Constitution Pipeline asked FERC on Thursday to dismiss a complaint by New York’s attorney general alleging illegal tree cutting, requesting fast-track resolution to the ongoing dispute over the proposed 124-mile natural gas project (CP13-499).
The company vehemently denied allegations made by Attorney General Eric Schneiderman that it encouraged illegal tree cutting by landowners in defiance of a FERC prohibition, calling the complaint “part of a pattern seeking to delay construction.”
“The complaint does not contain any evidence that ‘clear-cutting’ … has occurred or, if it did occur, that it was performed or caused by Constitution,” the company wrote. “Instead, the complaint merely contains vague allegations that landowners or the landowners’ logging companies, against whom the attorney general seeks no enforcement action, conducted tree clearing, road building or other ground disturbing activity on the pipeline right of way in New York, in 10 locations [that] the attorney general refuses to, and fails to, describe with any specificity sufficient to actually identify any of them.”
Constitution said the vagueness of the attorney general’s complaint required that FERC appoint an administrative law judge to develop a complete record. It also said that fast-track processing was necessary because the complaint alleged ongoing violations of federal law.
The pipeline is intended to bring shale gas from the Marcellus region of Pennsylvania into the New York and New England markets.
In April, the New York Department of Environmental Conservation denied Constitution a water quality permit under Section 401 of the federal Clean Water Act. Constitution last month appealed the permit denial in federal court. (See Constitution Pipeline Appeals Rejection of Water Permit.)
MISO said last week it will not yield on a planned July filing for capacity auction changes in deregulated areas, but a filing to add seasonal and locational constructs will be delayed until later this year.
During a two-day meeting of the Resource Adequacy Subcommittee, Jeff Bladen, executive director of MISO market services, said the July 15 filing goal for a new auction design is unchanged and draft Tariff language will be in front of stakeholders in time for a special meeting of the RASC on June 13.
The Tariff filing planned for next month would introduce a bifurcated procurement using both the existing Planning Reserve Auction and a separate three-year forward model for deregulated areas that would use a sloped demand curve. MISO will allow regulated demand to voluntarily participate in the forward auction, but not regulated supply.
The RTO released business rules and an updated work plan on its proposal and has retained The Brattle Group to review it.
Bladen also addressed disagreements between MISO and the Independent Market Monitor over the proposed changes, saying the RTO was working to “close the gap.”
“I wouldn’t describe it as ‘at odds,’” Bladen said of the opposing viewpoints. “There’s a philosophical difference in how a sloping demand curve would be applied. We’re trying not to place any new rules on nonparticipating states.”
“This isn’t a summit meeting of Cold War adversaries,” Bladen reassured stakeholders. “MISO meets with the IMM regularly, and there are discussions between MISO and [Monitor David] Patton and his staff almost every day.”
Bladen conceded that if the talks result in major changes to the design construct, the July filing timeline would be “very hard” to accomplish.
Bill Booth of the Mississippi Public Service Commission asked what changes might result from the talks.
“I certainly wish I had an answer on what a compromise is going to look like, but we’re going to work through it … and find common ground,” Bladen said.
Other stakeholders repeated a desire for more time to review simulation results and vet Tariff language.
“We understand where your intentions are, but there are some that think the competitive retail solution isn’t necessary, and there’s a lot of work to be done in the Business Practice Manuals. I think the July Tariff filing is overly ambitious,” said Jim Dauphinais, counsel for Illinois Industrial Energy Consumers.
NRG Energy’s Tia Elliott asked if MISO would have a third party critique the Monitor’s proposed solution as well as the RTO’s. Bladen said that could be done.
MISO released 17 pages of business rules last week based on the prior presentations and asked for stakeholder response by June 8 so input could shape draft Tariff language, which is due in time for the June 13 special meeting of the RASC. Subcommittee liaison Renuka Chatterjee said the rules could be made into a new Business Practices Manual or inserted into existing BPM 11, which governs the Planning Resource Auction (PRA).
“This is very much a first draft,” Dauphinais said of the business rules document, pointing out that a demand curve shape hasn’t yet been settled on. “We’re concerned you’re not prepared to put out Tariff language on June 8.”
“I’ve heard a lot of opposition, but I haven’t heard a lot of support,” added Booth.
“Nothing is ever not contested at FERC,” Chatterjee offered in response.
A filing to implement external resource zones in addition to MISO’s existing local resource zones (pictured above) and a two-season capacity construct will be delayed until the fall as the RTO gathers more information from stakeholders.
Chatterjee outlined the work plan:
June-July: Rewrite Tariff and BPM language
July-January: Software development
October-February: Internal and external auction training
March: Launch (for 2017/18 planning year)
Study to Delay Seasonal, Locational Construct
While pushing ahead on the auction design, MISO has abandoned the July filing goal of seasonal and locational constructs and promised stakeholders an additional two months for the concepts to be vetted through the RASC. The delay will allow completion of a new seasonal loss-of-load expectation (LOLE) study and continuing talks on dividing capacity accreditation into winter and summer, according to MISO’s Laura Rauch.
The study will explore how lower capacity reserve margins in the winter would affect seasonal capacity accreditation and how separate summer and winter LOLEs would impact capacity import/export limits and planning reserve margins. Rauch said MISO does not expect to have specific numbers on transfer capabilities and seasonal reserve margins until the fall.
Rauch also said more time is needed to consider definitions of external resource zones.
“We don’t want to put a hard and fast timeline on this. Once we resolved these concerns, we will file, but we do want to file this year,” Rauch said. Pressed by stakeholders, she said MISO is envisioning a September filing but would make an October filing if discussion or study findings warranted postponement.
“We’ve had three filings dates out there, and we don’t want to keep moving things around,” Chatterjee added.
Rauch said an open question is how MISO should define forced outage rates and planned outage hours during critical hours: weekday hours ending 15, 16 and 17 during June, July and August; and weekday hours ending 9, 19 and 20 during December, January and February.
Rauch said a seasonal capacity accreditation process would begin next June.
Even with the seasonal and locational constructs paused for discussion, stakeholders were wary.
“I get the impression MISO just wants time to explain this better, but there’s opposition because other alternatives exist,” Customized Energy Solutions’ David Sapper said.
Dynegy’s Mark Volpe also said stakeholders don’t want to spend the next two months sounding like a “broken record” on recommendations.
Both Chatterjee and Rauch said MISO staff would take time to respond to new questions and recommendations in the coming weeks.
Monitor Outlines Approach on Avoidable Costs
Meanwhile, Market Monitor Michael Chiasson outlined an approach that relies heavily on PJM to develop default technology-specific avoidable costs for future PRAs. FERC mandated the defaults in its New Year’s Eve order to lessen the burden of verifying reference levels on a unit-by-unit basis (EL15-70et al.).
MISO and the Monitor agree that the RTO should use PJM default values for the 2017/18 planning year but without PJM’s 10% adder. Chiasson said MISO doesn’t have enough time to survey generators to develop its own default values before next year’s auction.
“The June 28 compliance filing deadline makes it unlikely that a MISO survey would receive a sufficient number of responses to produce representative results for the various technology types,” the Monitor explained. However, the Monitor said it would “consider expanding the IMM’s operating cost survey so the default values can be based on MISO participant data in future years.”
Because PJM doesn’t develop default values for nuclear and wind units, the Monitor is proposing a wind avoidable cost of $108.30/MW-day based on Energy Information Administration data and a nuclear avoidable cost of $454.79/MW-day based on a recent white paper by the Nuclear Energy Institute.
For all the avoidable cost values, the Monitor suggested using the monthly Consumer Price Index to update values. Chiasson said the Monitor considered using other indices that track power production costs, but they were either overly reliant on capital costs versus operations and maintenance expenses, their values were too volatile or the reports weren’t produced often enough. For planning years beginning more than six months after the latest CPI is released, the Monitor recommended using a 10-year average of CPI changes to escalate prices an additional year.
Dauphinais asked for more evidence supporting use of the PJM default values. “We’re very anxious to get those,” he said. “We’re missing some data here.” Chiasson said the Monitor would provide more information on PJM values at the next RASC meeting.
Dynegy has closed its 500-MW Wood River Power Station near Alton, Ill., eliminating more than 90 jobs.
Company officials announced plans to close the coal-fired plant in November after it failed to recover operating costs. The utility cited unfair market conditions in the deregulated and regulated hybrid footprint in MISO. Dynegy also said Wood River was not necessary to maintain reliability in the region.
In addition to $12 million in lost pay for the workforce, the closure will cost the local government $1.6 million in lost property taxes.
Appalachian Power Enters PPA with NextEra Wind Farm
American Electric Power’s Appalachian Power has signed on to a 20-year power purchase agreement with NextEra Energy to buy 120 MW of wind generation in Indiana to supply its service areas in Virginia and West Virginia by 2018.
The wind power will come from the Bluff Point Wind Energy Center to be constructed in Jay and Randolph counties in Indiana. The company selected NexEra’s proposal over a dozen other bids.
The agreement brings Appalachian Power’s total wind portfolio to 495 MW.
DTE Energy Chief Investment Officer Paul Cavazos is leaving his position at the diversified energy company to join Texas-based American Beacon, an investment firm specializing in mutual funds and corporate pension plans.
Cavazos worked at DTE Energy for nearly nine years, managing about $10 billion in investments, including benefit and contribution plans, a foundation and a nuclear decommissioning trust.
Alliant Energy Vice President and Treasurer John Kratchmer announced plans to retire last week.
Robert Durian, Alliant’s current controller, will take over Kratchmer’s duties July 1. Kratchmer will serve in an advisory role during a transition period, according to the company. Durian has been with the company since 1992.
Alliant Assistant Controller Ben Bilitz will fill the position of controller.
Wind turbine manufacturer Broadwind Energy has been awarded a three-year $137 million supply deal with an unnamed customer.
Broadwind, which has factories in Manitowoc, Wis., and Abilene, Texas, would say only that its customer is one of the largest wind turbine manufacturers in the U.S. Siemens and General Electric are among Broadwind’s major customers, according to a 2015 annual report.
Pacific Gas and Electric last month left a “treasure trove” of company data open to Internet hackers, according to a security researcher who revealed the lapse.
The compromised database contained company IP and MAC addresses, hostnames, computer locations and other vital information. More than 47,000 PG&E computers and other devices were left unprotected, the researcher said.
PG&E confirmed the lapse, blaming it on a third-party technology vendor that was developing a new platform.
Municipal Utilities Sign Up with Grain Belt Express
The Missouri Joint Municipal Electric Utility Commission, which buys power for public utilities, said it has signed an agreement for as much as 200 MW of capacity on Clean Line’s Grain Belt Express, bolstering the transmission line’s embattled application with the Missouri Public Service Commission.
The new contract, which is contingent on Clean Line winning approval from Missouri regulators, would replace an electricity contract with Dynegy coal plants expiring in 2021, when Grain Belt is supposed to be operational.
The 780-mile transmission line would carry 3,500 MW of wind power from western Kansas to eastern markets and up to 500 MW of power into Missouri.
Keeping Westar’s HQ in Topeka Key to Great Plains’ Acquisition
Westar Energy CEO Mark Ruelle said Great Plains Energy was the only bidder among multiple suitors that agreed to keep the utility’s headquarters in downtown Topeka, Kan., one of the deciding factors in choosing it as its $8.6 billion merger partner.
Although an investor-owned company must first consider shareholder value, Ruelle said, Great Plains’ offer to stay true to Westar’s commitment to employees and its philanthropic efforts in the Topeka community weighed in its favor. The merger was announced May 31.
“It’s turned out that after all the work, the best deal is with our next door neighbors,” he said. “They’ve agreed to keep Westar headquarters in Topeka, and not only that, in downtown Topeka. Great Plains has agreed to continue our community commitments, our charitable giving, our connections downtown.”
The SPP Capacity Margin Task Force conducted its penultimate meeting last week as it continues to set up the stakeholder group that will replace it in determining how low the RTO can go with its planning reserve margin.
The task force won board and member approval in April to lower SPP’s planning reserve margin — previously called the capacity margin — from 13.6% to 12%. The change is expected to save load-serving members about $86 million a year in capacity costs. (See “Lowered Reserve Margin Promises $86M in Annual Savings,” SPP Board of Directors Briefs.)
The CMTF will hold its last meeting June 30, turning over its work to the newly created Supply Adequacy Working Group (SAWG). The group will be responsible for developing and implementing processes that ensure “reliable supply of capacity necessary to meet demand and planning reserve margin requirements/methodologies in SPP.”
The SAWG will also be tasked with ensuring SPP’s processes and policies meet NERC and North American Energy Standards Board standards.
A separate small group is continuing its work on staff’s Resource Adequacy Workbook (RAW). The workbook will be used to gather load-serving entities’ planning reserve margin requirement calculations and data needed for the Energy Information Administration’s Form 411 (Coordinated Bulk Power Supply and Demand Program Report).
SPP’s vice president of engineering, Lanny Nickell, asked the task force for additional input on calculating planning reserve margin requirements for purchases and sales, which are calculated differently than they are for the EIA 411.
CAISO is nearing completion of a proposal describing how the ISO would allocate the costs of building and operating transmission assets in an expanded balancing authority that could encompass areas of the West outside California.
The ISO considers development of a new transmission access charge (TAC) plan to be “a central policy element” of expanding into a region with dozens of balancing areas subject to multiple state and municipal rules determining compensation for transmission owners.
CAISO’s potential expansion into the West is forcing the ISO to reconsider how it would allocate transmission costs across the region currently divided into multiple balancing areas.
Most pressing for CAISO: Development of new TAC options is essential for enabling Portland-based PacifiCorp to join an expanded system as early as next year.
‘Postage Stamp’ Rate
CAISO Principal of Market Infrastructure and Policy Lorenzo Kristov summed up the issue during a June 1 conference call to discuss the issue with Western industry participants: “The conversation we’re having here is — when you add new customers [to the ISO] — who would be paying for the service charge.”
CAISO currently uses a regional “postage stamp” rate to recover transmission revenue requirements for all ISO-controlled facilities rated at 200 kV or above. All internal load and exports are subject to per-megawatt-hour usage charges to fund those facilities.
Facilities rated below 200 kV and located inside the service territory of a participating transmission owner are covered by “local” rates paid by load within that territory. CAISO’s primary participating TOs are California’s three investor-owned utilities: Pacific Gas and Electric, Southern California Edison and San Diego Gas and Electric.
CAISO market participants are charged for transmission access based only on the regional or local criteria.
The current TAC makes no distinctions among projects driven by economic, public policy or reliability considerations, nor does it factor in-service dates or other non-voltage criteria.
“We’ve determined that the structure does need to be changed with an expansion,” Kristov said.
New ‘Sub-Regional’ Category
CAISO proposes to retain the category of regional — or ISO-wide — projects eligible for broad-based allocation, albeit in an altered format. At the same time, the ISO would introduce a new sub-regional category to accommodate TOs joining what could become a Western RTO in the future.
Under the latest TAC proposal, revenues for existing transmission facilities would only be eligible for recovery under “license plate” rates specific to each sub-region.
The upside for current CAISO members: They would not be charged for projects already operating in a new member’s service territory.
The downside: The sub-regional identification would also apply to CAISO’s current balancing area, meaning new members would not be assessed charges for California’s existing network.
The only projects eligible for regional cost allocation would be regional facilities approved under a new transmission planning process for an expanded ISO. To be considered for ISO-wide allocation, a proposed facility would be required to meet at least one of three criteria:
Having a voltage rating above 200 kV;
Facilitating interconnection — or increasing interconnection capacity — between two sub-regions; or
Creating, increasing or supporting the increase of intertie capacity between the expanded balancing area and a neighboring area.
Project Types
The TAC proposal would also introduce into the Tariff the practice of differentiating among different project types. For example, the new rules would make explicit that facilities approved to meet a reliability need within a sub-region would be allocated solely to that sub-region.
Economic and policy-driven projects would receive different — and more complex — treatment. Decisions regarding construction and cost allocation for those projects would be left to a new body of state regulators created in concert with the integration of a new TO into the ISO — an idea modeled on similar structures in ISO-NE and MISO.
“We know from precedent that agreement among the parties for cost allocation is important for FERC approval,” Kristov said.
CAISO is also considering additional provisions that would allow the expanded system to charge new TOs for costs of new regional facilities previously approved under the expanded transmission planning process. It would recalculate the sub-regional cost-benefit shares for those facilities at least every five years.
The ISO must also determine a regionwide export rate — or wheeling access charge — and develop FERC-required backstop provisions for approving and allocating costs for economic- and policy-driven projects.
“I just want to acknowledge that a lot in this proposal is not complete,” Kristov said.
Still, a draft final proposal for TAC options is slated to be released June 28. CAISO staff plans to present the plan to the ISO’s Board of Governors on Aug. 31.
Comments on the most recent proposal must be submitted to the ISO by June 10.
ERCOTsaid Friday it has executed a reliability-must-run (RMR) agreement to keep a 371-MW natural gas-fired generator available through September, with the likelihood of extending the contract through June 2018.
NRG Texas Power’s Greens Bayou Unit 5 was to be mothballed June 27. However, it will now be made available to the ERCOT market from June 1 through September. Under the RMR agreement’s terms, ERCOT will make a standby payment to NRG of $3,185/hour during on-peak hours, regardless of whether the unit runs.
Greens Bayou Source: NRG
ERCOT said the agreement will ensure transmission stability in the Houston region. The ISO said last month it has enough generating capacity to meet its expected demand into the next decade, even with NRG’s announcement it would mothball Greens Bayou. (See “ERCOT Reports Show Ample Capacity into Next Decade,” ERCOT Briefs: Ample Capacity; Outage Procedures.)
The Texas grid operator will ask its Board of Directors to approve an extension to the agreement for the summer of 2017 and June 2018 during its June 14 board meeting. If the board rejects the extension, the RMR agreement will expire May 31, 2017.
The ISO said it expects the $590 million Houston Import Project, which will improve the region’s ability to draw power from elsewhere in Texas, to be completed by the 2018 summer peak. The RMR agreement does not include off-peak periods (October through May) because planning studies do not indicate Houston-regional reliability violations during that period.
The RMR agreement is ERCOT’s first since 2011. It has executed 73 other agreements since 2002, most of which were for transmission stability. Four RMR agreements in 2011 returned mothballed units to service because of anticipated generation shortages during that summer’s peak demand period.
Greens Bayou 5 is the largest of seven units at the Harris County complex. Built in 1973, it was mothballed in 2010 and 2011, but returned afterward.
NYISO has identified 10 proposed transmission projects as finalists to relieve congestion in western New York.
The ISO issued a report last week in response to a 2015 New York Public Service Commission order that said relieving transmission congestion in the Buffalo area would produce environmental and reliability benefits and satisfy a public policy requirement under FERC Order 1000 (14-E-0454).
Source: NYISO
The PSC order resulted in the ISO’s first Public Policy Transmission Planning Process, a solicitation that generated 15 proposals from eight developers at the end of last year.
The transmission need was defined in the PSC order and ISO baseline models. They identified overloads on the Niagara-Gardenville 230-kV and 115-kV transmission corridors, which were aggravated by imports from Ontario.
“In general, each project addresses at least some portion of the baseline transmission security issues, but not all projects addressed all of the bulk power transmission security issues,” NYISO wrote. The ISO also says upgrades to three non-bulk transmission facilities may be necessary to satisfy the NYPSC objectives.
The intent of the transmission solution is to allow NYISO to use the maximum 2,700 MW of generation from the Niagara hydroelectric power station and a nearby pumped storage facility, and full access to at least 1,000 MW that would be imported from Ontario in an emergency.
“For each sufficient project, the developer of the project is qualified, the solution is technically practicable and the developer has an approach for acquiring any necessary rights of way, property and facilities,” the report states.
The 10 qualified projects include four from North American Transmission, two from National Grid, one from the New York Power Authority and New York State Electric and Gas, two from NextEra Energy Transmission New York and one from Exelon Transmission.
The PSC will review the assessment made by the ISO and determine if the public policy need still exists. It would then issue an order for NYISO to continue to evaluate and rank the projects identified in the report.
NYISO would then determine which projects are most efficient or cost-effective and eligible for cost allocation and cost recovery under its Tariff. Its findings would be released in the Western New York Public Policy Transmission Planning Report.
The PSC has also determined a public policy need exists to help address transmission congestion into southeastern New York. Proposals from developers were due at the end of April and are currently being evaluated by NYISO. (See NYPSC Directs NYISO to Seek Tx Bids.)
About 43% of the nation’s 2,758 electric power generation “establishments” are renewable sites, according to the U.S. Census Bureau’s County Business Patterns report. More than half of the renewable locations are in the 10 states in green. However, only 13% of the electricity produced in the U.S. during 2015 came from renewables, according to the Energy Information Administration.
Feds Designate Offshore NY Wind Lease Area
The Interior Department on Thursday proposed a commercial wind lease for 81,130 acres 11 miles off Long Island, an area that the department’s Bureau of Ocean Energy Management identified earlier this year. (See Feds Set Offshore Wind Site near New York.)
“This is another major step in broadening our nation’s energy portfolio, harnessing power near population centers on the East Coast,” Interior Secretary Sally Jewell said.
The notice for the proposed lease includes a 60-day public comment period.
The D.C. Circuit Court of Appeals on Friday ruled that the Nuclear Regulatory Commission followed all necessary rules when it wrote the regulation allowing long-term storage of spent fuel at nuclear generating stations.
The ruling, which means spent fuel rods can be stored onsite indefinitely, is important because the federal government hasn’t yet fulfilled its obligation to develop a site for depleted fuel, despite spending billions at the now-moribund Yucca Mountain site.
The attorneys general of New York, Vermont, Massachusetts and Connecticut had challenged the rule, joined by the Natural Resources Defense Council. Eric Schneiderman, New York’s attorney general, vowed to continue the fight.
Clinton Vows Increase in Renewables on Fed Property
Clinton
As Californians go to vote in the state’s primary elections, Democratic presidential contender Hillary Clinton is pledging to increase the development of renewable energy projects on federal lands and water if elected.
“Now, as we work to combat climate change and build America into the world’s clean energy superpower, our public lands can once again play a key role in unlocking the resources we need,” Clinton wrote in a piece published in The Mercury News. “While protecting sensitive areas where development poses too great a risk, we can accelerate our transition to a clean energy economy by increasing renewable energy generation on public lands and offshore waters tenfold within a decade.”
NRC to Review Entergy’s Response to Baffle Bolt Issue
The discovery of the failure of more than a quarter of the bolts used to secure baffles crucial to channeling cooling water in Entergy’s Indian Point 2 reactor has spurred an investigation into what caused it and what the company is doing in response.
“We will review Entergy’s analysis and plans before deciding if the company’s proposed course of action is acceptable,” Nuclear Regulatory Commission spokesman Neil Sheehan said.
The Indian Point discovery prompted another operator, PSEG Nuclear, to inspect its Salem 1 reactor, where it found that 18 of that reactor’s baffle bolts were degraded.
The Navy is looking to expand its nuclear operations from shipboard reactors to onshore locations.
Secretary Ray Mabus said he wants the Navy Department to look at the possibility of employing small modular reactors to provide power for shore installations. “With some of the new technology that’s coming along, it’s much safer, produces far less residue and nuclear waste, and it is an option that I think we should explore,” he said.
The Navy and the Marine Corps set a goal in 2009 of getting more than 50% of its shore power from alternative sources. Using solar, wind, geothermal and hydro, they met that goal at the end of last year.
FERC Approves $2 Billion Kinder Morgan LNG Project
FERC approved Kinder Morgan’s proposed $2 billion LNG export terminal on Elba Island near Savannah, Ga.
The first units will come online in early 2018 and eventually the terminal will liquefy up to 350 Mcfd. Kinder Morgan has a 20-year contract to supply Royal Dutch Shell.
Kinder Morgan already has an import terminal at Elba Island, built in the 1970s, but it has seen little use since domestic natural gas supplies expanded with the shale-gas revolution. The terminal has 11.5 Bcf of LNG storage capacity and 1.76 Bcfd of peak vaporization send-out capacity.
EPA decided Wednesday that two Rocky Mountain Power coal-fired plants must install pollution controls to improve atmospheric visibility near national parks. The company, which said it would cost $700 million to comply with the ruling, said it is reviewing its legal options.
The agency’s ruling, and its Regional Haze Rule, are aimed at restoring natural air conditions at 156 national parks and wilderness areas by 2064.
Utah officials said the goals can be reached less expensively by following its own regulations. Part of the state-sponsored plan was to shut down one of the company’s plants. But EPA ordered selective catalytic reduction systems installed at the two remaining coal-fired plants in Emery County.
A report released Monday by a trade group for the transmission industry calls for a new “proactive” approach to transmission planning, saying it could save consumers as much as $47 billion annually.
The report, prepared for WIRES by The Brattle Group, says traditional planning, focused primarily on addressing reliability issues over a five- to 10-year horizon, is too myopic and results in “piecemeal projects instead of developing integrated and flexible transmission solutions that enable the system to meet public policy goals more cost effectively.”
The paper says a more proactive approach is desirable regardless of whether generation changes because of energy markets, technology or EPA’s Clean Power Plan.
After allegations of management interference led PJM to replace its internal market monitoring unit with an independent monitor in 2008, FERC had an opportunity to prohibit other RTOs from using the internal structure. Because it chose not to do so, the temptation for RTO officials to muzzle their MMUs remains.
Second in a Series
By Rich Heidorn Jr.
Joe Bowring and David Patton often disagree, as anyone who has watched a FERC technical conference featuring the two independent market monitors can attest.
But while the two — both Ph.D. economists — may clash over seams issues or the virtues of forward capacity markets, they are 100% in agreement on the need for independence in market monitoring.
“I don’t know how we would do this job effectively if we weren’t independent,” said Patton, whose Potomac Economics provides market monitoring for MISO, ISO-NE, NYISO and ERCOT and has done occasional work for CAISO and SPP.
“You cannot do your job as a market monitor if you’re not independent, if you’re not free to criticize the RTO and its members, if you’re told to pull your punches,” agreed Bowring, whose Monitoring Analytics serves as PJM’s monitor.
Stormy Beginning
Monitoring Analytics was born in 2008, after Bowring — then a PJM employee — complained at a FERC technical conference that then PJM President Phil Harris and his allies were attempting to muzzle him. Bowring accused PJM management of censoring his reports, preventing him from presenting his views to a stakeholder committee, raiding his staff and threatening to disband the MMU altogether.
“PJM has made it clear that, from management’s perspective, the market monitor is first an employee of PJM with all the duties of an employee including obeying management orders, i.e. following the chain of command,” Bowring told the commission. “Based on my experience, it is not possible, as a practical matter, to maintain the independence of the MMU while leaving the control of personnel decisions, including hiring, firing, reviews and promotions, with RTO management.”
State consumer advocates, the PJM Industrial Customer Coalition and several electric cooperatives filed a request for a show cause order requiring PJM to answer Bowring’s allegations (EL07-56). State regulatory commissions and the Organization of PJM States Inc. (OPSI) followed about a week later with a complaint seeking a FERC investigation (EL07-58).
“The independence of the PJM MMU is of paramount importance because a wholesale market that is not competitive and not resistant to market power allows market participants to exercise market power and demand monopoly prices from customers to the detriment of the public,” the OPSI complaint said.
The settlement called for Bowring — who previously worked at New Jersey’s Board of Public Utilities and Division of Rate Counsel — to form an independent company, which was awarded a six-year contract as PJM’s market monitor (EL07-56, EL07-58).
The PJM Board of Managers was given limited authority over the monitor — specifically, the power to review its budget and to decide whether to retain or replace the firm at the end of the initial term.
2013 Skirmish with PJM Board
The settlement did not end all conflicts. Both Bowring and PJM Board Chair Howard Schneider are strong-willed personalities and can be blunt when they disagree. Bowring also disagrees frequently and forcefully with PJM officials at stakeholder meetings.
Tensions flared anew in 2013 when the board attempted to issue a request for proposals to shop for potential alternatives to Bowring’s firm after the initial six-year term.
It’s doubtful the RFP would have generated many responses. Market monitoring requires an analytical infrastructure that few firms possess, and many of those that do would be prevented from bidding because they have market participants as clients. When the Public Utility Commission of Texas issued an RFP last year for monitoring of ERCOT, only incumbent Potomac Economics submitted a bid.
Nevertheless, state regulators, industrial consumers and cooperatives reacted with alarm to the draft RFP, saying it contained language that would undermine the independence and quality of the monitoring function. They sent letters to the board praising Monitoring Analytics’ performance and threatening to protest to FERC.
The board dropped the RFP in response to the outcry, signing a new contract with Monitoring Analytics running through 2019. (See PJM, Monitoring Analytics Sign New Contract.)
At the OPSI annual meeting in October 2013, Bowring and Schneider symbolically buried the hatchet. The two shared the dais with then-Maryland Public Service Commissioner Lawrence Brenner, chairman of OPSI’s Market Monitoring Committee, who had intervened in the contract dispute.
Brenner said he was happy to be able to call Bowring the “current and future market monitor,” prompting Schneider to interject — “current and future king” — with a chuckle.
“He has managed to annoy just about everybody in this room,” Robert Hanna, then president of the BPU, said of Bowring. “To me that’s a very good sign. He’s not in the tank for anybody. He does it in a principled way and he lets you know the basis.”
Patton not Shy About Criticizing Clients
David Patton hasn’t gotten involved in such drama since founding Potomac Economics in 2001 after stints at the Department of Energy and FERC.
But like Bowring, he has not been shy in criticizing the grid operators that hired him.
Patton’s first client was NYISO, followed in 2003 by ISO-NE and ERCOT in 2005. His firm also has done work for CAISO and SPP. It employs more than two dozen employees, most in its Fairfax, Va., headquarters, with several others in Texas and at MISO headquarters.
The firm’s role varies by region. At ISO-NE, for example, the internal monitoring staff of 20 handles day-to-day monitoring and market power mitigation; produces monthly, quarterly and annual markets reports assessing market competitiveness and making recommendations; and conducts investigations of participant behavior and refers violations to FERC’s Office of Enforcement. Patton’s firm produces monthly and quarterly reports for internal use and an annual public assessment critiquing market performance and making recommendations.
The company provides virtually all monitoring for MISO, NYISO and ERCOT. (The monitors work in ERCOT’s headquarters in Austin.)
All recommendations from Potomac are considered in the NYISO’s annual project prioritization, a stakeholder process in which costs and benefits are weighed to determine the highest priority projects for the upcoming year.
Recommendations
It can take a while for monitors’ recommendations to result in changes — if ever. When MISO did a periodic review of Patton’s recommendations last August, 22 were pending, some dating back to 2005. (See What Happens to All Those MISO Market Monitor Recommendations?)
As of March, about one-quarter of Bowring’s recommendations between 1995 and 2015 had been fully adopted by PJM. (See Bowring Urges Return to ‘Fundamentals.’)
“This is the one job I can think [of] where an economist can not only just observe something they have no control over, but observe, draw conclusions and contribute to improving the performance of the market by making recommendations,” Patton said in an interview in his office. That, he said, “is extremely satisfying.”
“Because we’re independent of the RTO and the participants and FERC, we are in the position to be completely objective about what we see, what we think is right,” he continued. “We have no client that has an interest that we need to worry about. Our client is the market and our objective is to maximize the competitiveness and the efficiency of the market.”
Virtues of Independence
The RTO itself, Patton notes, is one of the entities the monitor is charged with policing. “Nobody affects the market more than the RTO does, with the decisions that they make as they operate the market; the reliability actions they take; the parameters they set in the software. And a lot of those actions are nonpublic; they can’t be observed by participants. So I’ve always viewed one of the most important jobs we have is to monitor what the RTO is doing and ensure that the RTO is following its own Tariff and not exceeding the authority provided under the Tariff, and not engaged in actions that could conceivably be deemed manipulative. … I don’t know how you would do that effectively as an internal market monitor.”
Patton said that independence also allows him to take positions that may be unpopular with stakeholders.
“We can get out in front and propose things that the stakeholders might come around [to], like the sloped demand curve, or that FERC, frankly, might take up and compel the RTOs to address,” he said.
Patton said internal MMUs are subject to what he called the “the customer satisfaction conflict.”
“Because RTOs are voluntary and FERC has not enforced a very high standard on entities that want to leave RTOs or switch RTOs, the RTOs have a pretty strong incentive to make their customers happy. Generally, that’s a really good thing. But a lot of what you do as a market monitor may make individual customers or groups of customers very unhappy,” Patton said.
CAISO declined to provide budget totals for its Department of Market Monitoring, saying that while it makes division budgets public, it does not do so for individual departments. CAISO also declined to provide the budget for its Market Surveillance Committee, an advisory group, calling it “proprietary.”
Indeed, SPP saw Entergy spurn it for MISO in 2014, after acting as the company’s independent coordinator of transmission for more than seven years. MISO member American Transmission Systems Inc. moved to PJM in 2009, followed a year later by Duke Energy Ohio and Duke Energy Kentucky. Just last month, Dynegy called on Illinois legislators to approve a bill that would move Central and Southern Illinois to PJM from MISO. (See Dynegy Introduces Bill to Move All of Ill. Into PJM.)
“So I think it’s a benefit for the RTO and for us to be independent,” Patton continued. “If [the monitor] is a group of employees of the RTO, then it’s pretty easy for the customers to be upset with the RTO when something happens that they’re not happy with. So that conflict is nearly completely resolved by having the market monitor be independent.”
Patton has demonstrated his independence repeatedly in his criticism of MISO’s capacity market.
“The economic theory underlying a three-year forward procurement is not sound,” he said. “The notion that … new participants can offer efficiently in that auction and have that guide their decision to invest when you’re giving them a one-year contract on a 40-year asset is” unproven.
He has long proposed that MISO switch from a vertical to a sloped demand curve.
At MISO’s Annual Meeting last June, Patton engaged in a debate with board members Michael Curran, Judy Walsh and Paul Feldman over the issue. (See MISO Monitor Debates Capacity Rules with Board.)
At the end of the meeting Curran thanked Patton for his analysis, but couldn’t resist a little jab. “You’re going to have a sloped demand curve on your tombstone.”
“Cause somebody’s going to kill me?” Patton responded, laughing nervously.
“No,” Curran said. “This is the Midwest. These are nice people.”
– Tom Kleckner, William Opalka and Amanda Durish Cook contributed to this article.
INDIANAPOLIS — FERC last week accepted a generation interconnection agreement between MISO and the first utility-scale battery storage project in the footprint.
The commission approved a GIA for Indianapolis Power & Light’s Harding Street Station Battery Energy Storage System, which is planned to go online this month, in spite of IPL’s protests that the project was being mischaracterized. IPL had urged the commission to view the storage facility as a transmission asset.
The agreement isn’t a straightforward storage-to-grid situation. The contract includes Harding Street’s two existing gas turbine generators — designated as black start resources — alongside the newly constructed 20-MW storage facility. The batteries — eight 2.5-MW blocks — will use the existing interconnection facilities of the two existing gas turbine generator units, which connect to the Harding Street South substation. The commission accepted the GIA “in the interest of expeditiously connecting the battery facility to MISO’s transmission grid” but said that it will not create a precedent for future storage facilities (ER16-1211-001).
“The Harding Street GIA is narrowly focused on the terms necessary to interconnect Indianapolis Power’s battery facility and two existing combustion-turbine generators; the commission’s action in this proceeding, therefore, does not prejudge potential improvements to the procedures or agreements that govern the interconnection of electric storage resources in the future,” FERC explained.
Comprehensive Market Rules Needed
The commission also said that more comprehensive market rules for storage are needed.
“Although we accept the Harding Street GIA … we appreciate that MISO’s pro forma GIA was not originally intended to govern the interconnection of electric storage resources to MISO’s transmission grid,” the commission said.
MISO and IPL disagreed over whether the pro forma agreement was an appropriate vehicle for the project. The RTO contended interconnecting under the GIA was correct, while the utility insisted that the storage facility should not be subjected to GIA provisions or referred to as a “generating facility.”
FERC said a “generating facility” designation was appropriate because the pro forma definition includes “device(s) for the production and/or storage for later injection of electricity identified in the interconnection request.” The commission also pointed out IPL’s battery storage was bundled with two other generating units. However, the commission ordered MISO to add one instance of “energy storage resource” to the agreement.
MISO regarded the battery facility as an upgrade because it shares the same interconnection facilities as the existing generation. IPL had objected to this treatment, maintaining that the non-generating battery facility is a transmission asset that provides ancillary services.
IPL had also argued that the GIA’s appendix does not apply to storage, but FERC decided it was unnecessary to “delete non-applicable provisions of a pro forma GIA.”
The agreement was approved as MISO is considering expanding its definition of demand response resources to include medium-term energy storage. In April, stakeholders urged MISO to develop a cost of new entry for storage technology. MISO said a final proposal to change Tariff or Business Practices Manual revisions to accommodate near-term storage would be presented late summer or early fall. (See MISO Stakeholders Provide Ideas on Incorporating Storage.)
The company vehemently denied allegations made by Attorney General Eric Schneiderman that it encouraged illegal tree cutting by landowners in defiance of a FERC prohibition, calling the complaint “part of a pattern seeking to delay construction.”
Dynegy has closed its 500-MW Wood River Power Station near Alton, Ill., eliminating more than 90 jobs.
American Electric Power’s Appalachian Power has signed on to a 20-year power purchase agreement with NextEra Energy to buy 120 MW of wind generation in Indiana to supply its service areas in Virginia and West Virginia by 2018.
Wind turbine manufacturer Broadwind Energy has been awarded a three-year $137 million supply deal with an unnamed customer.
Pacific Gas and Electric last month left a “treasure trove” of company data open to Internet hackers, according to a security researcher who revealed the lapse.
The Missouri Joint Municipal Electric Utility Commission, which buys power for public utilities, said it has signed an agreement for as much as 200 MW of capacity on Clean Line’s Grain Belt Express, bolstering the transmission line’s embattled application with the Missouri Public Service Commission.
Westar Energy CEO Mark Ruelle said Great Plains Energy was the only bidder among multiple suitors that agreed to keep the utility’s headquarters in downtown Topeka, Kan., one of the deciding factors in choosing it as its $8.6 billion merger partner.
“This is another major step in broadening our nation’s energy portfolio, harnessing power near population centers on the East Coast,” Interior Secretary Sally Jewell said.
The D.C. Circuit Court of Appeals on Friday ruled that the Nuclear Regulatory Commission followed all necessary rules when it wrote the regulation allowing long-term storage of spent fuel at nuclear generating stations.
The discovery of the failure of more than a quarter of the bolts used to secure baffles crucial to channeling cooling water in Entergy’s Indian Point 2 reactor has spurred an investigation into what caused it and what the company is doing in response.
EPA decided Wednesday that two Rocky Mountain Power coal-fired plants must install pollution controls to improve atmospheric visibility near national parks. The company, which said it would cost $700 million to comply with the ruling, said it is reviewing its legal options.
The commission approved a GIA for Indianapolis Power & Light’s Harding Street Station Battery Energy Storage System, which is planned to go online this month, in spite of IPL’s protests that the project was being mischaracterized. IPL had urged the commission to view the storage facility as a transmission asset.