Page 1694 – RTO Insider

January 5, 2016

Infrastructure Moves to Forefront in New England

By William Opalka

Winter reliability, the forward capacity market and infrastructure expansion have been the dominant themes in New England in recent years, and 2016 appears to be no different.

Record warmth this winter has kept power prices tame and new reliability incentive programs are expected to ensure adequate fuel supplies. Capacity prices may also moderate due to the addition of new generating resources.

Capacity Prices Expected to Drop

Forward Capacity Auction revenues have almost quadrupled over the past two auctions, from just more than $1 billion in 2013 to $3 billion in 2014 and $4 billion last year. About 1,000 MW of new generation entered the market for the 2018/19 capacity commitment period.

Morningstar says it expects 750 MW of dual-switching capability to be added for winter 2015/16 and 1,000 MW more by winter 2016/17. (See ISO-NE: Little Room for Error in Winter.)

A lingering controversy to be cleared up before the coming auction is how solar resources should be calculated. (See Generators Dispute ISO-NE on Solar Capacity.)

Moving Toward Renewable Energy

Massachusetts is expected to reconsider its net metering cap early this year after proposals to raise it got bogged down in the legislature in 2015. Utilities there are closing in on the 1,600-MW limit.

Massachusetts, Connecticut and Rhode Island have embarked on a joint effort to procure clean energy more cost-effectively. Bids on prospective projects are due at the end of January.

The shift to renewable energy is progressing, as New England continues to lose its nuclear generation fleet. Entergy last year announced its 680-MW Pilgrim nuclear station will close no later than mid-2019, but the final date is expected to be announced by the middle of this year.

Key Milestones

Meanwhile, several proposals for new transmission lines and two natural gas pipelines reached key milestones last year, with more significant decisions on their fates due by the end of 2016.

Spectra Energy’s Algonquin Gas Transmission asked FERC in November for a pre-filing review of the proposed Access Northeast pipeline. The company expects to file a formal application in about a year and hopes to put the first phase of the project in service by November 2018. (See Algonquin Submits Pre-Filing Request for Access Northeast Pipeline.)

Also in November, developers of the Northeast Energy Direct pipeline through Massachusetts and southern New Hampshire filed certificates of need with FERC. The Kinder Morgan project would transport Marcellus shale gas from Pennsylvania. The developers hope for FERC approval in the fourth quarter. (See Northeast Energy Direct Files for FERC Certificate.)

Hydropower Plans Move Forward

Two competing proposals to import Canadian hydropower into the region also advanced last year.

Northern Pass Transmission received its draft environmental impact statement from the U.S. Energy Department. The New Hampshire Site Evaluation Committee is expected to rule by the end of the year on the 192-mile transmission line to move 1,090 MW of hydropower from Quebec. (See Committee Rules Northern Pass Application Complete.)

TDI New England’s Clean Power Link received its final environmental impact statement, which recommended approval of a presidential permit. The cross-border project would transmit 1,000 MW of Canadian hydropower under Lake Champlain.

The first phase of the project’s open season in December received expressions of interest from seven utilities on both sides of the border seeking 3,200 MW of capacity. Negotiation of the agreements will continue through this year.

January 5, 2016

After Year of Change, PJM Faces Questions

By Suzanne Herel

2015 was a year of change for PJM, which said goodbye to CEO Terry Boston, ushered in its new Capacity Performance product and awarded its first competitively bid transmission projects under FERC Order 1000.

Capacity Performance undoubtedly will be in the headlines again in 2016 under new CEO Andy Ott, previously executive vice president of markets. The new year also will see policymakers dealing with cost allocation for new transmission, the future of demand response and potential FERC rulings on financial trading and transmission planning.

That work will take place against the backdrop of a continuing fuel shift. For the first time in 2015, natural gas passed coal as the fuel used to generate the most electricity, thanks to the cheap bounty uncapped in the Marcellus Shale.

Morningstar analyst Jordan Grimes says the RTO, which retired 9.8 GW of coal-fired generation last year, could see as much as 18.5 GW of gas-fired combined cycle units come online through 2019.

Grimes said the new generation will have some of the lowest prices in the PJM dispatch stack after wind, nuclear and hydro and is unlikely to set marginal prices often during on-peak hours. “The combined cycles will displace some coal generation, but at the margin it will be displacing less efficient gas units. This gas-on-gas competition means coal will actually be on the margin more often,” Grimes wrote. “Coal plants amortizing costs over a shorter time period, MATS compliance and less energy revenue should encourage coal plants to raise offers with their new pricing power on the margin.”

Effective March 31, PJM will move its deadline for day-ahead energy offers up 90 minutes to 10:30 a.m. ET to ensure gas units have time to procure fuel before the revised 2 p.m. ET timely nomination deadline for gas. (See PJM, NYISO, ISO-NE Gas Scheduling Filings OK’d.)

After a long debate, PJM members voted to raise the energy market offer cap to $2,000 to ensure that gas-fired generators can recover their costs when prices spike during extreme conditions, like those seen during the 2014 polar vortex. (See PJM Members OK $2,000/MWh Energy Market Offer Cap.)

Capacity Performance

It was unusually high generator outages during the polar vortex that also gave rise to the controversial new Capacity Performance model, designed to strengthen reliability by giving bonuses to over-performing generators and assessing heavy penalties on those that fail to perform.

The new year will bring PJM its first operational experience under the new rules. PJM will have about 95 GW of Capacity Performance resources for the 2016/17 delivery year beginning June 1.

Transition auctions to add the upgraded product cleared at $134/MW-day (2016/17) and almost $152 (2017/18). (See PJM Transition Auction Means Reprieve for Exelon Nukes.)

The 2018/19 Base Residual Auction — the first BRA to include the product — saw prices rise 37% to $165/MW-day in most of the RTO, while the ComEd zone broke out at $215 and Eastern MAAC hit $225.

UBS predicts prices will dip to about $100/MW-day for the 2019/20 delivery year and $153/MW-day for 2020/21. The analysts said changes to PJM’s load forecasting methodology — aimed at correcting several years of overly bullish projections — “largely [undo] the upside” from CP. (See “Load Forecast to Include Distributed Solar” in PJM Markets and Reliability Committee Briefs.)

pjm

Bidding behavior could be affected by FERC rulings on PJM’s market rules.

Last month, PJM asked FERC to rule by Feb. 1 on its Capacity Performance compliance filings and outstanding rehearing requests (ER15-623, EL15-29). PJM said it is trying to avoid “operational challenges” that could result from uncertainty over when PJM’s dispatch decisions will result in a capacity market seller being exposed to non-performance charges.

“Some resource owners have told PJM they will turn to self-scheduling (or self-dispatching) and operate at maximum output to avoid non-performance charges,” PJM wrote. “This clearly is an anomalous result which is contrary to the goals of Capacity Performance as a tool to enhance operational performance and system reliability.”

Changes also could result from a problem statement approved by stakeholders in December to consider widening force majeure rules and expanding ways for generators to minimize underperformance penalties by netting them against over-performing generators. (See “Ways to Mitigate Risk in CP Market to be Studied” in PJM Markets and Reliability Committee Briefs.)

Despite the increase in prices under Capacity Performance, FirstEnergy and American Electric Power have asked Ohio regulators to approve proposals to essentially reregulate 6,300 MW of their generation. PJM filed testimony last week expressing concerns over the impact of the proposals on the wholesale markets. (See PJM Seeks Changes to AEP, FirstEnergy PPAs.)

Order 1000 Projects

The PJM Board of Managers ended the year by approving $490 million in transmission projects proposed in response to FERC Order 1000 competitive solicitations.

In July, it finally greenlighted its first Order 1000 project, a stability fix for the Salem and Hope Creek nuclear reactors on New Jersey’s Artificial Island. The approval of the project, which followed a controversial two-year selection process, almost immediately spawned a new dispute as officials in Maryland and Delaware complained that they were being billed for virtually all of the $146 million price tag. The cost allocation issue will be the focus of a FERC technical conference scheduled for Jan. 12. (See FERC Questions Fairness of Artificial Island Cost Allocation.)

Transmission Planning, UTCs, FTRs

PJM stakeholders will be spending a lot of time with FERC in 2016:

Reply comments are due Jan. 15 in FERC’s inquiry into PJM’s local transmission planning process, the subject of a technical conference in November. (See PJM TOs Defend Jurisdiction at FERC Conference.)
PJM traders are awaiting a FERC order telling them whether up-to-congestion trades will be charged uplift and made subject to PJM’s financial transmission rights (FTR) forfeiture rule (EL14-37). In opening the Section 206 docket in 2014, the commission said it would rule within five months after it receives comments following a technical conference. The conference was held Jan. 7 and comments were due May 29. That put FERC on schedule for a ruling by the end of October, but there has been no word from the commission so far. (See Monitor at Odds with PJM, Marketer over FTR Forfeiture Rule.)
Last week, the commission ordered a technical conference on PJM’s proposed changes to its FTR allocation rules. (See related story, FERC Orders Technical Conference on PJM FTR Rule Changes.)
2016 also could see action by FERC to address issues over PJM’s seam with MISO. In February, the commission said it was considering intervening and ordered the RTOs to provide status reports on eight unresolved seams issues (AD14-3). (See Impatient FERC Hints at Action on PJM-MISO Seams Disputes.) Commission staff have attended three PJM/MISO joint stakeholder meetings since.

PJM stakeholders also are anxiously awaiting the Supreme Court’s ruling on an appellate court order that voided FERC’s jurisdiction over DR. With one justice having recused himself, the court could split 4-4, leaving the ruling standing and PJM scrambling to adjust to the impact on its capacity market. (See FERC Jurisdiction over DR in Peril as Supreme Court Splits.)

The court also will review lower court rulings throwing out state-issued contracts Competitive Power Ventures won to build combined cycle plants in Maryland and New Jersey. (See SCOTUS Agrees to Hear Md., NJ-FERC Subsidy Case.)

New Faces and Retirements

In addition to the departure of Boston, the RTO also said goodbye to board member William Mayben, who retired after eight years. South Carolina engineer Terry Blackwell was elected to serve out the remainder of Mayben’s term. Going forward, the board announced, members will be ineligible for re-election once they either turn 75 or have served five terms. (See New PJM Board Member Elected, Re-election Eligibility Changed.)

January 5, 2016

Company Briefs

Ameren Floods closed segments of the Illinois and Mississippi rivers to navigation in the St. Louis area and forced Ameren to use ferries to gets its workers to a stranded power station.

The flooding also caused Enbridge and Spectra Energy to shut down oil pipelines until the waters recede.

Workers at Ameren’s Sioux Energy Center north of St. Louis were being ferried to the isolated coal-fired plant, which remained in operation.

More: Bloomberg News

New Wind Farm Gives Westar 280 MW of Renewable Energy

Westar Energy is working with Infinity Wind Power to construct a 280-MW wind farm in western Kansas. The Western Plains Wind Farm will bring Westar’s renewable energy total to more than 1,500 MW.

Westar says it is finalizing a separate agreement for another 200 MW of wind energy, with an option to own 50% of that power.

The utility company anticipates both wind farms to be operational in early 2017. The projects will supply enough electricity to power 400,000 homes.

More: Wichita Business Journal

PNM Brings Solar Facility Online South of Albuquerque

Public Service Company of New Mexico’s fourth solar energy center is its largest yet, with more than 40,000 photovoltaic panels that will generate enough energy a year for more than 4,000 residential customers.

The Rio Communities Solar Energy went online Dec. 31 south of Albuquerque. PNM invested about $20 million in the project, which was built on 103 acres of land.

More: Valencia County News-Bulletin

ComEd Planning Tx Line Along O’Hare Expressway

Commonwealth Edison is holding open houses throughout January in various suburban Chicago towns to present its plans for a 9-mile transmission line along the Illinois Route 390. The 138-kV line, which will run through DuPage and Cook counties, will be supported by towers ranging from 140 feet to 170 feet tall.

The company said the line is necessary to improve service to Chicago’s western suburbs. It will need approval from the Illinois Commerce Commission. The company wants to complete the project by the summer of 2018.

More: DuPage Policy Journal

PSE&G’s Mount Holly Solar Facility Starts Operation

Public Service Electric and Gas put the finishing touches on its largest solar facility in New Jersey, and the 12.9-MW solar farm is now generating electricity for the grid. The solar farm, consisting of 42,000 panels, is on the former L&D Landfill near Mount Holly.

It is the fourth solar facility the utility has built on New Jersey landfills. It has a 3-MW facility in Kearney, a 10-MW solar farm in Bordentown and an 11-MW facility in Deptford. The L&D landfill was a former Superfund site. PSE&G used 53 acres of the site for this facility and may expand it later.

More: The Philadelphia Inquirer

Dominion Proposes $85 Million to Offset James River Tx Line Impacts

Dominion Virginia Power has proposed spending $85 million to offset environmental and visual impacts of its proposed 500-kV transmission line across the James River near its Surry Power Station. The company said the line, supported by 17 towers up to 295 feet high, is necessary to protect reliability in the region.

Opponents said the project would be an eyesore and harm sensitive environmental areas. National Park Service Director Jonathan B. Jarvis urged the U.S. Army Corps of Engineers to deny a construction permit, saying the power line would “mar the historic setting” of the nearby Yorktown battlefield, part of Colonial National Historical Park.

The company’s proposals include spending $15.5 million in water quality improvements, about $12 million in landscape conservation near the Yorktown site and $4 million to protect a marsh at Hog Island Wildlife Management Area.

More: The Virginia Gazette

Murray Energy Eyeing Cutting Nearly 600 Mining Jobs

The downturn in coal demand is prompting Murray Energy to cut nearly 600 mining jobs, according to the United Mine Workers of America. While a Murray spokesman declined to confirm the number, he said there were changes coming and described upcoming “workforce adjustments.”

CEO Robert Murray has been among the most vocal critics of the Obama administration’s Clean Power Plan, which would accelerate the retirement of coal-fired generation throughout the country.

The decline in coal-fired generation is causing a decline in coal demand, pressuring the Appalachian mining industry, which already is suffering from competition from cheaper coal from Illinois and Wyoming.

More: Associated Press

Dominion Sheds Solar to SunEdison for $180 Million

Dominion Resources completed the first phase of a two-part deal to reduce its solar investments by 425 MW when it sold 33% of its interest in 15 projects to SunEdison for $180 million.

SunEdison turned around and sold the newly acquired portfolio to Terra Nova Renewable Partners, a joint venture SunEdison formed with JPMorgan Chase investors.

The second phase of Dominion’s solar sale will come early this year, when it is expected to sell 33% of its stake in nine more projects, representing 172 MW of capacity. Dominion says it will use the cash from the sales to reduce debt.

More: Richmond Times-Dispatch

Two-Thirds of Duke’s Ash Ponds Rated Medium or High Risk

The North Carolina Department of Environmental Quality ranked 20 of Duke Energy’s 32 coal ash storage ponds in the state as high risk or intermediate risk. A department draft report placed fewer of the ash repositories in the high-risk category than an earlier report.

The DEQ will release its final report within 30 days. Any ponds in the high- to intermediate-risk categories must be excavated instead of merely drained and capped, driving up remediation costs. The company has estimated the cost of closing all 32 ponds at $3.4 billion. Those costs will be passed on to customers through rate increases.

More: Charlotte Observer

Talen Energy Execs’ ‘Golden Parachutes’ Sign of a Possible Merger?

talen Documents filed by Talen Energy with the Securities and Exchange Commission detailing possible severance pay and other benefits could be a sign that Talen might be the target of a merger or subject of an acquisition attempt, according to The Morning Call.

The newspaper reported that Talen filed so-called “change-in-control” agreements with the SEC. Such agreements are often approved by a company’s board to retain key executives when the company is the target of a takeover. Talen spokesman Todd Martin said the filings were routine. “Agreements and provisions similar to those disclosed are not unusual for a public company, and the filing itself is a standard regulatory requirement.”

Talen CFO Jeremy R. McGuire, COO Clarence J. Hopf Jr. and Chief Nuclear Officer Timothy S. Rausch were named in the documents. In addition to severance pay based on their salaries — each makes at least $400,000 annually — they would receive stock options, restricted stock units and performance bonuses. The value of the extras ranges from $840,000 to $1.1 million.

More: The Morning Call

January 5, 2016

Changes to PJM Load Forecast Cuts Benchmark Peaks

PJM’s new load forecasting methodology cuts projected peaks for several key benchmarks by 3.5% or more, the RTO said last week.

In response to criticism that its forecasts overestimated loads, PJM has made a number of changes to its methodology. Among them is the treatment of weather, added variables to gauge trends in equipment and appliance saturation and efficiency, and accounting for energy efficiency resources and distributed solar generation. (See “Load Forecast to Include Distributed Solar” in PJM Markets and Reliability Committee Briefs.)

The new methodology has particular ramifications for both the capacity market and transmission planning. It reduces the forecast peak for the 2019/20 Base Residual Auction by 5,660 MW (-3.5%) and that for 2021 — the next Regional Transmission Expansion Plan study year — by 8,406 MW (-5.1%).

The forecast released Wednesday projects a 2016 RTO summer peak of 152,131 MW. That’s a reduction of 5,781 MW (-3.7%) compared with PJM’s forecast a year ago but an increase of 1,836 MW (1.2%) from the 2015 normalized peak.

The RTO’s summer peak is predicted to grow 0.6% annually over the next 10 years, with growth rates for individual zones ranging from -0.1% in the Atlantic Electric zone, which has been hurt by a decline in casino gambling, to 1.2% in the Dominion zone, which is seeing “substantial on‐going growth in data center construction.”

The winter peak load is expected to rise an average of 0.8% per year over the decade, bracketed by Atlantic Electric, which shows no growth, and Dominion, up 1.6%.

The forecast for the APS zone reflects increasing load from natural gas processing plants, which are expected to add 120 MW to 280 MW annually for 2016-2020. The zone’s summer peak is expected to increase 0.8% per year through 2026 with a 1.1% annual increase in winter peaks.

— Suzanne Herel

January 5, 2016May 27, 2025

Transmission, REV Dominate NYISO’s Landscape

By William Opalka

Bradley Jones, who stepped in as CEO of NYISO late last year, recently told RTO Insider that his three top initiatives “have always been transmission, transmission, transmission.”

He came to the right place. Transmission upgrades dominated activity in the NYISO footprint in 2015 and promise to occupy headlines in 2016.

The improvements are occurring amid a changing energy landscape. State officials and regulators are deciding how to handle aging and unprofitable power plants in western New York. Meanwhile, the Reforming the Energy Vision initiative seeks to encourage the growth of distributed and renewable resources throughout the state.

The New York Public Service Commission last month declared a public policy need for an expected $1.2 billion in upgrades to move 1,000 MW of power from upstate generation sites to load centers in and around New York City. The project has been discussed for more than three years; now, NYISO will seek bids on the projects. The PSC hopes to evaluate siting proposals by the end of the year, with approvals anticipated in 2017. The upgrades are expected to be in service in 2019. (See NYPSC Declares Public Policy Need; Directs NYISO to Seek Tx Bids.)

Future of Nuclear Uncertain

Will the transmission projects come too late to save aging and unprofitable nuclear and coal-fired power plants in the western part of the state? Or, as environmental and consumer advocates might ask: Are those plants even worth saving?

In his State of the State address on Jan. 13, Gov. Andrew Cuomo is expected to announce details of a plan to shift the state to 50% renewable energy by 2030, along with a strategy to keep the nuclear plants open until then by offering some financial recognition of their carbon-free emissions. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)

Nevertheless, Entergy is standing by its decision to close the James A. FitzPatrick nuclear plant on Lake Ontario in late 2016 or 2017.

Exelon and stakeholders are finalizing a reliability support service agreement for the R.E. Ginna nuclear plant that would run through March 2017 — after which, the company says, the plant is likely to retire. The PSC has extended the negotiating window for that deal to Feb. 29. (See Ginna Lifeline to End in 2017; Profits After ‘Unlikely’.)

At the same time, the state’s REV proceeding is continuing with development of demonstration projects, including microgrids and energy efficiency programs.

Much attention will be paid to the anticipated Track 2 Order that addresses rate design for the new business models. (See NYPSC Outlines Reforming the Energy Vision Changes.)

RMRs Winding Down

In the meantime, several reliability-must-run agreements that pay unprofitable plants above-market rates are starting to wind down. Some of the facilities hope to repower with natural gas, proposals that will be addressed by regulators this year.

One of these, the coal-fired Dunkirk station outside of Buffalo, was mothballed Dec. 31, when its RSSA expired. Owner NRG Energy has suspended the repowering plan pending resolution of a lawsuit filed by Entergy. (See NRG Plant Closures Could Impact Reliability in NY.)

The 312-MW Cayuga coal-fired plant outside of Ithaca is operating under an RSSA through mid-2017. Although its owner has proposed converting it to natural gas, a transmission project proposed by a distribution utility and endorsed by environmentalists could make the plant unnecessary.

Plans to convert the idled Greenidge power plant on Seneca Lake to gas are on hold as EPA has said it must undergo a “new source” review.

January 5, 2016

SPP, ERCOT Set New Wind Peaks

SPP, which has already set six wind peaks this fall, established another on Dec. 19 with 9,948 MW, the second time it has eclipsed 9,000 MW. The RTO said wind’s penetration level was 33.5%, off the record 38.3% set Nov. 4.

ERCOT closed out 2015 with its eighth wind peak of the year, a record 13,883 MW on Dec. 20, representing more than 93% of its installed wind capacity and 44.7% of load served.

The wind generation easily topped the previous peak set Dec. 19, when the ISO exceeded 13,000 MW for the first time with 13,029 MW.

ERCOT generated almost 4.4 million MWh of wind energy in November, accounting for 18.4% of energy used.

— Tom Kleckner

January 5, 2016

A Few Growing Pains for SPP as it Celebrates 75 Years

By Tom Kleckner

During the past two years, SPP has added new markets for its members, some 5,000 MW of peak demand and 7,600 MW of generating capacity in the Upper Great Plains, extending its footprint to the Canadian border in the process.

So what does it plan for an encore in 2016?

Celebrating its 75th anniversary, for one. SPP will mark the occasion this fall with several ceremonies and a commemorative publication chronicling the RTO’s history, which began in the days after the attack on Pearl Harbor.

That’s when 11 regional power companies in the Southwest — including predecessors of today’s SPP member companies — signed an agreement to pool their energy resources and ensure Central Arkansas’ aluminum production could maintain 24/7 operations. When World War II ended, an executive committee decided to continue the organization to maintain reliability and coordination.

From those modest beginnings, SPP has grown into a sprawling member-driven organization, coordinating electricity flows over 56,000 miles of high-voltage transmission lines across 575,000 square miles in all or parts of 14 states, from the Deep South to the Dakotas and westward. It counts 97 members representing cooperatives, power producers, marketers and independent transmission companies along with the usual transmission owners, and has 170 registered participants in its markets.

A ‘Success Metric’

SPP’s growth has been good news for its members.

The RTO projects the addition of the Integrated System (IS) last October will yield $334 million in member benefits over a 10-year period. It also has said the Integrated Marketplace — comprising day-ahead, real-time balancing and congestion-hedging markets — generated approximately $210 million in total regional net savings in its first year, in addition to $170 million in savings from SPP’s previous energy imbalance service market. SPP plans to release a study quantifying the transmission benefits its members receive in January.

“It’s been another interesting year for the corporation and our members,” SPP CEO Nick Brown said during October’s board meeting. “If ever there’s a success metric, it’s the members who have decreased costs or rates.”

SPP will focus much of this year on improving its rapidly maturing markets with three projects: enhanced combined cycle (ECC) logic, gas-electric “harmonization” and the Z2 crediting tool.

Improved Economic Dispatch

The ECC project is designed to provide more sophisticated modeling that captures the flexibility of combined cycle plants. Each combined cycle configuration will be modeled in the market-clearing engine as a separate resource.

SPP expects the increased flexibility to allow “optimization of the combined cycle resource configuration throughout the unit commitment processes,” projecting in its 2016 budget a $3 million to $5 million reduction in generation costs. The savings are expected to grow as new combined cycle plants join SPP in the future.

SPP has targeted March 2017 for completion of the $1.5 million project. (See “Enhanced Combined-Cycle Project Moves Forward” in SPP Board of Directors/Members Committee Briefs.)

The ECC work will be done in conjunction with system changes needed to close the Integrated Marketplace’s day-ahead market earlier and shorten the solution time for posting results by 30 minutes. Both have significant impacts on the market operating system’s solution time.

SPP said the gas-electric harmonization work will be completed by the fall, at a projected cost of $6.2 million.

The initiative is a result of FERC Order 809, which moved the timely nomination cycle deadline for gas from 11:30 a.m. CT to 1 p.m. (See “Board Approves Gas-Electric Timeline Change” in SPP BoD/Members Committee Briefs.)

SPP says the schedule changes are “an incremental improvement over the existing timeline.”

Years of Incorrect Credits

The Z2 crediting project dates back to the last decade as a result of years of incorrect credits for transmission upgrades. (See “Z2 Crediting Task Force Remains on Track” in SPP Markets and Operations Policy Committee Briefs.)

A project team is developing software that will properly credit and bill transmission customers for system upgrades under SPP’s Tariff attachment Z2. The problem has been avoiding over-compensating project sponsors and including a way to “claw back” revenues from members who owe SPP money for other reasons.

The task force has estimated creditable upgrades of $750 million, with up to $90 million in transmission customer improvements and the remainder from sponsored upgrades.

The task force hopes to present a better estimate during the Markets and Operations Policy Committee and Board of Directors/Members Committee quarterly meetings in January.

SPP says the new system should reduce errors, disputes and resettlements.

Eyes on Expanded Footprint

SPP’s day-to-day business in 2016 will remain focused on maximizing the addition of the IS to its footprint.

The IS tripled SPP’s hydroelectric capacity, which represented only 1.1% of the RTO’s capacity in 2014. It also added winter-peaking regions, increased seams coordination issues and greatly expanded the geographic area for SPP’s reliability monitoring function.

SPP says the addition of the IS has “opened opportunities to expand SPP’s services to affiliated entities in the Western Interconnect” through membership or contracted services. SPP has an ongoing market-consulting contract with the Northwest Power Pool, which has been exploring the possibility of opening an energy market for several years.

Because of the surge in wind production, the RTO will refresh its 2009 wind-penetration study in February.

Navigating the Clean Power Plan

SPP will continue its work helping states comply with EPA’s Clean Power Plan. The RTO expects “significant impacts in the near term and well into the future.”

SPP’s 2016 operating plan says it intends to encourage regional compliance. But it acknowledges some states may decide to go it alone. Several SPP states have joined litigation to block the rule.

“The lawsuits will muddy the water in terms of how SPP interacts with its stakeholders as they work to comply with the standards,” it said.

SPP’s 2016 operating plan says it intends to encourage regional compliance. But it acknowledges some states may decide to go it alone.

The RTO will include CPP compliance in the 2017 Integrated Transmission Planning 10-year assessment. A near-term transmission study also will be conducted this year, with the results presented to MOPC and the board in April.

At that time, MOPC and the board should be taking up for consideration SPP’s first Order 1000 project, the 21-mile, Walkemeyer-North Liberal 115-kV project in Kansas. An industry expert panel is currently evaluating responses to SPP’s request for proposals.

SPP expects to receive 3,200 proposals for competitive projects in 2016, double the number it saw in 2014.

It also expects a “significant increase” in generation interconnection studies. SPP projects a 12% bump in transmission volume to more than 407 MWh in 2016.

January 5, 2016

FERC Again Rebuffs Brayton Point Union

FERC on Wednesday denied rehearing of its June decision certifying the ninth Forward Capacity Auction results in ISO-NE, dealing another blow to a utility union’s claim that supply of the Brayton Point plant was illegally withheld to raise prices (EL15-1137).

The Utility Workers Union of America, which represents workers at the Massachusetts plant, in July asked FERC to void the auction results. (See Fourth Time the Charm? Brayton Point Union Again Challenges ISO-NE Auction.)

Energy Capital Partners, former owner of the 1,517-MW plant, did not offer it in capacity auctions for 2017/18 and 2018/19 after announcing the plant would close in 2017. Brayton Point was sold last year to Dynegy, which said it would close the plant as scheduled.

FERC previously rejected the union’s challenge to results of FCA 8 on similar grounds. FERC said a non-public investigation by its Office of Enforcement failed to uncover any evidence of wrongdoing.

“This conclusion remains valid for FCA 9,” FERC wrote.

The commission also reiterated its acceptance of the conclusion of ISO-NE’s Internal Market Monitor that no anti-competitive behavior existed before the auction.

FERC also rejected the union’s contention that the ISO-NE Tariff requires a determination that a unit is uneconomic before it is allowed to retire.

“The Tariff contains no provision requiring a resource to demonstrate that it is uneconomic before it is allowed to retire, and UWUA does not point to any such provision. There is no test as to whether the unit can economically provide capacity, nor is there a mechanism by which ISO-NE can compel the resource to continue operating under any circumstances,” the commission wrote.

— William Opalka

January 5, 2016

FERC Accepts Order 1000 Compliance Filing

FERC has accepted NYISO’s fourth Order 1000 compliance filing, turning aside the protests of transmission developers that claimed it unfairly favored incumbent transmission owners (ER13-102-007).

LS Power and NextEra had protested the ISO’s right to terminate development agreements if a force majeure event prevents a non-incumbent developer from completing its project by the in-service date. (See Tx Developers Challenge NYISO, SPP, ISO-NE Order 1000 Filings.)

NYISO and the New York Transmission Owners submitted their fourth Order 1000 compliance filing in May. It included a pro forma development agreement for NYISO’s reliability transmission planning process.

“NYISO argues that it must have the option to terminate the development agreement and identify alternative means of satisfying an identified reliability need if a developer cannot complete its project by the required project in-service date,” FERC wrote on Dec. 23.

The commission cited a similar provision at PJM, ordering NYISO to add comparable language in its development agreements with incumbent transmission owners to prevent discrimination.

In a second order Dec. 23, FERC rejected a NYISO filing that the commission said was unfair to competitive transmission developers (ER15-2059).

FERC said the proposal “subject[s] nonincumbent transmission developers to an interconnection process with different requirements than the interconnection process that applies to incumbent transmission owners.” While all interconnection customers are required to obtain system impact and facility studies, the nonincumbents were required under the proposal to additionally submit a feasibility study and deposits for all three studies.

NYISO had argued the incumbent would have already conducted a feasibility study in its normal planning process, but FERC said that would create two different processes that are not comparable.

— William Opalka

December 29, 2015

FERC Orders Tech Conference on PJM FTR Rule Changes

By Rich Heidorn Jr.

FERC on Monday ordered a technical conference to sort out conflicting claims over PJM’s proposed rule changes to reduce underfunding of financial transmission rights.

PJM’s proposed changes, filed in October, were challenged by the Financial Marketers Coalition and others, who said they would be ineffective and discriminatory. The commission said the conference was needed to develop more evidence before it rules (EL16-6-001, ER16-121).

The conference will explore PJM’s claim that its existing rules on FTRs and auction revenue rights are unjust and unreasonable and that the problems would be remedied by its proposed changes. Specifically, the conference will look at ARR modeling and allocation processes; treatment of portfolio positions in allocating underfunding or surplus among FTR holders; and the potential for market manipulation.

pjm — Crews install towers as part of Commonwealth Edison’s Grand Prairie Gateway project, which is expected to go into service in 2017. PJM said the need for the project might have been approved earlier under its proposed FTR rule changes.

An FTR entitles its holder to credits based on LMP differences in the day-ahead energy market when the transmission grid is congested. FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.

PJM improved funding under current rules by modeling more transmission outages, clearing more counterflow FTRs and improving its modeling of loop flow, the alignment of the FTR, day-ahead and real-time energy markets, and market-to-market coordination with MISO.

PJM said the changes raised FTR revenue adequacy from as low as 69% during planning years 2010/11 through 2013/14 to at least 110% since the 2014/15 planning period.

However, PJM said the changes resulted in an unfair shift of revenues from ARR holders to FTR holders. It said the load-serving entities receiving reduced Stage 1B ARRs are largely different from the LSEs receiving the over-allocation of infeasible Stage 1A (10-year) ARRs.

To correct the cost shift, PJM proposed eliminating the netting of negatively valued FTRs against positively valued FTRs within portfolios. It also proposed increasing current ARR results by 1.5% annually — equal to the average ARR 10-year growth rate since 2007 — in the Stage 1A 10-year simultaneous feasibility process. (See PJM to File FTR, ARR Rule Changes with FERC.)

PJM said the changes will increase the likelihood of infeasible ARRs, potentially identifying needed transmission upgrades such as Commonwealth Edison’s Grand Prairie Gateway project sooner. The 60-mile 345-kV line through four counties in northern Illinois began construction in the second quarter of 2015 and is expected to begin service in 2017. The company says it will allow the import of cheaper wind power from the west, saving customers about $250 million net of all costs within the first 15 years.

Commenters including utilities and the Independent Market Monitor told FERC they generally supported the proposed changes. But the Financial Marketers Coalition (representing DC Energy, Inertia Power, Saracen Energy East and Vitol), Shell Energy N.A. and others protested the elimination of netting, saying PJM failed to show the current rules are unjust and unreasonable and that the change would cure underfunding.

Without netting, the coalition argued, underfunding risks would shift to those that take on counterflow FTR obligations and could encourage market manipulation.

Opponents also questioned whether the proposed 1.5% escalation would be as effective in preventing ARR infeasibilities as claimed by PJM.

[Editor’s Note: An earlier version of this article mistakenly reported that J. Aron & Co. is a member of the Financial Marketers Coalition.]