The New York Public Service Commission last week extended the comment period on a proposed multibillion-dollar nuclear power subsidy by four days, until Friday (15-E-0302).
The comment period on a July 8 staff proposal, providing subsidies for the upstate nuclear fleet for up to 12 years, was to have ended on Monday. Environmental groups, industrial customers and anti-nuclear activists had sought a 45-day comment period.
“These extensions are granted for the fair, orderly and efficient conduct of these proceedings,” the PSC said Friday.
Political and labor leaders and economic development proponents in the Finger Lakes region have embraced the proposed zero-emission credit for financially stressed nuclear power plants. It is part of the proposed Clean Energy Standard, which seeks to transition the state to 50% renewable energy by 2030.
But the ZEC proposal has been opposed by some environmental organizations.
“Staff’s earlier cost estimates for the nuclear tier ranged from $59 million to $658 million over the first seven years. Now, under the new proposal, staff estimates the first two years will cost nearly $1 billion. Over the life of the program, it could amount to over $7 billion,” the Alliance for a Green Economy wrote in its petition seeking an extension last week.
Nine Mile Point Nuclear Plant
Exelon, which owns three nuclear plants on Lake Ontario, opposed any extension that would prevent the commission from voting on the proposal at its next scheduled meeting Aug. 1. It repeated its position last week that any delay jeopardized its attempt to schedule a $55 million refueling of its Nine Mile Point 1 reactor next spring. (See Exelon Threatens to Close Nine Mile Point 1.)
The company said it needs a signed contract guaranteeing the continued operation of Nine Mile Point by Sept. 30 to prevent the plant’s retirement.
The company also started a separate proceeding to obtain subsidies through a cost-based regulatory order in the event the CES did not get approved in time. That proceeding is pending.
Exelon also owns the R.E. Ginna plant, which also could close at the end of March when its reliability support services agreement with Rochester Gas & Electric expires, and is in negotiations to acquire Entergy’s James A. FitzPatrick plant. (See Entergy in Talks to Sell FitzPatrick to Exelon.)
The Corporation Commission approved Arizona Public Service’s demand-side management plan, which includes $4 million to incentivize the use of battery storage systems for residential customers.
The plan’s aim is to reduce peak load on the utility’s distribution system and includes programs to encourage the use of smart thermostats, demand response, LED lighting and technologies that improve the efficiency of air conditioners.
“Pairing advanced technology with customer education empowers our customers to have more control over their own energy use,” said Jim Wontor, the utility’s manager of demand-side management.
Gov. Jerry Brown’s administration last week moved to keep the state’s cap-and-trade program alive beyond its scheduled expiration in 2020. The Air Resources Board proposed a plan that would progressively decrease emissions caps until 2031 — to 40% below 1990 levels — and extend the carbon market to 2050.
Legislation to limit 2050 emissions to 80% below 1990 levels — and extend the market — stalled in the state’s lower house last year. While lawmakers have taken up a scaled-down version of the bill this year, passage is not ensured because of strong opposition. Brown is negotiating with oil companies who have criticized the cap-and-trade program.
CAISO solar output hit a new record of 8,030 MW at 1:06 p.m. on July 12, exceeding year-ago levels by 2,000 MW and nearly doubling the peak in May 2014. Renewable portfolio standard resources together covered 29% of load during the ISO’s system peak later that day.
The state currently has about 8,600 MW of solar resources connected to the grid.
The state has the highest average energy costs in the nation, according to financial website WalletHub. The report says the average household in the state spends $400/month on energy.
The state ranked No. 3 for electricity costs, No. 3 for home heating oil costs, No. 11 for natural gas costs and No. 14 for gasoline costs, equating to average monthly costs of $155, $104, $44 and $100, respectively.
The state’s New England neighbors also ranked in the top five.
The state’s Green Bank unveiled a new $800,000 grant program called Energy on the Line to assist manufacturers in using renewable energy and efficiency measures.
The program provides up to $50,000 in supplemental funding for projects. An $800,000 funding pool from the state Department of Economic and Community Development will be matched by more than $8 million in private-sector loan funds procured by the Green Bank.
Manufacturers interested in participating in the new grant program must apply by Sept. 16.
Gov. Paul LePage, speaking at a town hall in the Moosehead Lake region, said that area is not right for renewable energy development.
“Is there room for wind and solar?” the governor said. “Yes, in certain spots of the state. But I want to tell you Moosehead is not one of them.”
SunEdison is seeing opposition in the Greenville area to its proposed 26-turbine wind farm on Misery Ridge, near Moosehead Lake, but the project’s fate is uncertain since the company’s bankruptcy. Though the governor mentioned solar power, there are no such projects being proposed for the area.
Ranger Solar is conducting an environmental assessment for a solar farm of up to 80 MW that could break ground in 2018.
The project would be the largest utility-scale solar farm in the state. A solar farm requires about 5 acres/MW, according to the developer. An exact number of panels that would be needed for the project is not yet known, but upward of 90,000 to 100,000 panels are likely.
Once a project plan is completed, Ranger Solar will bring it formally before the Farmington Board of Selectmen and the state Department of Environmental Protection.
The state has hired two companies to analyze the financial impact of a hypothetical rupture of Enbridge’s underwater pipelines, collectively called Line 5, in the Straits of Mackinac and to explore potential alternatives to their route. Enbridge will pay $3.5 million for the studies but declined to oversee the work.
Det Norske Veritas will work on an analysis of the cleanup costs in the event of a rupture. Dynamic Risk Assessment Systems will look into alternatives for Line 5, which carries 23 million gallons of oil and LNG per day.
Gov. Rick Snyder has appointed a former BP lobbyist to head the state’s Department of Environmental Quality, sparking criticism from residents and environmentalists already galvanized over the Flint water crisis.
Heidi Grether, currently a deputy at the Agency for Energy, previously spent 21 years with BP in external communications, including managing the public response to the Deepwater Horizon oil spill. Former MDEQ chief Dan Wyant resigned in late December amid the Flint controversy.
“After the Flint water crisis clearly demonstrated there were cultural problems within the DEQ, this appointment is a concerning development,” said Lisa Wozniak, executive director of the Michigan League of Conservation Voters.
The Public Service Commission ruled that Clean Line Energy must wait another 60 days for its Grain Belt Express transmission line application to be considered for approval because the company did not provide adequate public notice when it made its filing.
The commission rejected the project a year ago in a 3-2 vote, but it said this latest delay was strictly procedural.
The state Site Evaluation Committee approved an application from Eversource Energy and National Grid for construction of the Merrimack Valley Reliability Project, the first major upgrade to the electrical transmission system in 20 years.
The new 18-mile overhead transmission line will be built on an existing interstate right of way.
The application for the project was submitted in July 2015. Its cost is estimated at $125 million, and the utilities are evaluating construction bids.
PRC Schedules Hearing on Facebook’s Planned Facility
The Public Regulation Commission unanimously agreed to hold an Aug. 9 hearing on Public Service Company of New Mexico’s request to provide renewable energy to a proposed data center for social media giant Facebook. If no comments are received by July 27, however, the commission may waive the hearing.
PNM submitted an application seeking expedited approval, without public comment or hearing, of a plan to provide 60 MW of solar or wind power. Facebook, which also is considering locating the site in Utah, wants the facility online by mid-2017 and has agreed to cover most of the costs of the power facility.
Facebook wants the center to run on 100% renewable energy, but it would still use traditional power plants as backup energy sources. As part of the deal, Facebook would require PNM to guarantee a fixed price on backup power for the first 10 years.
The Utilities Commission says two nonprofits must put up a $98 million bond to go forward with an appeal of a permit given for a new Duke Energy gas-fired power plant. The commission originally set the bond at $10 million, but an appellate court told it to recalculate the bond based on “competent evidence.”
The commission set the new amount based upon a 1965 state law and said it is designed to protect developers from costs associated with construction delays in the event they win a legal challenge. “The statute plainly places on the appealing party the financial risk of what potentially could be extensive additional costs,” the NCUC said in its order.
NC WARN and the Climate Times objected to the Buncombe County plant because it would use gas extracted using fracking. Duke had requested a $240 million bond, while the nonprofits said they were willing to put up $250. NC WARN’s director, Jim Warren, said it is not going to put up the bond. “We don’t have the money.”
The Public Service Commission unanimously approved the $250 million Brady Wind Energy Center II project, which will have 72 turbines and a capacity of 150 MW.
The project would double the potential capacity of Brady Wind, an indirect subsidiary of NextEra Energy Resources. The new facility will be located in Hettinger County, south of its sister project, approved last month, in Stark County.
Commissioner Brian Kalk said the approved siting permit includes strict turbine setbacks of 2,000 feet from homes in the project area and 2,640 feet from homes owned by those not participating in the project. He said the setbacks were negotiated based on county and PSC standards.
Two administrative law judges are recommending that the Public Utility Commission fine Blue Pilot Energy $5 million for charging its variable-rate customers high prices during the polar vortex of 2014.
The judges found that the Las Vegas-based company did not provide accurate pricing information, charged prices that did not match its disclosure statement and falsely promised savings.
They also said that Blue Pilot did not comply with the state’s Telemarketer Registration Act. The company countered that the PUC is authorized only to enforce its own regulations, not the telemarketer law.
The Commission on Environmental Quality renewed and expanded a wastewater permit for Dos Republicas Coal Partnership, allowing the company to expand its current operations near the Mexican border and mine up to 6,300 acres for low-quality coal.
The mine’s opponents say the project will pollute the air and the Rio Grande, which is the area’s only source of water. Several Native American tribes have also argued that the mine threatens sacred ancestral ground and that they were never given proper notification about the company’s plans.
Dos Republicas is owned by Mexican companies and by the Plano-based North American Coal Corp. and its subsidiary Camino Real Fuels. Because the coal is categorized as too low-grade for use in the U.S., it’s shipped to Coahuila for use in Mexican plants.
NRG, Denton Reach $3.7M Settlement over Rate Credits
The Denton City Council has approved a $3.7 million settlement reached between NRG Power Marketing and the city over money owed to ratepayers.
After the Texas Interconnection became deregulated in 2002, Denton Municipal Electric contracted with NRG to represent Denton at ERCOT until the city could begin buying and selling electricity directly in October 2014. Denton sued the company last year, alleging that NRG withheld credits from ratepayers.
The two parties were ordered into mediation, with Mayor Chris Watts personally assisting in the talks.
The Public Service Commission approved a $16.5 million refund to We Energies customers after the utility underestimated how falling fossil fuel prices would affect the cost of power. The refund will amount to about $5 for the average residential customer.
Four other state utilities — Wisconsin Power and Light, Madison Gas and Electric, Wisconsin Public Service and Northern States Power — will also issue refunds that range from $9.5 million to $16.5 million.
We Energies had asked the commission for a pass on issuing refunds, arguing that the money should be used to counteract future rate hikes, but consumer advocacy groups lobbied the PSC for immediate refunds.
RAPID CITY, S.D. — The SPP Markets and Operations Policy Committee last week refused to take action on American Electric Power and Oklahoma Gas & Electric’s revision request to remove the day-ahead limited must-offer.
The Market Working Group approved RR 125 last November but postponed moving it forward in December to allow further discussion on RR 135, which would revise physical withholding rules. It again failed to move the request forward in May on a tie vote (8-8, with one abstention).
“This is about the fourth or fifth bite at the apple others have tried with this issue,” Golden Spread Electric Cooperative’s Mike Wise said. “When we were designing the market, we debated this issue ad nauseam. I suggest we not change something that works right now.”
Wise said he agreed with the Market Monitoring Unit’s position of waiting to move forward with RR 125 until RR 135’s rules for physical holding have been completed. He suggested waiting for the enhanced combined cycle (ECC) project to go into effect next spring. The project — an effort to provide more sophisticated modeling that captures such plants’ flexibility — is being done in conjunction with changes to align the Integrated Marketplace’s day-ahead market with gas nominations.
“We should wait until the enhanced combined cycle [project’s completion] next spring, and then move forward,” he said. “It will remove the difficult decision and guessing about which mode of combined cycle operation the market needs, and remove some of those concerns dealing with the physical withholding in the market.”
“I haven’t heard enough about why it’s so important to remove the limited must-offer provision,” Midwest Energy’s Bill Dowling said. “I haven’t heard enough about the benefits [of] moving forward without knowing what the next steps are.”
RR 125 was a result of the Market Monitoring Unit’s recommendations to improve the Integrated Marketplace. It was designed to run in parallel with another revision request that would revise physical-withholding rules.
“We focus on the market power of units and the specific impact of units on the market,” MMU Director Alan McQueen said. “From a market monitoring perspective, physical withholding is the issue that’s a concern to us. I believe there’s value in coupling these things together and think about it in the way FERC’s going to look at it.”
The MOPC passed three revision request brought up individually, though each received a handful of opposing votes and abstentions.
RR 2, which predates SPP’s new revision request process, gives market participants the option of submitting interchange data in five-minute or hourly intervals. Participants were previously prohibited from submitting the data in five-minute intervals.
“As I understand it, the functionality won’t be used by the entire footprint for a long time,” said OG&E’s Greg McAuley, who cast one of four opposing votes against the measure. “Our MWG rep told me no single market participant intends to use this functionality. If we’re not going to consistently use it, why are we even talking about it?”
McAuley also questioned the estimated $50,000 cost of implementing RR 153, which would eliminate market participants’ need to make two separate submissions for a single intraday change.
Under current protocols, resource offers roll forward hour-to-hour, which can cause problems when intraday changes only meant to apply to the current day carry forward to subsequent days.
“It sounds like a software problem,” Kansas Power Pool’s Larry Holloway said. “If the software isn’t doing what it’s supposed to, isn’t there some sort of maintenance that occurs before [a revision request] comes to MOPC?”
“It’s a very fine nuance in the protocols,” said American Electric Power’s Richard Ross, who chairs the MWG. “I thought it was the software at first, too, but as we dug into it, there’s a very fine, quirky, strange reading of the protocols. We’re changing the protocols and the Tariff to make sure we get exactly what we want.”
Another request approved by the MOPC, RR 167, would avoid Tariff violations resulting from the incorrect submission of annual revenue rights or transmission congestion rights. It is expected to cost $134,000.
“What’s the saying? ‘Sooner or later, it becomes real money,’” McAuley said. “We’re nickel and diming ourselves to death.”
Ross said the MWG has passed or is working on nine improvements to the Integrated Marketplace at a combined cost of about $11.4 million. The bulk of that total — $9.2 million — is linked to the ECC project.
Revision Requests Approved
The MOPC approved nine revision requests on its consent agenda:
BPWG-RR 88, modifying the time of day when unscheduled firm transmission is released for sale as hourly, non-firm transmission service for the next day from noon (CT) to 10 a.m. The change will allow coordination of next-day scheduling with the Western Electricity Coordinating Council.
MWG-RR 7 MPRR155, revising instructions for dispatching generators out of merit order into two categories: reliability issues and emergency conditions.
MWG-RR 161, changing the method for calculating make-whole payments for multi-configuration combined cycle resources; the new rules allow use of a netting approach in calculating the commitment-level costs eligible for recovery.
MWG-RR 165, removing references to the retired Mitigated Offer Task Force from the Tariff’s Appendix G.
MWG-RR 166, removing references from the protocols and Tariff to the interim transmission congestion rights process developed for the transition into the Integrated Marketplace.
MWG-RR 169, changes reliability unit commitment calculations from evaluating megawatts needed hourly to those needed for each dispatch interval.
ORWG-RR 159, moves requirements regarding the outage-coordination function into SPP Operating Criteria Appendix OP-2 “Outage Coordination Methodology,” eliminating redundant language elsewhere.
RTWG-RR 160, clarifying the Integrated Transmission Planning manual to note which generation interconnections and associated upgrades are required to be modeled in ITP assessments.
RTWG 163, correcting Tariff language to specify the ITP manual includes references to requirements.
Working Group Closes 5 of 9 MMU Market Recommendations
AEP’s Ross briefed the committee on the MWG’s progress in implementing the market monitor’s recommended improvements to the Integrated Marketplace. The recommendations were a result of the July 2015 State of the Market report, which covered the markets’ first year of operation.
Four of the MMU’s nine recommendations are considered closed, having been addressed by revision requests:
Not subjecting quick-start resources to reliability unit commitment and not providing make-whole payments for resources dispatched in the real-time balancing market;
Reducing available financial transmission rights to minimize over-allocations when not supported by day-ahead congestion revenues;
Improving transmission-outage reporting in the FTR process; and
Automating the bidding process for transmission congestion rights to prevent ongoing Tariff violations.
The MMU withdrew a fifth recommendation, related to market power mitigation conduct thresholds. The monitor said it had observed lower-than-expected mitigation levels during the Integrated Marketplace’s second year of operation.
Ross said a task force has been formed to address ramp-constrained shortage pricing, which the MMU suggested should be priced the same as operating-reserve capacity shortages.
SPP RE Selects New Trustee Candidates
The Regional Entity’s trustees have worked with a search firm to select two candidates as new trustees: Mark Maher, who retired as the WECC’s CEO, and retired NYISO CEO Steve Whitley. SPP’s Members Committee will vote on their nominations during the July board meeting.
Maher and Whitley would join incumbents Dave Christiano and Gerry Burrows. Christiano replaced John Meyer as the trustees’ chairman earlier this year, when Meyer resigned to join Western Interconnection reliability coordinator Peak Reliability.
RE General Manager Ron Ciesiel told the MOPC the trustees approved the entity’s $10.9 million budget for 2017 and its business plan during their June meeting.
Ciesiel said the RE continues to see a downward trend in standards violations and vegetation contacts. He reported just two regional events during the second quarter, an outage and a 30-minute partial loss of monitoring at a control center.
The RE is conducting its first Critical Infrastructure Protection v.6 audit this month. Ciesiel said a FERC-led CIP compliance audit is expected next year, as the SPP footprint was not selected for an audit this year.
Recommendation: Retire Task Force, Create New Working Group
The CMTF held its last meeting June 30, when it finalized a charter for the new working group. It also reviewed its final deliverable, a resource adequacy workbook that combines the data needed for complying with NERC standards with those needed to validate SPP’s planning reserve margin. Chairman Tom Hestermann, of Sunflower Electric Power, said many of the task force’s members will transition to the new group.
The task force was created in 2014 to update SPP’s capacity margin requirements and methodology. Its work resulted in the RTO’s first reduction in its planning reserve margin since 1998 and a package of policies defining a load-responsible entity and its obligations. The task force also drafted a planning-reserve assurance policy and conducted a deliverability study. (See “Lowered Reserve Margin Promises $86M in Annual Savings,” SPP Board of Directors Briefs.)
Study Scopes Approved
The MOPC unanimously approved study scopes and revisions for a pair of studies, the Variable-Generation Integration study and the 2017 Integrated Transmission Plan’s 2017 Near-Term assessment.
The variable-generation study will include stability and frequency-response analyses with wind resources representing 30%, 45% and 60% of total SPP generation. SPP’s peak wind penetration record is 49.17%, and staff has said it expects to see levels approaching 60%.
Asked whether the task force is trying to determine when the 60% figure will be reached, SPP’s Casey Cathey, manager of operations analysis and support, said, “Sixty percent is a good level [to measure], because we have to add wind [generation] to get to that level. …The real issue, based on our footprint and our models, is will we see such penetration?”
Cathey said he is interested in determining whether there will be any voltage issues, saying, “We have to make sure that, given how we work the market, including dispatchable wind, whether we can maintain nominal voltage levels.”
The study will also analyze a potential five-minute ramping product.
The 2017 ITPNT’s scope was revised to include additional NERC transmission system planning performance (TPL-001-4) contingencies. Members also approved a modification to the 2017 ITPNT’s scenario 5, which sets all wind generation and reservations between companies to maximum firm service, as allowed on a pro rata basis. The modification aligns with the TPITF’s white paper, which assumed long-term firm transmission-service usage levels and conventional renewable resource output levels.
Regional Cost Allocation Review Approved
Members approved the Regional Allocation Review Task Force’s second regional cost allocation review of SPP’s regional- and zonal-allocation methodologies (RCAR II). There was one dissent.
The report’s 10 recommendations included proposed Tariff revisions and a proposal to incorporate its lessons learned in future assessments of the SPP highway/ byway methodology.
RCAR II identified the City Utilities of Springfield zone as SPP’s only deficient zone, with a benefit-cost ratio of 0.59, below the 0.8 threshold. Future transmission and seams studies with MISO and Associated Electric Cooperative Inc. are expected to help address the deficiencies. If not, a high-priority study for the area remains an option.
Two other zones (the Omaha Public Power District and Empire District Electric) are above the 0.8 cost-benefit threshold but below 1.0, requiring the RCAR II’s analysis be considered in future transmission plans.
The task force shared its report Monday with the Regional State Committee. Stakeholders will be able to provide their input through Aug. 5 for a lessons-learned report.
The New York Public Service Commission on Thursday declared a moratorium on energy marketers signing up low-income customers, citing the inability of stakeholders to agree on consumer protection reforms (12-M-0476, et al.).
The commission voted 3-1 to impose the moratorium, which takes effect in 60 days.
The PSC ordered a stakeholder collaborative after its February 2015 order requiring energy service companies to guarantee that low-income consumers enrolled in utility assistance programs will pay no more under an ESCO contract than they would have as a full-service utility customer. (Alternatively, the ESCO must provide the customer with value-added products or services that do “not dilute the effectiveness of the financial assistance programs.”)
The collaborative, which included ESCOs, low-income advocates, utilities and regulators, was unable to reach a consensus that would have satisfied the aims of the order.
Commissioner Diane Burman opposed the moratorium. “The statements in the conclusion [of the order] seem to [be] more in the nature of an advocacy, rather than in a reasonable balancing of the issues that we’re supposed to deal with as regulators,” she said.
Burman said the collaborative’s report showed that some ESCOs were willing to offer savings but that the “pathway” for further discussion was cut off by the moratorium.
PSC Chair Audrey Zibelman said that the first imperative was to “do no harm” while the commission dealt with further enhancing consumer protections.
“The record is clear that low-income customers have not benefited from electric and gas supply services from ESCOs when that’s all that’s being purchased. The commission is taking steps to ensure energy affordability for low-income customers,” Zibelman said in a statement. “Unless and until these guarantees can be made, it is critical that we ensure that low-income customers are not paying any more than necessary for gas and electricity. We challenged the competitive retailers to look for ways to guarantee savings at or below the cost of utility-supplied power and gas.”
The action follows a PSC order in February 2016 that mandated savings for most retail customers. That order has been challenged by retail energy marketers. (See Court Delays New York ‘Guaranteed Savings’ Rules.)
The PSC estimates that there are more than 400,000 low-income customers served by ESCOs. Low-income customers represent about 25% of all electric customers in the state.
Customers currently served by an ESCO will revert to the host utility’s default service when their contract expires. The moratorium will last until the commission determines it can be lifted, the order states.
The Retail Energy Supply Association said it was reviewing the order with its members and legal counsel.
“If maintained, the moratorium would prevent low-income customers from accessing fixed-price energy offers that provide price certainty when compared to New York utilities’ monthly variable rates,” spokesman Bryan Lee said in a statement. “This is a benefit that is of particular value to consumers on fixed or limited incomes. By way of this order the commission has taken away the low-income consumer’s ability to enter into fixed rates just before the potentially volatile winter months when we know from experience that utility default rates can fluctuate widely in response to extreme weather.”
SPP’s Seams Steering Committee can expect to soon see a final scope of the next planned joint transmission study with MISO.
Adam Bell, SPP’s interregional coordinator, told the committee July 8 that the two RTOs have not nailed down the scope, but that it may not be limited to the Dakotas’ seam with the Western Area Power Administration, as MISO would prefer. The two grid operators agreed May 31 to take a “targeted” look at the newly created seam. (See “SPP, MISO Agree to Conduct ‘Targeted’ Joint Tx Study,” SPP Seams Steering Committee Briefs.)
“The scope will leverage some of the work we’ve done regionally,” Bell said.
The study is planned for completion in the first quarter of 2017.
SPP staff also told stakeholders it had filed an out-of-time intervention in an interregional planning dispute between MISO and PJM, as approved by the committee in June (EL13-88). (See “Committee Recommends SPP Intervene in FERC’s NIPSCO Docket,” SPP Seams Steering Committee Briefs.)
Staff said a MISO compliance filing removed several limitations that hampered efforts to resolve SPP-MISO seams issues, including the 345-kV and $5 million cost thresholds.
Committee Chairman Paul Malone, of the Nebraska Public Power District, reminded the committee that MISO believes the docket only applies to the MISO-PJM seam. “Why shouldn’t these same principles apply to the MISO-SPP seam?” he asked.
The Delaware General Assembly has passed a resolution opposing PJM’s cost allocation for the Artificial Island project and creating a seven-member Cost Equity Committee to follow the issue through a planned rehearing at FERC.
The Delaware Public Service Commission estimates that under the PJM transmission owners’ distribution factor cost allocation method (DFAX), about $354 million of the projected $410.5 million project cost will be assigned to customers in the Delmarva transmission zone, while the area stands to receive only 10% of its benefits. Following a January technical conference, FERC approved the Artificial Island project’s cost allocation on April 22. On June 21, it agreed to a rehearing. (See FERC Taking a Second Look at Cost Allocation for 2 PJM Projects.)
In addition to giving the new committee the authority to intervene in the rehearing, the measure also grants the group permission to be involved in any related court proceedings.
State and federal legislators representing Delaware, Gov. Jack Markell of Delaware, Maryland Gov. Larry Hogan and various agencies representing Delmarva ratepayers have bombarded FERC and the PJM Board of Managers with letters criticizing the cost allocation. (See Stakeholders Ask FERC to Rehear Cost Allocation Order.)
The upgrade to the New Jersey complex that houses the Salem and Hope Creek nuclear reactors involves sinking a new 230-kV transmission line under the Delaware River to Delaware.
The Long Island Power Authority on Wednesday delayed approving a proposed 90-MW offshore wind farm off the coast of Montauk, N.Y., that would be the largest such project in the U.S.
LIPA executives had expected an easy approval vote from its board of trustees, but they delayed the vote at the request of the New York State Energy Research and Development Authority, which also has a wind farm planned for off the Long Island coast.
The authority “has asked for a brief delay of the LIPA board vote so the project can be examined in the broader context of the Offshore Wind Master Plan, the development of which [NYSERDA] is leading for the State,” NYSERDA spokeswoman Dayle E. Zatlin said.
“The Master Plan and its forthcoming draft blueprint will inform decisions about the best way to manage this valuable resource in an environmentally responsible way and in order to obtain the lowest achievable offshore wind electricity cost for New Yorkers.”
That “blueprint,” she said, should be completed in a few weeks. “Together, these efforts are part of New York’s intent to foster greater renewable energy production, including offshore wind, on Long Island and throughout the state.”
A LIPA spokesman said a few week’s delay in the vote should have no impact on the Montauk project. “We’ve been talking off-shore wind for about 11 years on our island so the few weeks delay, in context, is not a deal breaker.”
LIPA has selected Deepwater Wind, which is already building a 30-MW project off Block Island, R.I., to develop the project.
The U.S. Bureau of Ocean Energy Management has awarded about a dozen leases for commercial wind, but only the Block Island project has begun construction.
Deepwater Wind spokeswoman Meaghan Wims said the Long Island project, to be called the South Fork Wind Farm, is part of a larger lease obtained from BOEM. “We bid 90 MW to LIPA as part of this” request for proposals, she said. “Our total capacity at that site is 1,000 MW, to be built over phases. The South Fork Wind Farm is the first phase.”
View of the Block Island offshore wind project currently under construction by Deepwater, which was selected to build the Montauk project.
Montauk Project to Use 15, 6-MW Turbines
Deepwater will install 15 6-MW turbines about 30 miles off the coast of Montauk. Two 5-MW lithium-ion batteries will replace transmission investments that otherwise would be necessary. If all goes well, construction work could begin by 2021, with an operational date of December 2022, Falcone said.
“It is part of our goal to attain 400 MW of renewable energy, as part of the New York Clean Energy Standard, by 2023,” LIPA CEO Tom Falcone said in an interview Friday.
“We have an area of our service territory, East and South Hampton, with a lot of load growth, and we needed to address it in some way,” Falcone said. He said LIPA considered a transmission project to address the growing load, but after reviewing responses to its RFP, it determined the offshore wind project fit all the requirements.
“It’s the right project, the right size, and we can land in the right price area,” he said. Falcone said the project will cost a typical residential customer about $1.20/month.
Earlier offshore wind proposals were much more expensive than that, he said. Now, the cost of offshore wind is about the same as utility-scale solar — a resource not suited for crowded Long Island.
“I am not aware of any other utility that has signed a contract on a utility-scale project like this,” Falcone said. “We don’t have many other options” when it comes to renewable energy, he said. “On Long Island, land is constrained. But we have this tremendous offshore wind resource, thousands of megawatts. It is a tremendous resource.”
Lead Time Reduced
Falcone said much of the federal review process necessary for the Montauk project has already been done by Deepwater, which could save up to three years in the lead time for the project. “That was one thing that was particularly attractive” about the Deepwater plan, he said. “They are ready to go.”
Offshore wind projects need to be reviewed by BOEM to ensure they don’t encroach on commercial shipping areas or fishing grounds.
Community opposition has hindered other offshore wind projects on the East Coast. A 468-MW facility proposed off the coast of Massachusetts is tangled up in opposition from residents and no firm construction start date has been set.
Since news of its project got out, said LIPA Spokesman Sid Nathan, the authority has received dozens of messages of support from lawmakers, business owners and labor leaders. “We don’t expect community opposition of the proposal,” Falcone said.
“New York is boldly leading the way on a clean-energy revolution that will transform the nation’s energy future,” Deepwater CEO Jeffrey Grybowski said. “There’s real momentum for offshore wind in the United States, and Long Islanders are leading the charge.”
Currently, the largest offshore wind facility in the world is the 630-MW London Array, a 175-turbine facility off England’s eastern coast, in the outer Thames Estuary. DONG Energy is building tandem wind farms off the Dutch coast that will total 700 MW.
PJM CEO Andy Ott released a letter July 8 defending the RTO’s paper on competitive markets, saying that while it believes its markets are effective in both regulated and competitive retail structures, it did not conclude that any market outcome was superior to cost-of-service regulation.
“Instead, our analysis supports the hypothesis that markets lead to more cost-effective and economically efficient outcomes in managing new entry and exit of resources,” Ott wrote. “But this is purely an economic observation and is not to suggest that markets lead to the ‘best’ or ‘most superior’ outcomes for all parties in all circumstances.” (See PJM Study Defends Markets, Warns State Policies Can Harm Competition.)
Ott also indicated PJM would consider adding multiyear commitments to the capacity market’s current one-year contracts, which are procured three years in advance.
AEP, FirstEnergy Challenge
A coalition of generators led by American Electric Power and FirstEnergy challenged PJM’s analysis in a letter May 19, saying it presented a skewed view of the benefits of competitive constructs compared with the traditional regulated model. (See Generators Rebut PJM Study on Investment in Competitive Markets.)
AEP and FirstEnergy were joined by Dayton Power and Light, Duke Energy Ohio and Kentucky, Buckeye Power and East Kentucky Power Cooperative.
PJM’s Board of Managers commissioned the study after AEP and FirstEnergy asked Ohio regulators, and Exelon asked Illinois legislators, for help in supporting money-losing generators. (See PUCO Staff Recommends $131M Annual Rider for FirstEnergy.)
On July 7, Exelon officially notified PJM of its plan to close its Quad Cities nuclear plant on June 1, 2018, citing a lack of action by Illinois legislators. It also intends to shutter its Clinton station next year.
In his letter, Ott said, “As a threshold matter, we agree that cost-of-service regulation has managed the entry and exit of generation resources in a highly reliable manner over many decades. Indeed, as we noted in Part 2 of the PJM paper, regulated environments offer a forum to balance social, political and environmental interests alongside electricity costs to the consumer. … PJM also believes, however, that markets result in a more cost-effective and economically efficient approach to procuring adequate generating resources.”
Coal Retirements not Unique
Ott acknowledged concerns over generation retirements in PJM, but he said, “The retirement of coal generation and its replacement with combined cycle natural gas power plants is happening across this country; it is not unique to PJM.”
He also combatted generators’ assertion that PJM’s competitive markets owe their success to legacy assets and that it has relied on its pre-existing reserve margin for a decade.
“PJM forward projections indicated installed reserve margins were declining and would fall below 16% in 2008. In order to address these concerns, PJM proposed and implemented the [Reliability Pricing Model] forward capacity construct under which the declining reserve margin trend reversed,” he wrote. “Despite unprecedented forces changing the generation fuel mix in this country, PJM’s forward capacity market has maintained robust installed reserve margins. For the 2019/2020 planning year, PJM is carrying an approximate 22% reserve margin.”
Fuel Diversity
The regulated model, he said, lends itself to sacrificing some of that objective in favor of others, including promoting fuel diversity.
“While the recent investment trends have actually made PJM’s aggregate fuel mix more diverse over the past decade, PJM understands the concern that we need to analyze and quantify any potential operational or reliability challenges that may occur if the PJM region trends toward a very large percentage of gas-fired generation in the future,” Ott wrote. “PJM commits to perform such an analysis and will share results with stakeholders by first quarter of 2017.”
Multiyear Commitments
He added that PJM agrees in concept that the capacity market would be strengthened by the addition of some multiyear commitments.
“On this point, we agree that through bilateral agreements or market design changes, the market would be served by better options to lock-in price [and] manage risk and volatility for at least a portion of the supply portfolio,” he said.
In contrast with the negative reception it received from utilities in Ohio and Kentucky, PJM’s paper was lauded by the PJM Power Providers Group (P3) and a coalition of 16 independent power producers, including Calpine, Dynegy, NRG Energy and Talen Energy in letters last month.
“When markets are allowed to work, and are not undermined by out-of-market interventions or uneconomic new entry, consumers across the region will continue to see highly reliable service at the most efficient price,” wrote the IPPs.
Both P3 and the IPPs noted the new natural gas capacity added or proposed in the past five years.
“The IPP sector continues to lead this new investment, and the competitive PJM market structure has been the enabling platform on which these investment decisions have been made,” the IPPs said. “What PJM’s markets have not done — and should not do — is provide protection for certain suppliers who want to be shielded from market risk.”
RAPID CITY, S.D. — The Transmission Planning Improvement Task Force’s recommendations to streamline SPP’s transmission planning process won unanimous approval from the Strategic Planning Committee and the Markets and Operations Policy Committee last week.
If the recommendations win final approval from the Board of Directors next week, SPP will combine the Integrated Transmission Planning (ITP) near-term and 10-year assessments and NERC transmission planning (TPL) assessments into a single 10-year study that will produce an annual transmission expansion plan addressing reliability, economic and policy needs.
The new process will begin in September 2017, with its first results unveiled in October 2019. SPP will complete the 2017 ITP10, the 2017 and 2018 ITPNTs and conduct TPL assessments during the transition period.
NextEra Energy Transmission’s Brian Gedrich, the task force’s chair, said the new process will yield more accurate and forward-looking results.
“It’s a holistic approach, the opposite of the sequential way we do it now,” Gedrich told the SPC. “A lot of manpower resources are spent to provide [transmission-planning] information for you and the board. This will free up time so folks can do analysis … that will actually be actionable.
“No one was happy with the process. Today, all you do is take a 10-year look ahead. How can you possible see what is happening in real time, when all you look out is 10 years?”
Gedrich said building the initial future cases would require two to four additional full-time equivalents and $350,000 to $400,000 in consulting costs, depending on whether staff analyzes two or three futures. The task force recommended two futures.
“What are we getting out of this additional cost?” asked SPP Director Harry Skilton, who chairs the RTO’s Finance Committee. “I hear you say more efficiencies, but what tangible benefits do members get?”
ITC Holdings’ Marguerite Wagner agreed the benefits can be difficult to quantify.
“We spend hundreds of millions of dollars on transmission, and we see congestion in the same areas,” she said. “We expect this new process to be more granular, thus leading to potentially better solutions and outcomes.”
“As you do the same thing over and over, I think you will gain efficiencies. Right now, as we start and stop, you lose a lot of time,” Gedrich said.
Skilton seemed satisfied with the responses. “If in the judgment of the membership it will get better results, address congestion in the near term and improve the planning process … that’s a helluva accomplishment,” he said.
The task force’s other recommendations included:
Standardizing the ITP’s scope and developing a streamlined assumptions document;
Developing a single, base reliability powerflow model that will be used for all planning processes;
Adding accountability with mechanisms designed to promote timely data exchanges, reviews and approvals; and
Limiting the initial 2019 study scope to two study futures to help facilitate the move to the new planning process.
Export Pricing Task Force Given the Go-Ahead
The committee unanimously accepted staff’s recommendation to create an export-pricing task force to research SPP’s Tariff and FERC policy and evaluate how best to take advantage of the RTO’s abundant variable energy resources.
The task force would make recommendations on establishing “equitable and nondiscriminatory” rates to address recovering incremental transmission and facility costs needed to export and import electricity, and “how to avoid paying for it on the back of SPP ratepayers — which will be difficult to do,” said Sam Loudenslager of SPP’s regulatory staff.
Loudenslager said the SPP region currently has 22,000 MW of variable resources in its queue and not yet in service.
SPP’s Corporate Governance Committee, which doesn’t meet until late August, will have to approve the task force’s formation.
Dogwood Energy’s Rob Janssen suggested the task force’s representation include members experienced with life on the seams.
“We have to remember we have members with loads on both sides of the border, who move power any given day or time,” he said.
“If you can’t get the money right, you can’t get anything done,” SPP Director Phyllis Bernard said. “This is one of those task forces focusing in on how to get the money right. There are genuine legal problems here, and absent federal direction, export pricing has to be the solution.”
Asked by SPC Chairman Mike Wise of Golden Spread Electric Cooperative whether the task force would develop a marketing campaign to “advertise our energy,” Loudenslager responded, “I’m not a marketing guy.”
PJM and the Retail Energy Supply Association want a say in Dayton Power and Light’s plan to keep its coal-fired plants running.
Both organizations have filed motions to intervene in DP&L’s “electric security plan” application before the Public Utilities Commission of Ohio. If their past actions are any indication, they will voice objection to the plan, much as they did in similar cases involving FirstEnergy and American Electric Power, which are Ohio’s two largest electric utilities. (See PJM Looking at AEP, FirstEnergy PPAs; Critics Join Forces.)
DP&L’s application proposes a 10-year reliable electricity rider (RER), which would help parent company AES continue operating its fleet of coal-fired plants. Under the rider, DP&L would agree to acquire generation from the shares another AES subsidiary owns in the Ohio Valley Electric Corp. and the Conesville, Killen, Miami Fort, Stuart and Zimmer plants — all baseload coal-fired facilities DP&L used to own but was required to sell under its current ESP.
The rider would further stipulate that the difference between the revenue requirements of each plant and its expected revenue would be calculated annually. Depending on the outcome of the calculation, customers would receive a credit or a charge.
Kyger Creek Power Plant
In announcing the application, DP&L estimated that, if approved, the first year of the rider in 2017 would result in an additional $1.21 charged to each monthly bill but “contribute an estimated $26.5 billion in positive economic benefits for Ohio.”
In their filings, PJM and RESA said approval of the plan would have market-wide impacts.
“The commission’s decision in this matter will affect the viability of the competitive retail electric market in DP&L’s service territory,” RESA said in its filing.
“The nature and extent of PJM’s interest is to ensure DP&L’s RER proposal will not negatively impact PJM’s ability to administer efficient and competitive wholesale energy, ancillary service and capacity markets, and maintain the reliability of the transmission system in the PJM region,” PJM’s filing stated.
DP&L’s plan has drawn criticism from environmental groups, including the Ohio Environmental Council and the Environmental Defense Fund. Both groups are also contesting similar proposals from FirstEnergy and AEP.
The companies are “cherry-picking some of their worst plants, and they’ll put those in a package and they’ll say that the state of Ohio needs these for jobs and economic development,” said John Finnigan, a lead attorney with EDF.
“It’s a subsidy for these plants. These plants are out of the money.”
Under its current ESP, DP&L was required to divest its generating assets. AES decided in 2014 to retain the Dayton-area power plants, which were nearly 3,500 MW at the time. The generation was sold to another AES subsidiary, AES Ohio Generation.
Both AES Ohio and DP&L are overseen by DPL, another AES subsidiary. Today, DPL serves (through DP&L) approximately 515,000 customers in 24 counties throughout West Central Ohio and operates (through AES Ohio) 3,066 MW of generation, 2,078 MW of which is coal-fired.
DP&L said it was reviewing the petitions to intervene. “Once a thorough review is complete, we will explore all options for our next steps,” said spokeswoman Mary Ann Kabel.
The plan’s aim is to reduce peak load on the utility’s distribution system and includes programs to encourage the use of smart thermostats, demand response, LED lighting and technologies that improve the efficiency of air conditioners.
Ranger Solar is conducting an environmental assessment for a solar farm of up to 80 MW that could break ground in 2018.
The state has hired two companies to analyze the financial impact of a hypothetical rupture of Enbridge’s underwater pipelines, collectively called Line 5, in the Straits of Mackinac and to explore potential alternatives to their route. Enbridge will pay $3.5 million for the studies but declined to oversee the work.
The Utilities Commission says two nonprofits must put up a $98 million bond to go forward with an appeal of a permit given for a new Duke Energy gas-fired power plant. The commission originally set the bond at $10 million, but an appellate court told it to recalculate the bond based on “competent evidence.”
Two administrative law judges are recommending that the Public Utility Commission fine Blue Pilot Energy $5 million for charging its variable-rate customers high prices during the polar vortex of 2014.
The Commission on Environmental Quality renewed and expanded a wastewater permit for Dos Republicas Coal Partnership, allowing the company to expand its current operations near the Mexican border and mine up to 6,300 acres for low-quality coal.
Adam Bell, SPP’s interregional coordinator, told the committee July 8 that the two RTOs have not nailed down the scope, but that it may not be limited to the Dakotas’ seam with the Western Area Power Administration, as MISO would prefer. The two grid operators agreed May 31 to take a “targeted” look at the newly created seam. (See “SPP, MISO Agree to Conduct ‘Targeted’ Joint Tx Study,” 
