While MISO is under budget so far in 2018, the RTO’s financial staff is forecasting a slight overspend by year-end, members of the Audit and Finance Committee of the Board of Directors learned Wednesday.
In the first three months of 2018, MISO has spent $41.5 million of its $42.3 million year-to-date budget, under budget by 1.8%. Chief Financial Officer Melissa Brown said the savings were mostly related to belated start times of some of MISO’s planned investments.
“A lot of those just had slow starts this year,” Brown said during a committee conference call ahead of a March 29 board meeting in New Orleans, where numbers will again be presented.
However, Brown said MISO is forecasting spending $266.8 million by year-end, 0.7% more than its $264.9 million 2018 budget. The expected overspend is because MISO is reclassifying $1.6 million from its capital budget into one-time operating expenses. The reclassification will lower the RTO’s projected total capital expenses from $29.6 million to $28.1 million for the year.
| MISO
So far this year, MISO’s capital spending is trending lower, also owing to delayed project starts, Brown said. To date, the RTO has spent $6.1 million of its $7.3 million budget.
In addition to beginning work to replace MISO’s aging market platform with a new modular computer system, the 2018 capital budget includes maintaining its cybersecurity team, automating employee system access revocations, automating its settlements program, replacing software and hardware that fails throughout the year and renovating meeting space at the Carmel, Ind., headquarters.
Board Chairman Michael Curran asked in future meetings to see a separate financial report for MISO’s $130 million, seven-year effort to replace its market platform. (See MISO Makes Case for $130M Market Platform Upgrade.)
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.”
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.”
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.
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.
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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.)
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.
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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.)
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.
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.
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.”
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.
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.
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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.
Meade and Prettyman Courthouse | DC-Circuit
“Except to the extent that the challenges are moot, we affirm EPA’s actions,” said the March 20 opinion 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.”
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.
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 statement. “We are confident in his ability to lead the agency as it fulfills its oversight role.”
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.
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.
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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.
BOSTON — The numerous East Coast offshore wind projects being developed through individual state procurements should be viewed as regional resources, panelists told a New England energy conference last week.
The 10 GW of offshore wind slated for the region has already reached a critical mass that has lowered financing costs and promises local suppliers a real market rather than a one-off opportunity, a panel of three offshore developers and one state regulator said during the Raab Associates’ 157th New England Electricity Restructuring Roundtable on Friday.
Massachusetts in 2016 set a goal to develop 1,600 MW of offshore wind by 2030, followed last year by New York, which is targeting 2,400 MW by 2030. New Jersey this year topped both with a target of 3,500 MW by the same year.
While slightly behind Massachusetts, New York is in a hurry to get rolling and plans to issue its first 400-MW offshore wind solicitation this fall, followed by a similar one in 2019, said Alicia Barton, head of the New York State Energy Research and Development Authority. (See NY Offshore Wind Plan Faces Tx Challenge.)
“I think people are looking at this the wrong way, looking at it state by state,” Barton said. “These are all leases in federal waters and this will be a growing Northeast regional resource rather than a state-by-state resource.
Although New York’s Public Service Commission will make the final determination, NYSERDA would propose to provide eligibility to projects that can either deliver directly into NYISO or through an adjacent control area, she said.
“We are eager to send the message that all of these leaseholders should be looking at this New York market opportunity and this procurement coming up,” Barton said.
First Actor Advantage
Representatives of the three developers who bid into Massachusetts’ offshore wind solicitation in December supported Barton’s regional resource theme, but each would first like to win the Massachusetts contract.
Orsted North America President Thomas Brostrom said his company will soon announce the first offshore wind factory in the U.S., to be located in Massachusetts. He said Orsted has “entered into an exclusive arrangement with a very large and recognized European manufacturing company” for the facility.
For the solicitation, Orsted partnered with Eversource Energy to form Bay State Wind, which proposed a 400-MW or 800-MW wind farm 25 miles off New Bedford, to be paired with a 55-MW battery storage facility.
“You create an industry when you have volume and pipeline,” Brostrom said. “You have basically a pipeline of 10 GW; that’s why we think we can create a local supply chain now.”
The growing reality of a Northeast offshore wind industry is already influencing bankers, who have quickly reduced the cost of project financing, he said.
In its initial request for proposals in its 83C solicitation last July, Massachusetts sought a minimum of 400 MW of offshore wind but said it would consider bids of up to 800 MW if it determines that a larger proposal “is both superior to other proposals submitted in response to this RFP and is likely to produce significantly more economic net benefits to ratepayers.”
| Deepwater Wind
The three developers, Bay State, Deepwater Wind and Vineyard Wind (the last of which is a joint venture between Avangrid Renewables and Copenhagen Infrastructure Partners), placed their bids in December and the state will announce winners on April 23, with contracts to be submitted at the end of July. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)
Brostrom presented Orsted as the global leader in offshore wind, but Matthew Morrissey, vice president of Deepwater, said his company was the leader in the Americas, having built the 30-MW Block Island project, the only offshore wind farm operating in the U.S.
Deepwater also signed a contract with the Long Island Power Authority last year for the 90-MW South Fork project, scheduled to become operational in 2022.
In Massachusetts, Deepwater proposed two versions of Revolution Wind, a 200-MW wind farm consisting of about 25 turbines, or one double that size.
“Revolution Wind contains a very innovative, expandable transmission system, a pumped storage offering and, for a project of this scale, enormous economic impact,” Morrissey said. “The Brattle Group provided us with a study — 2,700 jobs, $300 million in economic impact, and we are committed to delivering our power in 2023.”
Deepwater’s proposal includes an agreement with the largest hydroelectric pumped storage facility in New England, the 1,200-MW Northfield Mountain station operated by FirstLight Power Resources.
“The reason why timing matters here — Alicia said it’s a regional industry and I fully agree with that — but the reality is that the first projects will decide where the first part of the supply chain goes,” said Lars Pedersen, CEO of Vineyard Wind, which submitted proposals for 400-MW and 800-MW wind farms with approximately 50 and 100 turbines, respectively. “And if you follow the logic from Europe, the more of a head start you get, the more likely you are to get more of the supply chain.”
There will be supply chain up and down the East Coast, as there should be, Pedersen said, but Massachusetts has an “incredible” starting advantage with the harbor in New Bedford. He said that synergies on the transmission side of the project would enable his company to build an 800-MW line for essentially the same cost as a 400-MW one.
