CAMBRIDGE, Mass. — Speakers at the Northeast Energy and Commerce Association’s dinner meeting last week discussed pending legislation in Maine, the future of the proposed Northern Pass Transmission project and net metering.
The state’s Site Evaluation Committee has a 10-step process for approving such projects. “The governor has been clear that she is waiting for the site evaluation process to play out,” Allegretti said.
Christopher Sherman, president of New Hampshire transmission for NextEra Energy, said one of the investor-owned utilities in Massachusetts earlier this year reached the 4% limit on the integration of net-metered generation onto the grid.
“The governor’s own bill [which would raise the cap to 6%, with future increases left to state regulators] will be considered at a hearing by the end of this month, with the possibility the legislature will pass a bill later in the fall,” Sherman said.
Sandi Hennequin, vice president of U.S. public affairs for Nova Scotia-based Emera Energy, mentioned a bill backed by Maine Gov. Paul LePage that would allow local distribution utilities, which were divested after restructuring in 2000, to own some generation assets.
The bill would require the Public Utilities Commission to determine “that ownership is beneficial to the utility’s ratepayers” and to “impose terms, conditions or requirements the commission determines are necessary to protect the interests of the utility’s ratepayers.” The bill was introduced last session and has been held over for consideration during the coming session.
Patrick C. Woodcock, director of the governor’s energy office, said LePage saw the need for the legislation because of ambiguity about whether affiliates of local utilities can own generation. Woodcock said neither the state’s restructuring law nor a recent court ruling provided clarity. The case involved a proposed $333 million joint venture by Emera and First Wind to finance wind farms in the state.
“The governor asked, ‘Does it really make sense to have this iron-clad prohibition?’” Woodcock said in an interview after the dinner. He said limited utility ownership of generation could help the state modernize older hydro facilities.
“I think there’s an opportunity there for some of the utilities to benefit from generating from solar,” said Maine Rep. Larry C. Dunphy, who introduced the bill on the governor’s behalf. “There’s a number of motivations.”
FERC Chairman Norman Bay named a long-time associate from New Mexico as FERC general counsel, replacing David Morenoff.
Max Minzer, who served as Bay’s special counsel in 2009-10 when the latter headed FERC’s Office of Enforcement, joined the chairman’s staff as an advisor in June.
Minzer met Bay while working as a law clerk at the U.S. Attorney’s Office in New Mexico almost 20 years ago. Bay was U.S. Attorney for New Mexico in 2000-01 after serving as an Assistant U.S. Attorney in D.C. and New Mexico from 1989 to 2000.
Like Bay, Minzer is a former professor at the University of New Mexico School of Law, where he won the university’s 2013-2015 Presidential Teaching Fellowship, an award recognizing teaching excellence. He previously taught at the Benjamin N. Cardozo School of Law in New York. A graduate of Brown University and Yale Law School, Minzer has been published in the Harvard Law Review, the Texas Law Review and the William & Mary Law Review.
Bay praised Morenoff even as he moved him aside. “It is a testament to the high regard in which David is held that he is one of the few general counsels who has served three different chairmen as either the acting general counsel or as general counsel,” Bay said in a statement.
Morenoff, who joined FERC from Troutman Sanders, formerly served as a legislative aide to U.S. Sen. Jack Reed (D-R.I.). He is a graduate of Brown University and Harvard Law School. In addition to his work in the general counsel’s office, he also served as senior legal and policy advisor to former Chairman Jon Wellinghoff.
FERC granted a waiver to a New England power generator that missed the deadline for a payment to increase the plant’s offer for the next Forward Capacity Auction.
The commission majority said Northeast Energy Associates had made a “good faith” effort to comply with ISO-NE rules once it discovered an administrative oversight (ER15-1934).
NEA sought a 25-MW increase in the capacity of its Bellingham Energy Center in Massachusetts but failed to make a $50,000 interconnection deposit for FCA 10 by the March 3, 2015, deadline.
It discovered the error that day but was unable to make a bank transfer before the Federal Reserve’s 5:30 p.m. deadline. The funds were transferred the following morning.
“We find that NEA acted in good faith by submitting its interconnection deposit as soon as possible after it discovered the omission … [and] the request for waiver is limited in scope, because it allows a one-time, finite waiver of a procedural deadline under the narrow circumstances of this case,” the majority said.
FERC said the company filed an otherwise valid request to increase its capacity and the delay in submitting its interconnection deposit would not affect the qualification process for FCA 10.
ISO-NE had opposed the request for relief, saying that it would be unfair to other project sponsors who submitted invalid interconnection requests and did not seek a waiver. The RTO also said NEA had not shown the resource would be needed in the newly proposed Southeastern New England capacity zone that will be created in the reconfigured zones in the 2018-2019 capacity commitment period.
Commissioner Philip Moeller agreed with the RTO, saying granting the waiver violates FERC precedent and will create future headaches.
“Such requests will present the commission with an enormous challenge to ensure that all market participants are treated similarly after missing [a Forward Capacity Market] or other deadline,” he wrote.
GridLiance arrived on the RTO scene in March billed as the nation’s first competitive transmission company focused on collaborating with public power entities. It came with a pedigree of experienced transmission executives from ITC Holdings and the deep pockets of private equity giant The Blackstone Group.
Now, the company has made its first two acquisitions — 420 miles of 69-kV and 115-kV lines in Missouri and Oklahoma — and announced plans to bid on SPP’s first competitive transmission project.
Incorporated last year, the company unveiled its business plan in March with the announcement that it and its affiliates had entered into 30-year development agreements with the Missouri Joint Municipal Electric Utility Commission (MJMEUC) and the Oklahoma Municipal Power Authority (OMPA), giving them the exclusive right to jointly plan, construct and operate the agencies’ transmission infrastructure in SPP and MISO.
On Sept. 1, GridLiance announced a pair of acquisitions that will give it ownership of the transmission assets of Nixa, Mo., a member of MJMEUC, and of Tri-County Electric Cooperative in the Oklahoma panhandle. Both acquisitions are expected to be completed by year’s end.
ROE Request
On the same day as the announcement, GridLiance subsidiary South Central MCN filed a request with FERC seeking a return on equity of 11.4%, including a 50 basis points (bps) adder for RTO participation and a 100 bps adder as a standalone transmission company (ER15-2594). The company asked for approval of an initial capital structure of 60% equity and 40% long-term debt.
South Central said FERC should grant the incentives to the company, “given its unique business model, which will provide benefits to current and future customers of the wholesale electric grid, including its public power partners.”
The company said it intends to submit a bid to SPP to build the North Liberal-Walkemeyer 115-kV project and requested commission approval to collect construction work in progress if it wins the solicitation. (See SPP Issues RFP for 115-kV Transmission Project.)
South Central will be the operating company for GridLiance in SPP. In MISO, the company will operate under the Midcontinent MCN.
Investment Opportunities, Reliability Benefits
In announcing the acquisitions, GridLiance president and CEO Ed Rahill said the deals allow Nixa and Tri-County to shift their operations and regulatory risk to GridLiance while gaining access to investment opportunities and funding for previously unaffordable transmission projects, including access to — and delivery of — wind energy.
Participating systems will see reliability benefits, according to Rahill, because public power systems are often excluded from regional planning models, leaving many served by a single radial feed, vulnerable to outages if that connection is lost.
“Operating and maintaining transmission infrastructure is expensive without scale, often taking valuable resources away from other core municipal responsibilities,” Rahill said.
Experienced Team
Rahill is one of several transmission and public power veterans who comprise the leadership team of the company, which has offices in Chicago, Kansas City and Austin, Texas.
Rahill was part of the of the management team that acquired ITC Transmission from DTE Energy in 2003 and managed its initial public offering in 2005. As president of ITC Grid Development, he oversaw ITC Great Plains’ greenfield start-up and the development of $500 million in transmission in SPP.
Noman Williams, GridLiance’s senior vice president of engineering and operations, is former vice president of transmission policy and compliance for Sunflower Electric Power, which runs six rural electric distribution cooperatives in central and western Kansas. He has filled several key leadership roles within SPP, and currently serves as chair of the RTO’s most important member body, the Market and Operations Policy Committee.
Like Rahill, Senior Vice President of Business Development Carl Huslig comes from ITC, where he was president of ITC Great Plains. He has worked extensively with SPP and MISO stakeholder groups during his 20-plus years in the industry, leading an SPP task force that paved the way for independent transmission companies.
General Counsel Beth Emery held the same titles at CAISO and San Antonio’s CPS Energy, the nation’s largest municipal utility. (Emery was joined in the company’s Sept. 1 filing to FERC by former Commissioner William L. Massey, now with Covington and Burling.)
Blackstone
The company is being financed by Blackstone Energy Partners, which has invested more than $8 billion of equity globally across a broad range of energy industry sectors. Blackstone Senior Managing Director Sean Klimczak, who oversees the firm’s investments in the transmission and power sectors, said the company saw an opportunity to fill an underserved market for 40 million public power customers.
Public power has “been largely excluded from participating in the planning of and investment in new transmission infrastructure as well as the financial and service reliability benefits they provide to customers,” Rahill said at the announcement of GridLiance’s incorporation in March 2014.
GridLiance’s partnerships with public power allow it to compete with investor-owned utilities that are building most transmission in MISO and SPP, the company says. About 90% of transmission projects in MISO have been awarded to ITC, Xcel, MidAmerican Energy, Ameren and American Transmission Co., the company says. In SPP, IOUs have been responsible for all but a few projects.
Meanwhile, public power rates have been increasing, with MJMEUC’s rates doubling under SPP’s highway-byway cost allocation. And 70% of public power transmission lines and transformers are at least 25 years old.
“Working together, we will have the necessary scale and resources to more effectively invest in, develop and construct new transmission infrastructure,” Rahill said.
Outsourcing
The deals announced Sept. 1 will give GridLiance operational responsibility for Tri-County’s 410 miles of transmission and Nixa’s 10-mile, 69-kV transmission line between Springfield and the Southwest Power Administration.
Jack Perkins, CEO of Tri-County, which has about 23,000 customer meters in the Oklahoma Panhandle, said the deal will allow the co-op to complete transmission reliability projects that it could not have otherwise afforded while outsourcing transmission operations. “Additionally, we will be able to reallocate funding and resources to upgrade our distribution system,” he said.
Doug Colvin, public works director for Nixa, said it no longer makes sense for the city of 21,000 to own its transmission infrastructure. “As regulatory requirements became increasingly complex, the city evaluated a number of options to protect our residents against rising costs and, at the same time, maintain our high reliability standards,” he said. “The GridLiance transaction ensures that we can meet these important requirements, as well as opens the door for our involvement in new transmission projects that can offset rate increases and provides us a much needed seat at the planning table.”
The nine Northeastern and Mid-Atlantic states participating in the Regional Greenhouse Gas Initiative last week said the 29th auction of CO2 allowances on Wednesday sold at a clearing price of $6.02. The price is 23% higher than the clearing price from a year ago.
Proceeds for the auction were $152 million, which brings the cumulative total for the program to $2.26 billion for investment in clean energy and energy efficiency programs in the member states.
Bids for the CO2 allowances ranged from $2.05 to $10 per allowance.
FERC Ruling Could Clear Way for School District’s Solar Project
A recent FERC ruling may clear the way for a local school district to generate solar power and sell its excess production to its host city.
The Rudd-Rockford-Marble Rock Community School District wanted to install a 750-kW system, which would produce twice the energy it needs. It proposed to sell the excess to the city of Rockford. But the Rockford municipal utility has a contract with wholesaler Municipal Energy Agency of Nebraska (MEAN) and argued that it would be violating the terms of its contract if it bought power from the school district.
A recent FERC case regarding a similar situation in Colorado ended in favor of a new solar generator, citing the Public Utility Regulatory Policies Act. Another utility has asked FERC to clarify its ruling, and the school district and MEAN are awaiting that review.
The application period is open for state residents who are having trouble paying their energy bills to get some help from the federal Low Income Home Energy Assistance Program.
John Allen, Delmarva Power and Light regional vice president, said the block grant program doesn’t pay anyone’s entire bill.
But, he said, “The financial assistance can help someone get through a crisis, a really cold winter or a dangerously hot summer.”
North Adams is now generating more solar power than the entire state did in 2007.
A 3.5-MW facility atop a former landfill, which feeds electricity into the power grid and is purchased back by the city at a reduced rate, is expected to produce most of the energy consumed by the city’s buildings, streetlights and other operations.
Combined with two other smaller solar projects with which the city has agreements, North Adams expects to offset all of its electricity usage with solar power. The city expects to save more than $400,000 a year now that the landfill solar facility is up and running.
Minnesota Power has told the Public Utilities Commission it will continue to move away from coal-fired electricity over the next 15 years and generate more power from natural gas, wind and solar sources.
The company’s 15-year integrated resource plan, which is filed biennially, lays out a pathway to comply with the Environmental Protection Agency’s Clean Power Plan. Minnesota Power pledged to add 200-300 MW of natural gas generation over the next 15 years, but the 500-page plan does not say where and when that will happen, or which of its coal-fired generators it will retire.
Environmental groups have pressed for a faster reduction in coal generation. Minnesota Power says that it needs to maintain a base of coal-fired plants to supply its large industrial customers.
The Public Utilities Commission has revoked licenses for the Sibley Wind Substation and Comfrey Wind Energy project.
Sibley Wind, a 10-turbine farm rated at 20 MW, asked for its construction permit to be withdrawn to address ongoing opposition based on bird- and bat-death concerns. The project’s management said it would try to meet with opposition members and attempt to “find a solution to answer their concerns.”
Comfrey Wind began construction before the end of 2014 to qualify for the federal Production Tax Credit without completing full compliance filings. Comfrey Wind President Pete Samuelson urged the PUC to show some compassion. “Comfrey asks that the commission understand and empathize that Comfrey had no choice but to perform minimal construction work, without holding a pre-construction meeting, prior to the end of 2014 to qualify for the PTC.” Comfrey is rated at 31.5 MW and includes 17 turbines on nearly 4,000 acres.
NPPD Offering Lower Rates for Long-Term Commitments
Nebraska Public Power District is considering offering lower rates in 2016 for cities, power districts and other wholesale customers that sign new 20- or 25-year commitments. A proposal during the August board of directors meeting sets the potential wholesale rate increase at just 0.6% for entities that enter into a new agreement. Customers who don’t commit themselves would get a 3.8% increase.
NPPD’s contracts with wholesale customers — including 51 communities and 25 public power districts and cooperatives that resell electricity to their retail customers — do not expire until the end of 2021. NPPD has been working on a plan to extend those contracts and improve its long-term financial stability.
The board is expected to vote on the 2016 rates in November. NPPD has raised its wholesale rates about 60% in the past nine years.
The North Country Community Recreation Center’s board of directors has voted to return a $10,000 grant from a fund created by the owner of the controversial Northern Pass project.
“We can’t just take a payoff,” said John Fothergill of the NCCRC board of directors. “We look to partner with our funders. We’re unclear about the Northern Pass Fund partnership intentions except that this seemed like an award for their own immediate public relations needs.”
The money came from the Coös County Jobs Creation Association, which was created by Northern Pass developer Eversource Energy. John Gallus, a former state legislator who chairs the association, said there were absolutely “no strings attached” to the award, other than that it be used to create or keep jobs in Coös County.
Public Service Electric & Gas has donated 35 electric car charging stations at seven sites as part of pilot program aimed to help spur the market for EVs.
“The lack of convenient charging stations remains an impediment that keeps potential EV drivers from going all electric,” said Joe Forline, vice president for customer solutions.
PSE&G plans to donate 150 units under the $400,000 program, particularly to companies, colleges and hospitals.
PRC Commissioners Refuse to Recuse from San Juan Hearings
Two members of the Public Regulation Commission have said they will not disqualify themselves from hearing Public Service Company of New Mexico’s (PNM) plans for the controversial San Juan Generating Station, despite an environmental group’s call for them to recuse themselves because they are allegedly too chummy with the utility.
Commissioners Sandy Jones and Patrick Lyons filed responses to a motion by the nonprofit New Energy Economy seeking to disqualify four of the five PRC members from ruling on the utility’s plans for the coal-fired power plant near Farmington. PNM aims to close two of the San Juan plant’s four coal-fired units and replace the lost capacity with more power from another unit at the plant, as well as power from a proposed new facility and third-party sources.
The activists contend that emails between PNM executives, as well as public statements by some commissioners, show the regulators are too cozy with the utility and should excuse themselves from voting on the issue.
PNM Asks for 15.8% Rate Increase in Return for Lower Fuel Costs
Public Service Company of New Mexico (PNM) has filed for a rate increase that would boost residential rates by 15.8%, generating about $123.5 million in additional revenue.
PNM said the rate increase would be lower if the state’s Public Regulation Commission also approves its plan for the San Juan Generating Station. The company arranged a new coal-supply contract as part of the San Juan proposal, which would reduce the increase to 8.3% for the average residence, or about $6.07 a month on residential electric bills.
The five-member commission in May rejected PNM’s previous rate request. The new request no longer includes a new fee for solar customers to connect to the grid, which would have ranged from $21 to $26.
The Monroe County legislature is considering authorizing the installation of two solar farms on about 28 acres of vacant county-owned land. County Executive Maggie Brooks said the project would be the largest solar installation in the state outside of Long Island and save the county $7.3 million in energy costs over the next 20 years.
The farms would encompass five parcels of vacant land and house 42,000 solar panels, totaling 11 MW. Under the terms of the agreement, the county would lease the land to Buffalo-based Solar Liberty, which would install and operate the solar farms. In exchange, the county would buy electricity from Solar Liberty and sell it to Rochester Gas & Electric for transmission and delivery credits that county officials and Solar Liberty executives estimate would be worth about $366,000 annually.
Solar Liberty estimates the project would be complete by the end of 2016.
The Environmental Protection Agency’s Clean Power Plan is hitting close to home in the state, where the final rule requires power plants to cut their carbon dioxide emissions almost in half. Democratic Sen. Heidi Heitkamp has called EPA’s plan a “slap in the face.”
Utility executives wonder how they can meet the EPA targets in the coming years without raising electricity rates and affecting system reliability, given that much of the electricity in the state’s west-central region is generated from brown coal. Some executives are considering closing coal plants to meet the emissions target, but they say they’re still working to understand the implications of the regulations.
“What is a fear on my part is that we’ll make irreversible or irrevocable decisions, and you might look like a hero or you might look like an idiot,” said Robert “Mac” McLennan, president and CEO of Grand Forks-based Minnkota Power Cooperative.
OG&E Customer Bills Lowered due to Lower Natural Gas Prices
Oklahoma Gas & Electric says lower natural gas prices and SPP’s Integrated Marketplace will mean lower bills for its customers. OG&E said the typical residential customer should see a monthly bill reduction of $5 starting this month.
OG&E, however, is also waiting on a final decision from the Corporation Commission on the utility’s $1.1 billion environmental compliance and replacement generation plan. The plan would increase customer bills 15 to 19% by 2019.
Solar Customers to See Changes Under OG&E’s New Billing Structure
Oklahoma Gas & Electric last month filed a new billing structure with the Corporation Commission that will add a demand charge for customers who install solar panels on their roofs. About 200 OG&E customers have installed rooftop solar.
The new rate structure for distributed generation customers would have four parts: a demand charge, an energy charge, a fuel charge and a customer charge. That’s a change from current bills, which are comprised of an energy charge, a fuel charge and a customer charge.
OG&E said the new billing structure will eliminate any subsidization of distributed generation customers by other customers.
The Public Utility Commission has approved PPL Electric’s plan to upgrade its smart maters. Installations are expected to start in 2017.
The meters will replace earlier devices installed in 2002 that are reaching the end of their useful life, according to the company.
The affected 1.4 million customers will soon begin paying a fee on their monthly bills expected to fluctuate from 58 cents in the beginning to $6.69 in 2019, the final year of installation.
PECO Energy customers will see their rates rise next year as the utility continues replacing equipment and upgrading infrastructure.
Under an agreement reached with the Public Utility Commission, the average monthly bill increase for residential customers will be $4.17. Small businesses will see their bills rise $17.02; for large businesses, the increase is $432.32.
The rates will translate to $127 million in increased annual income for the company.
PUC Commissioner Concerned over Hunt’s Oncor Acquisition
Anderson
Public Utility Commissioner Ken Anderson has filed a memo saying the agency must determine whether Hunt Consolidated’s bid to take over bankrupt power distributor Oncor gives “tangible and quantifiable benefits to ratepayers.” Anderson said the commission raised similar concerns in 2008 about the $45 billion leveraged buyout of TXU, which created Energy Future Holdings — whose bankruptcy is setting the stage for the Oncor sale.
Dallas-based Hunt filed a proposal with a federal court in August to split EFH into two companies as part of EFH’s $40 billion bankruptcy proceedings. Hunt and a group of creditors would raise $12 billion to take over Oncor, Texas’ largest power distributor with more than 119,000 miles of power lines. EFH’s power-generating division Luminant, which owns coal-fired power plants, and its retail electricity unit TXU Energy would be owned by a different set of creditors.
Anderson’s concern is that Oncor would become part of a real estate investment trust largely to avoid being hit with a big tax bill. Observers say a transaction of similar size has never been attempted.
Appalachian Power is seeking regulators’ permission to upgrade a transmission line serving Bland and Wythe counties as well as a small portion of Mercer County in West Virginia.
The Bland Area Improvements Project would upgrade 20 miles of existing line, add about 5 miles of new line and create a new substation.
Construction on the $80 million project would begin late next year, with a projected in-service date of December 2018.
Dane County Gives up Efforts to Force More Money out of Enbridge
Officials in Dane County are giving up their attempts to force pipeline company Enbridge Energy to pony up money to be held in case one of the company’s pipelines breaks and spills oil.
“It’s just fruitless,” lamented county zoning administrator Roger Lane, who said his county’s efforts were blocked by state lawmakers.
The county wanted to make a $25 million bond a requirement for its approval of a zoning permit for a pipeline pump station. But Gov. Scott Walker signed a state budget that, as a provision, forbade local entities from requiring pipeline insurance. The county wanted the provision because of perceived issues getting Enbridge to pay for damage related to a Michigan spill.
VALLEY FORGE, Pa. — DC Energy’s Bruce Bleiweis appears to face an uphill fight in his effort to win a rule change to mask the ownership of financial transmission rights.
Bleiweis’ problem statement won 61% support in a roll call vote of the Market Implementation Committee last week following protests from some members and the Independent Market Monitor.
Most problem statements are approved by acclamation, but members made clear there were too many differing opinions for such an endorsement in this case. Bleiweis would need to boost his support to a sector-weighted two-thirds majority to win approval at PJM’s senior committees.
Currently, all RTOs publish the identities of FTR holders when posting auction results. However, PJM does not disclose the ownership of other products, according to Bleiweis. (See “PJM Asked to Consider Masking FTR Ownership” in PJM Market Implementation Committee Briefs.) ISO-NE has begun a process by which it will post FTR market data only in the aggregate, according to the problem statement.
“We think this is a terrible idea,” said Market Monitor Joe Bowring, noting, as other speakers did, that members at the same time are being asked to consider relaxing some rules around data confidentiality. (See “Conversation Continues on Relaxing Confidentiality Rules,” below.)
“Reducing transparency at a time we’re talking about increasing transparency is a bad idea,” he said.
Carl Johnson, representing the PJM Public Power Coalition, concurred. “We would not support this as a one-off proposition,” he said. “It goes against transparency.”
Steve Lieberman of Old Dominion Electric Cooperative agreed. “From where I sit, it’s bad timing,” he said. “We just don’t view this as a problem.”
Bleiweis said the ownership disclosure was a problem because it allowed people to analyze companies’ positions, which can lead to unfair market advantages.
“We’ve spent 10 years advocating for more transparency. At this point, we just want parity because we haven’t gotten any sense that membership will move toward more transparency with other products,” he said. “We just want to be treated like everybody else.”
The initiative was assigned to the MIC. The work is expected to take three to five months.
Conversation Continues on Relaxing Confidentiality Rules
Members weighed in with their concerns in a discussion over proposed manual changes that would relax PJM’s data confidentiality rules.
Under the proposed changes, PJM would be permitted to release data in six areas:
Concluded individual generation outages, if it was determined to be relevant to an event on the grid, such as severe weather;
Demand response reply available in localized areas;
The identities — but not the offers — of resources committed in capacity market auctions;
Uplift payments in an area no smaller than a transmission zone, for a time period no shorter than a single operating day;
Aggregated statistics related to the execution and results of the Three Pivotal Supplier test, an addition requested by the Monitor; and
Information already in the public domain.
Some members worried that details about generation outages during a severe weather event might allow competitors to calculate non-performance charges under the new Capacity Performance product. Others suggested that data in the public domain be restricted to information released by the affected company in order to ensure its accuracy. PJM also was asked to provide clarity regarding whom it would release such information to.
Changes Coming to Settlement Process?
PJM is considering changing rules governing how electric distribution companies correct settlement errors.
The Settlement C process allows EDCs to correct significant errors 60 days after an initial settlement is performed, but its efficacy is limited by a requirement that all affected parties must consent to the resettlement.
PJM introduced a problem statement and issue charge that would ask the Market Settlements Subcommittee to determine whether changes need to be made to the process.
The issue was brought to PJM’s attention by Dayton Power and Light, Direct Energy and Pepco Holdings Inc.
Implementation of any accepted proposals is expected by the third quarter of 2016.
The MIC deferred until its next meeting consideration of manual and Tariff changes designed to reflect a Tier 1 compensation proposal that members approved in July. The delay was requested by Dave Pratzon of GT Power Group.
Enhanced Security Updates in the Works
PJM is updating its security rules for accessing the RTO’s website, with changes to password length, security questions and timeout restrictions. Customer account managers and users will be able to start creating system accounts Sept. 15. The changes are expected to be complete in the second quarter of 2016.
Fitch Ratings affirmed SPP’s long-term debt rating at A (third-highest) and its short-term grade at a top-ranked F1. Fitch said approximately $267 million of SPP debt was affected by the rating action, which came with a stable rating outlook.
Fitch said the ratings reflect SPP’s predictable cash flows as a result of its FERC-approved Tariff, which provides for the full recovery of all costs. It also cited the low business risk of its transmission operations, the investment-grade credit worthiness of its members and FERC’s “supportive federal regulatory environment.”
Fitch found SPP’s current liquidity position to be “sufficient,” with a $30 million unsecured revolving line of credit and approximately $43 million of unrestricted cash and cash equivalents.
Fitch said SPP’s voluntary membership remains “a modest credit concern,” which is mitigated by exit fees “equal to its share of SPP’s outstanding debt and other committed expenses.” Fitch also noted SPP’s exposure to a market participant’s payment default “is minimized by the collateral requirements as well as bylaws that allow for costs of the default to be spread among the remaining market participants.”
CAMBRIDGE, Mass. — Officials from PJM and ISO-NE were joined by consultants and market players in debating new performance incentives and the pros and cons of energy-only scarcity pricing at EUCI’s Capacity Market conference early this month. Several employees of MISO, which runs a voluntary capacity market to supplement state resource planning, were in attendance.
Below are some of the highlights.
PJM Senior Economic Policy Advisor Paul Sotkiewicz said he wishes consultant Roy Shanker had never invented the term “missing money” in describing the need for a capacity market.
“It makes it sound like it’s only about money when really this is about reliability,” he said. Capacity is less than 20% of wholesale cost, “yet we fight some of the biggest holy wars over it,” he added.
One of the benefits of PJM’s Reliability Pricing Model for capacity is that it is technology-, size- and age-neutral, he said. “I don’t care if you put a hamster on a wheel. As long as you feed it lettuce and it runs, [PJM is] good with it.”
Michael Borgatti, director of RTO Services for Gabel Associates, said PJM’s Capacity Performance rules are more risky for generators than ISO-NE’s Pay-for-Performance.
Borgatti said PJM officials have said that their limited force majeure rules would not have been declared in either the derecho or Hurricane Sandy in 2012.
“We can show you the material where they tell you you would have been penalized, even though the transmission lines are laying on the ground,” he said. “Now if the dispatcher calls you and says ‘the transmission lines are laying on the ground, take your machine offline or you’re going to blow a substation,’ you’re [absolved of] penalties. So this is the subjective nature of the PJM package. I would not count on simply the fact that the transmission system failed to excuse you from penalties.”
William Hogan, research director of the Harvard Electricity Policy Group, said the new capacity rules in ISO-NE and PJM have worsened the “disconnect” between the energy and capacity markets.
“I understand the problem and I think trying to make sure the generators perform is a good idea. But I think this is a Rube Goldberg system designed to avoid the obvious,” he said. “It does capture the marginal incentives for the generators … but it completely excludes load from this conversation.”
PJM Market Monitor Joe Bowring responded to Hogan’s criticism of PJM’s capacity construct, acknowledging that other markets have gone different routes in ensuring resource adequacy: Alberta allows limited market power; MISO uses cost-of-service regulation; California uses bilateral contracts; and ERCOT uses scarcity pricing.
“But all of these solutions have one element or another of administrative oversight,” Bowring said. “That is, none of them are some pure market solution.”
Sam Newell, principal for The Brattle Group, noted that his company has been involved in the calculations of the cost of new entry (CONE), which are used to set the ceiling on capacity offers. PJM allows bids up to 85% of net CONE without review.
“The thing that makes me nervous is that we’ve been involved many times in determining what is net CONE for use in the auction. I think we do a great job of it. But I know better than anybody there’s a lot of uncertainty in it. So, in effect, this very big administrative parameter, net CONE, now takes on a lot more weight. But I don’t know if it’s that’s the right level.”
Jeff Bentz, director of analysis for the New England States Committee on Electricity, said the joint solicitation for clean energy resources by Massachusetts, Rhode Island and Connecticut was a response to the lack of progress on proposals to bring new transmission into the region. (See New England States Combine on Clean Energy Procurement.)
“The concept here is we would hope maybe a wind provider and a solar provider and a hydro provider could maybe team up as one bidder and team up with a transmission developer and builder, and those three or four entities could put one bid into the RFP. And then when the wind’s blowing, the wind guy is providing the clean energy commitment. When the wind’s not blowing or the sun’s not out, the hydro guy can step in and fill the line. So we kind of wanted to leave this up to the market and let them prescribe how they best can meet the delivery commitment.
“[I have] no idea whether this is going to work or not. No idea whether the bids are going to be beneficial or not. But on the other hand we don’t see anything else really coming in to New England to solve this infrastructure issue.”
Andrew Gillespie, principal analyst for ISO-NE, said he hopes Pay-for-Performance will reduce the use of administrative pricing in future auctions. But he said they are unlikely to be eliminated because of political opposition to severe short-term price spikes.
“You could have price signals that in the long run provide the most efficient outcomes, but we don’t live in the long run,” he said. “The political reality is we live in the here and now. It is untenable to consumers for prices to go to $17, $18/kWh.”
Scott Harvey of FTI Consulting said that forward capacity markets such as PJM’s make procurement decisions based on often incorrect RTO load forecasts. “We’re consistently over-forecasting demand. So we’re constantly buying too much capacity. That’s one of the consequences of contracting forward like this.”
Todd Schatzki, vice president at the Analysis Group, said his company’s research has found wide disparities between the best- and worst-performing generators during reserve shortages. That, he said, will be reflected in their offers into the PJM and ISO-NE markets.
“If I’m a good resource, I actually want to be in this market. This is a good market for me because I’m going to make more money when I get to the compliance period. If I’m a poor resource, I’m probably going to lose money when I get to the compliance period, but I’m going to be able to anticipate that and include that in my offer.”
Debate over PJM Transition Auction
Wilson
PJM’s 2016/17 transition auction results were released during the conference, sparking a debate between Sotkiewicz and James Wilson, a consultant to consumer advocates in the RTO. (See Timing of PJM Auction Announcement Sparks Real-Time Debate.)
BOSTON – ISO-NE’s draft Regional System Plan shows flat load growth through 2024 due to growing solar PV and energy efficiency but predicts challenges from generation retirements and integration of variable resources.
The plan, released at a presentation last week, also cites eastern Massachusetts and Rhode Island as having the greatest need for new generation.
Load is growing annually at about 1.3%, said Michael Henderson, director, regional planning and coordination for ISO-NE. “But you subtract photovoltaics and energy efficiency, it comes down to about 0.6%,” he said.
The net summer peak average forecast is 26,565 MW for 2015, which grows to 27,875 MW for 2024. Winter load is slowly growing, but that peak is at night, when PV is of no help.
‘Tremendous’ Renewable Potential
The study says the region has “tremendous potential” for renewable energy, but it requires additional transmission, revisions to interconnection requirements and improved forecasting to ease their integration.
The region had 908 MW of solar capacity (nameplate rating) at the end of 2014, which is expected to grow to 2,449 MW over the next decade.
“As these [interconnection] improvements are made, it can only act to promote distributed resources because they will then be interconnected in a more reliable way and the overall system will be more tolerant of distributed resources,” Henderson said.
The region has almost 2,000 MW of wind capacity with another 4,100 MW in the interconnection queue. “Proposed onshore wind resources are predominantly in northern New England, and offshore resources are being proposed off the southeastern New England coast,” the study says. “A number of wind projects have interconnected to areas of the regional power system that have favorable wind conditions but are electrically remote and weak, and additional wind projects are proposed for these areas.”
Capacity Additions
A bright spot is the additional generation resources attracted in the ninth Forward Capacity Auction. (See Exelon, LS Power Join CPV in Adding New England Capacity.) The report cites improved incentives for resource performance and the use of a sloped system demand curve in the Forward Capacity Auctions to reduce price volatility.
“The addition of natural gas pipeline capacity or the increased use of existing [liquefied natural gas] facilities also could improve fuel assurance and regional reliability,” the study says.
The plan reiterates previous concerns about the north-south transmission corridor that starts north of Boston and runs through the metropolitan area into Rhode Island. New resources in the NEMA/SEMA/RI areas would provide the greatest reliability benefit.
Interregional Planning
The study calls for increased coordination of planning with other systems “particularly to provide access to a greater diversity of resources, including hydro and variable resources, and to meet environmental compliance obligations.”
The Operating Committee last week unanimously agreed to create a task force to close the gap between PJM metering requirements and member practices.
The Metering and Metering Requirements Task Force will be tasked with revising Manual 1: Control Center and Data Exchange Requirements.
“Manual 1 is deserving of a rewrite; it’s been too long,” PJM’s Ryan Nice said. “Metering is important because it’s a large capital investment, and it feeds into a lot of settlement applications.”
The changes will aim to address “long-standing clarity and readability issues” that have caused gaps between PJM’s “intended meaning and member understanding” on metering requirements, according to the problem statement.
Among the topics to be considered are meter maintenance and calibration standards. The group will examine existing metering infrastructure and common practices, particularly among transmission owners.
The work is expected to take three to six sessions.
Members should send names of those interested in joining the task force to ryan.nice@pjm.com.
Proposal Would Curtail RegD Resources in Regulation Market
The Regulation Performance Impacts group has proposed a modified benefits factor curve and a situational cap on “RegD” megawatts to address the issue of PJM’s regulation market purchasing too much of the fast-responding resources at times.
The solution, which will be brought up for a vote at the group’s Sept. 25 meeting, involves moving the benefits factor curve to the left so that it is at 0 at 40%. A cap of 26.2% also would be implemented during identified excursion hours — hours when dispatch frequently manually moves the regulation signal.
In addition, the group proposes a “tie-breaker logic” for the benefits factor ranking to address the issue of the adjusted total cost formation being ineffective when RegD self-schedules or is offered at $0.
“We want to review this quarterly,” Hsia said. “Nothing’s etched in stone.”
Sandi Hennequin, vice president of U.S. public affairs for Nova Scotia-based Emera Energy, mentioned a bill backed by Maine Gov. Paul LePage that would allow local distribution utilities, which were divested after restructuring in 2000, to own some generation assets.
