Page 1384 – RTO Insider

April 24, 2018

PJM Markets and Reliability Committee Briefs: April 19, 2018

WILMINGTON, Del. — Has the door for revising PJM’s Capacity Performance calculations been opened too far? Some stakeholders fear so after members at last week’s Markets and Reliability Committee meeting endorsed revisions to an issue charge for an initiative examining the calculation of the balancing ratio used in setting capacity offer caps.

Originally, the market seller offer cap (MSOC) equation was out of scope in the inquiry being conducted by the Market Implementation Committee and members were only focused on how to determine the balancing ratio.

The PJM Markets and Reliability Committee met on April 19, 2018 | © *RTO Insider*

The balancing ratio needs to be addressed because it is currently based on the number of performance assessment intervals PJM experienced in the past three years, and it can’t be determined if there are no such events. That became a reality this year, requiring PJM to reuse last year’s as a stopgap until a new calculation is developed. (See “Stopgap Balancing Ratio OK’d Despite Questions,” PJM MRC/MC Briefs 10-26-17.)

Beyond the balancing ratio, the issue charge also allows for evaluating how many assessment intervals are assumed in calculating the nonperformance charge rate. The current assumption is 30 intervals per year, which some stakeholders have argued is too high.

But Joe Bowring, PJM’s Independent Market Monitor, pointed out that changes to the nonperformance charge can affect the MSOC, so the MIC needs the latitude to consider changes to it as well. It’s important to maintain the consistent relationship between the nonperformance charge rate and the MSOC, said PJM’s Pat Bruno, who was presenting the proposal.

“We can’t keep the equation ‘net [cost of new entry] times B’ as the default offer cap out of scope with this issue charge because any changes we make with the nonperformance charge rate may impact that default offer cap equation,” he said.

PJM MRC offer caps — Exelon’s Jason Barker points to a FERC order that he argued shows the commission’s intent to maintain the equation for an offer cap as the net cost of new entry for a unit’s technology class multiplied by the balancing ratio. | © *RTO Insider*

Exelon’s Jason Barker questioned that position, arguing that FERC approved the specific MSOC equation — the net CONE for a unit’s technology class multiplied by the balancing ratio. He said all the necessary assessment-interval changes can be made while keeping “the FERC-approved tether to net CONE” by ensuring the interval calculation remains consistent throughout the formulas, a point on which Bruno agreed.

Barker said that — and not a potential wholesale re-evaluation of the MSOC — is what he believed stakeholders were agreeing to when they approved the issue charge. Other stakeholders agreed.

“I don’t think there’s anything in the issue charge as it stands now that would prevent us from completely changing the nonperformance charge rate,” Bruno acknowledged.

But Bowring argued there’s nothing “magical” about the current MSOC and that FERC approved the logic through which the equation was developed.

“You have to address this additional question if all of these issues are at play, which they are at the moment,” he said.

Barker said he couldn’t endorse the widened scope and encouraged others to vote against it as well.

Other stakeholders voiced concerns about the potential effect on other market mechanics, but Barker’s lobbying fell short. The proposal was endorsed with five objections and one abstention.

Offer Cap Walk Back Stalled

PJM’s hope to return to previous language over energy market offer caps was dashed after stakeholders agreed with Bowring that the previous rules also weren’t correct.

Members approved the current Manual 11 language at the October 2017 MRC to comply with FERC Order 831. PJM staff subsequently discovered the revisions restrict market-based offers to $1,000/MWh, contradicting language in the Operating Agreement. The proposal would have reverted to previous rules that market-based incremental energy offers may not exceed $1,000/MWh unless the cost-based incremental energy offer is greater than that amount. In that case, the market-based incremental energy offer is capped at the lesser of the cost-based incremental energy offer or $2,000/MWh.

The current proposal was pushed through PJM’s stakeholder process unusually quickly, with a first reading at the Members Committee webinar just three days before the MRC meeting. PJM’s Rami Dirani said the quick turnaround was necessary to maintain consistency because the order became effective on April 12. He described the return to the prior language as “very straightforward,” but Bowring disagreed.

“It doesn’t strike me as being so straightforward,” he said, noting that the previous rules didn’t address PJM’s obligation to verify cost-based offers ex ante — based on forecasts — and ensure that price-based offers not exceed cost-based offers of more than $1,000.

Carl Johnson, representing the PJM Public Power Coalition, noted that many Manual 11 changes were being discussed in October, “so maybe it just slipped our focus. But I thought we knew what we were doing then, and it’s clear from reading the manual language that we didn’t.”

The changes were originally made to reduce complexity, Dirani said.

“The inclination would be to spend a little more time on this rather than move another … rule that is not right,” Johnson said.

Other stakeholders agreed.

Calpine’s David “Scarp” Scarpignato asked that PJM return with some comparison of potential rule changes.

“I need to know more than just the mechanics,” he said.

“I’m sure it seems simple; you’re going back to previous language. So I’m sure it felt simple, but it has obviously led to further questions,” said Adrien Ford with Old Dominion Electric Cooperative.

Staff agreed to send the issue back to the MIC for discussion but said they aimed to get feedback in time to have a proposal prepared for a vote at next month’s MRC.

Price Formation Reshuffle

PJM’s Adam Keech outlined staff’s plan to address energy market price formation changes in accordance with the Board of Managers’ request that stakeholders break the issue into pieces so that less controversial changes can be implemented sooner. The board made its request in a letter April 11. (See PJM Board Seeks Reserve Pricing Changes for Winter.)

The plan breaks potential changes into short-, mid- and long-term goals that correspond with the board’s request that some reserve market changes be ready for implementation by next winter and that other energy market changes be prepared for next spring.y

In the short term, PJM plans to focus on the synchronized reserve market, dynamic reserve zone modeling, simplifying the operating reserve demand curve (ORDC) and fast-start pricing if FERC approves the proposal PJM has already filed.

The mid-term topics for the first quarter of 2019 would include developing a 30-minute reserve product, along with additional revisions to the ORDC and fast-start pricing.

The long-term plan would extend the implementation of integer relaxation and look to add shortage pricing to the day-ahead market.

“My interpretation of the discussions [at the most recent meeting of the Energy Price Formation Senior Task Force] was there were no objections to moving forward with that,” Keech said.

Greg Poulos, the executive director of the Consumer Advocates of the PJM States, said his members don’t necessarily see the need to make these changes, “but we are aligned with the goals” of analyzing the situation to see if any changes are warranted.

The consumer advocates are particularly interested in cost-impact analyses, he said.

Stakeholders OK Manual, Operating Agreement Changes

Members approved changes to Manual 12: Balancing Operations to incorporate rules approved by FERC in November regarding reviews required for approval of pseudo-tied generators. The changes were endorsed with two objections and three abstentions. (See “External Capacity,” PJM PC/TEAC Briefs: March 8, 2018.)

Stakeholders also endorsed unanimously several manual revisions and other operational changes:

Manual 14A: New Services Request Process. The revisions clarify language to match existing procedures and add language to describe in detail system impact study (SIS) and interconnection feasibility study analyses. In January, a FERC administrative law judge issued an initial decision finding that PJM’s process is unjust and unreasonable because of a lack of transparency (EL15-79). On Feb. 20, PJM filed a brief on exceptions challenging the ruling. (See FERC Judge Faults PJM, TOs on Transmission Upgrade Process.)
Manual 14B: Regional Transmission Planning Process. The revisions are the result of a periodic review that identified several administrative changes, including a revision to the generator deliverability procedure and adding the Ohio Valley Electric Corp. to the western region study area definition. (See “Transformer Consideration Changed for Gen Deliverability,” PJM PC/TEAC Briefs: March 8, 2018.)
Manual 28: Operating Agreement Accounting. The revisions address changes to comply with FERC Order 825 implementing five-minute settlements. Also makes a technical correction for the revenue data used to calculate settlements for generation resources. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
Revisions to the Operating Committee charter to replace the term “spinning reserve” with “synchronized reserves” to match the language in PJM manuals.

— Rory D. Sweeney

April 24, 2018

FirstEnergy Announces Mixed Earnings, Plan for FES Bankruptcy

By Rory D. Sweeney

FirstEnergy announced mixed first-quarter earnings Monday, along with a potential path to exit the bankruptcy of its merchant subsidiaries.

The “agreement in principle” with two groups of “key” creditors that represent most of the outstanding debts for FirstEnergy Solutions (FES) includes $225 million in cash and a tax note of $628 million due before 2020, according to a company financial disclosure filed with the U.S. Securities and Exchange Commission.

Additionally, a $787 million unsecured claim would be allowed for creditors of the company’s Bruce Mansfield coal-fired plant in Pennsylvania, where a fire damaged two of the facility’s three coal-fired units earlier this year and two workers died from exposure to hydrogen sulfide gas in August, according to company filings. Four other employees were injured. The claim would be allowed against FES and its subsidiaries, FirstEnergy Generation and FirstEnergy Nuclear Generation.

Although FirstEnergy’s Allegheny Energy Supply (AE Supply) subsidiary hasn’t filed for bankruptcy, the agreement would also transfer to creditors its ownership of the Pleasants coal-fired plant, for which it hasn’t found a buyer. (See FirstEnergy Selling Merchant Fleet Despite NOPR.)

Earnings

The agreement came as the company also reported unadjusted first-quarter earnings of $1.2 billion ($2.54/diluted share), which improved from $205 million ($0.46/share) during the first quarter last year. Operating earnings of 67 cents/share improved from 52 cents during the same period in 2017 but missed expectations by 1 cent. Revenue increased to approximately $3 billion compared with $2.9 billion a year ago but remained several hundred million dollars below analysts’ expectations.

The company attributed the improved performance to shedding its beleaguered merchant generation fleet.

FirstEnergy earnings q1 2018 bankruptcy — FirstEnergy’s coal-fired Pleasants Power Station in West Virginia would be signed over to creditors as part of an agreement announced Monday that would allow the company to exit the bankruptcy proceedings of its merchant-generation subsidiaries

“Today, we are pleased to report strong earnings that represent FirstEnergy as a fully regulated company,” CEO Charles E. Jones said.

The company raised its forecast range for unadjusted earnings for the year to $3.61 to $3.91/share, but it announced a gloomier forecast for next quarter. Unadjusted earnings are expected to drop to no more than 4 cents/share and could fall to a loss of 6 cents. Operating earnings are expected in the range of 47 to 57 cents/share.

Agreement Conditions

Company executives clarified several of the agreement’s points during a conference call on Monday to discuss the quarterly earnings with financial analysts.

One of the agreement’s conditions allows that if more than 60% of unsecured claims are recovered, FirstEnergy would receive 50% of any additional recovery. Jones acknowledged that such a situation would include any federal bailouts, such as those the company has requested through the Department of Energy, but emphasized that his interest is in keeping the plants open for the well-being of the communities in which they’re operating.

“We’re highly motivated to get support for those generating assets because it would be a mistake for our country for them to close,” he said. “I’m going to keep fighting for support for those plants, because it’s the right thing to do. If it gets to the point where it exceeds the threshold that we’ve got in this agreement with creditors, then, yes, we would share some of that, but that’s not why we’re doing it.”

In exchange for assistance from FirstEnergy during restructuring, the settlement would release the parent company from all claims, including decommissioning obligations for any of the nuclear plants if they are closed as the company has announced, Jones confirmed. (See FES Seeks Bankruptcy, DOE Emergency Order.)

FirstEnergy would waive some intercompany claims and maintain all previously announced guarantees, including pension obligations for FES employees. Creditors agreed to “use their best efforts” to get remaining creditors to join the settlement by June 15.

The agreement must receive sign-off from a federal bankruptcy court in Ohio, along with the boards of directors for FirstEnergy and its subsidiaries, including FirstEnergy Nuclear Operating Co. (FENOC).

FES and FENOC voluntarily filed for Chapter 11 bankruptcy on March 31. FES is FirstEnergy’s merchant generation and retail marketing subsidiary, while FENOC operates FES’ three nuclear plants. The decision, while expected for some time, is nonetheless creating ripples of uncertainty throughout the industry. (See FES Bankruptcy Creating Additional Uncertainty.)

April 24, 2018

CenterPoint Energy to Acquire Vectren in $6B Deal

By Amanda Durish Cook

Houston-based utility CenterPoint Energy announced Monday that it will acquire Vectren in an approximately $6 billion deal expected to close in the first quarter of 2019.

CenterPoint will pay Vectren shareholders $72 for each share of Vectren common stock — a $6.45 premium to Friday’s closing price — and assume all outstanding Vectren net debt. Hours after the announcement, Vectren closed Monday at $70.31 while CenterPoint ended the day at $25.94/share, down 31 cents.

FERC PJM Vectren Centerpoint Energy — Vectren headquarters in Evansville | *Hafer Design*

The merged company will retain the CenterPoint name and its Houston headquarters. CenterPoint will also maintain Vectren’s Evansville, Ind., headquarters for the company’s natural gas utilities and Indiana electric operation. The company will serve more than 7 million customers, operate electric and natural gas delivery operations in eight states and hold about $29 billion in assets.

The merger agreement has been approved unanimously by the boards of both companies, though the deal still requires approvals from Vectren shareholders, FERC, the Federal Communications Commission and regulators in Indiana and Ohio. CenterPoint said it expects to maintain a 5% to 7% annual earnings per share growth target in 2019 and 2020, excluding any one-time charges related to the merger. Both CEOs said the move will benefit their companies.

“By combining our two highly complementary companies, we are creating an energy delivery, infrastructure and services leader that will drive value for our shareholders and customers, while enhancing growth opportunities for our businesses,” CenterPoint CEO Scott Prochazka said in a statement.

“With CenterPoint Energy, we’ve found the right partner to begin the next chapter for Vectren and our family of companies. … Together, we will be a stronger, more competitive company that will be well-positioned to continue to provide value for our stakeholders in the years to come,” said Vectren CEO Carl Chapman.

Prochazka will remain CEO of the combined company. All other executive positions will be announced “prior to or in conjunction with the closing of the merger,” the companies said. CenterPoint said it will establish an executive position in Evansville, Ind., to handle natural gas utility operations and a chief business officer for Vectren’s electric business to directly report to the CenterPoint CEO and “spearhead southwestern Indiana’s electric grid modernization and generation transition initiatives recently underway.”

Earlier this year, Vectren announced it would build an 800- to 900-MW, $900 million natural gas plant in southwestern Indiana and a 50-MW, $75 million solar farm about 60 miles from the gas plant site. The new generation would replace three of Vectren’s coal-fired plants. The proposed gas plant still requires approval from the Indiana Utility Regulatory Commission. The company is also set to complete construction this year on two solar farms near Evansville that will produce 4 MW combined.

Prochazka and Chapman told the Evansville Courier & Press that they expect the merger will reduce Vectren’s 5,500-person staff but that it was too soon to say where, or how deep, the cuts will be.

The company provides electricity to about 145,000 customers in Indiana and natural gas to more than 1 million customers in Indiana and Ohio. Vectren also owns non-utility businesses Vectren Infrastructure Services Corp., which provides underground pipeline construction, repair and replacement services, and Vectren Energy Services Corp., which offers performance contracting services and renewable energy project development. CenterPoint said it intends to continue operating both companies.

CenterPoint currently delivers electricity to more than 2.4 million customers in the greater Houston area and serves another 3.4 million customers with natural gas operations in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The company employs nearly 8,000 people.

April 24, 2018

CAISO Says Changes Will Better Match Forecasting, Demand

By Jason Fordney

CAISO last week provided details on its plans for major changes to improve the alignment of its day-ahead market with real-time demand by introducing more scheduling granularity and other refinements.

Nearly 150 participants joined a conference call Wednesday at which the ISO discussed technical aspects of the revised straw proposal it issued April 13. CAISO has also proposed extending the proposed changes across the Western Energy Imbalance Market (EIM).

As currently proposed, the changes would address forecasting uncertainty in the day-ahead that is currently left to the real-time market to resolve, CAISO Senior Design Policy Developer Megan Poage said during a presentation.

The proposal would introduce 15-minute scheduling in the integrated forward market, which procures the generation needed to meet forecast demand. It would also create a day-ahead imbalance reserve market product and combine the integrated forward market and residual unit commitment. The third major prong in the initiative is to procure imbalance reserves with a must-offer obligation to submit economic bids in the real-time market.

“These three elements are dependent on each other. They must all be introduced at the same time,” Poage said, adding that “We’ll be moving toward a co-optimized day-ahead market run.”

The initiative, which was announced in December, is seen as a possible forerunner for a new Western RTO market structure by introducing a day-ahead market into the EIM, which is currently only a balancing market. (See CAISO Day-ahead Could be Tailored for West.)

“Grid infrastructure has advanced, the resource fleet has changed and the policies regulating operation of the grid have evolved (i.e. FERC-mandated 15-minute scheduling in real-time energy markets),” the ISO said in the straw proposal.

The proposal is intended to help manage excess solar generation in the middle of the day and make it possible to also reduce generation output. The current structure does not allow the ISO to decommit resources that were scheduled in the integrated forward market.

CAISO said the current hourly scheduling structure causes the day-ahead forecast to be higher than actual demand, resulting in “downward uncertainty,” in hours 1 to 12, and mismatches between day-ahead forecast and actual demand in hours 20 to 22.

caiso day-ahead market scheduling — CAISO says the current hourly scheduling structure causes “downward uncertainty” between day-ahead forecast and real-time demand in hours 1-12 and “granularity difference” in hours 20-22 | *CAISO*

Based on comments from market participants, CAISO changed the proposed 15-minute and five-minute imbalance reserves products in upward and downward directions into a single product for both directions. To address five-minute needs, CAISO would create sub-regions for the imbalance reserves product.

It also provided additional information explaining certain formulas it plans to use in the new day-ahead market, data analysis and proposed methodologies to determine imbalance reserves requirement, as well as a settlement and cost allocation worksheet for use by potential market players.

Overall, CAISO said, the changes will help decarbonize the electric grid, improve reliability as the system changes and create more market benefits across the region. The goal is to present the proposal to the EIM Governing Body in August and the ISO Board of Governors in September.

April 24, 2018

Resilience, Storms, Survival are Topics at New Mexico Forum

By Jason Fordney

SANTA FE, N.M. — In an American West city known for its artists, writers and the beauty of its barren desert environment, state regulators and others last week discussed difficult grid reliability issues and the more vicious side of nature.

Grid Resilience Hurricane Season Current Issues Conference — New Mexico State University’s Center for Public Utilities held the Current Issues Forum at the El Dorado Hotel | © *RTO Insider*

New Mexico State University’s annual Current Issues Conference has a reputation as a more informal gathering than other industry gatherings. A major topic at this year’s meeting was the severity of the 2017 hurricane season, in which grid resilience was tested in Texas, Florida and the Caribbean.

Industry consultant Alison Silverstein told the forum that the duration, magnitude and “customer survivability” of electricity outages are metrics that could be used to measure grid resilience. The grid is operated for the benefit of customers, she said, and resilience should be measured in “customer-based” terms.

Silverstein was an author of the Department of Energy grid study released last August but later criticized the department when Energy Secretary Rick Perry used its findings in his proposal that FERC order price supports for coal and nuclear generators with onsite fuel. (See Author of DOE Grid Study Disputes Recommendations.)

Perry’s Notice of Proposed Rulemaking was rejected in January by FERC, which instead opened a new resilience docket.

Silverstein told the forum that the technical conclusions she reached did not align with the department’s contention in the NOPR that coal and nuclear plant retirements were a reliability threat. “They apparently didn’t read the results of their own study,” she said.

Regulators shouldn’t overly focus on generation-based outages because 90% of outages occur in the distribution system, Silverstein said, and big weather events don’t usually affect power plants. Fewer than one in 10,000 customer outage minutes were caused by generation shortfalls.

Coal plants forced to retire since 2002 were old, inefficient and lacked the flexibility that today’s grid needs, Silverstein said. “Regulations were not the cause of the retirements,” she said, adding that fuel diversity has improved in areas where coal plants have retired.

ERCOT FERC Hurricane Sandy MISO Informational Forum — Grid resilience and recovering from natural events were key themes at this year’s forum | © *RTO Insider*

Coal and nuclear subsidies are not the answer and would “cost a fortune,” she added.

There are many ways to improve resilience and reliability, she said, mentioning many of the topics discussed throughout the two days of the forum: distribution system improvements, situational awareness, emergency drills, system recovery and black start capabilities.

“Customer survivability” includes things like backup generators, rooftop solar and emergency supplies like flashlights. “You are already doing a lot of these measures,” Silverstein told the regulators.

Hurricane Response Ongoing, DOE Official Says

DOE Deputy Assistant Secretary Devon Streit discussed the department’s response to the hurricanes and natural disasters of 2017, an effort that is still ongoing. She said the department had response efforts in Texas, Florida, Puerto Rico and the U.S. Virgin Islands.

“We learned that island response is tough,” she said, mentioning not only the difficulties of restoring electric infrastructure in a remote environment but also the challenges of operating without facilities like radar, without which planes cannot land. Ships could not transport electrical equipment because they were carrying food, medicine and other critical supplies.

DOE’s Office of Infrastructure Security and Energy Restoration (ISDER) is responsible for energy sector preparedness and response, including electricity, oil and gas, and cybersecurity. It studies threats and examines hazards as well as holding exercises. It is responsible for communicating with federal and state agencies on what is happening on a near-hourly basis, she said in a presentation.

“We are still active for Hurricane Maria,” a response now in its 236th day, she said.

Streit discussed the value of situational awareness and mutual assistance projects, such as utilities sharing equipment. “What happened in Puerto Rico or Virgin Islands could happen in other places,” she said.

Texas Official Discusses Harvey Response

Public Utility Commission of Texas Chairman DeAnn Walker described how she went to her commission’s State Operations Center to conduct the response during Hurricane Harvey, which she said was “a very, very different storm than previous storms such as Ike and Rita.”

Walker said that in the first time in her experience, mobile substations were brought in because “we had substations flood that had never taken on water the whole time they were built.”

At the operations center, the PUCT worked on grid restoration with utilities and state and federal officials, including DOE, the U.S. Army Corps of Engineers, the Federal Emergency Management Agency and the Department of Homeland Security.

Harvey was the largest rain event in U.S. history, dumping an estimated 40 to 60 inches of water in southeast Texas and southwest Louisiana. ERCOT lost 12,000 MW of generation as gas-fired plants were evacuated or flooded, and coal plants and wind turbines were shut down. (See Weeks Later, Utility Officials Still Awed by Scale of Hurricane Harvey.)

April 24, 2018

RTOs Take to Catwalk for Western Commissioners

By Robert Mullin

VANCOUVER, Canada — The three RTOs vying to organize Western electricity markets on Thursday faced off before an audience of utility regulators in what one state commissioner billed a “beauty pageant.”

Peak Reliability PJM Connext Mountain West Western RTO — Kavulla | © *RTO Insider*

“Thank you for competing,” Montana Public Service Commission Vice Chairman Travis Kavulla jokingly told representatives of CAISO, SPP and PJM. Kavulla is co-chair of the Committee on Regional Electric Power Cooperation, which hosted the panel at its spring meeting in the Coast Coal Harbour Hotel.

The regulators were there to examine the possible benefits and drawbacks of the competing grid operators’ efforts to sign up utilities in a region that has been historically resistant to organized markets. (See CAISO Bid for Western RTO to Face Competition in 2018.) They, and other industry watchers, also learned what region PJM is focusing on in developing its Western market partnership with Peak Reliability.

Here’s some of what they heard.

Looking West

Little Rock, Ark.-based SPP has been running its Integrated Marketplace since 2014, after previously operating a balancing system like CAISO’s Western Energy Imbalance Market (EIM). The RTO last year entered membership negotiations with Mountain West Transmission Group, a partnership of seven transmission-owning entities within the Rocky Mountain region of the Western Interconnection. The effort hit a significant roadblock late Friday when Xcel Energy announced it was pulling out of the group and the negotiations with SPP because of the “limited benefits” for its customers in integrating into the RTO. (See Xcel Pulls out of Mountain West, Endangering SPP Integration.)

“There are benefits from operating together” in an RTO, SPP Chief Operating Officer Carl Monroe told Western commissioners. “A natural inclination we would have is to look west.”

“We’ve got another unique situation in that we’re the only one connected to ERCOT,” he said.

Monroe touted the fact that SPP’s Board of Directors cannot express a decision without the consent of the RTO’s Members Committee, which provides each market participant a vote over market initiatives presented to the RTO board.

He also pointed out that SPP has functioned as a reliability coordinator (RC) for 20 years.

“And how that interfaces with the market … that was one of the key issues we dealt with in the market,” Monroe said. “These are hybrid markets. … They have to be designed to protect reliability itself.

“Our job one is to keep the lights on — reliability,” he added. “Even the economics don’t make sense if you’re not reliable.”

SPP’s market has been efficient for its members, he said.

“The capital costs of putting the market in — we recovered those within six months,” Monroe said, adding that the SPP footprint today carries 5 GW less generation than it would “if we weren’t running the market.”

He also pointed to SPP’s expertise in integrating large volumes of renewables.

“Of course we’re in a wind-rich area. We just set a record when 63% of the load was served by wind,” he said. “That could not have been done unless on a regional basis.”

“We actually do interregional coordination,” Monroe continued. “This is one of the things we’ll need to do within the West itself, is making sure we coordinate all the activities, whether it’s transmission planning, transmission operations, reliability coordination, market activity. All those things will have to be coordinated with the other parties that border whatever footprint we finally get around to.

“Part of the strategy going forward is being open to those parties who want us to do these services for them,” Monroe said.

Listening to the West

“As you all know, many states in the West are aggressively pursuing more renewables,” CAISO CEO Steve Berberich said.

With a fleet heavy in renewables, ramping and overgeneration become “a focal point” for the ISO, he said.

“Security-constrained economic dispatch — in other words, an optimized market — is the best way to run the grid as efficiently as possible, and the sharing of resources is the best way to solve our critical need collectively to support the variability of renewables and the induced ramps,” Berberich said. “Further, the zero-marginal-cost power is better shared at a lower cost for all of our customers. We share this view with our [SPP] friends from Little Rock. You’ll also hear that from our friends from PJM in Philadelphia.”

Berberich trumpeted the EIM’s $250 million in member net benefits since it was launched in 2014. CAISO last year proposed to expand the EIM to include day-ahead transactions without transitioning the market into a full RTO. The ISO has also announced it will withdraw from Peak Reliability as an RC and provide reliability services to other balancing authority areas in the West.

He acknowledged that the EIM’s implementation of a day-ahead market will require the ISO to resolve approaches to resource adequacy and transmission compensation.

“Those are solvable, and we’ll continue to give deference to state control over resource mix and capacity margins. We also expect the EIM Governing Body to morph into a broader governing body with at least some joint decisional authority with the current [CAISO] board of directors,” he said.

CAISO expects to offer the combined EIM and day-ahead market at a cost significantly below the ISO’s current grid management charge, Berberich said. It also intends to offer the same reliability services as Peak at a “significantly reduced” cost.

“When you cut through it all, the fundamental markets are all the same. … What is different in our market, however, is the sophistication of our optimization and how it supports renewables, steep ramps and distributed generation aggregations,” Berberich said.

He said the ISO doesn’t foresee the need for any new transmission to “support the transformation into a regional market.”

On the issue of governance of an expanded ISO, Berberich told the commissioners that the “main pathway” is to change the existing governance model through legislation at the state level in California.

“The alternate pathway is to continue to evolve our governance according to the Energy Imbalance Market’s governing model, and with a day-ahead market, that will necessarily involve decisions on transmission compensation and some form of resource adequacy, both potentially having input from the [EIM] Body of State Regulators,” he said.

“Some of the ISO brethren say the Peak/PJM market offering is a market by the West, for the West, which misses what has already occurred in the Energy Imbalance Market. Participants are certainly not guests of the ISO, rather, they help form the market,” Berberich said.

The ISO’s job is to “listen to whatever the West wants and do our best to provide the value inherent in our interconnected systems.”

“When do we need to move to this new market? Soon, we think. We believe it will provide the most efficient way to streamline new transmission planning and upgrades, reduce the need for more capacity and reduce the need to curtail valuable clean resources. It provides the greatest value with the geographical and resource diversity that the West is blessed to have.”

For the West, by the West

“We believe there’s a very real opportunity for the utilities in the West to pursue the potential for the creation of a separate market,” said Stu Bresler, PJM senior vice president of markets and operations.

Bresler was speaking on behalf of the joint proposal between Peak Reliability and PJM Connext (a PJM subsidiary) to develop new wholesale market structures for the West. Like the CAISO EIM day-ahead expansion, it would fall short of creating a full RTO in the near term, while creating a foundation for one in the future.

Kavulla asked: “What area are you focusing on? Is it an area with lots of trees and hydro, or lots of sun?”

“We’re focusing primarily in the Southwest,” Bresler replied.

“The value proposition — and Steve has already said it before I had a chance to get up here — is a market for the West and by the West,” Bresler said. “What we are really leveraging here is the combined knowledge of our expertise of both of our organizations.

“PJM has proven its ability to promptly deliver on its commitments,” he said, citing PJM’s pledge to complete a business plan with Peak by March 30. (See Peak/PJM Enter Western Market Commitment Phase.)

“We have also been sharing the full plan with a set of key entities in the Western Interconnection that could potentially form the basis for a separate market out here in the West, should they decide to pursue that,” he said.

Striking a similar note to SPP’s Malone, Bresler said that wholesale electricity markets exist for the sole purpose of reinforcing grid reliability.

“That’s why we develop them; that’s why we operate them.”

Bresler said markets are intended “to ensure that physical asset owners have the financial incentive to act in a manner as to reinforce grid reliability.” Key to that is ensuring that market prices reflect actual operating conditions, and that “those prices are transparent to market participants in real time.”

“And that transparency and that reflection of actual operating conditions is what builds the confidence of the physical asset owners that the dispatch instructions delivered by the system operator are in their financial best interests. That financial best interest is a powerful motivator that supports reliable grid operations,” he said.

“We believe that the bulk of trading activity actually occurs in the bilateral markets,” Bresler said. “That is really an appropriate way for things to occur because it is what allows market participants to best manage and therefore minimize their risk.”

Bresler said the Peak/PJM business plan — which has not been made fully available to the public — shows that “with a large amount of participation in a market in the West, the production cost savings become very substantial.”

Lauding Peak’s RC capabilities, Bresler said that much of the hard work of starting up a regional market is already complete based on Peak’s West-wide model and the processes and mechanisms in place to support reliability.

“Really, the smaller part is layering [the market] on top of those reliable grid operations,” he said.

PJM’s “Day 1” market offering would consist of a day-ahead and real-time market.

“Some options that could be included as well, should participants want it, we could operate ancillary services. We could also add [financial transmission rights], but that’s not a requirement for Day 1,” Bresler said.

Based on feedback from potential participants, Bresler said Day 1 won’t include a resource adequacy construct or capacity market; consolidation of transmission tariffs; provision of transmission service; and regional or sub-regional transmission planning.

On one key issue, Bresler sought to score points from commissioners overseeing utilities already participating in the Western EIM.

“I don’t think of the establishment of the market as being exclusive of participation in the EIM,” he said.

Bresler noted that Peak and PJM had envisioned getting a “critical mass” of commitments from market participants by May or June, but they have extended that timeline to determine a “go or no go” decision on the market by the fall.

Kavulla asked Bresler when Peak/PJM anticipated releasing its full business plan for public review.

“We don’t really have any plan to do that. If members do decide to take the next step, we would take the decision with the members to do that,” Bresler said.

Bresler wrapped up his moment in the spotlight by echoing Berberich’s conclusion: “If utilities in the West want a full market … there’s not a better time to do it than now.”

April 24, 2018October 31, 2023

Overheard at the Energy Storage Association Annual Conference

BOSTON — Energy storage deployment will likely grow to 35 GW by 2025 as consumers, businesses and government agencies increasingly support the technology, industry experts said last week.

Storage Deployment Energy Storage Association Annual Conference

Speakes-Backman | © RTO Insider

“Our industry created the momentum for the unanimous support to unleash the benefits of storage through FERC Order 841,” Energy Storage Association CEO Kelly Speakes-Backman said at her organization’s 28th annual conference. “This is a watershed moment, friends, this is our moment.” (See FERC Rules to Boost Storage Role in Markets.)

The industry’s growth will create hundreds of thousands of jobs, result in $4 billion in cumulative operational savings and avoid 3.6 million metric tons of CO₂ emissions and 1,000 metric tons of CO₂ equivalents, including nitrogen and sulfur oxide, Speakes-Backman said.

“On a regular basis, our teams are in contact with ISOs and RTOs who are seeking guidance in how to create markets and support rules that enable more storage on the transmission level, distribution level, in businesses and in homes,” she said.

Clean Peak Shaving

Massachusetts Gov. Charlie Baker opened the conference April 18 by saying that energy storage’s ability to shave peak demand “may be greater than anything else.”

Baker mentioned the “very unusual winter here in New England and in Massachusetts … where we had subzero temperatures for almost two weeks,” during which the region’s generators burned through nearly 2 million barrels of oil, more than twice the amount used during all of 2016. (See Van Welie: ISO-NE in ‘Race’ to Replace Retirements.)

“If you push storage all the way … you could be in a situation where you store during off-peak so that when you have a period like that, you’ve got enough capacity available to draw the storage and you don’t have to pay those huge prices during peak; you don’t have to use those far dirtier sources of energy,” Baker said.

The Baker administration filed legislation in March to spend more than $1.4 billion on climate change measures, including proposing a Clean Peak Standard mandating that utilities use a minimum level of clean energy to supply the highest-priced peak hours, or 10% of grid hours each year.

Baker on Wednesday highlighted the state’s “combo platter” of ambitious goals to solicit 9.45 TWh per year of hydro and Class I renewables (wind, solar or energy storage) and to develop 1,600 MW of offshore wind by 2030, with contracts for the former due later this month, about the same time the state plans to announce its offshore wind selection.

The scheduling conflict overtaxed the Department of Energy Resources, delaying the offshore selection until later this spring, Baker said.

The state in December awarded nearly $20 million in grants for 26 energy storage projects as part of its Energy Storage Initiative and Advancing Commonwealth Energy Storage program, funded by the DOER through alternative compliance payments and administered by the Massachusetts Clean Energy Center.

The storage projects are also drawing an additional $32 million in matching funds pledged by developers or host municipalities, “which in my view is always the right way for us to be investing in this stuff,” Baker said. (See Massachusetts Awards $20M in Energy Storage Grants.)

Commercially Viable

ISO-NE had no storage in its interconnection queue a couple years ago. It now has more than 500 MW of grid-scale energy storage proposals in the queue, a number that has been growing even in recent weeks, said Christopher Parent, the RTO’s director of market development.

“I think that speaks highly both to state policy in the region driving interest in storage,” Parent said, “but also to the fact that storage itself is becoming a more commercially viable product and can actually participate in the market, potentially on a merchant basis as its costs continue to decline.”

Dan Finn-Foley, senior energy storage analyst for GTM Research, said “energy storage costs have dropped dramatically over the past few years” and projected the trend to continue. ESA figures show the costs for large-scale storage systems declined by 50% since 2014, and Finn-Foley estimates those costs will drop an additional 35% by 2022.

“Storage’s participation in the wholesale market depends on size, location and function — what they want to do,” Parent said.

He noted the RTO is applying the same market cost allocation exemptions to storage that are applied to pumped hydro — uplift charges, for example — and for the same reasons: the reliability services they provide to the grid.

Galen Nelson, senior director for innovation and industry support at the Massachusetts Clean Energy Center, said, “I think it’s interesting to note that two out of three offshore wind applicants included storage in their 83-C proposals, so that community is seeing storage as a key asset to improve the economic viability and attractiveness of those proposals.”

Finn-Foley said there could be a 20-GW opportunity for storage to replace costly gas-fired peaker plants.

“In California, several natural gas peaking plants that were planned have been either scrapped or they’re being re-examined, with energy storage potential taking over there,” Finn-Foley said. “In addition, in Arizona they’re putting a moratorium on new natural gas plants, focusing on energy storage instead.”

Unique Storage

Storage is unique in many ways because it can participate in markets on so many different levels, Parent said.

“Eventually you could put storage behind commercial very easily and I think that’s where it becomes unique, because if someone comes to me and says, ‘I have this great storage project, I want to participate in your markets,’ [the] first question I ask is: ‘What is your project?’” he said.

Packed house for the Energy Storage Association’s 28th annual conference | © RTO Insider

The RTO must first understand how a project wants to participate, which is a function of its size, location and purpose, Parent said.

“Some project developers come to us and they don’t even want to participate in the markets, they just want to understand how to interconnect,” Parent said. “They’re focused on demand charge savings.”

Asked about how the RTO treats solar facilities with storage capabilities, Parent said its prefers to directly meter solar.

For smaller applications, “we feel we get a much more efficient outcome by modeling those facilities discretely, so we’re dispatching and taking full advantage of the capability of the battery, and also in effect letting the solar participate in the market based on its physical characteristics,” Parent said.

“What we see is when we start bundling facilities together, our ability to efficiently dispatch that facility and count ancillary services on it actually starts to disappear,” he said.

— Michael Kuser

April 24, 2018

UPDATE: Xcel Leaving Mountain West; SPP Integration at Risk

By Tom Kleckner

Xcel Energy, the Mountain West Transmission Group’s largest member, said late Friday that it is withdrawing from the Rocky Mountain group and its efforts to join SPP — potentially dooming the planned integration.

Executive Vice President David Eves, group president for Xcel’s utilities, said in a press release that the company recently completed a review of the Mountain West’s proposal to join SPP and determined that “continued engagement in Mountain West is not in the best of interests of our customers or the company.”

Xcel said “limited benefits” for the company’s Colorado customers, a lack of “market expansion opportunities” for the Mountain West and increasing “uncertainty over the costs of the RTO” led to its decision.

The Mountain West entities sit in the Western Interconnection, which has seen several market-related developments in recent months. Multiple Entities, Markets Now Beckon in West.)

Friday’s announcement caught SPP and Mountain West off guard. Xcel spent much of Friday alerting Mountain West members, state and federal regulators and other interested parties before issuing the release.

In an emailed statement, SPP CEO Nick Brown said the RTO was “surprised and disappointed.”

“SPP has spent significant time and effort attempting to bring organized wholesale markets and their many benefits to the West,” Brown said. “We’re hopeful there will still be opportunities to do so.”

Brown addressed the issue at the Regional State Committee meeting in Kansas City on Monday. “Obviously, we were shocked Friday by the announcement of [Xcel] pulling out of the Mountain West initiative,” he said. “In my initial discussions with other participants of Mountain West, they’re meeting to determine what their next steps are, and we will certainly do the same.”

Members of the RSC, which comprises regulators from most of the 14 states in SPP’s footprint, have also expressed reservations about the integration’s cost allocations. (See Mountain West, Cost Allocation Top SPP RSC Concerns.)

The decision left several of Mountain West’s entities pondering their next steps. With 1.4 million customers, Xcel’s Public Service Company of Colorado subsidiary represents about 40% of Mountain West’s base.

Lee Boughey, senior manager of communications and public affairs for Tri-State Generation and Transmission Association, said the cooperative would “take time to review its options and determine the best approach to move forward.”

“Ultimately, any decision to participate in a regional transmission organization will be dependent on whether it benefits our members,” Boughey said.

Tri-State is a member of both Mountain West and SPP, having joined the RTO as part of the Integrated System’s membership in 2015.

Theresa Donnelly, senior communications manager for Black Hills Corp., said her company is also “evaluating the impact” of Xcel’s departure from the SPP integration effort.

“We will continue our discussions in the coming days and weeks,” Donnelly said. “We respect Xcel Energy’s decision to end their participation in Mountain West, as the benefits and costs of RTO membership differ for each company based on their unique business situation and interests.”

Mountain West, which primarily services Colorado, Wyoming and Nebraska, began discussing RTO membership in 2013. It announced in January 2017 that it was pursuing membership in SPP, and in March, the RTO’s Board of Directors approved a set of policy recommendations intended to govern the terms of Mountain West’s membership. (See SPP Begins Work of Integrating Mountain West.)

Xcel said “a variety of interrelated items” drove the company to its decision:

The limited overall benefits to Xcel’s customers, “given the relatively small size of the MWTG footprint.”
The few opportunities for westward expansion of the RTO, “which might have added to the value proposition.”
A recent increase in the costs of forming an RTO, with “less certain” benefits that are “highly dependent on both the footprint, generation flexibility and composition of” Mountain West.
Recent developments with RTOs have “introduced an increased risk of more significant changes to state-regulated retail electric service than Xcel Energy had anticipated.”

“Xcel Energy will continue to focus on initiatives that will benefit our customers, keep bills low and facilitate the addition of renewable resources on our system,” Eves said. “Our customers and the state of Colorado benefit when states control their own energy policy.”

Colorado’s Public Utilities Commission, which has jurisdictional authority over Xcel and Black Hills, was thought to be the primary stumbling block to completing the Mountain West’s integration. The PUC declined to comment Saturday.

Denver-based attorney Abby Briggerman, who represents consumer groups before FERC, said in a statement: “We appreciate Xcel’s efforts to ensure meaningful savings for ratepayers and hope that whatever the alternatives considered, there will be a transparent stakeholder process to allow for comprehensive consideration of the best course forward.”

The Western Area Power Administration issued a statement saying it “appreciates the strong collaborative partnerships” within Mountain West and “is assessing [its] next steps” following Xcel’s withdrawal.

“WAPA maintains its commitment to working with neighboring entities across its 15-state footprint to develop strategies to adapt to the evolving electricity industry,” said Chief Public Affairs Officer Teresa K. Waugh. “We will continue to evaluate and pursue opportunities to optimize the utilization of generation and transmission resources across multiple utility systems.”

In recent weeks, a growing number of SPP stakeholders have pushed back against the Mountain West integration. A group of five members filed a letter April 6 asking the RTO’s board to reconsider its decision to move forward with the integration until “there is more consensus within the SPP membership as to how to proceed.” (See SPP Group Balks at Mountain West Concessions.)

On Wednesday, Lincoln Electric System (LES) issued its own letter, saying it agrees with the April 6 missive that the board should reconsider the approved MWTG policy recommendations.

LES said it is concerned about the recommendation proposing regionwide cost allocation for the Mountain West DC ties. “The expectation that existing SPP members would pay for DC tie legacy facilities is unprecedented and in contravention to the SPP Tariff,” wrote LES CEO Kevin Wailes.

LES also said there is no policy justification for the proposed three-year phase-in administrative fee discount for Mountain West members. “lf the purported benefits of the [Mountain West] integration have been accurately represented, there should be no need for one subset of SPP transmission owners to subsidize another subset during this period,” Wailes said. “Like others, we are in support of efforts to strategically bring in new entities that aren’t at the unnecessary expense of SPP’s existing members,” he added.

On Friday, the Missouri Joint Municipal Electric Utility Commission and the municipal utilities of Springfield and Independence, Mo., filed a joint letter outlining their concerns in language almost identical to that of LES.

SPP’s board and its Members Committee are scheduled to meet Tuesday in Kansas City, Mo. The agenda includes a Mountain West update and a president’s report, which will likely generate much discussion.

April 23, 2018

Calif. Energy Bills Move Forward, but Big Ones Stall

By Jason Fordney

California lawmakers moved forward with several pieces of energy legislation last week, but hotly watched items such as a 100% renewable energy standard and CAISO regionalization seem to be set on simmer.

california energy legislation — Several bills moved through a California Assembly Committee last week | © *RTO Insider*

There has been no movement this year on SB100, former State Senate President Pro Tempore Kevin de Leon’s 100% renewable energy bill that was front and center as the 2017 legislative session drew to a close. (See CAISO Regionalization, 100% Clean Energy Bills Fizzle.) SB100 has seen no votes since the Assembly Appropriations Committee last September.

And AB813, legislation that would regionalize CAISO, sits in committee during this session as other, higher-profile issues heat up. (See Calif. Lawmakers Relaunch CAISO Regionalization.) The regionalization language is currently in the Senate Rules Committee and the next step is a referral to the Energy Committee.

The U.S. Senate Democratic primary between de Leon and longtime Sen. Dianne Feinstein is taking up a great deal of political oxygen and an unrelated series of sexual assault controversies are another major distraction in the Capitol. (See Wildfire Costs Ignite Worry at CPUC, Legislature.)

On Thursday, the Assembly Utilities and Energy Committee, chaired by Assemblyman Chris Holden (D) passed several pieces of legislation, including:

AB2068(Chu), to Appropriations: It would require IOUs to evaluate the feasibility of discounting rates for public schools by at least 15% and for the California Public Utilities Commission to determine whether to adopt the discount. It requires the CPUC to direct IOUs to evaluate and report on the feasibility and economic impact of establishing the discounts. The evaluation must include commercial rate increases for the past five years that affected schools and the economic impact to other ratepayers if all public schools receive the discount. The bill requires the CPUC to submit the report to the legislature by Jan. 1, 2020.
AB2208(Aguiar-Curry) to Natural Resources: The bill requires investor-owned utilities, community choice aggregators, retail energy sellers and publicly owned utilities to procure an unspecified percentage of their resources from geothermal, biogas or biomass facilities. An unspecified amount would have to be procured from the Salton Seageothermal resource area, 10 generating plants producing 327 MW in Southern California’s Imperial Valley. According to an author’s statement, “AB 2208 will make it easier to reliably integrate higher amounts of renewable energy generation into the grid by requiring the procurement of ‘grid-balancing’ renewables, such as geothermal and bioenergy.” It would allow bioenergy facilities open to continue accepting wood waste as a forest fire management measure.
AB2515(Reyes) to Appropriations: The bill requires the CPUC to report to the legislature pending and previously approved changes to IOU revenue requirements over at least the past five years that resulted from requests by IOUs and CPUC decisions and resolutions. It also requires IOUs seeking a rate change to disclose estimated rate and bill impacts on each customer class.
AB2831(Limon) to Appropriations: Requires the CPUC, in consultation with the Office of Small Business Advocate within the governor’s Office of Business and Economic Development, to ensure that adequate marketing, education and outreach are undertaken to enable small business customers to fully participate in demand-side energy management programs.

April 23, 2018

Western Regulators Get Schooled in RTO Legal 101

By Robert Mullin

VANCOUVER, Canada — With three RTOs advancing competing efforts to extend their services into the West, the region’s utility regulators last week took a timely crash course on the legal implications of allowing their utilities to join organized markets.

It was a bracing — and invaluable — session, according to some industry stakeholders attending the spring joint meeting of the Western Interconnection Regional Advisory Body and the Committee on Regional Electric Power Cooperation.

organized electric markets — Hempling | © *RTO Insider*

Scott Hempling, an attorney specializing in public utility law, provided a compressed but comprehensive 90-minute primer of the statutes, regulations and case law governing the functioning of RTOs, beginning with their origins in FERC Order 2000, which encouraged — but did not require — utilities to form or join an RTO.

“The primary purpose was to end discrimination by transmission owners,” Hempling said. “One of the methods of discrimination before Order 2000 was to keep secret the availability of transmission.”

Hempling explained the four “minimum characteristics” of RTOs required by FERC: independence; appropriate scope and regional configuration; operational authority; and exclusive authority over short-term reliability.

In addition, RTOs must fulfill eight “required functions,” including tariff design and congestion management. “Understanding those 12 things is crucial to understanding what’s getting turned over to the RTO,” he said.

Hempling clarified that a transmission-owning utility legally becomes a customer of an RTO once it joins the RTO and turns over its transmission assets. It also becomes FERC jurisdictional. “When your utility joins an RTO, it no longer provides transmission service,” he said.

“Let me put it bluntly: you lose jurisdiction over transmission costs” when a utility joins an RTO, Hempling told the audience of commissioners. As a result, any state commission that has approved RTO membership cannot “logically disallow” a utility from including in retail rates the costs of becoming a customer of the RTO.

“Once FERC determines that the rate charged by the RTO to the transmission owner is prudent, the state must pass that cost on” to customers, Hempling said.

And while a transmission-owning utility does receive a pro rata share of the revenues the RTO generates from all transmission customers, the resulting credits don’t always make retail ratepayers whole. “You’d think the retail charges and credits would be a wash, but that’s not necessarily the case,” Hempling said.

One commissioner asked if FERC made distinctions within RTOs between how it treats investor-owned utilities on the one hand and rural cooperatives and municipal power systems on the other.

Hempling noted that the Federal Power Act exempts publicly owned systems from FERC oversight — unless they are TOs and join an RTO. “Co-ops and munis join RTOs by contract. Now if they’re transmission owners, are they subject to FERC jurisdiction? The answer is ‘yes.’” Based on FERC’s reciprocity rule, “if you want to take transmission service and you own transmission, then you’re going to need to provide transmission service,” Hempling said.

FERC ‘Controversies’

Hempling turned to key areas “where FERC finds itself resolving controversies” related to the nation’s RTOs.

Chief among the agency’s concerns: return on equity for transmission investments.

“There is a great deal of controversy over what is the ‘fair return on equity,’ and it’s not just about profiteering,” he said. “We’re talking about hundreds of billions of dollars in necessary transmission investment, and that money is going to have to come from somewhere and get paid off over a certain period of time. So return on equity matters, both from the customer standpoint and the investor standpoint.”

Hempling pointed to the differences between administering general rate cases (FERC’s past approach) and formula rate cases (its current approach).

“A formula rate’s a spreadsheet, and I guess the word is that you ‘populate’ the spreadsheet with the numbers — as opposed to a general rate case, where everybody and their brother and father and mother and sister gets into the case and everybody fights over what the ultimate [regulated rate of return] should be,” Hempling said. “For years, FERC set transmission rates with a general rate case, but now it prefers to set them by formula. But just because it’s a spreadsheet that you populate across doesn’t mean that FERC goes to sleep and just asks that you include whatever you want to put in there.”

Hempling expressed his respect for FERC, calling the agency “very, very professional — even in the current political environment.” But he cautioned state commissioners about the agency’s limitations in judging the reasonableness of transmission project expenditures, another area of focus for the agency.

FERC “does not disallow costs very often. … There is a question whether an agency whose authority is transmission [has] competency in looking at alternatives,” he said, adding that FERC “does not do integrated resource planning.”

Hempling also pointed to FERC’s role in overseeing RTO transmission cost allocation.

“You’re a multistate region — which state’s customers are paying for what? And there are now a variety of court of appeals decisions and FERC decisions that allocate costs among the family members, who at conferences like this are all happy to see each other over pastries, but then they’re happy to hire very expensive lawyers to fight over who’s getting which dollars.”

Power to the States?

Hempling posed a series of hypothetical questions regarding a state’s influence over utilities before and after a decision to join an RTO. His answers, he made clear, were based on his own professional opinion, not settled law.

Can a state order its utility to join an RTO?

Yes, Hempling said. A state commission could find that a utility’s rates “will not be just and reasonable, reliability will be insufficient to satisfy state law unless the utility joins an RTO,” he said. “I also think therefore — and everything I’m saying now is subject to debate — that a state can reject a utility’s request to join, I think for the same reason.”

Can FERC order a utility to join?

“This question, along with all the others, is untested, because if FERC does have the authority to order a utility to join, then that would pre-empt a state that rejects a utility to join. That would be an inconsistency, right? You can’t put a utility between a rock and a hard place,” Hempling said.

“Do I think FERC has the authority to order a utility to join? I think they do. … And in any event, FERC has never said so,” he said. “And that’s why the joining of RTOs by utilities is opportunistic. That’s why they at least get to decide … based on their own self-interest, because FERC has not said it can order a utility to join.” But FERC has conditioned a utility’s request for merger approval on joining an RTO, he noted.

Hempling also posed the possibility of a state requiring a utility to get state permission before proposing to the RTO any new construction of transmission above a particular level. “In my legal opinion, a state can do that, but it has not been tested,” he said.

After the Fact

How can a state pursue its values after a utility joins an RTO?

Hempling noted that legal precedent precludes states from forcing a utility — including an RTO — to submit a tariff change with FERC. Still, a state can circumvent that restriction by persuading the utility or RTO to make a state-sought filing.

“The way the Federal Power Act works is this: If a utility makes a filing at FERC, and that filing satisfies the Federal Power Act standard of ‘just and reasonable’ … FERC is obligated to approve it, even if FERC has a better idea. … It’s a utility-deferential statute,” he said. “Which means if you are a state wanting to say, ‘I’ve got a better idea,’ and so you introduce at FERC a filing, FERC is going to say, ‘I like your idea a lot better, state, but the utility’s idea is just and reasonable.’”

SPP has worked around this situation through the authority granted to its Regional State Committee, which can order SPP to make a filing even if the RTO disagrees with it, Hempling said. “Now SPP can also make its own filing, and they can say, ‘We think the state’s idea is crap,’ but we file it because we agreed to file it. And what happens now is that FERC can actually choose either one. So it puts the states on equal legal footing in terms of the chances of being selected.”

Former California Public Utilities Commissioner Mike Florio, now principal of Florio Consulting, said that California legislators have asked him whether the state can direct an investor-owned utility to leave an RTO.

“My … answer is no, because … it’s a contract that FERC has approved,” Hempling replied. “And that contract is where you go to find out the authority of someone to leave. And because it’s a FERC-jurisdictional contract, a state cannot issue an order that causes a utility to act in violation of the contract. That would be pre-emptive.

“FERC wants the stability about decisions to be in FERC’s hands,” he added.

Utah Public Service Commissioner David Clark said one of his concerns about his state’s utilities joining an RTO is the cost-of-service differential between it and other states in the region — namely, California.

“I know FERC has been concerned that the RTO process maintain status quo benefits and focus on new benefits,” Hempling said. “I think FERC has not had the notion of creating enemies of the RTO process.”

Another commissioner asked: “How do we know we’re protecting our state’s interests?”

Hempling replied with a question: “What is the commonality that we’re trying to pursue through the RTO mechanism when there are so many differences? … Focus on what the commonalities are.

“I was once at a [National Association of Regulatory Utility Commissioners] meeting and there was a Midwestern commissioner who said, ‘Whoa, if we’re not preserving state regulation, what are we here for?’” Hempling said. “And I’m thinking, ‘What you’re here for is something bigger than that. You’re here for efficiencies; you’re here for the customer; you’re here for investors; you’re here for marginal values. You’re here for something. You’re not here for jurisdiction.’

“The mission is not jurisdictional preservation. It’s jurisdictional effectiveness.”