Page 1590 – RTO Insider

January 27, 2015June 15, 2023

FERC Looks Again at Export Pricing for MISO MVPs

By Chris O’Malley

multi-value projects — Commonwealth Edison and American Electric Power, which had been members of MISO, later joined PJM, leaving islands of PJM within MISO territory near Chicago and in Southwest Michigan.

The Federal Energy Regulatory Commission last week ordered a paper hearing to revisit its decision to prohibit MISO from assessing export charges to PJM for multi-value projects that benefit PJM customers.

FERC’s Jan. 22 order (ER10-1791) is in response to a 2013 remand by the U.S. Seventh Circuit Court of Appeals ordering the commission to determine whether its limitations on export pricing to PJM are still justified.

The commission will accept comments for 45 days, with reply comments due 30 days afterward. The commission urged parties to provide studies or other evidence in support of their positions.

The issue stems from the commission’s July 2002 order allowing American Electric Power, Commonwealth Edison and Dayton Power and Light to join PJM. That left small islands of PJM within MISO territory near Chicago and in southwestern Michigan, dividing highly interconnected transmission systems.

In subsequent rulings, FERC ordered MISO to eliminate rate “pancaking” that it said would otherwise result from the irregular seam, including a prohibition on charging PJM load for multi-value projects.

Less Disjointed Seam

In June 2013, the Seventh Circuit ordered FERC to reconsider whether its prohibitions on charging PJM for multi-value projects was still reasonable in light of membership changes that straightened out the border.

The court also cited the nature of multi-value projects, noting that they are not local in scope and will benefit other regions.

“Since they will benefit electricity users in PJM, those users should contribute to the costs,” the court said.

It added that FERC was being “arbitrary” in continuing to forbid MISO from charging anything for exports of energy to PJM enabled by multi-value projects “while permitting it to charge for exports of energy to all the other RTOs.”

“The commission must determine in light of current conditions what, if any, limitation on export pricing to PJM by MISO is justified.”

PJM TOs Seek Clarity

Impatient at FERC’s inaction since the court’s remand, PJM transmission owners petitioned the commission last May to set the issue for a paper hearing.

Whatever FERC ultimately decides regarding allocation costs of MISO multi-value projects, the TOs said, “there is no disputing the importance of a timely resolution in this matter. At issue are the costs of billions of dollars of projects, some of which are already underway, with others expected to follow.”

“Until this matter is resolved, interested parties will be left with great uncertainty regarding their burdens with respect to the MVP costs.”

January 27, 2015June 15, 2023

Federal Briefs

The Federal Energy Regulatory Commission has requested more information on the market impact of the proposed $2.8 billion sale of Duke Energy’s Midwest power plants to Dynegy. FERC’s request caused a postponement of the deal’s closing date.

FERC wants more information to ensure that competition in wholesale power markets will not be impaired. Dynegy is engaged in two large acquisitions — the Duke transaction and a separate $3.45 billion deal with New Jersey-based Energy Capital Partners — to acquire a total of 21 power plants. Both deals were supposed to close during the first quarter.

In their application for approval of the purchase, the companies contend Dynegy’s 6.5% share of the PJM market after completing the two deals would have a minimal impact on competition. FERC said the companies failed to demonstrate that Dynegy’s post-acquisition market share qualified as minimal.

More: Triad Business Journal; Houston Business Journal

NRC Issues Two Yellow Findings Against Entergy’s Arkansas One

The Nuclear Regulatory Commission issued two “yellow” findings of “substantial safety significance” against Entergy’s Arkansas Nuclear One station, citing shortcomings in the plant’s flood protection barriers.

The problems “created the potential for water to enter the auxiliary building in the unlikely event of extreme flooding, potentially compromising safety-related equipment,” according to NRC Region IV Administrator Marc Dapas.

The problems were discovered at the Russellville, Ark., power station during inspections in 2013 and 2014. The NRC said Entergy has fixed the problems, and the agency is reassessing “the appropriate level of oversight for the plant.”

More: NRC

‘No Chilled Work Environment’ at Palisades Plant, NRC Determines

Nuclear Regulatory Commission inspectors, following up on last year’s report chiding Entergy for a “chilled work environment” at its Palisades Nuclear Plant, says that workers at the Michigan reactor no longer feel uncomfortable raising safety issues.

The NRC reviewed plant operations, conducted focus groups and interviewed 30% of security department workers before issuing its findings that the work climate at the plant had improved. “The NRC will continue to monitor for safety-conscious work environment issues to assess the sustainability of improvements seen to date,” an NRC official wrote.

Palisades spokeswoman Lindsay Rose said the company promised to maintain the improved climate. “This is not an issue that we’re going to drop and wash our hands of,” she said.

More: MLive

FERC Extends Comment Deadline for PennEast Pipeline Project

The Federal Energy Regulatory Commission has extended the public comment deadline from Feb. 12 to Feb. 27 on the proposed PennEast natural gas pipeline running from Pennsylvania into New Jersey after the pipeline operator altered some contentious parts of the 108-mile route.

FERC has already scheduled five public “scoping” meetings, starting this week, which will give the public information on the proposed line. Pipeline opponents argued that the public comment period did not allow enough time for property owners affected by proposed route changes to respond.

The $1 billion pipeline would transport natural gas from the Marcellus Shale region in northeastern Pennsylvania to a connection near Trenton, N.J. It is financed by UGI and four New Jersey gas utilities.

More: NJ.com

Interior Department Moves Forward on North Carolina Offshore Wind Lease Plan

The Department of the Interior released an environmental assessment last week supporting a plan to lease up to 300,000 acres off the North Carolina coast to developers of wind farms. “In close coordination with our partners in North Carolina, we are moving forward to determine what places make sense to harness the enormous wind energy potential off the Atlantic seaboard,” Secretary of the Interior Sally Jewell said.

The study delineates three areas off the coast that could be leased to developers: about 122,000 acres 24 miles off Kitty Hawk; a 51,000-acre tract 10 miles off Wilmington; and a third area of about 133,000 acres 15 miles offshore of Bald Head Island.

A North Carolina Sierra Club organizer, Zak Keith, called the announcement “a huge opportunity to create jobs and investment in the clean energy sector without the risk of oil spills.” The study is open for public comment through Feb. 23.

More: News & Observer

January 27, 2015

ISO-NE CEO: Despite Mild Winter, Region Still Needs Infrastructure

By William Opalka

The mild winter that has moderated energy prices in New England shouldn’t lull policy makers into complacence about the region’s infrastructure needs, ISO-NE CEO Gordon van Welie said last week.

In a Jan. 21 presentation to the media on the state of the energy market, van Welie acknowledged that this winter has been warmer than the previous two, resulting in less demand for power and natural gas and a reduction in pipeline constraints.

“But this is New England,” van Welie said. “Winter’s not over yet, and a mild winter or two doesn’t guarantee we won’t have extremely cold winters again.”

The increasing reliance on natural gas-fired generation and retirements of oil- and coal-fired power plants have created “an urgent need for more energy infrastructure,” he said.

ISO-NE began a winter reliability program for 2013-2014 that was essentially repeated for the current season. That supplemental program provided financial incentives for oil-fired generators to store more oil than they otherwise would have. It has encouraged dual-fuel capable generation that can switch from gas to oil.

Although the RTO has added $7 billion in transmission since 2003 and has generation projects totaling about 9,500 MW in its transmission queue, plant retirements are causing localized stresses.

“We’re already seeing worrisome conditions in greater Boston, with the recent retirement of the Salem Harbor station and delays in development of the proposed Footprint natural gas power plant. That area will be short of needed resources as soon as 2016,” van Welie said.

Southeastern Massachusetts and Rhode Island also are areas of concern, with Brayton Point’s planned retirement in 2017.

In addition, the RTO hasn’t been able to add natural gas pipeline capacity fast enough to react to increased power and heating demand.

For each of the last three winters, natural gas prices have risen steeply, showing the effects of increasing pipeline constraints. On Jan. 1, 2014, the spot price for natural gas in New England was nearly $20 higher than the price paid in most of the country.

“They were not only the highest forward prices in the U.S.; at the time, they were the highest on the planet,” van Welie said.

He said ensuring the reliability of the power system will likely require more gas pipelines, more liquefied natural gas storage and more transmission lines.

“The region faces a conundrum: who will be the customer to ensure new gas infrastructure is built? Will it be end-use electricity consumers or electricity producers — that is, generators?” he asked. “Thus far, electric generators have not signed up for additional gas infrastructure and as a result, the New England states have been considering making an investment in additional gas infrastructure on behalf of consumers.

“Until more infrastructure is added, consumers can expect volatile pricing for both natural gas and wholesale power, with price spikes when either the pipeline or power system is operating under stressed conditions,” he said.

January 27, 2015January 29, 2024

DOE-Funded Report Suggests ‘ISO’ for Gas-Electric Communications

By William Opalka

(Click to zoom.)

A U.S. Department of Energy-funded study on gas-electric coordination suggests natural gas pipeline operators create an independent system operator (ISO) to coordinate communications with electric grid operators.

The proposal is one of nine recommendations in a white paper on long-term electric and natural gas infrastructure requirements, conducted by the Illinois Institute of Technology for the Eastern Interconnection States’ Planning Council (EISPC) and the National Association of Utility Regulatory Commissioners. Although dated November 2014, the report was released by NARUC only last week.

Most of the report’s other recommendations — such as aligning daily gas and electric market schedules, building more pipelines to serve growing electric load and improving training — have been under discussion or development by industry participants for more than a year.

For example, in November 2013, the Federal Energy Regulatory Commission approved a rule allowing pipeline operators to exchange non-public operational information with RTOs. (See FERC OKs Gas-Electric Talk.)

But the report notes that while public domain information “is generally shared between pipeline operators and ISOs,” concerns about proprietary information remain.

“[E]stablishing a coordinator in the natural gas industry that could directly communicate with ISOs through appropriate protocols could be an option to solve the confidentiality problem and enhance the information sharing in natural gas-electric system planning,” the report says.

The recommendation doesn’t go as far as those from some other commentators, who have suggested a “Regional Pipeline Organization” or a centralized gas trading platform. (See Gas Trading Platform Finds Few Takers at Moeller Meeting.)

The report also calls for integrating natural gas availability into the North American Electric Reliability Corp.’s long-term and seasonal reliability assessments and for improvements to NERC’s Generator Availability Data System to better track generator outages resulting from a lack of gas supply.

The EISPC, which is funded by the Department of Energy, is a consortium of state-level agencies responsible for siting electric transmission across the 39 states in the Eastern Interconnection.

EISPC President David Boyd, a member of the Minnesota Public Utilities Commission, said the report will help regulators overcome challenges of the electric industry’s increased dependence on pipelines.

“As this report spells out, there are a number of differences between the two industries that, if not reconciled, could have unintended consequences for consumers,” he said in a statement.

January 27, 2015June 15, 2023

FERC Denies IMEA Request for Extended Waiver on Capacity Obligation

By Suzanne Herel

The Federal Energy Regulatory Commission on Thursday rejected the Illinois Municipal Electric Agency’s request for an extended waiver that would allow it to use capacity resources outside of the Commonwealth Edison Locational Deliverability Area to meet its internal resource requirement in serving its Naperville, Ill., load. (ER14-1681-001).

Last May, FERC granted IMEA a waiver for the 2017/18 delivery year after the ComEd LDA last year was modeled for the first time with a separate variable resource requirement curve (ER14-1681).

In June, IMEA asked FERC to clarify that the waiver extended beyond the one delivery year to the “term of the life of IMEA’s resource investments and commitments or at a minimum for the five-year minimum term of the [Fixed Resource Requirement] Alternative.”

Without a waiver, IMEA said it will be subject to unnecessary financial risks in any delivery year for which PJM uses a separate VRR curve, estimating the annual penalty charges at $100 million.

In its Jan. 22 order, FERC said it approved the one-year waiver because the short notice of PJM’s announcement to establish the separate VRR curve left IMEA little time to prepare to meet the internal resource requirement. “For subsequent delivery years, IMEA has sufficient time to prepare for the requirements of the FRR Alternative,” the commission said.

While IMEA contended that a longer waiver would have no adverse effects, FERC said it could expose customers in the ComEd LDA to higher prices because the aggregate internal resource requirement would need to be increased in future delivery years.

If IMEA decides not to continue under the FRR Alternative, FERC said, it could seek early termination from that status for the Naperville load and instead participate in PJM’s capacity auctions.

FERC’s ruling does not bode well for the waiver request IMEA filed earlier this month for this May’s Base Residual Auction (ER15-834).

But it may get some relief from PJM.

In December, stakeholders agreed to a problem statement proposed by Vice President of Market Operations Stu Bresler to review modeling practices that he said may be shortchanging loads with transmission agreements that pre-date the RTO’s capacity market. (See PJM MIC OKs Capacity Transfer Rights Query.)

Members approved a related issue charge earlier this month, agreeing to 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.

January 27, 2015

States, LSEs Skeptical, Utilities Split Over Capacity Performance

By Suzanne Herel, Michael Brooks and Rich Heidorn Jr.

More than 60 parties filed comments or protests in response to PJM’s Capacity Performance proposal before last week’s deadline, with states and load-serving entities expressing skepticism over the need for a major overhaul and generators split over elements they like and others they insist must be changed.

The Electric Power Supply Association, which represents generators, was singularly conflicted, saying it “generally supports” the proposal, but joined with other generators in complaining that the proposed changes to force majeure provisions were unduly punitive.

EPSA also joined states and LSEs in criticizing the limited stakeholder input before PJM’s Board of Managers made its unilateral filing with the Federal Energy Regulatory Commission on Dec. 12. But the association said implementation of the new structure should not be delayed by needed changes.

In a 51-page filing, PJM’s Independent Market Monitor said it “strongly supports” the proposal but listed numerous changes it said were needed to prevent market manipulation and clarify the oversight roles of PJM and the Monitor.

Most other commenters fell clearly into camps of supporters or opponents.

PJM’s proposal would increase the reliability expectations of capacity resources with a “no excuses” policy. It is expected to result in both larger capacity payments and higher penalties for non-performance. (See What You Need to Know about PJM’s Capacity Performance Proposal.)

The details are outlined in nearly 1,300 pages filed in two dockets:

EL15-29 contains proposed changes to PJM’s Operating Agreement and Tariff “to correct present deficiencies in those agreements on matters of resource performance and excuses for resource performance.”
ER15-623 proposes changes to the Reliability Pricing Model rules in the Tariff and Reliability Assurance Agreement.

Below is a summary of the main arguments presented in the comments.

Supporters

Those supporting the proposal included the Natural Gas Supply Association, America’s Natural Gas Alliance and the Energy Storage Association.

“The Capacity Resource Performance provision would begin to address PJM’s current difficulties by incenting investments by generators that would help them perform more reliably and economically even during periods of peak demand,” said the Natural Gas Supply Association, which represents gas producers and marketers.

The Energy Storage Association lauded the proposal as an opportunity for energy storage resources to participate in PJM’s capacity market.

Exelon said it “strongly agrees with PJM on the urgent need” for the changes to address “an imminent reliability crisis due to a capacity market design that fails to ensure that generators who have made capacity commitments actually perform when they are needed.”

Exelon, the nation’s largest nuclear operator, stands to benefit perhaps more than any other market participant from the proposal’s incentives to ensure generators have secure fuel supplies.

Penalties, Force Majeure

Unlike most other generators, Exelon complained that PJM’s proposed non-performance penalties were too lax. It said the RTO’s method for determining the hourly penalty rate is flawed and will result in much lower penalties than intended. It also called on the commission to clarify that a forced outage due to fuel unavailability during emergencies, or “performance assessment hours,” will result in automatic referral to the commission for violation of the Tariff.

Other generators complained that the penalties are already too harsh.

“Redefining force majeure to apply only when catastrophic conditions occur over the entire PJM region is unnecessarily broad and, as applied, too punitive to generators,” the PJM Power Providers (P3 Group) said. “Notwithstanding the most prudent investments, it is nonetheless impossible for every generator to foresee every eventuality. Equally as important, it is illogical to apply a penalty for nonperformance of a generator based on the requirement that the entire PJM operational system would need to be negatively impacted.”

Not Enough

American Electric Power, Dayton Power and Light, FirstEnergy, Buckeye Power and East Kentucky Power Cooperative also called for a reduction in proposed non-performance penalties in a 186-page filing.

The group, filing as the PJM Utilities Coalition, said the proposal is insufficient to correct a revenue inadequacy problem that they said is threatening reliability. They said that the proposal fails to eliminate incentives for bidding as a price-taker and that clearing multiple products simultaneously with different performance obligations will result in price suppression.

Too Much, Too Expensive

Load-serving entities, however, complained that PJM’s redesign is overkill and will result in unnecessary price increases.

“Capacity Performance is too much, too quickly, for no clearly stated reason,” the Old Dominion and Southern Maryland electric cooperatives said in a joint filing with American Municipal Power.

The Transition Coalition — whose members include the PJM Industrial Customer Coalition, cooperatives and other load-serving entities — said its members estimate the proposal would cost as much as $2.8 billion in the 2016/17 delivery year and $3.6 billion in the 2017/18 delivery year. “What will we get in return for billions of dollars in new payments?” it asked.

Similarly, Pepco Holdings Inc. said PJM should be required to provide a more thorough analysis of its proposal’s impacts, including costs and benefits.

Some commenters took aim at the transition provisions that would apply to resources that clear in the base capacity auctions this May and in 2016.

“Acceptance would constitute retroactive ratemaking,” the Retail Energy Supply Association said, while Direct Energy maintained the transition mechanism contained “billions of dollars in unforeseen costs on the region.”

Impact on Renewables

Public interest organizations said that renewable, energy efficiency and demand response resources would be disadvantaged by the new market structure, concerns echoed by the American Wind Energy and Solar Energy Industries associations.

The Environmental Defense Fund, the Natural Resources Defense Council, the Sierra Club, the Sustainable FERC Project and the Union of Concerned Scientists filed a joint protest, calling on FERC to either reject the proposal, set it for evidentiary hearing or exempt non-fossil fuel resources from the proposed penalties.

“Unlike fuel-based generation, renewable generation and non-fuel-based demand-side resources cannot become available all year round through upgrades, and cannot avail themselves to the benefits of being able to firm up fuel supply and pass associated costs to consumers accorded to fuel-based generation under this rule,” the group said.

States: Evidentiary Hearing Needed

The concerns of the states within PJM’s territory differed, with some warning of higher rates and others complaining the proposal violates state resource planning authority. Almost all states, even those who generally support PJM’s overhaul efforts, said the proposal needed changes as a result of it being rushed without adequate stakeholder input. Many also called for FERC to hold an evidentiary hearing.

The Organization of PJM States Inc. (OPSI) said it could not determine the need for the proposal or whether it would result in just rates because PJM had not provided sufficient analysis.

“To better quantify the impact of the proposal on customers’ rates, and on system operations and grid reliability … requires the development, presentation and evaluation of data that have not yet been provided by PJM.”

Capacity Performance is “Overreaction”

Some stakeholders also said the proposal changes more than is necessary.

The Delaware Public Service Commission called the proposal “an overreaction” to the poor generator response in January 2014. “All stakeholders should have an opportunity to fully evaluate the [proposal] before it is implemented with undeterminable and questionable costs and unquantified benefits,” it said.

In a joint protest, consumer advocates in Maryland, New Jersey, D.C., Delaware, Ohio and Illinois, along with the PJM Industrial Customer Coalition, said the proposal is “unnecessarily costly and disproportionate to the level of changes that are required. The sole focus should be on revamping the structure of penalties that applies to cleared capacity resources, to align actual performance with the level of revenue that cleared capacity resources currently receive.”

The Illinois Commerce Commission agreed. “Addressing deficiencies revealed by 2014’s winter conditions is a critical need, but the [proposal] goes far beyond addressing the specific issues that likely contributed to poor generator performance during this period,” the ICC said. “Rather, the [proposal] represents an extensive revision and, in some of its elements, is an unnecessary reworking of the RPM model.”

The Pennsylvania Public Utility Commission said it supports PJM’s changes to generators’ performance requirement. But it said FERC should “reject or modify the other changes to PJM’s Tariff filing wherein PJM seeks to unilaterally and, without stakeholder support, alter the provisions of RPM that have developed through much deliberation by FERC, PJM and stakeholders and that contribute to the functioning of healthy wholesale markets.”

For example, the PUC said it was concerned that how PJM defines what qualifies as a Capacity Performance resource would affect DR resources. “The characteristics of DR providers are not compatible with PJM’s proposed trading restrictions and should be eliminated for these types of resources given the fundamental nature of the underlying characteristics of residential, business and industrial customers,” the commission said.

January 27, 2015

SPP, MISO Move Ahead on Flowgate Rules

By Chris O’Malley

The Federal Energy Regulatory Commission last week approved SPP’s market-to-market coordination rules with MISO, after the two RTOs resolved an earlier dispute over the creation of flowgates (ER13-1864).

SPP had originally proposed restrictions on the right of either RTO to designate a new M2M flowgate — transmission lines or transformers monitored for overloads — outside of their mutually agreed-upon scheduling timeframes.

SPP would have allowed the creation of flowgates during extenuating circumstances or when the RTO seeking a new designation compensated the other for any re-dispatch that resulted.

PJM and Exelon filed comments supporting SPP’s position, with Exelon noting that MISO created 500 new flowgates between September 2011 and October 2012, while PJM designated only 80. SPP’s transmission owners also supported the restrictions, citing the administrative burdens of complicated resettlement processes related to re-dispatches.

MISO and its Independent Market Monitor opposed SPP’s proposal, which they said would effectively give one RTO veto power. The Monitor noted that M2M flowgates are dynamic, responding to changes in outages and constraint definitions.

Compromise Reached

Following a technical conference last September, SPP agreed to drop its prohibition in a compromise with MISO. The RTOs agreed on new language, which FERC accepted in last week’s order, spelling out the conditions under which one RTO will be compensated by the other for costs stemming from flowgate designations.

In its Jan. 22 order, the commission also agreed to allow the two RTOs to defer a day-ahead firm-flow entitlement exchange process until they decide whether its implementation outweighs its costs.

FERC also ordered SPP to report back to the commission every six months on its progress resolving concerns over interface bus modeling methodologies. The MISO Monitor says disparities in the methodologies used by MISO and PJM is resulting in double counting of congestion. (See related story, Patton Asks FERC to Set Deadline on PJM-MISO Interface Pricing Dispute.)

Noting that PJM and MISO have been unable to resolve their differences over two years of discussions, the commission said “we anticipate … that SPP and MISO could face technical challenges in identifying the appropriate pricing methodologies.”

MISO-SPP Flow Dispute not Affected

The order does not affect a separate dispute between MISO and SPP over flows between MISO’s northern and southern regions. MISO began limiting flows between the regions last spring after SPP complained that MISO breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW physical contract path.

The commission said that issue, the subject of a separate docket (EL11-34), was beyond the scope of this proceeding.

January 27, 2015June 15, 2023

Patton Asks FERC to Set Deadline on PJM-MISO Interface Pricing Dispute

By Chris O’Malley and Michael Brooks

WASHINGTON — MISO’s Independent Market Monitor urged the Federal Energy Regulatory Commission last week to resolve a standoff between MISO and PJM over interface pricing that he said is costing consumers millions.

“We’re seeing tens of millions of dollars in uplift. We see transactions being scheduled that are not efficient. And the only way to really solve this is to get prices right,” MISO Market Monitor David Patton told commissioners during a panel discussion with RTO representatives and state regulators at FERC’s Jan. 22 meeting.

But PJM Market Monitor Joe Bowring and Stu Bresler, PJM vice president of market operations, said pressure for an immediate resolution could be short-sighted. “We have to be careful an arbitrary deadline does not force a bad answer rather than getting to the right answer,” Bowring said.

“I think a deadline that required a solution in a very near timeframe would be very difficult and potentially damaging if it resulted in an inferior approach,” agreed Bresler.

Whether the commissioners will set a deadline to help spur a resolution is unclear.

“I think we want to distill what we have heard today and get the sense of where the commissioners are,” Chairman Cheryl LaFleur said at a press conference following the meeting.

Two Years

MISO and PJM have been working for two years to resolve differences in the way they price transactions at interface buses.

The RTOs agree that the current methods undermine efficient scheduling of power because they cause both RTOs to model the same constraint, resulting in double-counting.

Patton says transactions are overcompensated when they are expected to relieve a constraint, and overcharged when they are expected to contribute to congestion. Interface pricing flaws “cost MISO some money. It costs PJM a huge amount,” he said.

Patton contends that PJM’s method exaggerates the effects of imports and exports on transmission constraints near the seam. As a result, he said, scheduling incentives have been inflated by as much as 600% at the Cook-Palisades interface in Michigan, the most active M2M constraint last winter.

“We massively overpriced congestion last winter and it resulted in an average of something like 3 GW being exported from PJM to MISO. This was during the timeframe when we were just coming out of the polar vortex and PJM had just incurred half a billion dollars in uplift, committing tons of generation under conservative operations, and they’re exporting gigawatts to MISO, where it’s demonstrably less valuable,” Patton added.

Bresler said he didn’t see the correlation. “PJM has made changes to its interface definitions in direct response to concern from MISO. Given the change we made, I’m not sure I understand the reference … to the polar vortex and the uplift,” he said.

Patton recommends removing the congestion component of the LMP for the non-monitoring RTO.

PJM offered an alternative in which each RTO would set its interface bus price relative to a common set of interfaces.

FERC to Set Deadline?

Patton said FERC should set a deadline for an agreement because there have only been two solutions under consideration for more than a year.

“We’ve had an incredible amount of analysis on those two solutions. Obviously, I think there’s one clearly correct answer, but not everyone agrees with me,” he said to laughter. “I think if we did have a deadline to file, it would be useful just to file and say ‘We’re agreeing to disagree, and here are the pros and cons of these two solutions that we have an enormous amount of research on, and then allow the commission to maybe weigh in and give some guidance and push the needle in one direction or the other.”

“We really need FERC’s involvement in this issue. We need a deadline to file a solution to this,” Patton told commissioners.

Bowring said he didn’t think a hard deadline made sense, although he suggested the RTOs could report back to the commission in June. “If we knew the answer, we would have told you already. We don’t.”

Bresler said Patton’s proposed solution to interface pricing could have negative impacts elsewhere.

“PJM has always defined our interface prices so that we reflect the impact of interchange transactions on the transmission system and more specifically on the transmission constraints which we are actually operating,” Bresler said. “And part of the solution that Dr. Patton has proposed is essentially eliminating the impact of some transmission constraints in the interface price.

“That may end up being the right solution,” Bresler added. “But I think the difficulty … is making sure that doing so doesn’t have detrimental effects elsewhere.”

LaFleur expressed frustration with the inability of the two RTOs to resolve the impasse.

“I am at least actively contemplating, should we do something more active than ask for another schedule, which is what we decided to do [in 2013] after a lot of tough talk,” she said. She acknowledged work done by the RTOs to address seams issues but added, “I’ve been a little disappointed with the level of progress on some of the thorniest issues, many of which have come before us today.”

Commissioner Philip Moeller said the problems are “partly our fault.”

“We kind of took our foot off the gas and stopped requiring the quarterly reports and basically lost focus on the fact that these issues were not going away,” he said.

Michigan Public Service Commissioner Greg White, another panelist, agreed a deadline could increase the parties’ “sense of urgency” but said he didn’t want to “end up with a product that is inferior because of a lack of time.”

Joint and Common Market Progress

The bus interface pricing issue has proven to be perhaps the most intractable issue facing PJM and MISO’s Joint and Common Market initiative, a joint stakeholder process to address seams issues.

Patton said the JCM process has borne fruit. He said MISO’s ability to export capacity into PJM has increased, although the two parties haven’t solved the underlying problems. “So while I don’t think we structurally have solved the problem and I don’t see a filing coming any time soon that will structurally solve this, I think the priority has diminished.”

Bowring was unapologetic. “There will continue to be issues as long as there are very substantial differences between the design for procuring capacity in MISO and the design for procuring capacity in PJM,” he said. “The … notion that there should be transfers no matter what I think is excessively simple-minded.”

Elizabeth Jacobs, chair of the Iowa Utilities Board, who represented the Organization of MISO States on the panel, said she was encouraged by MISO and PJM’s plans to introduce Coordinated Transaction Scheduling to improve interchange optimization. (See “PJM Posts MISO Price Predictions Before CTS Vote” in Market Implementation Committee Briefs, Jan. 12, 2015.) Jacobs noted that while the panel discussion focused on the PJM-MISO seam, many MISO members are facing new seams issues with an expanded SPP.

January 27, 2015

FERC to Tighten Policy on Hold Harmless Merger Commitments

By Rich Heidorn Jr.

The Federal Energy Regulatory Commission said last week that it intends to tighten the rules on the use of “hold harmless” commitments in support of merger applications and will prohibit commitments that are limited in duration, which could leave ratepayers vulnerable.

In a proposed policy statement (PL15-3), the commission said it was better defining the costs subject to such commitments and the accounting methods used to track them. The commission will accept comments on the proposal, which it called a reaffirmation of its 1996 Merger Policy Statement (Order 592), for 60 days.

FERC noted that hold harmless commitments — agreements not to seek recovery of transaction-related costs in rates unless they are offset by transaction-related savings — have become a common feature of merger applications under section 203 of the Federal Power Act (FPA) over the last decade.

The commission said, however, that “it has never defined those costs with much specificity, leading to inconsistency with respect to this issue.”

The policy statement’s definition includes the costs of consummating a transaction (e.g., legal, investment advisory, accounting and financing costs) and the capital and operating costs incurred to achieve merger synergies (e.g., severance payments, accounting and operating systems integration costs).

The commission said requiring applicants to explain how they track the costs will help ensure that they are not recovered in rates without commission approval.

Time Limits

The Merger Policy Statement requires that hold harmless commitments must protect customers “for a significant period of time following the merger,” a period that the commission has typically defined as five years.

FERC said it now realizes that such a limit “raises the risk that transaction-related costs could be included in future formula rate billings without applicants making the showing of offsetting savings.”

The commission said its concern arose from its experience auditing utilities with hold harmless commitments, the concerns of protestors in previous merger applications and the proposed treatment of certain categories of costs.

“For example, an applicant could try to include transaction-related costs in formula rates without making a showing of offsetting savings if the costs, though incurred during the hold harmless period, do not enter the ratemaking process until after the hold harmless period expires … Similarly, limiting the applicability of hold harmless commitments to specific time periods may incentivize applicants to delay incurring some types of transaction-related costs until after the hold harmless period expires.”

The new policy, FERC said, ensures “that the focus of a hold harmless commitment [is] on whether a cost is transaction-related, and not on when the cost is incurred.”

FERC also said removing the time limit will ensure proper treatment of costs that should be capitalized as an asset during the hold harmless period, but whose cost recovery would occur as the asset is depreciated over future periods that extend beyond the hold harmless period.

Changes are Prospective

The commission also reiterated its opposition to including acquisition premiums as transaction-related costs. It said it would continue to require a showing of “specific, measurable and substantial benefits to ratepayers” for recovery in a subsequent FPA section 205 proceeding.

FERC said the policy changes would apply prospectively and would not affect existing commitments or pending merger applications.

January 27, 2015

Environmentalists, Think Tank Urge Rejection of Exelon-Pepco Merger

By Ted Caddell

Environmentalists last week continued their campaign against Exelon’s proposed $6.8 billion takeover of Pepco Holdings Inc., with activists urging the D.C. Council to oppose the deal and a renewable energy think tank saying it would hurt both consumers and green energy.

At a council hearing Friday, environmentalists said Exelon power-generation investments would make it hostile to rooftop solar, unlike Pepco, which only distributes electricity. Approval of the deal is in the hands of the D.C. Public Service Commission but the council is an intervener in the regulatory proceedings and could influence regulators’ decision.

“They view renewable power and sustainability as a threat to their core business of selling electricity,” said Larry Martin of the D.C. chapter of the Sierra Club, according to a report in The Washington Post. “This merger is not contributing to the public interest.”

Mary M. Cheh, chair of the council’s Committee on Transportation and the Environment told the Post that the hearing had left her skeptical that the deal would benefit District residents.

No one from Pepco, Exelon, the PSC or the District’s Office of the People’s Counsel testified at the hearing. They are expected to appear at a hearing of the council’s Committee on Business, Consumer and Regulatory Affairs on Jan. 29.

Earlier last week, the Institute for Energy Economics and Financial Analysis joined the chorus of voices calling for rejection of the deal.

The Cleveland-based think tank, which supports reduced dependence on coal and other non-renewable energy resources, said in a Jan. 21 report that the merger would undermine D.C.’s renewable-energy initiatives.

It said the deal could mean higher rates for current Pepco customers because Exelon will need to earn returns to justify the $2.5 billion acquisition premium Exelon has offered.

Exelon “has been challenged in recent years by low wholesale power prices driven by cheap natural gas, reduced demand for power and the growth of renewable energy and energy efficiency,” wrote the report’s authors, Cathy Kunkel and Tom Sanzillo.

They wrote that if the acquisition is approved, Exelon will “acquire a stable earnings stream from Pepco’s regulated utilities that would help Exelon balance out the volatility of its merchant electricity generation business, which has proven susceptible to weakness in the competitive energy markets.”

“A merger with Exelon would also subject ratepayers to risks associated with Exelon’s aging nuclear fleet,” the report said. “Residents and businesses may be asked to accept rate increases and policy accommodations to assist Exelon with the management of aging nuclear plants.”

Exelon spokesman Paul Elsberg said the report contains some errors and draws incorrect conclusions.

“Customer rates will not increase as a result of the Exelon-Pepco Holdings merger and, in fact, by combining our companies, we will operate more efficiently and generate cost savings that will be passed on to customers,” he said Friday.

Elsberg said the two companies’ support for renewable energy will continue, noting that Exelon is the 11th largest U.S. wind producer and has made investments in solar, including the nation’s largest urban solar project in Chicago. “Our utilities will continue to facilitate customers’ installation of solar panels on their homes and businesses,” he said.

Kunkel said the study was not commissioned by any other group. She said the proposed merger drew the Cleveland think tank’s attention for several reasons.“IEEFA follows developments in the utility industry nationally,” she said Friday. “We see this case as part of a larger trend of major utilities moving increasingly towards regulated operations, and we also think it has important implications for renewable energy policy in the mid-Atlantic.”

The merger has already gained the approval of the Federal Energy Regulatory Commission and Virginia regulators. The staff of the New Jersey Board of Public Utilities has reached a settlement with Exelon that would give Atlantic City Electric customers $62 million in rate credits.

Exelon still needs the approval of Maryland, D.C. and Delaware. Public advocates in both states and the District have come out publicly against the merger under the current offer.