Page 1506 – RTO Insider

October 20, 2015

FERC won’t Rehear PJM MOPR Ruling

By Suzanne Herel

FERC declined last week to rehear a 2013 order approving PJM’s revisions to a rule designed to mitigate buyer-side market power in the capacity market.

The ruling addressed the minimum offer price rule (MOPR), which PJM added to its auction protocols in 2006 amid concern that load could have an incentive to suppress market clearing prices by offering supply at less than a competitive level (ER13-535). (See Split Decision on MOPR; FERC Upholds PJM Exemptions, Rejects End to Unit-Specific Review.)

PJM in 2013 proposed narrowing the list of resource types to which MOPR would apply, eliminating the unit-specific review process and establishing categorical exemptions for competitive entry and self-supply resources.

That, PJM said, would create a better defined and transparent process for granting MOPR exceptions, while addressing concerns from market participants about competitiveness in the 2012 capacity market auction.

FERC accepted the exemptions but ordered that PJM retain its unit-specific review process.

The order was challenged by stakeholders including NRG Energy, state consumer advocates, the PJM Power Providers Group (P3), the Illinois Commerce Commission, Calpine and FirstEnergy.

‘Flawed’ Process

Calpine said FERC was mistaken in requiring PJM to retain the unit-specific review because the commission had acknowledged in the 2013 order that it was “flawed.” FERC said it had acknowledged that the process “warranted additional stakeholder review and the consideration of certain enhancements.”

Nevertheless, it said “we cannot conclude, based on the record before us, that review of individual units’ costs and revenues is an unjust and unreasonable method of determining rates. To the contrary, the commission noted in the May 2013 order that, based on PJM’s assessment, the clearing prices in PJM’s capacity auctions held during the period in which the unit-specific review process has been in effect have been just and reasonable.”

Exemption for IGCC Units?

The ICC said FERC erred in allowing PJM to subject integrated gasification combined-cycle generators to the MOPR because they require long development times and thus incur significant sunk costs prior to their participation in capacity auctions, making them unlikely to suppress capacity prices.

The commission responded by citing PJM’s “concerns regarding the ability to eliminate the gasification component of an IGCC plant such that the project originally planned as an IGCC plant could become a combined-cycle plant.”

“Based on these concerns, we continue to find the relevant characteristics of an IGCC resource justify their inclusion in the MOPR, consistent with PJM’s treatment of other natural gas-fired units,” FERC said.

Discrimination Against Competitive States Alleged

The commission also rejected a complaint by consumer advocates that the MOPR is discriminatory because generation in restructured states is not eligible for the self-supply exemption and because the competitive entry exemption qualification requirements are more stringent than those for self-supply in traditionally regulated states.

The commission accepted PJM’s proposal to exempt new entry projects developed through a state-sponsored or mandated procurement process as long as that process was competitive and non-discriminatory. FERC gave no ground in its new order, saying the differences between the eligibility requirements for the competitive entry and self-supply exemptions were not discriminatory.

“Both the competitive entry and self-supply exemptions are tailored to ensure that merchant resources that have no incentive to artificially suppress capacity prices are able to offer into the capacity auction at prices that are not subject to mitigation,” it said.

Self-Supply Concerns

FirstEnergy worried that the self-supply exemption could be gamed. NRG argued that the self-supply exemption “will result in a large number of new power plants being built by vertically integrated utilities and public power entities, the effects of which will suppress market clearing prices.”

“We disagree,” the commission responded. “With properly calibrated [net short and net long] thresholds, PJM’s self-supply exemption will not operate in a manner that encourages uneconomic entry and thus will not artificially suppress market clearing prices.”

October 20, 2015

MISO SSR Unit’s Recovery of Fixed Costs Upheld

By Amanda Durish Cook

FERC last week issued two orders reaffirming earlier rulings on MISO’s disputed system support resource agreement with Illinois Power’s Edwards Unit 1 generator in Peoria, Ill.

The SSR agreement took effect in January 2013 to keep the Edwards unit operating to address thermal and voltage problems until transmission upgrades can be completed in December 2016. Dynegy’s Illinois Power unit acquired the plant from Ameren in December 2013.

In the first order, the commission affirmed its July 2014 finding that a generator should be allowed to recover its fixed costs through a full cost-of-service rate when it is forced to continue operating for reliability reasons (EL13-76-001, et al.).

MISO industrial customers and the PJM Market Monitor challenged the 2014 order, arguing that uneconomic generators targeted for retirement are not recovering their fixed costs from the market and should not receive a “windfall” because they are needed for reliability. (See PJM IMM Questions MISO Cost Recovery Ruling.)

The commission saw it differently. “Although a retiring generator may view undepreciated costs as being sunk and may write-off any loss at the time of retirement, the fact remains that MISO has the ability to unilaterally delay this decision,” FERC said. “During this delay, an SSR unit owner is providing utility service, and … when a generator is required to provide utility service, it should be permitted to recover costs beyond going-forward costs.”

Last week’s order also affirmed the commission’s earlier ruling that the Federal Power Act prevents the commission from providing retroactive cost-of-service recovery. The order left the commission’s previous rulings regarding Edwards’ 2013 and 2014 costs unchanged.

In the second order, FERC denied requests for rehearing of the commission’s March 31 order that renewed Edwards’ SSR agreement for one year through 2015 (ER15-943-002, et al.).

Hoosier Energy Rural Electric Cooperative, Illinois Municipal Electric Agency, Prairie Power, Southern Illinois Power Cooperative and Wabash Valley Power Association sought rehearing on the basis that MISO needed to conduct a new reliability analysis to re-evaluate the need for Edwards as an SSR unit. The companies contended MISO’s 2013 analysis may be out-of-date. FERC agreed with MISO that there were “no significant changes” that would necessitate a new analysis.

October 20, 2015

Former EPA Official: Clean Power Plan won’t Survive

By Rich Heidorn Jr.

BALTIMORE — Former Environmental Protection Agency official Jeff Holmstead says he hasn’t made predictions on how the courts will rule on previous environmental rules affecting the electric industry.

But Holmstead, former EPA assistant administrator for air and radiation, says he’s very confident that the agency’s new carbon emission rule, the Clean Power Plan, will not live long enough to be implemented.

“I have not been out there predicting any of the other rules would be struck down,” said Holmstead, now a lobbyist for utilities and the coal industry, during a panel discussion that opened the Organization of PJM States Inc. annual meeting last week.

clean power plan — Holmstead, Bracewell & Guiliani © RTO Insider

“I had my concerns about [the Mercury and Air Toxics Standards]; I had concerns about [the Cross-State Air Pollution Rule]; but I was pretty confident they would be upheld in court. … But this rule is completely different from anything that EPA’s ever done before. … If this gets to the Supreme Court, there are right now almost certainly five justices that would vote to overturn it.”

Although the court has said EPA can regulate CO₂emissions, Holmstead said, the agency must do so by setting an emission rate based on the best technology available. “It cannot require an existing source to go out and pay another entity to do something else that has nothing to do with the particular plant,” he said.

“The only program I think that would clearly withstand judicial scrutiny would be an inside-the-fence line, efficiency-based approach. The reason EPA didn’t do that is because it doesn’t get you very much,” he said. “The reason they’ve taken this big, legally vulnerable step is because that’s the only way they thought they could get meaningful reductions.”

Holmstead — who served in both Bush administrations and now lobbies for Arch Coal, Southern Co. and Duke Energy as head of the environmental strategies group at Bracewell & Giuliani — is hardly a neutral observer. He is loathed by environmentalists, with Greenpeace labeling him “King Coal’s Mercury Pollution Lobbyist.”

But none of the other members of the panel — which included PJM’s Mike Kormos and officials from Exelon, American Electric Power, the American Wind Energy Association and the Southern Environmental Law Center — challenged Holmstead’s legal analysis, although some questioned his prediction that a Supreme Court ruling could come by the end of 2017.

(At a conference in Washington Tuesday, EPA Associate Assistant Administrator Joseph Goffman said the rule’s building blocks – which include increased dispatch of natural gas plants and renewables – “reflect what states and utilities told us was the ‘Best System of Emission Reduction.’”)

Holmstead pointed to four dates that will determine the rule’s fate:

In the first quarter of 2016, he said, a decision is likely by the D.C. Circuit Court of Appeals on requests for a stay (highly unlikely, he acknowledges).

The next milepost will be the 2016 presidential election. “The [EPA] administrator and the administration have been telling people around the world that once this regulation is finalized it will be very hard for anyone to change it. It becomes a part of the law and what’s done is done,” he said.

“There are some rules that are very difficult for a new administration to change, for legal reasons or practical reasons. But this is not one of those regulations. So I can say with some confidence that if there is a Republican administration … the rule will fairly quickly be revoked.”

Holmstead sees a D.C. Circuit court ruling on the merits of the rule by the end of 2016 because the Obama administration has said it wants to defend it before the president leaves office.

Because of the expedited schedule, a Supreme Court ruling could come by the end of 2017, he said, though others say 2019 is a more realistic timeline.

And if the rule is thrown out?

“At that point we’re probably all back on Capitol Hill talking about legislation,” he said. “And the good thing about legislation of course is that it really does provide you much more certainty.

“The fact that EPA will ultimately likely regulate [carbon] regardless of how this rule comes out doesn’t tell you very much about your future investment decisions. Because you just don’t know if EPA can do anything that’s at all aggressive.”

October 20, 2015

ERCOT Releases Updated CPP Analysis

By Tom Kleckner

ERCOT last week released an updated analysis of the Clean Power Plan’s impacts on the Texas grid’s reliability, saying the Environmental Protection Agency’s final rule could result in the retirement of at least 4,000 MW of coal-fired generation, beginning as soon as 2022.

Warren Lasher, ERCOT’s director of system planning, said while the 4,000 MW represents only 6 to 7% of the grid’s total generation reserves, losing that capacity in too short of a timeframe would threaten the target reserve margin (13.75%).

“Coal retirements may happen sooner if owners have to make capital investments to comply with other plans,” Lasher said, noting the current reserve margin is 16%. “One of our concerns is the potential for all the units to retire in too short period of time.”

ERCOT said the changes could also increase retail power prices by up to 16% by 2030, based on an increase in the marginal price indicator. That doesn’t include the costs of new transmission projects or other investments that could be needed to support compliance.

“Unit retirements may lead to reduced reliability of the system in localized areas, as new transmission lines will be needed to connect customers to new generating,” Lasher said, noting it takes about five years to build transmission lines in Texas.

ERCOT’s analysis considers the CPP’s effects based on mass-based approaches to achieve the region’s emissions targets by modeling four scenarios:

Baseline: reflects current trends in the ERCOT region and market while considering announced retirements and current regulatory requirements;
CO₂limit: considers a system limit on emissions that allows the model to select the lowest-cost resource option without regard to market design or other considerations associated with implementation;
CO₂ price: estimates a price for CO₂ emissions that would cause the ERCOT region to achieve the compliance targets; and
CO₂ price/regional haze: also estimates a CO₂ price, but models the combined impacts of the CPP and the proposed Regional Haze Federal Implementation Plan within the ERCOT region as well.

ERCOT’s 4,000 MW of coal retirements would increase to about 4,700 when regional-haze requirements are taken into consideration.

“ERCOT focused on high-level reliability concerns, consistent with our reliability role in Texas,” Lasher said.

The scenarios that take into consideration a CO₂ price indicate more than 14,000 MW of utility-scale solar, 9,000 MW of wind capacity and nearly 3,000 MW of new gas-fired combustion turbines would have to be added to achieve compliance.

“Integrating intermittent renewables can be a challenge,” Lasher said. “Increased storage capabilities on the system would increase its ability to integrate renewables … that would be an additional tool.”

The ERCOT study only looks at the 85% of the state it is responsible for, leaving out East Texas, the Panhandle and El Paso areas.

October 20, 2015

MISO Planning Advisory Committee Briefs

The Planning Advisory Committee wrapped up stakeholders’ review of the draft 2015 MISO Transmission Expansion Plan with a vote of support last week. The System Planning Committee will consider the plan in December.

MTEP15 contains about 352 transmission projects valued at a total of about $2.4 billion. (See MISO Proposes $2.4 Billion in Transmission Projects.)

The approval comes amid continuing stakeholder discussion on revamping the MTEP economic planning process.

Durgesh Manjure, MISO’s manager of resource adequacy coordination, said the annual process typically begins in September and lasts until March or beyond. MISO has suggested a three-year cycle to replace the annual process and holding dedicated stakeholder workshops instead of setting MTEP planning as an agenda item. He said the reworking puts into question whether MISO should spend “six to nine months every year” of stakeholder time and energy devising the MTEP.

“There would be some work involved both on the MISO side and the stakeholder side,” Manjure said of the changes, which would be implemented beginning with MTEP17. (See MISO Planning Advisory Committee Briefs.)

The committee proposes conducting a review at the beginning of an MTEP cycle to see if the economic and policy landscapes are still properly represented, then reusing unaffected futures information. The panel also favors reusing resource expansion and siting data in subsequent PROMOD models, while updating the transmission topology annually.

MISO to Provide Clean Power Plan Scenarios in Analysis

MISO officials are still at work providing an impact analysis on how states will be affected by the Clean Power Plan. States have until 2018 to finalize plans under the rule.

“It’s necessary to start sooner than later because of long lead time on transmission projects,” said Jordan Bakke, senior policy studies engineer at MISO, who provided the PAC with a CPP analysis.

Bakke has worked on developing modeling assumptions and futures definitions. Through mid-2016, MISO plans to model transmission futures and sensitivities, with consideration given to state plans. Bakke said the PAC will turn to states, stakeholders and experts for feedback.

In its analysis, MISO examined the effects of both a partial and an accelerated CPP rollout. The model for a partial CPP implementation projects a 17% reduction in emissions by 2030 from 2005 levels. An accelerated CPP implementation would bring a 43% reduction. The final CPP rule calls for a 32% reduction.

“There are so many options available for states … that we really need to provide more certainty,” Bakke said.

The second round of stakeholder feedback included requesting detailed models of Environmental Protection Agency compliance options using both rate- and mass-based emission limits, allowances, set-asides, interstate trading and treatment of leakage. Stakeholders also asked that MISO re-evaluate the level of plant retirements, energy efficiency and penetration of solar and wind resources in the findings.

“We want as much feedback as possible. This is a very complex issue, and we don’t want to make stuff up,” Bakke said.

A final scope of study will be revealed at November’s PAC meeting.

— Amanda Durish Cook

October 20, 2015

SPP Strategic Planning Committee Briefs

LITTLE ROCK, Ark. — The Strategic Planning and Finance committees are collaborating on an effort to establish an operating plan that will create “line of sight from the strategic plan down to the budget,” said Michael Desselle, SPP vice president and chief compliance and administrative officer.

“It will ultimately drive what we do as an organization,” Desselle told the SPC and the Markets and Operations Policy Committee last week. “Doing this annually will add clarity and show us where we stand financially, with our budget items and our expense categories.”

The operating plan is linked to the strategic plan’s initiatives in three ways: 1) staff projects such as the enhanced combined-cycle and gas-electric harmonization; 2) technological investments that help achieve the projects; and 3) the business-as-usual, keeping-the-lights-on everyday work.

The plan will prioritize projects by categorizing them as mandatory projects that will spend their budget allocations; optional projects that might spend their budget; or projects that can be canceled should the first two categories need the money.

SPC Expands Committee by 2 Members

The SPC unanimously approved a recommendation to revise its charter to add two members, reflecting the recent addition of the Integrated System.

“There is enough of a reason, with the variety of members in the [Integrated System], to add one transmission owner and one transmission customer,” Desselle said. He said the governance committee will work to maintain geographical diversity and the proper mix of size and member types.

The SPC currently numbers 11 members: four transmission-owning and four transmission-using representatives, and three from the Board of Directors.

The SPC forwarded its recommendation to the Corporate Governance Committee for consideration.

SPP Continues Talks with Western Neighbors

SPP’s Carl Monroe told the committee there are “ongoing talks with our western neighbors,” but no serious discussions about potential new members.

SPP has an ongoing market-consulting contract with the Northwest Power Pool, which has been exploring the possibility of opening an energy market for several years. Two of the NWPP’s members, Puget Sound Energy and Portland General Electric, recently announced their intention to join CAISO’s energy imbalance market, though, as Monroe noted, Portland General is “considering all options.”

SPP’s membership will increase to 94 on Jan. 1, when Tri-State Generation and Transmission Association Cooperative and Central Power Electric Cooperative join the RTO. SPP currently has 166 active market participants.

– Tom Kleckner

October 20, 2015

FERC Again Rejects Price Suppression Argument in Ginna Dispute

FERC ruled on Thursday for the third time that an allegation of “price suppression” in the capacity market was outside of the scope of an ongoing proceeding to review a proposed agreement to prop up the struggling R.E. Ginna nuclear power plant in New York (ER15-1047).

NYPSC Approves 5.2% Ginna Rate Surcharge.)

Because the rehearing order reaffirmed FERC’s stance on the price suppression issue in its original order on Ginna, “we find that TC Ravenswood’s request for rehearing is improper and we will dismiss it,” the commission said.

– William Opalka

October 20, 2015

Artificial Island Generates Sparks in OPSI Discussion

By Rich Heidorn Jr.

BALTIMORE — Delaware Public Service Commission Chairman Dallas Winslow took on PJM planners over the Artificial Island project and rival developers sparred over the enforceability of cost caps at a panel discussion on Order 1000 implementation at last week’s Organization of PJM States Inc. annual meeting.

Opening up the session, PJM Vice President for Planning Steve Herling talked about how Order 1000 has increased planners’ workload and noted how cost allocation, “previously an end result of the process, is now getting fed into the process at the beginning.”

A slide in Herling’s presentation elaborated, saying that stakeholders are attempting “to influence our decision-making based on who will pay rather than which project is the most cost-effective.”

artificial island — Commissioner Winslow, DE PSC © RTO Insider

That didn’t sit well with Winslow. “I’m not sure a project can be cost-effective if it doesn’t cost the appropriate parties the burden of what they’re benefitting from,” he said.

Winslow called for a show of hands from other state regulators, asking: “What state in the room here would agree to pay voluntarily a cost allocation that made you pay 80% of the cost when you got 20% of the benefit?”

No one raised their hand.

While he didn’t mention the project by name, Winslow’s comments were a clear reference to the dispute over the cost allocation for the Artificial Island stability project.

Because the project is considered a lower-voltage facility, the cost of LS Power’s plan — running a new 230-kV circuit from Salem, N.J., under the Delaware River to a new substation near the 230-kV corridor in Delaware — is being allocated almost entirely to Delaware and Maryland customers.

In an Oct. 9 filing in response to complaints from those states, PJM acknowledged that the cost allocation may “appear disproportionate” but took no position on whether FERC should reconsider the use of solution-based distribution factor (DFAX) methodology for divvying up the bill on such projects (EL15-95). (See PJM: Artificial Island Cost Allocation Appears ‘Disproportionate.’)

Winslow called on PJM and its stakeholders to address the equity issues he said were raised by the dispute.

“There are times when you’ve got to stand up and say ‘is this is fair or not?’” Winslow said. “Should we just kick it down the road to Washington D.C.? Or should there be a mechanism to address what clearly and objectively is a violation of law?”

Cost Cap

Last year, PJM planners recommended Public Service Electric & Gas be selected to construct a different solution for Artificial Island. PSE&G’s winning proposal was estimated at $1.066 billion before planners eliminated two 500-kV lines from it.

Facing a barrage of criticism, PJM’s Board of Managers rejected the proposal and reopened the project, allowing PSE&G and two other finalists to revise their proposals in response to LS Power’s offer to cap its project cost at $171 million — $40 million to $90 million less than the PSE&G project.

After months of additional study and debate, the board awarded the project to LS Power, with smaller portions of the work to be done by PSE&G and Pepco Holdings Inc. (See PJM Board OKs LS Power’s Artificial Island Project Despite Objections.)

The bitter feelings over that battle were apparent at the panel discussion as Jodi Moskowitz, senior director of transmission development and strategy for PSE&G, suggested a developer might be able to recover costs above its cap if it can be shown to have acted prudently.

“FERC has yet to approve a cost cap coming out of an Order 1000 process. So we’re not sure at this point if cost caps are in fact legally enforceable,” she said.

She noted that ITC Holdings has asked FERC for guidance on whether a cost cap constitutes a just and reasonable rate. Because the commission hasn’t ruled, she said, “it is still very much an open question.”

LS Power’s Sharon Segner insisted the cap it agreed to was enforceable, saying it will be included in the designated entity agreement with PJM.

Workload Increasing

Herling said the volume of transmission proposals unleashed by Order 1000 has strained PJM’s resources.

“Most reliability projects — 90% or more — are solved by relatively simple upgrades to existing infrastructure. And we would typically have worked in a collaborative fashion with the transmission owner to identify one or two options to solve that problem,” he said. “Now we’re getting four, five, six — as many as 26 — proposals to solve a given problem.”

Herling said it added to the workload of not only the planners conducting the analyses but also the RTO’s legal and finance staff, who help administer the process.

Herling noted that CAISO and SPP have sought to reduce the workload by eliminating the sponsorship approach: “Simply pick the best solution and put it out for bid.”

But he said PJM wasn’t willing to abandon the sponsorship model yet. “We see a lot of value in the sponsorship process,” he said.

October 20, 2015

FERC Denies NSTAR Market Power Complaint

By William Opalka

FERC on Thursday denied rehearing of its approval of Constellation Energy’s acquisition of five New England power plants, a deal proposed five years ago (EC10-85).

NSTAR Electric challenged the sale of five power plants in the Boston area worth about 2,654 MW from various entities to Constellation for $1.1 billion. The sale represented about 8% of the generation fleet within the ISO-NE footprint at the time.

NSTAR claimed that the deal would harm competition in the New England energy market. FERC, however, approved the transaction as in the public interest.

NSTAR requested a rehearing, saying in part that two gas-fired plants originally owned by Mystic Power were susceptible to common mode failure because they both depended on a connection to a Distrigas liquefied natural gas terminal for their fuel. This condition, NSTAR said, could lead to the simultaneous loss of fuel supply, which would drive up consumer costs due to an increased reserve requirement by ISO-NE.

FERC in its order last week said this infrastructure issue was outside of the scope of the acquisition and noted that a 2006 settlement regarding the issue imposed conditions on the plant owners and subsequent buyers.

While the FERC docket for the case has been dormant since June 2011, when Constellation filed a response to NSTAR’s complaint, the companies have undergone significant changes of their own.

Original plaintiff NSTAR merged with Hartford, Conn.-based Northeast Utilities in April 2012 to create the region’s largest distribution utility that has since been renamed Eversource Energy.

Constellation was acquired by Exelon in March 2012. In 2014, Exelon sold one of the plants in the original deal, the 688-MW Fore Generating Station, to Calpine for $530 million, marking that company’s entry into New England.

October 20, 2015

FERC Sets Hearings for Entergy’s Cost Allocations

By Tom Kleckner

FERC last week set Entergy Corp.’s ninth annual allocation of its operating companies’ 2014 production costs for hearing and settlement procedures (ER15-1826).

As it has in years past, FERC said Entergy had not proven its proposed rates were just and reasonable. It accepted the proposed rates and made them effective June 1, 2015, subject to refund pending the hearing and settlement procedures.

The commission also issued three orders in long-running disputes regarding Entergy cost allocations for a portion of 2005, setting one issue for hearing and settlement procedures and rejecting two rehearing requests.

Bandwidth Remedy

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 has different operating costs.

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

Regulators in Entergy’s states have regularly challenged the annual bandwidth filings. Entergy’s proposed rates for 2014 drew protests from the New Orleans City Council and the Louisiana and Texas commissions.

FERC gave the administrative law judge overseeing the case discretion to combine the proceeding with the previous four years of disputed annual cost-allocation cases, which were consolidated in December. (See FERC Bundles Entergy ‘Bandwidth’ Disputes for Hearing.)

2005 Calculations

The three other orders concern Entergy’s first cost-allocation calculations, for a seven-month period in 2005.

It denied a request from the Arkansas commission to exclude Entergy Arkansas from making payments and an Entergy compliance filing for hearing and settlement procedures (EL01-88-013).

FERC had rejected a 2011 compliance filing because it used six months of data to recalculate the seven-month period. The company responded with a more comprehensive recalculation report it said were based on the actual books and records of each operating company.

The New Orleans City Council and the Arkansas and Louisiana commissions all protested. The Arkansas Public Service Commission argued the compliance filing should be rejected because it assumed Entergy Arkansas would make further bandwidth payments, even though the company had withdrawn from Entergy Corp.’s system agreement in December 2013.

FERC said that it had never indicated that Entergy Arkansas should be exempt from the bandwidth calculations for that period.

Interest Payments Required

The commission also rejected the Arkansas commission’s argument that the bandwidth payments — $167.3 million, plus $56.5 million in compounded interest — amounted to “exit fees,” saying the payments were “obligations specifically required by the system agreement and are for a period when Entergy Arkansas was subject to the system agreement.”

(FERC Commissioner Colette Honorable, a former member of the Arkansas PSC, did not participate in the order.)

The commission also denied Entergy’s request for rehearing of an earlier order rejecting a compliance filing (EL01-88-012) and one issued in response to a ruling by the D.C. Circuit Court of Appeals (EL01-88-011), ordering Entergy to include interest on recalculated bandwidth payment amounts from the seven-month period.

FERC disagreed with Entergy’s contention in the compliance-filing request that the commission had failed to adequately explain its decision to require interest. Interest, the commission said, ensures that “the recipient receives payment in inflation-adjusted dollars.”