VALLEY FORGE, Pa. — Stu Bresler, senior vice president for market operations, told the Market Implementation Committee Wednesday that discussions with market participants and among staff have highlighted the need for manual changes to clarify rules regarding capacity bilateral transactions.
“Neither the Tariff nor the manual provides clarity about those transactions,” said Bresler, delineating them as unit-specific, auction-specific and locational unforced capacity.
He explained that in such transactions, the performance obligation remains with the seller, while the title to the megawatts for the capacity is transferred to the buyer. If the resource earns bonus credits, they go to the buyer.
At issue is the physical nature of the transactions, Bresler said.
“A court could say it’s not a physical transfer of megawatts, it’s just an assignment of receivables,” he said. “The more the physicality of a transaction is questionable, the more likely in a bankruptcy proceeding that the credit associated with that would be yanked away from the buyer and included in the bankruptcy estate.”
A second issue involves the fact that a buyer indemnifies PJM against a seller’s non-performance. “What happens if the seller in the transaction replaces the resource that was the subject of the transaction in the first place?” Bresler said. “What should the replacement rules be?”
Bresler suggested that the issue be expedited.
After Months of Debate, Data Confidentiality Rule Changes Endorsed
With 16 opposing votes, members endorsed changes to data confidentiality rules that have been the subject of debate since June. (See “Market Data Confidentiality Rule Change Gets First Reading,” PJM Market Implementation Briefs.)
Current rules prohibit PJM from talking about certain information even after it’s been disclosed publicly. At the heart of the deliberation has been how to provide PJM the ability to discuss situations such as generator outages while at the same time not disclosing commercially sensitive information.
The proposal allows PJM to release and discuss:
Information on individual generation outages involving an unusual operating condition on the transmission system such as a severe weather event;
The amount of demand response in an area no smaller than three ZIP codes (specific offers or suppliers would remain confidential);
The total amount of capacity offered and cleared, aggregated by transmission zone;
Uplift payments in an area no smaller than a transmission zone, and for no shorter a time period than one operating day;
Aggregated statistics related to the results of the three pivotal supplier test; and
Data made public by a PJM member or a state or federal regulator.
One minor change was made since the first reading. A sentence was added to specify the circumstances in which DR information would be released. The revised language allows such disclosures for incidents including, but not limited to, a severe event on the transmission system, a severe weather event, the formation of a closed-loop interface or the need for a transmission system upgrade.
Operating Parameters to be Subject of Special Session
An educational session will be held Feb. 24 to explain updated operating parameter definitions.
A number of operating parameters whose definitions appear only in the eMKT/Markets Gateway Users Guide have led to confusion among members about what values should be entered.
PJM also wants to clarify several terms in Manual 15.
A new “soak time” parameter has been proposed that would define the minimum length of time a unit must run to reach its economic minimum.
PJM and its Independent Market Monitor asked FERC Thursday to revise Capacity Performance rules to address concerns that generators might ignore dispatch instructions to avoid penalties.
FERC’s June 2015 order approving PJM’s tougher capacity requirements directed the RTO to eliminate language that would allow generator parameter limitations to be used as an excuse for nonperformance (ER15-623, EL15-29). The order argued that if resources were held only to parameter limits based on their physical characteristics, those that were less flexible would be able to avoid nonperformance charges more readily than more flexible units. (See What is Changing in PJM’s Proposal?)
However, PJM said in a Dec. 22 informational filing that eliminating any consideration of parameter limits from penalty calculations might lead some generators to self-schedule at maximum output in anticipation of a performance assessment hour, ignoring economic dispatch.
In a joint statement last week, PJM and the Monitor asked the commission to allow consideration of parameter limits but incorporate the Monitor’s recommendation that the limits be based on original equipment manufacturer (OEM) specifications rather than on historical performance data. This, they said, would ensure that resources not escape penalties “as a result of economic decisions about maintenance and investment.”
Under the proposal, resources would not face nonperformance charges if their operating parameters complied with the OEM limits and they followed dispatch orders. Resources that offered parameters less flexible than the OEM specifications would be ineligible for uplift and could be vulnerable to penalties.
They also asked FERC to approve the Monitor’s proposal that parameter limits be defined for ramp rate and boiler temperature retention times.
DTE Energy reported 2015 net income of $727 million ($4.05/share), a 20% decline from 2014’s $905 million ($5.10/share). The company’s $80 million net income for the fourth quarter was off 73% from the $299 million reported a year earlier.
However, the company reported that 2015’s operating earnings, which exclude non-recurring items, certain adjustments and discontinued operations, totaled $863 million ($4.82/share), a 5.8% increase over 2014’s $816 million ($4.60/share).
The Detroit company blamed its lower 2015 earnings on non-utility business lines — power and industrial projects, natural gas pipelines, gathering and storage, and energy marketing and trading — where earnings dropped 65.6% to $101 million, due in part to a $22 million loss by the trading unit. Earnings for DTE Electric rose 3% to $542 million for the year.
Operating revenues were $10.3 billion for the year, down from $12.3 billion in 2014. At the same time, DTE trimmed operating expenses to $9.1 billion in 2015 from $10.7 billion a year earlier.
Peter Oleksiak, DTE senior vice president and CFO, said the company forecast a mild winter before the fourth quarter began and went into a “lean mode,” paring down expenses.
During a Feb. 10 conference call, DTE CEO Gerry Anderson said some gas storage and pipeline projects across the industry might be “sub-investment grade.” He said the company will monitor its own investments in gas storage and pipelines but would be open to purchasing other companies’ assets if they were offered. He said that DTE’s industrial segment lagged in 2015 because of a weak steel market, but overall he saw no problems in the balance of the company’s portfolio.
The company paid dividends of $2.84/share for the year, up from $2.69/share in 2014.
Among 2015’s bright spots, Anderson said in a press release, were the company’s completion of more than 100 reliability improvement projects and its success in meeting Michigan’s 2015 target by sourcing 10% of electricity production from renewables.
“DTE made great strides in 2015, both operationally and financially,” Anderson said. “The year brought significant improvements … contributing to the best overall reliability performance in eight years.”
Anderson said DTE would continue to focus on reliability and pledged to invest $6.5 billion in distribution infrastructure over the next 10 years. DTE also said it plans to begin construction this year on what it described as the largest utility-owned solar array east of the Mississippi, a 45-MW project in Michigan’s “thumb” region.
AUSTIN, Texas — When Bill Magness was named as ERCOT’s new CEO last August, ISO Chairman Craven Crowell cited his leadership skills, utility experience and commitment to “strong working relationships” with key stakeholders as the primary reasons for his elevation from legal counsel.
Asked in an interview about his networking skills, Magness laid it on thick. “I’m old,” he said. “I’ve known many people.”
His comment drew a laugh, as it was meant to, much the same way as when Magness introduced himself to ERCOT staff by flashing a picture of his younger, long-haired self on the meeting room screen.
“Some things change, some things are different,” he said, pointing to his long-ago locks. Then, touching his clean-shaven upper lip — a contrast with his mustachioed predecessors, Trip Doggett and Bob Kahn — he said, “See, no mustache. I’m different.”
Stepping before ERCOT’s Board of Directors for the first time as its CEO last week, Magness fiddled with his ear clip microphone.
“I really appreciate, No. 1, the people who gave me this fancy, Madonna microphone,” he said, pausing for a moment. “For you younger people, that would be like Lady Gaga.”
Quarter Century
Magness’ self-deprecating humor wins him friends. But ERCOT’s board also selected him because of his quarter century of experience in what he calls the “utility restructuring business.”
Before joining ERCOT in 2010 as legal counsel, Magness was a partner for about 10 years with an Austin law firm, specializing in electric and telecomm utility matters. He served as lead counsel in cases before regulatory commissions in 16 states.
He also spent several years practicing before and working at the Public Utility Commission of Texas, where he worked alongside future FERC Chairman Pat Wood, future PUCT commissioner and current ERCOT Vice Chair Judy Walsh and current PUCT Chair Donna Nelson.
“I’ve been in the mix. … The people in the industry, we’ve all been in this together for a long time,” Magness said. “We’ve been through lots of challenges over the years as we’ve implemented the restructured markets. We’re all sort of change natives, working through these issues together. I just hope I can bring the best of that to my work.”
Nelson has no doubt that he will.
“Bill is a bright visionary with great people skills,” she said. “He has shown impeccable judgment and is uniquely qualified to build on the high standards set by Trip.”
Working together with the board, Magness is focusing ERCOT on five strategic priorities: adapting to a changing resource mix; providing “thought leadership” on the market and operations; effective and transparent communication; continually strengthening cyber and physical security; and developing ERCOT’s people and technology resources.
“They are the company’s top priorities, and we need to emphasize them internally and externally,” Magness said.
Magness drove home that point during last week’s board meeting by asking members of ERCOT’s retail operations team to “come inside the horseshoe” — the conference room’s semicircle of desks — to recognize process improvements the team made that will save more than $400,000 a year.
“They made things faster and better, cheaper and better, and so much cheaper it’s got to be better,” Magness said, leading the applause for the group.
Magness sought a seamless transition from Doggett. Under his predecessor, ERCOT was named one of Austin’s best places to work last year by the Austin Business Journal. Like Doggett, Magness enjoys kibitzing with staff and takes an interest in their work. All that’s missing, aside from a mustache, is Doggett’s North Carolina accent.
No Surprises
So what has he learned from Doggett?
“We don’t want to surprise people, if we can avoid it,” Magness said, referring to ERCOT staff. “We have to rely on our ability to stay ahead of issues and let people know the good, the bad and the ugly of what we’re seeing. That’s true of everybody in this ISO/RTO business.
“We could not run markets with the level of sophistication and precision we do [and] we could not turn out the amount and quality of data we do if we didn’t have the best technology and people who understand how to use it.”
To that end, ERCOT’s board last year approved $48 million to update the Texas grid operator’s software and hardware, a “technology refresh” so “we could ensure the market we would have the latest technology and upgrade it out into the future.”
The approved budget resulted in a 9-cent increase in the ISO’s system administration fee to 55.5 cents/MWh — a fee that had remained flat for nine years until 2014, and which ERCOT hopes to maintain until at least 2020. ERCOT officials said the increase was necessary after the heavy investment to bring the nodal market live in 2011.
“Because we did a big bang with nodal go-live, a lot of those things are aging out,” Magness said. “We’re doing a better job of trying to space things out, so you don’t have these huge big bangs every five years. It’s just time. I mean, you’re not using a seven-year-old iPhone.”
The technology update is needed for other reasons. Texas already leads the nation in wind-generation capacity with more than 17,700 MW — it would rank sixth if it were a country.
ERCOT, which serves about 90% of the state’s load, has 15,764 MW of installed wind and current projections see ERCOT’s solar capacity increasing from 288 MW to more than 1,000 MW by this summer.
Wind energy’s usage surpassed that of nuclear in ERCOT’s footprint for the first time last year, accounting for 11.8% of the grid’s energy consumption. Wind met almost half of ERCOT’s load on Dec. 20 (44.7%), generating 13,057 MW. (See ERCOT Energy Use up 2.2% in 2015; Wind Surpasses Nuclear.)
Texas’ $7 billion Competitive Renewable Energy Zone initiative added 3,600 miles of transmission lines from West Texas’ wind farms to population centers.
“The day we saw [wind] at 40% of load, wind units in ERCOT were running about 90% of nameplate,” Magness said. “The increase of intermittent generation and the need to continue to integrate it is very important to us.”
Ahead of the Curve
Staff and stakeholders are also looking at how to incorporate distributed generation, storage devices and smart grid technologies. An ERCOT future ancillary services team has developed a proposal to unbundle those services based on their characteristics.
“We’re trying to stay ahead of the curve,” Magness said.
That’s where thought leadership comes in, Magness said. “We have a very active and effective stakeholder process that vets issues very thoroughly so that before an issue gets to our Board of Directors, it’s been through a whole lot of discussion and consideration.”
The board “looks to us to develop a range of options and see what makes sense to them. The balance of industry experience and ERCOT experience that stakeholder board members bring and unaffiliated board members bring get us to a solution where you don’t need further consideration.
PUCT Role
“This works most of the time,” he said. “My evidence is you seldom see a decision of the ERCOT board appealed to the Public Utility Commission. [The PUCT] is very engaged. It looks to us for analysis and understanding.”
Magness recalled frigid February 2011, when generation outages led to rolling blackouts in the state just as the Dallas-Fort Worth area was preparing to host the Super Bowl.
“When things don’t go well, [the PUCT] gets concerned. Our legislature gets concerned,” he said. “We’ve done a lot better reaching out and explaining what we do, so that when something does happen — like it does — people … and especially the media … know, ‘Oh, yeah. It’s those guys.’”
Thus, the priority placed on “effective and transparent communication.”
“We generate, receive and send back a tremendous amount of data. One of the things that makes markets work is the transparency of that data,” Magness said. “We want to be sure all the data coming into the ISO is consistent. Most of the information we receive is not our information. We’re getting it out to folks to use in their own business. It’s not an area I think is weak, but if you don’t think about it strategically, an ISO can get way behind.”
ERCOT is located in the “Silicon Hills,” an area encompassing Austin and San Antonio that is home to tech giants Dell, IBM and Oracle and hundreds of startups. That provides fertile ground for technical expertise but also makes it a competitive environment for employers.
“We don’t have a whole lot of [physical] assets,” Magness said. “We have a lot of sophisticated hardware and software and people. We have to keep [all] of them working crisply.”
Corporate procurement of renewable energy nearly doubled in 2015, Bloomberg New Energy Finance reported in its 2016 Sustainable Energy in America Factbook. Procurement totaled 3,000 MW last year, up from less than 500 MW in 2012 and more than 1,500 MW in 2014. Wind and solar dominated, with a small amount of biomass and waste.
Google has been the largest buyer, with 71 MW of solar and 1.2 GW of wind. Amazon is second, with 80 MW of solar and 458 MW of wind contracted in 2015.
The Factbook was commissioned by the Business Council for Sustainable Energy, which represents companies and trade associations in energy efficiency, natural gas and renewable energy.
GridLiance Adds Industry Vets Boston, Morris to its Board
Competitive transmission company GridLiance named former PJM CEO Terry Boston and former American Electric Power CEO Michael Morris to its board of directors.
“Terry and Mike share our commitment to create a strong, proactive entity that will represent and serve public power’s needs in regional and national transmission planning and award processes,” GridLiance CEO Ed Rahill said.
The new appointments, effective March 31, expand the company’s board to six seats.
CMS Energy CEO John Russell is expected to leave his post on July 1, and Patricia Kessler Poppe, currently the company’s senior vice president of distribution operations, engineering and transmission, is set to replace him.
Poppe says she will dedicate her time to advancing subsidiary utility Consumers Energy’s renewable portfolio and meeting standards under the Clean Power Plan.
“We are committed to making sure that our customers have the kind of energy that they need when they need it and so we’re focused on a balanced portfolio,” Poppe said during a Michigan-based radio show.
Navy and Mississippi Power Team Up on Solar Project
The U.S. Navy Department and Mississippi Power said they are teaming up to construct a 4-MW solar plant on 23 acres of the Naval Battalion Center in Gulfport.
Instead of compensating the base monetarily for the land, Mississippi Power has committed to providing electrical infrastructure upgrades to the base. The electricity that the solar facility would provide will be routed to Mississippi Power’s electric grid. Hannah Solar, a Mississippi Power developer, will finance and build the project, which it aims to complete by the end of the year.
“This project, coupled with our existing energy programs, will increase the energy security of the installation, which will allow us to operate more effectively during times of crisis,” said Capt. Cheryl M. Hansen, the base’s commanding officer.
Ameren Missouri could stand to lose 10% of its business if Noranda Aluminum suspends operations at its New Madrid smelter as announced last week. The loss of the smelter’s business to Ameren, valued at about $160 million per year, has some speculating that the utility would look to ratepayers to make up the loss.
Noranda Aluminum, which has filed for Chapter 11 bankruptcy protection, said work on its last remaining potline in southeast Missouri would be scaled back after March. (A potline is a collection of “pots,” or large electrolytic cells, in which aluminum is made.)
The Missouri Industrial Energy Consumers, a consumer advocate group, filed a request in early February, asking the Missouri Public Service Commission to grant the smelter a lower power rate. The group says if the smelter closes, Ameren would be forced to sell the excess power at a discount on the wholesale market, then recover costs from ratepayers.
Former FERC Chairman Jon Wellinghoff was named to the board of directors of kWantera Inc., a company that provides predictive analytics to identify wholesale electric prices around the world.
Wellinghoff said he believes kWantera, which is based in Pittsburgh, can help the U.S. develop a cleaner and more efficient power grid. “We can help translate, for instance, for the average wind farm developer who may not understand how to use the tools to help him maximize the profits from his assets,” he said.
It is the first board membership Wellinghoff has accepted since leaving FERC at the end of 2013 to become co-chair of the energy practice at the Stoel Rives law firm.
Duke Energy said it is considering selling its international business unit that runs Central and South American power plants.
Duke Energy International, which is based in Houston, owns 4,400 MW of generation capacity in power plants in Argentina, Brazil, Chile, Ecuador, El Salvador, Guatemala and Peru. Two-thirds of the power plant portfolio is hydropower and half of the plants are located in Brazil.
The company has released few details on the plan, but it did say it planned to retain its 25% stake in the National Methanol Co. in Saudi Arabia, a producer of methanol and methyl tertiary butyl ether, a gasoline additive.
Exelon has spent about $259 million so far in its attempt to acquire D.C.-based Pepco Holdings Inc., according to Securities and Exchange Commission filings. The Chicago-based energy giant has spent $121 million on integration costs, and a further $138 million on financing, through the end of 2015.
The company is awaiting a final decision from the D.C. Public Service Commission, the last approval it needs. Exelon CEO Christopher Crane said that if the company doesn’t get the approval by March 4, it would pull out of the deal.
Exelon launched its bid nearly two years ago to acquire Pepco. The D.C. PSC first rejected the deal, in which Exelon offered $14 million in incentives to the district. The company later came back, promising $78 million in incentives and winning Mayor Muriel Bowser’s approval.
Talen Energy this month closed the sale of its Ironwood combined cycle natural gas power plant in Pennsylvania to a subsidiary of TransCanada. The sale, part of FERC-ordered market mitigation efforts, was completed Feb. 1 for $657 million.
The 704-MW plant in Lebanon County was one of several Talen had to sell after it was formed last year from the spun-off competitive power generation business of PPL and generation assets owned by private equity firm Riverstone Holdings.
Several more mitigation-ordered sales are expected to be announced in the next few months, the company said.
Danish wind farm developer DONG Energy has unveiled plans to build a project 10 miles offshore from Atlantic City.
The site covers about 160,000 acres and has an average water depth of 80 feet. “The site conditions are quite similar to those we currently work with in Northwestern Europe, which means that the project could be developed using well known technology,” DONG wind power executive Samuel Leupold said in a statement.
The New Jersey project would be DONG’s second wind farm in the U.S., following a project of a similar scale that would be built south of Martha’s Vineyard. For both projects, DONG acquired the development rights from another company, RES Americas Development, which won the rights in auctions held by the U.S. Bureau of Ocean Energy Management.
Exelon has put the old Boston Edison power plant in South Boston up for sale, probably for redevelopment.
The 18-acre New Boston Generating Station has reportedly attracted interest from a half dozen developers. Reuse plans haven’t been made public, but experts say any winning bidder would likely turn the little-used power plant into a mix of housing and commercial space. An Exelon spokesman said the company hopes to close a deal this year.
The plant was built in 1892, first to burn coal, then oil, then natural gas. It was largely retired in 2007, though Exelon still turns on a small generator during periods of peak electricity demand.
Canada’s Algonquin Power & Utilities has agreed to purchase The Empire District Electric Co. for $2.4 billion, including the assumption of Empire’s debt.
The Missouri-based Empire, with 218,000 customers in Missouri, Kansas, Oklahoma and Arkansas, will be folded into Algonquin’s Liberty Utilities unit at the close of the transaction, Algonquin said. Liberty Utilities has about 485,000 customers in Arizona, Arkansas, California, Georgia, Illinois, Iowa, Massachusetts, Missouri, New Hampshire and Texas.
Empire’s headquarters will remain in Joplin after the deal closes, the companies said. Empire shareholders will receive $34 per common share, a 21% premium to Empire’s Feb. 8 closing price. The Ontario-based Algonquin said all of Empire’s 750 employees will be retained, and customer rates are not expected to change.
Algonquin said it doesn’t expect to close the deal until the first quarter of 2017. Approval is needed from various state and federal regulatory agencies, including FERC and the Department of Justice, as well as the Federal Trade Commission. Because Algonquin is a Canadian company, the acquisition will also need the approval of the federal interagency Committee on Foreign Investment.
“The acquisition of Empire represents a continuation of our disciplined growth strategy, which strengthens and diversifies Algonquin’s existing businesses and strategically expands our regulated utility footprint in the Midwest,” said Algonquin CEO Ian Robertson.
It was the second takeover of an American utility company by a Canadian firm in the same week. Earlier, Newfoundland-based Fortis announced it plans to buy ITC Holdings, the largest independent transmission operator in the U.S., for $11.3 billion. (See related story, Fortis to Acquire ITC Holdings for $11.3B.)
U.S. utilities are an attractive target for Canadian companies. They are typically permitted a larger return on equity than Canadian firms. At the same time, analysts say, Canadian companies have access to cheaper financing, making it easier for them to complete transactions and to outbid U.S. competitors for acquisitions.
ITC and Empire aren’t the only companies attracting Canadian interest. Last fall, Nova Scotia-based Emera announced its intention to buy Florida-based TECO Energy for $10.4 billion. TECO owns electric and gas companies in Florida and New Mexico. That deal is expected to close in the middle of this year.
NEW YORK — Investor-owned utilities will have a central role in the expansion of distributed generation and renewables, ensuring profit growth even as load remains flat, the industry’s trade group told securities analysts Wednesday.
At its annual Wall Street briefing, leaders of the Edison Electric Institute touted utilities’ dividend growth and partnerships with technology companies to make their case for utility stocks.
But when EEI President Tom Kuhn and five other executives completed their presentations and opened the floor to questions, the first query addressed the lack of load growth, an analyst calling it “the elephant that, frankly, is not in the room.”
“You have had no sales growth whatsoever in something like the past eight years despite the increase in the economy. My question to you is: What are you going to be selling … to customers in the future if they’re not buying electricity?”
Tom Kuhn
Kuhn said that while increasing efficiency has disconnected load growth from the gross domestic product, it is also providing opportunities for capital expenditures — about $7 billion annually, he told about 150 analysts at the luncheon session at the University Club off Fifth Avenue in Manhattan.
He also cited spending on grid security and opportunities in the electrification of transportation.
“You want to sell what’s best for the customer,” Kuhn said. “In the future it may be things that flatten load — storage and other kinds of things … I think [vehicle] electrification is an important part of the equation, but [we’re] not really counting on major electricity growth to deliver what’s best for the customer.
“Over the past seven years, although load hasn’t really increased, you’ve seen utilities do pretty well,” he continued, citing the growth in dividends (39 of 46 publicly traded companies tracked by EEI raised dividends in 2015) and stock prices (up 71.5% over five years, despite a 3.9% drop in 2015).
Kuhn blamed 2015’s drop on rising interest rates and low natural gas prices. The EEI index’s 2015 performance trailed the Dow Jones Industrial Average (0.2%), the S&P 500 (1.4%) and the NASDAQ (5.7%). EEI’s five-year average beat the Dow Jones (70.8%) but fell short of the S&P (80.8%) and NASDAQ (88.8%).
The EEI index was up 7% in January, however, while broader indexes lost more than 10% amid concern over slowing economic growth in China.
Kuhn noted that utility credit ratings have improved to an average of BBB+, with 84% of companies rated as stable or positive as balance sheets have shifted toward regulated operations and away from competitive businesses.
Capital expenditures, which hit a record $108.6 billion in 2015, are forecast at $101.2 billion for 2016 and $92.2 billion next year. Spending, which was formerly dominated by generation, has shifted to distribution, which has doubled its share over the last five years, he said.
‘Enhanced Relationship’
In recent strategy meetings with utility CEOs, EEI identified grid modernization, clean energy and customer solutions as areas for growth, said David Owens, executive vice president for business operations and regulatory affairs.
David Owens
“It’s not just about electricity sales. It’s about your enhanced relationship with the customer,” Owens said.
It is utilities that are developing microgrids for military bases and that will build the charging infrastructure needed for electric vehicles, he said.
“We have many customers who are looking at a full array of technologies where they have greater control over their usage and greater control over their bills,” he said. “We’re seeking to become a full-service provider behind the meter… so we see a bright future.”
Role in Renewables
Richard McMahon, vice president of energy supply and finance, said utilities are the “primary investors” in all forms of renewables, with utility-scale solar representing 60% of all installed solar capacity.
EEI’s solar value proposition is cost. Utility-scale solar costs less than half as much as roof-top panels ($1.48/W versus $3.55/W for the first three quarters of 2015), according to the group.
McMahon said utilities also will be “major players” in buying and deploying storage. “Maybe the one silver bullet in energy storage hasn’t emerged yet, but there’s a lot of testing … currently going on in the industry and its happening really across the value chain,” he said, citing uses at the wholesale level for peaking, at transmission for voltage control and in distribution for power quality.
Brian Wolff, executive vice president for public policy and external affairs, touted EEI’s 182 technology partnerships with the likes of Tesla, Apple, Google and Nest Labs. “We view many of the so-called ‘competitors’ or ‘disruptors’ to our industry as partners,” he said.
EEI members spent more than $90 million last year to add 800 plug-in electric vehicles to their fleets. Seventy utilities have committed to invest at least $250 million over the next five years to increase their EV fleets. “This helps to push down vehicle development costs for automakers, making EVs more affordable for customers,” Wolff said.
Policy Initiatives
In addition to making their case for utility stocks in investors’ portfolios, EEI officials also briefed analysts on the group’s policy initiatives — chief among them changing state net metering policies to eliminate cost shifting from customers with rooftop solar. Owens said legislatures or utility regulators in more than three dozen states are considering changes.
The issue could be addressed by increasing charges for the fixed costs of the grid; through separate rates for buying and selling power; or a three-part rate, including a monthly basic service charge, a demand charge and an energy charge, Owens said.
Wolff expressed disappointment that a bipartisan energy bill stalled in the Senate earlier this month over aid to Flint, Mich., which is seeking funding to address lead in its water system. Assuming the hurdle is overcome, it would have to be reconciled with legislation that cleared the House earlier.
Although Senate leaders said they will reconsider their bill later this year, Wolff said, chances of passage are far from certain. “The closer we get to the election, the less appetite Congress has for doing big things,” he said.
Former FERC Commissioner Philip Moeller, who joined EEI last month as senior vice president of energy delivery and “chief solutions officer,” expressed disappointment at the Supreme Court’s January ruling upholding FERC Order 745.
Moeller was the lone dissenter on the order, which required RTOs to pay demand response at the same LMP rate as generation. Moeller argued for payment of LMP minus the avoided cost of generation. “I hope the commission will [revisit DR pricing] sooner rather than later,” he said. (See Clark Calls for New Look at Order 745.)
Ohio PPAs
EEI executives declined to take sides when asked about the power purchase agreements FirstEnergy and American Electric Power are seeking for their merchant generation in Ohio. The issue has pitted EEI Chairman Nick Akins, AEP’s CEO, against EEI Vice Chairman Chris Crane, CEO of Exelon. (See Exelon Calls FirstEnergy PPA ‘Grossly Lopsided,’ Says it Can Offer a Better Deal.)
All but one of the Ohio plants at issue are coal-fired, the exception being FirstEnergy’s Davis-Besse nuclear station.
But EEI’s McMahon chose to focus on the woes of nuclear plants whose revenues have decreased as low natural gas prices have lowered clearing prices — an issue on which AEP, FirstEnergy and Exelon are in agreement.
“I think there’s an overall recognition that companies are going to do what they need to do” to protect their baseload generation, he said. “Our focus has been more working with the FERC, working with the other trades and the RTOs to address these issues so that the markets really provide the appropriate price signals to those companies.”
FERC’s general counsel told a congressional subcommittee that there are “significant benefits” to a proposed amendment to the Federal Power Act that would allow challenges to rates that take effect as a result of a commission deadlock.
The proposed amendment to Section 205 was considered in a hearing before the House Energy and Power Subcommittee on Feb. 2.
Kennedy III
The Fair RATES Act (H.R. 2984) was proposed last year by Rep. Joseph P. Kennedy III (D-Mass.) after he found there was no legal recourse to challenge the results of ISO-NE’s eighth Forward Capacity Auction. The results were certified “by operation of law” in 2014 when commissioners failed to take action and indicated in public statements that they were split 2-2. (See FERC Commissioners at Odds over ISO-NE Capacity Auction.)
FCA 8, effective for the 2017/18 capacity commitment period, saw capacity costs total $3 billion, about triple the previous year’s results. New England’s congressional delegation protested the results but found itself in legal limbo because there was no FERC order on which to request a rehearing by the commission, nor any way to appeal to federal court.
“Appellate review is an important procedural avenue for those who do not prevail before an administrative agency. It would also correct an unusual outcome in a specific context that may arise when the commission has four voting members,” FERC General Counsel Max Minzner said.
FERC’s five-member panel dropped to four again last fall with the departure of Commissioner Philip Moeller. Thus the commission could find itself split again when it is asked to certify the results of FCA 10, which was held Monday. (See Prices Down 26% in ISO-NE Capacity Auction.)
“This outcome is certainly not impossible before we get this law across the finish line … given the fact that there are four [commissioners] … and no other nominations are in the pipeline,” Kennedy said.
Minzner said a complainant persuasive enough to convince a second commissioner of the merits of its case deserved an opportunity for further review.
He said he is aware of only six times under the FPA or the Natural Gas Act when a public utility filing went into effect without a FERC order. However, Minzner said he believes any change in the law should apply to “future cases,” leaving FCA 8 results intact.
After the congressional hearing, Sen. Edward Markey (D-Mass.) introduced a version of Kennedy’s bill in the upper chamber (S. 2494). The two congressmen also wrote a letter to President Obama urging a nomination to fill the current vacancy and pointing out that the five-member panel could be reduced to three with Commissioner Tony Clark not seeking reappointment when his term ends in June. (See Clark Won’t Seek New FERC Term.)
AUSTIN, Texas — The ERCOT Board of Directors Feb. 9 remanded to the Technical Advisory Committee a proposal to pay lost opportunity costs to generators ordered to ramp down for grid reliability.
Nodal protocol revision request (NPRR) 649, in the works since September 2014, received 56% support in a TAC roll call vote in November, short of the two-thirds threshold for approval.
Odessa-Ector plant (Source: Odessa-Ector Power Partners)
ERCOT submitted the NPRR to satisfy a settlement agreement with Odessa-Ector Power Partners, owner of a West Texas combined cycle plant that said it lost $300,000 because of dispatch overrides during three days in November 2012.
The settlement came in response to an appeal the company and Merrill Lynch, its qualified scheduling entity at the time, filed with the Public Utility Commission of Texas (docket #41790).
Odessa-Ector, a subsidiary of Koch Ag & Energy Solutions, asked the ERCOT board to override the TAC’s rejection. “While nearly all out-of-merit actions have financial protection in the protocols, these specific actions, which were not foreseen during the original protocol development, result in financial losses for those complying with ERCOT’s instructions,” the company said, predicting that remanding the issue to TAC would not resolve the impasse.
ERCOT CEO Bill Magness proposed that the board return the issue to the TAC.
“We believe if we remand this [to the TAC], there could be an opportunity for further discussion around the compensation issue and put further alternatives on the table,” Magness said. “We would commit to filing comments and identifying options we might put forward. It seems like it might be better to take one more crack at it [in the TAC] and work it out.”
Interested parties who had filed position statements supported Koch.
“After more than a year of work on this NPRR by stakeholders and ERCOT staff, it is clear that there is no acceptable resolution that would be achieved by additional time or debate,” said Texas Competitive Power Advocates, which called the NPRR “fair and appropriate.”
South Texas Electric Cooperative and Golden Spread Electric Cooperative also asked the board to grant the appeal, saying “strong support at multiple TAC subcommittees are indicative of a NPRR that is well vetted and developed.”
The Wholesale Market Subcommittee unanimously endorsed the proposal in October and the Protocol Review Subcommittee endorsed it with one opposing vote.
Twelve voters from ERCOT’s Consumer, Cooperative and Independent Retail Electric Provider (IREP) market segments opposed the proposal at the TAC meeting, where there were also three abstentions from the IREP and Investor-Owned Utility segments.
Some opponents said that since ERCOT’s nodal market went live in December 2010, ramp-down dispatch orders have been rare and do not justify the estimated cost. Others contended that that the proposal could overcompensate generators rather than making them whole.
“It’s a slippery slope when you start paying opportunity costs and lost profits,” said Valero Services’ Jack Durland, who represents industrial customers. “ERCOT does everything it possibly can, but it can’t always take power. Should generators be guaranteed payments?”
“There are solid arguments on both sides of this issue,” said unaffiliated director Karl Pfirrmann. “It’s important for stakeholders to reach [a] solution, rather than us direct it from above.”
Pfirrmann said he was “concerned about precedent-setting issues as we go forward,” expressing his hope that “we find resolution in our committee structure.”
The motion to remand the issue to the TAC carried with one abstention. The board also directed ERCOT staff to file suggested alternatives that might satisfy the two-thirds majority requirement.
TAC Chair Randa Stephenson promised the board her committee would be “very diligent” about bringing the NPRR back to the board for its next meeting in April.
The Supreme Court’s stay of the Clean Power Plan won’t affect PJM’s planned analysis of the economic and reliability implications of complying with the federal program.
“Our main concern is reliability. We don’t have a position on the Clean Power Plan as far as merits, but we recognize it is a transformational change that we need to be prepared for,” PJM’s Muhsin Abdurrahman told the Transmission Expansion Advisory Committee on Thursday. (See Supreme Court Blocks Clean Power Plan.)
Earlier in the week, PJM released the methodology it will use to study the CPP for a report to be published by May 31. That target date still stands.
PJM said the report will “identify potential economic, operational, resource adequacy and transmission usage implications” of the CPP, emphasizing that the review will not be used to decide on specific transmission upgrades.
PJM’s analysis of the Clean Power Plan will model various scenarios to provide states with detailed information about the impact and costs of possible compliance pathways.
States had faced a Sept. 6 deadline to file a compliance plan or request an extension. Now that they have more time, Abdurrahman said, they are asking for even more sensitivity studies.
“They want to know, is my state a net buyer or seller of allowances? Do I have to incentivize more wind and solar, or do I have an option to purchase it externally, and what would it cost?” he said.
PJM’s first review will address the long-term impacts of the plan and be confined to the PJM footprint. Future analyses coordinated with other balancing authorities will address energy market interchange and broader emissions trading in the medium term and short term, the RTO said.
The EPA rule includes performance standards for generators. Together, PJM said, the standards would “shift the way energy is produced and delivered within the PJM system and influence future investments in generation sources.”
In PJM, the rule would reduce carbon emissions by 36% from 2005 levels by the year 2030.
The key variable in compliance will be the choice of a rate- or mass-based approach, along with the level of credit trading in which generators will be permitted to engage. Rate-based compliance limits emissions in tons per megawatt-hour; the mass-based method caps emissions in tons per year.
“Each of the compliance pathways is likely to yield different economic and reliability results for the PJM region over the interim (2022-2029) and final (2030 and beyond) compliance periods,” PJM said in announcing its methodology. “PJM’s modeling approach is designed to provide states with answers on how compliance with the CPP will drive market outcomes and the need for additional investment in the electric system.”
Natural gas prices and state renewable portfolio standards “have the potential to affect power sector-wide economic outcomes and incremental CPP compliance cost perhaps more than any other driver,” according to PJM. “Consequently, PJM will study each of the compliance pathways and the reference case with and without the renewable portfolio standards and for a high and low natural gas price forecast.”
Analysts will employ the reliability pricing model base case — used to develop the parameters for PJM’s capacity auctions — for their initial transmission and generation assumptions.
Initial assumptions regarding renewable resources available in 2019/20 will be based on an evaluation of the historic commercial probability of resources that enter the generation queue and the incentives from the extension of the federal production and investment tax credits, PJM said.
Westar Energy is set to deploy drones to help it perform a variety of tasks, such as pinpointing storm damage and inspecting wind turbine blades.
Duke Energy said it is considering selling its international business unit that runs Central and South American power plants.
Talen Energy this month closed the sale of its Ironwood combined cycle natural gas power plant in Pennsylvania to a subsidiary of TransCanada. The sale, part of FERC-ordered market mitigation efforts, was completed Feb. 1 for $657 million.
Danish wind farm developer DONG Energy has unveiled plans to build a project 10 miles offshore from Atlantic City.
Exelon has put the old Boston Edison power plant in South Boston up for sale, probably for redevelopment.
