Interface Pricing Flaw: Today, the full effect of transactions on the MISO M2M constraint is modeled by both RTOs.(Source: Potomac Economics)
WASHINGTON — MISO’s Independent Market Monitor urged the Federal Energy Regulatory Commission last week to resolve a standoff between MISO and PJM over interface pricing that he said is costing consumers millions.
“We’re seeing tens of millions of dollars in uplift. We see transactions being scheduled that are not efficient. And the only way to really solve this is to get prices right,” MISO Market Monitor David Patton told commissioners during a panel discussion with RTO representatives and state regulators at FERC’s Jan. 22 meeting.
But PJM Market Monitor Joe Bowring and Stu Bresler, PJM vice president of market operations, said pressure for an immediate resolution could be short-sighted. “We have to be careful an arbitrary deadline does not force a bad answer rather than getting to the right answer,” Bowring said.
“I think a deadline that required a solution in a very near timeframe would be very difficult and potentially damaging if it resulted in an inferior approach,” agreed Bresler.
Whether the commissioners will set a deadline to help spur a resolution is unclear.
“I think we want to distill what we have heard today and get the sense of where the commissioners are,” Chairman Cheryl LaFleur said at a press conference following the meeting.
Two Years
MISO and PJM have been working for two years to resolve differences in the way they price transactions at interface buses.
The RTOs agree that the current methods undermine efficient scheduling of power because they cause both RTOs to model the same constraint, resulting in double-counting.
Patton says transactions are overcompensated when they are expected to relieve a constraint, and overcharged when they are expected to contribute to congestion. Interface pricing flaws “cost MISO some money. It costs PJM a huge amount,” he said.
Patton contends that PJM’s method exaggerates the effects of imports and exports on transmission constraints near the seam. As a result, he said, scheduling incentives have been inflated by as much as 600% at the Cook-Palisades interface in Michigan, the most active M2M constraint last winter.
“We massively overpriced congestion last winter and it resulted in an average of something like 3 GW being exported from PJM to MISO. This was during the timeframe when we were just coming out of the polar vortex and PJM had just incurred half a billion dollars in uplift, committing tons of generation under conservative operations, and they’re exporting gigawatts to MISO, where it’s demonstrably less valuable,” Patton added.
Bresler said he didn’t see the correlation. “PJM has made changes to its interface definitions in direct response to concern from MISO. Given the change we made, I’m not sure I understand the reference … to the polar vortex and the uplift,” he said.
Patton recommends removing the congestion component of the LMP for the non-monitoring RTO.
PJM offered an alternative in which each RTO would set its interface bus price relative to a common set of interfaces.
FERC to Set Deadline?
Patton said FERC should set a deadline for an agreement because there have only been two solutions under consideration for more than a year.
“We’ve had an incredible amount of analysis on those two solutions. Obviously, I think there’s one clearly correct answer, but not everyone agrees with me,” he said to laughter. “I think if we did have a deadline to file, it would be useful just to file and say ‘We’re agreeing to disagree, and here are the pros and cons of these two solutions that we have an enormous amount of research on, and then allow the commission to maybe weigh in and give some guidance and push the needle in one direction or the other.”
“We really need FERC’s involvement in this issue. We need a deadline to file a solution to this,” Patton told commissioners.
Bowring said he didn’t think a hard deadline made sense, although he suggested the RTOs could report back to the commission in June. “If we knew the answer, we would have told you already. We don’t.”
Bresler said Patton’s proposed solution to interface pricing could have negative impacts elsewhere.
“PJM has always defined our interface prices so that we reflect the impact of interchange transactions on the transmission system and more specifically on the transmission constraints which we are actually operating,” Bresler said. “And part of the solution that Dr. Patton has proposed is essentially eliminating the impact of some transmission constraints in the interface price.
“That may end up being the right solution,” Bresler added. “But I think the difficulty … is making sure that doing so doesn’t have detrimental effects elsewhere.”
LaFleur expressed frustration with the inability of the two RTOs to resolve the impasse.
“I am at least actively contemplating, should we do something more active than ask for another schedule, which is what we decided to do [in 2013] after a lot of tough talk,” she said. She acknowledged work done by the RTOs to address seams issues but added, “I’ve been a little disappointed with the level of progress on some of the thorniest issues, many of which have come before us today.”
Commissioner Philip Moeller said the problems are “partly our fault.”
“We kind of took our foot off the gas and stopped requiring the quarterly reports and basically lost focus on the fact that these issues were not going away,” he said.
Michigan Public Service Commissioner Greg White, another panelist, agreed a deadline could increase the parties’ “sense of urgency” but said he didn’t want to “end up with a product that is inferior because of a lack of time.”
Joint and Common Market Progress
The bus interface pricing issue has proven to be perhaps the most intractable issue facing PJM and MISO’s Joint and Common Market initiative, a joint stakeholder process to address seams issues.
Patton said the JCM process has borne fruit. He said MISO’s ability to export capacity into PJM has increased, although the two parties haven’t solved the underlying problems. “So while I don’t think we structurally have solved the problem and I don’t see a filing coming any time soon that will structurally solve this, I think the priority has diminished.”
Bowring was unapologetic. “There will continue to be issues as long as there are very substantial differences between the design for procuring capacity in MISO and the design for procuring capacity in PJM,” he said. “The … notion that there should be transfers no matter what I think is excessively simple-minded.”
Elizabeth Jacobs, chair of the Iowa Utilities Board, who represented the Organization of MISO States on the panel, said she was encouraged by MISO and PJM’s plans to introduce Coordinated Transaction Scheduling to improve interchange optimization. (See “PJM Posts MISO Price Predictions Before CTS Vote” in Market Implementation Committee Briefs, Jan. 12, 2015.) Jacobs noted that while the panel discussion focused on the PJM-MISO seam, many MISO members are facing new seams issues with an expanded SPP.
The Federal Energy Regulatory Commission said last week that it intends to tighten the rules on the use of “hold harmless” commitments in support of merger applications and will prohibit commitments that are limited in duration, which could leave ratepayers vulnerable.
In a proposed policy statement (PL15-3), the commission said it was better defining the costs subject to such commitments and the accounting methods used to track them. The commission will accept comments on the proposal, which it called a reaffirmation of its 1996 Merger Policy Statement (Order 592), for 60 days.
FERC noted that hold harmless commitments — agreements not to seek recovery of transaction-related costs in rates unless they are offset by transaction-related savings — have become a common feature of merger applications under section 203 of the Federal Power Act (FPA) over the last decade.
The commission said, however, that “it has never defined those costs with much specificity, leading to inconsistency with respect to this issue.”
The policy statement’s definition includes the costs of consummating a transaction (e.g., legal, investment advisory, accounting and financing costs) and the capital and operating costs incurred to achieve merger synergies (e.g., severance payments, accounting and operating systems integration costs).
The commission said requiring applicants to explain how they track the costs will help ensure that they are not recovered in rates without commission approval.
Time Limits
The Merger Policy Statement requires that hold harmless commitments must protect customers “for a significant period of time following the merger,” a period that the commission has typically defined as five years.
FERC said it now realizes that such a limit “raises the risk that transaction-related costs could be included in future formula rate billings without applicants making the showing of offsetting savings.”
The commission said its concern arose from its experience auditing utilities with hold harmless commitments, the concerns of protestors in previous merger applications and the proposed treatment of certain categories of costs.
“For example, an applicant could try to include transaction-related costs in formula rates without making a showing of offsetting savings if the costs, though incurred during the hold harmless period, do not enter the ratemaking process until after the hold harmless period expires … Similarly, limiting the applicability of hold harmless commitments to specific time periods may incentivize applicants to delay incurring some types of transaction-related costs until after the hold harmless period expires.”
The new policy, FERC said, ensures “that the focus of a hold harmless commitment [is] on whether a cost is transaction-related, and not on when the cost is incurred.”
FERC also said removing the time limit will ensure proper treatment of costs that should be capitalized as an asset during the hold harmless period, but whose cost recovery would occur as the asset is depreciated over future periods that extend beyond the hold harmless period.
Changes are Prospective
The commission also reiterated its opposition to including acquisition premiums as transaction-related costs. It said it would continue to require a showing of “specific, measurable and substantial benefits to ratepayers” for recovery in a subsequent FPA section 205 proceeding.
FERC said the policy changes would apply prospectively and would not affect existing commitments or pending merger applications.
Mike Tidewell, director of the Chesapeake Climate Action Network (L), and Tyson Slocum, director of Public Citizen’s energy program (R), at an October 2014 press conference in Baltimore by activists opposing Exelon’s proposed acquisition of Pepco Holdings Inc. Already approved by FERC, the merger still must clear state regulators.
Environmentalists last week continued their campaign against Exelon’s proposed $6.8 billion takeover of Pepco Holdings Inc., with activists urging the D.C. Council to oppose the deal and a renewable energy think tank saying it would hurt both consumers and green energy.
At a council hearing Friday, environmentalists said Exelon power-generation investments would make it hostile to rooftop solar, unlike Pepco, which only distributes electricity. Approval of the deal is in the hands of the D.C. Public Service Commission but the council is an intervener in the regulatory proceedings and could influence regulators’ decision.
“They view renewable power and sustainability as a threat to their core business of selling electricity,” said Larry Martin of the D.C. chapter of the Sierra Club, according to a report in The Washington Post. “This merger is not contributing to the public interest.”
Mary M. Cheh, chair of the council’s Committee on Transportation and the Environment told the Post that the hearing had left her skeptical that the deal would benefit District residents.
No one from Pepco, Exelon, the PSC or the District’s Office of the People’s Counsel testified at the hearing. They are expected to appear at a hearing of the council’s Committee on Business, Consumer and Regulatory Affairs on Jan. 29.
Earlier last week, the Institute for Energy Economics and Financial Analysis joined the chorus of voices calling for rejection of the deal.
The Cleveland-based think tank, which supports reduced dependence on coal and other non-renewable energy resources, said in a Jan. 21 report that the merger would undermine D.C.’s renewable-energy initiatives.
It said the deal could mean higher rates for current Pepco customers because Exelon will need to earn returns to justify the $2.5 billion acquisition premium Exelon has offered.
Exelon “has been challenged in recent years by low wholesale power prices driven by cheap natural gas, reduced demand for power and the growth of renewable energy and energy efficiency,” wrote the report’s authors, Cathy Kunkel and Tom Sanzillo.
They wrote that if the acquisition is approved, Exelon will “acquire a stable earnings stream from Pepco’s regulated utilities that would help Exelon balance out the volatility of its merchant electricity generation business, which has proven susceptible to weakness in the competitive energy markets.”
“A merger with Exelon would also subject ratepayers to risks associated with Exelon’s aging nuclear fleet,” the report said. “Residents and businesses may be asked to accept rate increases and policy accommodations to assist Exelon with the management of aging nuclear plants.”
Exelon spokesman Paul Elsberg said the report contains some errors and draws incorrect conclusions.
“Customer rates will not increase as a result of the Exelon-Pepco Holdings merger and, in fact, by combining our companies, we will operate more efficiently and generate cost savings that will be passed on to customers,” he said Friday.
Elsberg said the two companies’ support for renewable energy will continue, noting that Exelon is the 11th largest U.S. wind producer and has made investments in solar, including the nation’s largest urban solar project in Chicago. “Our utilities will continue to facilitate customers’ installation of solar panels on their homes and businesses,” he said.
Kunkel said the study was not commissioned by any other group. She said the proposed merger drew the Cleveland think tank’s attention for several reasons.“IEEFA follows developments in the utility industry nationally,” she said Friday. “We see this case as part of a larger trend of major utilities moving increasingly towards regulated operations, and we also think it has important implications for renewable energy policy in the mid-Atlantic.”
The merger has already gained the approval of the Federal Energy Regulatory Commission and Virginia regulators. The staff of the New Jersey Board of Public Utilities has reached a settlement with Exelon that would give Atlantic City Electric customers $62 million in rate credits.
Exelon still needs the approval of Maryland, D.C. and Delaware. Public advocates in both states and the District have come out publicly against the merger under the current offer.
Refinery Files for Permit to Build $100 million Hydrogen Plant
PBF Energy, owners of the state’s only refinery, is seeking permission to build a $100 million hydrogen plant as part of a plan to begin refining ultra-low sulfur fuel at the Delaware City facility.
PBF applied to the Department of Natural Resources and Environmental Control for water intake and discharge permits for the project. Any construction along the state’s coastline needs Coastal Zone Act approvals.
PBF said in the application that the new plant would allow removal of more than 20,000 tons of sulfur from products made at the refinery. PBF in October announced it was cancelling plans to build a different, $1 billion plant on the site.
Natural Gas Rate Hikes Waiting for Two New ICC Members
Rate-increase proposals from two Integrys gas utilities are on hold until Gov. Bruce Rauner names two new members to the Commerce Commission to replace Chairman Doug Scott and Commissioner John Colgan, whose terms ended yesterday.
North Shore Gas and Peoples Gas have applied for increases to their base rates. Bills for Peoples customers would increase by about $5 a month and North Shore bills by about $2.50 a month.
Both companies are also seeking substantial boosts to their monthly fixed-rate customer charges. Peoples has requested a 43% increase in its $27 monthly fee to $38.50. Its fee is already the second-highest of any utility in the Midwest. North Shore is seeking a 24% increase of its monthly service charge to $29.55. Consumer groups and the state attorney general’s office have already voiced opposition.
General Assembly Starts with New Legislation for Renewable Energy
Environmentalists and other activists rallied outside the State House to mark the introduction of a renewable energy bill at the start of the state’s lawmaking season.
Sen. Brian J. Feldman of Montgomery County sponsored a bill that would require 40% of the state’s electricity come from renewable sources by 2025. The state’s utilities got 10% of their electricity from renewable sources last year.
The bill’s passage is a long shot though. Larry Hogan, who gets sworn in on Wednesday as governor, says ratepayers should not be asked to pay a premium for renewable power. The chairman of the House Economic Matters Committee, which handles such legislation, said he doesn’t see it passing this year.
PSC Approves Increase for Consumers Energy Gas Rate
The Public Service Commission narrowly approved a 2.4% gas-rate increase for Consumers Energy. The monthly bill for a typical residential customer will go up by about $1.97.
Consumers Energy asked for an $88 million rate increase. The PSC approved $45 million. The company said it needed the increase to offset increased operating and maintenance expenses. It was its first contested rate increase since 2010.
Opposition Growing to Xcel’s Plan for 62-MW Solar Project
Local residents want more say over a NextEra Energy Resources plan to build a 62-MW solar project on 500 acres of farmland in southwestern Minnesota.
Under state law, approval of solar projects of more than 50 MW shifts from local control to state regulators. Local opponents of the $100 million NextEra project, which would sell its output to Xcel Energy’s distribution system, say their rights are being ignored in the state’s quest to produce more renewable energy. The state has set a goal of developing 1.5% of its electricity by solar by 2020.
“If loss of local control, decreased property values, increased cost of electricity or future cleanup issues of a 500-acre industrial site is a concern, then this project is a concern,” farmer Greg Boerboom wrote in a letter to The Marshall Independent. “This project, mandated by the metro members of our Minnesota Legislature along with our governor, ignored the facts about the inefficacy of solar power.”
Rail Authority Gives Backing to Sandpiper Pipeline Plan
The Anoka County Regional Rail Authority has voiced its support for a proposed oil pipeline that would run from North Dakota through Minnesota to Wisconsin, relieving some of the traffic from congested rail lines in the northern Great Plains.
The seven-member authority voted to endorse the Sandpiper Pipeline in part because it will help relieve rail congestion on the Burlington-Northern Santa Fe (BNSF) route through Minnesota. Commissioner Jim Kordiak said he was “very supportive” of the plan because he sees the pipeline as a much safer way to transport crude oil from North Dakota’s Bakken field.
Two Bills Aimed at Supporting Solar Introduced to General Assembly
The state’s solar industry, experiencing a rapid slowdown tied to the end of utility rebates, could get a boost if two measures introduced in the General Assembly are approved.
The first proposal would raise the limit on solar installations that qualify for net metering, from the current 100 kW to 1 MW. A second proposal eliminates the size cap and would allow for a yearly “true-up” of net generation, which would let solar owners bank generation credits for a year, rather than the current month. Excess generation is currently tabulated monthly at a reduced-fuel cost, about 2 cents/kWh.
“I’m trying to find some place that is workable for a new industry and workable for how the current power producers work,” said Rep. T.J. Berry, sponsor of one of the bills.
The Public Service Commission approved an increase of Ameren Missouri’s energy efficiency fee from $3.70 a month for a typical customer to $6 a month starting Jan. 27. The fee finances the company’s demand-side management programs and other efficiency efforts.
Anne Boyle, whose family’s political roots go back to her great-grandfather’s service in the Legislature, retired from the Public Service Commission after 20 years.
Boyle, a Democrat, often found herself fighting for the rights of “the little guy,” according to fellow PSC Commissioner Frank Landis, a Republican. “Anne truly believed in doing the most that she could to better the quality of life for the underprivileged,” Landis said. “She believed it. She acted on it. And she lived it.”
Xcel Energy is reaching out to landowners in preparation for building a 159-mile, 345-kV transmission line that would run from Texas to New Mexico.
The Tuco-Yoakum-Hobbs project is in its early stages, according to the company. If it gains regulatory approval from the Federal Energy Regulatory Commission and state agencies, it could go into service in 2020. The company said the $237 million project is necessary to deliver power to the growing natural gas and oil industry in West Texas and in New Mexico.
The transmission line is one of more than 44 possible projects proposed by Southwest Public Service Co., Xcel’s subsidiary in New Mexico. The company submitted plans for those projects, which would cost an estimated $557 million, to SPP in 2014.
The Utilities Commission says that Duke Energy’s two utilities are generating higher rates of return than allowed, but that the rates are dropping to the allowed levels.
Both Duke Energy Carolinas and Duke Energy Progress experienced dramatic increases in rates of return after a 2013 rate case. Duke Carolinas’ overall return peaked at 8.36% in June, nearly half a percentage point above the allowed 7.88%. Duke Progress’ overall return was 8.06%, above the 7.55% allowed.
The agency’s staff said cold weather at the start of 2014 may have been a factor for the increases but that the commission could take action if the figures don’t stay in line with the allowed margin.
Bill Could Undo Regulations to Reduce Natural Gas Flaring and Oil Conditioning
Legislators are seeking to roll back state regulations that call for a decrease in gas flaring at oil wells and a reduction in the volatility of crude oil that will be transported by rail and road.
The rule on gas flaring calls for oil producers to capture 77% of wellhead natural gas this year, 85% by 2016 and 90% by 2020. Some oil producers, who burn off associated natural gas from oil wells where they have not yet built pipelines to capture the gas, have cut back production in order to reach the 2015 goals. The rule ordering oil transporters to condition crude to make it safer for transport is set to go into effect April 1.
The new rules, approved by the Industrial Commission, did not go through the Legislative Assembly’s Administrative Rules Committee. Putting both regulations through legislative review could take an additional nine to 10 months.
PUCO Holds Hearing on FirstEnergy’s Guaranteed Return Plan for Plants
About 100 people attended the first of three public hearings on FirstEnergy’s “electric security” plan that would allow its largest generating plants to receive a guaranteed price from customers.
Opinion was split at the Public Utilities Commission hearing. FirstEnergy said the plan would keep the plants open in the face of increased competition from natural gas-fired plants and wind farms, and save consumers billions of dollars. Several elected officials and business owners came to express their support for the plan.
But some consumer advocates complained that ratepayers were being asked to subsidize the energy company to the tune of billions. “FirstEnergy doesn’t play by the rules,” said Dex Sims, a member of the Communities United for Responsible Energy. An evidentiary hearing is set for Jan. 28.
PUC Chief Says Philly’s Gas Lines Pose Risk to City Residents
The chairman of the Public Utility Commission said almost half of Philadelphia Gas Works’ natural gas lines are “at risk” and announced a comprehensive program to review the city-owned utility’s pipeline safety and replacement program.
Chairman Robert Powelson said the city’s residents are “threatened by at-risk pipelines and an alarmingly slow replacement schedule.” He said the company’s current plans to replace its riskiest gas mains in 88 years is insufficient.
PGW maintains the largest municipal-owned system in the U.S., with about 1,500 miles of cast iron pipes, some dating to the 1800s. The PUC said it costs about $1.4 million to replace each mile in Philadelphia.
Public officials received a briefing last week on a proposed 1,134-mile crude-oil pipeline to run from North Dakota, through South Dakota and eventually terminate in Illinois.
The Dakota Access Pipeline, with an estimated price of $3.78 billion, is designed to carry Bakken crude from the North Dakota oil fields to other pipelines in Illinois, and then to refineries.
The South Dakota Public Utilities Commission is holding a public hearing Thursday in Sioux Falls on the project. Depending on regulatory approval, construction is to begin early 2016 and be completed the following year. It is designed to carry up to 570,000 barrels of crude oil a day.
Regulatory Authority Approves Plains & Eastern Clean Line
The Regulatory Authority has approved the Plains & Eastern Clean Line, a $2 billion, 700-mile transmission line designed to bring Oklahoma wind power to Memphis.
The authority granted a Certificate of Public Convenience and Necessity, the final approval needed. The project already had received necessary approvals from the Federal Energy Regulatory Commission and the U.S. Department of Energy. Construction is set to begin soon, with the line going into operation by 2019.
More Opposition to Proposed Tx Lines for Prince William County Data Center
More than 800 residents packed a high school auditorium to protest the proposed construction of a transmission line to serve a data center in a semi-rural district near D.C.
Opposition formed quickly to the Dominion Virginia Power proposal, for which the company has not yet applied for permits with the State Corporation Commission.
Although Dominion has not identified the high-load customer for the transmission line, some elected officials have said the data center is to be built for Amazon.com. Dominion has prepared two separate route plans for the line — one above-ground, and one with portions to be underground. The part-underground route, which would run along Interstate 66, is estimated to cost about $140 million, nearly $80 million more than the aerial line.
Appalachian Power Plans to Upgrade 21-Mile Transmission Line
Appalachian Power announced last week it plans to upgrade a 69-kV transmission line that dates back to 1917.
The line, which runs 21 miles from Bland and Wythe counties in Virginia to Mercer County, W. Va., would be upgraded to 138 kV. The company said it needs the line to serve bigger load from an increased population.
The project could be completed by 2018 at an estimated cost of $70 million to $90 million.
Manitoba Hydro Seeks 3.95% Rate Hike, Another 3.5% Later
Manitoba Hydro, citing a need to update its aging distribution system, applied to the Public Utilities Board for a 3.95% rate increase to go into effect April 1. It also warned that it would need an additional 3.95% hike next year.
President and CEO Scott Thompson said the company needed the additional revenue to pay for upgrades to reduce outages. “No one wants to see energy prices rise, but it does cost money to replace these assets,” he said. “It’s really just replacing aging infrastructure that’s the key driver right now.”
The head of a coalition that has been critical of Manitoba Hydro’s expansion plans said the company’s rate increases may not be sufficient. “The path that they’re on, they’re fooling themselves if they think they can get by with that rate of increase,” said Garland Laliberte, president of the Bipole III Coalition, named for the controversial transmission project the coalition opposes.
The Federal Energy Regulatory Commission has approved Minnesota Power’s plan to build a 200-mile transmission line from Manitoba to Grand Rapids, Minn.
The 500-kV Great Northern Line will run from the Canadian border near Roseau, Minn., to a substation near Grand Rapids. The total cost is estimated at $560 million to $710 million. MISO has included the line in its transmission expansion report.
The line will be a joint project by Minnesota Power and Manitoba Hydro, and 383 of its 883 MW of transmission capacity will be used to deliver hydro power purchased by Minnesota Power for its customers. Minnesota Power will be the line’s majority owner.
Obama Administration Announces Plan to Cut Methane Emissions
The White House announced that it will implement a combination of regulations aimed at reducing methane emissions from oil and gas drilling, a significant source of greenhouse gases that affect climate change.
The administration said the new regulations aim to cut industrial emissions of methane by 40 to 45% over the next 10 years. Methane, a major component of natural gas, is emitted at gas wells and pipelines.
The Environmental Protection Agency is expected to set requirements for new or modified oil and gas wells and natural gas facilities. The rules are expected to be rolled out in the spring or summer.
FERC Scheduling Hearings on PennEast Pipeline Project
The Federal Energy Regulatory Commission is hosting a series of five public meetings on the proposed PennEast natural gas pipeline in Pennsylvania and New Jersey.
FERC will collect comments that will be used in the final determination on whether the pipeline will be built and what route it will take. The pipeline, financed by operating units of UGI and four major New Jersey gas utilities, is estimated to cost $1 billion. It would deliver Marcellus Shale gas from northeastern Pennsylvania to a pipeline interconnection near Trenton, N.J.
Opponents are already organizing. “The environmental impacts are very significant, very serious,” said Maya van Rossum of the non-profit Delaware Riverkeeper Network. “This environmental impact statement is critically important. We have seen uniformly in pipeline projects FERC not fully considering the impact.”
FERC, DOE Release Final Version of Data Code of Conduct
The final version of the Voluntary Code of Conduct for smart grid data privacy, designed to protect information gathered by smart meters and other technology, was released Friday.
The code protects customer data, including account information and records of energy usage. Under the code, data can be collected and used by service providers, third parties and contracted agents. President Obama held up the code as an example of privacy and cybersecurity during a speech last Monday.
DOE Energy Efficiency Standards Promise $78 Billion in Savings
The Department of Energy released its energy efficiency standards for fluorescent lamps and commercial ice makers, the last two such standards completed in 2014.
The standards for general-service fluorescent lamps alone are expected to save $15 billion in electricity bills and 90 million tons of emissions. Together, the 10 standards approved in 2014 promise energy savings of $78 billion through 2030 and reductions of more than 435 tons of emissions.
Report Claims Offshore Wind Industry Could Provide Double the Energy of Gas, Oil
A report by environmental group Oceana says that Atlantic offshore wind energy industry has the potential to generate twice the number of jobs and twice the amount of energy as offshore drilling for oil or natural gas.
“If we commit ourselves to developing offshore wind resources, it could definitely surpass all that we have with oil and gas,” said Andrew Menaquale, author of the report. “And also, keep in mind, once that oil and gas runs out, it’s gone. Offshore wind, well beyond that, will keep producing energy and will continue to power coastal communities.”
Millstone at Risk of Possible NRC Enforcement for Violation
The struggles of Millstone Power Station to repair a cooling pump has prompted the Nuclear Regulatory Commission to cite the Connecticut facility with a finding of low to moderate safety concern.
The NRC dispatched a team of inspectors to Millstone after problems emerged in 2013 and again in 2014 with a pump used to cool the reactor in the event of failure of both offsite power and backup generators. The findings were not publicized because of security concerns.
Dominion Resources, owner of Millstone, has said that policies and procedures are being changed as a result of the inspection findings.
NYISO last week asked the Federal Energy Regulatory Commission to exempt competitive transmission, including the Champlain Hudson project, from the ISO’s buyer-side mitigation rules.
The ISO and other stakeholders filed comments last week in response to a December complaint by transmission owners, who said NYISO’s market power rules are being misapplied to unsubsidized, competitive projects entering the ISO’s capacity market (EL15-26).
In its response, NYISO essentially asked FERC to order a rule change it was unable to achieve through its stakeholder process, where it was blocked by opposition from generators.
The transmission owners — Consolidated Edison of New York, Orange and Rockland Utilities, New York State Electric and Gas, Rochester Gas and Electric and Central Hudson Gas and Electric — told FERC on Dec. 4 that NYISO should amend its Tariff to include a competitive entry exemption in its BSM rules. The exemption would ensure that projects that did not have contracts with, or receive financial support from, any New York distribution companies, municipalities or the state government are not subject to an offer floor in the ISO’s capacity auctions.
TDI Holdings filed a separate complaint Dec. 16 asking FERC to exempt its high voltage, direct current Champlain Hudson project from the BSM rules after NYISO said it would be subject to the offer floor (EL15-33). The $2.2 billion project would deliver 1,000 MW from the Canadian border to the New York City metropolitan area. TDI said subjecting the project to the offer floor — a minimum clearing price — would jeopardize its commercial viability “because generation supply in Canada may be unwilling to execute transmission service agreements with TDI.”
Supporting TDI’s filing, the transmission owners said the project “emphasizes the need for the commission to grant the [TOs’] competitive entry exemption complaint.” At the same time, the group asked FERC to put off ruling on TDI’s complaint until it ruled on theirs, saying that if it were successful, TDI would not need a project-specific exemption.In their complaints, both the TOs and TDI say they recognize the need for BSM rules in preventing market power.
Buyer-Side Mitigation
NYISO’s rules are similar to PJM’s minimum offer price rule (MOPR).
The rules, approved by FERC in 2013, are intended to prevent state and local governments and large net buyers of capacity — market participants whose load dwarfs the amount of capacity they own — from subsidizing the entry of “uneconomic” generation projects into the capacity market in order to artificially lower prices.
A project is considered economic if its average forecasted price exceeds its net cost of new entry (CONE), or if the annual forecasted revenues in NYISO’s Installed Capacity (ICAP) Spot Market Auction exceed the default net CONE in the project’s locality. The default net CONE is defined as 75% of the net CONE of the reference unit used to determine that locality’s ICAP demand curve.
Uneconomic projects are subjected to the offer floor, defined as the lower of either its net CONE or the default net CONE.
Responses to Complaints
NYISO stakeholders filed comments both in support and in protest to the complaints last week.
In its comments, NYISO said it supported the TOs’ complaint, save for a few minor details. The ISO had proposed a competitive entry exemption last February, but it failed to gain the necessary 58% sector-weighted vote from the Management Committee.
“The NYISO asks that the commission: (i) replace certain proposals in the complaint with alternatives previously advanced by the NYISO in its stakeholder process; and (ii) direct the NYISO to adopt additional Tariff language that will be needed if the competitive entry exemption is to be legally effective and practicably implementable,” the ISO wrote.
It also echoed the TOs’ response to TDI, saying the company should wait until FERC rules on the broader exemption.
NYISO said that BSM rules are intended to prevent uneconomic entry, not protect market participants from competition. The ISO “believes that the BSM rules provide necessary protections to the market and that adding a competitive entry exemption would be entirely consistent with their purpose,” it said.
NYISO’s Market Monitor also supported the exemption, noting that it has proposed such a measure in its past three State of the Market reports.
New York City also voiced its support. “For many years, and in multiple proceedings before the commission and at the NYISO, the city has argued that the NYISO’s buyer-side mitigation rules are overbroad and serve more as a barrier to new entry than a protection against market abuses,” the city said. “Indeed, incumbent generating companies have wielded the mitigation rules as a sword (to strike against potential competitors) and a shield (to block new entry).”
Other stakeholders opposed the rule change.
“At first blush this proposal may seem harmless, but it would in fact create a myriad of new opportunities to artificially suppress capacity pricing in NYISO where out-of-market interference in the markets already is pervasive,” Entergy Nuclear Power Marketing said in its protest to the TO’s complaint.
“While couched in the guise of simply permitting ‘purely private investment’ to risk its own money, review of the proposed Tariff revisions reveals that blanket exemptions would be granted to projects that are not, in fact, purely private. The commission should protect the wholesale NYISO capacity market and reject the complaint.”
The Independent Power Producers of New York said “NYISO’s proposal, which was soundly rejected in the stakeholder process as part of a package of exemptions last year, is fatally flawed.”
The BSM rules were proposed by NYISO as a way of dealing with New York’s ongoing struggles with transmission congestion due to the heavy load imposed by the city. The U.S. Department of Energy has called New York City “an epicenter of transmission congestion.”
This also led to a controversial decision by NYISO to combine its five Lower Hudson River Valley capacity zones into one. The move attracted criticism from ratepayers and attention from the state’s U.S. senators. NYISO, however, claimed vindication when it announced last month that the new zone had led generators to reopen 1,900 MW in shuttered power plants. (See Coal-to-Gas Conversions, New Capacity Zone Ease NYISO Reliability Concerns.)
Michael J. Pacilio, president and chief nuclear officer of Exelon Nuclear, was promoted to executive vice president and chief operating officer of Exelon Generation, the business unit overseeing all of Exelon’s generating stations. Bryan Hanson, Exelon Nuclear COO, will assume Pacilio’s previous roles.
Dynegy Betting on Edwards Station, Commits to Emissions Investments
Dynegy said it plans to upgrade pollution controls at the E.D. Edwards coal-fired plant in Bartonville, Ill., rather than shut the 695-MW plant down in response to more stringent emissions standards. It told Illinois officials that the improvements would reduce Edwards’ noxious emissions by 90%.
As part of the agreement reached with state environmental authorities, Dynegy will continue its 10-year practice of burning low-sulfur coal.
Environmental groups were pleased with the news, but they cautioned that the plant would still produce waste. “While Dynegy’s announcement represents one step in addressing one type of coal plant emissions, there are still many harmful pollutants emitted from the coal plant’s stacks and dumped into its ash ponds on a daily basis,” a Sierra Club spokesperson said.
Exelon Appealing Valuation of Byron Nuclear Station
Byron Generation Station (Source: Exelon)
Exelon often touts the value of its nuclear generating stations. But not for tax purposes.
For the third straight year, the company is appealing Ogle County’s assessed value of its Byron Generating Station in Illinois. The county’s Supervisor of Assessments puts the value of the nuclear plant at $509 million. Exelon says it should be set at $212.6 million.
The company appealed assessments in 2012 and 2013, but both times the Ogle County Board of Review upheld the valuations — $449 million in 2012 and $509 million in 2013. Exelon’s appeals are still pending before the Illinois Property Tax Appeal Board.
PPL is asking for more time to meet Federal Energy Regulatory Commission conditions to win approval of the spinoff of its generating assets to Talen Energy.
In December, FERC set a series of conditions to increase market competition for the spinoff. PPL told FERC last week that it would be unable to complete the plan by the Jan. 20 deadline and asked for an extension of 10 days. Talen Energy would combine the generating assets of PPL and Riverstone Holdings.
PPL and Riverstone are still determining which plants to divest to meet the FERC conditions. PPL spokesman George Lewis said an extension would not delay completion of the deal.
JD Power: PSE&G Ranks Highest in Customer Satisfaction Among Large Eastern Utilities
Public Service Electric & Gas topped the list for business customer satisfaction among large Eastern electric utilities, according to the latest survey by J.D. Power.
PSE&G scored 685, above the segment average of 659 for electric business customers. PPL came in at 681, while Exelon’s PECO scored 644, dropping in rankings from fourth to ninth. Pepco Holdings’ Delmarva Power & Light ranked highest among mid-sized utilities. All three of Duke Energy’s utilities — Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida — came in at the bottom of the Southern region rankings.
NRG Concentrating on Solar as Energy Generation Prices Droop
NRG Energy is taking aim at the rooftop solar installation market in the face of declining profits in the conventional power generation industry.
NRG President David Crane said his company wants to move up the charts among domestic solar installers. SolarCity Corp. current ranks first in the U.S., according to GTM Research, and NRG ranks fifth. “We expect to convincingly persuade our investors that NRG has an embedded SolarCity within it,” Crane said.
The company plans to install 250 MW of home solar systems this year, 875 MW by 2017 and 2,400 MW by 2022. Market leader SolarCity installed 520 MW last year. “Everyone is beginning to believe that residential solar is this trillion-dollar market that currently has about 1% market penetration,” Crane said.
DALLAS — SPP members last week approved spending $270 million on transmission improvements over the next five years, but not before stakeholders expressed misgivings about the investment — which comes after the RTO spent $1.8 billion on upgrades in 2014.
Several members of the Markets & Operations Policy Committee complained that the spending was benefitting wind exporters rather than internal loads and that the RTO’s load projections — driven in part by oil and gas producers — might prove too high.
Members also rescinded approval for a controversial project in the Ozarks in the face of falling demand projections and split one project in two, agreeing to consider generation alternatives to a local voltage problem.
Doubts about Load Projections
Burton Crawford of Kansas City Power and Light declined to endorse the 2015 Integrated Transmission Plan 10-year (ITP10) assessment, which was approved by voice vote with some nays and multiple abstentions.
Crawford said the assessment predicts wholesale sales 50% higher than his company’s internal estimates. “We’re a little concerned with the calculations behind this,” he said.
“We’re concerned that the load forecast is way off,” said the Empire District Electric Co.’s Bary Warren, who noted that much of the growth is based on anticipated demand from oil and gas producers. With the continued fall in oil prices, he said, “we need to determine if these projects will be needed.”
“What if oil goes to $20 a barrel and everyone stops drilling? Or there’s more earthquakes in North Texas and that affects fracking?” he added. “Things have changed in the last six months.”
But Jay Caspary, SPP director of research, development and special studies, noted that while spot prices have fallen to $45 a barrel, futures prices remain above $80, suggesting the price drop may be short-lived.
Several speakers also noted the volume of existing wind generators and oil producers that are unable to connect to SPP.
Xcel Energy’s Southwestern Power System (SPS) area in North Texas and eastern New Mexico is showing the worst potential problems in SPP’s reliability studies.
“They’re out there pumping oil. So there’s additional load that we could add to our system if we had the infrastructure in place,” Caspary said.
Caspary said there has been no significant drop in activity in the SPS territory, noting that The Wall Street Journal recently reported that rigs are being redeployed from the Eagle Ford shale zone in south Texas to the Permian Basin, an SPS territory in southeast New Mexico.
Bill Grant of Xcel Energy said there is at least 80 MW of load that wants to be served, including 30 MW of requests that were denied service and 53 MW of distributed generation.
Warren said the near-term prospects will become clearer this spring when oil producers announce their capital spending plans.
Cost Allocation, Modeling Complaints
SPP’s cost allocation and modeling methodology also came under criticism.
“We’re getting allocated these reliability benefits [for improvements] nowhere near our system,” Crawford said.
In abstaining on ITP10, Warren cited concern about how benefits are calculated.
“We need to think about whether there are some fundamental problems with the way we model our system,” commented Richard Ross of American Electric Power.
Jason Atwood of Northeast Texas Electric Cooperative voted against the 2015 Integrated Transmission Plan Near-Term assessment (ITPNT), which was endorsed with several abstentions. “I don’t want my load to pay for transmission to move power outside the footprint,” he said.
Atwood said wind generation in SPP has never exceeded 1,000 MW during the summer peak, “and we’re modeling for 7,000” MW based on transmission service reservations.
Discussing SPP’s strategic initiatives later in the meeting, Michael Desselle, SPP vice president of process integrity and chief administrative officer, said the RTO’s highway/byway cost allocation methodology is “not appropriate” for exports.
Jeff Knottek, of City Utilities of Springfield, Mo., raised a more acute modeling issue, citing the occurrence of transmission load relief procedures on two flowgates between SPP and Associated Electric Cooperative.
“No one can seem to replicate this problem that occurs in real time. We need to dig down and find what the cause of the problem is.”
2015 ITP10
The MOPC approved a portfolio of $273 million in engineering and construction costs for projects based on the ITP10 assessment of a business-as-usual future and one that assumed up to 20% of hydro capacity and conventional generation — including most coal units under 200 MW — would be lost.
It included 166 miles of reliability projects estimated at almost $210 million and 94 miles of economic projects costing almost $70 million.
The MOPC’s approval also recommended the Board of Directors issue Notifications to Construct (NTCs) for 16 projects needed in 2019. These projects’ cost of $142 million was reduced when members amended the plan to split the largest project, totaling $36 million, into two.
The original project would add a new substation with a 345/115-kV transformer on the Hitchland-Finney 345-kV line; a new 1-mile, 115-kV line from the substation to the Walkemeyer 115-kV line; and a second 21-mile, 115-kV line from Walkemeyer to North Liberal.
Members voted to split the project in two based on differences in the needed in-service dates. Some members suggested studying whether converting the 76-MW Cimarron natural gas generator to a synchronous condenser would eliminate the need for the Walkemeyer-North Liberal line.
Other projects exceeding $10 million were an upgrade of the Iatan-Stranger Creek 161-kV line to 345 kV ($16.1 million) and the rebuild of the South Shreveport-Wallace Lake 138-kV line ($10.3 million).
2015 ITPNT
The 2015 ITPNT, which addresses reliability problems through 2020, includes 42 projects totaling $257 million. Eight of the projects also were identified in the 10-year plan.
More than half of the total is slated for New Mexico ($82.1 million) and Kansas ($50.7 million).
The MOPC separately endorsed two Consolidated Balancing Area projects in the 2015 ITPNT: an upgrade of 138-kV terminal equipment at Benton ($480,000) and a rebuild of the Southwestern Station-Carnegie 138-kV line ($13.4 million).
Ozarks Project Cancelled
Members also recommended the Board of Directors withdraw the NTC for the 41-mile Kings River-Shipe Road 345-kV line.
The NTC was issued following the 2007 Ozark Study as one of several 345-kV projects that would create a loop around Northwest Arkansas and extend eastward across northern Arkansas and into southern Missouri.
Southwestern Electric Power Co. opposed the route selected and requested rehearing. The project also was opposed by a citizens group, Save the Ozarks.
Lanny Nickell, SPP vice president of engineering, said a review last year showed a 50% drop in load growth rates in the area critical to the project’s need. There was a 54-MW drop in post-contingency loading on the East Rogers-Avoca 161-kV line, “a fairly large percentage of [the new line’s] capability,” Nickell said.
“We’re not seeing nearly the severity in the number of overloads that we saw the last time,” he said.
The Federal Energy Regulatory Commission has approved changes to NYISO’s credit requirements to protect the ISO from defaults by market participants that under-forecast their loads (ER15-470).
The new rule will require extra collateral from market participants that consistently fail to forecast their load within 90% of their actual meter data. It also prohibits those participants from using unsecured credit.
NYISO bills participants initially based on forecast load, with true-ups four months later, when meter documenting actual load is available to the ISO.
“During periods of increased prices like the 2013/2014 winter cold snaps, if a market participant is under-forecasting, the current credit requirements may not cover the exposure caused by the under-forecasting,” the ISO explained in its filing with the commission. “This potential exposure can grow the longer the market participant under-forecasts and [other] market participants could be exposed to potential bad debt losses as the NYISO may not have sufficient credit support in place to cover this true-up exposure if the market participant ultimately defaults.”
FERC said the new rules will go into effect on Feb. 18, unless NYISO requests a later date.
Minnesota’s ALLETE Clean Energy will increase its MISO wind portfolio by one-third with a $10 million acquisition from EDF Renewable Energy.
The companies asked the Federal Energy Regulatory Commission last week to approve ALLETE’s acquisition of EDF’s Northern Wind Energy, which owns 97.5 MW of wind capacity in Minnesota (EC15-58).
Northern Wind owns the 85.5-MW Chanarambie wind farm in Murray County, Minn., as well as eight 1.5-MW qualifying facilities in Minnesota: Buffalo Ridge Wind Farm, Moulton Heights Wind Power Project, Muncie Power Partners, North Ridge Wind Farm, Vandy South Project, Viking Wind Farm, Vindy Power Partners and Wilson-West Wind Farm.
All of the facilities being sold have long-term power purchase agreements with Northern States Power (NSP).
They would be acquired by ALLETE’s subsidiary, ACE Mid-West, which owns a 50-MW wind farm in Condon, Ore., and three wind generators in MISO with a combined capacity of about 290 MW.
The applicants requested approval by Feb. 17 to allow them to close the deal by March 1.
They said the deal raises no market power issues. “Ignoring the fact that the capacity from those facilities is fully committed to NSP under a long-term PPA, it would result in ACE and its affiliates controlling 2,991.6 MW, or 1.69%, of the installed capacity in MISO,” they told FERC.
A sister company of Minnesota Power, ALLETE was formed in 2011. It had no wind assets until last year, when it purchased four wind farms in Oregon, Minnesota and Iowa from NRG Energy and AES for a combined $41.9 million.
It also has an option to acquire a 101-MW wind farm in Armenia Mountain, Pa., from AES and plans to build a 107-MW wind farm near Hettinger, N.D., that it will sell to Montana-Dakota Utilities for about $200 million.
