MISO’s Board of Directors last week approved a $2.5 billion transmission expansion plan funding 369 projects, including a 500-kV line to carry Canadian hydropower to Minnesota Power customers.
The $676 million Great Northern Transmission Line is the single most expensive project in MISO’s 2014 Transmission Expansion Plan, the product of 18 months of work by MISO stakeholders. The line, which will connect the Manitoba border to the Minnesota Iron Range, is set for completion around 2020.
The plan also includes 50 baseline reliability projects totaling $269.5 million, six generator interconnections totaling $38 million and 312 “other” projects totaling $1.5 billion, including those supporting lower-voltage transmission systems.
The plan will allow for the interconnection of 726 MW of new wind generation and import of 883 MW of hydroelectric power from Manitoba, said Jennifer Curran, MISO’s vice president of system planning and seams coordination, in a memo to the board.
Interconnection requests are shifting from predominately wind to a mix of natural gas and wind, as gas-fired generation steps in to replace coal plants forced to retire or switch fuels because of federal environmental rules, MISO said. Natural gas interconnection requests in MISO soared to 9,424 MW this year, from 1,994 MW in 2011.
There also have been about 810 MW of new solar request interconnections in 2014. “This could be the result of recent federal energy legislation and the economic stimulus package, and the lower price of solar photovoltaic modules,” the MISO plan states.
MTEP 14 was the first planning cycle that included full participation of MISO’s south region in economic and reliability planning.
The south region is targeted to receive about $359 million in transmission investments, including two of the largest projects in MTEP 14: a $60 million, 115-kV line by Entergy in Mississippi, and a $56.3 million, 230-kV line in Louisiana.
Since MTEP ‘03 about $19 billion of transmission project investment has been identified, with roughly 40% of it completed. MTEP 14 covers projects expected to be completed by 2023.
If you want to know why many think that demand response hasn’t fulfilled its potential in MISO, talk to Brian Helms.
Helms, the director of energy services at new MISO member Century Aluminum, said that when he attended a MISO workshop he was unable to get an answer about what form of approval would be needed to register his plant as a Load- Modifying Resource. And when he asked his local utility how to sign up, it told him it wasn’t interested.
“The path to providing those resources is kind of tortuous and murky,” Helms recounted at the MISO Advisory Committee’s “hot topic” discussion on demand response last week.
The committee sought stakeholder input on how to make the most of demand response programs, and whether MISO should take any action while waiting for final word on whether last May’s appellate court ruling voiding the Federal Energy Regulatory Commission’s Order 745 will stand.
Unlike PJM, most of MISO’s demand response assets are administered through state programs. While that means less disruption if the D.C. Circuit Court of Appeals ruling in the Electric Power Supply Association v. FERC case stands, stakeholders told the committee the disparate state rules make it more of a challenge for the RTO to maximize such resources. (The D.C. Circuit yesterday granted the U.S. Solicitor General’s request for more time to seek a Supreme Court rehearing of the case.)
Representing end-use customers, DeWayne Todd, energy services manager at Alcoa in Newburgh, Ind., said that MISO has done a good job of integrating available Load-Modifying Resources through legacy interruptible electric service rates.
Demand Response Resources ‘Untapped’
But Demand Response Resources are largely untapped in the energy and ancillary services markets due to retailers’ restrictions on participation and compensation, the End-Use Sector said. They cited the Independent Market Monitor’s State of the Market report, which shows there are just 75 MW of controllable Demand Response Resources — all attributable to Alcoa, which often interrupts production when electric price signals rise. (See chart.)
“I think there’s a huge opportunity, and not just [in] smelting, but other customers and consumers, as well,” Todd said.
The Environmental Sector agreed, saying MISO’s minimum threshold of 5 MW for participation in energy and ancillary services markets is too high. PJM’s threshold, they noted, is 100 kW.
The Environmental Sector recommended MISO employ demand response as a “transmission-like resource” in its planning, saying DR resources could help maintain reliability at lower cost than System Support Resources while longer-term transmission or generation solutions are implemented. “DR can also reduce or eliminate the need for costly transmission upgrades, or be paired with a transmission upgrade or voltage support to help eliminate potential reliability issues,” it said.
Aggregators ‘Frozen Out’
The environmentalists lamented that third-party providers, which play a big role in PJM, are “largely frozen out” of MISO’s markets. Among MISO states, only Illinois permits aggregators of retail customers (ARC) to participate, they said.
The Organization of MISO States said MISO “has done an adequate job of meeting FERC requirements for DR, while balancing stakeholder desires for sometimes conflicting market parameters.”
It urged the RTO to work with market participants to accommodate new demand response technologies and remove barriers to participation. OMS cited methods of directly controlling customer-owned electric water heaters to support grid reliability. Participants “would like to develop programs to offer this DR in MISO’s ancillary services market, however current MISO protocols, relating to metering and zonal boundaries, may be prohibiting participation,” OMS said.
The Transmission-Dependent Utilities Sector said MISO has allowed DR fair access to its markets and said load-serving entities should continue to have the option to operate their DR programs at the retail level, without offering it as a wholesale product.
Reliability Benefits
The Public Consumer Group acknowledged that the state-by-state variation in demand response programs is a challenge for MISO but that the RTO should nonetheless make increasing DR a top priority, saying such resources could aid reliability and reduce rates.
During last winter’s polar vortex, the group said, MISO did not even consider calling on DR resources, unlike PJM. “As a result, capacity margins were unnecessarily tight, and prices, which were ultimately passed on to consumers, were likely higher than necessary,” it said. “In addition to paying higher prices when DR is not called upon in near-emergency circumstances, end-use consumers in MISO are not getting appropriate use of DR resources for which they are paying in their rates. … Because DR is so rarely called upon, customers are not enjoying the full value of these resources.”
IPPs: Demand Response Has No Place on Supply Side
MISO’s independent power producers took a position similar to that of generators in PJM and ISO-NE, citing the EPSA ruling in arguing that demand response has no place in the supply side of wholesale markets. “MISO will need to establish parameters for load-serving entities and state regulators in order to use these assets focusing on their primary function: load modification, also known as load shaving,” they said.
“There’s a lot of uncertainty, but it’s pretty clear if you look at ISO New England and PJM, they’re being very proactive in what they’re doing with DR and moving it back over to where it traditionally was prior to the advent of organized wholesale markets,” Mark Volpe, senior director of regulatory affairs for Dynegy, told the committee.
Advisory Committee Vice Chairman Kevin Murray said that’s problematic.
“You could take an approach as Mark suggested and force all the demand response back on to the load side of things,” he said. “The problem with that, as MISO has observed, [is] it produces a result where it’s not integrated into MISO’s market when it’s dispatched, [and] it has the effect of reducing load, [depressing] prices during a point in time when the system is stressed during an emergency.”
A number of commenters noted that DR programs among the states differ widely, with some going back decades.
Directors Judy Walsh and Michael Curran said MISO might consider offering incentives to replace the many differing utility contracts with a model that would be easier for MISO to manage.
“I wonder if there’s a way to structure a new opportunity for these players where they would opt-in to some other opportunity to participate in the market where in fact [they] get paid for participating,” Walsh said. “Perhaps we could move out of these old contracts.”
The Federal Energy Regulatory Commission will hold four technical conferences next year to discuss the effects of the Environmental Protection Agency’s Clean Power Plan on reliability and wholesale electricity markets.
FERC announced the conferences in response to a request from three Republican lawmakers, including Alaska Sen. Lisa Murkowski, who will likely become the chair of the Energy and Natural Resources Committee when Republicans take control of the Senate in January. The Republicans said in a letter to FERC that the EPA “lacks the mission and the expertise to determine what is necessary to maintain the reliability of the nation’s electric grid.”
The first conference will be held on Feb. 19, with a “National Overview” session led by the commission itself. It will be a part of FERC’s monthly open meeting, which will start an hour earlier to accommodate the conference. Staff will conduct three more regional conferences in D.C., St. Louis and Denver on dates to be announced.
Participants in the first conference will discuss whether state regulators “have the appropriate tools to identify reliability and/or market issues that may arise” as a result of compliance with the plan, as well as how to coordinate with RTOs on how to comply.
“The commission clearly has a role to play in ensuring that the nation’s energy markets and infrastructure adapt to support compliance with the proposed Clean Power Plan,” FERC Chairman Cheryl LaFleur said. “These technical conferences will be an opportunity for the commission to hear from a wide range of stakeholders across the country on issues related to reliability, market operations and energy infrastructure.”
Murkowski said she appreciated FERC announcing the conferences. The conferences are “no substitute for EPA’s failure to engage FERC and [the Department of Energy] in a formal, documented process to address the impact on electric reliability of EPA’s series of major rulemakings in recent years,” she said.
“I remain hopeful, however, that the conferences will be useful to develop a better public record on these crucial questions, and I will remain as vigilant on this issue as I have been since 2011.”
Republicans have made blunting the EPA’s Clean Power Plan a top priority for when they take full control of Congress, following a wave of Republican victories in Senate elections in November. (See GOP Election Victories Unlikely to Thwart EPA Carbon Plan.) One of the casualties was Sen. Mary Landrieu (D-La.), the current chair of the Energy Committee. (See related story, Honorable Clears Senate Energy Committee.)
PJM on Friday filed its long-awaited Capacity Performance proposal with the Federal Energy Regulatory Commission, a two-docket, 1,275-page capacity market overhaul that it hopes will prevent a repeat of last January’s poor generator performance.
EL15-29, filed under sections 205 and 206 of the Federal Power Act, contains proposed changes to PJM’s Operating Agreement and Tariff “to correct present deficiencies in those agreements on matters of resource performance, and excuses for resource performance, in the wholesale markets administered by PJM.”
ER15-623, filed under section 205, proposes changes to the Reliability Pricing Model rules in the Tariff and Reliability Assurance Agreement.
PJM will ask the Federal Energy Regulation Commission this week to raise the cost-based energy offer cap to $1,800/MWh through March 2015, CEO Terry Boston said in a letter to members Tuesday.
The proposal, authorized by the Board of Managers, would let offers up to $1,800 set clearing prices. Generators could recover “justifiable costs” above $1,800 through make-whole payments, but such offers would not set prices for other market participants.
The Section 206 filing comes after stakeholders failed over eight months to reach consensus on changes to the current $1,000/MWh cap.
The issue resulted from the spike in gas prices last January, which pushed some generators’ costs above $1,000. FERC granted PJM’s request for a waiver from the cap to allow some gas-fired generators to cover their costs.
“We believe this action is prudent preparation for the possibility of high fuel costs that could result in generating sources not recovering their costs despite producing power when most needed to meet high demand,” Boston wrote.
Although PJM is not expecting the same weather extremes this winter, Boston wrote, “seeking approval for a higher cap through this winter [allows PJM] to avoid any possibility of having to scramble to submit waivers that seek FERC decisions in 24 hours.”
Boston noted that the concept of allowing cost-based offers in the energy market to set prices up to $1,800/MWh mirrors the proposal presented at the Nov. 20 Members Committee. Old Dominion Electric Cooperative’s Ed Tatum — who negotiated the proposal with Gabel Associates’ Mike Borgatti — withdrew it after it became clear it had little support from members representing load. (See Last Ditch Effort to Break PJM Offer Cap Deadlock Fails.)
Boston said PJM limited its proposed change to the coming winter “in anticipation of FERC developing a longer-term solution to offer cap issues from a national perspective over the next year.”
State Reviewing Company’s Plan to Use Corn-Based Ethanol at New Plant
State environmental officials have agreed to a special review of a company’s plan to make ethylene oxide at a proposed riverfront plant south of Wilmington rather than import the hazardous chemical on rail cars from Gulf Coast refineries.
Croda, a specialty chemicals producer, wants to build a new processing unit at its Atlas Point plant near the Memorial Bridge to convert corn-based bio-ethanol, or alcohol, into ethylene oxide. Croda uses ethylene oxide as a raw material in it production process. The $170 million project could provide 200 temporary jobs and up to 80 permanent ones.
The plan needs a review under the state’s Coastal Zone Act, passed in 1971, which prohibits industrial use of land near the Delaware River, Bay or coastline, and limits use at existing plants.
The Commerce Commission unanimously approved an ambitious direct-current transmission line to deliver power from Iowa wind farms, putting the $2 billion Rock Island Clean Line one step closer to construction.
The 500-mile line, proposed by Clean Line Energy Partners, is the first merchant-owned transmission project approved by the ICC. The project, which advocates say would cut energy prices and help the state meet renewable energy goals, still needs approval from Iowa, where the line would cross 16 counties and local opposition is forming.
But in Illinois, even the Sierra Club endorsed the line. “The project will deliver pollution-free power to Illinois homes and businesses and create good jobs in clean-energy technologies,” said Jack Darin, director of the Illinois chapter of the Sierra Club.
Senate Approves Ameren, Com Ed Smart Grid Rate Plan Extension
The state Senate approved a plan that will allow Ameren Illinois and Commonwealth Edison to raise rates to pay for smart grid improvements through a formula, bypassing potentially lengthy rate-setting procedures with the Commerce Commission.
The legislation extends a law allowing the two companies to recover money used to bolster grid reliability, including paying for smart meters. The rate provision is set to expire at the end of 2017, but the bill approved in a 40-4 Senate vote would extend that through 2019. Gov. Pat Quinn, whose veto on the original smart-grid law was overridden, could veto the current legislation too. Legislators have already been sent home for the session, so it’s unlikely the body would have an opportunity to override a veto this time.
A consumer group, the Citizens Utility Board, opposed the extension. “We’ll be talking to the governor about our concerns,” said David Kolata, the board’s executive director.
Co-ops and IOUs Want to Block Munis from Gaining Through Annexation
A turf battle is brewing in the state between municipal electric providers and rival distribution companies.
Rural electric cooperatives and some investor-owned utilities are backing a legislative proposal to block municipal providers from expanding service into territories newly annexed by their cities and towns. Co-ops control about 80% of customers in the state and want to make sure they don’t lose any customers as municipalities push out their borders.
A 2002 law allows municipals to petition the state Utility Regulatory Commission to take over systems in annexed territories. But Sen. Mike Crider is working on a bill to limit the ability of municipal providers to expand. Municipal operators, who now control about 7% of the market, question the need for such a bill. “I haven’t seen cities all of the sudden taking their territory,” Columbia City Mayor Ryan Daniel said. “This sure seems like a monopolistic situation.”
Gov. O’Malley Says He’ll Set Rules for Fracking Before Leaving Office
Outgoing Gov. Martin O’Malley said he will propose strict regulations for natural-gas development in Western Maryland before he leaves office. The O’Malley administration, which issued a draft report on Marcellus Shale drilling, said it is preparing regulations using “best practices” from other states, including restrictions on drilling locations and rules to limit water and air pollution.
The report gives guarded approval of the viability of fracking in the state, saying that “the risks of Marcellus Shale development can be managed to an acceptable level. Some of the proposed best management practices have not been tested, and although we are confident that they will reduce the risks, some risks will remain, as is the case with all industrial activities.”
Governor-elect Larry Hogan said he favors gas development in “an environmentally sensitive way,” but environmentalists are concerned that he will loosen some of the restrictions when he takes office. “The fact that we have a governor-elect who wants to move forward on fracking means we want to get some protections in place as soon as possible,” said Karla Raettig, executive director of the Maryland League of Conservation Voters.
UP Residents on Hook for Higher Fees to Pay for Presque Isle Plant Output
Upper Peninsula electric customers this month began paying most of the $97 million in annual costs to keep the Presque Isle power plant in Marquette operating.
Grid operator MISO ordered We Energies of Milwaukee, which owns the plant, to keep it operating to maintain grid reliability. We Energies had threatened to shut the plant after it lost several large industrial customers to competitors. We Energies customers in Wisconsin successfully petitioned FERC to be excluded from obligations to cover the plant’s cost, shifting the burden to customers on Michigan’s Upper Peninsula, who are protesting.
Widespread Power Outage Points to Need for Grid Improvements in Detroit
A major cable failure on Detroit’s waterfront left a large swath of the city’s buildings and traffic signals without power for most of a day just before Thanksgiving, illustrating the need to update the aging municipal system’s infrastructure.
A cascade of failures of the city’s Public Lighting Department system caused schools to close, hospitals to divert patients and the Wayne County Jail to use emergency backup power. The lighting department, which distributes power to 890 public buildings, five multi-unit apartment buildings, 1,000 traffic lights and public emergency communications systems, is undergoing a $200 million four-year upgrade financed by DTE Energy, which will take over the municipal system.
“Everybody is aware the system has not gotten the attention it needed over the past several decades because of the city’s ongoing financial problems,” DTE Spokeswoman Randi Berris said. “One of the key reasons why this migration is happening is because DTE can provide the reliability and affordability to the customers that are on the system.”
Lawmakers Craft Bills to Protect Customers from Crafty 3rd Parties
State lawmakers are considering a three-bill package that would tighten regulation of third-party energy providers in response to consumer complaints about dramatic spikes in energy charges during last winter’s extreme cold.
The legislation would require a more understandable explanation of prices from different suppliers, allow customers to switch providers with 30 days’ notice and force the development of a standard, easy-to-read contract. The legislation mirrors the administrative efforts of the Board of Public Utilities to enact tighter regulations on suppliers.
“There needs to be more transparency in the process,’’ said Assemblyman Tim Eustace, a co-sponsor of the package. “We want consumers to continue to make their own choices with clear rules and regulations in place to guard residents who enter into these contracts with chosen suppliers.”
McBride Energy to Build 80-MW Solar Project near Concord
The state Utilities Commission gave McBride Energy Services permission to build a $200 million, 80-MW solar plant near Concord, the latest commercial solar project to win approval in North Carolina.
The proposed McBride Place Energy Project could be operational by the end of next year. If so, it could qualify for tax credits and depreciation allowances totaling more than $100 million. McBride, which has concentrated on much smaller projects in the past, is searching for a buyer of the power.
The Public Utilities Commission has granted American Electric Power a special hearing on Dec. 17 so the company can explain why it thinks it should get a guaranteed rate of return, funded by ratepayers, on one of its merchant plants.
AEP told the commission earlier this year that it wants ratepayers to cover any above-market costs of its coal-fired Kyger Creek plant. Customers would also get a credit if the plant generated excessive returns. AEP says it needs the guarantee to keep the plant in operation to support the regional power grid. Environmentalists and consumer advocates say it’s an unneeded subsidy that would prolong the life of a coal plant.
AEP’s filing is considered a test for the commission. FirstEnergy and Duke Energy have also filed requests for rate guarantees for marginal power plants. The commission has delayed ruling on AEP’s request, which was initially filed nearly a year ago.
State Gas, Oil Production Shows Steady 3rd Quarter Increase
Wells tapping into the state’s oil and shale gas fields produced 3 million barrels of oil and 132 billion cubic feet of natural gas during the third quarter, according to a state report issued last week. That’s an increase of about half a million barrels and 43 billion cubic feet over the previous quarter. The success rate of wells drilled is impressive as well, according to the report. Out of 717 wells drilled in the state’s Utica and Marcellus shale formations, 674 are producing.
PGW Deal Dead After UIL Pulls Out in Face of City Council Opposition
UIL Holdings, the company that agreed to pay $1.86 billion to buy the city-owned Philadelphia Gas Works, said Thursday it was pulling out of the deal because of opposition from the city council. Not a single member of the council stepped forward to introduce Mayor Michael Nutter’s legislation to approve the sale, which was required for the deal to conclude.
“We are extremely disappointed that no ordinance was introduced to approve the acquisition, and we’re equally disappointed that we were not afforded a hearing to present the facts regarding our bid proposal,” UIL President and CEO James P. Torgerson said.
The announcement triggered a flurry of finger pointing.
“The citizens of our city, the customers of PGW and our own city workers will feel the negative effects of this terrible indecision for years to come, and ultimately will regret that city council chose to end a legitimate debate on this issue even before it started,” Nutter said.
Council President Darrell L. Clarke blamed the mayor for the deal’s demise. “Once again, the Nutter administration has learned that the birthplace of American democracy has little tolerance for sweeping policy decisions made unilaterally with no input from the public,” he said.
An 86-year-old woman from Dunmore was killed early Thursday by an explosion that destroyed her home as she waited on her porch for somebody to pick her up after a gas leak was reported in the area.
A water main break had been reported in the area when residents detected the odor of gas. Emergency responders were organizing an evacuation when the explosion destroyed several buildings. Madlyn Mecca, who had called for somebody to come get her, died when her home exploded as she waited, according to neighbors.
UGI, which provides gas service in the Scranton suburb, was investigating the deadly explosion.
State Regulators Approve ‘Standby Fee’ for Using Solar
The State Corporation Commission has approved a plan for Appalachian Power to charge home solar users a fixed charge of up to $100 a month to reflect their use of the energy grid, no matter how much net power they consume from the distribution system.
The plan would only apply to homeowners whose solar setups produce more than 10 kW. An Appalachian spokesman said only five customers would be affected. The idea is to charge those customers whose solar arrays put power back into the grid for resale, offsetting their own energy consumption. The utility argued that such customers should pay for the use of the grid.
WASHINGTON — Colette Honorable, President Obama’s latest nominee for the Federal Energy Regulatory Commission, appeared headed toward Senate committee approval last week after a confirmation hearing that saw Republicans and Democrats praise her “moderate” views on fossil fuels and her pledge to put a high priority on grid reliability.
Less clear was whether the full Senate will vote to confirm Honorable before it adjourns. Sen. Ron Wyden, an Oregon Democrat who led the Thursday hearing of the Senate Energy and Natural Resources Committee, promised “to do everything we possibly can to see if we can get you confirmed before Congress wraps up.” The 113th Congress is scheduled to close on Dec. 12, but Majority Leader Harry Reid (D-Nev.) said he may extend the session by a week or more to assure votes on key measures.
A Democrat, Honorable has been a member of the Arkansas Public Service Commission since 2007 and its chairman since 2011. She recently concluded a term as president of the National Association of Regulatory Utility Commissioners. Underscoring her bipartisan popularity was an introduction by Arkansas’ Republican Sen. John Boozman, who joined the state’s Democratic Sen. Mark Pryor in praising the nominee as a fair, hardworking and intelligent public servant. “It’s not just bipartisan support,” Pryor said of Honorable’s backing in Arkansas, “it’s from business, consumer groups.”
The committee announced it will meet Wednesday to vote on Honorable’s confirmation.
Some members of the energy committee pressed the nominee to pledge support for their policy views.
Sen. Lisa Murkowski (R-Alaska), who will assume the committee chairmanship in January, prodded Honorable to criticize the Environmental Protection Administration’s proposed carbon emission rule. (See related story, RTOs Raise Concerns over Reliability, Schedule in EPA Clean Power Plan.) The senator said the proposed rules “could seriously challenge the reliability of our nation’s grid system and push more Americans into energy insecurity.”
Murkowski also read from comments on the rule jointly filed by the Arkansas PSC and Department of Environmental Quality. In the comment cover letter, Honorable and the interim head of the state environmental agency said that the EPA proposal is “technically flawed” and that its goals were “unobtainable under the current time frame.”
Honorable didn’t repeat those criticisms at the hearing, but she said the rule’s implementation would require EPA and other federal agencies to cooperate with the states and utilities. She pledged to Murkowski that “I will continue to be a proud participant in our mission to ensure reliability” of the grid.
‘Significant Overreach’
Wyden, who led the hearing in the absence of Chairman Mary Landrieu as she campaigned ahead of a run-off election in Louisiana, wanted Honorable’s assurance that she would oppose an expansion of FERC Order 1000. (Landrieu lost her bid for re-election on Saturday, giving Republicans a total of 54 seats in the Senate.)
Wyden, who represents a region served mostly by the Bonneville Power Administration and other government utilities not subject to FERC jurisdiction, described the order as a “significant overreach.”
FERC has long required federal power authorities and other non-jurisdictional transmission providers purchasing open access transmission service from utilities under FERC authority to reciprocate by providing those utilities access on their own systems. Order 1000 extends this reciprocity, allowing transmission developers outside of FERC jurisdiction to propose transmission projects in the regional transmission planning process as long as that developer “abides by the same requirements as those imposed on public utility transmission providers.”
Saying she was reluctant to comment on matters that may still be pending before the commission, Honorable said that any participation in RTOs or ISOs should be voluntary and that she has been impressed by “the ability of each state to plan what works best for them.’’
West Virginia Sen. Joe Manchin, a Democrat, asked Honorable to address concerns about last winter’s polar vortex, which strained the grid’s ability to deliver power for heat. “How close are we to having a repeat?” he asked.
“I read somewhere that the grid bent but didn’t break,” she said. “We need to think not only of reliability but also resilience.”
Honorable also fielded questions about the reliability of freight rail deliveries of coal to generators, an issue she said should be addressed cooperatively by FERC and the U.S. Surface Transportation Board.
The Federal Energy Regulatory Commission has ordered NYISO to begin a stakeholder proceeding to resolve a dispute over the installed capacity market on Long Island, which was excluded from a previous attempt to address transmission congestion in the areas around New York City.
The ISO is to report its findings to FERC by June 1, 2015. FERC rejected a recommendation by the ISO’s Market Monitor that it complete tariff changes to address the issue by June.
In August 2013, FERC approved NYISO’s proposal to create a new capacity region encompassing New York City and its northern suburbs. The zone did not include the Long Island suburbs because NYISO said insufficient transmission existed there for it to participate.
Critics said Long Island (Zone K) contributes to overloading of the Upstate New York/Southeastern New York (UPNY/SENY) Interface — which led to the creation of the new capacity region — but has escaped any cost responsibility for the overloads, thus causing higher capacity prices for New York and the Hudson Valley (Zones G, H, I and J), which were included.
FERC’s order follows a February 2014 technical conference that considered whether Long Island could be modeled as an export-constrained zone for future ICAP Demand Curve proceedings.
“We agree that it would be worthwhile for NYISO and its stakeholders to explore whether a proposal can be developed that could reduce the cost of procuring capacity while meeting the NYISO [loss-of-load expectation] objective,” FERC said (AD14-6).
FERC directed the report to include points raised by the Market Monitor, which said that the ISO should be required to improve its methodology for modeling deliverability constraints and calculating local capacity requirements.
The new capacity region went into effect in May over the strenuous objections of utilities, consumer groups and the New York Public Service Commission. NYISO said it was necessary to send price signals to encourage development of additional generation and transmission in the area.
FERC agreed with NYISO that June was too soon to require tariff amendments but added “market rule changes that could reduce costs should not be unduly delayed.”
PJM’s most recent competitive window for transmission projects attracted 63 proposals from 12 entities, the majority of them transmission owner upgrades.
The second window in the 2014 Regional Transmission Expansion Plan was open to proposals addressing transmission owner criteria, 2019 baseline n-1 voltage, 2019 n-1-1 voltage and 2018 light load reliability criteria problems. The proposals address about 49 facilities with thermal violations and 69 with voltage problems in nine TO zones.
Of the 63 proposals, 43 were transmission owner upgrades (ranging in cost from $200,000 to $71 million) and 20 are greenfield projects ($6.1 million to $450 million).
The window, the result of the Federal Energy Regulatory Commission’s Order 1000, was open from Oct. 17 through Nov. 17, although PJM extended the deadline for proposals regarding violations in one area to Dec. 5.
Industrial customers, consumer advocates and state regulators called on the Federal Energy Regulatory Commission to reject a request by MISO transmission owners for a 50-basis-point adder as an incentive for their participation in the RTO.
The Nov. 6 filing by MISO and its transmission owners (ER15-358) came weeks after the commission ordered an evidentiary hearing on complaints from industrial customers that the base rate of return of MISO’s 24 transmission operators is not just and reasonable (EL14-12). (See FERC Orders ROE Hearing on MISO TOs.)
FERC made return on equity (ROE) adders available to RTO members in Order 679, a response to a Congressional mandate in the 2005 Energy Policy Act. “Subsequent commission orders have made clear that this incentive for RTO participation remains available both to new and continuing RTO members,” the TOs said.
In filings last week and in late November, opponents said that many TOs have been members of MISO for more than a decade and there’s no threat that they would leave if they couldn’t collect the adder.
“Instead, at a time when base ROEs must decrease to remain consistent with prevailing conditions in capital markets, the MISO TOs are simply using the RTO adder as a means for attempting to claw back some of that revenue,” industrial consumers from Illinois, Indiana, Minnesota and Wisconsin said in a Nov. 28 filing.
They contend that electric customers would pay about $50 million annually toward the adder without any corresponding benefits. “The MISO TOs have not demonstrated whether an additional $50 million in revenue each year plays a pivotal role in their economic analysis of MISO membership.”
The Organization of MISO States also filed a protest to the proposed adder, saying it “appears intended to mitigate against any refunds that may result” from the pending ROE reduction case.
OMS said the adder should be awarded only when it influences decisions to join or remain in an RTO. “The historical record has simply shown there are no instances of MISO members leaving its membership except to transfer to a different RTO,” OMS said.
OMS asked the commission to consolidate the adder filing with docket EL14-12, contending “that the TOs’ waiver and deferral requests clearly demonstrate the linkage between the RTO adder and the level of the base ROE and the zone of reasonableness.” A settlement conference in the ROE case is set for Dec. 16.
A number of other groups also have asked FERC to deny the adder, including Hoosier Energy Rural Electric Cooperative, Southern Illinois Power Cooperative and Dairyland Power Cooperative. They contend that the TOs included no rate of return analysis as part of the adder request.
FERC opened the door to ROE fights in June, when it changed the way it sets ROE rates for electric utilities to a two-step discounted cash flow methodology similar to what it uses for natural gas and oil pipelines. (See FERC Splits over ROE.)
