Page 1222 – RTO Insider

January 23, 2018

Counterflow: The Devil Went Down to Georgia

Counterflow

By Steve Huntoon

Georgia Public Service Commission Vogtle — Huntoon

“Johnny, rosin up your bow and play your fiddle hard,
’Cause hell’s broke loose in Georgia and the Devil deals the cards.”

There’s a process problem with the Georgia Public Service Commission’s Vogtle decision, and there’s a substance problem.

Process Problem

Georgia commissioners publicly and vehemently stated that Vogtle should be completed.^[1] And then they had a hearing on whether Vogtle should be completed. See the problem?

Regulators are supposed to make reasoned decisions based on records. It’s hard to do that before you have a record.

“Sentence first! Verdict afterwards,” as the Queen said in “Alice in Wonderland.”

Substance Problem

Last September, my column showed that the original “need” for Vogtle, in the form of a projected increase in customer demand, had basically disappeared.^[2] And with simplifying assumptions favorable to Vogtle, and using Lazard cost estimates, completing Vogtle would impose excess costs of $23.6 billion on Georgia consumers over the next 40 years.

Here’s a quick quiz: After eight years of construction, what percent of Vogtle is constructed? Answer in footnote below.^[3]

So there was a hearing. Or more like Kabuki theater. The Public Interest Advocacy Staff (PIA Staff) of the Georgia commission showed:^[4]

Because of multiple flaws in Southern Co.’s case, “the project is uneconomic on a going forward basis by $1.6 billion.” The commission’s Advisory Staff agreed with PIA Staff that completing Vogtle is uneconomic at the cost estimated by Southern.^[5]
“Certain costs [$1.5 billion, excluding Toshiba’s parental guarantee] for which the company is seeking recovery from ratepayers resulted from project mismanagement.”
“Had the commission been more accurately informed by the company as to the depth of the problems facing the project, the commission would have had the opportunity to assess the project status and make different decisions earlier on in the construction, when sunk costs were not so daunting an issue.”
Giving Vogtle co-owners “the right to abandon the project if any company costs are disallowed for any reason, including fraud, failure to disclose a material fact or criminal misconduct” was a “threat” and “unconscionable.”

Southern, of course, disputed all this.

Given the enormity of these issues and the long-term consequences of a decision to complete or not complete Vogtle, one would have expected a deliberate, careful analysis of the record and a reasoned decision.

Instead, the last day of hearings was Dec. 14, briefs were required five days later and the commission made its decision two days after that. Speed readers, I guess.

Are you ready for the decision itself? The Georgia commission without any explanation at all simply proclaims:^[6]

“Based upon careful consideration of all the evidence in the record, the commission finds as a matter of fact and concludes as a matter of law that it is appropriate to continue construction of Vogtle Units 3 & 4 under the terms set forth in this order.”

Georgia, that’s all the explanation you get. C’est la vie.^[7]

But what should consumers expect from regulators who had announced their decision before the hearing? Why waste ink?^[8]

More Project Delays Rewarded

Going forward, Georgia consumers have no protection against continuing project delays and overruns.^[9] The Georgia commission order claims that it incents performance by reducing return on equity if target dates aren’t met.

Unfortunately that is just wrong. Reduced ROE during delays is only for the periods of delay. After the project is in commercial operation, that ROE becomes part of the rate base, upon which Southern gets a generous return for at least 40 years. That is why Southern already will make an extra $5.2 billion over the life of the project from the delays to date.^[10] Nice work if you can get it.

The longer Vogtle takes to complete, the more Southern makes.

And every electric consumer in Georgia is on the hook for whatever Vogtle ends up costing.

What site selection advisor for a large consumer of electricity will recommend locating a new facility in Georgia? Because there is no competition in Georgia,^[11] any new business would have unlimited exposure to the Vogtle plant. Moody’s Investor Service already downgraded JEA because it owns 206 MW of Vogtle.^[12]

Customer Refund Gimmick

One last note on the Georgia commission decision: It directed that Southern refund part of the Toshiba/Westinghouse Electric settlement payment to consumers, $25 per customer per month for three months, with a bill line item saying “Vogtle Settlement Refund.” Great PR, but this refund money isn’t coming from Southern. It’s money that otherwise would have been credited against the cost of Vogtle.

So consumers effectively will be paying Southern a generous return on their refunds for decades. Sort of like your credit card company sending you a $75 gift card, but then that $75 shows up on your next bill as a cash advance. Which you can’t pay off for the next 40 years.

Oh, sorry, one more thing: The Georgia commission authorized a token 5-MW solar project to be located at, you guessed it, Vogtle. No consideration of whether that project size or location made any sense. But even more rate base for Southern.

The Sad Reality

The sad reality is that Vogtle never made sense, and this became obvious years ago. The Vogtle owners failed to oversee the failures of Toshiba and Westinghouse, failed to report the failures to the Georgia commission, and failed to provide realistic project costs and schedules. The hole became billions deeper as a result, and Southern’s past and future profits grew as a result.

Instead of holding the Vogtle owners accountable for their failings, the Georgia commission is more concerned with not appearing to have made consumers pay something for nothing. So the Georgia commission approves continuing an uneconomic project, gives Southern and the new project contractor an even bigger blank check than before, and maintains the incentive of higher profitability from greater delays.

The flogging will continue until morale improves.

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

“I do want to see this project completed,” said PSC Commissioner Lauren “Bubba” McDonald. “I do not like to see failure.” http://www.ajc.com/business/georgia-power-told-its-homework-vogtle-nuke-options/mnHqeJ7BdDza0U25xAxfbP/. “As an unabashed supporter of nuclear power,” [PSC Chairman Stan] Wise wrote, “I intend to be present for that vote and will resign shortly thereafter so that you may appoint my successor prior to the (candidate) qualifying period for the 2018 elections.” http://politics.myajc.com/news/state–regional-govt–politics/psc-wise-quit-after-vogtle-vote-governor-can-appoint-successor/Dv6bJbPTpNupmLUUe83f8J/. Commissioner Tim Echols said: “The last thing I want to do to my ratepayers is to say, ‘Look, I spent $4.5 billion of your money, and you have nothing to show for it.’ That’s a formula for getting unelected, as far as I’m concerned.” https://www.greentechmedia.com/articles/read/the-nuclear-power-war-isnt-over-yet#gs.1G0g8AQ. Echols went on to write an op-ed for The Wall Street Journal and an article for Public Utilities Fortnightly in full-throated advocacy for completing Vogtle, all before the hearing on whether to complete Vogtle. ↑
http://energy-counsel.com/docs/Vogtle-the-Law-of-Holes-and-Two-Modest-Proposals.pdf. The column also showed that the fuel diversity argument for Vogtle was vacuous. ↑
Reportedly, 40%. A shocking audit report on Vogtle’s sister nuclear units in South Carolina was prepared by Bechtel in 2016. It was never meant to see the light of day, but the link to it is in the news story here: https://www.postandcourier.com/news/audit-highlighted-problems-with-south-carolina-nuclear-project-a-year/article_9ac96112-9185-11e7-9979-977331ac2233.html. ↑
http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=170562. In this proposed order, the PIA Staff provides a damning “just the facts” recitation of everything wrong about Vogtle. ↑
https://www.youtube.com/watch?v=JtycWKqQVk8 ↑
http://www.psc.state.ga.us/factsv2/Document.aspx?documentNumber=170765. ↑
Adding to the incredulity is that terms of the commission decision were reviewed with Southern in advance of the commission meeting. “Although Echols said he did not want to get into details about his interaction with Georgia Power over the new conditions, he added, ‘Ultimately, they were read in and gave feedback’ on those restrictions.” http://chronicle.augusta.com/news/2017-12-21/georgia-public-service-commission-vote-allows-plant-vogtle-proceed. ↑
Not part of the decision is a motion by one of the commissioners on what the decision should be. This motion refers to the uncertainty of future natural gas prices, and how Vogtle can be a hedge against high gas prices.Of course future energy prices can’t be known. But the salient fact is that a forecast of future natural gas prices is effectively a mean. Lower gas prices would mean Vogtle is even more uneconomic. Higher gas prices would mean Vogtle is less uneconomic and might even be economic. But decisions need to be based on the mean, not on one extreme or another. And here’s another important point: If the gas price hedging value is significant the right thing to do is suspend Vogtle at a relatively trivial cost of $112 million for up to 10 years, which cost comes from Southern’s own consultant. http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=169459 (Black & Veatch Deferral Study). The Georgia Commission decision makes no mention of this option. ↑
The original project completion date was in 2017. In December 2016, Southern promised completion by 2020. Then nine months later, the completion date was pushed back almost two more years. And that date is likely more fantasy than reality. As of late 2016, two AP1000 plants in China were supposed to go into commercial operation in early 2017. https://www.reuters.com/article/us-westinghouse-nuclear/westinghouse-to-start-first-china-reactor-in-2017-sees-tens-more-idUSKCN11M1Q7. Somehow that didn’t happen, and last month the China state agency said they “will hopefully begin commercial operation next year.” http://www.nicobargroup.com/news-views-1/. “Hopefully”? ↑
“As a result of the delays experienced by the project, the company will make considerably more profit over the lifecycle of the units than it would have had the project been completed on time. The company’s profit will increase from approximately $7.4 billion to approximately $12.6 billion over the unit’s entire lifecycle.” http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=170562 (page 8). ↑
As I’ve pointed out before, Vogtle and the lack of competition are joined at the hip. ↑
https://www.moodys.com/research/Moodys-assigns-Aa2-and-Aa3-to-JEA-FL-sr-and–PR_904363490 ↑

January 23, 2018

MISO Looks to Align Load Forecasting, Tx Planning

By Amanda Durish Cook

CARMEL, Ind. — MISO is seeking to more closely harmonize its load forecasting process with the four 15-year future scenarios it creates to support long-term transmission planning, but stakeholders are wary of two ideas being floated by the RTO.

MISO load forecasting — Lawhorn | © *RTO Insider*

“I think it’s time we move to where the … load forecast is future-dependent,” John Lawhorn, MISO senior director of policy and economic studies, said at a Jan. 17 Planning Advisory Committee meeting.

Lawhorn said that the futures created for the MISO Transmission Expansion Plan could link up with the load forecast in one of two ways: require load-serving entities to supply detailed planning-level data for each of the futures; or use the RTO’s “independent” load forecast as a starting point to create forecasts for each future.

“In both cases, the level of information would be the same; it would include a 20-year forecast, energy efficiency, demand response [and] distributed generation,” Lawhorn said.

“It’s a paradigm shift,” he said. “It’s becoming increasingly evident that a long-term forecast is needed to study the futures,” citing the potential for MISO to swing from summertime peak planning to possible hour-by-hour planning for a future in which smaller distributed generators provide scatterings of energy.

The biggest hitch with the current forecasting approach is that MISO can’t get a clear picture of demand-side management programs, which will be instrumental in forecasting future demand, Lawhorn said.

“This is driving our planning process to areas that we haven’t yet been forced to look at in this level of detail,” he added.

Developed by Purdue University’s State Utility Forecasting Group, MISO’s independent load forecast does not draw on any of the futures, which include “limited,” “continued” and “accelerated” fleet change predictions, as well as a scenario in which distributed generation and emerging technologies gain popularity. The independent forecast also does not account for individual load forecasts produced by MISO’s LSEs, but instead relies only on publicly available information to predict summer and winter peak energy demand for the RTO’s 10 local resource zones along with systemwide peaks.

Unlike the 10-year forecasts produced by LSEs, the Purdue forecast is for informational purposes only — not tied to any official MISO predictions — with an Applied Energy Group study lending the independent load forecast its projections for EE, DR and DG. But the RTO now thinks either the Purdue or LSE forecasts could perform a larger role in transmission planning.

MISO says its pace of fleet evolution “highlights the need to create a new source of load forecasts tailored for long-term economic planning.”

“Our process lacks transparency and it lacks … the detail needed to effectively and efficiently move energy to all areas of the MISO footprint,” Lawhorn said. He also said the 140-plus separate LSE load forecasts currently lack a common set of assumptions.

Two Approaches

If the RTO decides to have LSEs prepare more detailed forecasts, they would have to ready four separate 20-year forecasts, a total of 8,760 hourly load shapes, 20 years’ worth of demand-side management growth predictions, and four iterations of program penetration for EE, DR and DG.

MISO could adopt the LSE-centered approach by the 2021 MTEP at the earliest, Lawhorn said, noting that it would take a minimum of two years to modify the RTO’s member website to accept more detailed information.

Currently, LSEs submit 10-year demand and energy forecasts, extrapolated for another 10 years to develop a 20-year forecast.

“By having a 20-year forecast, you might be outrunning the headlights of state regulators and local planners,” said David Harlan, president of consulting firm Veriquest Group.

“That level of specificity is where the industry is heading,” Lawhorn replied.

MISO’s second load forecasting option involves a third-party consultant like Purdue developing a 20-year demand and energy forecast for each local resource zone by future scenario. Such a system could be in place by MTEP 19.

MISO load forecasting transmission planning — MISO PAC meeting on Jan. 17, 2018 | © *RTO Insider*

PAC Chair Cynthia Crane asked whether MISO plans to calibrate a long-term third-party forecast against the shorter forecasts furnished by LSEs if it takes the second route.

“Oh, absolutely,” Lawhorn said.

LSE Ability to Forecast

Stakeholders are divided over how difficult it would be for LSEs to provide more detailed forecast data.

Indianapolis Power and Light’s Lin Franks said there’s no reason MISO couldn’t begin now to use more detailed LSE information for load forecasts.

Lawhorn responded that it’s a “fairly considerable task” to coordinate forecast information from more than 140 LSEs, noting that not all of them are prepared to offer that level of detail. MISO will instead issue a survey to determine the feasibility of producing 20-year forward-looking data, he said.

Customized Energy Solutions’ Ted Kuhn pointed out that forecasts are only worthwhile if MISO develops a process for historically assessing their accuracy. He said the RTO must be able to compare forecasts with actual demand.

Minnesota Public Utilities Commission staff member Hwikwon Ham said he thinks “the independent load forecast is as good as the input used.”

American Electric Power’s Kent Feliks said it’s a “daunting amount of work to require all 140-plus LSEs to provide 20-year forecasts.”

“It seems like an awful lot of resources spent … for little improvement,” he said.

Other LSE representatives at the meeting said creating a load forecast would be a nominal challenge, as they already collect the data needed to prepare forecasts for each MTEP future.

WPPI Energy’s Steve Leovy asked MISO to be more specific about what kind of forecasting information LSEs will be asked to provide. “I’m concerned with what I see, to be blunt, is a half-baked proposal,” he said.

Other stakeholders questioned what came of a 2017 presentation aimed at blending Purdue’s independent load forecasting with LSEs’ 10-year forecasts. (See Bigger Role Seen for Independent Forecast in MISO Tx Plan.)

Madison Gas and Electric’s Megan Wisersky said that LSEs will not be able make an informed choice between the two approaches until they research the costs of preparing more in-depth forecasts.

Lawhorn said MISO is collecting input on the new pair of proposals, and that he would return to the PAC in June to discuss the RTO’s take on the prevailing stakeholder opinion.

January 21, 2018September 25, 2023

FERC to Furlough Most Employees in Govt. Shutdown

FERC will furlough all but 49 of its 1,465 employees if it runs out of money because of a prolonged federal government shutdown.

The first shutdown since 2013 began Saturday after the Senate failed to reach agreement on a spending plan. On Monday night, however, President Trump signed a bill to fund the government through Feb. 8.

The commission’s contingency plan says it will continue normal operations until its funds from prior year appropriations are exhausted. After that, it will continue only “excepted” activities, such as protecting life and property (e.g., inspections of LNG facilities), monitoring for physical and cyber threats to infrastructure, and market monitoring. “The excepted staff will perform a minimum level of these oversight roles, to monitor for urgent matters,” the plan says.

FERC staff and commissioners pledge allegiance at open meeting Thursday. Most staff would be furloughed during a prolonged shutdown but the commissioners will remain at work | FERC

Because the five commissioners will continue working through any hiatus, FERC also will keep some legal staff working to provide advice.

The commission will stop accepting filings from the public and postpone deadlines and due dates for all pending matters not related to excepted activities. It will seek stays from all cases pending in federal courts. “If the courts deny the stay and explicitly or implicitly rule that FERC participation in these matters is authorized under the protection of life and property exceptions provided in 31 U.S.C § 1342 or some other applicable provision of law, FERC staff will be required to meet obligations established by these courts.”

In addition to retaining 49 staffers (3.4% of the total), the commission will also maintain 18 contract workers to provide physical security for FERC facilities and information technology support.

The Interior and Energy departments expect to furlough about three-quarters of their workforces. EPA could lay off 95% but says it has “sufficient resources to remain open for a limited amount of time.”

— Rich Heidorn Jr.

January 21, 2018

PJM MRC/MC Preview: Jan. 25, 2018

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:50)

Members will be asked to endorse the following proposed manual changes:

A. Manual 14F: Competitive Planning Process. Revisions developed to incorporate construction cost caps, the subject of special Planning Committee sessions. (See “Cost Cap Discussion Continues,” PJM PC/TEAC Briefs: Jan. 11, 2018.)

B. Manual 38: Operations Planning. Revisions developed from periodic review to include protection system/relay communication outages and PJM assessment of impact.

C. Manual 40: Training and Certification Requirements. Revisions developed to accommodate new exams and other training changes.

3. Gas Pipeline Contingencies (9:50-10:20)

Members will be asked to approve a problem statement and issue charge at their first reading to address how gas-fired generators should be compensated if PJM orders them to switch to alternative fuel sources, such as oil or a different pipeline. (See “Emergency Pipeline Switching Instructions Sparks Rights Debate,” PJM MIC Briefs: Jan. 10, 2018.)

4. RERRA Review of Energy Efficiency Participation (10:20-10:40)

Members will be asked to endorse Tariff and Reliability Assurance Agreement revisions associated with the Demand Response Subcommittee proposal for the relevant electric retail regulatory authorities (RERRA) review of energy efficiency resource participation in the capacity market. (See “Rules Endorsed for Enforcing Regulator Requirements on EE,” PJM MIC Briefs: Jan. 10, 2018.)

5. Capacity Construct/Public Policy Senior Task Force (CCPPSTF) (10:40-11:30)

PJM management will discuss its recommendation to the Board of Managers that the RTO file with FERC a capacity repricing proposal. Members will be asked to endorse proposed Tariff revisions for the Independent Market Monitor’s MOPR-Ex proposal to extend the minimum offer price rule to all resources. (See PJM Going it Alone on Capacity Repricing Plan.)

Members Committee

Consent Agenda (1:20-1:25)

Members will be asked to endorse:

B. Tariff revisions related to the procedures associated with the study of transmission service requests and upgrade requests in the new services queue process. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)

1. FTR Modeling, Performance & Surplus (FTRMPS) (1:25-1:40)

Members will be asked to endorse revisions to the Tariff, Manual 28: Operating Agreement Accounting and Manual 6: Financial Transmission Rights resulting from special sessions on FTR issues. The revisions will address changes to long-term FTR modeling for future transmission expansion, streamlining management of overlapping FTR auctions and allocating any surplus funds from day-ahead congestion and FTR auction revenue. (See “FTR Changes in the Works,” PJM MIC briefs: Dec. 13, 2017.)

2. Capacity Construct/Public Policy Senior Task Force (CCPPSTF) (1:40-2:10)

Members will be asked to endorse proposed Tariff revisions associated with the proposal developed by the CCPPSTF. (See MRC item 5 above).

3. Incremental Auction Senior Task Force (IASTF) (2:10-2:25)

Members will be asked to endorse proposed Tariff and Operating Agreement revisions for proposal A”, which would reduce the number of Incremental Auctions from three to two following each Base Residual Auction. PJM says the change will reduce the opportunities for BRA sellers to “shop” for the cheapest replacement capacity while allowing them to cure a physical inability to satisfy their commitments. (See “Incremental Auction Revisions Endorsed,” PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)

4. RERRA Review of Energy Efficiency Participation (2:25-2:40)

Members will be asked to endorse proposed Tariff and Reliability Assurance Agreement revisions for the RERRA review of energy efficiency resource participation in the capacity market. (See MRC item 4 above).

— Rory D. Sweeney

January 21, 2018

House Panel Considers Bills on PURPA, LNG Exports

By Michael Brooks

A House Energy and Commerce Committee panel Friday heard testimony from federal officials and stakeholders on Republican legislation to expand LNG exports and revise the Public Utility Regulatory Policies Act. Support for the bills, introduced late last year, fell along party lines at the hearing.

PURPA Modernization

The PURPA Modernization Act of 2017 (H.R. 4476), introduced by Rep. Tim Walberg (R-Mich.) in November, would substantially reduce the number of PURPA qualifying facilities from which utilities would be forced to buy power.

Currently, QFs of 20 MW or larger are presumed to have nondiscriminatory access to the wholesale competitive markets and are thus ineligible to invoke utilities’ must-purchase obligation. The bill would reduce this threshold to 2.5 MW.

It would also make it harder for QF developers to game FERC’s 1-mile rule — the presumption that QFs located 1 mile or more apart from each other are separate facilities — by making that presumption rebuttable.

State regulators also would be allowed to exempt utilities from having to purchase from QFs if they determine that the utilities have no need for their power, or if utilities use integrated resource planning and conduct competitive procurement processes.

The provisions in the bill mirror solutions that critics suggested at a subcommittee hearing in September. (See Witnesses Offer Alternate Realities on Need for PURPA Reform.)

Testifying on behalf of the National Association of Utility Regulatory Commissioners, Montana Public Service Commission Vice Chairman Travis Kavulla praised the bill. “This legislation is an important and significant leap forward in providing us with the ability to secure a reliable and affordable energy future for the nation,” he said.

LNG Exports FERC PURPA — From left to right: Travis Kavulla, Montana PSC; Timothy Sparks, CMS Energy; Karl Rabago, Pace Energy and Climate Center; Paul Cicio, Industrial Energy Consumers of America; and Charlie Riedl, Center for Liquefied Natural Gas. | *Travis Kavulla*

Kavulla said PURPA forces state commissions to essentially guess a utility’s avoided costs, which usually results in overstated rates. Responding to a question by Rep. Bill Flores (R-Texas), Kavulla said, “The smaller the consumer base of the utility, the greater the potential magnitude of erroneous price forecasting from the regulator would be.” In the case of small municipalities and cooperatives, the city or county councils that regulate them “are probably even in less of a good position than I am to try to guess about the future market prices of energy for the purpose of establishing a rate.”

Karl Rabago, executive director of the Pace Energy and Climate Center, said the bill “proposes three significant and problematic changes to PURPA and should be rejected in favor a more measured and competition-friendly approach to addressing perceived concerns about electricity markets.”

“The real problem today is the need for modernization of the utility business model that is now more than 100 years old,” Rabago said.

LNG Exports

The Unlocking Our Domestic LNG Potential Act (H.R. 4605), introduced by Rep. Bill Johnson (R-Ohio), would amend the Natural Gas Act of 1938 to eliminate the Department of Energy’s role in approving requests to export and import gas. The NGA requires the department to determine whether import/export agreements are in the public interest before approving them. Trades with countries that have free-trade agreements with the U.S. are automatically considered in the public interest.

The bill leaves intact FERC’s jurisdiction over siting LNG terminals, as well as the president’s power to prohibit trade with countries under U.S. sanctions.

Republicans repeatedly emphasized the need to capitalize on the country’s supply of natural gas.

“We literally have more natural gas production capability in the United States than we know what to do with,” Rep. Joe Barton (R-Texas) said. The legislation “is simply an acknowledgement of that and says, ‘let’s use this economic resource that we have to benefit the rest of the world and create more economic benefit in the United States.’”

Democrats were less enthusiastic.

“I fail to see the need for almost any of the policy changes,” said Rep. Frank Pallone (D-N.J.), ranking member of the subcommittee. The bill “removes longstanding consumer protections and prevents DOE from ensuring exports of liquefied natural gas to non-free-trade-agreement countries are consistent with the public interest.”

So was Paul Cicio, president of the Industrial Energy Consumers of America, who said domestic gas supplies are not as abundant as commonly thought. Increased LNG exports could harm U.S. consumers by raising prices, he said. He called DOE studies used to determine whether trades with non-FTA countries were in the public interest “woefully inadequate.”

Cicio’s claims about the amount of domestic supply were challenged by Charlie Riedl, executive director of the Center for Liquefied Natural Gas, who said Ohio alone added 5 Tcf of proved reserves in 2016. (See No Agreement on Tipping Point for LNG Exports.)

“When we talk about a supply situation, it’s driven by market demand,” Riedl said. “As market demand continues to increase, we’re able to respond to that with supply.”

The other members of the panel, including those who only came to testify on the PURPA bill, agreed that there was no short-term threat to gas supply.

Steven Winberg, DOE assistant secretary for fossil energy, told the subcommittee that the Trump administration has taken no position on the bill. President Trump, however, has repeatedly emphasized expediting LNG exports, and Energy Secretary Rick Perry and EPA Administrator Scott Pruitt have traveled abroad to promote U.S. natural gas.

January 21, 2018

FERC Approves CAISO Resource Adequacy, MRTU Revisions

FERC last week issued decisions related to CAISO’s resource adequacy program and markets, as well as transmission service in the Pacific Northwest.

The commission approved six tariff revisions related to CAISO’s resource adequacy program (ER18-1). The order allows resources in a local capacity area to provide substitute capacity based on how that capacity is reflected in resource adequacy plans. It also accepted the ISO’s proposal to cap a load-serving entity’s monthly local capacity and system requirements at the same levels.

FERC CAISO resource adequacy winter reliability program — FERC granted Wheatridge Wind Energy’s request for an order directing Umatilla Electric Cooperative to interconnect with Wheatridge’s proposed wind energy project

The order is a follow-up to FERC’s October 2015 acceptance of a CAISO filing regarding updates to its reliability services initiative stakeholder process. The filing included criteria for qualifying capacity values of certain resource adequacy resources, must-offer obligations and other modifications.

In another order, FERC (ER17-1459) addressed modifications it had directed CAISO to make regarding its 2006 Market Redesign and Technology Upgrade (MRTU). CAISO’s latest compliance filing was on April 21, 2017.

FERC considered six directives it had issued, saying “we find that CAISO has either complied with the outstanding directives in the September 2006 MRTU order or has provided information demonstrating circumstances have changed such that further revisions are not necessary.”

In the Northwest-related order, FERC granted Wheatridge Wind Energy’s request to direct Umatilla Electric Cooperative to interconnect with Wheatridge’s proposed 500-MW project and provide it with transmission service to the Bonneville Power Administration balancing area (TX17-1).

FERC CAISO resource adequacy MRTU — FERC made several CAISO-related decisions on Thursday | © *RTO Insider*

The project would serve a collector substation in the service territory of Columbia Basin Electric Cooperative, which had protested Wheatridge’s application, arguing that it must be the exclusive provider of transmission service to the project. Umatilla supported the Wheatridge filing.

— Jason Fordney

January 21, 2018

NYPSC Approves New CCA, 4th VDER Tranche

By Michael Kuser

New York regulators last week approved the state’s third community choice aggregation (CCA) program, authorizing energy consultant Good Energy to provide five upstate municipalities with bulk purchasing of electricity and natural gas.

The Public Service Commission’s Jan. 18 order allows the new CCA to serve the villages of Fayetteville and Minoa in central New York, along with the village of Coxsackie and the towns of Cairo and New Baltimore near Albany.

CCA NYPSC community choice aggregation aggregation — NY DPS Staff and audience at the January 18th PSC session | *NY DPS*

Authorized by the PSC in 2015 under Gov. Andrew Cuomo’s Reforming the Energy Vision, CCAs can provide communities with lower energy prices as well as clean energy options, according to the PSC.

“Residential and small business customers can reduce their energy bills, take advantage of renewable energy choices and enjoy other money-saving services thanks to the leverage enabled by the bulk purchasing available through these community-based associations,” PSC Chair John B. Rhodes said.

While the five towns represent Good Energy’s first programs in New York, the company has helped create CCAs for more than 60 communities in other states, serving nearly 400,000 households and providing 3.3 billion kWh annually.

The commission previously allowed 20 municipalities in Westchester County to form a CCA (14-M-0224), and last year it approved a CCA by the Municipal Electric and Gas Alliance for several towns in central and upstate New York.

CCA NYPSC community choice aggregation aggregation good energy — Burman | *NY DPS*

Commissioner Diane Burman supported the measure, but she urged that all stakeholders affected by the decision be heard, especially low-income residents and consumer advocates.

“Out of the seven states that have done community choice aggregation, New York is the only state that has done this outside of the legislative process,” Burman said.

Communities can pass local laws to join or establish a CCA, but they must ensure that residents and small businesses can choose to remain a customer of a utility or energy service company (ESCO). Good Energy will help each of the five communities select an ESCO to manage its CCA, which could begin operating during the second quarter of 2018.

PSC Approves 4th Tranche of VDER

The commission last week also approved implementation of the fourth tranche in its Value of Distributed Energy Resources (VDER) tariff, continuing the transition away from net energy metering (NEM).

The PSC’s VDER Phase I order of March 2017 (Case NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)

“Several transition mechanisms were in that order,” Ted Kelly, assistant counsel for the Department of Public Service, told the commission. “Onsite mass market customers such as rooftop solar continue to receive net metering for all projects built before Jan. 1, 2020. Mass market customers — that’s residential customers as well as small businesses —participating in community-generated distribution projects, community solar for example, receive a market transition credit, or MTC, on top of the value stack.”

The commission’s Jan. 18 order recognized that several utilities had exceeded the limits of their capacity allocations under the program. Orange and Rockland Utilities last April filed a letter notifying the commission that 85% of the total megawatt capacity for its tranches had been allocated, but the utility continued to assign projects to Tranche 3, which is now 28 MW over its original 12-MW size.

In December, Central Hudson Gas and Electric told the PSC that it had reached 85% of its total allocation, and then subsequently filed an update that Tranche 3 had exceeded its 19-MW capacity, with 29.7 MW currently allocated.

Burman supported the measure but said, “I continually have felt that we are doing a delicate dance of being unwilling to admit that we may have a problem in going from net metering to [VDER] and the transition of that and what that means for when we lift and completely get rid of NEM and the grandfathering issue.”

Burman nonetheless said she supported the majority position of not disrupting the distributed generation effort and agreed that REV should ultimately decide alternatives to net metering.

January 21, 2018

FERC OKs Extended Window for MISO Capacity Auction

MISO obtained a one-time waiver of the deadline for its 2017/18 capacity auction after FERC last week agreed that technical difficulties on the RTO’s market platform was reason enough to extend the offer window.

While MISO normally closes the three-day offer window for its Planning Resource Auction at 11:59 p.m. ET, it said last year network connectivity issues caused by a hardware failure forced it to extend the window until 12 p.m. on April 1. Without the extension, at least one market participant would have been unable to submit or modify its offers during the final hours of the auction on March 31, according to the RTO.

MISO FERC waiver capacity auction market platform — | *MISO*

In its ruling last week (ER17-2113), FERC said that extending the offer deadline ensured “all market participants had the requisite time under the Tariff to submit their auction offers.” The additional time “provided sufficient, but not excessive, time for market participants to submit or modify offers,” the commission said.

MISO had assured the commission that the waiver will “not have undesirable consequences and that no third parties are harmed.”

All 10 zones in the RTO cleared at $1.50/MW-day during the 2017/18 Planning Resource Auction, a result of new supply and lower demand in the Midwest. (See All Zones at $1.50/MW-day in 5th MISO Capacity Auction.)

Consumer rights watchdog Public Citizen questioned the waiver, claiming MISO failed to adequately describe what caused the connectivity issues or to explain what corrective actions it has planned “to avoid such disruptions in the future.” FERC disagreed with the group’s contention that MISO should have to provide additional evidence or detail any future plans stemming from the mishap.

― Amanda Durish Cook

January 21, 2018

Commission OKs SPP Price Corrections

FERC last week approved SPP’s request to issue price corrections and resettlements for a two-week period in December 2016, stemming from Omaha Public Power District’s retirement of its Fort Calhoun nuclear plant (ER17-2495).

After OPPD deregistered Fort Calhoun from SPP’s Integrated Marketplace on Dec. 1, 2016, the RTO established a replacement settlement location to recognize previously awarded transmission congestion rights (TCRs) at the plant. However, the market software did not model the replacement location’s correct shift factors, resulting in an overstated marginal congestion component and understated TCRs. The error was not corrected until Dec. 14.

FERC SPP Fort Calhoun price corrections — Fort Calhoun in 2016 | *OPPD*

In a September 2017 filing with FERC, SPP said the error did not affect other settlement locations. It requested commission approval for the repricing because it did not notify market participants of the contemplated price correction within five calendar days of the operating day, as required by its Tariff.

SPP told FERC the modeling errors were associated with the Fort Calhoun deregistration and were “human performance anomalies that have since been corrected.” The RTO said it can recalculate the prices “with accuracy,” ensuring that market participants that “unfairly suffered” from the error will be made whole and creating only a “minor monetary impact” for other participants.

The resettlements will amount to $145,000 in net payments to TCR holders at the location, and a net charge of $400 to the virtual transactions.

— Tom Kleckner

January 21, 2018

FERC: Ameren Illinois Formula Rate Stands

FERC on Thursday again rejected a challenge to Ameren Illinois’ formula rate while tamping down a rehearing request from Ameren itself (EL16-1169-001).

FERC Ameren formula rate — | *Ameren Illinois*

The ruling denying rehearing lays to rest a challenge by Southwestern Electric Cooperative and Southern Illinois Power Cooperative to Ameren’s 2015 $214.4 million projected net revenue requirement. FERC largely upheld the rate in a September 2016 order while ordering Ameren to change how it accounts for contributions in aid of construction; include net operating loss carryforward in its rate base; and exclude some charges for allowance for funds used during construction from its 2016 true-up. (See FERC Finds No Significant Problems in Ameren Rate Filing.)

Both Ameren and the cooperatives sought rehearing of the 2016 ruling, with the company arguing that FERC should have dismissed the cooperatives’ first challenge outright because of “nebulous and undocumented assertions.” The cooperatives said FERC had broken with commission precedent that allows “parties to challenge the inputs to the formula rate in the same way as they can challenge costs in a stated rate case” because the commission declined to investigate whether the challenged costs were recoverable.

FERC rejected both arguments. “The commission’s power to dismiss a pleading summarily is discretionary, and declining to exercise that power here is therefore not legal error,” it told Ameren. It told the cooperatives that their interpretation of commission precedent was inapplicable because they were challenging the rate itself and not seeking “after-the-fact corrections and updates.” Finally, the commission refused the cooperatives’ request to expand the proceeding into a broader investigation of Ameren’s expenses. Initiating such an investigation, FERC said, would be beyond the scope of the complaint.

― Amanda Durish Cook