WILMINGTON, Del. — PJM officials said last week they intend to move up the day-ahead energy market schedule despite a lack of consensus among stakeholders.
RTO officials said they believe the change is necessary as a result of the Federal Energy Regulatory Commission’s April order moving the timely nomination cycle deadline for gas to 2 p.m. ET from 12:30 p.m. and adding a third intraday nomination cycle.
The order required grid operators to adjust the posting of their day-ahead energy market and reliability unit commitment processes to a time “sufficiently in advance” of the timely and evening gas nomination cycles to allow generators to obtain gas (or to show cause why such changes are not necessary). Compliance filings are due July 23. (See FERC Approves Final Rule on Gas-Electric Coordination.)
Adrien Ford, director of market evolution, said PJM officials determined that they must change the energy market deadlines to comply with the order.
PJM’s filing will propose moving the deadline for submitting day-ahead offers up 90 minutes to 10:30 a.m. ET from noon. The RTO said it will post day-ahead results by 1:30 p.m., up from the current 4 p.m., as it reduces its clearing time to three hours from four.
The rebid window for the reliability assessment and commitment (RAC) run will be open from 1:30 to 2:15 p.m., up from the current 4 to 6 p.m. (Day-ahead commitments are based on demand bids from load-serving entities; the RAC run adds resources PJM believes may be needed based on PJM’s load forecast.)
In a poll of 51 stakeholders, none of the five suggested day-ahead clearing windows received a supermajority.
Slightly more than half of voters selected as their first choice a clearing window of 11 a.m. to 2 p.m., which PJM said would be too late to comply with the order. A clearing window of 10:15 a.m. to 1:15 p.m. was the first choice of 29%.
PJM said the window it proposed “received the highest overall support.” Although it was the first choice of only 8%, 31% picked it second and 59% made it their third choice.
Ford said stakeholders expressed a variety of opinions on how much time they needed between the posting of energy market awards and the gas nomination deadlines. “There was one stakeholder that needed 10 minutes. We had other members who said they needed an hour. There were others who didn’t think any of these [proposed windows] were sufficient,” Ford said. “Based on what I heard, 30 minutes was a way to meet” the FERC compliance requirement.
Stakeholder Reaction
Consultant Bob O’Connell said the changes increase risk premiums because generators will be basing offers into PJM’s markets on gas transactions executed during periods in which there is less price transparency. “You’re imposing higher costs on customers,” he said, adding that PJM should set a goal of clearing the day-ahead market in two hours or less.
John Citrolo of Public Service Electric and Gas said his company, which owns gas generation, would prefer a somewhat later start than proposed by PJM. But he added, “If gas traders get to their desks by 7 a.m. and show me some liquid prices by 9 a.m.,” the industry will adapt.
David “Scarp” Scarpignato of Calpine said his company supports PJM’s proposal, calling it “critical” to the company, whose fleet is virtually all gas-fired.
Generators with firm transportation can use second intraday nomination (ID 2) to bump those without firm transport who bought gas in ID 1. ID 3 is not bumpable.
As a result, if generators selected on the reliability run aren’t able to get their gas nominations in time for ID 2 at 3:30 pm., he said, “We’re not going to get gas.”
“Under [Capacity Performance], PJM has told generators to secure firm gas transport,” he added. “What’s the point of getting firm gas transport if we don’t get committed in time to use it?”
“We think we can get most RAC run commitments out before ID 2,” said Stu Bresler, PJM vice president of market operations.
Citrolo noted that PJM clears about 94% of its megawatts in the day-ahead market, urging, “Don’t turn things upside down for the other 6%.”
Scarp countered that on some days, the RAC run could provide as much as 12,000 MW. “It would be absolutely critical for reliability,” he said.
“We’ve been managing that later rebid window with one less nomination cycle for years,” responded Citrolo.
“And we’ve had a lot of units that can’t get gas,” interjected Mike Kormos, PJM executive vice president of operations. “We’ve been managing, but not that well.”
PJM’s Independent Market Monitor told the Federal Energy Regulatory Commission last week that proposals by the RTO and a marketer to change the financial transmission rights (FTR) forfeiture rule would weaken protections against market manipulation.
The Monitor leveled the criticism in comments filed last week in the Section 206 case FERC ordered last year regarding the RTO’s treatment of virtual transactions (EL14-37).
The Monitor said PJM’s proposal to use a load- or generation-weighted reference bus rather than the largest impact bus would “functionally eliminate” the forfeiture rule under the current, non-portfolio approach to evaluating impacts of transactions on congestion.
In September, FERC ordered the Section 206 proceeding to determine whether PJM is improperly treating up-to-congestion transactions differently than incremental offers (INCs) and decrement bids (DECs). While INCs and DECs are charged uplift and subject to the FTR forfeiture rule, UTCs are exempt from both.
Ruling by October?
The Monitor’s criticism was in response to some of the almost two dozen comments filed in late May following a Jan. 7 technical conference on the issue.
In opening the Section 206 docket last year, the commission said it would rule within five months after it receives comments following the technical conference. That would put FERC on schedule for a ruling by the end of October. (See FERC Issues Request for Comments in UTC Uplift Docket; Ruling by October?)
The Monitor’s reply, filed June 23, was also critical of a proposal by EDF Trading to replace the forfeiture rule with individual enforcement actions.
“An enforcement action approach, relative to a rule-based approach, is inefficient, non-transparent and of limited value as a deterrent to market manipulation,” the Monitor said. “Such a rule is unclear and effectively unenforceable, which may be the point.”
The Monitor added that PJM’s current rule not subjecting UTCs to forfeitures “ignores [the] laws of physics.”
“As the power flows from the UTC source to the UTC sink, it flows across constraints. As a result, the net flow from a UTC should be treated the same as an INC when the UTC net flow is an injection and the same as a DEC when the UTC net flow is a withdrawal, under the FTR forfeiture rule.”
Uplift Task Force to Resume
FERC’s ruling in the 206 case may result in the application of uplift charges to UTCs, an issue that has split PJM stakeholders. UTC trading volumes collapsed after Sept. 8, the refund-effective date set by FERC for any uplift assessments.
PJM told the Markets and Reliability Committee on Thursday that the Energy Market Uplift Senior Task Force (EMUSTF) will resume regular meetings in August or September.
Stakeholders had asked to suspend the task force’s efforts on uplift cost allocation pending FERC action on PJM’s Capacity Performance proposal. FERC largely approved the proposal June 9.
Until last week — when it met to discuss the results of the backcast analysis on several cost allocation proposals — the task force had not held a meeting since April.
The Supreme Court ruled Monday that the Environmental Protection Agency acted “unreasonably” when it failed to consider costs before deciding to regulate mercury and other toxic emissions from power plants under the Clean Air Act.
The court’s 5-4 ruling did not void EPA’s authority to regulate the emissions but will require the agency to rewrite the Mercury and Air Toxics Standards (MATS) with a consideration of costs at the beginning of the process. It remanded the case to the D.C. Circuit Court of Appeals for further review.
Muted Impact
The ruling in Michigan v. Environmental Protection Agency is not expected to affect the number of coal-fired plant retirements. Industry analysts say about two-thirds of the nation’s 460 coal plants are already in compliance and investments in emission controls have already been made. (See MATS Challenge Too Late for Targeted Coal Plants.)
“EPA is disappointed that the court did not uphold the rule, but this rule was issued more than three years ago, investments have been made and most plants are already well on their way to compliance,” EPA spokeswoman Melissa Harrison said in a statement.
“Because of the stricter air regulations that have been in place in New England for years, most plants would not have been affected by this rule,” said ISO-NE spokeswoman Marcia Blomberg. “And further, the economics of low-priced natural gas have driven many of the region’s older fossil-fired units to retirement, so we expect there will be limited impact from this ruling.”
NYISO is analyzing the decision, spokesman David Flanagan said.
Coal plants also are under pressure from EPA’s cross-state pollution rule and the carbon emission rule expected later this summer. Even without MATS, EPA Administrator Gina McCarthy told HBO’s “Real Time with Bill Maher” on Friday, “we’re still going to get at the toxic pollution from these facilities.”
Overreach
Nevertheless, the ruling gave EPA’s opponents something to celebrate. “The Supreme Court’s decision today vindicates the House’s legislative actions to rein in bureaucratic overreach and institute some common sense in rulemaking,” House Majority Leader Kevin McCarthy (R-Calif.) said.
Coal stocks rallied on the news. Peabody Energy rose almost 10% on the day, while Alpha Natural Resources was up 8.6%, Cloud Peak Energy gained 6.4% and Arch Coal jumped 4.5%.
‘Appropriate and Necessary’
MATS went into effect in April, although some power plants were given an extension until April 2016. Michigan v. Environmental Protection Agency combined what began as three challenges by industry groups and 23 states.
After the D.C. Circuit upheld the rule last year, the Supreme Court agreed to consider whether EPA acted unreasonably by refusing to consider costs in determining whether it is “appropriate and necessary” to regulate hazardous air pollutants emitted by electric utilities.
“EPA strayed well beyond the bounds of reasonable interpretation in concluding that cost is not a factor relevant to the appropriateness of regulating power plants,” Justice Antonin Scalia wrote in the majority opinion, in which he was joined by Chief Justice John Roberts and Justices Clarence Thomas, Samuel Alito and Anthony Kennedy.
“It is not rational, never mind ‘appropriate,’ to impose billions of dollars in economic costs in return for a few dollars in health or environmental benefits,” Scalia said.
In a dissent, Justice Elena Kagan noted that while EPA’s power plant regulations would have been unreasonable without considering costs, the agency had taken an “exhaustive” consideration of costs.
“Over more than a decade, EPA took costs into account at multiple stages and through multiple means as it set emissions limits for power plants,” Kagan wrote. “And when making its initial ‘appropriate and necessary’ finding, EPA knew it would do exactly that — knew it would thoroughly consider the cost-effectiveness of emissions standards later on.” Justices Sonia Sotomayor, Stephen Breyer and Ruth Bader Ginsburg joined in the dissent.
Cost-Benefit
EPA has said MATS compliance will cost electric utilities $9.6 billion annually but produce total benefits of at least $37 billion to $90 billion per year, while preventing as many as 11,000 premature deaths and 130,000 asthma attacks. It will also eliminate 5,700 hospitalizations and emergency room visits and 540,000 missed workdays, the agency said.
However, only a fraction of the benefits — $500,000 to $6.2 million annually — are directly related to cuts in mercury emissions. The remainder are “co-benefits” that arise not directly from reducing toxic emissions, but from reductions in particulate matter and carbon emissions expected to result from the standards.
EPA critics have said the agency has engaged in over counting, citing the same co-benefits to justify multiple EPA regulations.
Clean Air Act Amendments
The MATS regulations were initiated when Congress amended the Clean Air Act in 1990. The amendments ordered EPA to regulate 189 hazardous air pollutants, including mercury, arsenic and cadmium, which had not been previously controlled. (See MATS: 25 Years in the Making.)
“It is disappointing that a quarter century after the 1990 Clean Air Act amendments, Americans are still waiting on the first-ever limits on mercury from coal-fired power plants, the single largest source of these toxic emissions,” Ken Kimmell, president of the Union of Concerned Scientists, said in a statement.
Implications for Future Regulations
The ruling is a “groundbreaking administrative-law case,” Justin Savage, a partner at the law firm Hogan Lovells and a former Justice Department environmental lawyer, told the National Journal. “It essentially says that when a statute is ambiguous, an agency must consider costs.”
“After this decision, an agency would not want to walk into court saying, ‘Your Honor, we did not consider costs at all when deciding to take regulatory action on an issue,’” agreed environmental law professor Jonathan Adler of Case Western Reserve University.
Sean Donahue, who represents environmental and public health groups that supported EPA, told The New York Times that the ruling will require the agency “to do more homework on costs.”
“But I’m very confident that the final rule will be up and running and finally approved without a great deal of trouble. This is a disappointment. It’s a bump in the road, but I don’t think by any means it’s the end of this program.”
FBR Capital analyst Benjamin Salisbury told StreetInsider.com that the ruling could ultimately result in tougher regulations on mercury and toxic emissions. “EPA could resurrect MATS in a stronger form, given the ‘baseline’ EPA will observe includes less of the older, high-emission coal-fired plants and current units with more emission control than previously,” he said.
NYISO and SPP told the Federal Energy Regulatory Commission last week it should reject transmission developers’ protests to their recent Order 1000 compliance filings.
NYISO said that LS Power and NextEra Energy made “inaccurate or misleading statements” in response to its filing, and that the protests raise issues outside of the proceeding and propose changes that would impair system reliability (ER13-102).
LS Power said an incumbent transmission owner should be required to execute a development agreement if its regulated backstop solution is selected by NYISO as the more efficient or cost-effective transmission. “It is important that the developer agreement impose no more stringent obligations on the developer of an alternative regulated solution,” it wrote.
NextEra said the filing burdens alternative developers without guaranteeing faster project completion.
NYISO responded that the incumbents are already required to file a development agreement under Order 1000. The ISO said the language suggested by NextEra “would interfere with the existing requirements to timely identify and address potential project delays.”
SPP Protest
LS Power also filed a protest against SPP, which responded by saying its May 18 compliance filing fully complied with FERC’s directives.
The RTO said LS Power’s arguments were a “collateral attack” on Order 1000. “SPP has demonstrated full compliance with all of the regional transmission planning and cost allocation requirements of Order No. 1000” and FERC’s compliance orders, SPP said (ER13-366-006).
In April, FERC ordered SPP to submit a fourth compliance filing revising Tariff provisions pertaining to “‘rights of way where facilities exist.’” The commission said SPP must acknowledge that “retention, modification or transfer” of rights of way remain subject to state and local laws.
SPP said its proposal is “substantially similar” to FERC’s Order 1000 language and that LS Power failed “to demonstrate otherwise.”
LS Power said SPP should only invoke the right-of-way language when the relevant law expressly “prohibits” alteration of existing rights of way and there is only one “feasible route” for the transmission project that would alter a transmission owner’s use over its existing rights of way.
The RTO also said LS Power’s request “seeks to impose requirements on SPP not found in Order No. 1000 and not required by the commission in the SPP compliance orders or in other Order No. 1000 transmission planning regions.”
PJM, ERCOT and CAISO have asked the Commodities Futures Trading Commission to remove language from a draft order that they say could undermine the broad exemptions the commission granted RTOs and ISOs in 2013.
The three grid operators filed joint comments last week concerning CFTC’s May 2015 draft order on a request from SPP seeking the same exemptions from the Commodity Exchange Act that the commission granted the six other RTOs and ISOs in 2013.
CFTC’s 2013 order exempted electricity transactions subject to tariffs approved by the Federal Energy Regulatory Commission from most provisions of the CEA while retaining its general anti-fraud and anti-manipulation authority over such transactions. SPP was the only grid operator not party to the 2013 order because its day-ahead market, the Integrated Marketplace, was not fully implemented until March 2014. (See CFTC Approves Dodd-Frank Exemption for RTOs.)
Private Rights of Action
The three grid operators said they are concerned that the CFTC draft order to SPP included, for the first time, a statement of its intent “to preserve private rights of action” under Section 22 of the CEA.
“Although the proposed exemption involves another RTO, the commission’s insertion … can be construed as a retroactive attempt to modify the ISO-RTO final order and, therefore, raises fundamental fairness and regulatory policy issues that potentially impact the ISO-RTO final order,” they said.
Although the text of the proposed SPP order does not preserve a private right of action, the preamble states that “[i]t would be highly unusual for the commission to reserve to itself the power to pursue claims for fraud and manipulation … while at the same time denying private rights of action and damages remedies for the same violations. …Thus, the commission did not intend to create such a limitation and believes the [2013 order and the proposed SPP order do not] prevent private claims for fraud or manipulation under the act.”
“In the draft order, the CFTC generally addressed whether private parties could bring actions against RTO/ISO market participants they allege to have manipulated energy products and markets, which had otherwise been exempted from CFTC regulation,” PJM said in a press release. “However, rather than clarifying the CFTC’s intent on private rights of action, the draft order is confusing and could increase legal exposure to RTO/ISO market participants.”
PJM said its concerns were heightened by a recent civil case in Texas arising out of market conduct in ERCOT, which it said “raised questions as to whether the CFTC intended to also preserve the ability for a private party to sue a market participant for alleged market manipulation.”
Regulatory Certainty
Exempting ISO and RTO transactions from private rights of action under the CEA is essential to avoiding conflicting or duplicative regulation and providing market participants with certainty about the regulatory treatment of the transactions, the grid operators said.
The three requested that CFTC “remove its proposed statement about private claims in the preamble language or conform it to the text of the proposed SPP order. Alternatively, the commission should defer any action on its statement of intent until after it has conferred with its fellow regulatory and enforcement agencies.”
SPP’s application to CFTC asked for an exemption from provisions of the CEA and CFTC regulations for transmission congestion rights, energy transactions and operating reserve transactions. CFTC issued its draft order May 18.
PJM, ERCOT and CAISO filed their comments June 22 after consulting with other ISOs and RTOs, FERC and industry trade groups.
New England transmission owners and a coalition of state officials and consumer groups are expected to conclude a Federal Energy Regulatory Commission evidentiary hearing this week in their long-running transmission rate dispute.
The hearing, which began last week, concerns the return on equity earned by the transmission owners. It is a consolidation of two complaints initiated by the states’ attorneys general, combining a docket about transmission charges from December 2012 to March 2014 (EL13-33) with a second dispute over the ROE from June 2014 through October 2015 (EL14-86).
The hearing is being conducted under the new framework FERC set in its June 2014 ruling that switched to a two-step discounted cash flow (DCF) model incorporating short-term and long-term growth rate estimates. The commission previously had relied on only short-term growth rates as benchmarks for electric transmission ROEs. (See FERC Splits over ROE.)
The ruling lowered the New England TOs’ base ROE from 11.14% to 10.57%, the 75th percentile of a “zone of reasonableness” of 7.03% to 11.74%.
The plaintiffs seek a base ROE of 8.75% for the period ending March 2014 and 8.12 to 8.82% for the later time period.
FERC trial staff is recommending ROEs of less than 10%.
“The evidence confirms what the complainants’ prima facie showing indicated: all of the ROEs at issue have become unjust and unreasonable. … Even if — contrary to the evidence — it were found that these base ROEs should again be set at the top quarter of the DCF range, the resulting values would be 9.52% and 9.91%,” trial staff wrote in a prehearing brief. “Either way, the 11.14% and 10.57% base ROEs that customers have paid and continue to pay are well above any just and reasonable level.”
A recommended decision by the administrative law judge is expected by the end of the year with FERC issuing a final ruling in mid-2016.
The plaintiffs are seeking refunds of up to $180 million and say their proposed ROE reduction would save New England ratepayers an additional $74 million annually.
A list of joint transmission projects between MISO and SPP has been trimmed and sent further down the line toward possible board approval late this year.
MISO’s Planning Advisory Committee last week voted to recommend to the MISO-SPP Joint Planning Committee three projects totaling $156.9 million near the RTOs’ seams in Kansas, Nebraska and Louisiana.
MISO and SPP staff initially identified nearly 70 potential economic projects to relieve congested flow gates. In May, the MISO-SPP Interregional Planning Stakeholder Advisory Committee narrowed that list to four transmission projects totaling $276 million. (See SPP, MISO Considering 4 Transmission Projects.)
The list was reduced to three before it was presented at the PAC on June 24. The revision eliminated one of two 345-kV transmission projects proposed to straddle the Kansas-Nebraska border.
Surviving the cut is the proposed $133.8 million, 78-mile Elm Creek-NSUB transmission line. Removed from the list is the $138.8 million, 100-mile Elm Creek-Mark Moore line that would also have run in the north-south direction across the border but would have been further east.
Elm Creek-NSUB had a benefit-cost ratio of 1.22 versus 1.03 for Elm Creek-Mark Moore. Only 7% of the benefits of the latter project would have gone to MISO, compared to 20% from Elm Creek-NSUB.
The three transmission projects would provide an estimated $234.5 million in benefits, based on a net present value analysis over 20 years, according to a report on the MISO-SPP Coordinated System Plan released June 18.
Cost-Benefit Questioned
Though none of the stakeholders at the PAC meeting voted against recommending the three projects, some had questions about how costs would be allocated to MISO. In particular, some questioned how MISO South might be affected by Elm Creek-NSUB.
Eric Thoms, MISO’s manager of planning coordination and strategy, explained that 80% of Market Efficiency Project costs are allocated to zones that benefit, with the remaining 20% spread on a postage stamp basis. “If MISO South is not identified as a [beneficiary], they would not be allocated any of the costs,” he said.
Neal Balu, director of transmission policy at Wisconsin Public Service Corp., and George Dawe, vice president at Duke American Transmission Co., questioned why MISO was pursuing projects that don’t meet the minimum 1.25 ratio benefit-cost ratio required of other MISO projects. “I’m wondering how the 1.22 B-C becomes any different in a MISO analysis than it was in the MISO/SPP joint amount,” Dawe said. “… I think it’s a slippery slope. I think that means you evaluate everything and you never stop.”
Thoms said the projects are being evaluated under the MISO-SPP Joint Operating Agreement, which only requires that “an interregional project has to be greater than $5 million, it has to show benefit to each region of more than 5% and [that] the benefits outweigh the costs.”
He was backed up by Jenell McKay, a senior MISO analyst, who explained that because MISO receives only 20% of the benefit of Elm Creek-NSUB, it would be allocated 20% of the cost, or approximately $30 million.
“When MISO takes the project to our regional review process, assuming we get that far, our percent of the costs will be the denominator in the B-C ratio. … So we’re not going to use the full project cost when we determine our regional B-C ratio,” she said.
Next Steps
The projects next go to the MISO/SPP Joint Planning Committee for a vote, and then return to PAC later this summer for regional review. Potential board approval could come late this year.
The projects are also receiving scrutiny by SPP in a roughly parallel track.
Regulators Call Halt to Eversource Work Site Closure
The Public Utilities Regulatory Authority has ordered Eversource Energy to delay the proposed closure of a regional district office in Simsbury until it could assess the effect of a previous round of closures of district work centers throughout the state.
Eversource sought the closures as a move to consolidate its state footprint and lower operating costs. Attorney General George Jepsen and Consumer Counsel Elin Swanson Katz argued that the closure of the Simsbury work center could slow Eversource’s response to power outages in the Farmington Valley during major storms.
PURA noted that Simsbury is largely isolated from major highways. Regulators approved the closure of three other centers. Altogether, 400 workers will be moved to other work sites.
The Commerce Commission voted 4-1 to approve Wisconsin Energy Corp.’s $9.1 billion acquisition of Integrys Energy Group but attached a number of conditions mostly directed at Peoples Gas, an Integrys gas-distribution system in Chicago.
The ICC will require Peoples Gas to file reports by September committing itself to the scope, schedule and cost for a gas-main replacement project that has been the target of much criticism. The project’s cost, initially estimated to be about $2 billion, has more than doubled.
The ICC approval is the final regulatory hurdle required for the merger, which expands WEC’s reach from Wisconsin to Illinois, Minnesota and Michigan.
Is the State Headed for a Competitive Energy Market?
A consortium of more than two dozen large-scale energy users is pushing for the state to open up to retail energy competition.
Indiana Industrial Energy Consumers argues that the state’s energy prices have gone from being the nation’s fifth-lowest in 2003 to 26th lowest in 2014. Meanwhile, neighboring states Illinois and Ohio, which once had higher average industrial electricity rates, now have lower rates.
The consortium plans to lobby lawmakers this summer to expand opportunities for co-generation plants at the industrial facilities. The companies also are discussing a broader reform that could increase market competition for industrial and residential customers.
The Public Service Commission has approved a rate-increase settlement for Kentucky Power.
The agreement allows the utility to increase its annual revenue by $45.4 million, about 57% of the company’s initial rate request. Kentucky Power also agreed to drop its appeal of an earlier PSC decision disallowing certain fuel costs, which represents a savings to customers of about $54 million.
Other provisions include imposition of a 15-cent customer monthly charge to be matched by company shareholders that is expected to generate about $300,000 per year to support economic development in the company’s service area. Kentucky Power, a subsidiary of American Electric Power, has about 173,000 customers.
The Legislature has passed a bill that would give residents who are not represented by local governments an opportunity to exclude their communities from areas considered for large wind power projects.
The bill would give residents of the Unorganized Territory the right to petition the Land Use Planning Commission to pull out of the expedited wind permitting area, a region designated in the 2007 Wind Energy Act. Under the law, organized municipalities can pass ordinances to control wind power projects, but residents in areas without organized government cannot.
The Unorganized Territory — the part of the state that has no incorporated municipal government — covers slightly more than half the state’s area, including much of the interior and some coastal islands.
Legislature Overrides Veto of Energy Efficiency Bill
LePage
The Legislature unanimously overrode Gov. Paul LePage’s veto of a bill that corrects a one-word clerical error potentially worth nearly $38 million for an energy efficiency program.
The bill reinserts what has become known as the missing “and” in a law that funds the Efficiency Maine program. It was made necessary in 2013 when the Legislature passed a massive energy bill that authorized a surcharge on electricity ratepayers but left out the critical conjunction. The Public Utilities Commission voted in March to interpret the language literally, meaning program funding would be capped at $22 million rather than the $59 million envisioned by the Legislature.
LePage, who opposes the ratepayer surcharge, vetoed the corrective measure. State law requires a two-thirds majority in both houses of the Legislature to override a veto.
Residents Concede in Pepco Tree Management Dispute
A group of Potomac homeowners who banded together to try to keep Pepco from cutting down trees on private property near its power lines has conceded defeat. Armed off-duty Montgomery County police officers began standing guard last week to keep protesters from interfering with Pepco contractors cutting down trees on residents’ property.
Pepco stepped up its vegetation management program after the Public Service Commission in 2011 fined the utility for poor performance. A PSC working group developed standards dictating how close a tree’s branches can grow to different types of power lines and said that no jurisdiction in the state could override the standards.
The utility says it’s within its rights to bring its bucket trucks and chainsaws onto people’s property because of a series of easements it purchased in the 1950s, before modern neighborhoods were built in the area. Pepco says it has decreased the number of outages per customer an average of 8.6% and that their duration has been shortened by nearly 24%.
PSC Member Accused of Conflict of Interest in Merger Vote
Speakes-Backman
Opponents of Exelon’s $6.8 billion acquisition of Pepco Holdings Inc. have appealed the Public Service Commission’s approval of the deal, saying a commissioner who cast the deciding vote had a conflict of interest.
Commissioner Kelly Speakes-Backman was in talks to take an executive position with the industry group Alliance to Save Energy when the PSC voted on the merger on May 15. (See How Exelon Won Over Maryland.) Exelon is on the board of directors for the group, which lobbies Congress on energy efficiency issues.
“Speakes-Backman’s failure to recuse herself from voting on the Exelon-Pepco merger while negotiating employment with an organization tied to and financed by Exelon Corp. constitutes a clear conflict of interest,” said Tyson Slocum of advocacy group Public Citizen. Speakes-Backman, who became a senior vice president with the trade group after the vote, denied there was a conflict, saying she ceased communication with the group when she learned of Exelon’s place on the board until after the commission’s decision.
The Maryland Office of People’s Counsel has appealed the commission’s decision in circuit court. The D.C. Public Service Commission is the only remaining regulatory body still to vote on the deal, which has attracted vociferous opposition in the district.
Death of Vet After Utility Shutoff Prompts Discussion on Rules
The death of a veteran from hypothermia last winter has prompted a call to discuss how utilities handle shutoff notices.
John Skelley, 69, was found dead in a Detroit home in February after Consumers Energy shut off natural gas service. Utilities are forbidden from shutting off utilities in the homes of seniors from November to March, but Consumers Energy said it was unaware anybody was living in the house. The service was listed under a different name, and the company said it sent numerous shutoff notices to the service holder with no response.
The Public Service Commission is calling for a full report from Consumers Energy and is asking all utilities in Michigan to form a “collaborative work group” to review current rules and see if any changes need to be made.
The Public Utilities Commission approved a settlement between Xcel Energy and several community solar garden developers that will allow more of the small-scale solar projects to be built.
Xcel had pushed for a limit to the size of community-owned solar facilities, which they saw as cutting into their business without paying to support grid development and maintenance. Some community solar facilities as large as 50 MW were proposed, “well beyond what was intended,” Xcel Regional Vice President Laura McCarten said.
The agreement limits the size of a community solar facility to 5 MW. The agreement is retroactive, and all facilities will go back for a design review to ensure they don’t exceed that size.
Clean Line Taps Kansas City Contractor for Tx Project While Awaiting Regulatory OK
Clean Line Energy announced it will hire PAR Electric Contractors of Kansas City to help build its Grain Belt Express transmission line, buttressing arguments that construction could put 1,300 people to work in the state. The announcement came as the Public Service Commission delayed a vote on the project for a deeper evaluation.
The planned 750-mile HVDC line would carry wind power from Kansas into Missouri and further east.
Indiana and Kansas regulators have already approved the project.
The Public Service Commission has approved a $17.1 million rate increase for the Empire District Electric Co., 29% less than the company sought when it filed last August. The ruling will add about $7 to the average residential customer’s electric bill.
Empire sought the increase mainly to cover the costs of installing emission controls at its Asbury Power Plant. Empire also said it needed to pay for a new maintenance contract for its 12-unit Riverton gas-fired plant and faces higher RTO charges.
Empire serves 149,300 electric customers in 16 Missouri counties.
State regulators approved a temporary increase of 0.07 cents/kWh for customers of Eversource Energy to pay for reliability projects. The commission first approved the reliability enhancement program in 2006 to reduce the frequency and duration of power outages. The current funding was set to expire at the end of June.
On June 10, Eversource asked the Public Utilities Commission to approve the temporary rate increase to recoup money spent on reliability projects since 2013. According to the company, since the start of the reliability program, there has been a steady decline in the duration and frequency of outages affecting customers.
Fishermen’s Energy Takes Case to State Supreme Court
Fishermen’s Energy, a consortium of commercial fishermen developing wind farms off the state’s coast, is appealing the Board of Public Utilities’ denial of a proposed 25-MW pilot project off Atlantic City.
The company asked the state Supreme Court to direct the BPU to approve the project, which received a $46.7 million grant from the Obama administration. The BPU rejected the project because it said it was too costly, even with federal subsidies.
Half of State’s Power to Come from Renewable Sources by 2030
The New York State Energy Research and Development Authority has approved a new state energy plan that aims to reduce carbon emissions by 40% from 1990 levels in the next 15 years and calls for the state to get half of its power from renewable sources by 2030.
The long-awaited plan, released Thursday, aligns with the Cuomo administration’s Reforming Energy Vision initiative to remake the energy grid and provide more renewables and energy efficiency.
“The eyes of the country really are on New York, and where we are going and how we are going to get there,” NYSERDA Director John Williams said.
National Grid will submit its plans for a smart grid demonstration project for the Clifton Park area on July 1.
The project will be based on one currently operating around Worcester, Mass., where customers can choose different pricing models for their electrical usage and can access advanced smart grid technologies to help them control their usage.
National Grid also introduced a new team that will lead the company’s various smart grid demonstration projects. The team will be led by Ed White, vice president of new energy solutions.
Lower Fuel Prices Lead to Savings for Duke Energy Progress Customers
Duke Energy Progress has proposed a rate reduction that would cut the monthly energy bill for a typical residential customer by 2.5%.
The new rate, if approved by the Utilities Commission, would reduce the average residential monthly bill from $111.38 to $108.69. The decrease is a result of the falling prices of coal and natural gas as well as in the cost to ship coal to the state by train and barge.
PSC Approves 2 Pipelines to Run Beneath Lake Sakakawea
The Public Service Commission has approved two pipelines to run beneath Lake Sakakawea — one carrying crude oil, the other natural gas. Both projects were proposed by Hess North Dakota Pipelines.
The first is a 25-mile oil pipeline to run from a Hess facility near Keene in McKenzie County to the Ramberg Truck Facility near Tioga. It would carry about 76,000 barrels of oil per day. The second, called the Hawkeye NGL Pipeline, would run along a similar route for about 19.2 miles, using an existing oil pipeline that would be converted to carry natural gas liquids. It would carry about 30,000 barrels of NGLs a day.
Hess is one of the largest oil producers in North Dakota.
PUC to Hold Public Hearing Before Crucial Keystone Decision
The Public Utilities Commission will hold a final public hearing on July 6 at the state Capitol to get input on the Keystone XL Pipeline. Although the project received initial approval back in 2010, the PUC must rule on whether or not conditions have changed substantially before construction can be approved.
WILMINGTON, Del. — PJM officials Thursday delayed a vote on manual changes for the Capacity Performance plan, sidestepping a potential confrontation with anxious stakeholders.
The agenda for Thursday’s Markets and Reliability Committee said PJM would seek endorsement of the Manual 18 changes, which run for more than 200 pages. But PJM officials delayed the vote — apparently chastened by a stormy stakeholder meeting the week before, which left some stakeholders complaining that the RTO had not thought through all the details before the Federal Energy Regulatory Commission approved the proposal June 9.
Stu Bresler, vice president of market operations, said PJM’s “current thinking” is to seek endorsement at the July 23 MRC meeting. There will be an additional meeting on the changes from 1 to 4 p.m. on July 15, following a training session from 1-4 p.m. on July 8.
“Technically speaking, we can put manual changes in place without a stakeholder vote,” Bresler said. But he said the RTO had traditionally sought stakeholder endorsement of the manuals, which spell out Tariff and Operating Agreement rules and procedures in detail.
In the meantime, PJM must make a compliance filing by July 9, said Dave Anders, director of stakeholder affairs and market services.
Rules Still Being Developed
Officials said they delayed the vote in part because they saw the need for additional changes beyond what they outlined during a testy, six-hour meeting June 18. (See PJM Stakeholders Rush to Figure out What’s Changing for the BRA.) “We will have some additional tweaks,” said Bresler.
PJM also agreed with Exelon’s proposal that a seller’s requested risk premium level can be “reasonably supported” rather than “documented and quantifiable” as it originally proposed.
“We do intend to add a little more language consistent with something Exelon offered [regarding] what we consider to be acceptable as far as risk,” said PJM attorney Jen Tribulski.
Ed Tatum of Old Dominion Electric Cooperative said after the June 18 session that RTO officials “seem to be making [the rules] up as they go along.” It was an observation that several other stakeholders told RTO Insider they agreed with — while conceding some uncertainty was unsurprising given the breadth of the changes.
Tatum on Thursday expressed gratitude for the additional time. “Our interest is that we have as few surprises as we possibly can,” he said.
American Electric Power’s Brock Ondayko also expressed frustration during Thursday’s meeting. “In response to many questions, PJM says, ‘We’ll have to go back to look at that.’”
Officials said they hoped the additional month would give them time to resolve all outstanding questions about the rules that will apply for the Base Residual Auction beginning Aug. 10.
Aggregation Rules
Bruce Campbell, of demand response provider EnergyConnect, said a discussion at a training session Wednesday on how resource providers can aggregate resources “left a lot of people confused, if not unhappy, with what PJM is proposing.”
“The language seems to say you can offer aggregation, but performance will be assessed based on individual resources,” Campbell said. “It seems inconsistent.”
“It seems to me we should be going back to some sort of stakeholder process to consider” alternative rules on issues such as aggregation, said consultant Tom Rutigliano of Achieving Equilibrium.
Fixed Resource Requirements
Marji Philips of Direct Energy questioned whether PJM had included a transition for fixed revenue requirement entities, asking whether the RTO was “concerned that FRR won’t be prepared.”
“It’s really not appropriate to debate the FERC order,” responded CEO-in-waiting Andy Ott. “… The scope of this meeting is compliance.”
Ott said he disagreed that FRRs won’t be prepared, saying their plans were already submitted for the transition years of 2018/19 and 2019/20.
Philips persisted: “We have the competitive market that’s meeting the reliability standard and the regulated part of PJM that’s not.”
FERC Order
The new rules, a response to the poor generator performance during the January 2014 polar vortex, increases reliability expectations of capacity resources with a new Capacity Performance product. It is intended to result in larger capacity payments for the most reliable resources and higher penalties for non-performers.
Although FERC rejected some of PJM’s related proposals for changes to the energy market, it otherwise approved the RTO’s changes with only limited modifications. (See FERC OKs PJM Capacity Performance: What You Need to Know.)
The Federal Energy Regulatory Commission denied the Louisiana Public Service Commission’s request to reconsider Entergy’s allocation of transmission upgrade costs at its Ouachita Power Facility in northeast Louisiana, saying regulators should make their case in proceedings addressing changes to the company’s system agreement.
The Louisiana regulators had requested rehearing of a 2012 order in the matter (EL11-63-001).
At issue is the allocation of $70 million in transmission upgrades necessary to qualify the Ouachita plant as a network resource for Entergy’s operating companies.
Entergy Arkansas purchased the three-unit, 789-MW natural-gas fired facility from Cogentrix Energy in 2008, selling one unit to Entergy Gulf States Louisiana in 2009.
The LPSC contended Entergy Louisiana should not be liable for costs that allowed Entergy Arkansas to receive energy from the Ouachita plant, as the Arkansas utility had received approval to withdraw from Entergy’s system agreement effective in 2013.
In its January 2012 order, FERC said the LPSC’s arguments were premature because the Arkansas utility had not yet left the system agreement. Entergy Arkansas formerly withdrew from the system agreement Dec. 19, 2013, when it was integrated into MISO’s footprint.
In denying the LPSC’s request for a rehearing, FERC said the LPSC failed to support its contention that the pre-withdrawal allocation of the plant’s transmission upgrade costs could not be justified. “As Entergy has explained, until Entergy Arkansas’ departure from the system agreement, the Ouachita plant provided benefits to all operating companies.”
FERC said “the fact that planning of the Ouachita plant acquisition occurred after Entergy Arkansas provided notice of intent to withdraw from the system agreement does not provide a basis for treating it differently from other system resources for the purpose of allocating associated transmission costs.”
The LPSC contended the 2012 order violated section 306 of the Federal Power Act, which requires a public utility to answer a complaint filed by a state regulatory commission. FERC countered by saying complainants “bear the burden to prove their allegations under both sections 206 and 306 of the FPA, irrespective of the FPA section 306 requirement.”
FERC’s denial said the LPSC had “misread” section 306 and said the section “provides a public utility that is the respondent to a complaint with two options: it may either (1) ‘satisfy’ the complaint or (2) answer the complaint in writing.” FERC said the LPSC’s misreading “has the effect of improperly shifting the burden of proof to a respondent” and that Entergy had fulfilled its obligations under section 306.
FERC said it saw no reason its findings conflicted with cost-causation principles and said “the appropriate forum for the Louisiana commission to raise issues regarding cost causation with respect to the post-withdrawal period was in the proceedings addressing changes to the system agreement following Entergy Arkansas’ withdrawal.”
