Page 1536 – RTO Insider

January 6, 2015June 15, 2023

PJM, TOs Respond to Deficiency Notice on Multi-Driver Projects

By Suzanne Herel

Transmission-Owners-Proposed-Cost-Allocation-For-Incremental-Multi-Driver-Projects-(Source-PJM-RPPTF) — (Click to zoom)

PJM and its Transmission Owners filed a 65-page response Dec. 23 to address what the Federal Energy Regulatory Commission deemed deficiencies in their plan to integrate multi-driver projects into the regional transmission expansion plan (RTEP) (ER14-2864, ER14-2867).

PJM proposed the concept in response to FERC Order 1000, saying it could lower the cost of states’ public policy transmission projects by incorporating them in upgrades that address market efficiency or reliability.

Related revisions to PJM’s Operating Agreement and Tariff were approved by the Members Committee June 26 and filed with FERC Sept. 12, following much debate among stakeholders over what would qualify as such a project and who would pay for it. Some critics worried that the cost allocation scheme would make public policy projects too costly to pursue. (See States Still Miffed with TOs’ ‘Multi-Driver’ Cost.)

FERC’s deficiency notice focused on definitions, process and cost allocation.

Responding to FERC’s question of how such projects will be selected, PJM said, “In essence, there is no separate process for selection of multi-driver projects. … Consistent with Order No. 1000, all projects selected as multi-driver projects will be included in the RTEP for cost allocation purposes because they are found to be the more efficient or cost-effective solution to the PJM region’s needs.”

FERC had also asked PJM and the TOs to show how their cost allocation method satisfied the six regional allocation principles and how it is consistent with determining that participant funding cannot be the regional method.

PJM responded that a multi-driver project will be eligible for regional cost allocation because each component — economic, reliability and public policy — will meet the relevant requirements.

The TOs said that the costs would be allocated “to those who benefit from the facilities in a manner that is at least roughly commensurate with the estimated benefits.”

No new cost allocation method is being proposed for multi-driver projects, the TOs said, with the exception of local transmission projects “boosted” into regional cost allocation due to their combination with a public policy driver. For “boosted projects,” the portion of the project designed for reliability or market efficiency will be allocated 20% pro rata and 80% to those calculated to directly benefit, rather than 50-50.

“Even though the allocation to the reliability or market efficiency portion has changed by having 20% of those portions allocated pro rata, those who would not have received a cost allocation but for the ‘boosting’ of the project to a regional facility, still receive a benefit because of the greater capacity of the regional facility,” the TOs said.

Cost allocation would continue to be assigned by two methods: incremental and proportional.

The incremental method would be used when the project was developed to address a single driver, but modified to satisfy other goals and becomes more cost-effective for all drivers. The initial driver would have its cost share reduced by “an amount equal to the ratio of the estimated incremental cost of the new driver(s) to the estimated new total cost of the project multiplied by the estimated cost of the original driver.”

The proportional method would apply when a project was developed parallel to individual solutions to different drivers and then combined. In that case, cost would be allocated relative to what would have been required to address each driver separately.

Annual Cost Allocation Update Filed

In a related matter, PJM on Dec. 30 submitted its updated annual cost allocation for regional facilities and “necessary” lower-voltage facilities included in the RTEP (ER15-758).

January 6, 2015June 15, 2023

Federal Briefs

A dozen House Republicans asked the Federal Trade Commission to explore allegations of deceptive trade practices related to third-party solar leases.

Rep. Paul Gosar, R-Ariz., leading the effort, wrote a letter to FTC Chairwoman Edith Ramirez urging the commission to investigate “deceptive marketing strategies” that overpromise the benefits of home solar while understating the risks of entering into an agreement “that will likely exceed both the life of the roof and the duration of the lessor’s home ownership.” He characterized the booming third-party solar installation industry as “largely unregulated.”

“My letter to Chairwoman Ramirez simply asks the FTC to look into these practices and answer a series of questions,” Gosar said in a news release. “In order to protect consumers and expand domestic solar production, proper oversight of the emerging rooftop solar industry must be maintained.”

More: Rep. Paul Gosar; Daily Signal

FERC Approves Cheniere’s Corpus Christi LNG Terminal

The Federal Energy Regulatory Commission last week approved Cheniere Energy’s planned liquefied natural gas terminal in Corpus Christi, Texas. The company now needs only approval from the Department of Energy to start construction.

Cheniere is the only company in the U.S. to have two active LNG export terminal projects underway. Its $10 billion Sabine Pass terminal in Louisiana is already under construction and scheduled to go into operation later this year. Construction at the Corpus Christi terminal should start this year, with an operational date of 2018.

More: Houston Business Journal

Environmental Groups Charge FERC Erred in Approving NY Pipeline

Environmental groups are asking the Federal Energy Regulatory Commission to reconsider its December approval of the Constitution Pipeline, a proposed 124-mile natural gas pipeline that would run from Pennsylvania into New York.

The groups, including EarthJustice, the Clean Air Council and the Sierra Club, said FERC’s environmental review didn’t take into account habitat damage and runoff potential. “When the Federal Energy Regulatory Commission issues a permit for a natural gas pipeline without fully assessing the environmental impact as required, concerned citizens must take a stand,” said Moneen Nasmith, an EarthJustice attorney.

More: Akron Beacon Journal

Burns Takes Reins at NRC, Replacing Macfarlane

Stephen G. Burns became the chairman of the Nuclear Regulatory Commission on Jan. 1, assuming the seat held by Allison Macfarlane, who left to take a professorship at George Washington University.

Burns, the commission’s former general counsel, has held various positions at the NRC for more than 33 years, but he has only been a commissioner since November.

More: Nuclear Street

Duke Energy’s Dry Cask Storage Plan for Crystal River OK’d

The Nuclear Regulatory Commission has approved Duke Energy’s plan to use dry cask storage for spent fuel at its Crystal River Nuclear Plant in Florida.

Duke ordered the plant permanently shut down in 2013 after its previous owner, Progress Energy, botched repairs in 2009. The company estimates it will cost more than $265 million to build the fuel storage facility. The spent fuel rods are scheduled to be transferred in 2019.

More: Bay News 9

Republicans Asking FERC Commissioners About EPA Meetings on Clean Power Plan

Ranking House and Senate Republicans have asked each member of the Federal Energy Regulatory Commission to describe any meetings they had with the Environmental Protection Agency about the agency’s proposed Clean Energy Plan. The lawmakers suggest that commissioners had little interaction with the EPA before the agency released its new emissions standards. EPA officials have said there was sharing of information.

“Your views about the extent of collaboration between FERC and EPA on these matters, and especially about the details of your personal involvement or that of your staff in any or all of these meetings … will contribute significantly to the public record,” the legislators said in a letter.

It was signed by Sen. Lisa Murkowski (R-Alaska), ranking Republican on the Senate Energy and Natural Resources Committee, Rep. Fred Upton (R-Mich.), chairman of the House Energy and Commerce Committee, and Rep. Ed Whitfield (R-Ky.), chairman of the Energy and Power Subcommittee.

More: Bloomberg News

Comment Period on Offshore Wind in Virginia Extended 2 More Weeks

The Bureau of Ocean Energy Management has given a two-week extension for public comment on a pilot project to install two offshore wind turbines in Virginia.

The agency recently issued a 210-page environmental assessment on Dominion Virginia Power’s plan to install two 600-foot turbines and a sea-to-shore transmission line that would set the stage for a more ambitious offshore wind project. The deadline for comment is now Jan. 16.

More: The Virginian-Pilot

Colette Honorable Joins Commission

The Federal Energy Regulatory Commission announced yesterday that Colette Honorable has been sworn in as the commission’s fifth member, replacing former Commissioner John Norris. Honorable, former chairman of the Arkansas Public Service Commission and president of the National Association of Regulatory Utility Commissioners, was confirmed to the position by the Senate in December.

FERC Schedules Workshop on NERC ATC Rules

The staff of the Federal Energy Regulatory Commission will conduct a workshop March 5 to discuss actions the commission may take to ensure that transmission providers are calculating available transfer capability (ATC) “in a manner that ensures nondiscriminatory access” to the grid.

FERC’s action (AD15-5) is a response to the North American Electric Reliability Corp.’s proposed changes to its ATC-related reliability standards and an initiative to replace them with business practice standards to be developed by the North American Energy Standards Board. The workshop will be held from 8:45 a.m. to 5 p.m. in the Commission Meeting Room, 888 First Street NE, Washington, D.C., 20426.

January 6, 2015

No Penalty for MISO on Reliability Violations

By Rich Heidorn Jr.

MISO and reliability watchdogs have reached a settlement over self-reported violations related to MISO’s ability to maintain visibility over its reliability coordinator area following a contingency event.

The settlement, between MISO and regional entity ReliabilityFirst, was submitted to the Federal Energy Regulatory Commission Dec. 30 by the North American Electric Reliability Corp. (NP15-14). While MISO will not pay a financial penalty, it agreed to corrective actions.

MISO said it discovered in March 2012 that some of the input data it used in the network model to support real-time analysis of its transmission system was incorrect: for 321 of 19,936 facilities (1.6%), default facility ratings, instead of actual facility ratings, were assigned.

MISO also identified errors in voltage monitoring flags for several facilities and that several transmission lines had monitoring disabled. In addition, alarms on six tie lines were not functioning and the network model failed to monitor 14 transformers.

Another violation resulted from MISO’s discovery that it had only limited ability to determine current post-contingency element conditions (voltage or thermal) within its reliability coordinator area for almost six hours on Jan. 30, 2013.

The problem occurred when a MISO Energy Management System shift engineer implemented a corrupted contingency case file, resulting in 2,626 contingencies being excluded from the real-time contingency analysis database. MISO typically screens for about 11,400 active contingencies.

Alarms Not Heard

“Although MISO has audible alarming to alert control room personnel to significant changes in the number of contingencies in the real-time contingency analysis database, the control room personnel failed to notice the alarm due to other audible alarms sounding at the same time,” NERC said.

The problem was discovered after a transmission operator notified MISO of a trip on one of its transmission lines resulting in new post-contingency overloads on several 69-kV lines.

The settlement resolves violations related to MISO’s operations in the ReliabilityFirst, Midwest Reliability Organization and SERC Reliability Corp. regions.

The regions said the violations did not affect MISO’s processes to identify and validate System Operating Limits (SOLs) and Interconnection Reliability Operating Limits (IROLs), respond to real-time system conditions, or produce next-day models. “Considered as a whole, the regions determined these violations posed a minimal risk to the reliability of the bulk power system,” NERC said.

Penalty Recovery Sought

In a related matter, MISO last week asked FERC for authority to recover from its members a $75,000 penalty arising from a settlement agreement with ReliabilityFirst over earlier reliability violations (ER15-764). The settlement, which was previously approved by FERC, resulted from a compliance audit conducted in late 2012.

January 6, 2015June 15, 2023

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