SPP’s recent trend of sending market-to-market payments to MISO continued in September, but that trend figures to reverse itself in the months that follow.
SPP’s Gerardo Ugalde told the Seams Steering Committee on Wednesday that the RTO sent $1.66 million to MISO as a result of temporary and permanent flowgates with the ISO. It was the third straight month the M2M process has resulted in a payment from SPP to MISO.
| SPP
“We don’t foresee this showing up in November,” Ugalde said. “This seems to be a seasonal change, where the flows flip.”
Temporary flowgates resulted in 591 hours of binding M2M and $1.14 million in charges from SPP to MISO; permanent flowgates added another $517,000 in M2M charges to the RTO as a result of 441 hours binding.
SPP Interregional Coordinator Adam Bell reminded stakeholders of a Nov. 30 deadline to submit projects they would like to see included in a potential joint study with the ISO as part of the 2016 Coordinated System Plan. (See “SPP, MISO Shared Joint Study Needs List,” SPP Briefs.)
Bell said initial discussions have been held with MISO to use the targeted study as the “foundation” for a “much broader study” next year. He said progress has been slow in developing coordinated system plans with both the ISO and Missouri-based Associated Electric Cooperative Inc.
CenterPoint Energy continues to focus on its gas business even as its regulated electric business contributed to a strong third-quarter earnings report.
The Houston-based company, which owns electric transmission and distribution and natural gas distribution, sales and services subsidiaries, on Friday reported a third-quarter profit of $179 million ($0.41/share), beating a Zacks Investment Research consensus of $0.37/share.
| CenterPoint Energy
It was a marked reversal from the same period last year, when CenterPoint reported a $391 million loss after a taking an $862 million impairment charge due to its investment in struggling Enable Midstream Partners.
CenterPoint’s revenues for the quarter rose 16% to $1.9 billion, including $908 million from its electric transmission and distribution segment, an almost 10% increase over a year earlier. The company attributed the rise to customer growth and higher rates.
Earlier last week, CenterPoint announced its CenterPoint Energy Services had reached an agreement to acquire Atmos Energy Marketing for $40 million. Atmos, which manages assets for utilities, power plants and local distribution companies, will add six states to the 26 in which CenterPoint Energy Services already markets its energy packages.
“This deal will allow us to grow our customer base and revenues while maintaining a low operating model and a cost-effective organization,” Joe McGoldrick, president of CenterPoint’s gas division, said during a conference call with analysts Friday. “This deal will increase our scale, geographic reach and expand our capabilities.”
CenterPoint is also continuing to evaluate “strategic alternatives” for its Midstream partnership with Oklahoma-based OGE Energy, including a sale or spinoff, to “reduce exposure to commodity price influences,” CEO Scott Prochazka said.
CFO Bill Rogers told analysts the company is continuing its discussions with interested parties. If no deal is reached by mid-January, CenterPoint will be required to submit a right-of-first-offer to OGE — allowing OGE to buy out CenterPoint’s interest — before continuing discussions with other prospects, Rogers said. (See CenterPoint Abandons REIT Plan; Offers Stake in Gas Partnership to OGE.)
Duke Energy last week announced five executive appointments — effective at varying dates between now and year-end — with the goal of strengthening its regulatory and economic development initiatives.
Clark Gillespy, currently South Carolina state president, will become senior vice president of economic development. Alex Glenn, currently Florida state president, will become senior vice president of state and federal regulatory legal support.
Kodwo Ghartey-Tagoe, currently a senior vice president of state and federal regulatory legal support, will take over Gillespy’s role. Harry Sideris, currently a senior vice president of environmental health and safety, will take over Glenn’s role. Paul Draovitch, currently a senior vice president for fossil-hydro operations, will take over Sideris’ role.
PG&E Hit with Federal Lawsuit over Pension Benefits
Three Pacific Gas and Electric workers filed a lawsuit Nov. 1 in the U.S. District Court for the Northern District of California accusing the utility of wrongly classifying them as independent contractors to deny them pension benefits.
The lawsuit alleges that PG&E adopted different and conflicting interpretations of its pension plan and stopped asking its counsel for advice “when it did not like the results.”
Emails and memoranda that allegedly support the workers’ allegations are attached to the court filing. The internal documents came to light during another worker’s pension lawsuit settled by PG&E in 2013.
Swiss Companies to Supply Battery Storage System for PJM
Swiss Green Electricity Management Group, which invests in energy storage projects, has announced a partnership with fellow Switzerland-based company Leclanché to supply a 20MW/10MWh battery storage system for PJM’s frequency regulation market.
Leclanché will act as SGEM’s engineering, procurement and construction partner and supply the battery storage system, which will be constructed in Marengo, Ill.
In August, the two signed an agreement that gives SGEM right of first offer for Leclanché projects, which are expected to grow to more than 85 MWh in 2017.
Duke Energy, Siemens Team Up for Wind Farm Services
Duke Energy Renewables and Siemens’ wind power and renewables division are teaming up to provide operations and maintenance services for wind farms whose turbines have multiple manufacturers.
Under their agreement, the companies can bid separately on services at wind projects. If either company wins a contract, it will bring the other in for appropriate work.
The partnership establishes “one-stop shopping” for wind farm owners who would otherwise need to make separate contracts with each original equipment supplier, Duke Renewables spokeswoman Tammie McGee said.
GE to Supply Converter Stations For Plains & Eastern Clean Line
GE Energy Connections will supply three HVDC converter stations to Clean Line Energy Partners for its $2.5 billion Plains & Eastern project, which will deliver 4,000 MW of wind power generated in the Oklahoma panhandle over a 720-mile system to a terminal near Memphis, Tenn.
Clean Line selected GE as the exclusive provider of the stations, which will convert electricity from DC to AC. The stations will be located in Pope County, Ark.; Texas County, Okla.; and Shelby County, Tenn. Construction could begin in the second half of 2017.
GE described HVDC transmission as “the most efficient means of connecting wind generation to distant end-use customers.”
Marcellus Shale Partnership Ends For Noble Energy, Consol Energy
Noble Energy and Consol Energy announced last week that they have ended their shale exploration partnership in the Marcellus drilling region.
In 2011 the companies agreed to jointly explore and develop 669,000 acres across Pennsylvania and West Virginia, producing 1.07 Bcfd of natural gas equivalent.
Noble will keep 363,000 acres, producing about 450 Mcfd of natural gas equivalent and pay Consol $205 million. Consol will keep 306,000 acres producing 620 Mcfd.
Amazon Plans Ohio Wind Farm To Power Cloud Computing Business
Amazon announced last week that it is planning a wind farm in Hardin County, Ohio, to help power its cloud computing business.
The wind farm, scheduled to open in December 2017, will be the fifth renewable energy project undertaken by the company’s cloud computing division and its second wind farm in Ohio.
The new wind farm will generate 530,000 MWh of wind energy per year and feed into the grid connected to the division’s Ohio and Virginia data centers.
Utilities Partner to Share Equipment During Disasters
A group of utilities in the Southeast have created a program to identify spare transformers and other transmission equipment that they can obtain from each other if disasters should strike.
Southern Co., Louisville Gas and Electric and Kentucky Utilities, PPL Electric Utilities and Tennessee Valley Authority last week announced the Regional Equipment Sharing for Transmission Outage Restoration (RESTORE) program, which would make needed transmission equipment available for purchase by the participating utilities.
The companies are interested in expanding the voluntary program to include others in the region.
FirstEnergy Must Save $200M To Preserve Credit Rating
FirstEnergy must find cost savings of about $200 million to preserve its credit rating — and possibly stay independent after receiving about half of a special rate rider it requested from Ohio’s Public Utilities Commission.
“We’re evaluating everything we do as a company to try and find a way to close that gap. Because [what’s been done so far] is not enough to get us into the position with the credit rating agencies that we need to be in,” CEO Chuck Jones said.
FirstEnergy’s stock is trading at 12 times the company’s earnings, with many of its competitors’ shares trading at 20 times their earnings, Jones said.
With unprofitable power plants dragging down its bottom line, FirstEnergy says it is calling it quits on competitive generation. And its days as a competitive retail supplier may be numbered as well.
CEO Charles Jones said during the company’s third-quarter earnings call Friday that the company will seek to sell its 17,000 MW of competitive generation or persuade Ohio regulators to transfer them into rate-base units.
“After the election is over … we plan to begin legislative and regulatory efforts designed to preserve our remaining generation assets. We are looking to convert competitive generation to a regulated or regulated-light construct in Ohio,” Jones said. “We’re also open to exploring the sale of any or all of these assets, particularly the gas and hydro units at Allegheny Energy Supply. If we find that one or more of these options are not viable, we’ll also consider deactivating additional competitive generating units, similar to the ones we announced this summer at Sammis Units 1 through 4 and Bay Shore.”
Sammis Power Plant | Bechtel
He also raised the prospect of a bankruptcy filing for FirstEnergy Solutions, the company’s competitive retail arm.
The news came as FirstEnergy reported earnings of $380 million ($0.89/share), down slightly from earnings of $395 million ($0.94/share) for the same period last year. The company expects a loss of $1.30 to $0.90/share for the year.
Jones said the company would be seeking a “solution” for its nuclear units in Ohio and Pennsylvania “that recognizes the environmental benefits of these established baseload-generating resources.” New York regulators’ approval of a zero-emissions credits system to preserve the state’s upstate nuclear plants has been challenged in court. (See Federal Suit Challenges NY Nuclear Subsidies.)
$1.1B Loss
Jones’ announcement on the fate of FirstEnergy’s merchant generation was his most definitive yet. After posting a $1.1 billion second-quarter loss tied to the closure of five coal-fired plants, Jones said the company would not make any large investments to prop up the credit rating of its generation business. (See FirstEnergy Posts $1.1B Loss, Eyes Exit from Merchant Generation.)
Last month, the company was disappointed when Ohio regulators rebuffed its request for a $4.46 billion subsidy spread over eight years, approving instead $612 million over three years. (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M.)
Jones last week blamed “weak” current prices and “anemic” demand forecasts for the poor financial performance of the generation fleet, which he said “is weighing down the rest of our company.”
“And while we have fought hard, we cannot continue to wait for an upturn,” he said. “We believe an accelerated timeframe is necessary so that we can remove lingering uncertainty, especially for our employees, and ensure that our company is singularly focused on the transition to becoming a fully regulated company.”
Jones estimated it would take 12 to 18 months for the company to execute its plans for its generation.
He also warned of deteriorating conditions at FirstEnergy Solutions, which sells retail energy to residential, commercial and industrial customers in the Northeast, Midwest and Mid-Atlantic regions.
“Further downgrades … by the rating agencies could require posting additional collateral of $355 million,” he said. “The continued viability of FirstEnergy Solutions is also pressured by some additional risks over the near term. These risks, which include an inability to implement our strategic alternatives in a timely manner, an adverse outcome related to a coal transportation contract dispute at FirstEnergy Solutions, or the inability for FirstEnergy Solutions to extend or refinance debt maturities of $515 million in 2018 could cause FirstEnergy Solutions to take additional actions, including restructuring its debt and other financial obligations or seeking bankruptcy protection.”
In West Virginia, meanwhile, FirstEnergy’s Mon Power subsidiary plans to issue a solicitation by the end of this year to address its generation shortfall.
VALLEY FORGE, Pa. — After months of debate, PJM’s Manual 15 revisions on fuel-cost policies and hourly offers won the approval of the Market Implementation Committee on Wednesday.
The changes are based on FERC’s approval of related Tariff changes that were filed in August (ER16-372).
Catherine Tyler Mooney of Monitoring Analytics, PJM’s Independent Market Monitor, questioned why some language on the review process that the Monitor and PJM had previously agreed upon had been struck from the revisions.
PJM’s Jeff Schmidt explained that elsewhere in the manual, the policy review was detailed as a “collaborative process” between the Monitor and PJM, so it needed to read that way everywhere in the manual. “The way we had it broken up before, it was staged,” he said. “It didn’t make sense for one [section] to be staged or stepped, and one to be at the same time.”
The section in question put generators on a five-day clock for responding to inquiries from the Monitor. “If the [Monitor] lets us know you want us to keep track of the clock, we’ll start the clock,” Schmidt explained. “If you have some specific question during the process about the fuel-cost policy, you have to let us know [to start the clock]. Then we’ll keep track of it.”
Mooney indicated that the explanation wasn’t satisfactory, but she declined to continue the debate. The exchange was the latest skirmish in an ongoing dispute between PJM and the Monitor. (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)
Several stakeholders, including Mike Borgatti of Gabel Associates, had concerns with how that plan would be implemented to ensure a generator is aware whether it’s on the clock or not. Schmidt assured him that PJM would make them aware.
Schmidt’s efforts were good enough for Calpine’s David “Scarp” Scarpignato. “I’d like to do something I usually don’t do: I’d like to commend you,” he told Schmidt. “It’s pretty specific what this engineering judgment is referring to, and I think this is a well-written sentence.”
The revisions were endorsed with seven objections and two abstentions.
‘Fully Metered’ EDC Definition OK’d
Members endorsed by acclamation Manual 28 changes describing a “fully metered” electric distribution company.
The changes were developed in response to a stakeholder request for a definition of the phrase, which was added in a recent update to Manual 01: Control Center and Data Exchange Requirements.
The new language in Manual 28: Operating Agreement Accounting defines a fully metered EDC as one that “reports hourly net energy flows from all metered tie lines to PJM via Power Meter and revenue meter data for the hourly net energy delivered by all generators within that EDC’s territory via Power Meter, for the purposes of energy market accounting.”
PJM’s Tom Hauske had come to the MIC meeting hoping for endorsement of changes to the Tariff and Manuals 11, 12 and 28 relating to operating parameters. But the Monitor’s concerns about definitions and modeling shelved that idea and the item was changed from an endorsement to a first read. (See “Stakeholders Approve Last-Minute PJM-IMM Operating Parameters Collaboration,” PJM Market Implementation Committee Briefs.)
Monitoring Analytics’ Joel Romero Luna raised concerns with how the definitions were applied, specifically pointing to what he saw as an over-complication of how to handle facilities with multiple breakers. He suggested standardizing the language to “the last breaker” throughout the revisions.
“When there’s one breaker, that’s always the last one,” he said.
Based on Luna’s concerns, Dave Pratzon of GT Power Group suggested delaying the vote until the Monitor had revised the language. “Personally, I can’t see voting on something where the [Monitor] is going to come back and make changes,” he said.
More Adjustments for Five-Minute Settlement
PJM will transition from an hourly calculation to a five-minute calculation for balancing spot market energy charges in order to eliminate an imbalance created when values such as demand, generation, imports and exports are calculated on different time scales, PJM’s Ray Fernandez explained.
Additionally, PJM proposed including the value of the generation and load imbalance in the transmission loss charges calculation and the transmission loss credits allocation. (See “Order 825 Progress,” PJM Market Implementation Committee Briefs.)
“The key piece to remember in here is the five-minute [generation-to-load] imbalance component,” Fernandez said. “That component is part of the balancing spot-market charge.”
PJM’s shortage pricing proposals from Oct. 26 and Nov. 2. | PJM
Next, PJM’s Rebecca Stadelmeyer explained the RTO’s proposed adjustments to shortage pricing to integrate with five-minute settlement requirements. PJM’s plan would change the scarcity signal for the maximum $850 penalty factor from the economic maximum of the single largest contingency to the highest actual output of a single unit. Next, it would add two lower “steps” that would trip a $300 pricing level. One step would be calculated as the highest actual output plus 190 MW — a static number derived from the synchronous reserve mean of the Mid-Atlantic Dominion zone plus one standard deviation. The second step would be calculated as the previous step plus an extension.
Stakeholders had several concerns with the proposal. Direct Energy’s Jeff Whitehead questioned the value of additional penalty thresholds that would just trigger lower levels of scarcity pricing more often. “I’m still a little perplexed as to why the reserve requirement is even being discussed here,” he said.
PJM argued it would reduce volatility.
IMM Clarifies Fuel-Cost Policies
Bowring outlined fuel-cost issues he’s observed and how they should be handled. First, he addressed penalty gas — gas used by generators that exceeds the amount the generator committed to using that day.
“The basic issue with penalty gas is it’s intended to be an incentive to not use the gas,” he said. “It’s not appropriate to include that in the cost of your gas.”
Stakeholders took exception to that, saying not being able to recover those costs would make them less likely to respond if called by PJM.
Bowring also discussed how generators should account for the costs of “ratable take” gas — gas that is not guaranteed to be available. “If a generator chooses to take a less-firm service, that’s fine, but they should take the risk,” he said.
Again, stakeholders were less than enthusiastic with Bowring’s perspective. “We need to be able to recover the costs of responding to PJM’s request. If we can’t do that, we’re going to have issues,” Dynegy’s Jason Cox said. (See Heeding Stakeholders, PJM Reduces Proposed Fuel-Cost Penalties.)
Generators Displeased with FTR Adjustments
To comply with FERC’s order on assigning balancing congestion costs, PJM is proposing several changes to its financial transmission rights market. First, it plans to assign all real-time balancing congestion to load. Along with that, PJM proposed returning to auction revenue rights holders any FTR auction and day-ahead congestion surplus after ARRs and FTRs are fully funded.
“PJM believes the allocation of FTR surplus should change to align closer with allocation of balancing congestion,” PJM’s Asanga Perera said in his presentation.
PJM also proposed annual replacement of retired Stage 1 paths. “We would only consider any future replacements as units retire. in other words, we wouldn’t be doing this process over and over every year,” Perera said. PJM has proposed a hybrid plan that would replace merchant paths RTO-wide and zonal-wide rate-based paths only in that zone.
Calpine’s Scarp was concerned with this approach. “I think you need to go back to the original presumption, which is, ‘Those who pay for the transmission get the rights,’” he said. “To say I have [capacity injection rights] and don’t get some of the incremental ARRs doesn’t make sense.”
“Why would a generator need a congestion hedge?” asked PJM’s Tim Horger. “They have no load.”
“I think the generator deliverability analysis lines up directly with the load deliverability analysis,” Scarp said. “There’s a parallel here. You can ignore it if you want, but I’m telling you it exists.”
The Long Island Power Authority is inching toward New York’s first offshore wind farm, which would supply 90 MW of electricity on a site off the eastern tip, said Mike Voltz, director of energy efficiency and renewables for PSEG-Long Island, which operates the power grid for LIPA. “We expect that power purchase agreement to go to the LIPA board of trustees in December for approval.”
David Mooney, director of the Strategic Energy Analysis Center at the National Renewable Energy Laboratory, discussed how New York could meet its 50% clean energy mandate. Because the current hydropower penetration of 20% is not expected to increase substantially, wind and solar would make up the remainder.
“There’s enough flexibility that exists in the system to be able to manage 30% penetration of wind and solar, and that’s without adding storage to manage variability,” he said.
Charles Fox, senior director of regulatory affairs and business development for fuel cell manufacturer Bloom Energy, praised New York’s level of sophistication in discussing clean energy policy. But he said the state needs to proceed with caution.
“The process of implementation is absolutely critical. We all want to get to the promise of Reforming the Energy Vision, but it’s important to do that to recognize that not only customers but financial institutions have entrenched business models that are going to need to change to finance projects. With companies that may have power purchase agreements in seven to 10 states, and when you suddenly change the rules in one of those places, it has a reverberating effect through just the law of unintended consequences.”
Richard Kauffman, Gov. Andrew Cuomo’s chairman of energy and finance for New York, took on critics of the zero-emission credit program, which would subsidize upstate nuclear plants to keep their carbon-free generation available for another 14 years.
“It would be great, as some critics would have us do, to say ‘let’s replace the nuclear plants with renewable energy. Let’s do that right now.’ It’s just not practical,” he said. “We cannot snap our fingers and have it done. We need to recognize the role nuclear will play in a transition to a renewable energy future, as no one has put forth a credible plan for cost- and time-effective replacement.”
Jim Muscato, a partner at the Young/Sommer law firm, which has represented wind developers for 15 years, said permitting has become more difficult as state agencies like the departments of Health and Transportation become involved.
“The totality of the siting process is that it will take about three years. One of the specific challenges is that the government does not speak with one voice. When getting through the preapplication process, we’ve had more government agencies get involved in the process than have ever been involved before. We’ve had 15 years successfully siting projects, but now we are working with agencies that had never been involved before.”
INDIANAPOLIS — After demonstrating the capabilities of its new 20-MW battery for five months, Indianapolis Power and Light says it’s time for it to get paid.
The energy storage system at its Harding Street Station here has been providing MISO with primary frequency response since May. But the company told FERC in an Oct. 21 complaint that the battery is “supporting the grid with no means for compensation for the services rendered” (EL17-8).
Interior of IP&L’s Harding Street facility | AES
The complaint asks FERC to compel MISO to update its energy storage definitions and compensation.
“Nothing [in the Tariff] exists to allow the battery to participate in the regulation market and be appropriately paid,” Lin Franks, IPL’s senior strategist for RTO, FERC and compliance initiatives, told RTO Insider in an interview. “We’re hoping FERC will see the wisdom in compensating automatic frequency control, injecting when frequency is too low and withdrawing when frequency is too high.”
IPL argues its battery should be paid instead of charged when “withdrawing [power] in response to a frequency deviation.”
Franks said IPL is not trying to be critical of MISO in making the filing. She pointed out that in 2009, when MISO opened its ancillary services market in accordance with FERC Order 888, the requirement did not include details on how fast-start resources recover costs.
“That was fine for back then, but now that we have a lithium ion battery in the MISO footprint, it’s no longer just and reasonable. What was just and reasonable in 2009 isn’t necessarily just and reasonable now,” she said.
Franks said creating proper definitions and a compensation mechanism is an “industry-wide kind of challenge.”
“Nobody is mad at anybody. It’s just time to make a change … and we don’t want this to get on the back burner,” Franks said.
The battery — consisting of eight 2.5-MW blocks — is using the interconnection facilities of two gas turbine generator units, which connect to the Harding Street South substation. (See FERC Approves 1st Storage GIA in MISO.)
Franks said settlement and dispatch for IPL’s lithium ion batteries are “vastly different” than for MISO’s current Type II storage energy and demand response resources. IPL claims MISO’s dispatch protocols are currently tailored to flywheel storage only.
MISO spokesperson Jay Hermacinski said the RTO is assessing its next steps before responding to the complaint.
“It is relevant to point out that at MISO and across the industry, there are numerous discussions at both the policy and technical levels to determine the most efficient and effective ways to integrate new technology, including storage, to the grid,” Hermacinski said.
He added that MISO has begun work on broader storage issues, starting with a stakeholder workshop in January and through its market roadmap process. He also said MISO staff will attend FERC’s technical conference on storage Wednesday (AD16-25). (See “FERC Calls Tech Conference on Storage,” Federal Briefs.)
MISO is currently considering including medium-term energy storage resources in its definition of DR resources. (See MISO Stakeholders Provide Ideas on Incorporating Storage.) IPL called the current stakeholder process “indeterminate” and asked for “tight time limits on any required MISO compliance filings.”
Franks insists that MISO should gather stakeholders to work on new storage definitions. “You really have to start all over. It’s a very time-consuming process,” she said.
IPL has committed to sharing “as much data as it practically can,” Franks said, to help explain the battery’s benefits.
In its filing, IPL suggested using PJM’s Regulation D payment factor as a provisional model until MISO can develop its own method for compensation.
IP&L’s Harding Street Facility exterior | DOE
PJM developed the regulation market payment after being approached by IPL parent company AES in 2009. AES’ Laurel Mountain facility in West Virginia — 98 MW of wind generation and 64 MW of integrated battery-based storage — has been providing PJM regulation service since October 2011.
The PJM payment mechanism is “certainly not going to be perfect for the MISO footprint,” Franks said. “But for the interim period, we’re suggesting that it is equitable and fair until MISO does its own body of work.”
Franks said working through the stakeholder process to incorporate a new storage definition and compensation into the Tariff would take about two to five years. She added that while IPL has a few ideas on what storage definitions might look like, it would rather reveal them in MISO’s stakeholder process.
“We prefer to share our data and testing and experience and work together to find a way that actually works to present to the stakeholders. No man is an island,” Franks said.
The Energy Storage Association lauded IPL’s move and urged FERC to take action to stop IPL from having to “operate the system in a suboptimal manner” and degrade the useful life of the battery.
“Without proper market structures that recognize the value delivered by energy storage systems, there is no way that the system can be dispatched cost-effectively. And without market signals that reflect the storage system’s operating parameters, the storage system could be unintentionally compromised or damaged,” the group said.
IPL’s complaint has attracted motions to intervene from American Municipal Power, Calpine, the Electric Power Supply Association, the Indiana Utility Regulatory Commission, Alliant Energy and the Coalition of MISO Transmission Customers and battery maker Alevo.
ALBANY, N.Y. — A coalition of environmental groups and clean energy developers on Thursday called for upgrades in New York’s transmission system at the Alliance for Clean Energy New York’s 10th Annual Conference.
“Today’s unique circumstances dictate that the rapid construction of new high-voltage transmission infrastructure should be an important component of the state’s strategy to meet its clean energy goals,” said ACE NY, the Sierra Club, Pace Energy and Climate Center, Environmental Advocates of New York and the Natural Resources Defense Council in a statement released at the conference.
“When we’re looking at transmission projects for the future, we need to see them through the 50% renewables lens,” ACE NY Executive Director Anne Reynolds said, referring to Gov. Andrew Cuomo’s State Energy Plan, which requires the state to procure 50% of its electricity from renewables by 2030.
The joint statement was also filed with the New York Public Service Commission, which is overseeing two transmission initiatives under the public policy provisions of FERC Order 1000. (See NYISO Identifies 10 Public Policy Tx Projects.)
The groups had a willing ally in NYISO CEO Brad Jones, who addressed the attendees at the morning session. He decried the 10- to 12-year process to get transmission built, advocating an expedited process of no more than six years.
“We need to develop our transmission system with an eye toward where renewables will be built,” Jones said. He said transmission developers need to build what he called a collector system, where renewables can be easily connected.
He said the ISO wants to lessen risks for energy developers who currently may seek less-than-optimal sites to access existing transmission; Jones had experience in Texas helping to develop collector systems in which networks of lower-capacity transmission lines would link several wind farms to a central point where they would connect to the main transmission corridors.
“My staff calls this our moon shot,” said Jones, who paraphrased President John F. Kennedy’s 1962 Rice University speech about landing a man on the moon: “We do it not because it is easy, but because it is hard.”
Reynolds said new lines should be built only if they help deploy wind and solar projects.
“With nearly 4,000 MW of new renewable energy projects proposed, real progress toward New York’s 50-by-30 goal is in sight,” Reynolds said in a statement. “New transmission capability is needed, but with upstate New York turning to a renewable energy future, the state should only be investing in those lines that are needed to deliver wind- and solar-generated power.”
WESTBOROUGH, Mass. — The challenge of preserving competitive markets while decarbonizing the New England economy was much on the minds of attendees at the Northeast Energy and Commerce Association’s 15th Power Markets Conference last week.
Some stakeholders fear New England states’ plans to procure up to 2,000 MW of renewable capacity could suppress prices in ISO-NE’s Forward Capacity Auctions. Those fears have receded somewhat, as the states are currently in negotiations for no more than 460 MW. (See New England States Move Toward Renewables Contracts.)
“The short-term problem isn’t as big as what was expected,” Jeff Bentz, director of analysis at the New England States Committee on Electricity, said during a panel discussion on the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) process. “That level is pretty small and could enter in FCA 12 [2021/22] but probably won’t enter until FCA 13 [2022/23].”
Another panelist, Peter Fuller, vice president of market and regulatory affairs at NRG Energy, described his company’s proposed two-step auction to accommodate state policy resources while maintaining efficient pricing for merchant generators.
The first auction would reflect the market without the effect of subsidized resources. which would be paid to all generating resources clearing in the first step. A second, lower price including the subsidized capacity would be paid to the generating resources that are subsidized by state policy.
All resources cleared in both steps would receive a capacity obligation, but these obligations would be pro-rated to ensure that the total quantity of generation purchased is no greater than the status quo, ‘merchant’ outcome. NRG says this would ensure that the cost impact of the states’ policy actions is shared among all market suppliers equitably.
“While NRG supports including state policy-subsidized generating resources in the markets, t wholesale sellers and the private investors in the market should not have to shoulder the entire burden of all of the state policy objectives,” Fuller said. “And effectively that’s the world we’re in right now. The [ISO-NE] renewable technology resource exemption, while limited, does create a price-suppression effect and potentially puts the full cost of adding those resources on the backs of all resources in the markets.”
Bill Berg, vice president of wholesale market development at Exelon, said the IMAPP meetings instead need to determine what subsidized resources are able to bid into the FCA and which aren’t. An estimated 8.7 GW of nameplate clean energy generation capacity will be needed to meet the states’ 2030 goals.
“We’re talking about 8.7 GW of subsidized capacity. Think about the angst that 200 MW has caused. Think about trying to design a market that puts both objectives, allowing the states to do what they want and protect reliability and the market, when you’re dealing with an 8.7-GW spread, which is 25% of the [FCA] market,” he said.
Pallas LeeVanSchaick, vice president of Potomac Economics, the ISO-NE External Market Monitor, said there are inherent risks in the adoption of out-of-market contracts intended to achieve public policy objectives.
“We’re going to get to the point that contracts with individual resources may not pass on costs in the short term, except that they’re able to fund those priorities through lower wholesale prices,” he said. “Maybe in the short term we don’t see higher rates to consumers, but in the long term, I bet we will see legacy costs that go on long after the impacts on the lower wholesale prices end. We’re going to notice over time that these are not in the interests of consumers.”
On a panel on the opportunities presented by energy storage, Ian Springsteel, director of U.S. regulatory strategy for National Grid, likened the industry to how consumers might have reacted to a smart phone a decade ago. It has seemingly unlimited potential, but the industry and public aren’t quite sure what the device can do or how to integrate it into daily practices.
“We’re in the same place with storage. We have an inkling of what it can do as one of many tools in the energy market or the distribution system. But to integrate it into all the rules and operational framework, to fully use this technology, we’re at the beginning of that process,” he said.
Christopher Parent, director of market development at ISO-NE, said the RTO is comfortable with storage, having had decades of experience with pumped hydro in New England. ISO-NE currently has about 90 MW of storage in its interconnection queue. The queue has a total of 10,000 MW of resources, many from flexible fast-start gas generators.
“When we look at our 2025 [projections], we’re looking at 4,400 MW of wind and about 3,300 MW of solar on the system,” Parent said. “That creates a lot of variability on the system that shows annual summer peaks of about 25,000 to 28,000 MW. That’s going to create a need for a lot of flexible resources on the system, be it storage or whatever technologies materialize in the coming years. The key thing in the market is to send the right price signals so we get the response we need.”
MISO has filed with FERC its proposal to implement a separate three-year forward capacity market with a downward-sloping demand curve for its retail-choice areas.
The nearly 1,700-page filing, submitted Nov. 1, creates Tariff Module E-3 and makes corresponding changes to modules A, D and E-1 (ER17-284). Jeff Bladen, MISO executive director of market services, said the RTO took pains to incorporate stakeholder advice into the proposal over the 20-month period since the initial issues statement.
“The proposal is a reflection of the breadth of advice we got throughout the process,” Bladen said during a conference call after the filing. “There are no surprises in what we filed this afternoon. … We look forward to the review process FERC will undertake.”
The filing came despite calls from some stakeholders for more discussion. Bladen said that although all stakeholders didn’t agree on MISO’s forward auction solution, virtually all stakeholders agree that a problem exists that needs to be corrected. Bladen pointed to the OMS-MISO Survey that found a possibility of a generation shortfall below the RTO’s minimum reserve margin requirement in 2018. (See OMS-MISO Survey: Generation Shortfall Possible.)
MISO’s plan is designed to “ensure conditions don’t deteriorate further,” Bladen said.
“It’s no secret that there has been difference in opinion about the preferred approach,” he said.
Bladen said the proposal is designed to provide equally valued capacity from both merchant generators and regulated utilities. An analysis from The Brattle Group has demonstrated that the proposal would ensure enough capacity to meet reserve margins.
MISO is requesting an effective date of March 1, 2017, the beginning of its implementation timeline for the 2018/19 planning year capacity auction. He would not speculate as to what the RTO might do if FERC doesn’t approve the changes by then. “There are many plausible ways FERC might act, so there are too many hypotheticals,” he said.
To respect state jurisdiction, the filing includes a prevailing state compensation mechanism modeled after one in PJM that will provide an alternative method for demonstrating long-term resource adequacy outside of the forward auction.
Under the mechanism, state regulators can facilitate settlements of compensation rates between their load-serving entities and suppliers outside of MISO’s processes. Authorities must notify MISO of the amount of demand under such agreements two months prior to the auction.
Clark Gillespy, currently South Carolina state president, will become senior vice president of economic development. Alex Glenn, currently Florida state president, will become senior vice president of state and federal regulatory legal support.
Amazon announced last week that it is planning a wind farm in Hardin County, Ohio, to help power its cloud computing business.
FirstEnergy must find cost savings of about $200 million to preserve its credit rating — and possibly stay independent after receiving about half of a special rate rider it requested from Ohio’s Public Utilities Commission.
