Page 1257 – RTO Insider

October 30, 2017

AEP Falls Short of Q3 Expectations, Remains Optimistic

By Tom Kleckner

American Electric Power on Thursday said the mildest weather conditions since 1992 led its third-quarter sales to fall 12.8% from a year ago, down to $4.1 billion.

The Columbus, Ohio-based company reported a quarterly profit of $544.7 million, a vast improvement over last year’s loss of $765.8 million for the same period. A one-time $2.3 billion impairment charge in 2016 related to the value of competitive coal plants, wind farms and coal-related properties accounted for much of that loss. (See AEP Turns Away from Generation to Transmission, PPAs.)

But the company’s adjusted earnings per share of $1.10 missed the Zacks consensus estimate of $1.19. It was also down from $1.30/share — which excluded the impairment — a year ago. Its year-to-date earnings are $2.82/share, down from $3.25/share in 2016.

During an earnings call, CEO Nick Akins, a drummer in his spare time, drew inspiration from the progressive rock group Dream Theater’s song “Another Day” in reaffirming 2018’s guidance range of $3.75 to $3.95/share, built around a 5 to 7% growth rate. He recited the song’s lyrics to analysts: “Live another day, climb a little higher, find another reason to stay.”

“Because of our efforts to overcome the weather and other obstacles, we’ll finish out the year 2017, we’ll live for 2018, and continue on our path,” Akins said. “The fundamentals of our business plan remain secure, and we’re confident going into 2018.”

AEP narrowed its guidance range for 2017 to $3.55 to $3.68/share. Akins said the company will make up lost ground by “driving efficiency, eliminating expenses where practical and with negligible movement of expenses to 2018.” The company also expects to benefit from continued economic growth in its footprint.

Akins said AEP now has procedural schedules in the four state jurisdictions — Arkansas, Louisiana, Oklahoma and Texas — with regulatory oversight of the company’s proposed $4.5 billion Wind Catcher Energy Connection Project, a 2-GW wind farm in the Oklahoma Panhandle. Hearings will be held January in Oklahoma and Texas, February in Louisiana and March in Arkansas. The company has requested approvals by April 30.

“At this point, I should figuratively drop the microphone,” Akins said, “but we’ll let the facts — $4.5 billion invested, $7.6 billion in customer savings, substantial infrastructure development and great use of wind resources — speak for themselves.”

AEP also has $603 million in pending rate cases before five state regulatory commissions.

October 30, 2017

CPUC Bolsters Demand Response, Pans Resiliency NOPR

By Jason Fordney

SACRAMENTO, Calif. — California regulators voted Thursday to extend the life of a state demand response pilot project, saying they hope it could lead to a permanent program to help meet the state’s clean energy goals.

FERC CPUC Demand Response extended LMP — California PUC staff present their comments on the U.S. Department of Energy’s grid resiliency pricing rule proposal to the commission. | © *RTO Insider*

The California Public Utilities Commission heard from the public about several matters at the meeting, held across the street from the state capitol. The five commissioners were also predictably unified in their opposition to any possible FERC-proposed grid resiliency pricing rule as a result of the U.S. Department of Energy’s Notice of Proposed Rulemaking calling for financial support for nuclear and coal-fired power plants.

DRAM Extended

The PUC unanimously approved extending the Demand Response Auction Mechanism (DRAM) pilot program into 2018, against the recommendation of its administrative law judges.

“There were a lot of things that really led me to this decision to see the merit of continuing with this an additional year,” Commissioner Martha Guzman-Aceves said. The program has grown in terms of new participants, including low-income residents, “to levels that are really quite outstanding and different from the [investor-owned utility] programs.”

In the DRAM program, third-party sellers bid aggregated DR directly into the CAISO day-ahead energy market. Utilities acquire the capacity but do not receive revenues winning bidders might gain from the market. In the 2017 DRAM, third-party providers could bid in as both local and flexible resource adequacy, not just system resource adequacy.

Thursday’s decision requires Pacific Gas and Electric and Southern California Edison to procure $6 million of DR in their territories in a 2018 auction for 2019 delivery, while San Diego Gas & Electric must acquire $1.5 million. DR companies bid for the contracts on a pay-as-bid basis.

The program also created two new working groups: one to define new DR programs, and one to study barriers to DR.

Commissioner Liane Randolph said, “It is helpful for us to continue these pilot projects until the evaluation is complete, and we decide whether we are ready to adopt the DRAM as a permanent program.” By keeping the auctions going and modifying the guidelines, “we encourage market participants to continue to invest in this new type of DR,” she said.

Commissioner Carla Peterman said there are limited opportunities for DR.

“I do think it is important to continue our momentum in this area,” Peterman said. She noted the auction will use the same procurement guidelines as a permanent auction. “I think it will be a good opportunity to see how those guidelines work in practice,” she said.

Commission Encourages CCA, Direct Access DR

The commission’s decision also moves forward the process of enabling community choice aggregators (CCAs) and direct access (DA) providers to create DR programs to compete with those of IOUs.

California’s CCA program allows local governments to aggregate retail electric customers and secure electricity supply contracts to serve them, while the DA program allows some nonresidential customers — such as agricultural, commercial and industrial, and small business — to choose alternative electricity suppliers.

The decision allows CCAs and DA suppliers to file with the PUC to determine whether their DR programs are similar to those of utilities. The measure takes steps to implement the “Competitive Neutrality Cost Causation Principle,” which defines what constitutes a similar program and adopts a four-part process make a final determination. If a CCA or DA provider proves its case, competing utilities must cease cost recovery for DR from customers that sign up with the third-party programs.

Chairman Michael Picker said he supports the proposal, but he is concerned that by moving existing DR customers out of the rate base of regulated utilities into the rate base of the CCAs, “we are frustrating the second promise of the CCAs, which is that they will create competition. Here we are actually hindering competition.”

Picker added that it will be important to carefully analyze the applications for DR programs. “The practice has not always met the theory in CCA world; they have been uneven in actually expediting our drive for clean energy sources,” he said.

But he said he strongly support the continuation of the DRAM because it has created unique products, not just opportunities to arbitrage.

Strong Opposition to DOE NOPR

The commission also endorsed comments developed by staff in opposition to the DOE NOPR. Comments on the proposal were due to FERC on Oct. 23.

The approved comments state that “this rushed effort erodes trust in U.S. wholesale electric markets and undermines the role of the FERC as an independent body. If the energy crisis has taught us anything, it is that diversification of resources is critical for resiliency and reliability planning.”

Instead of narrowing the choice of resources that qualify as “resilient,” the PUC said there should be “a wide range” of tools to meet reliability needs, including energy storage, flexible demand and distributed energy technologies.

Picker said that while any such rule would have little immediate impact in California, it could in the long term, and it has aroused concern in neighboring states. He said it was a signal that the Trump administration does not “care to observe a series of long-held conventions on wholesale markets.” The parties creating the rule “don’t have their act together to actually come up with a reasonable argument” and “they have a prescription that is looking for a problem,” Picker said.

Commissioner Clifford Rechtschaffen said “this rule did what was otherwise unimaginable,” noting that it united petroleum, natural gas and renewable energy interests in opposition. “It is so beyond the pale,” he added, saying that PUC staff had devised a strong mix of legal and policy arguments against the rule.

October 30, 2017

Entergy Profits up as Company Continues Merchant Gen Exit

Entergy last week reported a third-quarter profit of $398.2 million ($2.21/share), up from $388.2 million ($2.16/share) a year ago.

“We now expect to finish the year in the top half of our utility, parent and other adjusted earnings guidance range,” CEO Leo Denault said in a statement.

The New Orleans-based company affirmed its 2017 operational earnings guidance range of $6.80 to $7.40/share, and its utility, parent and other segment adjusted guidance range of $4.25 to $4.55/share. Operational earnings do not include non-routine expenses, such as the costs to close or sell the company’s merchant nuclear power plants.

Denault said Entergy will work with regulators to recover $85 million to $120 million in Hurricane Harvey restoration expenses, and that the company expects $3 million to $5 million in unbilled revenue for 2017.

entergy profits q3 — Palisades plant | *Entergy*

The CEO also said Entergy’s recent decision to extend a power purchase agreement with Consumers Energy regarding the Palisades nuclear plant does not mean the company is staying in the merchant nuclear business. (See Entergy Abandons Palisades PPA Termination.)

“Our strategy to exit the merchant business and become a pure-play utility remains unchanged,” Denault told analysts in an earnings call last Tuesday. “This decision to continue to operate the plant will preserve value for our owners while extending our exit from the merchant nuclear business by only a year.”

— Tom Kleckner

October 30, 2017

ERCOT Briefs

ERCOT last week approved the shutdown of two plants, including Luminant’s coal-fired Monticello facility in East Texas, that will take nearly 2 GW of antiquated generation out of service.

Staff approved Monticello’s retirement, effective Jan. 4, saying the plant is not necessary for reliability operations. The plants’ three units, dating back to the 1970s, have a combined capacity of 1,880 MW but found themselves frequently out of the market. Luminant announced the units’ proposed retirement Oct. 6. (See First Shoe to Drop? Vistra to Retire 3 Texas Coal Units.)

ERCOT Coal-Fired Generation Luminant Monticello — Luminant’s Monticello Power Plant | *Luminant*

The ISO also approved the indefinite mothballing of two gas units at the city of Garland’s Spencer plant, totaling 118 MW of capacity. The city filed notice with ERCOT on Oct. 4. The units began service in 1966 and 1973.

TAC Approves LDF Library Changes in Email Vote

ERCOT’s Technical Advisory Committee last week unanimously approved staff revisions to the ISO’s load distribution factor (LDF) library. The measure gathered 23 out of a possible 30 votes by email.

The vote was conducted after an Oct. 23 web informational session, which became necessary following revisions to account for a nodal protocol revision request (NPRR831).

Staff made changes related to private-use networks (PUNs), which are connected to the ERCOT grid and contain load that is typically netted with internal generation and not directly metered by the ISO. The change updates market systems to calculate a net load value for each PUN that will be included in the load zone price for all markets, when the load is a net consumer from the grid.

LDFs are used in congestion revenue rights and day-ahead market clearing activities, and developed using historical state estimator or supervisory control and data acquisition (SCADA). ERCOT staff added language to generate LDFs for PUN loads, which behave differently from non-PUN loads.

TAC’s October meeting, scheduled last Thursday, was canceled because of a lack of voting items.

— Tom Kleckner

October 30, 2017

FirstEnergy Selling Merchant Fleet Despite NOPR

By Rory D. Sweeney

FirstEnergy supports the U.S. Department of Energy’s call to financially support nuclear and coal-fired units, but that won’t stop the company from selling off its merchant generation fleet and retreating to the predictable returns of regulated assets.

FERC NOPR merchant generation FirstEnergy — FirstEnergy’s Akron, Ohio headquarters

CEO Chuck Jones last week said he is also “pleased” with signs of state-level support, including a resolution from the Pennsylvania legislature supporting the department’s proposal and the introduction of the Ohio Clean Energy Jobs bill to support nuclear units with zero-emissions credits (ZECs). But “whether these state or federal activities result in meaningful and timely support remains to be seen,” he said.

“We have no interest in maintaining generating assets that have commodity exposure, and we’re moving forward with exiting the commodity-exposed generation business,” Jones said during a call to discuss third-quarter earnings.

FirstEnergy reported earnings of $396 million ($0.89/share) on $3.7 billion in revenue, missing guidance by $80 million. However, operating earnings of 97 cents/share beat guidance by 10 cents. The results exceeded performance from the same quarter a year ago, when the company reported earnings of $380 million ($0.89/share) on revenue of $3.9 billion and non-GAAP earnings of 90 cents.

Company executives credited the success to “stronger-than-expected results” in its competitive and corporate segments, along with solid regulated performance that included distribution deliveries that were better than forecasted and higher transmission revenues.

The company increased its GAAP forecast for 2017 to a range of $2.02 to $2.42/share and non-GAAP to $3 to $3.10/share, which had been targeted at $2.70 to $3/share.

Jones said Ohio’s House Bill 381 was introduced earlier this month with terms that were “reduced” from FirstEnergy’s previous requests for nuclear price supports. But they’re “likely” enough to make plants “economically viable” when combined with the planned restructuring of First Energy Solutions (FES), the company’s competitive generation arm. He expects a final vote on the measure around the middle of the first quarter next year.

“We believe this effort is imperative for Ohio’s energy security,” he said.

Despite the price support discussions, the company remains focused on shedding FES, Jones said.

“A preferred outcome” would include agreement from FES’ creditors, he said, but Chapter 11 bankruptcy remains an option that hinges on several variables, including DOE’s proposal, FERC’s actions and discussions with creditors’ advisers.

“We recognize the varied interests of our stakeholders, but we’re also aware that some have an interest in floating rumors about our company,” he said in warning that he would not discuss the progress of negotiations.

The company is moving quickly to disgorge the assets. LS Power has agreed to pay $825 million in cash for 1,615 MW of capacity that includes four Pennsylvania gas-fired plants and interests in the Bath County Hydro and Buchanan gas-fired facilities in Virginia, which are owned by FirstEnergy’s Allegheny Energy Supply subsidiary. The transaction involving the four Pennsylvania gas plants is expected to close this year, while the sale of the interest in the Virginia facilities is expected to close in the first quarter of 2018.

Jones said the full deal, which added some assets but was still reduced by $100 million since it was announced earlier this year, was priced on “the existing market conditions.”

The company’s regulated Monongahela Power subsidiary in West Virginia “continues to work through the regulatory process” to take ownership of the 1,300-MW Pleasants plant and expects approval from the West Virginia Public Service Commission and FERC by early 2018, Jones said. Allegheny expects to receive $350 million in net proceeds after paying off all its remaining long-term debt.

October 30, 2017

MISO Clear to Adopt One-Time Interconnection Study Fee

FERC last week approved a MISO proposal to charge interconnection customers subject to quarterly operating limit studies $10,000 as a deposit (ER17-568).

MISO interconnection study — | © *RTO Insider*

MISO had estimated that its annual cost of quarterly operating limit studies for an interconnection customer was about $2,500, which it had been collecting yearly. The change allows the RTO to charge a single $10,000 fee to cover four years and refund any remaining amount when the customer is no longer subject to quarterly operating limits. MISO said the new collection schedule will be more efficient for interconnection administrators.

FERC accepted the Tariff revisions effective Feb. 15, 2017, on the condition that MISO clarify that the $10,000 study deposit is a one-time fee and not due every quarter.

MISO created quarterly operating limits almost a decade ago to allow for the limited operation of some generators based on seasonal studies.

— Amanda Durish Cook

October 30, 2017

Lively OMS Discussion Probes Common Grid Beliefs

By Amanda Durish Cook

CHICAGO — State regulators, their staff and utility executives proved reluctant to be pinned down on predictions about the future of the grid during a spirited question-and-answer session at the annual meeting of the Organization of MISO States (OMS) last week.

OMS MISO organization of miso states — Deora | © *RTO Insider*

Tanuj Deora, chief content officer of clean energy facilitator Smart Electric Power Alliance, posed a series of questions to scrutinize attendees’ core assumptions about the power grid during the Oct. 27 meeting.

“We have an agreement that the power grid is the foundation of our modern civilization, yes?” he asked the audience rhetorically. “Well, there are a number of folks pushing back at that.”

Deora said he’s encountered people who are convinced that the power grid will become a stranded asset. Just a smattering of hands went up in the audience when he asked if any of them believed that people would altogether defect from the grid in the future.

A Future of Low Load Growth

Deora pointed out that recent trends demonstrate that economic growth no longer drives power consumption. “I think most people are planning on a world where we don’t have a lot of load growth,” he said.

Some in the audience noted that electricity demand could spike over the next five to 10 years as more consumers adopt electric vehicles, similar to past spikes when refrigerators and air conditioning started to become commonplace. Deora also pointed out that electricity could increasingly displace natural gas for water and space heating as gas suppliers realize that may be more feasible to meet state emission-reduction targets.

Other audience members noted that if President Trump succeeds in a reviving American manufacturing, companies won’t return to now-vacant energy-devouring factories, but instead design energy-efficient spaces.

Wisconsin Public Service Commission staffer Randy Pilo added that, after multiple years of growth, a recession will loom sooner or later.

A Gray Area

Deora was met with no audience agreement when asked if regulators should continue to plan the grid on the assumption that generation should follow load with no reserve inventory.

“That is a sea change, because, gosh, the [Department of Energy] believes this with their measure of resiliency,” Deora said. He added that he believes the U.S. is on the verge of a “demand response renaissance.”

At least half of the audience agreed that economies of scale still favor central station generation, but generally hesitated when Deora asked whether that supply is best provided through the usual baseload, mid-priced peaker model.

“Come on, this was the first thing I learned as an intern,” Deora said, lightheartedly goading the audience.

Multiple audience members called out: “You can’t choose!” and “It’s gray area!”

“That worked really well when you could build a baseload plant and get energy value. … It’s turned on its head,” said Bruce Campbell, director of regulatory affairs at CPower Energy Management. He said once natural gas prices eventually rise, developers will migrate to yet another fuel type.

Deora ventured that it may be time to reconsider the economic model for power. “Usually when I bring up at conferences that we might need a rethink of power economics, the audience shudders and tells me it’s not time,” he said.

‘Sleepy Backwater’

Deora said that while some utilities are still focused on being a strict wires-only owner or operator, more are exploring how to optimize a distribution system platform or interconnect distributed energy resources — and are even open to owning their own portfolio of distributed resources.

Charles Goldman, a strategic adviser with the Lawrence Berkeley National Laboratory, said past predictions of the adoption of photovoltaic DER have proven too conservative. He said in his state of California, distributed solar is in clustered hot valley areas, wealthy coastal communities and tech-friendly Silicon Valley. Rooftop solar has significantly shifted the noon to 6 p.m. load curve.

“It’s all happened in the last four to seven years,” Goldman said.

“I realize in the Midwest, this is not a topical, front burner issue,” he said, but he noted that Minnesota is considering requiring its utilities to file distribution system plans, including DER forecasting.

“Distribution planning has been the sleepy backwater,” Goldman said.

He admitted that RTOs will have more difficulties forecasting and modeling future distributed resources than single-state ISOs.

Outgoing OMS President and Indiana Utility Regulatory Commissioner Angela Weber said regulators and OMS are uniquely positioned to steer the industry in rules surrounding DER.

“It’s the first time in OMS that I see the states leading on an issue.”

October 30, 2017March 20, 2024

Texas Regulators Seek More Details on Sempra Oncor Bid

By Tom Kleckner

AUSTIN, Texas — The Public Utility Commission of Texas on Thursday threw a bit of cold water on Sempra Energy’s proposed $9.45 billion acquisition of Oncor after issuing a preliminary order that calls for Sempra to prove it’s financially fit to own the state’s largest utility.

Whether that’s enough to short-circuit yet another bid — the third — for Oncor remains to be seen.

Commissioner Ken Anderson filed a memo last week asking for more information on Sempra’s debt, the transaction’s financing, Oncor’s governance structure, the effect of Sempra’s other projects on its credit rating and Sempra’s corporate relationship with Oncor (Docket 47675).

“These issues are important because Sempra creates uncertainty when it fails to produce details about how it will fund the transaction,” Anderson wrote. “The purchaser must be able to prove it has the financial strength and stability to complete the purchase on its own, without impairing itself or Oncor.”

Hunt Consolidated and NextEra Energy failed in previous acquisition attempts to meet the PUC’s ring-fencing measures. Sempra announced it would make a bid for Oncor in August. (See Sempra Outmuscles Berkshire for Oncor.)

Anderson said Sempra’s current application before the commission provides “very limited details” on how it will finance the transaction and manage “liabilities associated with its debt and far-flung operations.” He noted the company’s debt has risen from $5 billion in 2007 to about $18 billion, but that cash from operations increased slightly through 2009 and has remained relatively stable since.

“So far, it seems Sempra has not realized a proportional increase in cash flow from its projects,” Anderson wrote.

Anderson reminded Chair DeAnn Walker and fellow Commissioner Brandy Marty Marquez that the PUC’s goal is to “once and for all” help Oncor escape a “risky, debt-laden majority owner” and “move forward without the nagging specter of a financially troubled parent.”

Oncor parent Energy Future Holdings, which declared bankruptcy in 2014, has retained an 80% stake in the utility since going into Chapter 11.

“Our objective,” Anderson said, is to “ensure that Oncor is not being permitted to hop from one frying pan into another, or even just into a simmering pot.”

He added a list of additional issues to be considered in the preliminary order, which Walker and Marquez approved.

Spokesperson Amber Albrecht took exception to Anderson’s comments, saying Sempra is a “very strong, growing and conservatively financed company.”

“We have investment-grade credit ratings at the holding company level, as well as at all of our operating subsidiaries, and our market capitalization over the past 10 years has grown to nearly $29 billion from about $15 billion,” she said.

Anderson allowed that while Sempra’s current credit ratings of Baa1 (Moody’s) and BBB+ (Standard & Poor’s) are investment grade, they are also “bottom tier.”

“The company is vulnerable to changing economic conditions and could face challenges if overall economic conditions decline or if Sempra continues to experience significant challenges,” Anderson said, pointing to the company’s $10 billion LNG export project in Louisiana and international holdings in South America.

Sempra has already revised its financing structure since its initial bid in an effort to appease intervenors in the previous attempts to acquire Oncor. (See Sempra Reworks Oncor Bid to Erase EFH Debt.)

The PUC has scheduled a Feb. 21-23, 2018, hearing on the proposed acquisition in Austin.

PUC Orders Refiling in NextEra Ownership Bid for Oncor

The commission also rejected NextEra’s bid to acquire a 19.75% interest in Oncor and directed the parties involved to refile an application that includes Oncor as an applicant.

Walker had suggested in a memo that the filing be dismissed, saying the state’s Public Utility Regulatory Act (PURA) requires the “statutorily specified entity” to submit the filing. Anderson and Marquez agreed.

NextEra and Texas Transmission Holdings Corp. (TTHC), which owns the 19.75%, filed a joint application with the PUC in July. However, staff in August ruled the application deficient, saying neither applicant is a public utility under state regulations and that the case should not proceed without Oncor’s involvement (Docket 47453).

Oncor intervened in the proceeding in September, telling the PUC that it was not “seeking commission approval of the proposed sale.”

In her memo, Walker referenced statutory language that “an electric utility or transmission and distribution utility must report to and obtain approval of the commission before closing any transaction in which … a controlling interest or operational control of the electric utility or transmission and distribution utility will be transferred.”

Noting that neither NextEra nor TTHC complies with the requirements, Walker wrote, “In this case, Oncor must file the relevant report regarding this proposed transaction.”

Walker said the refiling would allow the commission to determine whether the proposed transaction should close.

Vinson & Elkins’ Matt Henry, representing Oncor, promised action within a few weeks. He said the utility intended to consult with NextEra and TTHC to determine how to proceed with a final filing, and that it would have to talk with Oncor’s board as well.

Commission Rules Against SPS’ Right of First Refusal

The commission issued a final order that made official its earlier rejection of Southwestern Public Service’s exclusive right to build new regionally funded transmission facilities in its service territory (Docket 46901).

The PUC discussed the issue publicly in July, making it clear how it would rule. (See Texas Commission Rejects SPS ROFR Request.) SPS said at the time it would seek a rehearing and an appeal; spokesman Wes Reeves said Monday the company plans to file a motion for rehearing by Nov. 20.

The commission further concluded that transmission facilities serving the public cannot be constructed in Texas without first obtaining a certificate of convenience and necessity (CCN) from the commission.

“Such a right would be inconsistent with the commission’s authority to issue CCNs for transmission facilities, which is not limited to only utilities that have a certificated service area in which the facilities would be located,” the commission wrote.

Walker abstained from the order, as the proceeding occurred a month before she joined the commission.

SPP and SPS in February requested the PUC determine whether the utility has the exclusive right to construct and operate new, regionally funded transmission facilities in areas of Texas that lie within its certificated service area. (See SPS, SPP Ask Texas to Rule on Transmission Competition.)

SPS contended that as an incumbent utility operating outside ERCOT, PURA gave it a right of first refusal to build in the service area prescribed by the PUC. SPP claimed that no such right existed, giving the RTO the ability to solicit and designate transmission-only utilities to construct and operate new transmission facilities within SPS’ service area under FERC Order 1000.

The project in question, the 345-kV Potter-Tolk transmission line in the Texas Panhandle, was pulled from SPP’s 10-year planning assessment in April. SPP’s Board of Directors directed staff to conduct a congestion study in the area, due within a year. (See SPP Board Cancels Panhandle Line, Seeks New Congestion Study.)

ERCOT’s Budget, Admin Fee Approved

The commission formally approved ERCOT’s 2018/19 biennial budget, which will keep the ISO’s system administration fee flat at 55.5 cents/MWh for the next two years (Docket 38533). The fee was raised from 46.5 cents/MWh in 2015.

The ERCOT board approved the budget in June, setting operating expenses, projects and debt-service obligations at $222.3 million and $228.0 million for 2018 and 2019, respectively.

October 30, 2017

FERC Denies CAISO Waiver for DR Availability

FERC last week denied CAISO’s request to waive Tariff requirements regarding “availability assessment hours” used to assess utilities’ compliance with resource adequacy requirements (ER17-2263).

The ISO uses availability assessment hours to measure the availability of generation during a predetermined time period of the day for each type of capacity. Resources that are available for 98.5% of the hours for a month are eligible for payments, while resources that are available for less than 94.5% for that month are subject to non-availability charges.

CAISO FERC waiver Demand Response — | *City of Glendale, Calif.*

CAISO wants to keep its 2017 availability assessment hours for 2018, but that violates a requirement that the hours vary by season. The ISO requested the waiver to provide relief to demand response companies that had offered to provide capacity based on qualifying capacity values calculated under California Public Utilities Commission rules, which are the same as 2017, creating a conflict with CAISO rules.

FERC’s Oct. 24 order said the waiver request affects the availability assessment hours applied to all nonexempt resource adequacy resources and not solely the DR providers that require relief.

“CAISO does not provide a precise accounting of the demand response resources that require relief through this waiver request,” FERC said. “However, the number appears to be relatively small compared with the total number of resource adequacy resources subject to the availability assessment hours. In sum, CAISO has not shown that the small amount of resources requiring relief justifies or requires the proposed scope of the waiver CAISO requests.”

The commission said CAISO could submit a limited waiver request that directly addresses the problem of DR participation without creating undesirable consequences for the resource adequacy program.

— Jason Fordney

October 30, 2017

OMS Still Seeking Unity on MISO Tx Cost Allocation

By Amanda Durish Cook

CHICAGO — The Organization of MISO States (OMS) last week failed to reach consensus on how to respond to MISO’s plans to allocate costs for smaller transmission projects that produce broader economic benefits for the grid.

OMS is slated to present its suggestions on cost allocation at a Nov. 16 Regional Expansion Criteria and Benefits Working Group (RECBWG) meeting, but members were still unable to develop a unified position during their annual meeting on Oct. 27. OMS set a priority to establish a group position on the subject late last year. (See No OMS Consensus on MISO Cost Allocation Changes.)

LOC MISO cost allocation market efficiency projects — The OMS Annual Meeting was in Chicago, Ill. on October 27, 2017 | © *RTO Insider*

MISO currently has no mechanism in place for allocating costs for economic projects with voltage ratings below 345 kV.

OMS board members say they might ask MISO to require market efficiency projects to be at least 230 kV and have a cost threshold of either $1 million or $5 million to $20 million in order to be eligible for cost allocation. They could also request that the benefit-cost ratio be increased from 1.25:1 to 1.5:1 if benefits other than the adjusted production cost are factored in, a move MISO has promised to consider.

The RTO has meanwhile assembled a straw proposal that would lower the cost allocation eligibility threshold to 100 kV, replace the 20% footprint-wide allocation with a postage stamp rate and enact a still unspecified project cost threshold. The proposal would limit cost allocation to benefiting transmission pricing zones.

Missouri Public Service Commission economist Adam McKinnie said his state requires a voltage threshold below 230 kV. “The interconnections between my state are 161 kV [or] 169 kV. I’m very wary of any cost allocation that does not give lower-voltage projects between SPP and MISO a cost allocation,” he said.

North Dakota Public Service Commissioner Julie Fedorchak expressed discomfort with any proposal that would allocate 100% of costs to benefiting transmission pricing zones, pointing out that much of the transmission development occurring in her state will not necessarily benefit its ratepayers.

The OMS board has also contemplated a cost-sharing proposal that would designate one portion of costs to benefiting transmission pricing zones and another to the local resource zones that contain those pricing zones.

“I think this debate shows that regulators need time to go back to their states and digest this,” said OMS President Angela Weber.

“Every state might not get everything they want, but the question is, ‘Can we come up with something that is better than what MISO is proposing?’” said Public Utility Commission of Texas staffer Werner Roth.