Page 1540 – RTO Insider

December 23, 2014

FERC OKs 2018 Entergy System Agreement Exit

By Chris O’Malley

The Federal Energy Regulatory Commission last week conditionally accepted Entergy’s request to terminate the system agreement for its Gulf Coast operating companies beginning in 2018, but it ordered a hearing and settlement proceedings to consider the concerns of regulators in Texas and Louisiana (ER14-75 et al).

The system agreement among Entergy and its operating companies has been the basis for planning and operating its generation and transmission facilities as a single system since 1951.

After Entergy’s April 2011 announcement that it would join MISO, the Public Utility Commission of Texas said the benefits of joining the RTO would be diminished by Entergy Texas’ continued participation in the agreement and called for terminating it sooner than the eight-year notice period required by the pact. Texas regulators argued that Entergy would need no more than three years to achieve operational readiness to participate in MISO’s capacity markets.

Entergy responded by asking FERC permission for a five-year exit. For Entergy Texas that would be in October 2018; for Entergy Louisiana and Entergy Gulf States Louisiana, the withdrawal would be effective in February 2019. (Entergy Arkansas withdrew from the system agreement in December 2013; Entergy Mississippi’s withdrawal is effective in November 2015.)

The company said the original eight-year notice requirement was based on the time frame for constructing a new coal-fired generating plant. It said a five-year notice was now sufficient because that is enough time to plan and build a new gas combined-cycle unit and that the MISO capacity market provides a “backstop” for any shortfalls.

The New Orleans City Council balked, saying that it was uncertain whether all of Entergy’s operating companies would join MISO. It also said five years might not be enough to plan new generation, citing delays in the development of Entergy’s Ninemile Point Unit 6.

The Louisiana Public Service Commission, meanwhile, called for a new “modern, comprehensive tariff” addressing planning and operation of the Entergy system in the MISO market, saying it is improper for Entergy to continue operating under an “anachronistic” agreement developed before RTOs existed.

Louisiana asked FERC to consolidate proceedings concerning the notice question with dockets ER13-432 and ER14-73, which involve revisions to the system agreement related to Entergy’s entry into MISO.

The commission rejected the consolidation request, saying the factual and legal issues were too disparate to combine in a single docket.

FERC did agree to combine the six notice dockets, and it ordered appointment of a settlement judge within 15 days. If the parties cannot reach a settlement, FERC said, the case will go to a public hearing to resolve the factual disputes.

Entergy has more than 2.8 million customers in Arkansas, Louisiana, Mississippi and Texas.

December 23, 2014June 15, 2023

FERC Bundles Entergy ‘Bandwidth’ Disputes for Hearing

By Chris O’Malley

Saying the “time is ripe,” the Federal Energy Regulatory Commission has consolidated four years of Entergy Corp.’s disputed annual cost allocation cases for hearing and settlement.

At issue is how Entergy allocates production costs among its half-dozen operating companies under its system agreement. The companies essentially operate as one system, although each have different operating costs.

Each year payments are made by low-cost operating companies to the highest-cost company in the system, using a “bandwidth” remedy that ensures that no operating company has production costs more than 11% above or below the Entergy system average.

Under the 2014 bandwidth implementation — its eighth —Entergy Texas would pay $15.3 million to Entergy New Orleans.

Regulators in each state where Entergy operates have regularly challenged the annual bandwidth filings. FERC agreed Dec. 18 to review not only the 2014 filing but also Entergy’s fifth, sixth and seventh bandwidth formulas (ER14-2085).

The commission said the filings raise factual issues that it could not resolve based on the existing record. It set a refund effective date of June 1, 2014.

In Entergy’s 2014 filing, the New Orleans City Council sought a hearing to determine if Entergy’s rate calculations and accounting practices are in agreement with the bandwidth formula and previous FERC orders.

The council also raised an issue with the 2013 bandwidth filing, noting that it includes the cancellation costs of the Little Gypsy Repowering Project that a FERC judge in an initial decision (ER12-1384) excluded from the bandwidth calculation.

The Louisiana Public Service Commission, meanwhile, said it wanted a hearing to determine whether Entergy’s inputs are unjust and unreasonable due to incorrect calculations, “misapplications of the formula or imprudence.”

The Public Utility Commission of Texas also sought a hearing on the 2014 filing but asked that it be delayed until the accounting for the previous years are resolved.

“Our preliminary analysis indicates that Entergy’s proposed rates have not been shown to be just and reasonable and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful,” FERC said.

December 23, 2014June 15, 2023

FERC Orders Proceedings to Decide PJM’s Postage-Stamp Cost Allocation

By Michael Brooks

The Federal Energy Regulatory Commission last week ordered settlement judge and hearing procedures to determine how costs should be allocated for PJM transmission projects of 500 kV or more that were approved before February 2013.

PJM’s “postage-stamp” cost allocation for the projects was challenged in court by the RTO’s Midwestern utilities. The method billed all PJM utilities in proportion to their load, regardless of where the projects were located.

The Seventh Circuit Court of Appeals has remanded the case back to FERC twice, most recently in June. The commission had originally approved the postage-stamp method in 2007 and attempted to justify it in its order on remand. The court, however, ruled that FERC had again failed to show how a western utility would benefit as much as an eastern utility from new transmission facilities in the east. (See PJM: Court Ruling Won’t Upset ‘Hybrid’ Cost Allocation.)

In last week’s order, FERC noted the court’s criticism, saying it expects PJM and the western utilities “to support their respective proposals for cost allocations for these projects with quantitative evidence, or at least an estimate of the benefits, adjusted as necessary to reflect any uncertainty in benefit allocation among the PJM utilities.”

The case concerns 15 projects costing $2.7 billion.

FERC urged PJM and the utilities “to make every effort to settle their disputes before hearing procedures are commenced.” A settlement judge will be appointed by Jan. 2 to oversee the discussions (EL05-121-009).

PJM replaced the postage-stamp method last year with a hybrid formula that allocates half the costs using the former method, with the remaining costs allocated by a solution-based distribution factor (DFAX).

December 19, 2014June 15, 2023

PJM Seeks to Postpone Some Generation Retirements through 2015/16

By Rich Heidorn Jr.

PJM officials are seeking to postpone generation retirements — or accelerate planned new generation — to help the RTO ride through potential shortages next winter.

Officials told the Markets and Reliability Committee Thursday that they will file proposed cost allocation language with the Federal Energy Regulatory Commission before the end of the year 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 (MATS) rule 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.

PJM Vice President for Operations Mike Kormos said the RTO is acting in light of the 22% forced outage rate from last January and uncertainty over the role of demand response in the wholesale markets.

The final amount procured will be dependent on load estimates and the projected forced outage rate for winter 2015/16 and the volume of capacity procured at the third incremental auction for the year. No demand response will be permitted to clear in that auction, officials said, because of the appellate court ruling threatening DR’s role in the wholesale markets. (See Verrilli to Seek Supreme Court Review of EPSA Ruling.)

Without such actions, Kormos said PJM estimates it would have about 2% less capacity than it had last winter, when it narrowly avoided voltage reductions or other severe actions.

“There is a cost effectiveness [consideration],” he said. “This isn’t 2,500 MW at all cost. This is an insurance policy.”

The FERC filing will seek authority to negotiate contracts with generation owners. Contracts with individual generators would be filed for FERC approval later. “We have no authority to negotiate this” currently, Kormos said.

PJM has negotiated RMR contracts when past retirements have prompted the need for transmission upgrades. The costs of those contracts were allocated over the relatively small areas benefiting from the new infrastructure.

This filing will likely seek RTO-wide cost allocation because of the broader reliability issues involved, Kormos said.

Market Monitor Joe Bowring said the costs should be limited to incremental costs of “speeding up a [new] unit or keeping [an old one] around.”

December 19, 2014

FERC Staff Seeks $30 Million Fine in Powhatan Case

By Ted Caddell and Michael Brooks

The Federal Energy Regulatory Commission issued notice Wednesday that it may seek $29.8 million in fines from hedge fund twins Rich and Kevin Gates over a PJM trading scheme that became the centerpiece of a debate over FERC enforcement policy during Commissioner Norman Bay’s confirmation process earlier this year.

FERC issued an Order to Show Cause, the next step in the enforcement process over what it called a “fraudulent scheme” by the Gates brothers, their Powhatan Energy Fund and associate Houlian “Alan” Chen to collect line-loss rebates on riskless up-to-congestion trades. It gave the accused 30 days to tell the commission why they shouldn’t be fined.

The attached enforcement staff report recommended that the parties give up more than $4.7 million in profits collected by alleged wash trades in 2011. The show cause order didn’t include that recommendation.

They can ask for a hearing or pay the fines. If the fines aren’t paid, FERC can file in U.S. District Court to collect.

FERC’s Office of Enforcement alleged that “with Powhatan’s knowledge and encouragement, Chen placed UTC trades in opposite directions on the same paths, in the same volumes, during the same hours for the purpose of creating the illusion of bona fide UTC trading and thereby to capture large amounts of” rebates.

Kevin Gates said Powhatan would respond to the allegations in the enforcement staff report, insisting that everything they did was legal. He said they seek an extension in the filing deadline.

“I still firmly believe that no violations occurred, that there were no ‘wash trades’ and no violations of any kind,” he said in an interview. “There was an economic purpose to the trades, and there were risks.”

Chen said in an interview that he is “struggling” to understand the allegations against him. “I ask myself, ‘are the type of trades we put on, the match trades, are those trades supportive [of the market]?’ And the answer is definitely ‘yes.’ They were necessary trades to provide a healthy market.”

Both he and Kevin Gates said the type of trades they undertook would have been helpful, in fact, during last winter’s polar vortex. “They would have been there to support the market at the very time the market needed them the most,” Gates said.

FERC enforcement cases usually take place quietly via letters and documents filed back and forth between parties, and they nearly always result in settlements.

But Rich and Kevin Gates have taken a much more public route fighting FERC. They hired expert witnesses, and posted video depositions and statements and reams of legal documents on their website, ferclitigation.com.

The brothers argued that Bay, who headed FERC’s Office of Enforcement during the Powhatan investigation, should recuse himself from any dealings with the case. Bay has since done so.

It appeared in October that a settlement might be in the works when the brothers took down the site. However, when FERC issued a notice on Dec. 5 that the commission was heading toward the next step, civil prosecution, the site was reactivated, and the fight was back on.

The next step was FERC’s, when on Wednesday it issued the show cause order.

At Thursday’s FERC meeting, Commissioner Phillip Moeller read a statement citing the show cause order and explaining the FERC investigation and enforcement process. Moeller took pains to say the commission has not made any final determinations, comments Gates said he found “comforting.”

“In the show cause order, the commission noted that issuance of the staff report does not indicate commission adoption or endorsement of staff’s findings,” Moeller said. “This statement reflects the commission’s long-standing practice not to pre-judge the findings made in staff reports. Instead, the commission will consider the entire record in this proceeding to determine whether the assessment of civil penalties is appropriate.”

Chairman Cheryl LaFleur was asked in a press conference after the meeting if the show cause order means the commission has reached a decision on the Gates case.

“We’ve reached the conclusion that’s reflected in our order, which is that, if you will, it rose to a level of an order to show cause to say ‘here respond to this,’ but we have not reached a conclusion as to a finding of market manipulation. We’ll make that determination presuming we get to the next stage of the case when we decide if there’s market manipulation,” LaFleur said.

LaFleur also was asked whether traders should be prosecuted when they were acting within the RTO’s rules, at the time. PJM’s rules on collecting the rebates were changed after officials recognized the loophole Powhatan was exploiting. Although UTCs don’t involve the movement of physical energy, UTC traders then had to reserve transmission service for each transaction, making them eligible for the line-loss rebates.

“Clearly the issue you identified is one of the ones that’s been debated a lot: what are the bounds of market manipulation under our regulations and we’re seeing it evolve more and more as we take on more cases,” LaFleur said.

December 17, 2014

Update: Senate Confirms Honorable to FERC

By Michael Brooks

The Senate last night confirmed Arkansas Public Service Commission Chairman Colette Honorable to the Federal Energy Regulatory Commission. Honorable recently completed a term as president of the National Association of Regulatory Utility Commissioners.

Honorable was nominated in August by President Obama to fill the remainder of departing Commissioner John Norris’ term, which will end in June 2017. She was confirmed unanimously by simple voice vote. Honorable was among a handful of non-controversial nominations that the Senate quickly approved before adjourning until January, making her confirmation among the last acts of the 113th Congress.

“Colette brings a wealth of experience and expertise to the important issues we are facing,” FERC Chairman Cheryl LaFleur said in a statement. “She and I worked together closely during her time as the president of NARUC, and I very much look forward to continuing that strong relationship when she joins the commission.”

The Senate Energy and Natural Resources Committee voted last week to advance Honorable’s nomination to a full vote. Ranking member Lisa Murkowski (R-Alaska) said a majority of the committee met off the Senate floor Thursday, also voting by voice, after the committee failed to reach a quorum at its meeting the day before.

Assist from Cruz

Honorable was expected to be confirmed by the Senate this week, but only after some political kabuki by Sen. Ted Cruz (R-Texas) inadvertently expedited her nomination.

On Friday, the Senate convened to debate a $1.1 trillion omnibus spending bill, which had to be passed by Saturday night to avoid a government shutdown. Party leaders worked out a deal to pass a short-term spending bill that would fund the government through Wednesday before convening again on Monday to pass the omnibus bill.

Under the rules of the Senate, votes need to be scheduled a certain amount of time in advance, but this wait period can be waived by unanimous consent. Cruz and colleague Mike Lee of Utah, however, objected to the waiver in an effort to oppose Obama’s executive order delaying the deportation of 5 million immigrants living in the country illegally.

The move forced the Senate to stay in D.C. Saturday, infuriating members of both parties. But it also gave Senate Majority Leader Harry Reid (D-Nev.) an opportunity to push through 24 of Obama’s nominations, including Honorable’s, which were being stalled by Republicans in the hopes that they would be delayed until the GOP took over the Senate in January.

“While we wait we shouldn’t waste time,” Reid said when the Senate convened Saturday. “The Republican leader has known for weeks, if not months, that we intend to vote on the president’s nominations.”

Senators spent nearly 10 hours voting on procedural motions to advance the nominations while they waited until they could vote on the omnibus bill, which they ended up passing 56-40 Saturday night.

While the Senate was expected to take up the nominations when it reconvened on Monday, Democrats had feared that the process would take too long and some senators would leave for the holidays before all of them passed.

Reid spent most of Monday and Tuesday putting more controversial nominations to a vote, such as Obama’s pick for surgeon general Vivek Murthy, to get them confirmed before the Senate adjourned and Republicans take over in January. While Honorable would have likely been confirmed next year, Cruz’s maneuver guaranteed that she would be confirmed this week and not have to be advanced by the Energy Committee again next year.

Honorable had received praise from members of both parties at her Dec. 4 confirmation hearing. (See FERC Nominee Colette Honorable Gets Bipartisan Support at Senate Hearing.)

Farewell to Landrieu

The committee met on Wednesday to vote on Honorable’s nomination, but it spent most of its 20-minute business meeting complimenting and thanking outgoing Chairman Mary Landrieu (D-La.) for her service. It adjourned when Landrieu announced it had failed to reach a quorum.

Landrieu lost her bid for re-election earlier this month in a runoff vote against Republican Bill Cassidy, who represents Louisiana’s 6th district in the U.S. House. Murkowski, Landrieu’s likely replacement as chair, said her Democratic colleague has been a “true leader” on energy issues.

Landrieu focused “on the things that are not only important to the people of Louisiana but for the people of this country,” Murkowski told her. “I am very, very grateful for what you have given the United States Senate, for what you have given your state and for what you’ve given to the American people.”

Sens. Maria Cantwell (D-Wash.), Joe Manchin (D-W.Va.), Al Franken (D-Minn.), Ron Wyden (D-Ore.) and Rob Portman (R-Ohio) also offered their appreciation and support for Landrieu. Franken noted that as a former comedian, he would mostly miss Landrieu’s “infectious” laugh.

December 16, 2014

Transmission Outage, Cold Causes Price Spike on Long Island

Power prices briefly spiked above $1,000/MWh on Long Island Wednesday due to a combination of cold weather and an unplanned transmission outage.

The price jolt occurred around noon and lasted for only a few minutes when the East Garden City Bank #2 line failed due to equipment issues between 10:45 a.m. and 2 p.m., according to NYISO spokesman David Flanagan.

The Long Island Zone K jumped to about $1,102/MWh. The adjacent Zone J, in New York City, remained at about $33/MWh.

The Zone K day-ahead forecast was for 2,450 MW from 9 a.m. to 2 p.m., but real-time demand was 2,550 MW.

December 16, 2014June 15, 2023

PJM MRC Preview

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:30)

Members will be asked to endorse the following manual changes:

A. Manual 10: Pre-Scheduling Operations — This update, an annual review, includes a new section highlighting the criticality of reporting outages on facilities providing black start service.

B. Manual 14D: Generator Operational Requirements — Modified to provide consistency with revised North American Electric Reliability Corp. standard VAR-002-3, effective Oct. 1, 2014. Sections 7.1.2 and 7.3.4 contain revisions regarding notifications of status changes on automatic voltage regulators, power system stabilizers and reactive capability.

C. Manual 01: Control Center and Data Exchange Requirements — Addition to Section 3.2.4 regarding user agreements related to purchase of PJMnet connections.

3. Zonal and Residual Metered Load Aggregates (9:30-9:45)

Members will be asked to approve Tariff revisions related to data availability for the bus distribution factors for zonal and residual metered load aggregates utilized by the day-ahead energy market. If there are technical problems that prevent PJM from obtaining the load distribution factors from the snapshot one week prior to the operating day, the load distribution factors from the most recently available day of the week that the operating day falls on will be used.

4. Harmonization of PJM’s Governing Documents (9:45-10:00)

Members will vote on a proposed problem statement and issue charge related to ensuring PJM’s Operating Agreement, Tariff and Reliability Assurance Agreement are consistent in their definitions. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)

5. Enhanced Inverter Capability (10:00-10:15)

The committee will be asked to approve Tariff and manual revisions related to enhanced inverter capabilities. The new rules will apply to Federal Energy Regulatory Commission jurisdictional inverter-based generators defined as asynchronous generation that have an Interconnection Service Agreement or a Wholesale Market Participation Agreement. The changes will not affect merchant transmission facilities, HVDC inverter-converter facilities or existing generation. (See Enhanced Inverters Clear MRC.)

December 16, 2014

NYPSC OKs Con Ed’s Demand Management Program to Relieve NYC Overloads

By William Opalka

The New York Public Service Commission on Thursday approved a plan by Consolidated Edison of New York to address overloads in Brooklyn and Queens through a $200 million program that will deploy distributed generation and demand-side management (DSM) in order to defer installation of a $1 billion substation until at least 2026.

The commission said it was the first time New York has chosen to relieve congestion in “non-traditional” methods instead of authorizing construction of utility infrastructure.

Con Ed’s plan is consistent with the state’s “Reforming the Energy Vision” program to restructure the electricity market with greater reliance on technology and distributed resources, the commission said. “The commission is making a significant step forward toward a regulatory paradigm where utilities incorporate alternatives to traditional infrastructure investment when considering how to meet their planning and reliability needs,” the order states.

Commission Chair Audrey Zibelman added that because of the recent D.C. Circuit Court of Appeals decision striking down federal jurisdiction over demand response in wholesale markets, it’s important for state regulators to set market rules for that resource.

Con Ed said the feeders serving the Brownsville No. 1 and 2 substations began to experience overloads in 2013 and would be overloaded by 69 MW for 40 to 48 hours during the summer by 2018. A new substation, transmission subfeeders and a switching station would cost $1 billion, according to the company. The PSC accepted the company’s estimate of the DM Program’s costs and ordered a cap of $200 million.

The program would include 52 MW of non-traditional utility-side and customer-side relief, including about 41 MW of energy efficiency, demand management and distributed generation, and 11 MW of utility-side battery energy storage. This will include incentives to upgrade building “envelopes,” improve air conditioning efficiency of equipment, encourage greater use of energy controls, and establish energy storage, distributed generation or microgrids.

This will be supplemented by approximately 17 MW of traditional utility infrastructure investment, consisting of 6 MW of capacitors and 11 MW of load transfers from the affected area to other networks.

The commission said the project is hoped to have a salutary effect on utilities statewide. “Important and critical lessons will be learned as changes to traditional utility operations and ratemaking are explored, which are consistent with the core elements of the REV proceeding,” it said.

December 16, 2014

PJM MIC OKs Capacity Transfer Rights Inquiry

PJM stakeholders last week agreed to review modeling practices that the RTO said may be shortchanging loads with transmission agreements that pre-date the RTO’s capacity market.

Members of the Market Implementation Committee approved a problem statement proposed by Stu Bresler, vice president of market operations.

Bresler said PJM’s capacity modeling considers all external firm point-to-point transmission resources as sinking to the “rest of RTO” region, including historic resources that actually sink in constrained zones. While PJM uses this transfer capability in calculating the Capacity Emergency Transfer Objective/Capacity Emergency Transfer Limit (CETO/CETL), it does not allocate the benefits of the capability to the transmission holder. This can expose the load-serving entities to locational capacity price differences, Bresler said.

Under the problem statement, stakeholders will consider adding a mechanism in the capacity market similar to one used to allocate Auction Revenue Rights to historical transmission paths in the energy market. PJM said the issue affects “a very limited number of entities.”

Market Monitor Joe Bowring, however, warned “it’s a slippery slope.”

“There were a lot of entities who had bilateral agreements when they joined the market. There is no reason to make special allowances for preexisting arrangements or for those who do not like the outcome of market rules,” Bowring explained after the meeting. “Others will seek concessions related to locational capacity price differences that are also not permitted by the market rules.”

Waiver Request

Bresler said the issue caused one PJM member in Commonwealth Edison’s locational deliverability area to seek a waiver of PJM’s Reliability Assurance Agreement before last May’s base residual auction.

It was an apparent reference to the Illinois Municipal Electric Agency, which won a waiver from the Federal Energy Regulatory Commission regarding its means of serving the Naperville, Ill., portion of its load (ER14-1681).

IMEA said it had agreed to pay $468 million for rights to capacity resources for self-supply of its ComEd load through 2035. IMEA said it had acquired firm transmission rights to ensure delivery of external capacity resources in Kentucky and Illinois. Without a waiver, it said, its investment in self-supply would be worthless and it would have had to spend as much as $24 million per year in additional costs to serve its Naperville load.

PJM supported the request, noting that the “ComEd LDA was recently, and for the first time ever, modeled with a separate VRR Curve.”

The commission approved the one-year waiver, concluding that it would “not lead to undesirable consequences,” but it urged IMEA and PJM to discuss a solution for future years.

Commissioner Philip Moeller dissented, saying the waiver “will transfer costs incurred on behalf of IMEA to everybody else in Chicago and its neighboring areas.”