Page 1249 – RTO Insider

November 3, 2017

McIntyre and Glick Confirmed to FERC

By Peter Key

The Senate on Thursday confirmed Republican Kevin McIntyre and Democrat Richard Glick to FERC, giving the commission a full panel for the first time in two years.

The two were approved on voice votes, putting them in a position to weigh in on Energy Secretary Rick Perry’s controversial proposal to provide price supports to coal and nuclear plants in competitive markets (RM18-1).

Kevin McIntyre Richard Glick FERC — McIntyre (left) and Glick before their confirmation hearing | © *RTO Insider*

McIntyre, the coleader of the global Energy Practice at the law firm Jones Day, will serve out the rest of a term that ends June 2018, and then serve a full term that ends June 2023. Glick, the general counsel for Democrats on the Senate Energy and Natural Resources Committee, will serve a term that ends in June 2022.

FERC REV Senate Energy and Natural Resources Committee Kevin McIntyre — McIntyre | © *RTO Insider*

The nominations of McIntyre and Glick were approved by the Senate Energy and Natural Resources Committee in September, but their confirmations were blocked last month by Sen. Jim Inhofe (R-Okla.), who complained Senate Democrats were blocking several of President Trump’s other nominees. (See Senate Panel Clears McIntyre, Glick for FERC.)

The two were among more than two dozen appointees approved Thursday.

Once they are sworn in, FERC will have its full five members for the first time since October 2015, when Republican Philip Moeller left the commission. FERC was without a quorum between February, when former Chairman Norman Bay resigned, and August, when Republicans Neil Chatterjee and Robert Powelson joined Commissioner Cheryl LaFleur on the commission. (See FERC Quorum Restored as Powelson, Chatterjee Confirmed.)

Chatterjee welcomed the two in a statement released by FERC. “I’ve enjoyed getting to know Kevin through the confirmation process and am eager to start working with him, and it will be great to reunite with Rich Glick, my former Senate colleague,” he said.

The addition of the two ensures, however, that Chatterjee would need to attract at least two votes for a majority in support of the Department of Energy’s Notice of Proposed Rulemaking to provide “full recovery” of nuclear and coal plant costs. (See FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.)

Chatterjee said at a luncheon Wednesday that the federal government may “cast a lifeline” to coal and nuclear power plants while it conducts a long-term review of the country’s power grid. Chatterjee said he was worried that short-term market pressures would force the owners of coal and nuclear plants to close them and later on the country would realize it needed the power they produced.

Although DOE put no price tag on its proposal, estimates of its cost range into the billions. (See Cost Estimates on DOE NOPR: $300 million to $32 billion.) In a conference call with Kentucky reporters Thursday, Chatterjee acknowledged that the policy could result in higher electric bills for some customers. Additional revenue to keep struggling coal plants running “would come from customers in that region, who need the reliability,” he said, according to the Courier Journal. “It’s in these customers’ interests to keep these plants open.”

Chatterjee, like his former boss, Senate Majority Leader Mitch McConnell, is from Kentucky.

During his confirmation hearing, McIntyre said, “FERC is not an entity whose role includes choosing fuels for the generation of electricity.” (See McIntyre to Senate: ‘FERC does not Pick Fuels’.)

November 2, 2017

MISO: Tx Link from Ontario to Mich. UP not Cost Effective

By Amanda Durish Cook

MISO has concluded there’s little economic benefit to new transmission connecting Michigan’s Upper Peninsula to Ontario.

Reporting on the results of a study requested by the state, MISO officials told a Nov. 1 Economic Planning Users Group call that none of several potential new lines through the twin Sault Ste. Marie cities on the U.S.-Canada border produces benefits commensurate with their costs over a 20-year span.

“Due to the relatively low transfer capability and relatively high construction cost, none of those transmission ideas provided enough benefit to cover its cost,” said MISO Manager of Economic Studies Zheng Zhou.

Currently there’s no transmission connection between Ontario and the UP, although the Lower Peninsula has connections to the province’s hydropower system. Michigan Gov. Rick Snyder requested the study last August in search of solutions to alleviate persistently high power costs in the UP. (See Michigan Asks MISO to Study Tx Links to Ontario.)

MISO michigan ontario transmission study — Lower voltage options examined under MISO’s UP to Ontario transmission study | *MISO*

MISO worked on the study with Ontario’s Independent Electricity System Operator (IESO), which found it could reliably transfer a maximum of 125 MW to the peninsula. Beyond that amount, “significant reliability upgrades would be needed on both systems to increase that transfer capability,” Zhou said.

‎Economic Studies Senior Engineer Tim Kopp said MISO studied 16 potential new lines, including 161-kV, 230-kV, 345-kV and DC options. It also found that the benefits of a new 400-MW combined cycle plant in Kalkaska County or a 100-MW plant at the nearby Pine River substation would not outweigh their costs either.

MISO did identify benefits over 20 years if a sub-345-kV transmission line allowed 400-MW transfers, but the scenarios showed the local 115-kV system couldn’t reliably support that amount in its current state and would need expensive upgrades.

Final public results of the study will be posted in mid-December, Zhou said.

Customized Energy Solutions’ Ginger Hodge asked if study results would be included in this year’s MISO Transmission Expansion Plan. Zhou said the study was considered ad hoc and not an MTEP study.

Zhou agreed to a request by Michigan Public Service Commission staffer Bonnie Janssen to present the study’s findings at the MISO Board of Directors’ December meeting.

MISO’s study results arrived a week after the PSC approved Upper Michigan Energy Resources Corp.’s $277 million plan to build two reciprocating internal combustion engine stations in the UP in spring (U-18224). Chairman Sally Talberg said the plants will result in a “more reliable and affordable” electric supply for UP customers, including the Tilden Mining operation. Tilden will cover 50% of the capital costs of the plants along with fixed operations and maintenance expenses.

The plants will replace the costly system support resource agreement that keeps the Presque Isle Power Plant running. In October, FERC ruled that ratepayers were overcharged by nearly $23 million for continued Presque Isle operations. (See $23 Million Owed to Ratepayers in Presque Isle SSR Case.)

November 2, 2017

MISO, PJM Respond to FERC’s Pseudo-Tie Questions

By Amanda Durish Cook

MISO and PJM have responded to a FERC deficiency letter with a defense and clarification of their proposal to impose stricter rules on pseudo-ties.

In early August, the two RTOs filed identical proposals to permit them to terminate or suspend pseudo-ties that don’t acquire transmission service or follow modeling rules by providing real-time data. The proposals would also allow a balancing authority the ability to redirect pseudo-tie output to avoid exceeding NERC operating limits.

In late September, FERC sent a deficiency letter asking how a native reliability coordinator would commit, de-commit or redispatch pseudo-tied generation to avoid operating limits. The commission also asked the RTOs to clarify rules for suspending terminating pseudo-ties. (See 2nd Deficiency Notice Issued for MISO-PJM Pseudo-Tie Effort.)

In filings Oct. 30, the RTOs defended their proposals, with PJM saying redispatch and recommitment of pseudo-tied generation is essential to maintaining operating limits during localized thermal issues, voltage issues or islanding situations (ER17-2218). MISO also said a redispatch option is crucial during planned transmission outages, forced transmission outages or during periods of heavy system transfers (ER17-2220). PJM added that there would be no limit to the number of times a pseudo-tied generator could be recommitted or redispatched. MISO said pseudo-tied resources would still be eligible to provide reactive supply and voltage control service, a point PJM did not address.

PJM said its 42-month notice to terminate a pseudo-tie is rooted in its three-year advance capacity auction and would give “planning engineers sufficient time to take into consideration the impact of the termination” and pointed out that it is “consistent with the notice requirement that a capacity market seller must give to PJM when it intends to deactivate a generator.”

PJM MISO pseudo-tie parameter rules — | *MISO, PJM*

MISO and PJM said they would only terminate a pseudo-tie under the circumstances described in their respective Tariffs and both would generally try to impose a suspension period first, during which the resource is decommitted or manually dispatched. PJM said termination conditions are “for the most part … tied to a situation in which a pseudo-tie is causing instability on the bulk power system or raising or causing reliability concerns.”

In identical language, MISO and PJM also said they would use a case-specific approach to termination, and would work with generators to address problems and avoid terminations, which they called a “last resort.”

The RTOs have said that they would suspend a pseudo-tie when they are “reasonably” found to pose a reliability risk or don’t follow the rules of their attaining balancing authority. PJM added that the RTOs “expect suspensions to be very exceptional events.”

MISO and PJM proposed that suspensions occur without FERC approval, and that a contested suspension remain in force pending a commission decision.

Meanwhile, MISO is still awaiting final word on its pro forma pseudo-tie agreement for PJM. The agreement was conditionally approved by FERC staff in August before the commission regained its quorum (ER17-1061). The proposal also was the subject of a deficiency notice in the spring. (See FERC Conditionally OKs MISO’s Pseudo-tie Pro Forma.)

November 2, 2017

PJM Members Still Split on Incremental Auctions

By Rory D. Sweeney

VALLEY FORGE, Pa. — While stakeholders remain divided on changes to PJM’s Incremental Auctions, hope remains for reaching a compromise that can be implemented in time for next year’s Base Residual Auction. (See Consensus Fades on PJM Incremental Auction Solution.)

Stakeholders at Tuesday’s meeting of the Incremental Auction Senior Task Force defined where they will and will not budge on their positions. The three main sticking points are the number of IAs per delivery year, at what price PJM should sell excess capacity and what to do about excess commitment credits (ECCs).

Number of Auctions

PJM BRA Incremental Auction excess capacity — Chmielewski | © *RTO Insider*

Stakeholders appear closest to consensus and willing to negotiate regarding the number of auctions. PJM’s Brian Chmielewski presented the results of a recent poll that found more than two-thirds of voters strongly supported the status quo of an IA for each of the three years between the BRA and the delivery year.

However, most respondents were willing to consider proposals to reduce the number to two. A majority of voters were neutral about an option to have PJM sell capacity in either IA, with 41% opposed. A proposal to limit PJM to selling capacity in the final IA was strongly supported by 38% and opposed by 44%, with 18% neutral.

James Wilson of Wilson Energy Economics, a consultant to consumer advocates for several PJM states, said there’s no reason to reduce the number of IAs, but reducing to two could be acceptable. Carl Johnson, who represents the PJM Public Power Coalition, agreed that his membership was “not willing to fall on our sword” over the issue.

Sell-Back Price

Stakeholders remain divided over the sell-back pricing approach. PJM’s Jeff Bastian argued that the price must be at least what the RTO paid for it in the BRA. “If I’m going to excuse someone from a BRA commitment, why should I pay them?” he asked.

Calpine’s David “Scarp” Scarpignato agreed it must be at “or close to” the BRA price. It is a position on which “we can’t move,” he said.

Wilson and Jeff Whitehead of GT Power Group argued PJM should sell for whatever the market will bear. “You may sell some capacity [at the BRA price], but you’re basically pricing yourself out of the market,” Whitehead said.

PJM’s position “doesn’t make much sense,” Wilson said, because the capacity is not as valuable in the IA if the load forecast has been reduced following the BRA. He has argued that PJM needs more accurate load forecasts prior to the BRA.

Bastian later floated an idea that was developed during a meeting break to allow market participants out of their capacity obligations but not excuse them from the daily capacity-shortfall penalties, which equal 120% of the capacity payments. Wilson and Adrien Ford of Old Dominion Electric Cooperative pointed out that the idea is analogous to selling the capacity at the BRA clearing price. Bastian agreed, adding, “you’d have a cleaner settlement report.”

EnerNOC’s Katie Guerry was concerned the idea would reduce liquidity in the IAs because those with capacity obligations could walk away and decide they “won’t even bother” attempting to replace them in the IAs.

Whitehead said the IAs would have to clear above the BRA price for load to benefit. “I think, mathematically, load is better off under what [Bastian] just described,” Whitehead said.

Split over Excess Commitments

Stakeholders were also split on what to do with ECCs, which are allocated to load-serving entities when reliability requirements decrease below commitments. Currently, LSEs can use ECCs to replace resource commitments. Load has proposed eliminating the ECCs so that the excess committed megawatts, if not otherwise sold in an IA, are retained. The proposal also removes an opportunity for market participants to bypass the intent of any new IA sellback-pricing approach, Susan Bruce, who represents the PJM Industrial Customer Coalition, told RTO Insider in an email.

Johnson said public power organizations “feel entitled” to the ECCs and find them “helpful” for covering EFORd (equivalent forced outage rate – demand) deficiencies while adhering to their business models. As nonprofit entities, public power has a “distaste” for “making money” on the commitments by selling them back, Johnson said. Ford said she agreed with Johnson.

Guerry said that LSEs incur costs to secure commitments. “It’s not all necessarily profit” when they are sold back, she said.

Bruce said she “can appreciate [public power’s] perspective when you have self-supply obligations,” but that “load is getting the short end of the stick.” She also questioned how auditable ECCs would be if customers attempted to negotiate for their proportionate share of them in a retail transaction. She acknowledged some “wiggle room here” to negotiate a different solution but said the “status quo is not an option from a load perspective.”

Chmielewski asked stakeholders to develop new proposals for the task force’s next meeting on Nov. 10.

The IASTF is also charged with resolving a second problem statement and issue charge on the potential for profiting off of replacement capacity. Chmielewski said the issue will be a focus of the next meeting as well. (See “Stakeholders Quibble with, but Eventually Endorse, Replacement Capacity Investigation,” PJM Markets and Reliability and Members Committees Briefs.)

To get the proposals implemented in time for the next BRA in May, they will need to be presented at the January meeting of the Markets and Reliability Committee, he said.

November 2, 2017

ERCOT: Sufficient Capacity for Winter, Spring

By Tom Kleckner

Despite the retirement of more than 3.5 GW of generation, ERCOT said Wednesday it has enough installed capacity available to meet forecasted peak demand through May 2018.

The ISO expects to have almost 81 GW of total capacity available this winter, more than enough to meet a projected peak of more than 61 GW. That would break the winter peak demand record of 59.75 GW, set last January.

ERCOT installed Capacity Coal Plant Retirements — ERCOT operators monitor the Texas grid. | © *RTO Insider*

ERCOT removed 3,551 MW of recently announced generation retirements from the final seasonal assessment of resource adequacy (SARA) report for the winter season (December-February). That includes 1,200 MW of capacity still being studied to determine whether it is needed to maintain system reliability.

Luminant accounted for most of the retired resources. The company said last month it will shut down three coal plants totaling 4.2 GW by the end of February. (See Vistra Energy to Close 2 More Coal Plants.)

“ERCOT still expects to have sufficient systemwide operating reserves for the winter season,” Pete Warnken, the ISO’s manager of resource adequacy, said Wednesday. “Our studies show this would be the case even with a much higher-than-expected peak demand.”

The winter SARA includes nearly 1.4 GW of mostly renewable capacity. The wind and solar projects are expected to contribute 209 MW to the winter peak.

ERCOT Senior Meteorologist Chris Coleman said he expects a mild winter overall, with some very cold periods in mid-winter.

The ISO’s preliminary assessment for the spring months (March-May) was equally optimistic. Staff projects a season peak of more than 59 GW, and expects to have 80.7 GW of capacity available.

The final spring SARA report will be released in early March.

ERCOT’s most recent Capacity, Demand and Reserves report indicated the ISO had an 18.9% reserve margin for next summer, with margins remaining above 18% the following three years. A revised CDR report incorporating the latest retirements will be released in December.

November 2, 2017

Calpine Profits down 24% in Q3

By Jason Fordney

Calpine reported Wednesday that it earned $225 million in the third quarter ($0.63/share), down 24% from $295 million ($0.83/share) a year earlier.

The decrease was primarily due to “an unfavorable variance in mark-to-market gain/loss, net, and increases in plant operating expense and depreciation and amortization expense,” Calpine said. The decline was partially offset by a higher commodity margin, which the company said was driven by hedge revenues from retail operations and higher regulated capacity revenue.

calpine earnings profits q3 — Calpine’s Sonoma Geothermal Plant north of San Francisco, Calif.

The company, which has agreed to go private in a $5.6 billion deal with Energy Capital Partners and an investors group, lost $47 million in the first nine months of this year, compared with a profit of $68 million in the same period a year ago. Company officials issued the earnings with no previous public notice and no conference call to take questions from analysts. (See Calpine Going Private in $5.6B Deal.)

In a news release announcing the results, CEO Thad Hill said the merger is on track to be completed in the first quarter of 2018. He focused on the company’s response to natural disasters in California and Texas.

“Since our last earnings call, we endured Hurricane Harvey in Texas and the wildfires in Northern California safely and without any material damage to our facilities,” Hill said. “I am particularly proud of team members on the front lines who kept our plants and operations going in the face of adversity.”

Operating revenues were $2.6 billion for the quarter, compared with about $2.4 billion in the same quarter last year. Operating revenues in the first nine months of 2017 were nearly $7 billion, compared with about $5.1 billion in the same period last year.

The company said cash from operating activities rose 21% to $807 million over the first three quarters, “primarily due to a decrease in working capital employed resulting from the period-over-period change in net margining requirements associated with our commodity hedging activity, partially offset by a decrease in income from operations, adjusted for non-cash items.”

November 1, 2017

Profits up, Edison International Talks Clean Energy Goals

By Jason Fordney

Edison International says its grid will help California meet its clean energy goals, but infrastructure and market improvements are still needed.

The company, parent of utility Southern California Edison (SCE), “must be a key enabler of California’s ambitious renewable policies,” CEO Pedro Pizarro said during an earnings call Monday. He mentioned renewable integration, customer technology choice, adoption of distributed energy, vehicle electrification and energy efficiency. Achieving those goals will require strengthening the existing electricity grid, he said.

Edison International clean energy — Edison International Is the Parent Company of Utility Southern California Edison (who’s control room is shown) | *SCE*

Edison said it would soon issue a whitepaper on a framework for the state to meet its energy goals, building on existing policies and summary results of different scenarios. The paper will discuss carbon-free electricity with storage, increased electric vehicle integration and improved building efficiency.

The company earned $470 million ($1.44/share) during the third quarter, compared to $421 million ($1.29/share) a year earlier. Net income for the nine months ending Sept. 30 came in at $1.1 billion ($3.41/share), compared to $982 million ($3.01/share) during the same period last year.

SCE’s net income through Sept. 30 increased by $73 million, or 23 cents/share, from the same period in 2016, primarily because of an earlier rate case decision, the company said.

The utility is in the midst of its 2018 rate case with the California Public Utilities Commission, having recently filed reply briefs, with public hearings slated for November. It does not expect a decision from the commission this year. Another proceeding with the PUC regarding electric vehicles and energy storage could increase SCE’s investment forecast by $1 billion, Edison said during the earnings release.

Company executives said Monday they continue to support the existing settlement over the San Onofre Nuclear Generating Station. SCE has been unable to reach agreement with settling parties and recently urged the PUC to support the existing settlement. (See CPUC Orders Renegotiation of San Onofre Settlement.)

“Folks have different ideas as we walk down the pathway here,” Pizzaro said of the proceeding.

November 1, 2017

FERC Clarifies Ruling on NYISO Capacity Change

By Michael Kuser

FERC last week denied NRG Energy’s request for rehearing of a January order concerning NYISO Tariff revisions intended to correct a pricing inefficiency in the ISO’s capacity market (ER17-446-003).

NYISO proposed the revisions last November to address situations in which a generator exports power out of an import-constrained locality, creating increased counter-flow on the transmission constraints between that locality and other zones in the New York Control Area (Rest of State).

FERC NYISO capacity tariff revisions — NRG Headquarters in Princeton, NJ. | *NRG*

The ISO proposed to use a locality exchange factor, reflected as a percentage, to calculate the amount of Rest of State generation that can be imported into the locality to replace a portion of the exported capacity. The ISO would multiply this factor — 47.8% for the G-J locality — by the amount of exported capacity to determine the additional capacity that can be procured from outside the locality as a result of the export.

NRG protested the Tariff changes, expressing concerns about NYISO’s “apparent” assumption that an exporting resource would indefinitely continue to provide capacity benefits to its locality through counter-flows produced by its exports. The company noted that, under the Tariff, any resource that ceases to participate in the capacity market — by continuously exporting for three years — loses its capacity resource interconnection service (CRIS) rights and therefore can no longer provide a capacity discount to the locality in which it resides.

In its January order, FERC rejected NRG’s protest, but the company’s request for rehearing alleged that the commission erred in approving NYISO’s filing without fully addressing its concerns on how a generator that loses its CRIS rights should be considered for purposes of the locality exchange factor methodology.

NRG also asked FERC to clarify that a resource cannot claim resource adequacy benefits once it loses its injection rights in New York. In the alternative, the company sought clarification that a continuously exporting unit that loses its CRIS rights cannot be counted in the ISO’s installed reserve margin modeling.

Clarifying Order Language

FERC’s Oct. 25 order denied NRG’s rehearing request, but granted — in part — what NRG was seeking.

“The express relief [NRG] seeks is for the commission to clarify a statement in the Jan. 27 order rather than to change the commission’s determination,” the commission said.

FERC acknowledged that its Jan. 27 order “may cause confusion” in how it addresses the relationship between the locality exchange factor and CRIS rights. That order meant to convey that, under the existing NYISO Tariff, the locality exchange factor does not apply to the exported capacity of a generator that has failed to maintain its CRIS rights, the commission said. The factor should be applied only to locational export capacity, and by definition would not apply to exports from a resource that has lost its CRIS rights.

But the commission demurred on NRG’s alternative request for clarification.

“It is our understanding that a unit that exports and loses its CRIS rights after three years would not be counted in installed reserve margin modeling,” the commission said. “However, installed reserve margin modeling is performed by the New York State Reliability Council, not NYISO, and we find questions regarding the establishment of the installed reserve margin to be beyond the scope of this proceeding regarding NYISO’s proposed revisions to its [capacity] market design.”

November 1, 2017

Federal Trade Panel Recommends Solar PV Quotas

By Michael Kuser

The U.S. International Trade Commission on Tuesday recommended that President Trump impose import duties as high as 35% on solar cells and modules.

cspv trade commission — USITC Building in Washington, DC | *USITC*

The independent panel announced the recommendations following its unanimous ruling in September that increased imports of solar cells and components are harming domestic manufacturers, which supported the claims of solar manufacturers Suniva and SolarWorld under Section 201 of the 1974 Trade Act.

The commission will forward its injury determination, remedy recommendations, any additional findings and the basis for them to Trump by Nov. 13. The president will then have 60 days to decide on what, if any, measures he will take. (See Trade Panel Rules PV Imports Hurting Domestic Manufacturers.)

Three of the four commissioners recommended imposition of tariff-rate quotas. The fourth, Meredith Broadbent, recommended that the president impose a hard annual quantitative restriction on imports of crystalline silicon photovoltaic (CSPV) products into the U.S. for a four-year period. That restriction would be set at 8.9 GW in the first year, increasing by 1.4 GW each subsequent year.

Tariffs and Quotas

Chair Rhonda Schmidtlein sought tariffs as high as 30% on imports of cells that exceed annual quotas of 0.5 GW, recommending that in-quota levels be incrementally raised and the tariff rate incrementally reduced during a four-year remedy period.

For CSPV modules, Schmidtlein recommended a 35% duty to be incrementally reduced during a four-year remedy period.

Vice Chair David Johanson and Commissioner Irving Williamson joined in recommending measures similar to Schmidtlein’s: “For imports of CSPV products in cell form, we recommend an additional 30% ad valorem tariff on imports in excess of 1 GW. In each subsequent year, we recommend that this tariff rate decrease by 5 percentage points and that the in-quota amount increase by 0.2 GW. The rate of duty on in-quota CSPV products in cell form will remain unchanged. For imports of CSPV products in module form, we recommend an additional 30% ad valorem tariff, to be phased down by 5 percentage points per year in each of the subsequent years.”

Who to Blame?

Schmidtlein also recommended that Trump initiate international negotiations to address the underlying cause of the increase in imports of CSPV products.

Broadbent said that surging imports and a global oversupply of CSPV products resulted “from the subsidization of manufacturers in China in the context of targeted industrial policy programs. I believe the president intends to address China’s non-market economic policies that have contributed to global oversupply as part of broader bilateral negotiations with the government of China, and I support those efforts.”

She said her recommended quotas “are consistent with the market share held by imports in 2016, adjusted to reflect projected changes in demand for photovoltaic products over the next four years. Therefore, they are set at levels that will not disrupt expected growth in CSPV demand but will help address the serious injury to the domestic industry by preventing further surges in imports.”

Where the Buck Stops

Timothy Fox of ClearView Energy Partners said in a statement that the commission’s recommendations for trade remedies represent another step toward final action, not final action itself.

“We regard today’s vote as another significant step towards trade action likely to raise the cost of solar domestically, potentially blunting solar power deployment over the next four years,” Fox said, adding that Trump’s decision could be driven more by politics than by economics.

“President Trump measures economic success in terms of bilateral trade balances and manufacturing jobs,” Fox said. “This solar trade proceeding could give President Trump a way to ‘win’ on both fronts. Economic nationalism appears alive and well within the White House, including in renegotiations of the North American Free Trade Agreement and Korea-U.S. Free Trade Agreement. As such, we think this solar proceeding could serve as a prototype for future protectionist efforts, including those concerning aluminum and steel (especially steel).”

November 1, 2017

SDGE’s Wildfire Costs Undercut Sempra Profits

By Jason Fordney

Sempra Energy’s third-quarter financial results were hobbled by an administrative law judge’s preliminary decision to deny subsidiary San Diego Gas & Electric’s request to recoup losses stemming from wildfires a decade ago.

A California Public Utilities Commission ALJ in August recommended the commission deny SDG&E’s request to recover $208 million in costs related to the 2007 Witch, Guejito and Rice wildfires, ruling that prior to the fires, the utility “did not reasonably manage and operate its facilities.” The ALJ decision is not binding, and the PUC is due to vote Nov. 9 on SDG&E’s request to recover the costs.

During an earnings call Monday, Sempra executives said they are prepared to take the matter to court if they are not allowed to recover the money.

Traditional accounting measures require the company to reflect the preliminary decision in its financial results, but Sempra said that on an adjusted basis, earnings increased to $265 million ($1.04/share), from $259 million ($1.02/share) a year ago. Unadjusted earnings came in at $57 million, compared with $622 million last year.

Sempra Energy earnings — Sempra Energy Is The Parent Company of San Diego Gas & Electric, Southern California Gas And Others | *SDG&E*

For the first nine months of the year, Sempra’s earnings were $757 million, compared with $991 million over the same period last year.

Sempra is also attempting to acquire Texas-based utility Oncor in a deal worth nearly $10 billion. The Public Utility Commission of Texas last week issued a preliminary order that calls for Sempra to prove it is financially fit to own the state’s largest utility. (See Texas Regulators Seek More Details on Sempra Oncor Bid.)

SDG&E recorded a net loss of $28 million in the third quarter, compared with earnings of $183 million a year earlier, “due primarily to the $208 million after-tax impairment related to cost recovery for the 2007 San Diego wildfires.”

The utility’s earnings were $276 million for the first nine months of 2017, compared with $419 million in the same period last year. Earnings for the first nine months of 2017 included the third-quarter 2017 wildfire-related impairment. In last year’s second quarter, SDG&E recorded an after-tax charge of $31 million, refunding to ratepayers the benefits from tax deductions related to the final 2016 rate case decision.