings dropped to 95 cents/share from $1.11 for last year’s second quarter, Duke reaffirmed its 2015 adjusted diluted earnings guidance range of $4.55 to $4.75 per share.
The company reported $5.59 billion in revenue for the quarter, significantly below Wall Street estimates of $5.85 billion and the $5.71 billion it generated last year.
The Charlotte, N.C.-based company said results were affected by continued weakness in its international business — particularly Brazil — and the timing of operations and maintenance expenses at its regulated utilities.
Duke’s international business income was $52 million for the quarter, down 64% from the second quarter of 2014. A $1.5 billion stock buyback in connection with its $2.8 billion sale of 11 power plants in April to Dynegy helped offset international results.
“We met our customers’ energy needs … during extended periods of warmer-than-normal temperatures, particularly in the Southeast,” Duke CEO Lynn Good said in a press release. “Equally important, we continued to follow through on the growth initiatives that will provide long-term benefits for our customers.”
In a call with investors, Good said Duke has made “significant progress” in its coal ash removal efforts. The company announced in June it would shut down 12 coal ash basins in North Carolina in addition to 12 basins it already announced plans to close.
— Tom Kleckner
Dominion Meets Expectations
Dominion Resources met expectations with second-quarter earnings of 73 cents/share, near the top of its guidance of 65 to 75 cents.
Dominion posted earnings of $413 million, compared with earnings of $159 million for the same period in 2014. Revenue of $2.75 billion missed Zacks Investment Research’s estimate of $2.93 billion, however.
The Richmond, Va.-based company said earnings were up because a planned refueling outage at Millstone Power Station did not occur and because of higher revenues from growth projects. “All of the major projects in our infrastructure growth plan continue to move forward on time and on budget,” CEO Thomas Farrell said.
Dominion affirmed its 2015 operating earnings guidance of $3.50 to 3.85 a share.
— Tom Kleckner
Wholesale Business Drags Down Entergy Earnings
Entergy’s second-quarter profit tumbled 21% on declines in its wholesale commodities unit.
Net income of $148.8 million ($0.83/share) fell below analyst expectations of $1.14/share and the $189.4 million ($1.15/share) in the second quarter of last year.
Revenue for the New Orleans-based power provider fell 9%, to $2.71 billion.
Most pronounced was a $121 million drop in revenue for the wholesale commodities business. Power sales declined due to lower wholesale energy and capacity prices.
Revenue from Entergy’s utility segment of $1.5 billion was flat: it compares to $1.4 billion in the same quarter last year.
Clean energy technologies like wind turbines are seen as beneficiaries of the Clean Power Plan, and two reports released by the U.S. Department of Energy show its growth continued last year despite uncertainty over federal policies.
The 2014 Wind Technologies Market Report from the Lawrence Berkeley National Laboratory shows total installed wind power capacity in the United States grew 8% in 2014 to reach a nameplate capacity of nearly 66 GW, enough for almost 5% of electricity demand. Wind now generates more than 20% of electricity used in Iowa, South Dakota and Kansas. Meanwhile, prices for wind power purchase agreements have reached all-time lows. The national average levelized price of wind PPAs signed in 2014 was $23.50/MWh, down from $70/MWh in 2009.
The report cautions that most of these PPAs are from lower-cost regions of the country. The prices also benefit from the production tax credit, a federal subsidy that has helped the industry boom but will expire unless Congress extends it. Projects under construction at the end of 2014 will qualify, but that pipeline is expected to end sometime in 2016.
Electric utilities continued to be the dominant off-takers of wind power in 2014, either owning (26%) or buying (40%) power from two-thirds of the new capacity installed last year, according to the report. Merchant projects accounted for the remaining one-third.
Distributed wind — 7,400 turbines serving on-site or local loads — reached an installed capacity of 906 MW according to the 2014 Distributed Wind Market Report, by the Pacific Northwest National Laboratory.
About 58% of the distributed capacity is connected to distribution lines, with the remaining 42% serving on-site loads, either as behind-the-meter, off-grid, microgrid or remote net meter resources.
SPP and MISO met last week with their stakeholders to review the first five months of market-to-market (M2M) operations between the two RTOs, saying that while the process is off to a good start, there’s much room for improvement.
“On the whole, market-to-market is working well. It’s a more efficient solution when both markets have control of the congested flowgate,” said David Kelley, SPP’s director of interregional relations. “We’re just talking about design flaws in the overall process … specific instances where we don’t believe it’s working as it should.”
“The price convergence is not happening on some flowgates,” said MISO’s Ron Arness, senior manager of seams administration. “We need to improve that.”
M2M is intended to improve price convergence on flowgates along the RTOs’ seams: The RTOs compensate each other for redispatching generation to reduce congestion in a way that reduces overall costs.
‘Philosophical Discussion’ Needed
The two RTOS have identified nine issues that need a “philosophical discussion,” Kelley said. They include developing criteria for M2M’s usage when one or both RTOs do not have effective control of a flowgate, leading to oscillation — when one market has significantly more control over a flowgate than the other market, resulting in the constraint’s unbinding and reloading too quickly during the exchange of shadow prices — and price separation. They also have called for criteria to recalculate firm-flow entitlements (FFE) due to modeling issues or outages.
SPP has a separate concern over the differences in the RTOs’ settlement billing cycles, which ends up with SPP floating dollars for several days while trying to remain revenue neutral. Arness said those discussions will involve SPP’s and MISO’s upper management.
SPP maintains the oscillations have overloaded flowgates and led to higher shadow prices for transmission constraints — the marginal costs of reducing a constraint per megawatt of flow.
“SPP was able to manage constraints just fine before market-to-market, and we didn’t have oscillation,” Kelley said. “We believe changes can be made, but the [joint operating agreement] is flexible enough to where we can do that.”
Through July 27, MISO has sent $10.4 million to SPP to compensate for congestion costs, with SPP sending MISO $2.2 million. The two RTOs have experienced 243 M2M events — when the RTOs exchange messages concerning a flowgate needing relief — totaling 1,024 hours.
SPP and MISO have 135 permanent flowgates and 45 temporary flowgates between the two. MISO’s footprint accounts for the bulk of those flowgates, with 89 permanent and 13 temporary.
The two RTOs hold weekly review calls to approve M2M events. SPP and MISO review real-time operations of the events and the data-sharing processes to ensure they are able to correctly perform M2M settlements. The two parties must reach agreement before performing any settlements or adjustments.
Monitors’ Perspective
SPP’s and MISO’s market monitors took turns presenting their views of M2M’s performance so far.
SPP’s Market Monitoring Unit noted effective M2M should lower shadow prices and the length of congestion events but that it has not yet looked at enough data for most constraints. It said data for the first months showed no major unexpected M2M effect on prices, but those impacts vary by constraint.
The MMU also said SPP and MISO calculate their shadow prices differently and that M2M on some flowgates can have a significant impact on prices for a large portion of the SPP market, especially in Nebraska and western Kansas.
MISO’s Independent Market Monitor (IMM) said M2M coordination has been a “net benefit” in MISO by reducing congestion costs. The IMM did note, however, a number of startup issues that were “isolated and … not ongoing.”
The IMM said the two RTOs have used work-arounds when normal coordination did not lead to efficient results. It said while some work-arounds have been expedient, they “have not been ideal” and called for improved coordination procedures and possible JOA revisions.
“In particular,” the IMM said, “the current JOA may assign the monitoring responsibility for a flowgate to the RTO that has less or ineffective relief capability. In theory, this would not preclude efficient coordination. In practice, timing and coordination issues cause this to result in constraint oscillation, inefficiencies that are difficult to resolve and higher costs.”
