The Federal Energy Regulatory Commission has for the third time refused to take up a Rhode Island citizen’s allegations that an offshore wind power contract is illegal (EL15-61).
Simulated view of Deepwater Wind project on horizon off of Block Island, R.I.
FERC declined without comment to refer the contract between Deepwater Wind and National Grid to its Office of Enforcement.
Benjamin Riggs Jr. claimed the 20-year power purchase agreement violated the Federal Power Act and the Supremacy Clause of the U.S. Constitution. He sought an enforcement action against the Rhode Island Public Utilities Commission under the Public Utility Regulatory Policies Act for violating the “commercially reasonable” provisions of that law.
Deepwater is constructing a 30-MW offshore wind farm near Block Island. The company and National Grid signed a contract that cost $500 million more than the avoided costs of conventional generation over the project’s life, which regulators approved in 2010. The commission had initially rejected an agreement, but the companies amended the contract after the state passed legislation to promote the wind farm as a clean energy resource and as an economic development project.
The final permit, from the U.S. Army Corps of Engineers, was issued last year and the project is now under construction. It would be the first offshore wind farm in the U.S.
Wider simulated view of Block Island.
National Grid argued that Riggs did not have standing to bring the action before FERC under the various statutes that he cited.
Riggs had filed complaints in 2011 and 2012 with the same allegations that also failed (EL12-16, EL12-100). He tried again in April because he said a recent Supreme Court decision, which he did not name, “suggests that any possible administrative remedy should be explored before resorting to the courts.”
The courts appear to be his only option.
“Our decision not to initiate an enforcement action means that Mr. Riggs may himself bring an enforcement action against the Rhode Island commission in the appropriate court,” FERC wrote.
The Rhode Island Supreme Court rejected a ratepayer challenge in 2012.
MILWAUKEE — Gas producers are “listening loud and clear” to environmental concerns about fracking, James Tramuto, vice president of governmental and regulatory strategies for Southwestern Energy, said at the MISO Annual Meeting last week.
Tramuto
Southwestern Energy, the fourth-largest natural gas producer in the U.S., has committed to becoming a net-zero user of fresh water in its operations by the end of the year. “We’ll get there through conservation,” Tramuto said during a panel discussion. The company currently claims to use rainwater collected in ponds and water recycled from its operations for 83% of its water use, with 17% from streams.
Southwestern is one of eight gas companies in the ONE Future Coalition, a voluntary effort whose members have pledged to reduce methane emissions from leaks or loss to 1% across the supply chain.
While gas is expected to increasingly displace coal-fired generation, and the industry has plentiful supplies, producers must address the “hot-button issues” of pollution and local moratoriums if it is to continue its growth, Tramuto said.
The Sierra Club, which won $80 million in donations from billionaire Michael Bloomberg for its “Beyond Coal” campaign — with a goal of retiring half of U.S. coal plants by 2017 — is also running a “Beyond Natural Gas” program, albeit without Bloomberg’s support.
Anti-gas protests have become a regular feature at open meetings of the Federal Energy Regulatory Commission.
“I would not discount the chance that gas may become the next ‘evil,’” said CAISO CEO Stephen Berberich, who also spoke on the panel.
Gas, Electric Schedules
Tramuto also commented on FERC’s efforts to better align the market schedules of the gas and electric industries. In April, the commission approved a rule adopting two gas scheduling changes but declined to move the start of the gas day to 4 a.m. CT from 9 a.m. CT. (See FERC Approves Final Rule on Gas-Electric Coordination.)
At the beginning of the scheduling discussions, Tramuto said, “people weren’t talking to one another, they were talking past one another and not really understanding the other side and what their needs were versus what our capabilities are.”
He added, “It’s the first time I’ve seen in a long time that the gas community collectively — that was the producers side, the pipelines, the whole group — all spoke with one voice on not changing that 9 a.m. start time.”
The Federal Energy Regulatory Commission last week proposed revisions to several sets of reliability standards:
In a Notice of Proposed Rulemaking (NOPR) on transmission operations (TOP) and interconnection reliability operations and coordination (IRO) standards, the commission outlined language it said would clarify standards for transmission operators and reliability coordinators, combining the eight current TOP standards into three. The commission said that the North American Electric Reliability Corp. had addressed concerns it raised in November 2013 about outage coordination and the treatment of system operating limits and interconnection reliability operating limits (IROLs) (RM15-16).
A second NOPR is designed to streamline and clarify requirements of emergency preparedness and operations (EOP) and protection and control (PRC) reliability standards. It would revise the definition of a remedial action scheme (RM15-7, RM15-13, RM15-12).
Comments on the proposed rules are due 60 days after publication in the Federal Register.
The Federal Energy Regulatory Commission last week rejected a rehearing request on its approval of Commonwealth Edison’s wholesale distribution charge on an energy storage facility (ER15-3).
Energy Vault’s solar-powered electric vehicle charging station on Northerly Island in Chicago.
In its request, the Energy Storage Association contested ComEd’s classification of Energy Vault — a Chicago-based company whose energy storage facility is connected to ComEd’s distribution system and participates in PJM’s ancillary services markets — as a load-serving entity. The association argued that because the commission has previously classified energy storage resources as generators, the charge should not apply, as ComEd has exempted generators from such charges.
“By defining an [energy storage resource] as a market seller it was PJM’s and FERC’s clear intention to ensure battery facilities, such as Energy Vault, would be treated similar to other market sellers, such as generators and pumped storage facilities, rather than as a market buyer or load, which ComEd proposes to do here,” ESA said.
Energy Vault echoed these arguments in its protest to FERC’s November 2014 approval of the charge, which costs the company $3,449 annually.
FERC disagreed, saying that energy storage could be classified as generation, transmission or distribution, depending on the circumstances. In this case, Energy Vault’s battery “spends a substantial share of its operating life being charged by withdrawing energy from the distribution system,” the commission said. “Generation does not.”
“Notwithstanding the label applied to Energy Vault, be it deemed a wholesale customer serving load, generation, market seller or some combination, it is indisputable that Energy Vault seeks to use the ComEd distribution system to both inject into and withdraw power from its batteries,” FERC said. “The Nov. 28, 2014, order was not based on any particular label or classification for Energy Vault, but upon the fact that Energy Vault is using ComEd’s distribution system to withdraw energy for battery charging and therefore should contribute to its costs.”
ComEd exempted generators from wholesale distribution charges in 2009. The company found that reverse flows from renewable generation potentially benefit its system by reducing congestion.
“While a storage device discharging to the distribution system should also provide beneficial counterflow, a storage device differs from generation in that it must spend a substantial amount of time charging,” FERC said. “During charging, it will add to the flow and load on the distribution system just like any other load and, crucially, unlike a generator.”
FERC said that while it does treat energy storage as generation for specific purposes, that does not preclude a transmission owner from recovering the costs of its system through distribution charges.
Energy Vault’s storage facility, E-Vault, is a 100-kW prototype battery system that stores and provides power for the company’s Solar Plugs, solar-powered EV charging stations, including one on Northerly Island in Chicago.
MILWAUKEE — MISO’s Board of Directors will generally be limited to three three-year terms, while the board chairman will be allowed to hold the gavel for a maximum of five years, under rule changes approved amid much gnashing of teeth last week.
The three-term limit comes with a caveat: Directors may petition for a waiver allowing a single additional term upon the determinations by the board and the Corporate Governance & Strategic Planning Committee “that a director’s continued service is necessary to retain his or her skills or expertise, to maintain geographic or other diversity of the board, or is otherwise in the best interest of” MISO.
The board rejected setting an age limit, accepting the Corporate Governance Committee’s position that “directors should be evaluated on their knowledge, skills and engagement, rather than an arbitrary limitation based on age.”
The five-year maximum for the chairman is up from the current two-year limit. That would allow Walsh, who was elected to a second one-year term for 2016, a longer tenure.
The board tabled action on a proposal to expand the Nominating Committee — currently three directors and two stakeholders — to add more stakeholder representatives. It will consider the expansion again in October, when they said they would have the benefit of the stakeholder governance discussions. (See related story, MISO Straw Man: Eliminate 10 of 27 Committees.)
The term limits vote was unanimous, although Director Mike Evans expressed misgivings, saying the board was getting sufficient turnover without the rule. “At some time in the future I’m going to say, ‘Why in the blazes did we do that?’” he said.
Director Paul Feldman objected to the fourth-term waiver, saying it was inconsistent with term limits and could create a “nasty dynamic” among board members. “Everyone is replaceable,” he said.
Director Thomas Rainwater said he supported the term limit, citing research suggesting directors are no longer independent after about 11 years.
But Director Mike Curran joined Evans in expressing unease, recalling a discussion with Howard Schneider, who has chaired PJM’s Board of Managers since its formation as an independent panel in 1997. “‘Why are you guys doing this to yourself?’” Curran said Schneider asked him after hearing that MISO was considering limits.
“A four-[term] limit would clear the decks at PJM,” joked Feldman.
The PJM board’s action was announced at the RTO’s Annual Meeting in Atlantic City, N.J., without any explanation — let alone the public debate that the MISO board engaged in before voting. Unlike MISO, PJM’s board does not meet in public.
Five small, rural utilities — hailing from places like Yazoo City, Miss. (population: 11,000) — have won the right to continue their fight against 24 of MISO’s large transmission-owning members, whom the utilities contend are earning too much.
The Federal Energy Regulatory Commission on Thursday set the utilities’ complaint for a hearing under section 206 of the Federal Power Act (EL15-45).
Commissioners said they would leave to the discretion of the Chief Administrative Law Judge whether it would be appropriate to consolidate the case with a similar complaint MISO industrial customers filed against MISO TOs that is set for an August hearing (EL14-12). (See ROE Talks Between MISO Industrials, TOs Collapse.)
This latest case was filed last February by Arkansas Electric Cooperative Corp., Mississippi Delta Energy Agency, the Clarksdale Public Utilities Commission, the Public Service Commission of Yazoo City and Hoosier Energy Rural Electric Cooperative.
The five argue that the TOs’ base return on equity (12.38%, except American Transmission Co. with an ROE of 12.2%) should be no higher than 8.67%. The complainants cited a recent Court of Appeals ruling that found that a complainant need only demonstrate that the existing rate is unjust and unreasonable and do not have to prove the reasonableness of a suggested replacement rate.
TOs Not Persuasive
The MISO TOs argued that the consultant for the five utilities used flawed data and failed to consider other relevant capital models.
But FERC in its June 18 decision said the complainants had used appropriate data and conducted the proper cash flow analysis in making their case.
The commission also rejected the TOs’ request that it dismiss the complaint because their base ROEs fall within the commission’s “zone of reasonableness.”
“The commission has previously rejected the contention that every ROE within the zone of reasonableness is necessarily just and reasonable, and we do so again here.”
Among other MISO TOs whom the five utilities have challenged in their ROE complaint are ALLETE, Entergy, ITC Midwest and Northern States Power.
New Methodology
FERC last year changed the way it sets rates for electric utilities, switching to a two-step discounted cash-flow methodology similar to what it uses for natural gas and oil pipelines.
A number of stakeholders have argued that the current financial market allows transmission companies to use more leverage while still maintaining an investment-grade bond rating.
MISO industrials argued that the capital structures of certain MISO TOs have unreasonably high levels of common equity and should be capped at 50% common equity. Last October, FERC rejected the industrials’ capital structure argument but granted a hearing on the base ROE.
New York won’t need to build too many new power plants for a while.
Demand served by the grid will remain essentially flat over the next decade, staying at about 160,000 GWh annually, according a new report by NYISO.
“Power Trends 2015” says energy efficiency and distributed energy resources will cut peak demand growth on New York’s bulk power system by more than 2,700 MW in 2025 (up from less than 500 MW now), while reducing annual energy usage by more than 14,000 GWh (from about 2,000 GWh). Based on current projections, about 8% of the projected demand of 174,000 GWh will be satisfied by efficiency and DER.
“Changing energy technologies have altered the conventional assumptions about economies of scale. Development of diverse smaller scale power supplies, including solar photovoltaics (PV) that are increasingly affordable to customers, have further challenged traditional models of centralized generation,” the report said.
“We can’t take a ‘one-size-fits-all’ approach to shaping the grid of the future. We need to bolster the strength and stability of the centralized grid while we foster the flexibility and resilience offered by distributed energy resources,” NYISO CEO Stephen G. Whitley said.
Distributed generation — solar PV and other behind-the-meter systems — is central to the Reforming the Energy Vision proceeding before the New York Public Service Commission that will transform the state’s energy landscape. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)
The report said that since the New York wholesale market started more than 15 years ago, more than 11,600 MW in new generation has been added, with more than 80% of that in the Hudson Valley, New York City and Long Island.
As a result, after years of shrinking, the state’s power surplus — capacity in excess of the state’s reliability requirements — grew to 2,300 MW in 2015, up from 1,900 MW last year. Demand response programs continue at about 1,100 MW.
NYISO credits the creation of a new capacity zone in the Lower Hudson Valley as incenting about 1,000 MW of generation resources returning to the market. (See New Yorkers Upset over NYISO Capacity Zone.)
“Capacity costs in New York are expected to be approximately $400 million lower in the coming year due to the increase in supply driven by the creation of the new zone,” the report said.
Natural gas price spikes during the winter of 2014 pushed average wholesale electric energy prices to $69.30/MWh last year, up from $59.13 in 2013.
PBF Energy, owner of refineries in Delaware, New Jersey and Ohio, is acquiring its first refinery on the Gulf Coast.
The company will pay $322 million for the 189,000-barrel-per-day Chalmette refinery near New Orleans. It purchased the refinery from Exxon Mobil and Petroleos de Venezuela S.A., the Venezuelan state-owned oil company.
PBF owns refineries in Delaware City, Del., Paulsboro, N.J., and Toledo, Ohio. It is involved in contentious negotiations with Delaware regulators over its permit to use Delaware River water for cooling operations at the Delaware City refinery.
SolarCity to Invest $200 Million in Solar Gardens in Minnesota
The country’s largest solar panel installer, SolarCity, will spend $200 million building 100 community solar gardens in Minnesota, offering their power to apartment dwellers, a segment of the population that has been left out of the rooftop solar market. SolarCity will team up with Sunrise Energy Ventures, which will market the output.
SolarCity is taking advantage of a 2013 law that authorized community-led solar projects for Xcel Energy’s 1.2 million customers. Other companies have gotten into the game in Minnesota, including SunEdison and SoCore Energy, but they have mainly focused on signing up corporate and institutional customers.
Developers are hoping to cash in on a 30% federal solar investment tax credit that expires in 2016. SolarCity’s plan is to build 100 MW of solar facilities in clusters of sites. Xcel is balking at this, saying that the law prohibits any facility from being more than 1 MW.
Murray Energy last week announced it had recalled 262 workers who had been laid off in March at its Monongalia County Coal subsidiary near Blacksville, W.Va.
CEO Robert Murray said the coal industry is still in “severe economic hardship” and said most of the blame for that can be laid at the doorstep of the Obama administration’s policies and a trend to switch from coal to natural gas by large generating companies.
FirstEnergy Moves to Keep Bruce Mansfield Plant Open
FirstEnergy is moving forward with a project to build a dewatering station for coal ash slurry produced at its Bruce Mansfield plant in Beaver County, Pa., in order to keep the massive coal-fired plant open.
The company is facing a Dec. 31, 2016, deadline to close its coal-ash slurry impoundment at the three-unit 2,714-MW plant. If the plant is to remain in operation, it needs to dewater the coal ash before it is disposed. FirstEnergy said it had been waiting for the PJM Base Residual Auction to see if there was a market for the plant’s future output, but the auction was delayed until August. Bruce Mansfield failed to clear the past two auctions.
FirstEnergy said it had to make a decision on the dewatering system now in order for it to be completed ahead of the deadline.
FirstEnergy Teams with 2 Companies to Re-open Manufacturing Plant
FirstEnergy and two nuclear waste storage companies are teaming up to re-open a Canonsburg, Pa., manufacturing facility that GE-Hitachi vacated last year.
FirstEnergy spent $1.3 million to upgrade the facility, which will serve as the base for maintenance and repair personnel serving the company’s nuclear and coal-fired generating units in the region. The workers will share the plant with the company’s new partners, Custom Nuclear Fabrication and Areva, who will use it to manufacture containers used to store spent nuclear fuel.
Dominion Applies for Rezoning for Controversial Tx Line
Dominion Virginia Power last week filed for a rezoning permit from James City County to construct a switching station as part of a controversial transmission line that crosses the James River. The county and other parties took Dominion to the state Supreme Court to establish that the county had permitting authority over the utility’s project.
Dominion argued unsuccessfully in the courts that the State Corporation Commission, and not the county, should have authority over siting decisions. It says the line is necessary for system reliability. The county and other parties have argued that the line will destroy scenic views along the river.
The county commission will consider the application and then host a public hearing on it before issuing any final decision. A hearing is scheduled for Aug. 5.
Sierra Club to Sue NJ’s DEP over PSEG’s Mercer Station
The Sierra Club says it will sue the New Jersey Department of Environmental Protection for allowing PSEG Fossil’s Mercer Generating Station to operate on expired permits and with an outdated cooling water system.
“For far too long, the DEP has allowed the Mercer Generating Station to pollute the river and kill more than 70 million fish and fish larvae per year,” said Jeff Tittel, Sierra Club’s state director. Doug O’Malley, director of Environment New Jersey, called on the company to upgrade its cooling system or shut down the plant. “If PSEG is unwilling to install modern cooling towers to stop this ecological damage, they should shut down this fossil fuel dinosaur,” he said.
PSEG wouldn’t comment on the pending litigation but said it has spent millions of dollars to reduce the plant’s impact on aquatic life. It said it is in the process of evaluating federal Clean Water Act regulations and will submit a renewed application.
Atlantic City Electric Working with NJ County on Lighting Project
Atlantic City Electric is replacing 900 street lights with light-emitting diode (LED) lamps to save Camden County, N.J., about $100,000/year in lighting costs. The LEDs are expected to last about 20 years, compared to five years for the existing high-pressure sodium lamps.
The U.S Department of Housing and Urban Development provided $800,000 for the project.
MISO should eliminate the right of transmission owners to dictate how interconnection customers pay for network upgrades, the Federal Energy Regulatory Commission ruled last week.
The commission instituted a section 206 proceeding, saying MISO must either change its pro forma generator interconnection agreement (GIA) or explain why it shouldn’t (ER14-2464-002, et al.).
FERC said article 11.3 of MISO’s pro forma GIA appears unjust and unreasonable because it allows transmission owners to fund upgrades in a way that forces interconnection customers to pay them for costs other than the return of and on the capital costs.
The commission suggested MISO amend the GIA and related agreements to state that transmission owners may only choose to provide the initial funding for network upgrades if the interconnection customer agrees. Otherwise, the facilities would be solely funded by the customer.
If the customer agrees to the transmission owner providing the initial funding, FERC said, MISO’s rules must result in calculation of a revenue requirement that is just and reasonable, the commission said.
The ruling came in response to a request by Otter Tail Power that MISO be forced to extend the unilateral initial funding election in MISO’s pro forma GIA to its pro forma facilities construction agreement. Otter Tail sought the change regarding the 150-MW Border Winds wind farm in North Dakota.
Expanded retail-level demand response programs will take effect as soon as July 1 in targeted areas of upstate New York under measures approved by the New York Public Service Commission on Wednesday (14-E-0423).
The PSC ordered the five distribution utilities outside of New York City to offer dynamic load management to customers. Payments would be made to customers who reduce load during “called demand response events,” when load is expected to reach its peak.
The programs are mandated to be available everywhere by July 2016, with implementation plans due in January. DR is already available in the Consolidated Edison service territory.
The PSC acknowledged that the “accelerated program rollout” created technical challenges that would limit availability. Priority areas were established that offered the greatest benefits at the lowest costs, based on factors including system stress and local distribution constraints, the PSC said.
For this summer, the plan is generally limited to more densely populated areas around upstate cities, such as Buffalo. New York State Electric & Gas and Rochester Gas & Electric did not designate areas but were ordered to do so by July 1.
Commissioner Diane Burman dissented in part, saying the commission was moving too fast and that she preferred the rollout a year from now, when utilities were able to offer the service system-wide.
“Are we doing this to rush it, and at the end of the day we’re not going to be successful? And we’ve mandated something, rather than carefully analyzing it,” Burman said.
Noting that the program is already expected to be modified for 2016, she said the fast track will merely cause customer confusion and waste resources.
Chairman Audrey Zibelman referred to her own experience as a system operator and DR provider in the private sector as CEO of Viridity Energy. She said discussions with market players indicate they are anxious to get the program operating. She also cited the potential ill will created with customers when a product is promoted or promised, only to be rescinded at the last minute.
Dynamic load management is considered a key component of the state’s Reforming the Energy Vision effort to revamp the electric industry in New York.
“Consolidated Edison had implemented and developed distribution-level DR programs in response to commission directives and was deriving substantial benefits from those programs. Based on this existing experience, it was determined that distribution-level DR programs are proven ‘no regrets’ cost-effective programs, for which immediate implementation was appropriate,” the order says.
The plan was devised after a December 2014 order by the commission that directed upstate utilities to devise distribution level DR for this summer using Consolidated Edison as a model. Three types of programs were devised: a peak shaving program to be called on a day-ahead basis when forecasted load approaches the summer peak; the ability to call on local distribution resources to address reliability concerns in specific electrical or geographic areas; and a direct load control program allowing customers devices that can be controlled remotely by the utility.
According to the PSC, the typical residential customer supplying their own specialized thermostat would receive a one-time bonus ranging from $30 to $100, as well as an annual performance payment ranging from $20 to $50 for allowing the utility to control the thermostat during demand response events.
The other three utilities affected by the order are Central Hudson Gas & Electric, Niagara Mohawk and Orange & Rockland Utilities.
