State regulators on Friday approved Public Service Company of New Hampshire’s divestiture of the Merrimack Station and other generation assets, ending a 20-year odyssey that began with the state’s Electric Utility Restructuring Act of 1996 (DE 11-250, DE 14-238).
The New Hampshire Public Utilities Commission’s order approves a settlement negotiated last year between the utility and regulators in which PSNH, a subsidiary of Eversource Energy, would recover $415.5 million from ratepayers for the cost of a scrubber at the 439-MW coal-fired plant.
Merrimack Station Source: Wikimedia
Eversource shareholders would forego $25 million in deferred equity. (See Eversource to Sell New Hampshire Plants.) The order also said the company “prudently incurred” the costs associated with the installation of the scrubber, which was approved by legislators in 2014.
The order also approves the sale of all Eversource generation assets in the state through an auction, which is expected to net $165 million in customer savings from 2017 through 2021.
More than a year ago, a state report said the Merrimack plant sale could net $225 million. In the meantime, however, cheap natural gas has strengthened its position as the dominant fuel source in ISO-NE and power prices have dropped dramatically. (See ISO-NE: Power Prices Fell by One-Third Last Year.)
In addition to Merrimack, and nine hydroelectric plants totaling 69 MW, the sale includes the 400-MW oil-gas Newington Station, built in 1974, and the 63-year-old, 150-MW Schiller Station, which burns coal, oil and biomass.
The plants are the last utility-owned generators in the state. PSNH challenged the 1996 restructuring law, which required retail choice and the divestiture of all utility generation, resulting in years of litigation. In 2003, the state legislature approved a bill delaying PSNH’s sale of its fossil or hydro assets until 2006.
Eversource must transition to competitive procurement for default energy service within six months of the sale of the assets. The agreement also calls for the company to provide tax stabilization to the host communities of the sold plants for three years if the plants sell for less than their assessed values.
The settlement also approves the sale of rate reduction bonds, which will finance the stranded cost balance at a lower interest rate lower than the return on equity that Eversource would receive if its generation remained in rate base. Eversource shareholders will also contribute $5 million to establish a clean energy fund for initiatives throughout the state.
The PUC said the settlement “involved a balanced compromise and resolved technically complex issues arising from the divestiture of Eversource’s generation assets.”
Govs. Speak Against Artificial Island Cost Allocation
Maryland Gov. Larry Hogan and Delaware Gov. Jack Markell stepped up their complaints that the cost allocation for New Jersey’s Artificial Island nuclear project disproportionately affects customers in their states.
The two held a news conference at a waterfront restaurant on their states’ border, insisting they’ll do “whatever it takes” to reverse the cost allocation scheme.
The State Lands Commission has given Pacific Gas and Electric permission to lease the site of the Diablo Canyon nuclear plant through 2025 without an environmental review.
Until the recent announcement of a settlement to retire the plant, environmental organizations and labor leaders had been urging the state to deny the company a lease beyond its previous 2018 expiration. As part of the settlement, the groups said they would back a move by the state to extend the lease. The plant’s operating license with the U.S. Nuclear Regulatory Commission ends August 2025.
The land commission unanimously approved extending the lease after staff assured it that an environmental review was not required for extension. The threat of a review, first raised by state officials last year, was one of the factors that pushed PG&E to seek an agreement.
Two weeks after the Public Service Commission denied a final challenge to Exelon’s $6.8 billion acquisition of it, Pepco has asked for a 5.25% rate increase for its 282,000 customers in the district. (See District, OPC Ask PSC to Reconsider Exelon-PHI Merger.)
Pepco said it needs the $85.5 million increase to help pay for the $658 million it has spent on reliability improvements over the past three years. The increase would cost district customers about $50 a year when it takes effect next summer.
Indianapolis Power & Light has filed for a rate hike to pay for the installation of $100 million in emissions-control technology at its coal-fired Petersburg Generating Station.
The utility filed petitions with the Utility Regulatory Commission to increase customer bills by 20 cents a month in 2017. The amount would rise until 2021, when customers would pay $1.40/month more for the pollution-control measures at Petersburg, which are aimed at reducing sulfur dioxide emissions and coal ash.
IPL has financed $450 million in pollution controls at Petersburg in recent years, but some environmentalists say continued investment is wasted as environmental regulations become more stringent. “IPL continues to throw good money after bad,” said Jennifer Washburn, an attorney at utility watchdog Citizens Action Coalition of Indiana.
A plan to install a pilot tidal energy project in the Cape Cod Canal is gaining momentum with a collection of grants, including funding from the state Seaport Economic Council.
The Marine Renewable Energy Collaborative is gathering the funds, permits and technology to install a tidal generator capable of producing up to 5 MW from the swift currents in the canal. The collaborative has identified a site, in the Muskegat Channel off Wasque Point, which has already received a preliminary permit from FERC.
The project has garnered more than $2 million in state and federal funds, and now needs about $300,000 to complete the final permits and conduct an underwater archeological study of the site. It would be the first of its kind in the U.S.
MSU 13-MW Solar Project To Go Forward with Tax Deal
A $24 million, 13-MW solar project at Michigan State University will go forward after the East Lansing City Council approved an 80% tax abatement for 10 years, 15 years fewer than the developer was seeking.
Inovateus, the developer, said the 10-year abatement will save it $2.6 million.
Some council members saw the tax subsidy as a win-win for the city by providing some tax revenue in the long run and increasing the renewable energy needed to help the city and the university meet their sustainability goals. Opponents decried the loss of tax revenue.
The state’s Agency for Energy has released a new report, “Clean Energy Roadmap,” recommending approaches the state can use to foster private competition in its clean energy industry.
The $702,500 report, funded primarily by the U.S. Energy Department, advises the state to strengthen research and development by partnering with universities, hosting regular technology contests and finding more sales and export opportunities for clean energy manufacturers in the state. It also encourages the state to use its business networking program to link technology developers with builders and architects.
The report also recommends the state “umbrella” all utility energy efficiency programs into a single program so customers have similar incentives.
Clean Line Energy Partners has submitted a new application for the Grain Belt Express transmission project to the Public Service Commission. The move came after recent high-profile endorsements from the public and private sector.
The PSC scuttled the project’s initial application last year amid concerns from farmers and other landowners in the transmission line’s path. Gov. Jay Nixon last week endorsed the project, and it has also won support from a number of state municipalities and businesses. The state’s approval is the last needed for the project to go forward.
The Public Service Commission narrowly approved suspending the $66/MWh qualifying facility rate for new small-scale solar facilities, instead requiring NorthWestern Energy to negotiate prices for solar projects ranging from 100 kW to 3 MW.
The state has recently seen a flood of solar energy developers looking to take advantage of the Public Utility Regulatory Policies Act’s QF provision, which requires utilities to obtain some of their power from smaller sources. The commission said the suspension was necessary to ensure that customers pay a reasonable price for solar power.
Commission Vice Chair Travis Kavulla dissented, saying the PSC should have devised a new rate and questioning the legality of the commission’s action. Commissioner Kirk Bushman also dissented, but he said that the suspension should apply to all QFs, not just solar facilities.
The Public Regulation Commission resumed a hearing last week on Public Service Company of New Mexico’s proposed rate increase of as much as 15.8%, which would add between $5 to $13 to customer utility bills.
PNM says it needs the money to offset the purchase of electricity from a nuclear power plant and its investments in alternative energy. Regulators and lawyers questioned whether PNM had taken into account the decline in the market for nuclear energy and the electricity needs of the state, as well as what is fair to customers.
The company purchased 64.1 MW from two units at the Palo Verde Nuclear Generating Station for a cost of $163.3 million in early January. The purchase was meant to replace the power lost in the shutdown of two coal-burning units at the San Juan Generating Station.
More than 100 environmental organizations urged Gov. Andrew Cuomo to reject a proposed plan to provide economic support to struggling New York nuclear generating stations, calling nuclear “dirty and dangerous.” They urged Cuomo to support renewable energy projects instead.
Sen. Joseph Griffo, chairman of the Senate and Telecommunications Committee, last month urged the state Public Service Commission to implement a nuclear subsidy in the pending Clean Energy Standard. Entergy has already announced plans to shutter its James A. Fitzpatrick plant, and Exelon has threatened the same for its Nine Mile Point Unit 1 while also saying Unit 2 and R.E. Ginna are also economically threatened.
Coal Ash Bill Passes House, Heads to McCrory’s Desk
McCrory
State legislators crafted a compromise that allows Duke Energy to close seven coal ash pits without excavation and does not reinstate an independent coal ash commission that Gov. Pat McCrory disbanded.
Legislators said the new bill, which is ready for McCrory to sign, will allow the company to spend less on cleaning up seven of its pits while ensuring that residents living near the coal ash pits will have clean drinking water, a large concern for many of the lawmakers.
IDT Customers Get Rebates From Polar Vortex Settlement
IDT Energy customers will receive $2.4 million in rebates under a settlement approved last week by the Public Utility Commission regarding electricity overcharges during the 2014 polar vortex.
IDT already has provided more than $4.1 million in rebates, refunds and rate adjustments voluntarily, the company said. Under the terms of the settlement, consumers who were on a variable-rate plan from January to March 2014 will be contacted by the settlement administrator if they qualify.
The refunds are part of a $6.75 million settlement IDT agreed to after Attorney General Kathleen G. Kane and Acting Consumer Advocate Tanya J. McCloskey leveled charges of deceptive marketing practices against the company. IDT will also pay a $25,000 civil penalty.
Legislators Seeks Limit on Turbines near Military Bases
Two state legislators are drafting proposals that would exclude wind energy projects in a 25-mile radius of military installations from getting state tax abatements, though the measures will not be considered until the Legislature reconvenes in January.
Two potential wind farm developments could threaten flight training missions and radar operations at nearby Sheppard Air Force Base, according to base officials and wind energy opponents. The worst-case scenario, they say, is that Sheppard’s missions are moved elsewhere and Wichita Falls loses an estimated $750 million in annual economic impact.
Representatives of Horn Wind, the developer of the projects, and Alterra Power, the Canada-based owner, have repeatedly said they want to minimize any potential impact the facilities have on the air bases. They also have contracted with an aeronautics consulting firm to determine whether projects in Bluegrove and Byers would interfere with base operations.
The Public Utility Commission is seeking comments on its recently released report on alternative ratemaking mechanisms.
The report, which surveys and analyzes 11 ratemaking rules and methods, was commissioned by the PUC in response to state legislation passed last year. The methods that may be of most interest to the state are ones focused on streamlining the regulatory process, according to the report.
The PUC is requesting comment on whether the report is “sufficiently comprehensive” and any other recommendations it should make to the legislature.
Gov. Terry McAuliffe signed an executive order creating a work group to address climate change, drawing complaints from both Republicans, who said the governor is overstepping his bounds, and environmentalists, who criticized the move as “vague and uncertain.”
The governor charged the group with recommending how the state can combat climate change. The move is seen as an attempt to get around language in the Republican-controlled legislature that blocks any actions by the state to comply with the Clean Power Plan.
Environmentalists pointed to the Democratic governor’s support of two planned natural gas pipelines that would cross the state, which they say show he is not serious about fighting climate change. Republican House Speaker William J. Howell criticized McAuliffe’s use of an executive order, saying it was “another deliberate attempt to circumvent the legislature and the will of Virginia voters.”
Nearly four decades after its passage, the Public Utility Regulatory Policies Act still generates controversy.
PURPA’s supporters and critics sounded off at a June 29 FERC technical conference exploring the ongoing challenges of implementing the law, which Congress enacted in 1978 to diversify the country’s energy supply, increase efficiency and develop a market for independent power producers. The session focused on PURPA’s mandatory purchase obligation and the determination of avoided costs for those purchases (AD16-16).
“In my view, PURPA has held up reasonably well,” Ken Rose, an economist representing the Independent Power Producers Coalition of Michigan (IPPC), told the conference. “It’s hard to believe [that] 40 years on, we’re still working on implementation.”
FERC Commissioner Tony Clark said the law provided a “foot in the door” for the renewable resources now roiling the power industry and its markets.
He also pointed out the commission’s motivation for revisiting the law, saying, “We’re hearing anecdotally about some of the concerns, especially from the West.”
‘Gaming’ the System
Paul Kjellander, president of the Idaho Public Utilities Commission, said his state’s biggest concern is developers disaggregating large wind projects into smaller units in order to obtain the most favorable avoided cost rates for qualifying facilities.
Kjellander referred to the practice as “gaming” the system.
PURPA requires utilities to pay QFs the cost a utility would incur for supplying the power itself or by obtaining supplies from another source. The law leaves it to each state’s utility commission to formulate those rates, depending on project size.
At one time, Idaho’s rules allowed for projects of 10 MW or below to qualify for the state’s most favorable avoided cost — or standard — rate. As in all other states, projects were subject to FERC’s “1-mile rule,” which requires developers to maintain a 1-mile buffer between projects in order to qualify them as separate QFs. The commission implemented the provision to prevent disaggregation.
In 2010, the Idaho PUC received applications for 500 MW of PURPA projects. The minimum system load for the state’s largest utility, Idaho Power, is about 1,100 MW.
Each project submitted that year came under the 10-MW threshold, and most met the 1-mile standard. Kjellander pointed to an instance in which a developer divided the 151-MW Cedar Creek Wind Farm into five projects, each spaced 1 mile apart.
The Idaho PUC reduced the eligibility cap for the QF standard rate to 100 kW later that year in response to requests from the state’s three investor-owned utilities. The regulator last year reduced contract terms from 20 to two years.
Still, Kjellander said his agency observed what it considered another type of gaming when a PURPA developer moved a proposed project across the state line to Idaho Power’s territory in neighboring Oregon, where avoided cost rates were higher. The Oregon Public Utility Commission approved the project, which had also been broken into five units. Despite the project’s location, Idaho customers will foot nearly all the costs for that project, he said.
“We’re looking at an ugly border war with the state of Oregon,” Kjellander said.
‘Manageable Issue’
“This is a manageable issue — it’s not something that can’t be resolved,” countered Robert Kahn, executive director of the Northwest and Intermountain Power Producers Coalition. “To say [PURPA] is easily gamed is to understate the capacity of [state] commissions.”
Kahn called PURPA a “keystone” in facilitating competition. He said that in Oregon — which he said was “a model for PURPA” — small power producers have built just 5% of the resources used to serve the state’s electricity customers.
Without PURPA’s mandatory purchase obligation, he said, small producers in the Northwest are unable to interconnect with the regional market.
“We advocate for organized markets,” Kahn said. “We are not there yet.”
“The argument that the [Western Energy Imbalance Market] negates PURPA is nonsense,” he added.
Organized Markets not Enough
Varnum attorney Laura Chapelle, who represented Michigan’s IPPC, said that even a fully organized market is insufficient to support the financial viability of most QFs in the state, most of which is located within MISO. She contended that the RTO fails to provide a long-term market for smaller generating resources, given that most states in the footprint retain regulated markets.
“Utilities [receive a state-regulated] rate of return to pay for their resources but want to require that QFs use MISO to get compensated,” Chapelle said.
The power purchase agreement is “the single most important component for a project not owned by a utility,” said Todd Glass, an energy attorney with Wilson Sonsini Goodrich & Rosati, who represented the Solar Energy Industries Association at the conference.
Wind projects are becoming more challenging to finance and develop, according to Glass. He also contended that “the utilities are becoming harder to deal with” with respect to negotiating contracts, and that interconnection processes are “very difficult and discriminatory.”
“You should do no harm to the mandatory purchase obligation,” Glass advised FERC commissioners.
Jeff Burleson, vice president of system planning for Southern Co., countered that “QF contracts that are based on long-term avoided costs pose a risk to our customers.”
Burleson said resources acquired through requests for proposals can be dispatched — or not — depending on power prices. “We fix the capacity price, so we can dispatch around it,” he said.
QF resources, on the other hand, cannot be curtailed, even when their costs exceed market prices, Burleson said.
Michael Wise, senior vice president with Golden Spread Electric Cooperative, noted that his members operate in both SPP and ERCOT and said those markets are “best positioned” to set avoided cost rates for their utility market participants. He suggested that FERC narrow the purchase obligation to cover projects of just 1 MW or less in order to prevent “unfair advantages.”
At the very least, Wise said, the commission should reduce the terms of PURPA contracts.
“QFs of all sizes have what we believe are unfettered access to these markets,” Wise said.
John Hughes, CEO of the Electricity Consumers Resource Council, said forcing QFs to become experts in RTO market design violates the spirit of PURPA. He also contended that the industry is trending toward the elimination of long-term contracts.
“We already have that in the organized markets and now we’re attempting that in the unorganized,” Hughes said. “This is a very serious situation that we’re going to have to look at.”
Those words, which NYISO CEO Brad Jones uses frequently, are themes echoed throughout the 2016 NYISO Power Trends report.
New York’s Reforming the Energy Vision, the Clean Energy Standard (CES), distributed generation and customer engagement also feature prominently in the report, which was released today.
“The power market is changing as much or more than I’ve seen it in the last 20 years,” Jones told RTO Insider in an interview. “It’s a fantastic place for the NYISO to be in, in the middle of all this dramatic change.
“We wring our hands around here all the time, but I feel very good that we have the capabilities here to meet these challenges,” Jones continued.
Nuclear Power
Part of the hand-wringing concerns the possible loss of much of the nuclear fleet, which is unable to earn sufficient revenues in an energy market dominated by cheap natural gas. New York’s average wholesale electric energy price last year was $44.09/MWh, the lowest in the 15-year history of the state’s competitive markets.
Without a financial lifeline, three nuclear plants in western New York are under threat of closure in early 2017. State regulators are considering a zero-emission credit to subsidize the upstate plants.
The CES requires the state to procure 50% of its energy from renewable resources by 2030. That would require 75,000 GWh of renewable power annually, according to an estimate by the state Public Service Commission. By themselves, that goal would require either 25 GW of solar, 15 GW of wind or 4 GW of hydro, most of that in northern or western New York, far from the load centers in and around New York City.
The city, Long Island and the Lower Hudson Valley use 58% of the state’s electricity. But while more than 80% of the new generation since 2000 has been downstate, the region still produces only 40% of the state’s total, the report notes.
“What this speaks to is the need for more transmission,” Jones said. “Transmission is the key for us to be able to move green power from remote areas to the high-demand areas of the state.”
Flat Load Growth
The increasing shift to renewables will come during a period of flat load growth. “Year-over-year growth in the overall usage of electric energy from New York’s bulk electric system is expected to flatten or decline slightly over the next decade,” the report says.
Other trends highlighted in the report include:
Shifting patterns of electricity demand because of energy efficiency and distributed energy resources: “Distribution-level solar photovoltaics, in 2016, have an estimated summer capability of more than 250 MW. That total is expected to triple by 2026.”
Aging infrastructure requiring replacement and upgrades: “More than 80% of New York’s high-voltage transmission lines went into service before 1980. Of the state’s approximately 11,000 circuit-miles of transmission lines, nearly 4,700 circuit-miles will require replacement within the next 30 years, according to New York’s transmission-owning utilities and power authorities.”
Increasing choices for customers as a result of public policies aimed at reducing emissions and expanding renewable power.
The report concludes with a plea to continue the state’s commitment to competitive markets — a commitment some observers say could be undermined by generation subsidies and long-term contracting for clean power.
The report notes that five of the seven reliability assessments the ISO has conducted since 2005 identified emerging reliability needs. “In each case, markets responded with resources to address those needs, avoiding the need to call upon regulatory solutions,” the report notes.
CARMEL, Ind. — MISO and its Independent Market Monitor have developed a compromise auction design calling for a prompt, single Planning Resource Auction with separate prices for competitive retail areas.
But that isn’t stopping the RTO from also keeping its original forward auction proposal on the table, a proposal Monitor David Patton says is not viable.
“We don’t believe there is one definitive solution forward, but we do believe we have two very good options in front of us,” MISO executive director of market services Jeff Bladen said during a two-day Resource Adequacy Subcommittee meeting Wednesday and Thursday. “We’re deep into the weeds of evaluating both for price stability.”
Bladen said MISO has hired The Brattle Group to conduct an analysis on both proposals and will select a plan based on the results.
The hybrid competitive retail solution marries elements from earlier proposals by the Monitor and MISO. With it, the RTO could abandon its proposed three-year forward auction for deregulated sections of the footprint in favor of the IMM’s multi-stage prompt auction in which only merchant supply could receive competitive retail pricing set by a systemwide sloped demand curve.
Assets controlled by a load-serving entity whose demand is outside a competitive retail zone would be precluded from clearing at the competitive retail price. MISO’s forward proposal would allow non-merchant generators to offer into the separate, retail choice auction.
Two-Stage Auction
The hybrid proposal would deliver the auction in two stages: Immediately after the competitive retail stage of the auction is cleared, the PRA, with traditionally rate-regulated supply and demand, would take place. The PRA would be referred to as the “legacy” stage of the auction and would continue using the current vertical demand curve.
Fixed resource adequacy plans remain the same under the two proposals; LSEs would have to create plans on a forward basis to opt out of serving retail-choice load.
“I think the hybrid prompt proposal would work,” Monitor David Patton said after multiple stakeholders asked for his opinion. “I’m confident the forward proposal would produce more volatility than the hybrid proposal.”
Patton said the hybrid proposal’s sloped demand curve could be adjusted by MISO to correct instances of over- or under-procurement.
Dynegy’s Mark Volpe asked for Patton’s view on both proposals.
Patton said the forward proposal MISO is continuing to consider is not structured to produce an efficient price and does not represent a compromise. “It may not surprise you that I don’t think the forward proposal is not a viable proposal,” he said . …We’re going to be providing some information regarding the price that you get under both proposals at the next meeting,” he said.
Bladen countered that the hybrid approach could produce volatility. He also said MISO’s Tariff would have to undergo extensive revision to implement the hybrid proposal.
“While it has theoretical elegance, the practical application is questionable,” Bladen said. “FERC is the ultimate judge.”
Stakeholders asked if either proposal had been reviewed by FERC staff.
Bladen said although commission staff has been following MISO’s deliberations “FERC would never give advance notice on what they would approve.”
Bladen also said he didn’t have an estimate on when draft Tariff language would be in front of stakeholders, but he did say it would be “very difficult to achieve” implementation in time for the 2017/18 planning year.
“I wish I could give an exact date when we’re going to walk into the room and announce the selected proposal,” he said.
Forward Proposal Still Unfinished
MISO has yet to offer a demand curve shape for its forward proposal for deregulated areas. Bladen said the final shape is “pending further Brattle Group analysis” but the resulting shape would most likely resemble shapes used by other RTOs. MISO has asked Brattle to look at broader, New York-style demand curves that have more megawatt breadth as well as the narrower PJM-style demand curve, he said.
The RTO’s forward proposal also has yet to identify the “hurdles” rate-regulated supply could face when electing to participate in deregulated areas. Bladen said MISO is working with Brattle on restrictions.
“MISO does not want to be a party to any LSE selling itself short,” Bladen explained.
Stakeholders: Give Us the Evidence
Stakeholders sought more evidence that either proposal would work, with several asking MISO to run simulations using the 2016/17 planning year offers.
Indianapolis Power and Light’s Ted Leffler asked if simulations have been run at all.
“We’re working on it. The short answer is it’s complicated,” Bladen said. He said both MISO and the IMM would come back with simulations and concrete examples, but their results could differ.
Bladen also said there has been “a high lack of understanding [among stakeholders] on how these proposals would work.”
Susan Satter, public utilities counsel for the Illinois attorney general’s office, asked at what point regulated suppliers would supply load in Zone 4 using a hybrid model. Bladen responded that regulated suppliers would influence the competitive retail price by contributing to the systemwide demand curve. He added the systemwide demand curve is needed so deregulated areas contribute to footprint-wide resource adequacy.
“In a sense, [rate-regulated load-serving entities] are providing a moderating service on the competitive retail price,” Bladen said. “While they’re not being explicitly committed to serving load, they’re implicitly moderating the price … versus if there was only merchant generator participation.”
Stakeholders asked if MISO’s forward proposal would guarantee lower prices.
“I’m hesitant to say anything in life is a guarantee,” Bladen responded. But he added that the forward proposal’s price mechanism should produce lower prices. “We think the proposal has legs.”
Initial stakeholder feedback on the hybrid and forward proposals is due July 7.
An additional special meeting of the RASC will take place July 14, at which stakeholders are again expected to discuss the hybrid proposal. Bladen promised Brattle representatives would be on hand to explain their analysis of both proposals and answer questions.
“One of these proposals will fall by the wayside, unless they’re miraculously merged, which I don’t think will happen,” said RASC Chair Gary Mathis.
MISO Contemplates Outages in Seasonal Capacity Accreditation
Stakeholders have said some planned outages during peak hours are appropriate under certain circumstances: when a unit is undergoing a one-time upgrade, when a unit hasn’t cleared the capacity auction or when weather is mild.
Currently, MISO’s planning reserve margin does not make room for any planned or maintenance outages during peak times. Rauch said the RTO is weighing increasing the reserve margin or reducing individual units’ capacity accreditations to reflect the risk of outages during peak hours.
“We’re still trying to get the point where we identify and clear what’s needed under a two-season construct,” said Rauch.
MISO’s locational filing, which would create external resource zones, is still being examined.
“One of the things stakeholders requested is more transparency and more clarity on how local resource zones would be run in the auction,” Rauch said. “Our homework is to come back with some better examples.”
Further discussion on MISO’s seasonal and external zone constructs is expected at the August RASC meeting. Rauch said an updated design document on the constructs will be released in September.
Hydro-Quebec and Public Service Company of New Hampshire (PSNH) filed a 20-year power purchase agreement with New Hampshire regulators on Tuesday that promises to deliver at least 100 MW of energy during peak hours over the Northern Pass transmission line (DE 16-693).
PSNH parent Eversource Energy hopes to build the line to deliver Canadian hydropower into the ISO-NE market to reduce power price volatility and promote fuel diversity.
The company has cited the PPA as one of the benefits of the Northern Pass, along with economic development and clean energy. The Tuesday filing begins the formal review process before the New Hampshire Public Utilities Commission, which must determine whether the PPA is in the public interest.
The 192-mile project from the Canadian border to Deerfield would have a capacity of 1,090 MW. Officials said New Hampshire consumes about 9% of the electricity used in ISO-NE, so a proportionate share of its capacity is targeted to the state’s customers.
Eversource Energy plans to lay much of the Northern Pass transmission line underground using the open cut trench method shown above. Source: Northern Pass
“This agreement is great news for New Hampshire electricity customers who have been struggling to pay some of the highest rates in the country,” Bill Quinlan, president of Eversource New Hampshire Operations, said in a statement.
Eversource says the PPA will save customers $1 billion over the first 10 years.
“The $1 billion in savings includes the $800 million in savings over a 10-year period as a result of market price suppression brought about by Northern Pass being in the regional market,” spokesman Martin Murray told RTO Insider. “In addition to that savings, the 20-year PPA will provide additional cost savings, and New Hampshire ownership of all the environmental [renewable energy credits] associated with the 100 MW of hydropower.”
Eversource said the PPA will provide its New Hampshire utility with 400,000 MWh of energy per year, Monday through Friday from 7 a.m. to 11 p.m.
Prices are redacted from the contract for competitive reasons, although the document says prices are “based on the MA Hub NYMEX forwards adjusted for delivery to the delivery point.”
Eversource said that New Hampshire retains “most favored nation” rights under the agreement. If Hydro-Quebec negotiates a PPA with another party over the first 10 years for at least 100 MW at more favorable terms, PSNH could demand similar prices.
Three New England states — Connecticut, Massachusetts and Rhode Island — have solicited clean energy proposals from regional suppliers for long-term contracts. Northern Pass is one of more than 30 respondents that are undergoing review, which is expected to be completed in about a month. (See New England States Combine on Clean Energy Procurement.)
Northern Pass has proposed to deliver energy to the three states in the second quarter of 2019, which could be ambitious given the several hurdles it has to overcome. It previously said construction would take two years once all permits were obtained.
The project has been opposed for its visual impacts on tourist-dependent northern New Hampshire, which has led to longer-than-expected reviews. Northern Pass is now before the state’s Site Evaluation Committee. It is also facing a legal challenge from conservationists. (See Northern Pass Challenge Headed to NH Supreme Court.)
CAISO’s regulation costs have quadrupled since the ISO increased requirements to help balance variable output from renewable resources.
Daily payments to regulation service providers jumped from about $100,000 to more than $400,000 after CAISO increased the requirements in late February, according to a report from the ISO’s Department of Market Monitoring.
Regulation prices more than doubled as the ISO increased its daily procurement to as much as 800 MW from 400 MW or less.
The department discounted the likelihood that market manipulation was behind the increase. “We did look at bid behavior and didn’t see it [had] changed,” Gabe Murtaugh, a department senior analyst, said during a call to discuss the report. “We don’t see any evidence of market collusion or anticompetitive behavior.”
CAISO implemented the change Feb. 20, increasing regulation requirements in both the day-ahead and real-time markets to 600 MW. Prior to that, day-ahead requirements were set in the 300-400 MW range, while real-time requirements were consistently pegged at 300 MW.
The Monitor said the ISO procured an average of 617 MW of regulation up and 619 MW of regulation down in the day-ahead market between Feb. 20 and March 31. Procurements reached as high as 800 MW on days when forecasts predicted high variability from renewables.
During that period, day-ahead prices for regulation up and down averaged $14.81/MWh and $12.92/MWh, respectively, compared with $6.50 (up) and $4.16 (down) before the change was implemented. Real-time gained in similar proportion, with regulation up averaging $17.18 and regulation down averaging $21.34.
Regulation prices more than doubled (top) after CAISO increased regulation requirements in late February. The increased prices and volumes procured quadrupled the ISO’s average daily regulation cost to $400,000 (bottom).
Regulation up and down are two of the four ancillary services products the ISO procures through “co-optimization” with the energy market, meaning that resources can bid into both markets simultaneously. Most regulation capacity is acquired in the day-ahead market, with the real-time market run used to cover additional needs or replace unavailable resources.
In addition to receiving a capacity payment, resources that provide regulation service are also eligible for a performance — or mileage — award for in the event they are dispatched. Payments for mileage have historically represented just a fraction of those for capacity.
California Energy Commission analyst Christopher McLean questioned the rationale behind the volume of regulation service the ISO is acquiring.
“Is all that’s being procured being utilized?” McLean asked. “Did it offset any [spinning reserve] procurement?”
Keith Collins, ISO manager of monitoring and reporting, responded that expanded regulation reserves did not reduce the acquisition of spinning reserves — nor could he provide estimates for utilization.
“That’s not something we reported, but we can look into that,” Collins said.
McLean pressed his point, asking if the ISO was using “any sort of formula” to set the regulation requirement, something the Monitor could not confirm.
“So you’re saying there is not any formula,” McLean said. “We’ll be interested in any justification for the change in the procurement level.”
CAISO’s Board of Governors on Tuesday appointed five members to serve on the newly established governing body of the western Energy Imbalance Market.
Candidates were selected after being vetted by a nominating committee representing five industry sectors, including EIM entities, ISO participating transmission owners, power suppliers and marketers, publicly owned utilities and state regulators.
“It was a consensus-driven process,” said CAISO board member Angelina Galiteva, a nonvoting committee member. “It was a successful outcome and can serve as a basis for a larger expansion” of the ISO itself.
PacifiCorp Transmission Vice President and General Counsel Sarah Edmonds, who headed the committee, said the new governing body demonstrated the “diversity of expertise” and independence necessary to oversee the EIM. She also noted its regional diversity.
“In terms of geography, we have the Pacific Northwest, California [and] the desert Southwest” represented on the body, Edmonds said.
Left to Right: Valerie Fong, Doug Howe, Carl Linvill, John Prescott, Kristine Schmidt
The members of the EIM’s new governing body are:
Valerie Fong — Recently retired after serving as the director of utilities for Palo Alto, Calif., from 2006 to 2015. Fong previously had a 20-year career at Pacific Gas and Electric and served on the boards of the Power Association of Northern California, Transmission Agency of Northern California, and the Northern California Power Agency.
Doug Howe — A Ph.D. in mathematics who has authored or co-authored more than 30 papers and presentations covering industry subjects such as energy efficiency in the European Union and utility regulation in the U.K. Howe previously served as a New Mexico state regulator and executive with GPU Inc., which was acquired by FirstEnergy in 2001.
Carl Linvill — Principal at the Vermont-based Regulatory Assistance Project, which produces white papers on energy and environmental issues. Linvill previously served as a utilities commissioner in Nevada and still acts as technical adviser for the Western Interstate Energy Board.
John Prescott — Retired earlier this year after 10 years as CEO of the Portland-based Pacific Northwest Generating Cooperative, a member-owned policy advocate for utility cooperatives in seven Western states. Prescott previously worked at Idaho Power and Seattle City Light and served on the Pacific Northwest Utility Conference Committee and the National Rural Electric Cooperative Association’s Regulatory Standing Committee.
Kristine Schmidt – President of Dallas-based Swan Consulting, which provides advisory services to businesses entering or expanding in the electricity and natural gas sectors. Schmidt was previously a vice president at ITC Holdings and director at Xcel Energy. She also worked as a commissioner adviser at FERC.
Members are appointed for three-year terms, but because this was the first governing body, the ISO board established staggered terms by randomly selecting names. Fong and Prescott will serve until June 30, 2019, Howe and Linvill until June 30, 2018, and Schmidt until June 30, 2017. In the future, all nominations will be subject to approval by the governing body.
DETROIT — MISO’s 2016 spending is in line with its budget for the year, Vice President of Finance Jo Biggers told the Board of Directors at the RTO’s Annual Meeting last week. Year-to-date expenses are $93.3 million, $300,000 under budget. The RTO was able to save about $700,000 with the renegotiated lease of its Carmel, Ind., building, among other factors, but spent an extra $400,000 on resource adequacy efforts, including capacity auction redesign and seasonal and locational constructs.
The RTO was allotted a $225 million operating budget in 2016. It currently expects to spend between $224.7 million and $225.5 million by the end of the year.
Biggers said that although MISO is $4.1 million under budget on capital expenses to date, it expects to spend most or all of the $31 million capital budget by year-end.
Board member Phyllis Currie said the board’s Audit and Finance Committee is considering whether the RTO should file for 501(c)(3) status. MISO is currently categorized as a 501(c)(4), a social welfare organization; 501(c)(3) status would designate it a charitable organization.
Weber Source: IURC
“Over time, we’ll look at the pros and cons. It’s a good time to take a look at this,” Currie said. MISO could benefit from tax-exempt status, especially when considering the amounts it may need to borrow over the next five years, she said.
Stakeholders Join Nominating Committee
Indiana Utility Regulatory Commissioner Angela Weber and Matt Brown, vice president of federal policy at Entergy Services, have joined MISO’s Nominating Committee, filling the two stakeholder vacancies, board member Michael Curran reported.
A retired elementary school teacher goes to Washington to take on a powerful utility — and wins a $4.2 million refund.
A David and Goliath story?
“It certainly felt that way,” says Martha Peine (pronounced “piney”), a former lawyer who hadn’t practiced since 2002. “I was dealing with rules and regulations and procedures I had never been familiar with. It was just me … funding my own way against what I consider a behemoth organization, with outside and inside counsel with many years of experience.”
The “behemoth” in question is American Electric Power, owner of the nation’s largest transmission system, with a market capitalization of more than $32 billion and more than 5 million customers in 11 states.
Peine received her law degree from the University of Texas and spent seven years as a sole practitioner specializing in “consumer-type” issues, before taking down her shingle in 2002. She spent the next nine years as an elementary school teacher and lecturer for the Houston Independent School District.
Ozark Mountain Tx Fight
Several years ago, Peine found herself involved in a community effort to fight AEP subsidiary Southwestern Electric Power Co.’s plans to build a transmission line through the scenic Ozark Mountains in Northwest Arkansas. A grassroots organization, Save the Ozarks, spun up enough community support around the eccentric town of Eureka Springs, a haven for artists and retired hippies, that SWEPCO withdrew its plans in December 2014.
By then, Peine was submerged in AEP’s filings at FERC, trying to make sense of transmission formula rates, protocols and operating tariffs. Poring over the company’s annual updated filings to its formula rate under SPP’s Tariff, she uncovered and contested almost $2.5 million in improperly recovered transmission costs for charitable contributions, general advertising, economic development, lobbying, and generation and distribution regulatory cases.
Peine
So what kept Peine going in what must have appeared early on to be a quixotic quest?
“Just determination. Pure determination,” she said. “I wasn’t going to give up until someone said, ‘Go home and don’t you ever come back here again.’ I just kept putting one foot in front of the other.”
Using her forensic skills and invoices provided by AEP, Peine was able to determine whether the company’s expenses were properly accounted for under FERC regulations. She contested air travel for SWEPCO President Venita McCellon-Allen to attend legislative meetings and a luncheon honoring former Arkansas Public Service Commissioner Colette Honorable before her appointment to FERC. She also contested a tree-planting program around SWEPCO’s Turk power plant in southwest Arkansas.
‘Drilling Down’
“Drilling down to the actual invoice is something that rarely happens,” Peine said, making sure she put quotes around “reviewed” when describing her understanding of how regulators and wholesale purchasers may check the annual updates. “They look at the delta from one year to the next and ask generally about it.”
A FERC staff review after her complaint found additional improper charges in SWEPCO sister company Public Service Company of Oklahoma’s AEP’s rate structure.
On June 13, Peine and AEP reached a $4.2 million settlement agreement.
The money will be distributed as a one-time credit to utilities using AEP’s SWEPCO and PSO transmission systems (ER07-1069). “I think it was a good result, a substantial refund, and I’m happy with that,” Peine said. “I followed through, I stayed committed … I think this was a right result for ratepayers.”
Pat Costner, director of Save the Ozarks, said in a press release, “Every SWEPCO electric customer owes a debt of gratitude to this remarkable woman, who has shown us that one person can make a big difference.”
It didn’t come easy, but pro se interventions — in which intervenors represent themselves — never are. Peine said she used a template provided by Keryn Newman and Alison Haverty, who successfully challenged AEP and Allegheny Energy (now FirstEnergy) in their bid to recover $121.5 million from an abandoned PJM project. (See FERC ALJ Rejects $10 Million in PATH Transmission Project Recovery.)
“That made my job much easier,” said Peine, who followed the case closely and attended several days of FERC hearings on the matter.
Peine’s interest was piqued during her work with Save the Ozarks. She asked herself, “What’s in it monetarily for these people? How do they recover costs? What’s the motivation there?”
She spent hundreds of hours on her challenges. She familiarized herself with the protocols and SPP’s Tariff. She learned how to file preliminary and formal challenges. And she researched FERC’s eLibrary database from the comfort of her home. “Everything is filed,” Peine marveled.
Proving Standing
Before filing her challenges, Peine had to first gain standing. She said AEP “quibbled” at first: Peine and her husband have a summer home in Eureka Springs, where they will eventually move to from Houston. It took a copy of Peine’s electric bill to prove she had standing.
Peine had to prove her standing again once the commission set her challenges for hearing. Administrative Law Judge Carmen Cintron recommended the commission find that ratepayers don’t have standing under the Federal Power Act. But FERC staff, the Electricity Consumers Resource Council and others strongly objected to Cintron’s interpretation, and the commission reconfirmed Peine’s standing.
She said she became aware in August 2013 of AEP’s formula rate updates to the SPP Tariff, which it files on behalf of SWEPCO and PSO each May. Peine said she asked AEP for electronic submission of the underlying documents in the filing but was told to come up to the company’s headquarters in Columbus, Ohio, to look at them.
“If you’re having a dispute like that, you can request a FERC administrative law judge to act as a discovery master,” Peine said. “Things were resolved that way. Certain documentation I never got, but we moved forward anyway.”
When Peine’s preliminary challenge was not resolved, she filed a formal challenge in January 2014. She followed the same process in challenging AEP’s May 2014 update to the formula rate.
Peine disputed the recovery of $92,511 in costs for 2013 and $2,467,024 for 2014 in her formal challenges, which were set for settlement proceedings in August 2015. The two sides exchanged and rejected offers and went through two ALJs before reaching a final agreement.
“The settlement will completely resolve all issues in the current proceeding,” said SWEPCO spokesperson Carey Sullivan, noting the agreement has yet to be approved by FERC. “The parties agree that the settlement is fair, reasonable and in the public interest.”
The settlement makes it clear that “directly assignable” AEP’s charges recovered under its formula rate after July 1 “shall mean expenses directly related to the provision of transmission services, and does not include those general, company-wide expenses that may be allocated partially to transmission.”
The parties said the settlement addresses issues “both retrospectively and prospectively,” through the ratepayer refund and by “explicitly excluding certain expenditures from recovery under the AEP formula rate.”
But while the settlement is signed, Peine says the proper recovery of rate expenses going forward is “not a resolved issue.”
“I will always wonder what mistakes there may be in the years to come,” she said. “Some [SWEPCO employees] wear so many hats and have multiple functions — public relations, lobbying and outreach to officials — it’s difficult to separate out what’s recoverable and what isn’t in a situation like that.”
Maryland Gov. Larry Hogan and Delaware Gov. Jack Markell stepped up their complaints that the cost allocation for New Jersey’s Artificial Island nuclear project disproportionately affects customers in their states.
The State Lands Commission has given Pacific Gas and Electric permission to lease the site of the Diablo Canyon nuclear plant through 2025 without an environmental review.
Two weeks after the Public Service Commission denied a final challenge to Exelon’s $6.8 billion acquisition of it, Pepco has asked for a 5.25% rate increase for its 282,000 customers in the district. (See 
Indianapolis Power & Light has filed for a rate hike to pay for the installation of $100 million in emissions-control technology at its coal-fired Petersburg Generating Station.
A plan to install a pilot tidal energy project in the Cape Cod Canal is gaining momentum with a collection of grants, including funding from the state Seaport Economic Council.
A $24 million, 13-MW solar project at Michigan State University will go forward after the East Lansing City Council approved an 80% tax abatement for 10 years, 15 years fewer than the developer was seeking.
The state’s Agency for Energy has released a new report, “
IDT Energy customers will receive $2.4 million in rebates under a settlement approved last week by the Public Utility Commission regarding electricity overcharges during the 2014 polar vortex.
