New York regulators last week delayed action on a financial lifeline for the R.E. Ginna nuclear plant in order to review its impact on ratepayers.
The approximately $200 million annual price tag for the reliability support services agreement prompted the New York Public Service Commission to open an inquiry, with initial filings due April 15 (14-E-0270).
The PSC’s March 18 order defers action on Rochester Gas & Electric’s request for approval of the agreement through July 29.
The RSSA, which is also pending before the Federal Energy Regulatory Commission, was supposed to be effective April 1. If approved, the agreement would be retroactive to April 1 and last until the end of September 2018.
RG&E and Exelon’s Constellation Energy Nuclear Group were ordered by the PSC to enter the agreement because the plant is deemed necessary to maintain system reliability in western New York until a transmission project goes online in late 2018.
RG&E has estimated that under the agreement, an average residential customer would see bills rise about 4.2%, while costs for large primary customers would increase 6%.
Interveners representing competitive suppliers, residential ratepayers and environmentalists have complained about the RSSA’s steep price, with industry and other large customers challenging RG&E’s estimates before FERC. (See New York Industrials Want Ginna Deal Tossed.)
“RG&E worked diligently in the best interests of our customers to reach an agreement with Ginna, recognizing the importance of ensuring reliable service on reasonable terms for all parties,” said Dan Hucko, a spokesman for RG&E.
“Given the important role of the proposed reliability support services agreement, we are working collaboratively with the PSC to accommodate the needed regulatory reviews in a timely fashion,” Exelon spokeswoman Maria Hudson said.
Connecticut’s Department of Energy and Environmental Protection issued its integrated resource plan last week, warning of natural gas pipeline constraints and stiffer competition for renewable resources.
Although energy efficiency is expected to flatten load growth, the blueprint for the 10-year period through 2024 predicts the New England region will need new resources to offset the retirement of more than 3,000 MW of generation.
Three new Connecticut generators cleared in ISO-NE’s Forward Capacity Auction for 2018-2019 in February: a 725-MW combined-cycle plant in Oxford and two 45-MW combustion turbines in Wallingford. (See Exelon, LS Power Join CPV in Adding New England Capacity.)
The outcome of the capacity auction, which ISO-NE officials hailed as a success for their new Pay-for-Performance rules, had been uncertain when Connecticut issued a draft of the IRP in December. (See Connecticut: Power Prices to Rise 63% by 2024.)
The IRP advocates a regional approach to expand natural gas infrastructure. DEEP says that at least 1 Bcf/d of natural gas transportation capacity or equivalent gas storage is needed for at least 30 days during the winter.
The final IRP also noted a tightening in the availability of renewable power, saying that as neighboring states try to reach their renewable energy goals, competition for the limited supply could cause a shortage by 2017.
Connecticut, Massachusetts and Rhode Island are joining together to procure new Class I Renewable Energy projects: wind, solar, small hydro, biomass and fuel cells of at least 20 MW and large-scale hydropower projects constructed after Jan. 1, 2003. (See New England States Combine on Clean Energy Procurement.)
The Federal Energy Regulatory Commission last week left intact most of its 2010 order meant to mitigate market power in the installed capacity market in New York City.
However, it clarified the previous order’s consideration of demand response programs that may benefit from state policies or subsidies.
The order accepted NYISO’s compliance filing with the exception of its proposal to grant a blanket exemption from offer floor calculations for all payments and other benefits to special case resources (SCR) under state programs. An SCR is a demand-side resource that participates as a supplier in NYISO’s capacity market.
“We clarify that our May 20, 2010, order did not intend for NYISO to rule on the legitimacy of particular state programs. However, neither did we intend to grant a blanket exemption for all state programs that subsidize demand response,” FERC wrote.
The order removes a requirement in the 2010 ruling that NYISO provide a list of criteria governing which payments are included in offer floor calculations. Instead, the commission will decide petitions for exemptions on a case-by-case basis.
The order granted rehearing on whether payments under Consolidated Edison’s distribution load relief program and the New York State Energy Research and Development Authority rebate program should be excluded from the SCR offer floor.
That shift resulted in a partial dissent from Commissioner Norman Bay.
“The commission announced five years ago that it did not intend ‘to interfere with state programs that further specific legitimate policy goals.’ Yet that is precisely what the majority does today by declaring the ConEd and NYSERDA programs to be presumptively improper exercises of market power,” Bay wrote.
The order denied rehearing on a challenge to the demand curve price used for calculating the default offer floor.
The Federal Energy Regulatory Commission last week rejected SPP’s proposal that the RTO review the information that transmission owners include in their initial revenue requirement filings after joining the RTO (ER15-859).
SPP filed the proposal with FERC in January as a result of a 2014 settlement reached with Southwestern Public Service Co. in a dispute over whether the transmission facilities of Tri-County Electric Cooperative were eligible to be included in SPP transmission rates (EL13-15, EL13-35).
SPP said the review process, which was unanimously approved by the SPP Members Committee, was intended to identify issues that might result in challenges to the initial rate filings. The RTO said it would have no authority to prevent a transmission owner from overriding SPP’s concerns in its filing with FERC.
The Missouri Joint Municipal Electric Utility Commission, the Kansas Power Pool and South Central MCN, a competitive transmission company that plans to partner with electric cooperatives and municipal utilities in SPP, filed protests in February.
The commission said the proposed review process, which could take as long as six months after a new transmission owner’s execution of the SPP membership agreement, was unreasonable.
“We agree with protesters that SPP’s proposed six-month review process could unjustly and unreasonably impair a new transmission owner’s ability to recover its costs,” the commission said.
The commission said it recognized that SPP was attempting to create a consensus solution based on the 2014 settlement. “However, we find that the review process SPP proposes to mandate here could unjustly and unreasonably impair a new transmission owner’s ability to recover its costs for transmission service it provides under the SPP Tariff.”
Faulted by some stakeholders for not approving cross-border transmission projects under terms of their joint operating agreement, MISO and PJM have identified what lower-voltage flowgate projects could be done quickly and cheaply on their own sides of the seam.
The RTOs have jointly identified more than two dozen flowgate projects that could relieve market-to-market congestion.
The list of upgrades includes at least 14 projects totaling more than $45 million on the PJM side and 12 totaling $59.5 million on the MISO side.
Eric Laverty, MISO’s director of sub-regional planning, told his RTO’s Planning Advisory Committee on March 18 that the projects were not identified as the result of complicated modeling but through simple analysis of congestion history during 2013 and 2014.
Flowgates that showed significant day-ahead and balancing congestion in 2013 and 2014, and M2M flowgates that caused auction revenue rights infeasibilities, were included. Solutions had to be completed and provide a payback on investment quickly. Greenfield projects were not considered.
“We didn’t run these through a full set of futures for market efficiency-type analysis,” Laverty said, sharing information from a recent PJM/MISO Interregional Planning Stakeholder Advisory Committee.
“Here’s the cost. Here’s what the congestion has been over the past couple years. Does this [upgrade] make sense?”
PJM engineers have been using production cost simulations to study issues on their side of the seam. Both RTOs modeled special transfer conditions, such as those resulting from high wind production and increased Michigan imports.
Smaller ‘Quick Hits’
(Click to zoom.)
Laverty said the upgrades didn’t amount to high-dollar projects, with the largest potential MISO project an $11.9 million upgrade at the Burnham-Sheffield 345-kV flowgate.
Also, “they’re not rising to a reliability project yet,” he said, but could grow more costly over time.
George Dawe, vice president of Duke-American Transmission Co., asked if the upgrades would be eligible for competitive solicitations if they were delayed and became reliability projects. Laverty said no. Later, referring to a potential southwest Michigan project, he added, “We don’t know yet.”
For now, PJM and MISO need “to get a pulse” of transmission owners to see if they have an appetite for making improvements. “It’s a matter of building the business case for these projects,” Laverty said.
These “quick hit” projects will be the subject of additional review at the April IPSAC meeting, with conclusions and recommendations likely in May.
The extent to which the projects improve conditions for utilities on the seams is yet to be seen.
Last December, Northern Indiana Public Service Co., a MISO member flanked by PJM in eastern Indiana and Illinois to the west, complained to the Federal Energy Regulatory Commission that the RTOs haven’t approved a single cross-border transmission upgrade project under the JOA (EL13-88). FERC ordered a technical conference on the issue.
Market Congestion Projects
MISO’s Planning Advisory Committee also received an update Wednesday on potential “high-benefits-to-cost” solutions involving 14 congested flowgates in four areas: southern Indiana, southern Illinois, northern Indiana/southeast Wisconsin and Iowa/Minnesota.
Seventeen transmission developers submitted 45 solutions, including 10 carried over from the 2014 market congestion planning study. Twelve of the 45 proposals passed the benefit-cost threshold.
The projects identified in southern Illinois and southern Indiana show particular promise as “those two areas have been hammered by congestion,” said Digaunto Chatterjee, senior manager of economic studies.
Chatterjee said MISO has been studying some areas of the grid “over and over and over” enough to know they stand out as particularly problematic.
“These are real problems with real market participants that have real pain,” he said.
The Independent Power Producers of New York failed to persuade federal regulators that out-of-market payments that keep financially strapped generation operating to maintain system reliability suppress capacity prices.
IPPNY had claimed that NYISO’s Market Administration and Control Area Services Tariff — which allows de minimis offers from capacity resources that would have left the market without reliability-must-run agreements or repowering agreements — disadvantaged other generators.
“We find that IPPNY has failed to show that NYISO’s tariff is unjust and unreasonable,” the Federal Energy Regulatory Commission wrote last week in denying the complaint over the Cayuga and Dunkirk generating stations (EL13-62). (See related story, FERC: Hearing or Settlement on Dunkirk RSSA Charges.)
Owners of Cayuga and Dunkirk had notified state officials that the plants would be mothballed because they were not economic to operate. Both negotiated reliability support services agreements (RSSA) with transmission owners that were approved by the New York Public Service Commission.
IPPNY sought to have those resources excluded from the capacity market or required to offer at levels no lower than the resources’ going-forward costs.
FERC said competitive capacity offers should reflect going-forward costs minus other sources of revenue. “If going-forward costs adjusted for revenues are very low, then it would be reasonable to expect a low capacity market offer that reflects the low going-forward costs,” the commission said. “We agree with the New York commission that, when RSSA revenues are taken into consideration, the Cayuga and Dunkirk units’ going-forward costs would likely be low.”
Although FERC rejected IPPNY’s complaint, it ordered NYISO to establish a stakeholder process to consider whether there are circumstances that warrant the adoption of buyer-side mitigation rules in the rest-of-state zone, and whether mitigation measures would need to be in place to address any price suppressing effects of repowering agreements.
“While we find that IPPNY has not satisfied its burden under section 206, we recognize that IPPNY’s [complaint] raises concerns regarding whether changed circumstances in the rest-of-state may necessitate the prospective adoption of market power mitigation rules for the rest-of-state,” FERC wrote.
Chairman Cheryl LaFleur further addressed that aspect in news conference after Thursday’s commission meeting. “The commission has drawn a distinction in its orders between new resources and existing resources. Where repowering falls is somewhere in the middle, which is one of the reasons we asked questions about that,” she said.
The Public Service Commission has approved an increase in the subsidy that Delmarva Power customers pay to fuel cell manufacturer Bloom Energy. The surcharge, adjusted periodically, will cost a typical customer about $4.34 a month.
Bloom Energy enjoys a 21-year deal under a 2011 law that guarantees revenue for power generated from its 30-MW fuel cell operation. In exchange, Bloom has to guarantee jobs and an ongoing operation in Delaware. Bloom currently receives about 16.687 cents/kWh, more than Delmarva’s 10.75-cent/kWh advertised rate.
Commonwealth Edison supporters have introduced another clean-energy bill into the mix as state lawmakers spar over conflicting visions of renewable power legislation.
ComEd’s bill, introduced by Sen. Kimberly Lightford (D-Maywood) and Rep. Bob Rita (D-Blue Island) aims to foster growth in clean energy for households, such as solar power, and for microgrids to provide greater reliability and resiliency.
The utility also proposes a $100 million program to build 5,000 Chicago-area electric vehicle charging stations.
Some suspect the bill is intended to build support for other legislation backed by ComEd parent Exelon, which would create a ratepayer surcharge to subsidize carbon-free nuclear power. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.) Environmentalists and green energy advocates are supporting a third bill they say would create tens of thousands of new jobs by boosting state goals for renewable power and energy efficiency.
Senate Likely To Allow IUB Selection to Stand Without Investigation
Huser
Senate Democrats say they won’t challenge the appointment of Geri Huser to chair the Utilities Board.
Gov. Terry Brandstad picked Huser, identified as a business-friendly former state representative, to succeed Republican Libby Jacobs as board chairwoman. Jacobs will remain on the three-person board. Sheila Tipton, a Democrat with a legal background in utilities regulation, was not reappointed.
Huser’s appointment came a month after the board ordered MidAmerican Energy to refund $2 million to customers. A MidAmerican Energy executive confirmed that the company recently met with the governor and criticized the refund decision. (See MidAmerican’s Fingerprints on Shakeup of Iowa Utilities Board?)
Renewables’ Tax Exemption to be Limited to 10 Years
A bill before the Senate Assessment and Taxation Committee would put a 10-year limit on property tax exemptions for renewable power projects.
The incentive has been in place since 1999, but the proposal would modify the tax breaks so that they would expire 10 years after the launch date of each project. The Kansas Division of the Budget estimates that existing renewable power projects would pay about $18 million annually in taxes in 2025, which could be used for school funding.
The proposal to end the unlimited tax break amounts to “bait and switch,” said Jeff Riles, manager of regulatory of affairs for Enel Green Power North America. Supporters say the incentive attracted many wind, solar and other renewable energy projects to Kansas.
Missing “And” Cuts Efficiency Investments by $36 Million
The Public Utilities Commission has reduced the amount utilities are required to pay into a fund that subsidizes energy efficiency programs by about $36 million — and it’s all because of a missing “and” in the statute.
The early version of the bill that created the Efficiency Maine Trust stated that funding would be determined by “total retail electricity and transmission and distribution sales.” The adopted legislation stated funding would be based on “total retail electricity transmission and distribution sales.”
The result is that electricity supply sales are not included, decreasing funding from $59 million to $23 million. Two of the three PUC members say the program should be funded exactly as the legislation stated. Energy efficiency advocates are contemplating a legal challenge to restore the $36 million “and.”
A Manitoba man who bought 50 acres outside the small town of Richer, Manitoba, is upset that Manitoba Hydro is planning to erect 200-foot transmission towers on his property, part of its proposed Manitoba-Minnesota transmission line.
“It never would have dawned on me that Manitoba Hydro could just come and say, ‘Hey, we’re cutting your property in half and taking some of it and there’s absolutely nothing you can do about it,’” Conrad Thiessen said. A company spokesman said he understood Thiessen’s frustration but that “if it’s moved from his property, it may impact four others down the road, and is that any fairer?”
Thiessen said he has contacted his elected officials but so far hasn’t had any luck.
Opposition Growing for Proposed 45-Tower Wind Power Project
Opposition is mounting to the proposed Mills Branch Wind Project, which would place 500-foot-tall wind turbines near the Eastern Shore town of Kennedyville.
Opponents to the project, which developer Apex Clean Energy of Charlottesville, Va., said would include 35 to 45 turbines, gathered for an organizational meeting last weekend. They have also launched a website, Keep Kent Scenic.
“With a forest of wind turbines visible up to 25 miles away, Kent County tourism will no longer enjoy its scenic resource, and historic properties and homeowners can expect a big hit on property values,” the organization stated.
Regulators Defer Decision on Xcel’s Request on Solar Gardens
The Public Utilities Commission has denied a request from Xcel Energy to limit the size of community “solar gardens.”
Xcel, which is required under the state’s net-metering law to buy electricity produced by the small solar cooperatives at a set price, argued that solar gardens more closely resemble utility-scale operations, whose output would be put out for a bid at a lower price competitive with wholesale markets.
The commission said it has decided “at this time” not to limit the size of solar gardens. “Potential adjustments, if any, to the program will be fully evaluated” in a few months, said a PUC official.
City, Coalition Want to Revisit 40-year Prairie State Contract
Columbia officials and a pro-competition advocacy group want to review the municipal utility’s 40-year power purchase contract with Prairie State Energy Campus in Illinois.
Columbia Water and Light procures about a quarter of its power from the coal-fired Prairie State complex under a 2006 contract. But concerns about energy costs and climate change have caused some advocates to rethink the wisdom of the long-term commitment.
“In addition to locking us into burning fossil fuels for the next 40 years, thereby undermining our ability to transition to clean energy, this contract gives us no ability to negotiate the price of the energy we purchase,” City Councilman Ian Thomas said.
JCP&L Announces Refund Finally – but Storm Costs Eat it Up
The Board of Public Utilities approved a refund from Jersey Central Power & Light for overbilling its customers, but it offset the reduction by allowing the company to recoup expenses from repairing damage from major storms. The decision has taken two years to settle.
The BPU ordered the utility owned by FirstEnergy to refund $115 million for overbilling the costs of transmission system maintenance. But it cut the proposed rebate to about $35 million to allow the utility to recover costs from storms in 2011 and 2012, including Hurricane Sandy.
“I was happy the board upheld their rate decrease, but I was hoping for more,” said Stefanie Brand, director of the Division of Rate Counsel. Monthly bills for residential customers will decrease by about $1.68 a month.
Henkels & McCoy Agrees to Pay $600,000 in Ewing Gas Explosion
Giant utility contractor Henkels & McCoy will pay a $600,000 penalty to the Board of Public Utilities to settle claims about its role in a fatal gas explosion in Ewing last year.
The company was repairing a power outage for utility Public Service Electric & Gas when its workers drilled through a mismarked PSE&G natural gas main. The crew did not notify emergency responders about the incident, and hours later an explosion killed the resident of a nearby house where the stray gas had migrated underground.
PSE&G has already agreed to pay $1 million in fines.
Coal Ash I: Groups Urge Supreme Court to Uphold Duke Ash Cleanup Ruling
North Carolina environmental groups last week urged the state Supreme Court to uphold a 2014 lower court ruling that they say requires Duke Energy to immediately halt groundwater pollution from its coal ash pits.
Duke, which is appealing the ruling, says the lower court decision became moot after the legislature created a statewide Coal Ash Management Commission that will prioritize the cleanup of four of Duke’s ash pits. But environmental groups say the decision covered all of Duke’s 14 identified pits and required an immediate total cleanup.
The coal ash issue has been front and center in North Carolina. Duke agreed to pay a $100 million fine related to a massive ash leak last year into the Dan River and a $25 million fine for groundwater contamination from its Dutton plant near Wilmington.
Coal Ash II: Judges Back McCrory in Coal Ash Commission Make-up
McCrory
A three-judge Superior Court panel ruled that the General Assembly erred when it created a commission charged with overseeing the cleanup of Duke Energy’s coal ash pits, ruling that the appointment of the commission’s membership was an executive function, not a legislative role.
The judges said lawmakers ignored the mandate for separation of legislative and executive powers when they formed the commission and appointed six of its nine members. House Speaker Tim Moore and Senate leader Phi Berger said they would appeal the ruling.
If it is upheld, the ruling could mean that Gov. Pat McCrory, a former Duke Energy executive, would choose most or all of the commission’s members.
Company that Spilled 2.2 Million Gallons of Brine Proposes New 14-Mile Oil Pipeline
Summit Midsteam, whose wastewater pipeline leaked 2.2 million gallons of oil-drilling brine in January, is seeking permits to build a new pipeline, this one for oil.
Summit subsidiaries Meadowlark Midstream and Epping Transmission asked the Public Service Commission to approve a plan to convert an existing 10-mile “gathering” pipeline to a transmission pipeline. The company said the oil pipeline is made of stronger materials than the water pipeline and would have increased safety systems, including pressure and flow sensors monitored in a control center. The water pipeline was supposed to be monitored by regular patrols, but that system failed to detect the brine leak for several days.
“I think right-of-way patrolling is something we’ve learned to do probably better,” Meadowlark spokesman John Millar said. “We’re still trying to figure out why with the patrols we did have in place we didn’t see this spill. We think that’s going to be a more prominent part of our surveillance.”
Lawmakers Join to Preserve State Parks from Fracking
Democratic and Republican lawmakers collaborated to prohibit oil and gas development in state parks in draft legislation designed to speed up state permitting for hydraulic fracturing operations.
As a result of last-minute discussions, state parks will be protected, but fracking will be allowed in state wildlife areas and in state forests, although surface disturbances will be prohibited. Nature preserves will continue to be protected.
The General Assembly approved fracking on state lands in 2011, but Gov. John Kasich imposed a moratorium by declining to name anybody to the governing authority, the Oil and Gas Commission. The new legislation will enable the commission to be activated again.
Historic Low Prices Don’t Slow Oil and Gas Drilling in State
The Utica Shale region in Ohio continues to be a hotbed of oil and gas production, despite the plunge in energy prices.
According to the federal Energy Information Administration, the Utica region, along with the Marcellus region to the east and north, will continue to show increased production of gas and oil in the coming months.
“The biggest thing that differentiates Utica from the other regions is Utica is relatively young,” said Jozef Lieskovsky, an analyst for the EIA. Younger wells typically produce at a higher rate than mature wells.
PUC Judges Recommend Lower Rate Hike for Met-Ed Customers
Administrative law judges have recommended a 10.9% rate increase for Met-Ed customers. The FirstEnergy subsidiary is seeking a 17.8% increase.
The recommendation was part of a larger rate proceeding dealing with FirstEnergy’s four Pennsylvania utilities. The judges recommended increases ranging from 7.4 to 13.1% for West Penn, Penelec and Penn Power.
The Public Utility Commission is set to consider the recommendations at a meeting in May.
DEQ Approves NRG’s Cleanup Plan for 17,000 Gallons of Oil at Plant
The state Department of Environmental Quality last week approved NRG’s plan to recover fuel oil and to clean up tons of contaminated soil at a former Pepco power plant in Alexandria on the Potomac River.
Officials estimated that 17,000 gallons of fuel oil leaked from the plant’s tanks. NRG said it plans to complete the cleanup over the next three years, and monitor soil and groundwater for two years after that.
The deputy director of Alexandria’s transportation and environmental services said the contaminated groundwater is not near any wells and poses no health threat.
A divided Federal Energy Regulatory Commission last week accepted ISO-NE’s second regional compliance filing to implement Order 1000, a filing that had languished for more than a year while the commission had only four members (ER13-193, ER13-196).
FERC largely affirmed its May 2013 order accepting ISO-NE’s regional planning and cost allocation process. It found proposed revisions, filed by ISO-NE and the Participating Transmission Owners Administrative Committee in November 2013, largely complied with the directives in its first order, requiring the parties to make additional filings on some provisions.
In a post-meeting news conference, Chairman Cheryl LaFleur was asked if the delay meant the commission had been deadlocked at 2-2 in the time it awaited replacements for former Chairman Jon Wellinghoff, who resigned in November 2013, and John Norris, who stepped down last August. Norman Bay replaced Wellinghoff in August but the commission remained short one member until Colette Honorable was sworn in Jan. 5.
“That’s a reasonable inference,” LaFleur responded. “It was 3-to-2 the first time and it was 3-to-2 this time so it took five people to vote it out,” she said.
Dissents over ROFR
The order affirms the commission’s prior findings that ISO-NE must remove right-of-first-refusal provisions and that the Mobile-Sierra doctrine does not preclude that requirement. The Mobile-Sierra doctrine presumes that freely negotiated wholesale energy contracts are just and reasonable unless they are found to seriously harm the public interest.
Commissioners Phillip Moeller and Tony Clark partially dissented from the order, saying the majority did not adequately address concerns regarding the Mobile-Sierra doctrine.
“On rehearing, the commission again declines to provide the actual quantitative or granular analysis of public interest harm that is required to overcome the Mobile-Sierra protection previously granted. The result in the instant case is thus legally suspect,” Clark wrote. “Moreover, the decision has the unfortunate side effect of calling into question the commission’s commitment to upholding the regulatory certainty provided under our Mobile-Sierra decisions.”
The majority wrote that “the commission must determine whether the instrument or provision at issue embodies either (1) individualized rates, terms or conditions that apply only to sophisticated parties who negotiated them freely at arm’s length; or (2) rates, terms or conditions that are generally applicable or that arose in circumstances that do not provide the assurance of justness and reasonableness associated with arm’s-length negotiations.”
In granting a partial rehearing, ISO-NE is permitted to restore certain provisions that recognize the transmission owners’ rights to retain use and control of their existing rights of way.
The commission found just and reasonable the proposal to allocate costs of public policy transmission upgrades 70% to the region based on load-ratio share and 30% to those states whose public policy necessitated the project. FERC gave ISO-NE 60 days to file additional modifications.
Additional Filings Required
The commission also required ISO-NE and the Participating Transmission Owners Administrative Committee to make additional compliance filings that:
Specify a process for transmission providers to enroll in the transmission planning region;
Describe the process through which participating transmission owners will identify transmission needs driven by federal public policy requirements that will be evaluated in the local transmission planning process and how they will be evaluated;
Revise the definition of a nonincumbent transmission developer in the ISO-NE Tariff to require that a participating transmission owner that proposes to develop a transmission facility not located within or connected to its existing electric system enter into a nonincumbent agreement;
Modify study deposit provisions to provide a description of the costs to which the deposit will be applied, how those costs will be calculated and an accounting of the actual costs; and
Revise the ISO-NE Tariff and Operating Agreement to provide a consistent definition of the term “backstop transmission solution” and remove language that would require a Participating Transmission Owner to continue developing a backstop transmission solution beyond what was originally proposed.
The Federal Energy Regulatory Commission last week accepted revised transmission formula rate protocols by four SPP and MISO utilities that had deficient protocols.
The commission also accepted a new protocol from Louisville Gas & Electric and Kentucky Utilities, a PJM member in Kentucky and Virginia.
While accepting the filings, FERC required further compliance filings within 60 days from Black Hills Power, which serves parts of South Dakota, Wyoming and Montana; Empire District Electric Co., with territory in Missouri, Kansas, Oklahoma and Arkansas; Kansas City Power & Light and KCP&L Greater Missouri Operations, with customers in Missouri and Kansas; and Westar Energy, which serves parts of Kansas.
The commission ordered the revisions for the SPP in July 2014, saying the existing protocols had impeded the ability to review and appeal transmission owners’ cost claims. The commission ordered similar revisions for MISO transmission owners in 2013. (See FERC OKs MISO, TO Rules on Formula Rate Challenges.)
The commission found that the provisions related to rate challenge procedures and transparency in all of the filings generally comply with directives in the July 2014 orders, but they required some additional modifications.
The Federal Energy Regulatory Commission last week rejected Dominion Virginia Power’s request to push back the effective date for a rate revision by more than year, a change that would have cost transmission customers $11.1 million (ER15-856).
Dominion had asked FERC to change the effective date of revised transmission depreciation rates from April 1, 2013, to Jan. 1, 2012. FERC approved the revised rates last April.
FERC said changing the date would violate its rule against retroactive ratemaking, a charge the North Carolina Electric Membership Corp. made in a February protest to the request. (See NCEMC: Dominion Request is ‘Retroactive Ratemaking’.)
“The filed rate and retroactive ratemaking doctrines both bar a public utility from charging a rate other than the rate properly filed with the commission, and similarly bar the retroactive imposition of an increased rate for service already provided,” FERC said. “However, this is precisely what Dominion proposes to do in the instant filing … by now proposing to charge customers an additional $11.1 million from Jan. 1, 2012, through March 31, 2013.”
Dominion said it requested the extension because of a Virginia State Corporation Commission ruling that increased its depreciation expense and accumulated depreciation effective Jan. 1, 2012 — the date of a depreciation study commissioned by Dominion. The SCC told FERC it supported Dominion’s request, saying it is standard practice to use the date of the study as the effective date for changes in depreciation rates.
FERC responded that “we are not suggesting that a Jan. 1, 2012, effective date would be inappropriate for retail rates, which is within the purview of the states. In this case, however, Dominion will receive all of its transmission operations and maintenance expenses through its formula rate, and its allowed rate of return and associated income taxes on all unrecovered plant balances. Furthermore, the commission has previously accepted rates that reflect regulatory differences from what this commission requires for accounting purposes and what state commissions require for state rate purposes.”
