MISO stakeholders will complete voting on June 16 on three options for responding to the Federal Energy Regulatory Commission’s final rule on coordinating gas and electric schedules (RM14-2, Order 809). MISO could post ballot results as early as June 19 and announce a decision by June 30 for discussion at the July 7 Market Subcommittee meeting.
Order 809 moved the timely nomination cycle deadline for scheduling gas transportation from 11:30 a.m. to 1 p.m. CT (from 12:30 p.m. to 2 p.m. ET). It also added a third intraday nomination cycle.
MISO and other RTOs are required to make compliance filings by July 23 that move the clearing and posting of the day-ahead market’s results to before the timely nomination deadline — or explain why it is not appropriate within their footprint. During a joint meeting last week of the Market Subcommittee and of the Reliability Subcommittee, Jeff Moore of Ameren asked MISO officials to what degree stakeholder votes will influence MISO’s final decision. “Is MISO going to consider themselves bound by the stakeholder vote? Are there other considerations?”
Kevin Vannoy of MISO said stakeholder votes “are very important to us” but noted a number of considerations are in play, including alignment with other RTOs and scheduling, staffing and market administration issues.
Moore said his takeaway from a natural gas availability study presented earlier in the week led him to believe natural gas supplies appear to be adequate in MISO in the years ahead and asked whether that would affect MISO’s decision regarding the three options presented for the day-ahead market.
“That’s something we’ll discuss as part of our final decision,” Vannoy said.
No changes. The day-ahead market closes at 11 a.m. ET, with next-day forward reliability commitment assessment (FRAC) results posted by 8 p.m. ET.
Align the day-ahead market with the timely gas nomination cycle by closing the day-ahead two hours earlier during daylight saving time (one hour earlier during standard time) and reducing clearing windows by one hour.
Align the FRAC with the evening gas nomination cycle by closing the day-ahead one hour early during daylight saving time and reducing the clearing window by one hour.
The status-quo alternative would require MISO to make a convincing filing with the commission, Joe Gardner, vice president of forward markets and operations services at MISO, told the Electric and Natural Gas Coordination Task Force on June 10.
Gardner said MISO estimates that alternative No. 2 could make available over one year an average of 7,500 MW more generation, while No. 3 could free up about 5,000 MW more than under the current system.
“Units that previously were not able to be considered because they [had] an hour or two longer start-up notification time than other units are able to be considered” in alternatives 2 and 3, he said.
“This allows basically just a few more units to be available for reliability purposes as part of the normal process,” Gardner added. “There is a reliability and an economic benefit.”
Other RTOs
ISO-NE reported last year that system operations had improved following changes it implemented in 2013 to move the day-ahead market and initial reserve adequacy analysis (RAA) timelines earlier in the day. It said the number of units committed in the day-ahead or RAA that were completely unavailable in real time due to gas procurement issues dropped from seven in the winter of 2012/13 to zero in the winter of 2013/14. Over the same period the number of generators with long start-up times dispatched before the day-ahead offer and bid deadline dropped from 12 to zero.
PJM, which currently posts its day-ahead results at 4 p.m. ET, is considering ways to post its results by 1 p.m., an hour before the first gas nomination deadline at 2 p.m. (See PJM Markets and Reliability Committee Briefs, “Members OK Gas-Electric Initiative.”)
Importance of Stakeholder Votes
During Friday’s MSC/RSC meeting, Lin Franks, senior strategist at Indianapolis Power & Light, said stakeholder votes are important for MISO to have a better understanding of generation owners’ concerns. That came after one stakeholder expressed reservations about MISO releasing to the public comments stakeholders made with their votes. (MISO agreed to withhold release of those comments upon a stakeholder’s request.)
“Fuel assurance is not MISO’s responsibility and that’s at the crux of this issue — managing the risks of natural gas. MISO did an amazing amount of work to formulate options for stakeholders to consider that appear to mitigate most of the concerns and risks we expressed with MISO collectively and individually,” Franks said.
MISO estimates that natural gas-fired generation could rise to 50% of its generation pool in 2016/2017 as coal-fired plants are shuttered in response to the Environmental Protection Agency’s Mercury and Air Toxics Standards. EPA’s proposed Clean Power Plan is expected to increase natural gas use further.
The nine Northeastern and Mid-Atlantic states participating in the Regional Greenhouse Gas Initiative said their 28th auction of carbon dioxide allowances raised $85 million for investment in energy efficiency, renewable energy and other programs. More than 15.5 million allowances were sold at the clearing price of $5.50. Bids for the CO2 allowances ranged from $2.05 to $12.50 per allowance.
The market for cost-containment reserve (CCR) allowances was not as robust. The CCR is a fixed additional supply of allowances that are only available for sale if CO2 allowance prices exceed certain price levels ($6 in 2015, $8 in 2016, and $10 in 2017, rising by 2.5% each year thereafter to account for inflation). Ten million CCR allowances were for sale, and none sold.
The June 3 auction was the second auction of 2015.
Opposition to Delaware City Refinery’s Water Use Permit Growing
Opposition is mounting to a proposed permit that would grant the Delaware City Refinery continued use of 300 million gallons of Delaware River water a day for coolant.
A coalition of lawmakers and environmentalists has asked the Department of Natural Resources and Environmental Control to uphold an earlier recommendation that the refinery install a cooling tower system, which would reduce water consumption and kill less aquatic life. The refinery, which was designed and built in the 1950s, is using older technology that last received a five-year water-use permit in 1997. The refinery has been operating under permit extensions for more than a decade.
Regulators estimated the cost of a tower cooling system at about $75 million. Refinery owner PBF put the price at closer to $300 million. The public comment period on the proposed permit ends this week.
Stricter Water Temperature Limits Could Result in Closing of Two NRG Plants
New regulations setting temperature limits for Chicago-area waterways could doom two NRG Energy coal-fired plants, according to comments the company filed with the Pollution Control Board last week.
The board has set temperature limits for waterways into which NRG’s Joliet Station and Will County plant discharge cooling water. NRG sought a six-year period to conduct new studies, analyze the data and petition for variances. But the board denied the extension request and says NRG has only three years to meet the goals.
If finalized in their current form, the proposed thermal water quality standard would “result in the closure of certain industrial facilities,” NRG wrote in the request for the extension.
State Supreme Court Ruling Allows Luther College to Go Solar
Luther College says a 2014 state Supreme Court case that allows third-party ownership of solar arrays made it attractive for the school to install an 825-kW solar system. The court ruling made it possible for the nonprofit institution, which would not directly benefit from renewable-power tax subsidies, to finance its solar system through a third party that could take advantage of the tax breaks.
The system, which will be one of the state’s largest solar facilities, is designed to provide about 6% of the school’s electricity needs. A big benefit is that it will produce power during peak hours, helping the school to reduce its demand charge with the area utility, Alliant Energy, which currently makes up about 35% of its bill.
Nearly 60% of State’s Coal-Fired Plants Will Close by 2040
More than 58% of the state’s coal-fired power plants would be retired by 2040, even before taking into account proposed U.S. Environmental Protection Agency emission regulations, according to state Energy and Environment Secretary Len Peters.
Peters told a legislative committee earlier this month that state generators have already proposed retiring plants or converting them to natural gas to comply with EPA’s Mercury and Air Toxics Standards. Even without the pressure to meet the proposed Clean Power Plan, about 5,830 MW of the state’s aging coal-fired fleet will reach retirement age of about 65 years by 2040. Peters said the new emissions regulations and the price of construction means that it is unlikely Kentucky will see many, or any, new coal-fired plants being built.
New England’s first utility-scale electricity storage system is contained in three large shipping containers in Boothbay’s industrial park. The 3-MWh system, which uses valve-regulated lead acid batteries, is designed to help supply demand during peak summer hours and to provide grid stability and resilience.
The system, which would typically be charged at night and discharged during the day, was developed through a partnership led by New York City-based Convergent Energy + Power. The pilot program, which can supply up to 500 KWh for six hours, is being run by GridSolar for the Public Utilities Commission.
The political opposition has taken aim at Manitoba Hydro, the quasi-governmental utility that is seeking a 3.95% electric rate increase before the Public Utilities Board.
At a board hearing, Progressive Conservative party leaders called Manitoba Hydro’s predicted long-range losses of $75 million to $192 million “mind-boggling.” Though it predicts healthy profits during the next three years, the utility projects a downturn in power export opportunities and an expensive capital construction campaign that will turn profits into losses starting in 2018.
Premier Greg Selinger’s administration has touted the utility’s near-term success.
Consumer Advocate Appeals PSC OK of Exelon-Pepco Deal
Paula Carmody
The Office of People’s Counsel last week appealed the Public Service Commission’s approval of Exelon’s acquisition of Pepco Holdings Inc., saying consumers will suffer from the deal. The OPC filed its petition for judicial review in the Queen Anne’s County Circuit Court.
“The majority decision to approve this transaction was flawed and failed to address the single most important aspect of the law — first, do no harm,” People’s Counsel Paula Carmody said.
The PSC voted 3-2 to approve Exelon’s takeover, which would make the company the electric supplier for 80% of Maryland ratepayers. (See How Exelon Won over Maryland.) D.C. regulators have yet to rule on the deal.
Regulators OK We Energy’s Acquisition of Integrys; Just Needs Illinois’ Approval Now
The Public Utilities Commission on Friday approved We Energy’s acquisition of Integrys Energy Group, joining Wisconsin, Michigan and and various federal authorities. We Energy now needs just the nod from the Illinois Commerce Commission to complete the transaction. The $9.1 billion deal, when completed, will create WEC Energy Group Inc., which will have 4.4 million customers in four states and be headquartered in Milwaukee. WEC will also own 60% of American Transmission Co.
The ICC is expected to rule on the acquisition at the end of this month. At the forefront of the issue in Illinois is the ongoing multibillion-dollar gas main replacement project going on in Chicago by Integrys subsidiary Peoples Gas. Wisconsin Energy has said it will put together a new upper management team at Peoples. That company, and the gas main replacement project, was the subject of a highly critical audit. The final cost of the gas main project is still unknown, and the state Attorney General’s office has begun a probe into the entire project.
Eversource, political leaders, the state Office of Energy and Planning, the PUC Office of Consumer Advocate and staff members of the PUC participated in negotiations that led to the filing. The agreement is also supported by the electrical trade unions; the Conservation Law Foundation; trade organizations representing independent power plant owners and competitive electricity suppliers; and the New Hampshire Sustainable Energy Association.
The settlement is likely to yield about $380 million in customer savings over the next five years, according to state Sen. Dan Feltes. Hearings are expected to begin this fall, with legislative updates required in October and a PUC decision by the end of the year.
The owner of the former Revel casino and a third-party power supplier have struck a court-approved deal to keep the lights on.
Glenn Straub’s Polo North Country Club, which bought Revel for $82 million out of bankruptcy court in April, has temporarily resolved his dispute with ACR Energy Partners over the cost of energy services it supplies and whether his company should have to assume the previous owner’s commitments to pay for the costs of the ACR power plant’s construction. ACR initially cut service to the complex, but lawmakers ordered the company to restore service to maintain fire protection systems and the warning light atop the 47-story building.
Under the agreement, ACR will maintain power until one of four things happens: the parties reach a long-term contract; a state order requiring ACR to provide service is canceled or changed; a judge allows ACR to stop providing service; or Polo North finds a new energy provider.
The state’s transition to competitive electricity markets has contributed to dramatic benefits for consumers and the state’s power grid, including nearly $7 billion in savings and reduced costs and significant reductions in emissions, among numerous other impacts, according to a NYISO report.
The report, “Powering New York — Responsibly,” examines the 15-year period since the inception of New York’s competitive market in 2000. It quantifies the major contributions made by NYISO to help the state meet its future energy needs and achieve its goals for cleaner energy and improved efficiency.
“The federal and state policy decisions that produced electric industry restructuring were founded on the conviction that competitive wholesale electricity markets expeditiously and effectively facilitate evolution of the grid,” said NYISO CEO Stephen Whitley.
Duke Energy is staying out of the debate as state lawmakers consider bills that could affect solar development.
One bill would let homeowners lease or finance solar systems through third-party developers like SolarCity. Another would cap utilities’ required purchases of renewable energy at 6% of demand this year, compared with the current target of 12.5%.
“There have been a half-dozen bills in this session dealing with energy,” Duke CEO Lynn Good told Bloomberg News. “It’s difficult to handicap which ones will go through.”
State Supreme Court Gives Duke Some Relief from Ash-Cleanup Ruling
The state Supreme Court last week vacated a lower court ruling that said regulators could force the utility to take immediate action to clean up coal ash-contaminated groundwater. The high court said legislation passed last year ordering coal ash remediation made the “immediate action” ruling unnecessary.
Environmental activists said the lower court ruling, arising from a 2012 case and predating Duke’s January 2014 ash spill on the Dan River, meant that Duke should be forced to stop the pollution at the source before any work restoring groundwater is taken. But the utility and state regulators said full assessments of the groundwater contamination is necessary first.
“We think the court’s ruling is appropriate, and we are pleased to close this issue so we can continue moving ahead with safely and permanently closing ash basins,” Duke spokeswoman Erin Culbert said.
Boston-based Competitive Power Ventures wants to build a $900 million natural gas-fired power plant in western Pennsylvania that could be up and running by the end of 2019.
Vice President Michael Vesca said construction could start in 2017 on the plant, which would be located near Vinco, about 65 miles east of Pittsburgh.
Penelec Spends $6M to Serve New Gas-Pumping Station
Pennsylvania Electric Co. plans to spend $6 million to build new distribution lines to supply power to pumping stations being built in shale-gas producing areas of central Pennsylvania.
New electric distribution lines will deliver 2.8 MW from substations in McConnelltown and Blain to new pumping stations in Marcklesburg and Doylesburg.
Kinder Morgan has scaled back a natural gas pipeline proposed for New England, but the changes will have little effect on the overall project to supply power plants and home-heating utilities.
Kinder Morgan filed an updated plan with the Federal Energy Regulatory Commission on June 2 for its Northeast Energy Direct project, saying it was eliminating local laterals and related facilities due to the inability to sign up utilities to support those spurs. “We just don’t have the customers,” Allen Fore, vice president of government affairs at Kinder Morgan, told TheBoston Globe.
The pipeline is planned to run from New York through northern Massachusetts, cut into New Hampshire and return to Massachusetts, where it will terminate in Dracut.
Kinder Morgan, the parent of project developer Tennessee Gas Pipeline, said it is eliminating a nearly 15-mile spur through seven Massachusetts towns and a 1-mile spur in Connecticut, along with a new meter station and modifications at three existing stations.
Remaining in the project are 37 miles of laterals running off the main line, which will mostly follow existing rights-of-way.
“This revised scope, which will be reflected in Tennessee’s next draft environmental report filing, will allow Tennessee to meet the needs for all the shippers that have executed binding precedent agreements for the project,” the company wrote (PF14-22).
The pipelines are controversial because they would import fracked shale gas from Pennsylvania and be funded by utility ratepayers. (See New England Governors Revise Energy Strategy.)
Kinder Morgan said the pipeline could bring more than 2 billion cubic feet of natural gas per day into the region. It plans to file a second draft of its environmental report next month and a final pipeline application with FERC in October.
Transmission developer LS Power Transmission is protesting Order 1000 compliance filings by NYISO, SPP and ISO-NE, saying they still favor regulated incumbents over independent developers. NextEra Energy also filed a protest in NYISO’s docket.
The protests, submitted last week, are to compliance filings the three regions made in response to Federal Energy Regulatory Commission orders in April and May.
LS Power praised NYISO for its handling of the stakeholder process, saying it was an “open dialogue that actually valued the exchange of ideas, rather than a perfunctory process, for process sake, that occurred in some regions that oppose Order No. 1000 at the regional planner level.”
It said its protest to the ISO’s developer agreement is limited to “sections that provide no ratepayer benefit but that have the potential to substantially increase costs either through increased financing costs or through a significant mismatch to the obligations undertaken by incumbent transmission owners proposing regulated backstop solutions.”
“Because both regulated and alternative projects will be evaluated against each other under the Order No. 1000 compliant process, it is important that the developer agreement impose no more stringent obligations on the developer of an alternative regulated solution than are imposed on incumbent transmission developers,” it wrote (ER13-102-007).
NextEra said the agreement burdens alternative developers without guaranteeing faster project completion. It said the deadlines within the agreement do not reflect the reality of project development schedules and that NYISO should not be given latitude to terminate a project agreement when the project is faced with obstacles beyond the developer’s control.
It said competitive bidders should only be disqualified if the only feasible route would alter an incumbent transmission owner’s use and control of its existing right of way and law or regulation prevents use of alternatives to those rights-of-way (ER13-366).
ISO-NE
In New England, LS Power said ISO-NE failed to delete certain language as ordered by FERC following its second compliance order from 2013 regarding backstop transmission solutions (ER13-193).
New York state is proposing to invest $1.5 billion in large-scale renewable energy development over the next decade under a revised procurement strategy to reduce costs.
Without a federal production tax credit, NYSERDA’s current 20-year REC contracts for wind result in a $33/MWh premium to market prices. The premium could be reduced to about $18/MWh using utility-backed PPAs with a developer that has a relationship with a YieldCo. Utility-owned generation is estimated to have a premium of less than $27/MWh.
The New York State Energy Research and Development Authority made the proposal in a report released early this month. “The current approach has been good, but we can do better,” said Richard Kauffman, the state’s chairman of energy and finance.
Unlike most state renewable portfolio standard programs, which delegate renewable purchases to utilities, New York designated NYSERDA to act as a central procurement agency.
NYSERDA said the $1.5 billion investment is comparable to the state’s spending since it created its RPS in 2004. The programs have led to the construction of 1,900 MW of clean generation, although the RPS goal of 29% for this year will not be met.
A 32-MW project on Long Island is the only large-scale solar project in the state, according to the Long Island Power Authority. The American Wind Energy Association says New York had 1,749 MW of installed wind capacity at the end of 2014.
The report recommends several new strategies that it said would allow it to obtain renewable resources at lower costs, optimize siting of projects and extend benefits to customers.
It said long-term bundled power purchase agreements would provide developers predictable revenue streams, allowing them to obtain cheaper financing and reducing the levelized cost by at least $11/MWh. Securitizing debt and opening projects to financing vehicles such as “YieldCos” — publicly traded companies formed to own operating assets that produce a predictable cash flow — could reduce costs further.
It also invited comment on whether utilities should be permitted to bid against other developers for renewable projects, saying the competition could also reduce costs.
Procurements should take into account not just price, the report said, but also plant retirements, price forecasts and integration with storage and demand response to ensure projects are sited where they provide the greatest system and customer benefits.
It called for ways to address insufficient demand volumes, contract durations and credit supports that it said had crimped voluntary renewable purchases.
A 10-year budget commitment of $1.5 billion would stimulate investment and help renewables become self-sustaining without subsidies.
The report was filed in response to a Feb. 26 New York Public Service Commission order laying out the role of renewables under the Reforming the Energy Vision overhaul of the state’s energy industry. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)
The PSC will hold a technical conference to discuss the report, with initial public comments due July 22.
The Federal Energy Regulatory Commission last week denied rehearing in a challenge to PJM’s method of funding Financial Transmission Rights, closing a docket that had been in limbo for almost two years — and potentially clearing the decks for a unilateral rule change proposal by the RTO.
FirstEnergy had requested removal of real-time congestion costs from the calculation of transmission congestion charges, saying it would allow FTR holders to better hedge congestion.
“We continue to find that allocation of real-time balancing congestion to current FTRs has a reasonable basis, because FTR holders are in the best position to reflect the associated underfunding in the value of FTRs,” the commission wrote. “Allocation to other parties would not create any incentive to reduce real-time balancing congestion and would provide even less of an ability to provide any reflection of the value of the underfunding in any instrument.”
The commission gave no reason for the timing of its ruling (EL13-47-001) on the rehearing request, which was filed by FirstEnergy, J. Aron & Co., DC Energy, Vitol and Public Service Electric and Gas and its affiliates after the commission denied a complaint by FirstEnergy in June 2013.
But it came after just days after PJM suggested it may make a unilateral section 206 filing to break a deadlock among stakeholders over potential rule changes.
PJM’s June 2 filing with the commission noted that the FTR funding shortfall the companies had complained of had been resolved — at least for now, with FTRs fully funded since the current planning year began in June 2014.
PJM said it had addressed underfunding by being more conservative in its annual modelling of Auction Revenue Rights and FTRs, particularly the impact of transmission outages, market-to-market flowgates and loop flow.
“Thus, while FTR underfunding has been resolved for now, the consequence is that customers have experienced reduced ARR allocations,” PJM said. “PJM’s solution has therefore shifted revenues from ARR holders, through a reduction of the quantity of ARRs, to FTR holders, in the form of increased FTR funding … PJM believes that the resulting status quo is less equitable and desirable than it would prefer.”
“Redesigning the funding and allocation processes for FTRs and ARRs is fundamentally an issue of cost allocation among different classes of members. Therefore, it is unlikely that stakeholders will be able to come to consensus on a long-term solution to address PJM’s FTR design,” PJM said. “Indeed, PJM expects that in the future any significantly proposed market rule changes aimed for an improved, more efficient and equitable ARR and FTR design may have to be prompted by a filing made by PJM under section 206 of the Federal Power Act.”
MILWAUKEE — The final session of the Mid-America Regulatory Conference last week brought together top officials from MISO, SPP and PJM to discuss balancing short-term expectations with long-term planning.
“We did not know how fast the wind would develop [in the Midwest] under state [renewable portfolio standards],” said PJM CEO Terry Boston, who will be retiring later this year. “If I reflect back, a plan to build HVDC from this area of the country into the Mid-Atlantic would have been an excellent plan.”
Sam Loudenslager, principal regulatory analyst for SPP, said his region was surprised by oil shale development.
He recalled a recent tour of the Bakken region in North Dakota. “I came back telling our planners, ‘You’re not going to get it. You’re going to miss this big time because it’s growing like nobody’s business,’” he recounted.
“They’ll continue to pump as long as oil’s $35 a barrel. And if you get to the heart of the Bakken, they’re pumping at $22. And these are areas that have no transmission whatsoever.”
Richard Doying, MISO’s executive vice president of operations and corporate services, lamented that officials had not anticipated the Environmental Protection Agency’s Clean Power Plan a decade ago. “When we were doing our initial transmission planning, 111(d) was not a significant focus,” he said.
MISO asked the Federal Energy Regulatory Commission to dismiss a complaint filed last month alleging it billed more than $21 million in excessive transmission rates, saying Southern Co. and three Missouri utilities have misinterpreted its Tariff (EL15-66).
MISO transmission owners, which joined the RTO last week in asking for dismissal, were blunter, saying the utilities’ claims amount to “misrepresentations” of the Tariff.
Both maintain the utilities’ complaint is duplicative to a proceeding already underway before FERC that involves similar issues (EL14-19).
In their complaint filed last month, the utilities alleged that MISO improperly shifted and reallocated sunk costs and network upgrade costs from its legacy region in the Midwest to Entergy export customers in the South following Entergy’s integration into MISO in 2013. (See Utilities Accuse MISO of ‘Massive’ Overcharges.)
Bringing the case were Kansas City Power & Light’s Greater Missouri Operations Co., The Empire District Electric Co., Associated Electric Cooperative Inc. (AECI) and five Southern Co. affiliates: Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Southern Power.
Entergy Integration
The utilities were receiving transmission service from Entergy before it joined MISO under the terms of the Entergy Tariff. When MISO succeeded Entergy as the transmission provider, they became subject to MISO’s Tariff.
Long-term, firm point-to-point transmission service rates under the Entergy OATT vs. MISO OATT.
The utilities contend that MISO’s drive-out and drive-through charges are not applicable to their transmission service reservations and that if they were applicable they should be declared unjust and unreasonable. They claim that Attachment FF-6 of the MISO Tariff provides a broad exemption for their through-and-out transaction charges. They say the allocations violate MISO’s Tariff and FERC findings that — with the exception of certain multi-value projects — point-to-point export services are provided under a no-cost-sharing rule.
Exemption Argument
In its response, MISO counters that the Tariff is clear that the utilities are not entitled to an exemption. The RTO maintains that FERC “has confirmed on several occasions” that through-and-out rates in question are applicable to transactions in the MISO South region.
“Over the past several years, the complainants have created an extensive paper trail in various proceedings, which casts doubt on their current Tariff violation claims. While the complainants have filed numerous pleadings to block and devalue the MISO South integration, those pleadings did not argue, until the instant complaint was filed, that MISO is violating the Tariff,” MISO said. “On the contrary, the complainants sought FERC action precisely because these rates were applicable.”
The RTO also said any dispute over its through-and-out rate should be resolved in the section 206 proceeding FERC initiated in February 2014 (EL14-19).
Increased Scope
MISO also said the fact that the charges may have increased does not render them unjust and unreasonable. Prior to the MISO South integration, service was limited to the Entergy transmission system. But now the utilities may redirect points of receipt or delivery on a region-wide basis, MISO counters.
“Not surprisingly, the complainants’ new charges reflect these benefits of scope, as well as many other unique benefits that a Day 2 RTO provides to its customers,” MISO said.
Finally, MISO contends that the utilities are seeking a preferential rate at the expense of other market players.
The Organization of MISO States voted last week to convene discussions on ways to improve the RTO’s stakeholder process and address friction between the RTO and some of its members.
OMS President Libby Jacobs noted that MISO has several efforts under way already, including a white paper that MISO’s Steering Committee will discuss Thursday on concerns that the stakeholder process has become “cumbersome and inefficient.” The MISO Advisory Committee has made stakeholder process improvement the “hot topic” for its October meeting.
“We certainly applaud MISO for their efforts,” Jacobs, of the Iowa Utilities Board, told OMS board members on June 11.
Richard Doying, EVP of MISO (L) and Elizabeth (Libby) Jacobs, IUB Commissioner and OMS President at MARC 2015 Annual Meeting
But she said, “We had some concerns that it didn’t appear there was a formal outreach to all the stakeholder groups to really weigh in on the process.”
OMS would convene the dialog but will likely hire an outside facilitator to moderate the discussions, she said.
The effort could help better document how the stakeholder and governance process works, look at best practices at other RTOs and help stakeholders identify priorities.
MISO’s white paper cites overlapping responsibilities among committees and insufficient focus on the most important issues as weaknesses in the current process.
Tensions
Tensions between some MISO stakeholders and the RTO have flared in recent months.
Transmission developers objected earlier this year to MISO’s approval of Entergy’s request for $217 million in out-of-cycle transmission projects in Louisiana. As out-of-cycle projects, they were excluded from competition.
The Consumer Advocates sector complained it was being disenfranchised after MISO denied its request for $200,000 in funding to help cover legal costs in a case before the Federal Energy Regulatory Commission on MISO transmission owners’ return on equity rates.
ISO-NE’s power prices dropped by more than 40% in the first quarter of 2015 thanks to lower natural gas costs, the Internal Market Monitor reported last week.
In a filing with the Federal Energy Regulatory Commission, the Monitor said a 43% decrease in the cost of natural gas from the previous year was largely responsible for the power price decline (ZZ15-4). Natural gas prices averaged $11.37/MMBtu, a drop from $19.95.
Day-ahead energy market prices averaged $84.84/MWh at the Massachusetts hub, down 41% from a year ago, while real-time prices averaged $81.97/MWh, a drop of 43%.
Also lower were real-time reserve payments (-80%), regulation payments (-56%) and net commitment period compensation payments (-67%).
Total wholesale market costs of $3.14 billion were down 41%. “Overall, market prices reflected the cost of providing energy, and energy market outcomes were competitive,” the Monitor said.
Pricing Flexibility
The IMM said generators are taking advantage of the flexibility resulting from the RTO’s Dec. 3 rule change allowing market offers to be made hourly and changed during the operating day. The energy market offer flexibility (EMOF) rule, which allows resources to respond to changes in production and opportunity costs, has been used primarily by natural gas generators.
“There has been a reduction in the volume of self-scheduling, in which generators assume a price-taking role, and to the extent to which generators vary economic minimum parameters to reach desired levels of output,” the Monitor said.
Some generators also took advantage of EMOF rules allowing them to offer negative prices to signal their desire to maintain minimum output levels.
Only hydro and wind resources offered negative prices in the day-ahead market. They were joined by some natural gas, biomass and coal resources in offering negative prices in the real-time market.
“On average, the amount of capacity offered in the real-time market at negative prices was equal to roughly 3% to 4% of load,” the Monitor said.
