MISO, Generators Oppose Duke Must-Offer Waiver Bid

By Chris O’Malley

MISO and three power suppliers have asked the Federal Energy Regulatory Commission to deny Duke Energy’s request for a waiver from MISO’s must-offer requirement, arguing the RTO’s reserve margins in Zone 6 have fallen by a “dramatic” amount since Indianapolis Power & Light obtained a waiver in October.

Duke Energy Indiana is the latest utility to seek a must-offer waiver (ER15-592), joining others that complain there’s no clear mechanism within MISO’s Tariff that would permit them to buy replacement capacity to cover a six-week gap in 2016 between when they plan to retire coal units under the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) and the end of the MISO planning year on May 31.

Requests by DTE Electric (ER15-90) and MidAmerican Energy (ER15-199) are pending before the commission. Consumers Energy, having been denied a waiver request last fall (ER14-2622), has come back to the commission with a modified request (ER15-435).

Duke told the commission that buying replacement capacity for its Wabash Units 2-6 for the six-week period could cost up to $17.7 million. Consumers said buying replacement power for the 2015-2016 planning year would cost $5.8 million to $84.8 million.

In a Dec. 29 filing opposing Duke’s request, MISO said the waiver requests have grown to 2,440 MW.

“It is very difficult to understand how these accumulated waiver requests are limited in scope and will not have a great potential for undesirable consequences. Moreover, a large number of pending requests creates additional regulatory uncertainty among buyers and sellers of capacity and hinders the efficiency of MISO’s capacity construct,” MISO said.

Dynegy, NRG Energy and Exelon also opposed Duke’s request, arguing that MISO’s reserve margins have suffered a “dramatic” fall since IPL’s June 2014 request. IPL cited an “available maintenance” of a minimum 3,000 MW in Zone 6 for the April-May 2016 period.

“By contrast, [Duke Indiana] acknowledges that ‘MISO’s updated monthly Maintenance Margins’ now show a low of 738 MW,’” the companies said in a Dec. 29 protest. “This is a razor-thin margin in a zone with forecasted demand of 17,629 MW.”

Pandora’s Box?

FERC Commissioner Norman Bay had warned that the number of waivers would grow last October when he dissented in the IPL decision. (See IPL Wins Waiver from MISO Must-Offer Rule for Retiring Eagle Valley Units.)

Bay warned that a one-time waiver “creates an unfortunate precedent that erodes MISO’s capacity construct, undermines the bilateral market for capacity and blurs, unnecessarily, a line that had once been bright.”

MISO used a monthly resource adequacy construct until 2012, when the RTO won FERC approval for an annual construct, saying the monthly capacity products might not provide the certainty to attract competitive participants to the auction. The change meant that capacity resources would be required to be available anytime during the planning year.

That became problematic when utilities began making plans to retire older units to comply with MATS. Duke Indiana decided that in 2016 it would retire Wabash Units 2-5 and suspend Unit 6.

Duke argues that it essentially faces the same situation that confronted IPL, which plans to retire its Eagle Valley coal units in 2016 as part of MATS compliance.

Duke Leaves Bigger Void

But suppliers noted that Duke’s 668-MW Wabash units are considerably larger than Eagle Valley’s 216-MW capacity.

In November, the commission rejected Consumers Energy’s initial request for a waiver of its Classic Seven units, noting they comprise 940.7 MW in Michigan, 14.5% of the utility’s total capacity.

As for Duke’s must-offer waiver request, the three suppliers told FERC that while the Eagle Valley plant represents about 1.2% of total demand forecast for MISO’s Zone 6, the combination of Eagle Valley and Wabash River Units 2-6 “would now represent 5% of the total demand forecast in that zone.”

January 6, 2015June 15, 2023

FERC Report Shows Spotty Growth for Demand Response, Advanced Meters

By William Opalka

Demand response and advanced meters are continuing to grow but progress is uneven, with some regions showing reductions in DR even before last May’s appellate court ruling challenging federal jurisdiction over the resource, according to a new report by the Federal Energy Regulatory Commission.

Nationally, potential peak reduction from DR in the organized markets grew 9.3%, or 2,451 MW, to 28,503 MW from 2012 to 2013. Potential peak reduction in RTOs and ISOs grew to 6.1% of peak demand in 2013, from 5.6% in 2012.

This occurred despite some setbacks in Northeastern markets, according to the ninth annual Assessment of Demand Response and Advanced Metering report released Dec. 23.

FERC also reported that advanced meters now represent almost 30% of the total, as an additional 5.9 million devices were deployed between 2011 and 2012.

Demand Response in RTOs, ISOs

Potential peak reduction increased by 2,600 MW in MISO from 2012 to 2013, largely due to increased demand response from behind-the-meter generation and load-modifying resource programs run by utilities.

In NYISO, however, fewer DR resources registered as special case resources following the RTO’s implementation of its baseline calculation and auditing methods, according to FERC. Tighter qualification criteria may have played a role. Relatively low capacity prices in NYISO were also cited.

DR in ISO-NE declined by 669 MW, or 25%. FERC cited reports that EnerNOC had reduced its participation in the forward capacity market because its customers believe that participation requirements outweighed the benefits.

DR’s future was further clouded by the D.C. Circuit Court of Appeals’ ruling, in a challenge by the Electric Power Supply Association, voiding FERC’s jurisdiction over pricing of DR in wholesale energy markets. FERC is seeking a Supreme Court review of the ruling.

Some have argued that the legal theory advanced in the EPSA ruling should bar DR participation in capacity markets. (See PJM to File Post-EPSA Demand Response Contingency Plan with FERC.)

Demand Response in Emergencies

Despite the legal uncertainties, demand response continued to prove its worth last year as a tool for grid operators during times of tight supplies, FERC observed. PJM activated about 2,000 MW of DR for several hours on Jan. 7, 2014 and more than 2,500 MW for several hours on Jan. 23 and Jan. 28.

ISO-NE’s 2013-2014 Winter Reliability Program gave it the ability to call on DR up to 10 times during the winter. DR resources provided 21 MW on each of five occasions between December 2013 and February 2014, according to the report.

Advanced Meters

Advanced meters continued to grow, but penetration rates varied widely by region.

The Texas Regional Entity leads, with penetration of 70%, followed by the Western Electric Coordinating Council at 51%. Bringing up the rear are ReliabilityFirst, which includes portions of PJM and MISO, at 17%, and the Northeast Power Coordinating Council at 12%.

Among the capabilities of advanced meters is time-based pricing. But the report found that enrollment in time-based DR programs dropped by 6.1% between 2011 and 2012.

FERC said participation dropped in SPP due to the end of programs by Southwestern Electric Power Co. and a large decline in enrollment in the programs run by Public Service Company of Oklahoma. The ReliabilityFirst region saw a decline as a result of attrition in Ohio Power’s residential program and Duke Energy Indiana’s commercial program.

January 6, 2015June 15, 2023

Two More Indiana Wind Farms Join NIPSCO Complaint over Tx Upgrades

By Michael Brooks

Two of the world’s largest wind farms have joined a complaint against Northern Indiana Public Service Co., asking the Federal Energy Regulatory Commission to cut the $35.8 million bill the utility assessed them and others in connection with transmission upgrades needed to reduce congestion that has caused frequent curtailments.

NIPSCO charged Fowler Ridge, Meadow Lake and seven other wind farms $50.4 million to build the upgrades and an additional $35.8 million to operate them over 35 years.

FERC ruled Dec. 8 that the 1.71 multiplier NIPSCO used to calculate the operating costs is too high. But it denied a request by the original complainant, E.ON Climate and Renewables North America, to eliminate it entirely. Instead, it directed NIPSCO and E.ON to enter settlement proceedings to determine a fairer rate (EL14-66).

The owners of the Fowler Ridge and Meadow Lake wind farms, located in western Indiana, filed their complaint last week (EL15-34), saying they wanted to ensure they would share in any refunds resulting from the resolution of the E.ON case.

Fowler Ridge and Meadow Lake companies were part of a group of Indiana wind farm owners that negotiated last year with NIPSCO a transmission upgrade agreement to alleviate congestion on the utility’s system.

E.ON estimated its Pioneer Trail and Settlers Trail wind farms, with 300 MW of combined capacity, lost between $9.8 million and $11.7 million in 2013 when grid operators forced them to curtail their output due to congestion.

Because MISO’s Tariff does not include a procedure for calculating the cost of transmission upgrades that require customer funding, the RTO instructed the wind companies to deal with NIPSCO directly.

E.ON said it immediately objected to the operating cost multiplier but that both MISO and NIPSCO refused to file the agreement on an unexecuted basis — an action that would have allowed FERC to rule on it before it went into effect. NIPSCO also refused to go through with the upgrades unless E.ON and the other companies signed the agreement and paid the total cost upfront, E.ON said.

“[G]iven the continuing curtailments, the only avenue was to agree to the terms of the proposed” agreement and hope that FERC would find it unjust once it was filed in February 2014, E.On said. FERC accepted the agreement in late March, and E.ON filed its complaint in June.

The 600-MW Fowler Ridge, jointly owned by BP Wind Energy North America and Dominion Resources, and the 526-MW Meadow Lake, owned by EDP Renewables North America, rank among the largest wind farms in installed capacity. Collectively they make up 73% of Indiana’s total wind capacity, according the U.S. Department of Energy.

January 6, 2015

FERC Approves $3.5M Settlement with Twin Cities Power over Manipulation

By Michael Brooks

Twin Cities Power will pay $2.5 million in penalties and disgorge almost $1 million in profits for manipulating energy prices in MISO under a settlement approved by the Federal Energy Regulatory Commission last week (IN12-2).

Twin Cities admitted the violations, while the three traders accused in the case neither admitted nor denied wrongdoing, FERC said. Traders Jason Vaccaro, Allan Cho and Gaurav Sharma did agree to pay civil penalties of $400,000, $275,000 and $75,000 respectively. They also agreed to bans from energy trading: Vaccaro for five years, and Cho and Sharma for four years each.

FERC said that while Twin Cities traded and scheduled power in MISO, it also traded financial products on Intercontinental Exchange, including the MISO Cinergy Hub Balance-of-Day Swap (Bal-Day-Cin).

“Twin Cities engaged in a consistent pattern of flowing physical power in the direction of its financial swaps. Twin Cities imported power into MISO when it held a short swap position, or exported power from MISO when it held a long swap position,” FERC said. “Moreover, Twin Cities’ financial positions were larger than its physical positions, such that the increase in the value of Twin Cities’ swaps exceeded the losses from its physical flows.” This showed that Twin Cities was moving energy prices to benefit their swaps, FERC said.

The three traders worked for Twin Cities Power Canada, a Twin Cities subsidiary in Calgary that ended operations in September 2012. At first, the company’s only employees were Cho as president and Vaccaro as vice president. At the time of the violations, the company employed 11 traders, including Sharma. On Feb. 1, 2011, several months prior to FERC’s investigation, Cho, Vaccaro and Sharma were fired.

The penalty is higher than most FERC approved in fiscal year 2014. It is the second penalty approved in fiscal year 2015, after CAISO agreed to pay $2 million for reliability violations related to the 2011 Southwest blackout.

January 6, 2015June 15, 2023

Vermont Yankee Retirement Leaves ISO-NE More Dependent on Gas

By William Opalka

Entergy powered down the Vermont Yankee nuclear station for the final time last week, leaving ISO-NE even more dependent on natural gas as it also faces retirements of its coal-fired generation.

The 615-MW plant in Vernon, Vt., which went on line in 1972, retired Dec. 29 after a protracted battle with state government and environmentalists.

Marcia Blomberg, a spokeswoman for ISO-NE, said that a 2012 study concluded that New England would have enough generation without the plant.

“But the loss of other non-natural gas generation throughout the region is causing concern about long-term reliability,” she said. “This generation is most likely to be replaced by natural gas, which will only exacerbate our dependence on that resource.”

The nuclear plant’s loss has been compounded by other recent and planned closures in New England. The 352-MW Norwalk Generating Station in Connecticut closed in 2013 and the 720-MW Salem Harbor Generating Station in Massachusetts shut down last spring. The 1,557-MW Brayton Point plant in Massachusetts is scheduled to retire in 2017.

New England now gets about half of its generation from natural gas, meaning generators are increasingly competing against heating load for gas in a region with limited pipeline capacity.

The switch to natural gas was what led to Vermont Yankee’s closure, according to Entergy. In its August 2013 announcement of the plant’s demise, it cited “a transformational shift in supply due to the impacts of shale gas, resulting in sustained low natural gas prices and wholesale energy prices.”

It also cited Vermont Yankee’s high cost structure and the costs of regulatory compliance on a small plant. Decommissioning is expected to last decades and cost more than $1.2 billion.

The plant employed more than 600 people with about one-half of those retiring or laid off by Jan. 19. Entergy will provide $10 million in economic development aid for Windham County over five years and $5.2 million in clean-energy development funds.

Entergy’s decision accomplished what state officials and environmentalists were unable to do.

Vermont passed legislation to force the plant’s closure, but Entergy successfully challenged that move in federal court. The court ruled the state lacked jurisdiction, as nuclear power was primarily licensed and regulated by the federal government.

January 6, 2015

PJM’s Offer Cap Proposal Sparks Opposition

By Suzanne Herel

PJM’s request to raise the cost-based energy cap to $1,800/MWh through March (EL15-31) drew a flurry of comments and protests in the days before the Christmas holidays.

Load representatives generally opposed the proposal, warning it could result in windfalls to generators at ratepayers’ expense. Suppliers told FERC that PJM’s proposal didn’t go far enough and that marginal costs more than $1,800 should be able to set market-clearing prices. Other commenters offered limited support for the idea, suggesting tweaks to the language or recommending that FERC simply extend the waiver it granted last year to allow gas-fired generators to cover their costs.

The proposal to boost the cap from $1,000/MWh — prompted by natural gas price spikes last winter — was made in a Section 206 filing to the Federal Energy Regulation Commission after members failed to reach consensus over the past eight months. (See PJM Board to Seek $1,800 Offer Cap.)

Load: ‘Profit Opportunities’

The PJM Load Group — consumer advocates and state regulators for West Virginia, Delaware, Illinois, Maryland, New Jersey and D.C., along with several other load-serving entities and groups representing load – was among those who urged FERC to reject PJM’s proposal outright. If the cap is raised, the group wants payments in excess of $1,000/MWh refunded to ratepayers through a credit against capacity charges.

The Pennsylvania Public Utility Commission said a higher cap is unnecessary, saying “other equally effective mechanisms exist to address the issue of unexpected spikes in fuel costs or other weather-related events.”

Likewise, the Maryland Public Service Commission rejected the proposal, saying, “It is clear that the purpose is to create profit opportunities for generators whose costs do not exceed the offer cap.”

Suppliers: Too Late, Too Little

The PJM Power Providers Group said PJM should have filed much earlier than it did, on Dec. 15, noting that last year’s polar vortex struck in the first week of January. “This filing leaves PJM and the commission exposed to the same ‘relative frenzy’ that both PJM and the commission experienced last winter,” the group said.

While the group agreed the current tariff is unreasonable, it said, “The proposed $1,800/MWh is not supported by any evidence. PJM appears to pick a number out of thin air with the only justification being that the number was part of a failed stakeholder compromise that was never voted upon by the PJM stakeholders.”

It suggested the commission set PJM’s filing for a paper hearing and establish procedures to develop an “appropriate energy market offer cap” by Aug. 1, in time for next winter.

PPL said PJM’s compromise — limiting offers that may set LMPs to $1,800/MWh and providing compensation for marginal costs above that through uplift payments — is “bad policy.”

“The proposal departs unreasonably from past commission and court precedent and from sound economic theory, sound principles of market design and PJM’s own expressed views as to the benefits of an LMP-based system and the harmful effects of payments needlessly being made via uplift,” PPL said.

Public Service Enterprise Group agreed that capacity resources should be able to bid their marginal costs into the market and set price.

It also called on FERC to prevent seams issues among neighboring markets with different policies, saying the commission should order PJM to adopt rules allowing generators to update their offers on an hourly basis to reflect real-time fuel costs. “Given the overwhelming benefits of hourly reoffers, we respectfully request that FERC direct PJM to begin a stakeholder process to develop rules similar to those already implemented in New York and New England,” PSEG said.

Coordination of comparable offer caps also was the concern of NYISO. “Offer caps must be discussed at a regional level in order for all interested parties to evaluate the potential for seams issues that could arise from different offer caps. … Materially different offer caps in neighboring regions that depend on the same natural gas supply could require operator actions to avoid electric system reliability impacts during periods of cold weather and high gas prices. NYISO is concerned that a number of markets in the Mid-Atlantic and Northeast are competing for the same supply of gas and generators subject to lower offer caps could be denied access to fuel.”

PJM CEO Terry Boston said last month he is seeking to reach a consensus with the RTO’s neighbors on a common offer cap. (See PJM Seeking RTO Consensus on Offer Cap Increase.)

Monitor Suggests Changes

Independent Market Monitor Joe Bowring expressed general support for the proposal, but he challenged some of the details, saying the highest valid cost-based offer the Monitor reviewed last winter was less than $1,500, not the $1,724/MWh cited by PJM.

He also advised that because it was natural gas spikes that prompted the filing, the cap should be restricted specifically to the cost to procure gas.

Bowring also expressed concern that the proposal not affect the maximum system scarcity price. “PJM does not explain what would happen if cost-based offers between $1,000 and $1,800 [were] applied during scarcity conditions,” he said. “The Market Monitor requests clarification that the maximum price would never be greater than the current maximum scarcity price even if cost-based offers exceed $1,000/MWh.”

January 6, 2015June 15, 2023

Company Briefs

Xcel Energy, already a top U.S. producer of wind energy, announced plans to vastly increase its renewable generation by 2030 and cut its use of fossil-fired generation.

The goals, included in its “2016-2030 Upper Midwest Integrated Resource Plan” filed with the Minnesota Public Utilities Commission, call for a 30% reduction in carbon emissions by 2020 and a 40% reduction by 2030.

The company plans to add 600 MW of wind energy to its portfolio by 2020 and 1,200 MW by 2030, bringing its total to 3,600 MW. It also plans to add nearly 2,400 MW of solar by 2030, maintain operations of its Monticello and Prairie Island nuclear plants, and reduce reliance on its coal-fired Sherburne County Generating Plant.

More: Star-Tribune

Entergy Adds New CCGT Plant to Louisiana Generation Fleet

Entergy Louisiana has added its first new power plant to its fleet in nearly 30 years. The Ninemile 6 combined-cycle gas turbine plant in Westwego was completed for an estimated $566 million, on time and below budget, the company said. Entergy Gulf States Louisiana and Entergy New Orleans will buy 45% of the 560-MW plant’s output.

Entergy also announced recently its subsidiaries will spend $948 million to acquire the 1,980-MW gas-fired Union Power Station in El Dorado, Ark. The Union Power Station is owned by Union Power Partners, an independent power producer owned by Entegra TC. Both companies filed for Chapter 11 bankruptcy protection in August. Entergy said the plant’s price was about half what it would cost to build a new power plant.

More: PennEnergy; The Times-Picayune

PSEG Taking over Completed Solar Plant in Waldorf, Md.

PSEG Solar Source is acquiring a 12.9-MW solar facility near Waldorf, Md., its 11th utility-scale photovoltaic project. It brings PSEG Solar’s total capacity to 123 MW.

The facility is being constructed by juwi solar and has a 20-year power purchase agreement with Southern Maryland Electric Cooperative. Construction is expected to be completed by June. Terms of the sale were not announced.

More: NJBiz

AEP Blitzing Ohio with 105,000 Automated Meters

American Electric Power will install 105,000 automated meters in Ohio, the third phase of its meter updating program.

The wireless meters will only allow the utility to take readings from a passing vehicle, unlike smart meters, which can both send and receive signals and allow two-way communication about electricity usage. With the new program, nearly a third of AEP’s 1.5 million Ohio customers will have the automated meters, which eliminate the need for a manual reading and should cut down on the number of estimated bills.

AEP has also proposed to increase the size of its smart meter program, which is currently still in the pilot stage.

More: The Columbus Dispatch

UGI Energy to Build $150 Million Gas Pipeline to Power Plant

UGI Energy Services plans to spend $150 million to build a 20-inch pipeline to deliver natural gas to a proposed generating station near Shamokin Dam on the Susquehanna River in Pennsylvania.

The 35-mile line, which would cross five counties, would connect the Transcontinental Pipeline to the power plant. The company said about 90% of the gas will go to the power plant.

The proposed 1,000-MW power plant, called Hummel Station, will be owned by Sunbury Generation and is slated to go on line in 2017. Sunbury recently retired a coal-fired generating station at the 216-acre site. The former PPL plant still has active oil-fired units on site.

More: PennLive

Dominion Buys 20-MW Solar Plant in Calif. from EDF

Dominion Resources added 20 MW of solar capacity to its fleet with the purchase of a facility in King’s County, Calif., from EDF Renewable Energy. Dominion now has 344 MW of solar either in operation or under construction in California, Connecticut, Georgia, Indiana, Utah and Tennessee.

The announcement comes after the company said it bought a 50-MW solar project in Millard County, Utah, from juwi solar. That purchase came just two months after Dominion purchased two other solar plants, the 24-MW Cottonwood and the 12-MW Catalina Solar 2 facilities. Both of those California plants were purchased from EDF as well.

More: Zacks

Asheville, NC, Demand Spurs Duke to Build 3 New Substations

Duke Energy has spent $13.6 million to buy three sites for new substations in Asheville, N.C., in order to bolster the company’s distribution system as demand grows in the western North Carolina city. The new substations will be the first in the city in 40 years.

Duke said it plans to open the first new substation by 2018. It did not release cost estimates for the project.

More: Asheville Citizen-Times

FirstEnergy Spending $100 Million on Shale Gas-Related Tx Projects

FirstEnergy said it is investing about $100 million on transmission lines and related projects in West Virginia to support industrial activity to process shale gas and oil, as well as power pumping and compression equipment to send shale-related energy to markets.

Substations, transmission lines and other equipment are included in the list, the company said. Projects include a $52 million 138-kV line to support demand in Doddridge, Harrison and Ritchie counties, and an 18-mile, $55 million 138-kV line expected to go into service near Oak Mound in late 2015.

More: The State Journal

January 6, 2015June 15, 2023

PJM Seeks Waiver on Capacity Release

PJM wants a one-time waiver to avoid releasing 2,000 MW of capacity for the 2015/16 delivery year, when the RTO fears it may run short of resources due to retirements of coal-fired generation.

PJM officials told the Markets and Reliability Committee Dec. 18 that they would seek to postpone generation retirements — or accelerate planned new generation — to help the RTO ride through potential shortages next winter. (See PJM Seeks to Postpone Some Generation Retirements through 2015/16.)

On Dec. 24, PJM made two filings with the Federal Energy Regulatory Commission to put its plan in action.

In one, PJM asked for a one-time waiver on rules that would otherwise require it to release 2,000 MW of capacity in the Feb. 23 Third Incremental Auction for 2015/16 (ER15-738).

In the second, PJM proposed revising its Tariff to allow it to enter into capacity agreements made outside the Reliability Pricing Model auctions (ER15-739).

Officials told the MRC they would seek to forestall some of the estimated 9,500 MW of retirements expected next year as a result of the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) and more than 2,000 MW being shut down by New Jersey’s High Energy Demand Day regulations.

In addition to offering reliability-must-run (RMR) compensation to delay retirements, officials said they are considering incentives to encourage some generation slated to come on line in delivery year 2016/17 to accelerate construction and launch earlier. In total, officials said they will attempt to secure as much as 2,500 MW of generation through April 2016.

In a related matter, PJM released its 2015 load forecast report. It includes a 2.6% reduction in the load forecast for 2018, due in part to a temporary change in modeling that aims to address over-forecasting in recent years. (See Model Change Results in Lower Load Forecast for PJM.)

January 6, 2015June 15, 2023

2014 Year in Review

The big news of 2014 in PJM was the same subject that’s likely to be big news in 2015: the capacity market.

Of RTO Insider’s 25 most-read stories of 2014, seven were about PJM capacity market rule changes or the results of the May Base Residual Auction.

With PJM seeking to overhaul the market with its Capacity Performance proposal — now pending before the Federal Energy Regulatory Commission — capacity issues are sure to be among the top stories for RTO Insider in the coming year. (See PJM Files Capacity Performance Plan.)

Speaking of FERC, four stories about FERC enforcement and commissioner confirmations also ranked in the top 25. The dynamics of the five-member commission will be fascinating to watch in 2015, with the arrival of new commissioner Colette Honorable and Chairman Cheryl LaFleur and Commissioner Norman Bay swapping seats in April. (See stories No. 2 and No. 18 below.)

DR, M&A, EPA

Demand response, mergers and acquisitions, Environmental Protection Agency regulations and the Artificial Island stability fix each claimed two spots on the list.

The EPA will be the subject of much coverage this year as its Mercury and Air Toxics Standards (MATS) force thousands of megawatts of coal-fired generation into retirement, and as it finalizes its carbon emissions rule in June. Legal challenges to the rule, which have already begun, will surely increase traffic at the D.C. Circuit Court of Appeals.

It was that court that roiled the demand response industry last year with a ruling voiding FERC jurisdiction over pricing of DR in wholesale energy markets, a decision FERC is hoping the Supreme Court will reconsider. (See related story, FERC Report Shows Spotty Growth for DR, Advanced Meters.)

The mergers and acquisitions that were big news in 2014 also will generate headlines this year as they make their way through the regulatory approval process. Among the most prominent: PPL’s spin-off of its generation in a combination with Riverstone Holdings; Exelon’s purchase of Pepco Holdings Inc.; Wisconsin Energy’s acquisition of Integrys Energy Group (with Exelon taking on Integrys’ retail power and gas subsidiary); Dynegy’s acquisition of generation from Duke Energy and Energy Capital Partners; and Constellation combining its commercial and industrial demand response business with Comverge.

PJM had hoped that the selection of a transmission developer for the Artificial Island fix — its first competitive transmission project under FERC Order 1000 — would be completed last summer. But controversy over PJM planners’ selection of Public Service Electric and Gas led the PJM Board of Managers to reopen the bidding for four finalists. Planners hope to present a final recommendation to the Transmission Expansion Advisory Committee in a few weeks. (See PSEG Nuclear Calls on PJM Board to Block ‘Risky’ Artificial Island Fix.)

RTO Insider’s Expansion

While we’ll be writing about a lot of the same issues in 2015, we’ll be doing so with an expanded reporting staff and geographic focus as we deepen our coverage in MISO, SPP, NYISO and ISO-NE.

With this issue, we are expanding our state briefs column to include the 11 MISO states not shared with PJM. Welcome to Arkansas, Louisiana, Mississippi, Missouri, Texas, Iowa, Minnesota, Montana, Wisconsin and the Dakotas — both of them!

Ten of those states are also shared by SPP. We’ll be adding the four states in the rest of SPP’s footprint, along with New York and the states in ISO-NE, later this year.

Welcome to Cruthirds Report Readers

We’ll be doing it with a much larger audience, thanks to our agreement to supply the unexpired subscriptions of The Cruthirds Report. Sadly, The Cruthirds Report ceased operations in December after 11 years of covering Entergy, Southern Co. and the electric industry in the Southeast.

Happily, its founder, former Dynegy regulatory attorney David L. Cruthirds, has agreed to continue raising hell with his observations as a columnist for RTO Insider. You’ll see his introductory column on page 1 of today’s issue.

David also will be writing from the Louisiana Public Service Commission’s monthly Business & Executive meeting in Baton Rouge on Jan. 21 and the Gulf Coast Power Association’s one-day briefing on “Challenges & Changes in Energy on the Bayou” in New Orleans on Feb. 5. The GCPA event will include a discussion on how the MISO South market has worked in the first year and what challenges lie ahead.

David is an outspoken advocate for competition, fairness and transparency. You may not agree with David’s opinions, but you’ll never have a question about where he stands.

We are thrilled to add David’s voice and loyal readers as we continue to build RTO Insider as your eyes and ears in the organized electric markets. Whether it happens in Valley Forge, Washington, Albany or Carmel — RTO Insider will be there bringing you exclusive “in the room” coverage.

Thanks for your support in 2014. Here’s to a great 2015!

Rich Heidorn Jr. and Merry Eisner

RTO Insider’s Top 25 Most-Read Stories of 2014

1	Capacity Prices Jump Following Rule Changes	5/27/2014
2	Analysis: LaFleur Cruises, Bay Bruises in Confirmation Hearing	5/21/2014
3	Court Throws Out Demand Response Rule	5/23/2014
4	How Exelon Won by Losing	6/3/2014
5	Capacity Prices Double in Western PJM, Flat in East	5/23/2014
6	States, not FERC, will be Challenge for Exelon-Pepco	5/2/2014
7	Monitor Suggests Price Gouging by Generators	5/20/2014
8	PSE&G Wins $300M Artificial Island Project	6/16/2014
9	Carbon Rule Falls Unevenly on PJM States	6/3/2014
10	PJM Trader Calls FERC on Manipulation Probe	3/3/2014
11	Billions at Stake in Capacity Market Challenge	4/22/2014
12	Rebound? Gens See Modest Price Boost as Auction Opens	5/12/2014
13	Who’s to Blame for Negative Prices?	4/22/2014
14	AES: Buyer’s Remorse on DPL Acquisition	3/14/2014
15	Cooling Water Rule: 7,000 MW Lost in PJM?	5/20/2014
16	Tiny Hydro Projects Joining Generation Mix in PJM	4/22/2014
17	Dominion, PSE&G Proposals Gain in Artificial Island Race	5/20/2014
18	LaFleur to Remain Acting FERC Chair for up to 1 Year in Senate Deal	6/18/2014
19	Members Committee Meeting Preview	5/12/2014
20	Rule Changes Clarify Synch Reserve Aggregation	4/15/2014
21	UTC Inquiry Moves Ahead	1/14/2014
22	Load Balks at Supply Curve Fix in Response to Auction Strategies	6/10/2014
23	FERC, CFTC Reject Due Process Complaints	4/15/2014
24	PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings	5/12/2014
25	PJM Cuts Voltage, Dispatches DR in Arctic Blast	1/7/2014

January 6, 2015

FERC Rejects Bid to Increase DR, Distributed Generation in ISO-NE Capacity Calculations

The Federal Energy Regulatory Commission Friday rejected a challenge by New England states to recalculate the contributions of demand response and distributed resources in advance of February’s Forward Capacity Auction.

FERC accepted the installed capacity requirement (ICR) filed by ISO-NE for the 2018/19 delivery year (ER15-325). However, FERC did order the RTO to conduct a stakeholder process to develop market rules that would consider DR in time for the 2016 FCA.

The New England States Committee on Electricity said ISO-NE has underestimated the impact of distributed generation and its pay-for-performance (PFP) program on the region’s capacity needs. FERC disagreed.

“We agree with ISO-NE that it would have no basis to use forecasted performance data in the absence of actual historical performance under this nascent two-settlement market design. We therefore support ISO-NE’s current methodology, which incorporates actual resource performance data,” FERC said.

FERC also suggested that a request to include distributed generation as part of the calculation was too soon, saying that the RTO first “must examine the market and operational issues.”

ISO-NE’s Nov. 4 filing established its ICR, local sourcing requirements and Hydro-Quebec interconnection capability credits (HQICC) for FCA 9.

The ISO proposed an ICR value of 35,142 MW, which includes 1,970 MW of emergency generation assumed obtainable from New Brunswick, New York and Quebec. The net amount of capacity to be purchased, after deducting the HQICC value of 953 MW per month, is 34,189 MW, the ISO said.