MISO must charge equal fees to all generators entering its interconnection queue regardless of whether they are internal, external, new or existing resources, FERC ruled last week (EL15-99).
The commission also directed MISO to revise its Tariff to spell out procedures related to external resources entering the queue, a process currently described only in the RTO’s Business Practice Manuals. FERC agreed with a group of MISO generators who contended that the absence of an explicit Tariff provision created a lack of transparency around the nature of RTO service agreements with external resources.
“The commission requires that matters that significantly affect rates and services, are readily susceptible of specification and are not so generally understood be in the Tariff rather than Business Practice Manuals,” the order stated.
FERC considered the issue significant enough to open a separate Section 206 proceeding (EL16-12) to review MISO’s Tariff and require revisions outlining specific procedures and milestone payments for all interconnection customers.
The ruling stems from a complaint by a group of internal MISO generators who contested the RTO’s practice of exempting external generating resources from paying a significant fee levied on any new internal resources seeking to enter the final stage of the interconnection process.
At the outset of the definitive planning phase (DPP), any new MISO interconnection customers within the footprint must make an M2 milestone payment to fund system impact and interconnection facilities studies, as well as a later network upgrade facilities study, before preparing a construction schedule and cost analysis. Existing internal generators are exempted from the payments. MISO also waives the fee for both new and existing generators outside its footprint under the assumption that those resources have already established interconnection agreements within their own balancing areas.
The complainants contended that the differing payment requirements represent a competitive disadvantage for them because external generators face a “significantly lower entry fee than generation internal to MISO.” The generators further argued that the lack of monetary collateral tied to the DPP phase could lead external resources to submit speculative project requests or nonchalantly withdraw projects, forcing MISO to revise its study assumptions and thereby delay other projects in the queue. They asked FERC to consider two options: Either force MISO to require all new interconnection customers to pay the milestone payments or eliminate the payments altogether in the interest of fairness.
In its answer to the complaint, MISO said the request to treat existing external generation identically to new internal generation was unjust and unreasonable. The RTO pointed to the milestone payment exemption for existing generation, also noting that the payments are refundable upon finalizing a generator interconnection agreement. The RTO said it would resolve the payment dispute by charging “some form” of initial payment to external customers wanting to enter the queue.
In its ruling, FERC went a step beyond the complainants’ original request by requiring all interconnection customers — including existing internal generators — to post milestone payments.
“All interconnection customers, whether they are new or existing, or internal or external, are seeking interconnection service and will be entering the DPP,” the commission said. “The Tariff provisions should ensure that all interconnection customers, internal and external, and new and existing, are treated comparably.”
FERC gave MISO 60 days to update its Tariff with the changes related to the interconnection process. The changes must include a pro forma service agreement and initial payment details for external resources. A final order on the matter is expected by Nov. 30.
Competitive transmission company GridLiance announced Monday it had closed its acquisition of about 410 miles of 69- and 115-kV transmission lines and related substation infrastructure from Tri-County Electric Cooperative (TCEC) in the Oklahoma Panhandle.
GridLiance CEO Ed Rahill called the transmission acquisition — GridLiance’s first —”an important milestone” for its business model to partner with cooperatives and other public power agencies.
GridLiance, which was formed in 2014, acquired Tri-County’s transmission assets and assumed full operational responsibility through its South Central MCN subsidiary, effective April 1. Under the transaction’s terms, GridLiance will represent the co-op and its members’ interest “in planning and development of new transmission projects within” SPP, the company said.
Rahill said his company would assume operations and maintenance responsibility for Tri-County’s assets, with the latter’s “boots on the ground” employees providing some O&M services.
“Over the long term, we can provide TCEC with a clear path to invest in SPP transmission projects that will reduce network congestion, increase service reliability and lower service costs,” Rahill said.
Tri-County CEO Jack Perkins said the move will allow the co-op to focus on its distribution system, with GridLiance upgrading the transmission assets. “Equally as important, we look forward to jointly investing with them in transmission projects that were previously inaccessible to us,” he said in a statement.
Headquartered in Hooker, Okla., the cooperative serves about 23,000 meters in the Oklahoma Panhandle, southwestern Kansas, the northern border of the Texas Panhandle and parts of Colorado and New Mexico.
GridLiance says its planning and development models are focused on providing more reliable transmission to public power customers, “hedging rising costs for regionally planned projects.” In addition to jointly planning, developing, owning and operating new transmission assets, GridLiance says it will work with entities such as Tri-County to identify “existing transmission infrastructure that can be more efficiently and cost-effectively upgraded and integrated into their RTO.”
GridLiance also announced Monday additions to its operations and compliance teams with the appointments of several regional-industry veterans to leadership positions: Kevin Hopper (late of Associated Electric Cooperative Inc.), president of the SPP Region; Neal Chapman (LS Power), vice president of engineering; and Jim Useldinger (Kansas City Power & Light), vice president of operations.
All three will be based in GridLiance’s Kansas City office and directly oversee the newly acquired TCEC transmission assets’ engineering and operations functions. The company said they will work with COO Noman Williams and Trent Carlson, regulatory and compliance vice president, to “build out its platform into other regions.”
GridLiance has also added several former SPP employees in recent months, including Brett Hooton, the RTO’s senior interregional coordinator, and Jody Holland, its manager of steady-state planning.
GridLiance is backed by Blackstone Energy Partners, an affiliate of New York private equity giant Blackstone Group.
WASHINGTON — More than 100 transmission developers, consultants, RTO officials and utility executives attended Infocast’s 19th Annual Transmission Summit. Here’s some of what we heard.
Competitive Transmission
Curt Bjurlin, an environmental services manager for Stantec, asked whether there are too many transmission developers chasing too few competitive opportunities under FERC Order 1000.
“I’m reminded of a story of a guy who comes to town and wants to play in a poker game and someone says ‘Why do you want to play in that game? Don’t you know it’s rigged?’ He says, ‘Yeah, but it’s the only game in town.’”
Bjurlin said he expects developers to employ more rigorous go/no-go decisions on bidding in the future.
Southern Co. is one utility that’s not entering the game. “We’ve looked at that business continually and feel that there’s enough players in that market and not a lot of projects to go after,” said Bruce Edelston, vice president of energy policy. “So we decided to stick to our knitting in our own service area.”
Lack of Interregional Transmission Projects
Edelston said the planning process isn’t the reason for the lack of interregional transmission projects.
“It’s whether there’s somebody who is benefiting from that line who’s willing to pay for it. … There are very few interregional lines that are going to be economic when you look at the alternatives available to the purchasing region — the region that would be receiving the renewable energy. They often have local alternatives or closer alternatives that don’t require transmission fixes, and these long distance interregional lines can be very, very expensive — and as we’re seeing with the Clean Line Energy Partners lines up in Illinois — very, very difficult to build.”
“In our case, with the price of solar having come down so far, it turns out to be much more economic to build utility-scale solar within our service area than it is to build long-distance transmission to access wind in the Midwest. And I think that’s true for a lot of East Coast load centers. You also have the opportunity these days to buy RECs — or renewable energy certificates — to meet any renewable portfolio standards that you have.”
Jared E. Alholinna, regional transmission planning strategist for Great River Energy, recalled MISO’s joint study with PJM, which identified up to 75 different “quick hit” transmission projects along their seam. (See MISO, SPP Considering Second Joint Tx Study.)
“Not one of them showed economic benefits. Many stakeholders thought this was a failure — you know, they’re saying ‘0 for 75.’”
The real reasons for not finding a viable project, he said, included the success of MISO’s multi-value projects in reducing congestion and low natural gas prices that make it cheap to redispatch around congestion.
“There have been projects on the border that are on the cusp of meeting criteria, but when you have two different RTOs, you have two different needs and you have two different approval processes. And trying to get all those stars aligned we’re finding is very, very difficult.”
Xcel Seeking Larger Dispatch Areas in the West
Gerald R. Deaver, manager of regional transmission policy for Xcel Energy, said although his company’s operators have developed expertise in making their systems more flexible, the increasing penetration of renewables is creating operational challenges.
“Xcel has been pushing the development of regional markets in the West because we think geographic diversity is the best way to deal with some of this imbalance between regions or areas with renewables. And it seems to be getting more traction in the West.”
“We’re trying to develop along the Front Range [in central Colorado and southeastern Wyoming], a common dispatch area with a number of entities, both [FERC] jurisdictional and non-jurisdictional, to try and widen that footprint. … I doubt you could go Western Interconnection-wide with, for example, an RTO, but we’re really pushing for bigger geographic areas for dispatch. That’s going to require probably some additional transmission interconnections.”
Xcel has reduced its carbon emissions by 20% since it began adding renewables in 2005, and its Colorado Public Service unit now gets 60% of its energy from wind during some hours of the day, Deaver said. “We’ve been able to line up long-term purchases of wind at steadily decreasing prices.”
Distributed Energy Resources
Eric Ackerman, director of alternative regulation for the Edison Electric Institute, said the planning for distributed energy resources will require granular data regarding both customer energy use and system status that few utilities currently capture, even though some 65 million interval meters have been deployed.
“But even if we have the data, the next issue is … do we want to give the data to the market? Because in California and in New York the preference is to have market-based third-party suppliers deliver the distributed energy. So the market is endlessly hungry for this data. They’d like it in real time. They’d like it constantly updated. And utilities — my members — are pushing back. They think their distribution franchise requires them to plan the system. And if they give too much of the data to the market, guess what? The market’s going to run away with that and they will lose control of their plan.”
Stuart Nachmias, vice president of energy policy and regulatory affairs for Consolidated Edison, said, however, there is a win-win opportunity for utilities and new entrants. “The [cost of] solar technology is coming down. But if you talk to the solar companies, their biggest cost is customer acquisition. And to the extent that utilities together with solar companies or battery providers ultimately can help reduce that acquisition cost and share in those savings there’s tremendous value.”
Nachmias also gave an update on his company’s plan to use distributed generation and demand-side management to address overloads in Brooklyn and Queens and delay the need for a $1 billion substation upgrade for a decade. (See NYPSC OKs Con Ed’s Demand Management Program to Relieve NYC Overloads.) “Stitching together the solution [is] really complex — much more than we thought,” he said. “And getting customer engagement is very difficult.”
Market for Grid-Scale Storage
Philippe Bouchard, vice president of business development for Eos Energy Storage, said that frequency regulation has been good for energy storage — responsible for about 80% of the 200 MW deployed last year.
“However the challenge with that market and application is … it’s a pretty shallow market. If you compare the amount of money that flows through FR in PJM relative to the energy market or the capacity market, it’s tiny. And the more assets that get built to provide that service are essentially cannibalizing the revenue streams that they can monetize.
“To me the real drivers of the market are going to be projects more like [Southern California Edison’s request for four hours of locational capacity] — large-scale longer duration projects that are providing services under long-term contracts with creditworthy off-takers. These are projects that are easily financed, that are providing a reliability service to the grid and which offer flexibility too.”
Alex Ma, senior manager of regulatory affairs for Invenergy, said grid operators will need to change their interconnection process in order to realize the potential storage has for supplementing variable energy resources.
“From an interconnection standpoint, it seems very difficult to get past the fact that you have two different technologies at the same [point of interconnection],” he said, recommending changes to “fast-track some of the resources — not necessarily based on size as they are today with small and large generation — but on technology.”
Brad Jones, CEO of NYISO, said storage is central to New York’s effort to create a more resilient grid following Superstorm Sandy. “The best technology for meeting resiliency at the distributed grid is having storage located there — having storage located at all the major substations to serve that load if they get disconnected.”
But, citing a Brattle Group study, he said only 40% of storage’s value is in resiliency. “The remainder of the value of storage comes from operating in the market. Recognizing that they can store energy at nighttime when it may be zero or negatively priced and can release the energy in the day when it’s positive. I’d like to see a way if we can figure out a way to capture those other benefits as well — perhaps allow the utility companies to auction off the energy value that exists in the wholesale market and then let others take that to market.”
John Jung, CEO of Greensmith Energy Management Systems, said the number of companies seeking a share of the energy storage industry will decline in the future. “There’s going to be a lot of consolidation in this space. It’s very natural. I’ve seen it in a lot of other spaces where there’s a lot of [venture capital] money. There was some $270 million in VC money that poured into this industry.”
Clean Power Plan
Gil Rodgers, senior managing director for natural gas markets at Energyzt, said he thinks the Clean Power Plan will likely survive legal challenges. “So it would be a mistake, it would really be foolish, not to consider the fact that this is something that’s coming down the road.”
Missouri Public Service Commissioner Scott Rupp said RTOs “can use [the CPP] to start making cases to build more transmission. Most of the people that make up them that have a lot of weight are the transmission companies.”
“I think it’s uncontestable” that the Clean Power Plan will be “a big driver for transmission,” agreed Larry Eisenstat of law firm Crowell & Moring.
Michael Ferguson, director at Standard & Poor’s, said states should not wait to respond to the rule. “We all know that when it comes to building a generator profile, building the transmission lines tends to be the long pole in the tent. … So if you’re a state that’s relying really heavily on new transmission build, it’s something that you probably don’t want to put off for too long.”
Kerry Worthington, a program officer for the National Association of Regulatory Utility Commissioners, also had advice. “My message to you today is to not depend on your assumptions and leave your options open,” she said. “It’s very difficult to predict with accuracy what the Clean Power Plan will look like after the stay.”
David Treichler, director of modeling and analytics at Oncor, predicted it would not be long before overnight load in Texas was served entirely by wind energy. “Things are going in this direction. CPP is not going to be the major driver for a clean Texas. Economics will be. … Government is not always the provocateur of our pain.”
Despite the CPP and competition from wind and cheap gas, some coal generation will be around for decades, said Todd Williams, a partner with ScottMadden. He noted that the average lifespan of a coal plant is 55 years and the newest one was built a year ago. “We’re going to have coal in the portfolio through at least 2070, if not beyond. … Coal’s not going away completely. Reminds me of the Monty Python skit ‘Not Dead Yet.’”
Improving Gas Infrastructure
“I would like to see going forward, in the next five years, coordinated planning discussions between the gas industry and the RTOs,” said John Lawhorn, MISO’s senior director of policy and economic studies.
“We have found that if you have a good fuel assurance program, like New England ISO has for several years, you don’t have electric reliability problems,” said Henry Chao, NYISO vice president of system resource planning.
“Ensuring that gas gets to the generators is definitely not currently in the job description of the ISOs or RTOs, as it’s currently written,” said Tanya Bodell, executive director at Energyzt. “Ensuring … reliability is; creating market-based incentives … to maintain that reliability most certainly is available.”
WILMINGTON, Del. — Mike Kormos, the departing chair of the Markets and Reliability Committee, couldn’t attend his last meeting because of a scheduling conflict, said CEO Andy Ott, who lauded his colleague for his nearly three decades of work at PJM.
“As he and I grew through the ranks of PJM, I saw him as a partner, and I think you all saw him as a person you could talk to on any subject and collaborate with,” he said. “I’m going to miss him. PJM is going to miss him. He has been with us for 28 years, and there’s just no replacing that kind of experience.”
Ott has said the position will not be filled.
Kormos, executive vice president and chief operations officer, announced his resignation last month. His last day with PJM is April 15. (See PJM COO Kormos Leaving; Post Won’t be Filled.) He has not indicated his future plans.
CFO Suzanne Daugherty, the new chair, presided over her first committee meeting. Members passed around Kormos’ place card, on which they penned parting sentiments.
Members OK Operating Parameters but Urge Refinements
The MRC unanimously approved changes to Manual 11: Energy and Ancillary Services Market Operations; Manual 15: Cost Development Guidelines; and Manual 28: Operating Agreement Accounting. The revisions define operating parameters. (See “Operating Parameter Definitions Approved,” PJM Market Implementation Committee Briefs.)
The changes to Manual 15, regarding start-up and no-load costs, also were endorsed unanimously by the Members Committee.
An alternate proposal put forward by Bob O’Connell of Main Line Electricity Market Consultants was not taken up for a vote because the initial motion passed. Combined cycle units traditionally have been disadvantaged by these definitions, he said. Minimum run time begins when the first gas turbine is synchronized, he said, leaving open the possibility that PJM could release a unit before the steam turbine is synchronized. O’Connell’s definitions included a calculation that would let PJM know when the steam turbine had been synched.
While the parameters would not invoke a nonperformance charge under the new Capacity Performance construct, they could affect make-whole payments, PJM’s Adam Keech said.
While O’Connell’s definitions were not considered, a number of members and the Independent Market Monitor agreed that the issue he raised should be addressed.
PJM’s Adrien Ford, who chairs the Market Implementation Committee, pointed out that the problem statement leading to the operating parameter definitions had been amended in his committee, allowing for ongoing conversations about them.
Keech said that even if the alternate definitions were approved, PJM programmers wouldn’t be able to implement them by June 1, when the new delivery year begins under CP rules.
“We have a bunch of significant compliance obligations coming down the pike that we are trying to work through as soon as we can,” he said. “While I understand the value of these changes, they don’t fall into compliance changes. I’m not certain what date we could hit with these.”
If the way the parameters are used is changed, especially for combined cycle units, it would require changes to the software and how PJM clears the day-ahead markets, he said.
Ed Tatum of American Municipal Power encouraged PJM to continue studying the issue.
“The stakes are huge,” he said. “AMP is very concerned about how these parameters are going to be implemented. They could have draconian impacts on a supplier. It is important from our standpoint to get it right — and if we can’t get it right, to think about transitioning things so we’re not unduly burdening or penalizing people. This is a grave concern.”
MRC, MC Endorse Interim Ramp Rate for Performance Assessment Hours
MRC members approved a temporary performance assessment hour ramp rate with a 77% sector-weighted vote. The interim solution also was approved by the MC, over 11 objections.
Market Monitor Joe Bowring voiced his opposition. “This significantly weakens the incentives of Capacity Performance,” he said. “We regard this as a direct contravention of FERC’s no-excuses policy. It’s not a good idea.”
Assistant General Counsel Jen Tribulski said that PJM’s filing with FERC will explicitly note that the ramp rate is an interim measure to “get us through the coming months.”
“We fully intend to continue the discussion,” which will include the issue of using original equipment manufacturing specifications, she said.
MC Votes to Flex Meeting Start Time Following MRC
Following a lively debate, the Members Committee voted to flex the start time of its meetings going forward. The change will ensure that lunch is preserved, which members said is valuable for networking.
The issue had been raised at the last meeting by John Horstmann of Dayton Power & Light, who asked if there was a way to streamline the work of the MRC and MC, which are held on the same day.
On Thursday, he suggested allowing the MRC — which usually has a meatier agenda than the MC — to run as long as necessary in order not to truncate debate and have the MC start 15 minutes to a half hour after it ends. If necessary, members will break for lunch during the MRC meeting.
Ten members objected.
Scheduling Changes Approved
The MRC unanimously approved revisions to transmission and energy scheduling practices to reflect PJM’s adjustment to its day-ahead energy market timeline. The changes include adding a five-minute “shotgun window” for the spot-in product. (See “Day-ahead Submission Deadline Moved up,” PJM Market Implementation Committee Briefs.)
MRC, MC Approve Updated Definitions, Clarifications to Governing Documents
The MRC approved updated definitions and clarifications to PJM’s governing documents. They involve the terms PJM board, market participant, credit breach, PJM region, regional entity, affiliate, PJM markets, economic minimum and transmission customer.
The MC also endorsed changes to governing documents as well as additional clarifications to previously endorsed revisions.
In addition, that committee approved Tariff and Operating Agreement revisions regarding the definition of the term counterparty. In an Aug. 27 vote, the word was removed from a batch of proposed definitions and returned to the Governing Documents Enhancements and Clarifications Subcommittee for further review at member request. The definition was aligned to use more precise language in the OA that specifies when PJMSettlement will and will not be a counterparty to a transaction or agreement.
Changes to Confidentiality Rule Allow Release of Certain Information
They address individual generation outages, the availability of demand response, cleared and offered capacity resources, information regarding uplift payments, results of the three pivotal supplier test and member data that has been made public by that member or a regulatory agency.
MRC Approves Manual Changes
The following manual changes were endorsed at Thursday’s meeting. Three of the votes were unanimous. There was one abstention on the changes to Manual 11 regarding Capacity Performance.
Manual 1: Control Center and Data Exchange Requirements. Adds new section for planning, coordination and notification of system changes and events; includes new content with updated procedures. New Attachment C is the new Inter-Control Center Communication Protocol (ICCP) failover test plans diagram. Revisions remove references to the PJM ICCP network interface control document and PJM ICCP communications workbook.
PJM’s Ryan Nice said that some companies had been found to be taking outages of a few minutes on their emergency management systems and not alerting PJM. “The implications of that are quite serious,” he said.
Manual 6: Financial Transmission Rights. Housekeeping changes resulting from annual review. Clarifications better describe existing rules and processes.
Manual 11: Energy and Ancillary Services. Changes accommodate the implementation of Capacity Performance regarding unit-specific parameters. For non-Capacity Performance resources, the status quo remains until 2018. From that delivery year on, unit-specific parameters for base capacity resources will apply during hot weather alerts, emergency actions during hot weather operations and when being offer-capped to maintain system reliability. For CP resources, beginning in delivery year 2016, unit-specific parameters will apply during hot weather alerts, cold weather alerts, emergency actions and when being offer-capped to maintain system reliability.
Manual 11: Energy and Ancillary Services Market Operations. Revisions reflect day-ahead market timeline changes. Among them: the deadline for submitting day-ahead bids will be 10:30 a.m. The day-ahead clearing window will be reduced to three hours. The deadline for posting day-ahead results will be 1:30 p.m. or as soon as practicable. Results will be posted upon approval but not before noon.
The Commodity Futures Trading Commission (CFTC) proposed Monday that electric capacity purchases and natural gas peaking supply contracts be exempt from regulation as swaps.
GE Energy Financial Services’ Linden, N.J. cogeneration plant is among those using peaking supply contracts to ensure natural gas supplies. Source: GE Energy Financial Services
The commission unanimously approved proposed guidance that said such contracts should not be considered swaps under the Commodity Exchange Act because they are “customary commercial arrangements” intended to meet regulatory commitments. The commission will accept comments on its proposal for 30 days.
“These contracts are entered into to assure availability of a commodity, not to hedge against risks arising from a future change in price of that commodity or for speculative or investment purposes,” Chairman Timothy Massad said in a statement supporting the guidance. “They are typically entered into in response to regulatory requirements, the need to maintain reliable energy supplies and practical considerations of storage or transport.”
The exemptions apply to:
Load-serving entities’ contracts to purchase electric capacity to comply with state or federal resource adequacy rules; and
Peaking supply contracts that allow an electric utility to purchase natural gas from another provider if its local distribution company curtails its delivery in order to preserve fuel for heating customers.
Massad said the proposed guidance, which complements the commission’s final rule regarding trade options, “will reduce burdens on end users and allow them to better address commercial risk.”
Avangrid is working with the MIT Energy Initiative to create a model to simulate the integration of distributed energy resources into the grid.
The model could support New York’s Reforming the Energy Vision plan by simulating how distributed resources, such as solar arrays and battery storage systems, might impact the power system. This model seeks to identify the scale at which distributed resources become beneficial to the grid while taking into account potential impacts on electricity prices, grid reliability and the environment.
The collaboration is part of MITEI’s broader Utility of the Future Study. Avangrid is the newly formed affiliate of the Iberdrola Group that operates New York State Electric and Gas, Rochester Gas and Electric, Central Maine Power and United Illuminating.
The average price of wholesale electricity, pushed lower by depressed natural gas prices, last year dropped to the second-lowest level in 12 years in New England, according to preliminary figures from ISO-NE.
The lowest and second-lowest average monthly power prices were in June at $19.61/MWh and December at $21.35/MWh. The second-lowest annual average price of wholesale electric energy was set last year at $41/MWh, with the lowest annual average price at $36.09/MWh in 2012.
For most of the year, natural gas prices in New England and much of the nation were at their lowest levels in nearly two decades.
Northern Indiana Public Service Co. has reached a settlement agreement that would allow it to proceed with a $1.25 billion seven-year infrastructure-upgrade plan. The utility originally sought $1.33 billion.
NIPSCO reached the settlement with its industrial customers, the Office of Utility Consumer Counselor, the LaPorte County Board of Commissioners and the Indiana Municipal Utility Group. Infrastructure upgrades include pole replacement, installation of underground cables and replacement of substation transformers and breakers. NIPSCO has also committed to retrofitting utility-owned streetlights with LED bulbs and splitting the cost between customers and municipalities.
The company has filed the settlement with the Utility Regulatory Commission.
The Public Service Commission reversed itself and voted to permit the $4.9 billion sale of Cleco to a consortium led by foreign investors. Cleco agreed not to raise its rates until 2020, and the utility’s 286,000 customers also would receive credits averaging $500 each for the next few years.
“I think we did a pretty good deal,” said Commissioner Foster Campbell, who flipped his position after negotiating from the dais during the hearing. The PSC had rejected the transaction in February, but the purchase will now close sometime in this month.
Three of the five elected PSC members were needed to approve the sale to a group led by Macquarie Infrastructure and Real Assets and British Columbia Investment Management Corp. In the end, four of the commissioners voted to approve the transaction.
A proposed law aimed at saving the state’s ailing biomass energy plants would save logging industry jobs but could add millions of dollars to electricity bills.
The bill would require the Public Utilities Commission to seek competitive bids and negotiate contracts for 80 MW of renewable energy for five years. Central Maine Power said the measure could add up to $48 million to ratepayers’ bills. The utility said that biomass plants have received more than $2.6 billion in ratepayer subsidies over the past 20 years, and despite that, half of them have closed since the 1990s because they weren’t competitive.
A logger group has estimated that the complete loss of the biomass industry in the state would cost 400 jobs at the biomass plants and at least another 900 related jobs. Total economic losses to the state could be as high as $300 million per year, the group says.
2 Large Solar Projects Headed for Delmarva Peninsula
Seattle-based Longview Solar has proposed building two solar projects on Worcester County farm land that together would generate up to 35 MW.
Longview, a partnership between Elemental Energy and Tuusso Energy, says one of the projects, estimated at $20 million, would involve 63,000 solar panels on 125 acres east of Snow Hill. The other would be located west of Berlin, cost $30 million and feature 85,000 panels on 190 acres.
Landowners last week complained to the Department of Public Utilities at a public hearing about Kinder Morgan’s proposal to take rights of way by eminent domain along the proposed route of its Northeast Energy Direct natural gas pipeline.
Kinder Morgan has identified 39 Berkshire County properties for compulsory land surveying because owners have refused access.
“This is about corporate greed at its most despicable; it is not about the greater good,” said landowner Williams Spaulding, who said he has filed numerous “no trespass” orders against the company but has still had to chase employees off his land.
A Marion Township moratorium to delay wind projects won’t impede the proposed wind farm that inspired the moratorium in the first place.
Opponents of Exelon’s proposed 68-turbine project in Marion, Bridgehampton and Custer townships had persuaded the Marion Township Board of Trustees last week to approve the moratorium that will halt all future wind development projects. But the 150-MW Exelon project was not included in the moratorium, officials said, because it already had been approved.
“I feel the board lied to and misled the citizens of Marion Township,” said Jennie Schumacher, a wind farm opponent who organized a protest at the local board meeting.
Industrial air pollution is imposing health risks on low-income and minority residents in Southwest Detroit and the surrounding areas, Newsweek reported. The region does not comply with federal sulfur dioxide standards under the Clean Air Act. More than 15% of adult Detroiters have asthma, 29% more than the statewide average, recent state data shows.
DTE Energy operates two coal-fired power plants that are the biggest sulfur dioxide emitters in the area. A Marathon Oil refinery also contributes emissions, and the Michigan Department of Environmental Quality is close to granting the refinery a new permit that will allow it to emit an additional 22 tons of sulfur dioxide annually.
Lynn Fiedler, a MDEQ spokeswoman, says the department has been working with companies to bring emissions down, but it’s a “difficult negotiation” because they will likely need to install costly carbon-reducing equipment. Fiedler added that DTE is “reluctant” to take steps in emissions-reduction.
PSC Staff Official Blasts Proposed Ameren Rate Scheme
Public Service Commission Staff Director Natelle Dietrich disparaged a proposal that would make it easier for Ameren to raise rates to pay for grid upgrades, calling it a “radical departure” from the current rate-setting procedure.
In testimony before the House Energy and the Environment Committee, Dietrich said the plan could increase residential rates by 62.1% over 10 years and boost industrial rates up to 94%. The rate scheme would also give Ameren’s biggest customer, Noranda Aluminum, power to negotiate rates in order to keep the troubled smelter afloat.
A group of large industrial customers, including Nestlé-Purina, Doe Run, Ford, General Motors, Monsanto and Anheuser-Busch, urged the state to stay with the current rate system. “Toss this bill on the scrap heap,” said Steve Spinner, representing the industrials.
PSC Orders Northwestern to Refund State’s Customers $8.2M
State regulators last week ordered NorthWestern Energy to refund $8.24 million that it charged to buy electricity on the open market during a six-month outage in 2013 at the Colstrip coal plant. The Public Service Commission said that NorthWestern failed to take prudent actions to protect customers against the financial exposure from such a massive outage.
The majority of commissioners said the utility should have taken out insurance or pursued legal action against the plant operator to recover some of the costs incurred during the outage, which occurred when equipment malfunctioned following maintenance work at one of Colstrip’s four units.
Despite National Trends, Coal Still No. 1 in State
Pope
Federal forecasters anticipate that natural gas will surpass coal in 2016 as the nation’s largest fuel source for power generation, but coal remains king in the state. Coal fueled 61.5% of electricity produced last year while natural gas made up 1%.
“It really does boil down to dollars and cents,” said Nebraska Public Power District CEO Pat Pope. The average cost of coal delivered for power generation in the state was $1.34/MMBtu in December, making it the cheapest in the nation and about 30% less than the national average. Natural gas delivered in the state cost $3.44/MMBtu, more than 2.5 times more than coal.
NYISO has selected Jane Sadowsky and Bernard Dan to fill vacancies on its Board of Directors, effective this month.
Sadowsky is the managing partner at Gardener Advisory, which provides consulting and advisory services predominately in the electricity power sector. Dan is the former CEO of Sun Holdings, a proprietary trading company that focuses on electronic trading of U.S. and European shares as well as currencies.
“Jane Sadowsky and Bernard Dan bring a wealth of talent and experience to our board,” said Michael Bemis, board chairman. “Their proven leadership and combined expertise in the areas of energy finance, financial markets and business strategy will be instrumental in guiding the NYISO Board of Directors as we continue to advance the efficiency of our markets while reliably meeting consumers’ energy needs.”
More than 150 people gathered for a 12-hour Public Service Commission hearing about the controversial, 87-turbine Brady Wind Energy Center in Stark County.
For the bulk of the day, attorneys for both Brady Wind, a subsidiary of NextEra Energy, and the grassroots Concerned Citizens of Stark County group, questioned witnesses about the wind farm and the effects on the area. Public commenters pushed the hearing into the evening. Commissioner Brian Kalk said it was the longest hearing he’s experienced in his eight years on the commission.
The PSC may take up to two months to make the final decision on the 150-MW wind farm, which was first proposed in late 2015.
The Corporation Commission says distributed generation and its effect on the grid should be explored in Oklahoma Gas & Electric’s pending $92.5 million rate case.
OG&E included a distributed generation tariff in its rate filing to comply with a 2014 law that requires utilities to establish a separate class for distributed generation customers if they can show those customers are not paying their fair share of grid-connection costs. The utility wants to establish a $2.68/kW demand charge for residential and small commercial customers. With the average peak demand for a residential customer at 6 to 8 kW, the demand charge could be $16-21 per month.
A hearing in the rate case is expected to begin May 3.
Oklahoma Gas & Electric next month will make a third attempt to win regulatory approval for a $500 million scrubber project at its Sooner coal-fired plant.
The Corporation Commission last year rejected a more comprehensive, $1.1 billion case and a pared-down modification of the utility’s environmental compliance plan. OG&E has asked for a rehearing and says it needs a decision by May 2 to meet a series of engineering and construction deadlines if the scrubbers are to be installed.
The utility is arguing for coal generation to remain a significant part of its fuel portfolio, while critics question why OG&E wants to keep a 35-year-old coal plant running for another 30 years when market and environmental forces are turning against the fuel.
A company that had planned to build a $360 million, 90-MW plant to generate electricity from old tires instead will partner with a high-tech firm to develop a facility to make diesel fuel and other products from the material.
Crawford Renewable Energy said it changed tack because a drop in the wholesale price of electricity made the Greenwood Township power plant proposal “economically unfeasible.”
The newly proposed non-combustion facility would recycle the tires into carbon black, a component in photocopier toner, and into the type of low-sulfur diesel required by the federal government for trucks and other heavy vehicles.
National Grid has started construction on a new substation that will improve electricity delivery to downtown Providence and the South Street Landing project.
The new substation will replace one dating to 1919. It is expected to be completed late in 2017.
“This facility will meet the electric demands of a major portion of the city for the immediate future and beyond,” said National Grid Rhode Island President Timothy F. Horan.
A Brown University professor is arguing that the construction of a new natural gas-fired power plant in Burrillville would make it impossible for the state to meet its target for reducing carbon emissions in the coming decades.
J. Timmons Roberts, who helped write the state’s climate change regulations, says building the 900-MW Clear River Energy Center conflicts with the Resilient Rhode Island Act, the 2014 law that set a non-mandatory goal of reducing state greenhouse gas emissions 80% below 1990 levels by 2050.
Roberts is submitting the testimony on behalf of the Conservation Law Foundation, a regional environmental group that is opposed to the power plant, which was proposed last year by Invenergy.
Opponents of a proposed electricity-producing manure digester in St. Albans say the project would jeopardize the wetlands that it ostensibly is designed to protect.
Green Mountain Power has applied to the Public Service Board for a Certificate of Public Good for the digester, which supporters say is a proven agricultural technology for improving water quality and reducing emissions of methane from dairy farms and compost operations. Green Mountain says its digester is the only one in the state that includes advanced systems for removing phosphorus from manure slurry.
But a vocal critic, Tim Camisa, co-owner of St. Albans-based Vermont Organics Reclamation, says the project would be located only 200 feet from a stream, too close to protect the streambank and wetlands from accidents.
The State Corporation Commission has approved Dominion Virginia Power’s plan to build a natural gas-fired power plant in Greensville County.
Construction is expected to begin this year on the $1.3 billion plant, which would generate 1,588 MW and be situated on 55 acres.
The company said customers will save $2.1 billion over the life of the plant through fuel savings compared with the cost of buying power on the open market.
State tax revenues from wind energy fell by 15% in 2015, coming at a time when the state is already suffering the effects of a pronounced downturn in the oil, natural gas and coal sectors. The reason for the 2015 tax decline was not immediately apparent.
The Cowboy State became the first in the nation to tax wind production when it approved a $1/MWh levy in 2010. Tax collections have varied between $2.6 million in 2012, the first year the levy was imposed, to $4.4 million in 2014. Last year, the state collected $3.7 million.
The state’s wind production capacity has remained unchanged since 2010. A lack of transmission capacity has stymied further development in the state.
AUSTIN, Texas — Technical Advisory Committee Chair Randa Stephenson and Kenan Ögelman, ERCOT’s vice president of commercial operations, last week suggested a workshop to discuss how ERCOT and its market participants exchange data and handle changes to data reports.
Denton Municipal Electric’s Lance Cunningham raised the issue by noting that staff told the Market Data Working Group it was issuing a 30-day notice — as required by ERCOT’s protocols — to change an existing wind-projection data report. Cunningham said that change would require an estimated 30 person-hours to make changes to the muni’s systems.
Several stakeholders sided with Cunningham, pointing out modest software changes can cost tens of thousands of dollars.
“Multiply that cost by the number of [market participants] that have to do it, and you’re in the millions pretty quickly,” The Wind Coalition’s Walter Reid said. “We need to be aware of what we’re doing.”
“[ERCOT’s] ability to unilaterally change reports has been a concern of mine,” said Calpine’s Randy Jones, representing independent generators. “I realize there are passages in the protocols to provide data to ERCOT upon [its] request, but the time may be ripe for a discussion that we start putting criteria around that … and mitigate the huge impact it has.”
Ögelman, while noting the change will actually take place June 30, did agree with Cunningham that such changes create inconveniences.
“It can be burdensome to adjust to [changes],” he said. “Long term, do we need to start thinking about another way we exchange data, rather than people scraping it off a report? Right now, this is the only way certain people can get this data. I think it’s very important to consider whole systemwide impact of changes.”
“You need a report you can input and utilize,” said Sharyland Utilities’ B.J. Flowers. “Maybe you utilize the workshop as business-requirement gathering, and hand it over to the market data group to work on the details.”
Stephenson told stakeholders she is working with ERCOT to schedule the workshop.
NPRRs Approved, NOGRRs Tabled
TAC members approved five Nodal Protocol Revision Requests:
NPRR 741: Clarifications to estimated aggregate liability (EAL) and total potential exposure (TPE) credit exposure calculations.
NPRR 744: Reliability unit commitment trigger for the reliability deployment price adder and alignment with RUC settlement.
NPRR 745: Change emergency response system availability from an hourly to 15-minute interval evaluation, plus other minor changes.
NPRR 748: Revisions associated with NERC reliability standard COM-002-4 and other clarifications associated with dispatch instructions.
Luminant’s Amanda Frazier, chair of the Protocol Revisions Subcommittee, said NPRR 744 exceeded ERCOT’s $100,000 impact-analysis threshold, but she noted staff filed comments that determined the ISO would have saved more than $9 million “over the last several months” if the revisions had been in place.
“We at PRS felt that was adequate justification for approving this process,” Frazier said.
The committee also tabled a Nodal Operating Guide Revision Request and an appeal of a second NOGRR:
NOGRR 151: Alignment with NPRR 748, revisions associated with COM-002-4 and other clarifications associated with dispatch instructions.
NOGRR 149 would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission operator services from a third-party provider if their annual peak is less than 25 MW. Jones expressed sympathy for the small municipalities most affected. “On the other hand,” he said, “it doesn’t seem to be fair to the market. Small entities are not carrying their obligations.”
Staff Share Reports, Updates
Staff shared the Emergency Response Service (ERS) report that is filed annually with the Public Utility Commission of Texas. ERCOT procures ERS three times during the year for four-month terms. Participants can provide the service for one or more of four time periods, which are designed to allow flexibility for customers during traditional business hours.
ERS expenditures are capped at $50 million. Staff said expenditures for last year were $48.8 million.
TAC also approved the Retail Market Subcommittee’s goals for 2016 and discussed staff updates on ERCOT’s debt strategy and changes to ERCOT’s antitrust admonition and guidelines.
ERCOT Treasurer Leslie Wiley shared feedback from her recent report to the Finance and Audit Committee. She said the ISO uses congestion revenue rights (CRRs) auction receipts — with a limit of $100 million — along with debt and revenue to fund its liquidity. Wiley said the committee encouraged her to use CRRs when available to fund long-term projects, but there are questions about how to pay for significant unbudgeted initiatives.
The ISO currently has an Aa3 credit rating. “We want to maintain that,” Wiley said.
ERCOT’s legal department is revising the antitrust guidelines to be a position statement. Nathan Bigbee, ERCOT’s senior corporate counsel, said there shouldn’t be any cause for concern, “as long as actions ERCOT takes fall within [its] authority under federal or state laws.”
FERC last week granted Missouri River Energy Services (MRES) an extension to comment on a series of “zonal agreements” submitted by ALLETE and Great River Energy to resolve revenue-sharing and cost recovery disputes (ER16-1107, et al.).
The commission extended the commenting deadline to April 5, a week short of MRES’ request but four days longer than what ALLETE and GRE were willing to concede.
The agreements would resolve the two companies’ disputes over revenue-sharing and cost recovery for transmission projects in MISO’s Minnesota Power (MP) pricing zone — including the proposed Great Northern Transmission Line linking the region with hydro resources in Manitoba.
ALLETE and GRE filed a joint answer urging the commission to disregard the protest by MRES, which contends the agreements were negotiated “outside of commission processes” and could be inconsistent with MISO’s Tariff.
“These complex, interrelated agreements proposed by the applicants as a black box settlement that implicitly cannot be ‘pried apart,’ present a challenge of analysis because of their complexity and lack of transparency,” MRES wrote in a March 24 filing.
“All of MRES’ claims are either procedurally improper or unfounded and should not delay the commission’s approval of the zonal agreements,” the two companies countered.
MRES’ concerns have less to do with the revenue-sharing portion of agreements than with their possible implications for transmission cost allocation within the MP pricing zone. Chief among of those concerns is whether ambiguous language in the settlement opens the door for ALLETE to eventually roll costs related to the 500-kV Great Northern line into its revenue requirement, a move MRES said should be prohibited under MISO’s Tariff because the project is participant-funded.
ALLETE and GRE counter that MRES is pursuing its concerns under the wrong proceeding — that the revenue-sharing methodology under the zonal agreements represents a separate issue from Great Northern’s cost allocation. The companies say MRES should raise allocation concerns under the Tariff’s Attachment O protocol, which deals with project cost recovery.
The two companies also defended the settlement process and its outcome, saying their agreements “worked within the context” of MISO’s Transmission Owner Agreement, which spells out how transmission revenue should be distributed in pricing zones with multiple transmission owners.
“MRES’ protest, at best, reflects a misunderstanding of the process used to negotiate the zonal agreements as well as such agreements’ fundamental purpose,” the companies said.
ALLETE and Great River insist that if they “had not resolved their differences, they would have been forced to litigate complex and fact-intensive issues” regarding MISO pricing zone boundaries, asset classification for cost allocation purposes and revenue sharing for select facilities and load within the MP pricing zone.
“This litigation likely would have taken years and resources away from all parties (including MISO and commission staff), who all may prefer to focus on other areas,” the companies said.
MISO’s day-ahead market schedules may continue to use Eastern Standard Time instead of Eastern Prevailing Time even as the RTO alters scheduling deadlines to comply with updated gas nomination cycles, FERC said (ER15-2256).
The commission last week ruled that MISO could persist in having its day-ahead market become effective at 12 a.m. EST, despite using EPT for other scheduling deadlines.
In a Jan. 19 compliance filing related to gas-electric coordination, MISO sought permission to continue using EST because “accommodating transitions to and from daylight saving time would require significant implementation costs to MISO and its market participants, while providing little, if any, quantifiable benefits.” MISO explained that moving to EPT would “divert resources and funding from higher priority initiatives.”
FERC agreed that MISO “sufficiently explained the discrepancy between its using EST for establishing when its day-ahead market schedules become effective and its using EPT for all other scheduling deadlines.”
The commission also approved MISO’s request to begin posting day-ahead market results by 1:30 p.m. EPT (12:30 p.m. CT), saying the new deadline provides natural gas-fired generators sufficient time to procure fuel and secure pipeline transportation ahead of the 1 p.m. CT timely nomination cycle. FERC additionally accepted a related MISO provision to move the day-ahead market trading and interchange scheduling deadlines to 10:30 a.m. EPT (9:30 a.m. CT) in order to meet the new posting time. (See FERC Orders MISO to Shift Electric Schedule.)
The schedule changes become effective Nov. 5 for the Nov. 6 operating day.
A MISO proposal to hold a separate forward capacity procurement auction for deregulated areas is meeting with skepticism from some RTO members.
Dynegy’s Baldwin Energy Complex in southern Illinois. Some generators in retail choice regions of MISO such as southern Illinois have exported their power to PJM, where capacity prices have been higher Source: MISO
MISO stakeholders raised their concerns at a March 28 Competitive Retail Solution Task Team discussion focusing on the Forward Local Requirements Auction (FLRA) proposed last month. (See MISO Proposes Adding Forward Auction for Retail Choice Zones.) The task team plans to turn the proposal over to the Resource Adequacy Subcommittee (RASC) this month.
Zone 4 an ‘Island’
Much attention was focused on the fully deregulated Zone 4 in southern Illinois — MISO’s only fully deregulated zone.
Aaron Patterson with The NorthBridge Group pointed out that Zone 4’s local clearing requirement of about 5 GW during the 2016/17 planning year would leave more than half the zone’s supply unused in a forward auction.
“What I’m wrestling with is — we have 10 to 11 GW of supply [in Zone 4] and sort of structurally only 5 GW” under the local clearing requirement, Patterson said. “The supply that doesn’t clear is getting a price signal that it’s not needed.”
Jeff Bladen, MISO executive director of market design, responded that leftover supply would be applied to the planning reserve margin requirement.
“A lack of a forward signal is not lack of a need,” Bladen said. “It is a lack of need for it to be a local resource.”
Others said the FLRA would make Zone 4 even more of an “island.”
Bladen said MISO would not introduce a new import constraint for the auction. Instead, the RTO plans to examine system-wide import capability. And while the grid operator does not intend to impose a minimum offer price rule, it would update its Tariff with a bright line reliability test for forward procurement.
Multiple stakeholders asked what data and forecasting methods MISO would use to calculate local clearing requirements three years into the future, questions that Bladen deferred to the April RASC. “We’ll need to discuss that with stakeholders in a little more detail,” he said.
Bladen also said the RASC could best address the concerns of stakeholders who think the FLRA will produce extremely low prices and want MISO to run simulations and present the results. Price formation is “something we’ve given extraordinary amounts of attention to,” he said.
“This might work for a partially deregulated zone, but this won’t work for a zone that’s been fully deregulated,” said Exelon’s Marka Shaw, who asked for another CRSTT meeting specifically focused on affected Illinois customers. “I don’t like the idea of this rolling into the RASC and this getting shortchanged given the tight timeline.”
David Sapper of Customized Energy Solutions wanted to know how generators could use the five-year FLRA opt-in to participate, but Bladen clarified that the opt-in applies only to load-serving entities, not generators.
In response to a question about how MISO’s new two-season construct would align with forward procurement, Bladen said seasonal constructs — currently scheduled to be enacted in the 2018/19 planning year — would apply to the FLRA as well.
“These filings are effectively being looked at in parallel,” Bladen said.
Jim Dauphinais, counsel for Illinois Industrial Energy Consumers, asked how the downward sloping demand curve would apply to market supply. Bladen stressed the curve is only applicable to the demand — not the supply — side of the auction.
“It is very feasible to have different purchase price sensitivities for different consumers, if you will, in the same market,” Bladen said.
The model could support New York’s Reforming the Energy Vision plan by simulating how distributed resources, such as solar arrays and battery storage systems, might impact the power system. This model seeks to identify the scale at which distributed resources become beneficial to the grid while taking into account potential impacts on electricity prices, grid reliability and the environment.
The average price of wholesale electricity, pushed lower by depressed natural gas prices, last year dropped to the second-lowest level in 12 years in New England, according to preliminary figures from ISO-NE.
Northern Indiana Public Service Co. has reached a settlement agreement that would allow it to proceed with a $1.25 billion seven-year infrastructure-upgrade plan. The utility originally sought $1.33 billion.
The Public Service Commission reversed itself and voted to permit the $4.9 billion sale of Cleco to a consortium led by foreign investors. Cleco agreed not to raise its rates until 2020, and the utility’s 286,000 customers also would receive credits averaging $500 each for the next few years.
A proposed law aimed at saving the state’s ailing biomass energy plants would save logging industry jobs but could add millions of dollars to electricity bills.
Landowners last week complained to the Department of Public Utilities at a public hearing about Kinder Morgan’s proposal to take rights of way by eminent domain along the proposed route of its Northeast Energy Direct natural gas pipeline.
A Marion Township moratorium to delay wind projects won’t impede the proposed wind farm that inspired the moratorium in the first place.
Public Service Commission Staff Director Natelle Dietrich disparaged a proposal that would make it easier for Ameren to raise rates to pay for grid upgrades, calling it a “radical departure” from the current rate-setting procedure.
State regulators last week ordered NorthWestern Energy to refund $8.24 million that it charged to buy electricity on the open market during a six-month outage in 2013 at the Colstrip coal plant. The Public Service Commission said that NorthWestern failed to take prudent actions to protect customers against the financial exposure from such a massive outage.
NYISO has selected Jane Sadowsky and Bernard Dan to fill vacancies on its Board of Directors, effective this month.
More than 150 people gathered for a 12-hour Public Service Commission hearing about the controversial, 87-turbine Brady Wind Energy Center in Stark County.
The Corporation Commission says distributed generation and its effect on the grid should be explored in Oklahoma Gas & Electric’s pending $92.5 million rate case.
A company that had planned to build a $360 million, 90-MW plant to generate electricity from old tires instead will partner with a high-tech firm to develop a facility to make diesel fuel and other products from the material.
National Grid has started construction on a new substation that will improve electricity delivery to downtown Providence and the South Street Landing project.
A Brown University professor is arguing that the construction of a new natural gas-fired power plant in Burrillville would make it impossible for the state to meet its target for reducing carbon emissions in the coming decades.
Opponents of a proposed electricity-producing manure digester in St. Albans say the project would jeopardize the wetlands that it ostensibly is designed to protect.
The State Corporation Commission has approved Dominion Virginia Power’s plan to build a natural gas-fired power plant in Greensville County.
The commission extended the commenting deadline to April 5, a week short of MRES’ request but four days longer than what ALLETE and GRE were willing to concede.
