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May 20, 2018

House GOP Seeks Changes to New Source Review

By Michael Brooks

The House Energy and Commerce Committee last week heard testimony on Republican-backed legislation that could allow power plants and industrial boilers to avoid expensive upgrades under EPA’s New Source Review (NSR) program.

Facilities are subject to NSR if they make non-routine modifications that increase annual emissions; such plants must use the “best available control technology” to minimize the emissions increase.

The bill, written by Rep. Morgan Griffith (R-Va.), would amend the definition of “modification” under Clean Air Act Section 111a to mean any alteration to a facility that increases its hourly pollutant emission rate.

The modification clause does not specify how a facility’s emissions should be measured to determine if a change would result in a pollution increase, which has led to multiple lawsuits since the clause was added in 1970. Under the NSR program, EPA has used a projection of annual emissions based on the modification.

“This type of annual emissions projection approach necessitates the consideration of complex factors such as projecting future demand of the product being produced and the selection of baseline emissions to use as a comparison point,” committee Republicans said in a memo ahead of a Environment Subcommittee hearing on the bill Wednesday. “Additionally, in certain instances, this type of emissions projection results in an overestimation of emissions, which is shown by comparing the projected emissions with a source’s true emissions after the fact.”

The bill would also exempt from NSR any modification that “reduces the amount of any air pollutant emitted by the source per unit of output or is designed to restore, maintain or improve the reliability or safety of the source.” Republicans said that NSR has impeded or canceled projects intended to reduce a facility’s pollution. The law already exempts routine maintenance or repair from review.

Support

At Wednesday’s hearing, Bill Wehrum, assistant administrator of EPA’s Office of Air and Radiation, told the subcommittee that the Trump administration does not have an official position on the bill. “Having said that, I strongly support the overall goals of the discussion draft,” he said. “The principal focus of the discussion draft on refining the definition of ‘modification’ in the Clean Air Act would go a long way towards simplifying application of the NSR program.”

Wehrum praised the bill’s exemption of pollution-reducing additions, noting that, “sometimes, the operation of such equipment, while it results in tremendous emissions reductions for some pollutants, may in some instances actually lead to increases in the emissions of other pollutants.” He said EPA had attempted to implement such a provision but was overruled by the D.C. Circuit Court of Appeals.

Kirk Johnson, senior vice president of government relations for the National Rural Electric Cooperative Association, said NSR has “more often served as an impediment, rather than an enhancement, to maintaining and improving efficiency at power plants.”

“One significant obstacle of the NSR permitting program is its application to equipment repair and replacement as well as even routine maintenance activities at existing generating units,” Johnson said. “Although routine maintenance, repair and replacement are supposedly excluded from being considered as ‘major modifications’ — and thus not subject to NSR — what qualifies as these NSR exemptions often changes with shifting EPA interpretations. This has led to utilities performing what they thought qualified as routine maintenance, repair and replacement, only to be cited for NSR violations years after the fact.”

Opposition

Paul D. Baldauf, assistant commissioner of the New Jersey Department of Environmental Protection, however, said Griffith’s bill could increase out-of-state emissions and extend the life of older generators, causing the state to fall out of attainment for the National Ambient Air Quality Standards (NAAQS). Baldauf cited as an example a generator that undergoes changes to increase its efficiency while also increasing the maximum heat input — the amount of fuel burned per hour — to increase electric output.

“This project would decrease the pounds of CO₂ and some other pollutants emitted per megawatt-hour but would increase the megawatts generated,” he said. “Without additional controls, such a project would result in both increased hourly and annual emissions of all its pollutants, including CO₂, criteria pollutants and air toxics, resulting from the increased fuel use. These increased emissions could likely result in adverse health impacts despite the increase in efficiency of the unit.”

Environmental consultant Bruce C. Buckheit, who served as director of EPA’s Air Enforcement Division during the Clinton and George W. Bush administrations, also opposed the bill. “The draft is not needed by the regulated community for any purpose and would not advance one of the fundamental purposes of the Clean Air Act — to eliminate, over time, the disparate treatment of new and existing sources,” he said. “It would severely impair the ability of the modification rules to effect this purpose and would exacerbate the current barrier to investment in new manufacturing and electric generating facilities created by the difference in the treatment of new and existing facilities.”

Democrats are likely to oppose the bill. “Without a firm requirement that facilities reduce the levels of all the dangerous pollution they emit, they simply will be allowed to pollute more,” Rep. Frank Pallone (D-N.J.), ranking member of the full committee, said in a statement. “That’s what the language in the bill on ‘maximum achievable hourly emission rate’ is all about.”

May 20, 2018

FERC Narrows GHG Review for Gas Pipelines

By Rich Heidorn Jr.

FERC’s Republican majority on Friday narrowed the circumstances under which it will estimate greenhouse gas emissions from natural gas pipeline projects, sparking dissents by its two Democratic commissioners.

The commission unanimously rejected a rehearing request by conservation organization Otsego 2000, which contended FERC had not conducted a sufficient environmental review in its 2016 approval of Dominion Energy Transmission’s New Market Project. The project includes two new compressor stations and upgrades to three others in upstate New York (CP14-497-001).

ferc ghg emissions gas pipelines richard glick cheryl lafleur — Wetland at existing Borger Compressor Station | *Dominion Transmission*

But Democrats Cheryl LaFleur and Richard Glick dissented from the commission’s declaration that it will no longer prepare upper-bound estimates of GHG emissions when “the upstream production and downstream use of natural gas are not cumulative or indirect impacts of the proposed pipeline project.” They instead contended the decision effectively eliminates any consideration of GHG emissions associated with a project.

Republicans Kevin McIntyre, Neil Chatterjee and Robert Powelson said they were taking the action to “avoid confusion as to the scope of our obligations under [the National Environmental Policy Act] and the factors that we find should be considered” when determining whether a project is in the public convenience and necessity under the Natural Gas Act.

NEPA requires FERC to prepare an environmental impact statement for pipelines that may significantly impact the environment but allows for a less detailed environmental assessment if it determines the project is not likely to have significant adverse effects.

Notice of Inquiry

In separate partial dissents, LaFleur and Glick said they were disappointed that the majority initiated the policy shift just a month after issuing a Notice of Inquiry to reconsider the commission’s 1999 policy statement on gas pipeline permitting (PL18-1). (See FERC Outlines Gas Pipeline Rule Review.)

LaFleur said the new policy reverses the commission’s practice since late 2016 of including more information on upstream and downstream GHG emissions in its pipeline orders. That included “upper-bound” estimates of downstream emissions that assumed all the gas transported by the project would be burned for electric generation, heating and other purposes.

“The commission placed caveats on the information and analysis, stating generally that the downstream impacts do not meet the definition of an indirect impact and are not mandated as part of the commission’s NEPA review,” LaFleur acknowledged. “The commission nonetheless made a full-burn calculation to determine an upper-bound GHG emissions amount, unless it had specific information to calculate net and gross GHG emissions.”

The commission used Department of Energy studies for generic estimates of the impact of projects on upstream natural gas production, including production-related GHG emissions.

LaFleur said the commission’s obligations increased under the D.C. Circuit Court of Appeals’ August 2017 Sabal Trail ruling, which found that the emissions resulting from burning the natural gas transported by a commission-approved project are an indirect impact. (See FERC Must Consider GHG Impact of Pipelines, DC Circuit Rules.)

“Today, however, the majority has changed the commission’s approach for environmental reviews to do the exact opposite. Rather than taking a broader look at upstream and downstream impacts, the majority has decided as a matter of policy to remove, in most instances, any consideration of upstream or downstream impacts associated with a proposed project,” LaFleur wrote. “The majority’s reasoning for excluding the information and calculations is generally that it is inherently speculative and does not meaningfully inform the commission’s project-specific review. I disagree.

“At a time when we are grappling with increasing concern regarding the climate impacts of pipeline infrastructure projects, the commission should not change its policy on upstream and downstream impacts to provide less information and be less responsive,” she added.

‘Remarkably Narrow’

Glick criticized the majority for what he called a “remarkably narrow view of its responsibilities under NEPA and the NGA’s public interest standard.”

“The principal reason that the commission does not have … ‘meaningful information’ [on GHG impacts] is that the commission does not ask for it,” Glick said, noting that FERC could require pipeline developers to provide information about the source of the gas to be transported and its end use.

“A simple data request would seem to fall easily within what constitutes the commission’s ‘best efforts,’” Glick said. “In the absence of any such efforts, the commission should not be able to rely on the lack of ‘meaningful information’ to satisfy its obligations under NEPA and the NGA to identify the reasonably foreseeable consequences of its actions.”

“There will undoubtedly be some cases where those emissions are, in fact, too speculative to be considered ‘reasonably foreseeable,’” he continued. “But there may also be others, such as Sabal Trail, where an adequate record would provide sufficient information to make those emissions reasonably foreseeable.”

Glick said he was not suggesting that the commission stop approving new pipeline projects. “What I am arguing is that, as a result of the commission’s new policy, we frequently will not know whether the benefits outweigh the costs because the commission is not asking enough questions or doing enough analysis.”

Dissents ‘Mischaracterize’ Shift

The majority said the dissents “mischaracterize” the policy shift as changing the commission’s public interest and environmental review.

“Our decision does not in any way indicate that the commission does not consider, or is not cognizant of, the potentially severe consequences of climate change,” the majority wrote. “We will continue to analyze upstream and downstream environmental effects when those effects are sufficiently causally connected to and are reasonably foreseeable effects of the proposed action.”

They also said the order does not “prejudge or preclude the [commission] from considering the questions on greenhouse gas emissions posed in the Notice of Inquiry.”

The Republicans said that even if the commission presumed a causal relationship between the New Market Project and upstream production, “the scope of the impacts from any such production is too speculative and thus not reasonably foreseeable.”

“Neither the commission nor the applicant generally has sufficient information to determine the origin of the gas that will be transported onto a pipeline. We disagree with the dissent’s assertion that we lack information about specific upstream production or downstream uses simply because we ‘did not ask for it.’ To be clear, the commission only has jurisdiction over the pipeline applicant, whose sole function is to transport gas from and to the contracted for delivery and receipt points. While the shippers might contract with a specific producer for their gas supply, the shipper would not know the source of the producer’s gas, and, for that matter, producers are not required to dedicate supplies to a particular shipper and thus likely will not know in advance the exact source of production. In short, ‘just ask[ing] for it’ would be an exercise in futility.”

May 18, 2018

UPDATED: PG&E Transmission Revenue Complaint Rejected Again

By Rory D. Sweeney and Michael Kuser

FERC on Thursday rejected a second attempt by several Pacific Gas and Electric transmission customers to potentially receive a larger-than-normal refund related to a rate increase the utility submitted in 2016 for its 18th transmission owner tariff filing (TO18) (EL17-59).

But in a separate decision (EL17-95), the commission also ruled that a complaint by the same customers about PG&E’s TO19 rate filing be subject to hearing and settlement judge procedures and consolidated it with the ongoing proceeding covering the TO18 complaint (ER17-2154).

In EL17-59, the complainants — which include the Transmission Agency of Northern California; the city of Santa Clara; M-S-R Public Power Agency; State Water Contractors; the California Public Utilities Commission; Modesto Irrigation District; and Sacramento Municipal Utility District — had requested a rehearing of FERC’s November denial of their initial complaint over TO18.

While the TO18 rate increase is the subject of an ongoing proceeding on tariff revisions PG&E wants approved (ER16-2320), FERC shut down the complaint and an alternative request for consideration of supplemental evidence. It rebuffed the argument that its initial rejection failed to provide the complainants protection to receive the refund that they argued they could proved justifiable if the complaint was accepted.

FERC PG&E Pacific Gas and Electric Revenue Requirement — FERC rejected a second attempt by transmission customers to potentially receive a larger-than-normal refund related to a California TO’s requested rate increase.

The complaint stemmed from PG&E’s request to increase its wholesale base transmission revenue requirement from $1.319 billion, as set in its previous rate case, to $1.705 billion, and boost its retail base transmission revenue requirement from $1.331 billion to $1.718 billion. The complainants had argued that they could show through discovery that PG&E actually required less revenue than it is already approved to collect, that FERC should allow for refunds below the current $1.319 billion revenue requirement and that their complaint should be consolidated with the rate increase proceeding.

FERC denied the complaint, saying the complainants failed to show that their proposed rate adjustments would result in a revenue requirement below $1.319 billion, leaving the standard refund protection intact. The complainants responded that not providing them the opportunity to prove their case through discovery in the proceeding “arbitrarily and capriciously deprived” them of protections in the Federal Power Act, but FERC said they must show evidence of the problem as part of the complaint, not ask the commission to trust them to prove it later.

FERC also rejected an alternative request, which asked the commission to consider evidence from PG&E’s ongoing tariff proceeding.

“The commission’s longstanding policy is to not accept additional evidence at the rehearing stage of a proceeding, absent a compelling showing of good cause,” it said. “Because other parties are precluded … from filing answers to requests for rehearing, allowing complainants to introduce new evidence at this stage would raise concerns of fairness and due process for other parties to the proceeding.”

TO19 Complaint

The commission accepted PG&E’s TO19 filing last September but suspended it for five months to become effective on March 1, 2018, subject to refund and the establishment of settlement judge procedures.

In EL17-95, the complainants alleged that PG&E failed to justify the proposed TO19 rate increase, which forecast a retail network transmission revenue requirement of $1.8 billion and a wholesale network transmission revenue requirement of $1.78 billion.

The complainants contended that PG&E overstated its proposed rates with inappropriate expenses, an excessive wholesale network transmission revenue requirement; a return on equity inconsistent with commission precedent; and an excessive composite depreciation rate. They claimed the utility failed to be transparent on expenses and made errors in its capital structure and cost of debt that require adjustment.

They also said that formal discovery should provide for additional adjustments to reduce PG&E’s rates below the last clean rate established in the TO17 settlement.

Complainants alleged that reducing PG&E’s proposed rates by $511.4 million, based on supporting materials, would bring the final rate below the last clean rate.

In addition, the amended complaint alleged the need to reduce PG&E’s federal corporate income tax rate from 35% to 21%, consistent with the recently enacted Tax Cuts and Jobs Act, which it said effectively made PG&E’s TO19 rate unjust and unreasonable.

PG&E countered that the complainants should not be allowed to attack the settled TO17 rate, that granting the complaint will make reaching a settlement in future rate cases more difficult and would be contrary to the policy behind the last clean rate doctrine.

Specifically, PG&E said that the last clean rate doctrine “prevents retroactive ratemaking and avoids penalizing a company for filing a rate increase,” which would happen if the commission granted the complaint.

PG&E also argued that complainants failed to carry their burden of proof under Section 206 of the FPA.

The commission’s May 17 order found “that the complaint raises issues of material fact that cannot be resolved based on the record before us.”

“We are unpersuaded by PG&E’s arguments that complainants have failed to meet their burden under Section 206 of the FPA, and find that complainants’ allegations, as amended, are sufficient to initiate an investigation into PG&E’s rates,” the commission said.

FERC emphasized “that we are not here making a finding on the merits of complainants’ arguments in their amended complaint; rather, we are simply finding that complainants have made a prima facie case warranting further investigation by providing sufficient support for their allegation.”

The commission said it was likewise unpersuaded by PG&E’s policy arguments.

“Specifically, we find that the complaint does not request that the commission reject the settled TO17 rates, nor does it seek to undo the results of any compromise reflected among the parties to the settlement,” it said.

The TO17 rates were in effect from March 1, 2016, through Feb. 28, 2017, when they were superseded by PG&E’s proposed TO18 rates, and therefore remain unaffected by this complaint for that period, the commission said.

“Here, complainants are using new data provided by PG&E in its TO19 rate case to allege that PG&E’s TO19 rates are overstated to such an extent that the final just and reasonable rates will be below those agreed to in the TO17 rate case,” the commission said. “The TO17 rates are thus relevant only to the extent that they establish the last clean rate and the floor below which additional refund protection is necessary.”

Based on its review of the record, the commission expects that the presiding judge should be able to render a decision within approximately 12 months of the commencement of hearing procedures, or May 17, 2019.

“Thus, we estimate that, absent settlement, we would be able to issue our decision within approximately 12 months of the filing of briefs on and opposing exceptions, or by July 17, 2020,” the commission said.

May 18, 2018

FERC Pushes NERC Further on GMD Rules

By Rich Heidorn Jr.

FERC took another step Thursday in its efforts to protect the grid from geomagnetic disturbance events (GMDs), proposing to approve a revised reliability standard but directing NERC to also require mitigation of vulnerabilities to localized events (RM18-8).

The commission’s Notice of Proposed Rulemaking would approve reliability standard TPL-007-2 (Transmission System Planned Performance During Geomagnetic Disturbances), which revises the definition of GMDs, requires grid operators to collect certain data and imposes deadlines for corrective actions, as the commission directed in Order 830 in 2016. (See FERC Approves GMD Reliability Standard.)

Supplemental GMD Event FERC NERC — GMD storm in Fairbanks, Alaska, April 2011 | *NASA*

GMDs occur when the sun ejects charged particles that cause changes in the earth’s magnetic fields, potentially causing geomagnetically induced currents that can cause voltage instability or collapse and damage connected equipment.

The rule would require planning coordinators and transmission planners to conduct supplemental GMD vulnerability and thermal impact assessments that go beyond NERC’s original “benchmark” GMD event definition that is based on spatially averaged data.

NERC defined the “supplemental” GMD event using individual station measurements rather than spatially averaged measurements, acknowledging that geomagnetic fields during severe GMD events can be “spatially non‐uniform” with localized peaks that could affect reliability.

The supplemental GMD event is defined by a “reference peak geoelectric field amplitude” of 12 V/km versus the 8 V/km used in the original spatially averaged definition. Both are intended to reflect a one-in-100-year occurrence and use scaling factors to account for local geomagnetic latitudes and earth conductivity. They also employ a “locally enhanced reference geomagnetic field time series or waveform” to analyze the impact of the GMD on equipment.

Mitigation Directive

NERC’s standard requires mitigation of vulnerabilities to the benchmark event, setting a one-year deadline for the completion of corrective action plans and two- and four-year deadlines to complete mitigation actions involving non-hardware and hardware mitigation, respectively.

But NERC rebuffed FERC’s call for mitigation of risks from supplemental events. NERC’s proposed standard would only require applicable entities to make “an evaluation of possible actions designed to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s)” if a supplemental GMD event is assessed to result in cascading outages.

NERC told FERC that its standard drafting team determined that requiring corrective action plans in response to supplemental GMD event vulnerabilities was premature because the supplemental definition is based on small number of observed events “that provide only general insight into the geographic size of localized events during severe solar storms.” NERC also said current tools are inadequate to realistically model localized events.

But the commission said NERC’s position ignored its directives in 2013’s Order 779, which were reiterated in Order 830.

“NERC’s proposal to modify the benchmark, but then allow applicable entities the discretion to take corrective action based solely on the results of the spatially averaged benchmark analysis while taking under advisement (‘an evaluation of possible actions’) the results of the supplemental assessment, does not satisfy the clear intent of the commission’s directive. …

“We are not persuaded by NERC’s reasoning that … existing technical limitations, specifically the limited number of observations used to define the supplemental GMD event and the availability of modeling tools to assist entities in assessing vulnerabilities, make requiring mitigation premature at this time.”

Deadline Extensions

NERC also diverted from Order 830’s directive that it consider extensions of the corrective action deadlines on a case-by-case basis.

Instead, NERC would allow entities to unilaterally revise their corrective action plan if events beyond its control — such as delays from regulatory and stakeholder processes, equipment lead times or inability to acquire rights of way — prevent implementation within the original timetable.

“Given the complexities and potential novelty of steps applicable entities may take to mitigate the risks of GMDs, we agree with NERC that there should be a mechanism for allowing extensions of corrective action plan implementation deadlines,” FERC said. “However, we would like to avoid unnecessary delay in implementing protection against GMD threats.”

The NOPR seeks comment on whether the standard should permit these “self-declared extensions” or be revised to require NERC’s case-by-case approval. “Under either option, the commission proposes to direct NERC to submit a report regarding how often and why applicable entities are exceeding corrective action plan deadlines,” FERC said.

May 18, 2018

FERC Keeps Eye on ERCOT, CAISO as Hot Summer Approaches

By Michael Brooks

WASHINGTON — FERC will be closely monitoring ERCOT and Southern California for reliability issues this summer as most of the country faces the likelihood of above-normal temperatures, staff said at the commission’s open meeting Thursday.

Both regions lie in a portion of the Western U.S. expected to be warmer than usual, according to the National Oceanic and Atmospheric Administration. But each faces a unique challenge.

FERC’s summer reliability assessment report shows that ERCOT has a 10.92% reserve margin — compared to a 13.75% reference level — in the wake of about 4.5 GW in coal-fired generation retirements last winter and construction delays for about 2.1 GW in new resources. However, the grid operator has assured stakeholders there is no reason for alarm, noting that the current expected reserve margin is up from the 9.3% originally projected in December. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)

“ERCOT expects to have sufficient operational tools to manage tight reserves and maintain system reliability,” FERC noted. “Those operational tools include deploying ERCOT-contracted load resources and emergency response services, using a previously mothballed unit expected to return to service in May 2018, requesting power across the existing DC ties, calling on generating resources that can switch between the Eastern Interconnection and ERCOT, and block-load transfers with SPP and MISO.”

Although FERC does not regulate ERCOT, Chairman Kevin McIntyre said the commission would be watching to see how the grid operator deals with any problems that arise.

Meanwhile, several disruptions to Southern California’s natural gas pipeline network mean CAISO will not be able to depend on natural gas generation to make up for a decrease in hydropower because of a lack of snowfall last winter. The state reached just 57% of normal snowpack, according to FERC, and the higher temperatures will reduce the level more quickly than normal.

CAISO ERCOT FERC Summer Reliability Assessment — Summer 2018 Outlook | *NOAA*

Operations at the Aliso Canyon gas storage facility outside Los Angeles are still limited. While the California Public Utilities Commission last week allowed Southern California Gas to temporarily increase injections, it denied a request to increase the facility’s allowable capacity. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)

In his comments on the report, FERC Commissioner Robert Powelson said, “I am deeply troubled by California policymakers’ refusal to support Aliso Canyon as a reliable storage facility to deal with critical backup storage, not only at the [local distribution company] level, but more towards merchant power resources in the market. … We’re getting away from economic dispatch, and we’re causing tremendous cost to consumers in the California marketplace.”

Further complicating California’s situation is the anticipated near-record-breaking demand for gas across the U.S. The Energy Information Administration expects gas burn to average 35.16 Bcfd in June-August, just 0.3 Bcfd less than the record set in 2016 and 3 Bcfd more than last year, FERC said.

“The addition of over 16,000 MW of new capacity to the natural-gas fired generator fleet since the record highs in 2016 and relatively low natural gas prices contribute to expectations for strong natural gas generation this summer,” the report said. As of March 23, Henry Hub summer futures prices were $2.76/MMBtu, down 52 cents (16%) compared to last year, according to Intercontinental Exchange.

McIntyre said that “on my personal to-do list is to drill further into” whether there’s anything more FERC can do to address California’s challenges with gas.

On May 9, CAISO warned that it this summer faces a 50% chance of a Stage 2 emergency, in which customers that have signed up for incentive rates would be required to use less power during peak demand times.

FERC based much of its report on NERC’s summer reliability assessment, which hadn’t been published as of press time.

May 18, 2018

FERC Sets PURPA Review; Powelson Targets 1-Mile Rule

By Rich Heidorn Jr.

FERC will review how it enforces the 1978 Public Utility Regulatory Policies Act, with the commission’s treatment of the 1-mile rule a likely focus, commissioners said Thursday.

Speaking at FERC’s open meeting, Chairman Kevin McIntyre announced FERC would “re-energize” the review it began in 2016 in response to pressure from state regulators and congressional Republicans.

McIntyre noted that the makeup of the commission has changed since its June 2016 technical conference on the law, when Democrats held the majority on the panel. (See FERC Conference Debates PURPA Costs, Purchase Obligations.)

Republicans now hold a 3-2 edge with the additions of McIntyre and Commissioners Neil Chatterjee and Robert Powelson.

McIntyre insisted he has “an open mind” on the need for change. He said the “format, scope and timing” of the review are to be determined and that “the process will allow for robust stakeholder input.”

Eager to Act

But Chatterjee and Powelson made clear they are eager to act.

Powelson called for an “expedited” review, noting the record the commission compiled in the technical conference and the post-conference comments on the 1-mile rule — the presumption that generators beyond 1 mile of each other are separate facilities.

In its request for comments following the technical conference, FERC asked for input on whether the 1-mile presumption should be made rebuttable and whether the burden of proof should fall on the interconnecting utility or the qualifying facility. It also asked whether it should set minimum contract length or other provisions in PURPA purchase contracts (AD16-16). Despite continued grumbling by Congress and state regulators, the commission made no rule changes following the inquiry.

Kevin McIntyre Robert Powelson PURA FERC — FERC ruled in January 2016 that Entergy did not have to purchase power from Occidental Chemical’s Taft plant in Louisiana because the PURPA generator had unconstrained transmission access and could sell its output in the MISO wholesale market. | *Occidental Chemical*

“There are things we know full well — from the 1-mile rule to QF reform — that we can address rather quickly,” said Powelson, who noted his background as a former “impatient” Pennsylvania regulator.

“This is an issue that has been top of mind to me since coming to the commission,” Chatterjee said. “Today’s energy landscape is profoundly different from that of the late 70s when PURPA was enacted. And because of this, many have rightly voiced their desire for a fresh look at existing policy.”

Still Important for Developers

Democratic Commissioner Richard Glick said he was open to the review but insisted the law is still needed, despite the growth in renewable generation.

“PURPA has, and continues to play, an important role in promoting competition within the utility sector in ensuring the qualifying facilities have access to the market,” he said. “If we do decide changes to our regulations are in order, we must address the concerns raised not only by industry but also by qualifying facility developers — and there were quite a few concerns that were raised during that 2016 tech conference.”

Democrat Cheryl LaFleur, the only commissioner who remains from the beginning of the commission’s review, gave no indication of her leaning on the topic, saying only that the review is “very timely.”

2005 Amendments, Order 688

The commissioners noted that fundamental changes to the law would require congressional action.

Congress amended PURPA in the 2005 Energy Policy Act, allowing utilities to be relieved of PURPA’s mandatory purchase obligation upon FERC’s finding that QFs have nondiscriminatory access to transmission and energy and capacity markets.

In response, the commission amended its regulations in Order 688 in 2006. The order found that MISO, PJM, ISO-NE and NYISO provided markets that meet the law’s criteria for relief from the purchase obligation. It also established a rebuttable presumption that QFs above 20 MW have nondiscriminatory access to those markets.

In other regions, the commission established a rebuttable presumption that QFs of 20 MW and above have nondiscriminatory access to markets if they are eligible for service under a commission-approved open access transmission tariff.

To prevent gaming of the 20-MW threshold, the commission said it would look beyond the 1-mile rule. “If parties are concerned that a QF has engaged in such gaming with regard to the certification or siting of a particular facility, we encourage those parties to bring their concerns to our attention. In any such proceeding, we will consider all relevant factors, including, but not limited to, ownership, proximity of facilities and whether facilities share a point of interconnection,” the commission said.

Since then, the commission has repeatedly relieved utilities of must-purchase obligations from QFs above the 20-MW threshold.

Complaints Continue

But that did not end complaints over the law. In November 2015, Republican congressional leaders called on FERC to hold a technical conference to “identify any potential administrative or legislative reforms that may be necessary,” noting the falling prices of natural gas and renewable energy since the 2005 amendments. They cited congressional testimony from Berkshire Hathaway Energy complaining that it was required to sign a PURPA contract at rates that are 43% above market prices, costing customers an extra $1.1 billion over 10 years.

Travis Kavulla, vice chairman of the Montana Public Service Commission, told the technical conference that PURPA issues consume more than one-quarter of his commission’s time on electric utility regulation.

Democrats responded to FERC’s notice of the technical conference with a letter to the commission saying the act “remains a singular federal backstop to support renewable energy in parts of the country that may otherwise have significant barriers.”

In December 2017, the National Association of Regulatory Utility Commissioners called on the commission to “align” its interpretation of the act “with modern realities.” NARUC called for new criteria for determining whether a single project has been disaggregated to create multiple QFs under the 20-MW threshold. (See NARUC Calls for PURPA Reforms, Outlines Proposed Changes.)

May 18, 2018June 15, 2023

MISO Cost Allocation Plan Hits Interregional Differences

By Amanda Durish Cook

CARMEL, Ind. — MISO’s proposal to redesign its cost allocation process for market efficiency projects (MEPs) has encountered conflicting stakeholder feedback on how to allocate costs for lower-voltage interregional projects, stakeholders learned Wednesday.

The RTO is proposing to eliminate its footprint-wide postage stamp rate and lower its current 345-kV cost allocation threshold to cover 230-kV MEPs. Staff have said the change would capture a reality in which 230-kV lines are prevalent in the RTO’s footprint, especially in MISO South.

The proposal would also make cost sharing available to projects 100 kV and above along the PJM seam, respecting a 2016 FERC order requiring MISO to lower its voltage threshold to 100 kV for interregional projects with its eastern neighbor. (See Stakeholders Debate MISO Cost Allocation Plan.)

MISO is currently exploring a new option for MISO-SPP small interregional project cost allocation and plans to finalize the cost allocation proposal at the June Regional Expansion Criteria and Benefits Working Group (RECBWG) meeting.

MISO said stakeholders are split over whether it should extend the 100-kV threshold mandated by FERC for MISO-PJM projects to interregional projects with SPP. MISO had originally proposed that both PJM and SPP interregional projects would both be cost shared down to 100 kV.

When the RTO revealed interregional cost allocation details in March, some stakeholders urged it to adopt a consistent 100-kV threshold for internal and interregional projects.

MISO Planning Coordinator Davey Lopez told the RECBWG that stakeholder differences over the issue has prompted the RTO to consider applying a local allocation to SPP interregional projects between 100 kV and 230 kV and a regional allocation to shared projects above those levels.

ITC Holdings’ Cynthia Crane asked why MISO is proposing two distinct interregional allocations based on RTO.

“Some said, ‘well, the seams are different.’ They don’t have to have the same allocation rule,” Lopez said during a May 16 RECBWG meeting.

Missouri Public Service Commission economist Adam McKinnie asked what is significantly different between the PJM and SPP seams.

“I’m not sure that we see something inherently different. We’re just laying out a different option based on stakeholder feedback,” Lopez said.

FERC’s order requires MISO to file an allocation plan for cost-shared interregional efficiency projects with PJM down to 100 kV by Oct. 31.

More Metrics

MISO also told the RECBWG that it is still exploring how to incorporate more benefit metrics into its MEP cost allocation.

The RTO currently uses a single metric, adjusted production cost savings, to determine transmission project cost responsibility among its cost allocation zones.

Director of Strategy Jesse Moser said MISO now seeks to include multiple metrics in the calculation, which will be summed and weighed against the RTO’s 1.25:1 benefit-to-cost ratio requirement to allocate costs on a proportional basis to allocation zones with net positive benefits.

MISO is currently considering using avoided transmission investments as a new potential benefit metric, after obtaining agreement about avoided projects through a stakeholder review. The RTO will finalize more detailed metrics sometime in August.

Market Efficiency Projects MISO FERC Cost Allocation Interregional Projects — Moser | © *RTO Insider*

New Sub-230-kV Category?

MISO is additionally considering a Tariff change that would create a new category of local economic transmission projects below 230 kV, Moser said. The small projects would have the same 1.25:1 benefit-to-cost ratio and benefit metrics as MEPs but cost allocated to the local zone. The new category would likely replace MISO’s current “Economic Other” transmission project category, which is not Tariff-defined and does not have a local cost allocation methodology.

WEC Energy Group’s Chris Plante expressed concern that the new project type could elicit FERC complaints if a lower-voltage project can demonstrate regional benefits but only has access to a local cost allocation.

Some stakeholders said MISO’s suggestion of the new project type provided further evidence for lowering the RTO’s regional MEP voltage threshold to 100 kV.

“This demonstrates that you’re willing to do the analysis on [sub-230-kV] projects,” LS Power’s Pat Hayes said.

Moser said MISO would have to review the project type for unintended consequences.

[Editor’s Note: An earlier version of this story incorrectly reported that MISO and the RECBWG intended to have a final draft of the MEP cost allocation proposal by May 16. The two plan to have a finalized cost allocation plan in June. ]

May 17, 2018

MISO Proposal Aims to Speed Up Queue Process

By Amanda Durish Cook

CARMEL, Ind. — MISO is proposing near-term changes designed to speed up its interconnection queue as it confronts its largest-ever influx of potential generation projects.

The RTO plans to reduce the number of project studies occurring in the first phase of the definitive planning phase (DPP) of the queue and require customers to demonstrate ownership, lease interest or land rights on a project’s site before entering the queue, stakeholders learned during a May 15 Interconnection Process Task Force (IPTF) meeting.

MISO Site Control Interconnection Queue — | *MISO*

MISO Director of Interconnection Planning Vikram Godbole said the proposal constituted “a small set of changes that will be very beneficial to the queue” and that the RTO began working on improvements to the queue last year after FERC accepted its redesign proposal. He said MISO and several customers have been meeting for months to discuss ways to expedite the RTO’s packed pipeline of potential projects.

Godbole said the changes are designed not to harm any existing interconnection customers. They come a month after FERC declined to order MISO to redesign aspects of its relatively new queue process but reminded the RTO of its duty to make a good faith effort to address a worsening backlog of projects. (See FERC Sides with MISO in Queue Design Dispute.)

100% Site Control

MISO is proposing to require interconnection customers to demonstrate 100% site control to the point of interconnection before entering the queue, scrapping the existing option that allows them to submit a $100,000 deposit in lieu of proof of site control. Just 25% of the projects entering the DPP in the April 2018 cycle demonstrated site control, with the rest electing to make the deposit.

The RTO currently requires a customer to demonstrate 75% of site control prior to entering the third — and final — phase of the DPP.

Godbole said the more stringent requirement should prevent unready projects from prematurely entering the first phase of the DPP. It would also prevent customers from submitting multiple, overlapping projects at the same development site, a recurring issue in the current queue, although Godbole declined to identify any specific instances.

“That is just not right, and we need to fix that,” Godbole said.

MISO’s interconnection queue currently contains 554 projects totaling 92.5 GW, including 239 additions last month representing 40.7 GW.

“With 93 GW, everyone needs to have a very realistic expectation of when these projects are going to be able to connect,” Godbole said. “Some of these projects are not going to get built, but how many is anyone’s guess. So MISO … needs to find ways to expedite the process.”

After looking into other RTOs’ practices, MISO found that ERCOT, ISO-NE, NYISO, PJM and SPP require 100% of site control either at entry or before the start of the system impact study, Godbole said.

“We said OK, if interconnection customers in other RTOs are OK with that, they should be OK with that in” MISO’s, he said. “We’ve looked at this from all angles.”

Some stakeholders said that state regulatory requirements can sometimes prevent customers from acquiring site control so early in the process. Godbole responded that in those cases customers would have to provide evidence that regulators are obstructing site control.

Godbole proposed a phased-in approach to requiring site control, with projects already in the queue but not yet studied required to secure 100% of site control requirements by the first decision point in the first phase of the DPP. All other projects would be required to demonstrate an increasing percentage of site control based on their progress.

Studies Reduction

To further accelerate the queue process, MISO is also proposing to eliminate its transient-stability, short-circuit and affected-system studies from the first phase of the DPP.

Removing the early, more uncertain iterations of those studies will result in quicker turnaround times for the first phase of DPP analysis, Godbole said.

In response to the concerns of some stakeholders that affected-system and transient-stability analyses were necessary earlier in the queue to determine the viability of a project, Godbole said that customers could hire an external consultant to conduct first versions of the analyses and pointed out that all three studies will still occur in the DPP’s second and third phases.

Godbole noted that MISO is currently holding monthly meetings with SPP and PJM to improve the affected-system study process, but he added that by removing the first affected-system study, MISO planners will have more time to devote to the more significant second and third studies.

“It’s not SPP, PJM or MISO’s fault. What’s happening is we have entities with three cycles that are just bombarding our affected systems with analyses,” Godbole said. “There are so many studies happening at the same time. If we keep requesting studies, we’re never going to finish. It’s going to be really tough to get those projects interconnected.”

Removing affected-system studies from the first phase of the DPP will reduce the potential for overlap among studies and eliminate at least 10 early affected-system studies in the next 12 months.

MISO said its West region — covering Iowa, Minnesota, part of Wisconsin and the Dakotas — has experienced one to two months of delays alone from conducting phase 1 affected-system studies.

“Look at the West region. It’s almost 200 projects alone,” Godbole said.

miso interconnection queue site control — | *MISO*

He asked stakeholders to submit feedback about the proposals by May 30, before MISO moves the recommendations to the June 13 Planning Advisory Committee meeting for an additional month of discussion. RTO staff hope to file Tariff changes with FERC by July or August.

While MISO is not seeking consensus to move forward, it will consider comments that could improve the proposal, Godbole said.

“Believe me, my phone does not stop ringing with customers concerned that they won’t get [production tax credits] in time. Something has got to give. And these are the … things that we think can have the most impact in a short amount of time. But it’s doesn’t stop here. We’re going to keep working [on the queue],” he said.

He added that future queue changes may entail moving milestone payments to a cash-only system, removing the option for customers provide a letter of credit. While MISO is not ready to propose the change, Godbole said the multimillion dollar companies that enter the queue should have no trouble providing milestone fees in cash. Some stakeholders said that although the monetary risk was the same, it’s more difficult going through the process of getting cash.

EDF Renewable Energy, which had petitioned FERC to order MISO to redesign the three-stage queue, said it supported the changes and expected them to help reduce delays, but the company thinks more needs to be done, including increasing milestone payments to deter speculative projects.

2 Projects, 1 POI

The IPTF is also collecting stakeholder feedback on a possible plan to loosen MISO’s one project/one point of interconnection policy in order to allow two projects with separate owners to connect at the same point of interconnection.

MISO manager Arash Ghodsian said the RTO would only move ahead with proposing the change if it doesn’t threaten reliability or present new delays in the interconnection queue.

Ghodsian said MISO has recently experienced an uptick in interest from customers wishing to connect multiple projects at a single point of interconnection.

Northern Indiana Public Service Co.’s Brett Furuness said he would appreciate future discussion on the topic because NIPSCO fields multiple interconnection requests at a single substation.

May 17, 2018

PJM Board Elects New Chair, Welcomes New Member

NATIONAL HARBOR, Md. — The PJM Board of Managers on Wednesday elected Ake Almgren as chairman and new member Neil H. Smith, the former CEO of generation developer InterGen.

Re-elected to three-year terms were John McNeely Foster, who joined the board in 2003, and Sarah Rogers, who began in 2012.

Almgren, a Ph.D. engineer, succeeds former Chairman Howard Schneider, who retired after 21 years on the board. Smith will fill the vacancy created by Schneider’s retirement. (See Retiring PJM Chair Schneider Reflects on 21 Years at the Helm.)

Ake Almgren Neil Smith PJM Board — Schneider | *PJM*

“Howard Schneider has led the PJM board by example, with a focus on integrity and the highest ethical standards,” PJM CEO Andy Ott said in a statement. “He has served on the board during a time of tremendous growth for PJM and unprecedented change in the industry.”

Almgren, who joined the board in 2003, is the former president of ABB Power T&D, former CEO of Capstone Turbine Corp. and a former member of the Department of Energy’s Electricity Advisory Council. He is the owner of Orkas Inc., which provides consulting in electric transmission and distribution, distributed resources, renewable energy and hybrid electric vehicles.

Smith retired as InterGen’s CEO in 2016 after 25 years with the company. He also is a former board member for The Wood Group, which provides project, engineering and technical services to energy and industrial clients.

Foster, a certified public accountant, is a former member of the Financial Accounting Standards Board and former vice president, treasurer and principal accounting officer of Compaq.

Rogers, an electrical engineer, served as CEO of the Florida Reliability Coordinating Council from 2007 until 2012. Between 1984 and 2007, she worked in a variety of positions at Progress Energy and its predecessors, including vice president of transmission.

— Rich Heidorn Jr.

May 17, 2018

FERC: MISO External Capacity Zone Plan Deficient

By Amanda Durish Cook

MISO’s plan to create external resource zones in its annual capacity auction isn’t detailed enough on several fronts, FERC told the RTO on Wednesday.

Commission staff issued MISO a deficiency notice explaining the proposal lacks sufficient detail about the reliability concerns that spurred it, the concept of border external resources, and how pseudo-tied resources and coordinating members’ resources will factor into the proposal (ER18-1173).

MISO FERC External Resource Zones — MISO Resource Adequacy Subcommittee in 2017 | © *RTO Insider*

MISO filed the plan in late March after three years of stakeholder meetings in its Resource Adequacy Subcommittee. It would create external resource zones by 2019 for MISO’s annual capacity auction, based on existing neighboring balancing authority area boundaries. External zones would not have capacity import limits, planning reserve margin requirements or local clearing requirements.

Resources in BAAs that border either MISO Midwest or South would clear at two different prices based on subregional unconstrained auction clearing prices, while those in BAAs that border both MISO areas — including Tennessee Valley Authority, SPP, Associated Electric Cooperative Inc. and Southwestern Power Administration — would receive a blended price.

In cases of auction price separation, the RTO would distribute historical supply arrangement credits from excess auction revenues as a refund to external resources with long-term and consistently used historical supply agreements. The proposal would also establish new zonal capacity export limits in time for the 2019/20 planning year auction. (See MISO Closing in on External Capacity Zones.)

In its deficiency letter, FERC asked MISO, among other questions:

Why it thinks that its current practice of giving external resources capacity credit in the local resource zone where its firm transmission service crosses into the footprint has the potential to cause reliability concerns;
How it will reconcile its current Tariff definition of local clearing requirement — defined as the minimum amount of unforced capacity physically located with a local zone — with its proposal to allow certain external resources to contribute to a local resource zone’s local clearing requirement;
If it will count pseudo-tied resources as external resources;
How it differentiates a “border external resource” — defined in the proposal as resources with direct electrical connections to the RTO but located in another BAA — from all other external resources;
How border external resources and coordinating owner external resources can be used to alleviate transmission constraints and address other reliability concerns for local resource zones;
How it plans to model external resources and how coordinating owner and border external resources will impact capacity import and export limits;
What physical and operational standards a coordinating owner external resource must meet to qualify for capacity credit in a local resource zone. FERC also asked MISO to identify any other coordinating members besides Manitoba Hydro, its sole listed coordinating owner;
If its proposed historical supply arrangement credits will be distributed to resources offered into the Planning Resource Auction, resources included in a fixed resource adequacy plan or both; and
How much estimated capacity would qualify for historical supply arrangement credits. FERC also asked MISO to describe scenarios in which the credits might not be fully funded.

FERC also ordered MISO to list all resources that would receive border external resource designation, their unforced capacity values and the local resource zones they border. The RTO previously said it identified about 3.8 GW of capacity from potential border external resources.

Finally, the commission said MISO must compare in writing the operational control it has over Manitoba Hydro’s resources versus other external resources, including Exelon’s Byron Generating Station, Duke Energy Indiana’s Madison Generating Station, WPPI Energy’s Nelson Energy Center and any resources with firm transmission service over a direct current line, such as the Grain Belt Express Clean Line.