Page 1397 – RTO Insider

March 22, 2018

States, Utilities, RTOs Push Back on Storage Order

By Rory D. Sweeney

A wide range of stakeholders filed comments this week requesting clarification or rehearing of FERC’s Order 841 requiring RTOs and ISOs to revise their tariffs to allow energy storage resources full access to their markets (RM16-23).

While their concerns included specific cost and billing issues, most comments focused on the high-level interaction between federal and state oversight in energy markets and argued that the order had overstepped FERC’s authority. (See FERC Rules to Boost Storage Role in Markets.)

Implementation Issue

Subsidiaries of AES, including Indianapolis Power & Light, requested clarification that the order — which doesn’t require implementation for nearly two years — doesn’t supersede MISO’s compliance requirements in response to IPL’s 2016 complaint that its 20-MW battery was being denied market participation despite its capability. That implementation is already underway. (See MISO Rules Must Bend for Storage, Stakeholders Say.)

Invenergy’s 31.5 MW Grand Ridge Energy Storage project | *Invenergy*

Otherwise, AES requested a rehearing to determine ways “to help alleviate in the interim” the conditions Order 841 is supposed to correct. It argued that “the commission simultaneously predicated participation of … electric storage resources on dispatchability, which … completely fails to recognize the physical and operational characteristics of electric storage resources like” IPL’s, which “can provide their services automatically, without a need for direct interface with RTO/ISO dispatch software at all.”

FERC required RTOs/ISOs to submit compliance filings detailing how they will implement the order by Dec. 3, with implementation finished a year after they file. MISO asked for a six-month extension of the implementation deadline to accommodate distributed energy resource issues that are still pending.

“Granting the requested clarification, or rehearing, will help ensure that an RTO/ISO has sufficient flexibility to design and implement [a storage] market participation model that is technically and operationally feasible in each RTO/ISO’s specific context,” MISO said.

The RTO also asked for clarification about how the 100-kW minimum threshold for resource participation should be calculated, noting that giving grid operators flexibility in how they handle charging and discharging limits “can avoid unnecessarily limiting the range for clearing energy or reserve products.” It also requested the ability to phase in the number of very small resources that can participate each year “to avoid an unmanageable influx.” Grid operators should also be allowed to require storage resources to comply with rules necessary to address any reliability impacts that distribution utilities identify, MISO said.

Finally, the RTO requested confirmation that three potential bidding parameters are acceptable:

Requiring storage units to provide their state-of-charge forecasts at the beginning of identified market intervals, such as day-ahead, five-minute and real-time.
Requiring storage units that don’t provide minimum limits and can be moved smoothly between negative and positive to submit a single hourly ramp rate for the day-ahead market and “look-ahead commitment” process, or alternatively applying MISO’s real-time security-constrained economic dispatch practice if appropriate.
Requiring units that use their state-of-charge to lock output to a narrow range to be treated as self-scheduled price-takers that can’t set prices because they are potentially unable to fulfill capacity obligations, provide ramp products or perform ancillary services.

EEI’s Issues

The Edison Electric Institute requested clarification or rehearing on whether relevant electric retail regulatory authorities (RERRAs) would have the ability to opt in or out of allowing distribution-connected resources from participating in wholesale markets because their participation “has significant implications for the operation and reliability of the distribution system.”

EEI pressed FERC on how rates should be calculated, arguing that in situations where storage is paired with a retail load behind a single retail meter, the storage should either pay for any costs to separately measure the retail and wholesale loads or the entire load should be treated as retail. The institute said that storage must still be required to “pay any applicable charges covered under state jurisdictional tariffs in order to adequately reflect their use of state jurisdictional facilities.” It also disliked the 100-kW threshold, fearing that an “influx of smaller resources” could create administrative, reliability and cost issues.

DER Technical Conference

Finally, EEI said rules developed through the separate technical conference that FERC ordered on DER aggregation (RM18-9, AD18-10) should also apply to any storage resources covered by Order 841 “to ensure consistency.”

Several organizations representing public power filed a joint request asking for the same, adding that any RTO/ISO tariff revisions regarding Order 841 not become effective until after rules from the technical conference are developed.

RERRA Clarifications

Like many other commenters, the public power organizations — which include American Municipal Power, the American Public Power Association and the National Rural Electric Cooperative Association — also focused on state and local authority and requested FERC include an opt in/out mechanism for RERRAs.

“The commission should … unequivocally state that [its] regulations … do not authorize an [energy storage resource] to violate state or local laws or regulations or contract rights governing retail electric service or the local distribution of electric energy,” the organizations wrote.

Pacific Gas and Electric asked for clarification that “nothing in Order 841 is intended to suggest that the state no longer has jurisdiction to determine how power flowing from the distribution grid, through the customer meter and then into the storage resource located behind the customer meter is to be split between retail consumption and wholesale charging for later discharge into the wholesale markets.”

FERC energy storage Order 841 — Sodium sulfur battery storage facility at Pacific Gas and Electric’s Vaca-Dixon substation. | *California Energy Commission*

The company warned that “if the commission were to conclude that the state no longer has this authority, then a retail customer could use its behind-the-retail-meter storage resource as a means to completely bypass retail rates for its onsite electricity consumption. The customer could simply claim that all electricity flowing through his/her retail meter went into the storage device for later discharge into the wholesale markets, even if the power were never returned to the wholesale market but instead used to meet on-site electricity demand.”

The Organization of MISO States reiterated the request to “clearly” acknowledge “applicable state and local laws, and applicable orders and rules” of RERRAs, disqualify resources that don’t comply with those rules and develop a process to confirm that compliance.

The National Association of Regulatory Utility Commissioners filed similar requests, warning FERC to “be careful that its actions do not inhibit or conflict with authority Congress specifically reserved to NARUC’s state commission members.” The association took issue with wording in the order that barred states from deciding whether distribution-level storage in their jurisdiction can participate in wholesale markets, which it said should be eliminated.

“FERC has exclusive jurisdiction over the wholesale markets and the rules that apply to resources participating in those markets, including how such resources participate,” the association said. “Nonetheless, Congress assigned states the task of determining whether resources located behind a retail meter or on the distribution system can, in the first instance, participate in wholesale markets.”

Xcel Energy Services, filing on behalf of its four utility affiliates in Minnesota, Wisconsin, Colorado and the Southwest, expressed concern about many of the same issues other stakeholders addressed, including: not providing states with an opt-out option; complications around separate metering for wholesale and retail activity; flexibility in developing an implementation schedule; allocation of integration costs for storage resources; and the inability to institute rules for storage to address reliability issues.

Market Exclusivity

The Transmission Access Policy Study Group (TAPS) noted the RERRA opt-out issue, but it also argued that FERC erred in rejecting the group’s proposal that storage resources be required to choose exclusive participation in either wholesale or retail markets.

“To avoid market manipulation, prohibited resales of energy purchased at retail and prohibited end-use consumption of energy purchased at wholesale, distributed storage resources [should] be required to make a binding choice to participate exclusively either in the wholesale markets or at retail,” TAPS said.

Grid Operator Responsibility

CAISO requested that FERC clarify several points about grid operators’ responsibilities, including that someone — although not grid operators — must directly meter storage resources, that grid operators can require storage resources to resolve retail double-billing issues with their retail energy provider as a condition of wholesale market participation, and that storage resources not incur transmission charges when they are dispatched to charge up because they’re performing a service.

Other Clarifications

Several organizations also sought separate clarifications of the order. PJM requested confirmation that the order “does not mandate a particular methodology” for accounting for “the physical and operational characteristics” of storage resources. The California Energy Storage Alliance requested clarity on “when and why transmission charges should apply to wholesale energy purchased for later resale in the same area” because potential “double-billing would be unduly and financially burdensome to the usage of energy storage and unreasonable in the application of the cost allocation and recovery for transmission charges.”

March 22, 2018May 8, 2025

CAISO: New 2019 RMR Contracts Possible

By Jason Fordney

A CAISO official revealed Tuesday that a generation owner has approached the ISO about seeking a 2019 reliability-must-run contract, a development likely to sharpen an ongoing stakeholder debate about the out-of-market payments.

rmr caiso reliability-must-run contracts

Johnson | © RTO Insider

Keith Johnson, CAISO infrastructure and regulatory policy manager, acknowledged the generator’s request in response to a series of questions during an hourslong stakeholder meeting that at times became slightly charged as market participants delved deeply into the ISO’s backstop energy procurement policies.

Generation owners typically inquire about an RMR when they are considering shutting down a unit and want to know if it might be eligible to receive one of the increasing number of contracts the grid operator has been inking in recent years to keep gas-fired plants available for reliability reasons.

Stakeholders have questioned whether retirement notifications and subsequent discussions between generation owners and CAISO should remain confidential or be announced immediately. In response, the ISO is working on rule changes that would allow it to provide the public early notification of unit retirements under different scenarios.

The notification changes are included in “Phase 1” of a broader set of RMR and capacity procurement mechanism (CPM) changes that CAISO is developing. Another primary component of the program is a must-offer requirement for RMR units that will “look, feel and act more like resource adequacy,” Johnson said.

| CAISO

The ISO on March 13 issued its draft final proposal for Phase 1, with the goal of getting approval from the Board of Governors in May, in place for fall contracting for the 2019 operating year. Comments are due April 10 on the proposed rule changes, a topic of a similarly pointed stakeholder session last month. (See CAISO, Stakeholders Debate RMR Revisions.)

CAISO has received plenty of feedback about including more RMR/CPM reforms in Phase 1, but Johnson told stakeholders Tuesday that “we are avoiding shoehorning stuff in there that can’t be adequately vetted with you.”

More comprehensive RMR/CPM refinements are being considered for a later Phase 2, CAISO said in a presentation during the meeting. Thirteen items are up for discussion for the second phase, including more clarification regarding the differences between RMR and CPM, and whether the two programs can be merged into one procurement tool.

Additionally, CAISO had already developed and submitted a package of RMR changes to FERC, which it said it expects to be approved on April 12.

RMR critics — which include the California Public Utilities Commission — say the growing need for the contracts points to market deficiencies that call for broader reforms across the market. The commission replaced a previous set of CAISO-approved RMRs with energy storage. (See CPUC Retires Diablo Canyon, Replaces Calpine RMRs.)

NRG Energy subsidiary GenOn recently notified the commission that it plans to retire three gas-fired plants by early next year, possibly setting them up for RMRs. (See NRG Set to Retire California Gas Plants.)

March 22, 2018

Ky. Rejects AEP Supplemental Tx Project

By Rory D. Sweeney

Citing FERC’s concerns over supplemental transmission projects, Kentucky regulators have rejected upgrades to two substations, ruling that Kentucky Power failed to prove they were needed.

The Kentucky Public Service Commission released an order on March 16 granting a certificate of public convenience and necessity (CPCN) to Kentucky Power for a baseline project to rebuild a 161-kV line between its Hazard and Wooton substations but denied a CPCN for a more expensive supplemental project to make upgrades at the substations. Kentucky Power, a subsidiary of American Electric Power, estimated the baseline project to cost $20 million and the supplemental project another $24 million.

PJM FERC supplemental projects Kentucky Power — | *PJM*

Baseline projects are administered by PJM to address violations of publicly available reliability criteria, while supplemental projects are developed internally by transmission owners and are not driven by RTO criteria. Supplementals are included with baseline projects in PJM’s Regional Transmission Expansion Plan to allow staff to identify possible reliability or operational performance issues, but they are not subject to staff oversight or approval. For years, several organizations representing demand-side interests have been clashing with TOs over the projects, arguing that TOs are incentivized by their formula rates to build as much as possible and that regulators’ oversight is not adequate to corral the impulse. Spending on supplementals has been on the rise, and critics believe TOs see them as an unsubstantiated way to build more. (See PJM TOs, Customers Await Ruling on Supplemental Projects.)

The PSC was unpersuaded by Kentucky Power’s contention that the supplemental made sense because engineering and construction resources would already be focused in that area. “This may speak to efficiency but not to necessity,” the commission said, noting that consideration of the projects happened through a PJM stakeholder process that FERC has since determined requires revision.

FERC ruled in February, following a 2015 technical conference and subsequent show-cause order in 2016, that TOs’ processes for receiving “meaningful input” from stakeholders on supplemental projects need additional structure to comply with Order 890 (EL16-71). TOs, through PJM, have subsequently submitted a proposed timeline for project consideration, but opponents have challenged the order as not sufficient. (See Group Contests ‘Supplementals’ Ruling as PJM, TOs Advance.)

March 22, 2018

UPDATED — Second Thoughts: FERC May Revoke Marketers’ Tariff

By Rich Heidorn Jr.

FERC this week rejected a proposed power and gas tariff filed by the North American Energy Markets Association (NAEMA) and indicated it is likely to revoke the group’s capacity and energy tariff, which the commission accepted in 2003. The group said Thursday night it will seek an emergency stay to give it time to amend the older agreement.

NAEMA, which claims about 150 members that have 500,000 MW of generating capacity and serve more than 100 million electric and gas customers, developed the power and gas tariff with the International Energy Credit Association.

The group said the tariff, filed in January, was similar to the 2003 tariff but was updated to reflect current industry preferences for contract language and products. It intended to leave the existing tariff in place with the new one available for companies that choose to use it.

But the commission said March 19 that the tariffs should not be on file with it because NAEMA is not a jurisdictional public utility (ER18-676). “Nor does the power and gas tariff filed by NAEMA set forth any rates and charges or terms and conditions that govern the transmission or sale of electric energy. Instead, the power and gas tariff merely contains standard form bilateral sales contracts with a set of standard terms and conditions that NAEMA members may choose to use when they make sales of their own capacity and energy or natural gas to customers.”

The commission said NAEMA members that are public utilities should enter separate, standalone bilateral agreements under their own market-based rate tariffs whether or not they comport with NAEMA’s standard terms and conditions. Such transactions should be included in the utility’s Electric Quarterly Reports, FERC said.

“We make no findings about [the proposed tariff’s] specific terms and conditions or whether NAEMA members should or should not use it as a template for any market-based rate bilateral sales agreements,” the commission said.

Show Cause

FERC also directed NAEMA to show within 30 days why the 2003 tariff, which was approved by a letter order by a division director, should remain on file with the commission (ER04-22). “If such a filing is not received within the required time, NAEMA’s capacity and energy tariff will be canceled in the commission’s eTariff system,” it said. The commission did not say why it now considered the 2003 order — which NAEMA says was updated as recently as 2011 — an apparent error.

NAEMA was created in 2003 as a successor to the Power and Energy Market (PEM) of the Mid-Continent Area Power Pool (MAPP) after the group expanded. NAEMA said the 2003 tariff was a successor to one approved by FERC in 2001 for MAPP (ER01-3045) and has been updated five times since then.

Power and Gas Tariff, NAEMA, FERC — NAEMA Executive Director Mike Critchley | *ZEMA*

Emergency Stay Sought

NAEMA attorney K.C. Hairston told RTO Insider Thursday evening that the organization will file an emergency motion seeking a stay of the show cause order to allow it to propose an amendment to the energy and capacity tariff that it said should address the commission’s jurisdictional concerns. The motion was filed early Friday.

The amendment would be a cost-based schedule, which NAEMA says will ensure the tariff falls “within the categories of agreements described by the commission in the show cause order where non-jurisdictional entities can submit tariffs on behalf of jurisdictional companies.”

The group pledged to submit the proposed amendment within 60 days.

Overwhelmingly Surprised

In the motion, NAEMA says it was “overwhelmingly surprised” by the order, claiming it contacted the commission’s Office of General Counsel regarding the jurisdiction issue and incorporated changes it suggested. The group said it realizes that OGC does not speak for the commission but “assumed that the commission would take a consistent view” with the office.

NAEMA said it had cause for the stay because “Terminating a tariff that has been repeatedly approved by the commission for over a decade and is currently used by market participants across the United States will be disruptive to the energy markets the commission regulates.”

The group also made an unusual request, saying “it will be beneficial to have a designated non-decisional commission staff member that it can consult with should issues arise” in drafting the amendment.

NAEMA, which holds regular conferences, says its goal is to “promote and facilitate a vibrant physical and financial energy marketplace” through “contacts and contracts.” Its board members include staff from ACES Power Marketing, AEP Energy Partners, EDF Renewable Energy, MidAmerican Energy, Southern Power, The Energy Authority, TransAlta Energy Marketing, WPPI Energy and Xcel Energy.

March 21, 2018

Group Contests ‘Supplementals’ Ruling as PJM, TOs Advance

By Rory D. Sweeney

The fight between PJM transmission owners (TOs) and customers over supplemental projects isn’t over yet, despite a FERC order approving the RTO’s plan.

Both sides made filings at FERC this week in the docket determining how oversight of the local, TO-driven projects is handled (ER17-179).

PJM and its TOs said in a compliance filing Monday that they are willing to revise their original proposal to provide stakeholders more time to examine the reasons why a TO decides to pursue a supplemental project, but the RTO said many other deadlines can’t be adjusted because they must fit within the timing of its current processes. (See PJM, TOs Propose FERC Order 890 Compliance Plan.) The projects include transmission expansions or enhancements not required for compliance with regional or national reliability, operational performance, or economic criteria.

A coalition of customers calling themselves “the load group” requested rehearing of the order, arguing that it still doesn’t hold TOs accountable for their obligations under FERC Order 890. They took issue with FERC’s approval of TO-proposed language to delineate the supplemental planning process and move it from the PJM Operating Agreement (OA) — which requires a super-majority endorsement from PJM stakeholders to make changes — to a new Attachment M-3 of the Tariff. The TOs have exclusive filing rights under Section 205 of the Federal Power Act to make changes to the Tariff; other stakeholders would need the PJM Board of Managers to file a complaint under Section 206. (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)

Additionally, PJM’s Independent Market Monitor (IMM) has asked to intervene in the docket, wading into a clash the IMM has largely stayed out of since it was touched off with a 2015 technical conference and subsequent FERC show-cause order in 2016 (EL16-71).

Compliance Filing

PJM submitted proposed Tariff and OA revisions to address FERC’s determination that the TOs were failing to provide stakeholders with adequate notification, information, and opportunities to engage in discussions over supplementals. While PJM includes the projects in its Regional Transmission Expansion Plan (RTEP) to allow staff to identify possible reliability or operational performance issues, they are not subject to staff oversight or approval.

TOs had proposed there be a minimum of 25 days between meetings covering the three parts of project planning: assumptions, needs, and solutions. They also offered to post information to be discussed at that meeting 10 days ahead of time and allow 10 days after meetings to receive comments. Finally, they proposed a 10-day waiting period to consider written comments before incorporating their local transmission plans into the RTEP.

In response to stakeholder feedback, PJM and the TOs agreed to extend to 20 days the period before the initial assumptions meeting.

“While the [TOs] are sensitive to the desire of some stakeholders for additional time between meetings and for more time to review the materials presented for discussion at the meetings, they determined that, in most cases, longer minimum time periods would compromise their ability to coordinate the supplemental project planning process with PJM’s planning of baseline projects [that address regional or national criteria violations] for inclusion in the [Regional Transmission Expansion Plan],” the filing said. “PJM apprised the [TOs] that minimum periods between supplemental project planning meetings of more than 28 days would have the potential to cause problems by preventing effective coordination with meetings of the PJM Transmission Expansion Advisory Committee.”

PJM FERC supplemental projects MISO Bylaws/Transmission Owners Agreement — | © *RTO Insider*

TOs said the deadline for feedback on a project’s first meeting about assumptions can be pushed back “without impeding the subsequent steps in the process.”

Rehearing Request

The load group’s request argues that Attachment M-3 doesn’t resolve Order 890 issues in the first place and that it’s inappropriate for PJM to add the attachment to the Tariff rather than the OA. It also took issue with the commission not requiring TOs to provide more information to stakeholders, such as the models and data necessary to replicate the analyses identifying the need for supplemental projects. FERC also should have subjected supplementals to the same obligation-to-build, milestone requirements and PJM impact analyses as RTEP baseline projects, the group said.

The group criticized FERC for what they said was allowing TOs “to disregard their obligation to respond to comments from stakeholders.”

“The commission is not free to ignore problems with a section 205 filing that a party identifies simply because that party proposed an alternative to particular filed terms and conditions,” the group wrote. “But that is precisely what the commission did in the order. … Given the PJM TOs’ track record in failing to meet their obligations under Order 890, the PJM TOs should be required to respond to stakeholder comments. Otherwise, stakeholders will have no way of knowing whether the TOs have honored their obligation to consider these comments. … The commission should ensure that any such process is robust and offers stakeholders recourse if their comments are ignored.”

The group includes American Municipal Power, Old Dominion Electric Cooperative, the Delaware Division of the Public Advocate, the PJM Industrial Customer Coalition, the Illinois Citizens Utility Board, the Office of the People’s Counsel for the District of Columbia, and the Public Power Association of New Jersey.

March 21, 2018

D.C. Circuit Denies EPA Haze Rule Challenges

By Michael Kuser

The D.C. Circuit Court of Appeals on Tuesday denied several petitions for review of final EPA action on steps to cut pollution from electric power plants in order to restore to “natural conditions” the air quality and visibility in “Class I” national parks and wilderness areas.

EPA, under the 2012 Clean Air Act, issued its Regional Haze Rule, which revised its guidelines on Best Available Retrofit Technology (BART) for stationary pollution sources, usually power plants, installed before August 1977. The new rule also specified that the agency’s 2011 Cross-State Air Pollution Rule (CSAPR) had requirements stringent and effective enough for it to serve as a better-than-BART alternative for states participating in CSAPR, thus excusing states from compliance with BART itself.

EPA DC Circuit utility air regulatory group Regional Haze Rule — | *EPA*

EPA also disapproved portions of certain State Implementation Plans (SIPs), designed to achieve reasonable progress under the Regional Haze Rule because those plans relied on a soon-to-be-defunct predecessor of CSAPR, the Clean Air Interstate Rule (CAIR).

The National Parks Conservation Association and the Sierra Club challenged allowing states to treat CSAPR compliance as a better-than-BART alternative.

Multiple power companies and the Utility Air Regulatory Group, as well as the State of Texas and the Louisiana Department of Environmental Quality, challenged EPA’s disapproval of SIPs relying on CAIR as a better-than-BART alternative.

“Except to the extent that the challenges are moot, we affirm EPA’s actions,” said the March 20 opini o n by D.C. Circuit Court of Appeals Senior Circuit Judge Stephen F. Williams.

The three-judge panel consisted of Thomas B. Griffith and Cornelia T.L. Pillard, circuit judges, and Senior Circuit Judge Williams.

Useful Life

Dealing with the conservationists’ petition first, the opinion said that “the attack on EPA’s use of presumptive BART … is jurisdictionally foreclosed by the 60-day filing window provided by the Clean Air Act.”

Furthermore, Judge Williams described “a cavalcade of attacks on alleged modelling errors,” wherein “the conservation petitioners fix on a comment that EPA failed to address in its response to comments, specifically an assertion that EPA’s model does not take into account the remaining ‘useful life’ of specific BART-eligible sources.”

The agency did not contest that it overlooked these comments.

“It argues now — reasonably, in our view — that the effects of a plant’s useful life are too speculative to model, and not significant enough to make any modeling a useful enterprise,” said the opinion. “We see no need to remand on this point for EPA to move this bit of post-hoc rationalization into a rulemaking record.”

The conservation petitioners finally argued that, in comparing CSAPR and BART, EPA compared the wrong averages.

The court disagreed, referring to its reasoning in an earlier petition from the Utility Air Regulatory Group.

“It is in the nature of averages that some particular sites may underperform while others overperform,” said the decision. “EPA’s rule requires aggregate average improvement, and its comparison of the CSAPR-region Class I areas as well as all Class I areas nationwide was reasonable.”

State and Industry

The state and industry petitioners in essence argued that if compliance with CAIR had for years allowed them to achieve greater reasonable progress than BART would have, their continued enforcement of emissions standards in line with the now-defunct CAIR must necessarily be found an adequate alternative to BART.

“But, of course, without CAIR — which all parties agree is dead and beyond revival — there is no legal basis for a requirement that states control their sources at CAIR levels; indeed, for states that are not part of CSAPR, there is no legal basis for requiring states to participate in any haze-related interstate trading program,” said the court.

The court cannot order EPA to consider CAIR an alternative to BART without resurrecting CAIR itself, “a rule that we have already stricken and ordered to be vacated,” said the decision.

The petitioners saved themselves from mootness only by couching their request for relief as “a contingency,” said the opinion. The court denied the state and industry petitioners, saying they “can afford no relief.”

March 21, 2018

Texas Commission Names New Executive Director

By Tom Kleckner

The Public Utility Commission (PUC) of Texas on Monday approved the choice of John Paul Urban as its executive director during a special open meeting.

PUC Chair DeAnn Walker said Urban will oversee “something of a reorganization” once he comes on board.

Urban brings a strong political background with him. He worked in a number of legislative positions since graduating from the University of Texas in 2000 and was the PUC’s director of government relations for three and a half years before joining NRG Energy in a managerial position.

executive director ercot puct — PUC OF Texas commissioners left to right: Brandy Marquez, DeAnn Walker and Arthur D’Andrea meet on personnel matters. | *AdminMonitor*

“Based on his past tenure at the PUC, John Paul has an excellent grasp of the agency’s mission and a sterling reputation in both the capitol and our regulated industries,” Walker said in a statem e n t. “We are confident in his ability to lead the agency as it fulfills its oversight role.”

Urban replaces Brian Lloyd, who announced his resignation from the commission in January. (See Texas PUC Executive Director to Resign.)

ERCOT PUCT Executive Director — PUCTs’ Stephen Journeay | *AdminMonitor*

Walker also announced new titles for two long-time staffers as part of the strategic alignment that Urban’s hiring will complete. Thomas Gleeson, who has been at the commission for 10 years, will become the PUC’s chief operating officer, while Stephen Journeay will become commission counselor in the Office of Policy and Docket Management.

Journeay, who sits in front of the PUC during open meetings and coordinates the work on dockets, will now report directly to the commissioners, instead of the executive director. He is a licensed attorney and professional engineer and has been with the PUC since 1996.

“When I found out he was reporting to the executive director, it didn’t make much sense,” Walker said. “He really reports to us.”

Walker also announced Andrew Barlow has been hired as the PUC’s communications director. Barlow previously served in communications roles for former Texas Gov. Rick Perry and former Texas Lt. Gov. David Dewhurst.

March 21, 2018

MISO to Recycle Tx Planning Scenarios for 2019

By Amanda Durish Cook

MISO is moving ahead with a proposal to largely recycle last year’s 15-year transmission planning predictions for use in its 2019 Transmission Expansion Plan, but some stakeholders are urging the RTO to at least expand the plan.

During a March 20 workshop to gather stakeholder input on MTEP 19, MISO Planning Manager Tony Hunziker said the futures were developed for reuse over multiple planning cycles, with small updates to cover uncertainties such as the capital cost of building generation, demand growth rate and projected fuel prices. (See MISO: Minimal Change to 2019 Tx Planning Futures.) Stakeholders generally support the idea, he said.

MISO last year created four future scenarios for use in MTEP planning, including:

A limited fleet change future, in which the fleet remains relatively static with coal units retiring at the end of their useful life;
A continued fleet change scenario, in which the grid develops according to the trends of the past decade;
An accelerated fleet change future driven by a strong economy that increases demand and motivates carbon regulations and increased renewable use; and
A future in which distributed and emerging technologies become more widely used.

MISO planners are proposing small adjustments to some MTEP 19 assumptions, namely to account for sluggish load and higher-than-expected renewable penetration.

With energy growth currently outpacing load growth, planners say MISO should abandon its previous practice of assuming energy will grow at 0.5 to 1.5 times the base growth rate (extrapolated from load-serving entities’ current forecasts) in its transmission planning, and instead plan for anything from no growth to twice the base growth rate. Preliminary demand forecasts from LSEs show a 0.3% average growth rate through 2027, down from 0.5% in MTEP 18 and 0.6% in MTEP 19, while energy is expected to grow at a 0.5% rate.

MISO staff are also considering raising projected renewable penetration by 5% across all futures — from 10-30% to 15-35% of capacity. They acknowledged that the low end of the MTEP 18 range does not reflect the number of renewables on track to complete the interconnection queue.

miso mtep 19 transmission planning — | *MISO*

The RTO also plans to update its base futures model to include planned units holding a certificate of public convenience and necessity, as well as units that have a signed generator interconnection agreement.

MISO will take stakeholder input on MTEP 19 futures through April 20 and expects to have futures finalized by September.

Fifth Future

But some stakeholders are asking MISO to create of a fifth future. Investment firm Veriquest requested the RTO develop an additional scenario that focuses on the regional siting of distributed resources, while MISO’s Environmental sector asked for a standalone future showing how possible federal or state carbon regulations drive fleet evolution.

Veriquest’s David Harlan said he’d like to see futures more informed by future capacity needs.

“I still don’t have a good picture where the source of needs is and where the capacity is,” Harlan said. He urged MISO planners to make projections to share with stakeholders about who benefits from cost-effective transmission requirements to move wind from North Dakota to Mississippi, for example.

“None of that is visible in this process,” Harlan said.

MISO Director of Policy Studies J.T. Smith said the RTO does account for future capacity movement when building MTEP models.

The Transmission Owners sector said the potential industry changes depicted in the four MTEP futures adequately capture future impacts to the transmission system. “While some of the currently defined futures, such as the limited fleet change, may not align well with the current industry projections, those futures provide valuable information … as well as provide a counter to the more aggressive generation change assumptions implemented in other futures,” it said.

Apex Clean Energy’s Richard Seide asked if MISO is accounting for commitments from utilities that intend to eliminate the use of coal, such as Consumers Energy, which recently announced its plans to go coal-free by 2040. (See CMS Energy Plans a Zero-Coal Future by 2040.)

“I don’t know how to say it, but the world has changed … and it occurred very quickly. You’re sitting on the largest queue ever,” Seide said.

Shane O’Brien, of MISO’s resource forecasting group, said stakeholders have so far said the RTO’s retirement projections are adequate. The RTO does not hold utilities to retirement announcements or include them in planning until owners submit Attachment Y retirement notices.

March 20, 2018

DC Circuit Rejects NorthWestern Reg Service Appeal

By Tom Kleckner

The D.C. Circuit Court of Appeals on Friday upheld FERC’s determination that NorthWestern Energy’s proposal to recover the costs of a generating station providing regulation service was not just and reasonable.

The court rejected NorthWestern’s claim that FERC’s decision was “arbitrary and capricious” and violated the Administrative Procedure Act’s requirement that an agency’s decision be “reasonable and reasonably explained” (No. 16-117).

The Midwest utility had filed with FERC to revise its rates to recover the costs for its Dave Gates Generating Station, a gas-fired facility built in Montana to provide its own regulation service, after purchasing 60 MW annually of the service from other utilities became too expensive. The 150-MW plant went into service in 2011.

Dave Gates Generating Station | *Corval Group*

NorthWestern proposed to use Gates to supply 105 MW of regulation service to all its customers. Retail customers would pay for 45 MW at a state-approved rate, separate from Schedule 3 under NorthWestern’s Tariff with FERC. Retail and wholesale customers would pay for the remaining 60 MW under Schedule 3, which was calculated by multiplying the plant’s revenue requirement by 0.57 (the ratio of 60/105).

The utility also proposed to charge customers for fuel costs but credit them for any revenue the Gates plant might bring in from off-system sales and other nonregulation service sales; charge customers for the regulation service that it purchased during a 2012 outage; and charge customers for any regulation service that NorthWestern might need to purchase during future outages.

FERC affirmed an administrative law judge’s order reducing NorthWestern’s proposed rate by: (1) multiplying the revenue requirement by a different cost-calculation ratio of 0.13 (19/150); (2) excluding fuel costs from the Schedule 3 rate and rejecting the utility’s crediting arrangement; (3) requiring the utility to make a separate filing to recover costs associated with the 2012 outage; and (4) requiring it to make separate filings before charging customers for any regulation service that it might need to purchase during future outages.

The commission directed NorthWestern to refund its customers the difference between the proposed rate and the modified rate. It also denied a request for rehearing.

Northwestern Energy Generating Facilities | *Northwestern Energy*

NorthWestern raised four challenges in arguing the case before the D.C. Circuit in December. It said FERC “unreasonably” reduced the numerator of its proposed cost-calculation ratio from 60 MW to 19 MW, but the court said the commission “reasonably modified” the calculation after determining that only 19 MW were needed to serve Schedule 3 customers.

The utility also contended that the commission arbitrarily increased the denominator of its proposed calculation from 105 MW to 150 MW. The court disagreed, noting that under FERC precedent, the denominator should reflect the nameplate capacity (150 MW), not just the megawatts that NorthWestern planned to devote to regulation service.

Third, NorthWestern argued that FERC inadequately explained its decision not to allow fuel costs and failed to account for the fact that the utility may be able to retroactively recover fuel costs. The court ruled otherwise.

Finally, the utility said the commission acted arbitrarily by requiring it to make separate Section 205 filings to recover costs associated with the 2012 outage and for any regulation service that it might need to purchase during future outages. FERC adopted the ALJ’s reasoning, which justified the separate proceedings on reasonable grounds, and “acted reasonably here as well,” the court ruled.

Writing for the court, Judge Brett Kavanaugh said he was not persuaded by NorthWestern’s challenge of FERC’s order for refunds. He noted that the commission “concluded that NorthWestern over-collected from its Schedule 3 customers, making this the kind of case in which FERC ordinarily orders refunds.”

“That determination was reasonable,” he said.

March 20, 2018October 21, 2025

Counterflow: German La La Land

By Steve Huntoon

It’s what you know that ain’t so …

That will get you in trouble.

The February Fortnightly features an article about the German Energiewende (“Energy Transition”) that makes three basic claims: (1) Germany is successfully decarbonizing with renewables, (2) Energiewende is “good news for consumers” and (3) there will be no adverse impact on electric reliability.^[1]

The first two claims are simply wrong. The third cannot be correct.

Wrong: German Electricity is Decarbonizing

German electricity isn’t decarbonizing. Because of its tragic decision to close nuclear plants, Germany is substituting coal and renewables for nuclear.

Despite the increase in renewable generation that Fortnightly extols, there has been no material decrease in carbon dioxide emissions from German electric generation. Germany is doing much worse than the European Union generally, much worse than the U.S. and much worse than France, as shown by changes in electric sector carbon dioxide emissions (2008 baseline):^[2]

In a nutshell, Germany is substituting coal and renewables for nuclear,^[3] while the U.S. and France are substituting natural gas and renewables for coal.^[4] Germany isn’t making a serious dent in its carbon dioxide emissions from electricity, while other nations are.

Does Germany “point the way”? No way.

Wrong: Energiewende is Good News for Consumers

Truth is that Energiewende has driven Germany’s sky-high electricity prices even higher. Here are Germany’s residential prices relative to the European Union, France and the U.S. (U.S. cents/kWh):^[5]

Energiewende, Germany, Energy Transition — | *Eurostat, EIA*

It may be hard for Americans to get their heads around it, but German residential electric prices are now three times U.S. prices.

For U.S. regulators out there, how many years of a 10% price increase each year would it take for the average U.S. residential price to reach the average German residential price?

The answer is 12 years. But the torches and pitchforks appear long before then. Like Year 2.

By the way, Energiewende hasn’t yet hit stride. Germany is planning much more costly renewable and transmission projects that are estimated to ultimately cost 25,000 euros per family household.^[6] That’s $30,750 American.

Does Germany “point the way”? No way.

Cannot be Right: No Impact on Reliability

The Fortnightly article claims that decarbonization has/will have no adverse impact on reliability. This claim is premature and cannot be correct.

The vision seems to be that Germany gets rid of all nuclear plants and all coal plants, and will rely on a combination of renewable resources, flexible fossil (presumably natural gas) generation, demand response and storage (batteries).

Fortnightly seems to think this is feasible because “Germany already produces hours of nearly 100% renewable electricity on the system.” According a German spokeswoman, “‘Baseload is no longer needed,’ otherwise it could ‘block the grid.’”

Say what? The problem isn’t hours when solar and wind generate enough to meet demand. The problem is all those other hours when they don’t, like these sorts of hours and days and weeks:^[7]

Renewables generated very little for a two week period. The vast bulk of demand had to be met with existing conventional power plants.

Supposed Reliability Fixes

Now let’s look at the supposed fixes when existing nuclear and coal power plants are eliminated: flexible fossil fuel (natural gas) generation? Creating a new fleet of gas generators with the necessary pipeline infrastructure would be astronomically expensive and make Germany even more dependent on Vladimir Putin’s natural gas.

By the way, the new German coalition agreement’s sole reference to natural gas is: “Make Germany a location for liquefied natural gas (LNG) infrastructure.”^[8] No such LNG infrastructure exists, and the one proposed LNG terminal looks like more of a pipe dream.^[9] And a very expensive one at that.

OK, how about demand response? An optimistic estimate of theoretically possible DR is about 10% of Germany’s total demand,^[10] requiring a new infrastructure and, of course, customers’ agreement.

Not only is the potential small, but the demand reduction is for one or two hours max. The chart above shows solar and wind can take a powder for days on end.

Batteries fall prey to this same problem. The cost of batteries is typically quoted in terms of four hours of stored energy for each hour of maximum output. What if you need battery output to last eight hours? Then the nominal cost of batteries doubles. If you need 24 hours, then the nominal cost of batteries goes up six times.

So when we think about the need to cover days of renewable non-generation, we should understand that the cost of batteries is many times the current publicized cost. And we can understand why no sophisticated industry player is flocking to batteries (unless subsidized by Other People’s Money — in which case they’re a great idea of course).

The claim that Germany can maintain reliability without nuclear and with only “very small amounts of fossil fuels,” as the article says, sounds like it came from the breatharians, who believe they only need air, and not food, to survive. We don’t hear from them too often — at least not the same ones. For the obvious reason.

The Fortnightly article goes on to cite customer outage and loss-of-load expectation (LOLE) data and projections supposedly demonstrating continued reliability under Energiewende. But the vast bulk of customer outages are attributable to distribution and transmission problems, not resource problems (as the article itself notes at the outset citing a Rhodium Group report). So outage data, especially with renewables still a minority of total resources, says nothing about future resource adequacy.

As for LOLE projections, the article relies on studies that assume that more than 30 GW of coal plants remain in Germany^[11] — which is the opposite of the article’s premise that they are eliminated. You can’t eat your cake and have it too.

In summary, Germany’s future without nuclear and without coal has no plausible means of meeting customer demand.

Does Germany “point the way”? No way.

Bottom Line

Energiewelde isn’t decarbonizing German electricity, only increasing sky-high electric prices, which it will continue to do indefinitely. And reliability can’t be sustained on the equivalent of thin air.

Energiewende does point a way. The wrong way.

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.

https://www.fortnightly.com/fortnightly/2018/02/how-german-energiewendes-renewables-integration-points-way. ↑
2008 emissions set at baseline of 100% for all data which is tons of carbon dioxide emissions. First year is 2008 because that is the first year of Eurostat data here, http://appsso.eurostat.ec.europa.eu/nui/show.do?dataset=env_ac_ainah_r2&lang (“Electricity, gas, steam and air conditioning supply.”) I thank Aldyen Donnelly of Vancouver for pointing me to the Eurostat database. U.S. emissions from EPA data here, https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks (Table 2-4, EPA inventory archives used for years 2008-2011). ↑
For discussions of this phenomenon, http://www.eiu.com/industry/article/1205236504/is-germanys-energiewende-cutting-ghg-emissions/2017-03-20, https://www.economist.com/news/europe/21731171-thanks-panicked-decision-shut-its-nuclear-plants-germany-carbon-laggard-germany. ↑
https://www.edf.fr/en/the-edf-group/our-commitments/corporate-social-responsibility/doing-even-more-to-reduce-co2-emissions. ↑
European prices from Eurostat data here, http://appsso.eurostat.ec.europa.eu/nui/show.do?dataset=nrg_pc_205&lang=en (select time frame back to 2008 and prices including all taxes and levies; prices converted to U.S. cents/kWh at 1.23 euro/dollar exchange rate). U.S. prices from Energy Information Administration data here, https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_5_03. ↑
http://energypost.eu/energiewende-running-limits/. ↑
http://energypost.eu/end-energiewende/. ↑
https://www.cleanenergywire.org/factsheets/climate-and-energy-germanys-government-coalition-draft-treaty. ↑
http://interfaxenergy.com/gasdaily/article/29453/german-lng-terminal-plans-draw-mixed-response. ↑
https://www.diw.de/de/diw_01.c.532689.de/presse/diw_roundup/demand_response_in_germany_technical_potential_benefits_and_regulatory_challenges.html. ↑
https://www.entsoe.eu/Documents/TYNDP2018_MAF2017_Market%20Data_provisional.xlsx (Tab BE 2025, Germany columns for “Hard coal” and “Lignite” assume 31.3 GW of coal capacity and, by the way, 27.6 GW of natural gas capacity); https://www.entsoe.eu/Documents/SDC%20documents/MAF/MAF2016_market_modelling_data.xlsx (prior year version with similar coal and gas natural capacities); https://www.bmwi.de/Redaktion/DE/Downloads/V/versorgungssicherheit-in-deutschland-und-seinen-nachbarlaendern-en.pdf?__blob=publicationFile&v=3 (pdf page 32). ↑