Page 1339 – RTO Insider

February 21, 2017

ERCOT Board of Directors Briefs

Potomac Economics’ Beth Garza, director of ERCOT’s Independent Market Monitor, summed up her 2016 market year-in-review as simply as she could at the Board of Directors meeting Feb. 14. “Cheap, windy and all RUCed up,” she said to laughter.

Market prices dropped to an all-time low of $24.62/MWh for load-weighted average real-time energy and $2.45/MMBtu for natural gas, down from $26.77 and $2.57, respectively. While prices were low, a 30% increase in wind energy production led to an increase in its curtailments, and reliability unit commitments almost quadrupled, from 70 “unit days” to 269.

Garza said almost a third of those RUC events are under review as potential enforcement actions primarily from generators failing to comply with ERCOT dispatch instructions or not accurately reflecting the resource’s status.

“We see evidence of uncertainty and confusion about what you’re supposed to do when you receive a RUC instruction,” she said. “Thirty percent of RUC events in 2016 had something wrong with them. That’s too much. We either have a problem with the rules or people’s understanding of the rules.”

It was the same message Garza delivered to the Technical Advisory Committee in January. (See ERCOT RUC Activity Jumps Sharply in 2016.)

“When ERCOT issues a RUC instruction, there are ways for that generator to express a preference to opt-out. ‘Yes, I will come online, but I’m forgoing any make-whole payments that might come my way’ in exchange for, ‘I get to keep all the revenue,’” she said. “Because of that mechanism, I believe the increase in RUC activity that we’re seeing is a … result of generators trying to get some assistance in making that commitment decision.”

Garza pointed out that the ERCOT market is a self-commitment market, without rules or obligations to commit in real time besides financial incentives.

“Just because you have a day-ahead award does not mean you are required to start your unit in real time. That’s very different than other markets,” she said. “That difference leads to a commitment decision that is de-centralized. Every generator is making their own decisions. ‘Does it make sense for me to start today or tomorrow evening?’

“ERCOT is in the tenuous position of sometimes trying to figure out [whether] that action will actually happen, and when do they have to step in and ensure the adequacy of the grid, which they do through RUC instructions.”

Much of that problem is expected to be resolved by a rule change approved by the board and the TAC last year and scheduled to be implemented in late June. NPR744 enables qualified scheduling entities that submit bids and offers on behalf of resource entities or load-serving entities to opt out of RUC settlement by telemetering a resource’s status during the first interval it is online and available.

When unaffiliated Director Peter Cramton suggested the problem was a procedural issue that would be corrected by the protocol change, Garza said, “That’s my hope.”

“There are myriads of individual-type situations that could continue to be problematic,” she said. “We’re working with the ERCOT 744 team to understand how it’s being implemented. I hesitate to say it will all go away, but I will continue to raise awareness of this issue.”

The 269 unit days (a unit committed for as little as an hour counts as a day) resulted in only $1.2 million in make-whole payments, which are paid for by entities that were short generation. Another $1.4 million was clawed back from generators with offers in the day-ahead market and distributed to all load, the difference being market energy prices don’t cover start-up or minimum energy costs.

Half of the payments from day-ahead offers are clawed back from generators that opt out of RUC dispatch orders. Garza said generators RUCed for a thermal constraint are often motivated to opt out because their real-time energy prices will likely exceed their operating costs. But those RUCed for a local voltage issue, which would not cause a price spike, would generally obey the RUC order to qualify for make-whole payments, she explained. The bulk of RUC activity took place in the Houston area and South Texas, two regions where infrastructure projects have recently been energized or are under construction.

Garza also said zonal price differences indicated that wind energy once trapped behind constraints is now serving load. The West zone’s increased oil and gas production activity and congestion around Houston instead of the West led to lower prices in the West, reversing recent trends.

ERCOT Releases 2016 State of the Grid Report

ERCOT has released its 2016 State of the Grid report, titled “Inside the Promise.”

The promise, the ISO said, “is to coordinate the operation of the grid and market that serve electric consumers. In 2016, ERCOT implemented new tools to help manage more renewables and upgraded aging equipment for increased functionality. ERCOT also worked closely with stakeholders to update criteria used to determine the need for new transmission projects and improvements.”

The report highlights the ISO’s demand and energy usage records set last year, new milestones for wind generation, the doubling of installed solar capacity and new lows for average wholesale market prices.

Magness Foresees Growth in Utility-scale Solar

CEO Bill Magness began his regular report to the board and members by asking, “What could be more romantic than an ERCOT board meeting on Valentine’s Day?”

Magness said the Long-Term System Assessment shows continued load growth for the ERCOT market, with every scenario indicating significant increases in utility scale solar resources that could accelerate the need for additional transmission infrastructure in West Texas. He said the falling costs of solar and its potential to replace older generation may shift the “summer resource adequacy challenge” from the traditional 4-5 p.m. window to the 8 p.m. hour.

“A lot of the best solar resources are not congruent with the best wind resources,” Magness said. “Net peak resource adequacy issues are something we have to keep an eye on. We’ll have to work on ramping issues, just like we did for wind.”

Staff and the Regional Planning Group endorsed six major transmission projects in West Texas last year, and others are under review.

The Port of Brownsville near the Mexico border, where several LNG facilities have been proposed, could be “the big wild card,” Magness said. That will require additional generation in the fast-growing Lower Rio Grande Valley or additional transmission, he said.

“We’re going to have continued challenges to meet that load,” he said.

ERCOT’s preliminary net revenues for 2016 show a $13.4 million favorable balance, Magness said. The system administration fees were up $2 million, thanks to a stronger Texas economy. Personnel costs and purchases of computer hardware and other equipment were a combined $6.2 million under budget.

However, milder weather at the start of 2017 has left ERCOT “a little behind,” Magness said. Administrative fees are already $1.4 million under budget.

According to the CEO’s operational report, ERCOT has 254 active generation-interconnection requests totaling 59,896 MW, including 26,732 MW of wind generation, as of Dec. 31. The ISO had 17,604 MW of wind capacity in commercial operation at year-end.

Another Above-Normal Texas Summer Seen

ERCOT Senior Meteorologist Chris Coleman predicted another hotter-than-normal summer in Texas this year, saying it will follow recent patterns.

“Eight or nine of the past summers have been hotter than normal,” he said. “That’s just been the trend. It would really be going out on a limb to forecast a mild summer for Texas this year.”

Using the latest information from the National Oceanic and Atmospheric Administration, Coleman said 2016 was Texas’ third warmest year on record, dating back to 1895. He said this winter has been the sixth-warmest on record, with Austin recording 17 days of 80-degree temperatures or warmer.

Still, frigid temperatures early in the year helped ERCOT set a new winter peak of 59,650 MW on Jan. 6, breaking the previous record of 49,263 MW, set in January 2016.

Coleman said there is increasing potential for a warmer-than-normal spring that will likely produce a spring load peak in May. He will issue his final spring forecast and preliminary summer forecast March 1 as part of ERCOT’s Seasonal Assessment of Resource Adequacy, but he said there’s “no reason to deviate from a warmer-than-normal spring” prediction.

He also projected a wet spring. Texas recorded its two wettest years on record, with almost 74 inches of rain, in 2015 and 2016. The rainfall ended the state’s drought and any possibility of long-term droughts into the next decade, Coleman said.

Technology Refresh on Schedule, Budget

CIO Jerry Dreyer told the board that ERCOT’s four-year effort to update its software and hardware technology — some of it dating back to the last decade — is on schedule and “on budget, or slightly below.”

The $48 million DC4 program, the ISO’s fourth data center refresh, is aimed at replacing technology at the end of its life and support, including networks, telecommunications, servers and storage. It was approved as part of ERCOT’s administrative fee request in 2015.

“Most equipment we’re running today is from the 2010 era,” Dreyer said. “You take on a lot of risk when you’re running outdated equipment. You take on compliance risk and security risk.”

Dreyer said he had no major risks and issues to report. He said 38% of the new technology has been deployed and 40% of the budget was spent through 2016. Some new technology has completed testing and is already being migrated.

Dreyer pointed out that his IT group supports three data centers, 4 million GB of stored data, more than 400 distinct applications and 1,400 servers. He said that at the same time the DC4 program is replacing 400 systems, ERCOT will also be making architectural improvements.

The project will conclude in 2019.

“The intention is to reduce the impact of an outage across multiple lines of business,” Dreyer said. “IT does not run the grid … but reliable technology is key. In order to ensure reliability at the top, we need to keep the underpinnings working as well.”

Board Approves 5 Revision Requests

The board unanimously approved four nodal protocol revision requests (NPRRs) and one Planning Guide revision request (PGRR) previously approved by the TAC. (See Revision Requests, Shadow-Price Cap Change Endorsed, ERCOT Technical Advisory Committee Briefs.)

NPRR794: Moves reporting requirements for unregistered distributed generation from the Commercial Operations Market Guide to the protocols.
NPRR800: Incorporates futures prices in calculations of collateral requirements.
NPRR805: Clarifies the criteria under which congestion revenue right (CRR) account holders can submit multi-month offers for long-term auctions. The months must be consecutive, within the period covered by the auction and during months when the account holder has ownership of the CRR.
NPRR806: Clarifies that municipalities and cooperatives not participating in ERCOT’s competitive market (non-opt-in entities, or NOIEs) have the option of accepting a refund or capacity for their pre-assigned CRR-eligible resources. The NOIEs cannot select one option for some months of the year and the other option for the remaining months.
PGRR053: Modifies the conditions proposed generating resources must meet to be included in steady state working group base cases, requiring only the data provided for full interconnection studies.

TAC Cancels February Meeting

With a “limited number” of voting items on the agenda, the TAC has canceled its Thursday meeting. The committee will resume its regular schedule March 23 before the board’s next scheduled meeting in April.

TAC Chair Adrianne Brandt told committee members to expect an email vote on a revision to the Commercial Operations Market Guide (COPMGRR044), which aligns with NPRR794.

– Tom Kleckner

February 21, 2017

SPP Eyes 75% Wind Penetration Levels

By Tom Kleckner

LITTLE ROCK, Ark. — Fresh off setting the wind penetration record for North American RTOs, SPP is setting its sights even higher.

spp wind penetration — Rew | © *RTO Insider*

The RTO’s two most recent studies of wind and other variable resources analyzed wind-penetration levels as high as 60% and found that the RTO has the potential to serve 75% of its load with wind, Operations Vice President Bruce Rew told SPP’s Variable Generation Integration Workshop on Wednesday.

But why stop there? Asked how high a penetration level SPP could handle, Casey Cathey, SPP’s manager of operations analysis and support, replied with a smile: “As high as you want.”

That’s a big change, Cathey said, recalling “we were freaking out about 20% in 2009.”

SPP set the record for wind penetration at 4:30 a.m. Feb. 12, topping out at 52.1%, with several hours also registering above 48.5%. (See related story, SPP First RTO to 50% Wind Energy Penetration Level.) The RTO has set seven wind peaks in the last 14 months, the latest coming Feb. 9 when the footprint produced 13,342 MW of wind energy.

“We’ve been studying [wind] at higher load levels than SPP’s minimum [load] at times,” Rew said. “With nukes and hydro, we could have a majority of our load being served by [non-thermal generation] using the existing system we have now.”

32 GW of Wind?

SPP currently has 87,635 MW of generating capacity, with gas (42%) and coal (31%) providing the great bulk of it. Wind accounts for 18% of the capacity (16,124 MW of nameplate generation), with hydro (4%) and nuclear (3%) trailing. An additional 32 GW of wind capacity is in the interconnection queue, along with more than 4 GW of solar.

Cathey said a “good” wind-capacity factor is around 30%, but SPP’s newest wind projects have factors of more than 50%.

“Maybe not all that 32 [GW] will be installed, but we know we’ll have more than 16” GW, he said.

Staff last week shared the results of its latest variable generation study, which looked at requirements to reliably operate at higher wind-penetration levels. Using 45% and 60% scenarios, staff analyzed transient stability, frequency response, seasonal voltage stability, seasonal load-pocket stability and five-minute ramping.

The study assumed 27,419 MW of wind generation would be in service by the end of 2019.

“I don’t that that we will hit 27 [GW] in three years, but when you see a number like this, I think there’s going to be a lot of wind coming in,” SPP’s Jason Tanner said.

“We discovered we needed additional data,” Cathey said, citing the longitude and latitude of every wind farm in the footprint as an example. “We really need a good, robust plan for handling this stuff.”

The transient stability study showed the system could handle 45% and 60% wind penetration for simulated events. But it found the SPP damping ratio criteria of 0.8% — a measure of how quickly oscillations in a system decay after a disturbance — to be very low, and out of line with the 3 to 5% used by much of the industry.

Frequency response was found to be fully compliant with NERC criteria and indicated that new and existing renewable resources can be reliably integrated at higher penetration levels. However, three of the four cases used in the voltage-stability analysis found limitations. A 2021 case at the 60% level was successful in the planning models without operation outages.

Staff determined further analysis is needed in the ramping five-year outlook to focus on the risk of forecast errors.

Recommendations

Based on the study’s results, SPP staff recommended:

Using an online voltage stability analysis tool to manage voltage fluctuations;
Having the Transmission Working Group define the requirements for a voltage stability analysis of low-load scenarios;
Asking the TWG to consider increasing the existing damping ratio (0.8%) in SPP’s voltage disturbance performance requirements;
Installing transient stability contingency screening and other tools measuring signal changes over time for next-day operational analysis;
Quantifying the risk of load and renewable forecast deviations;
Having the TWG assess the cause and impact of modes of inter-area oscillation for machines identified by the SPP study; and
Using the report’s findings as parameters for future phasor measurement unit siting.

Staff will present the study’s findings and recommendations to SPP’s Board of Directors and Markets and Operations Policy Committee in April.

“We are reliable, we are secure,” Golden Spread Electric Cooperative’s Mike Wise said. “That’s a great distinction to talk about.”

SPP’s Jay Caspary, Golden Spread Electric Cooperative’s Mike Wise | © *RTO Insider*

But when is too much wind too much? The Export Pricing Task Force found that SPP’s neighbors share the same problems in working with massive amounts of wind.

“There are things that can be changed in different areas, but there’s not a silver bullet,” Sam Loudenslager, the task force’s staff secretary, told attendees. “We’re not alone in this. There’s a lot of wind around us, and we’re all going to be competing to manage it.”

So far, the task force has focused primarily on educating members and other stakeholders, Loudenslager said. He said the group is planning to provide market and Tariff changes for consideration to the Strategic Planning Committee in April or May.

Staff described several market mechanisms it is pondering to deal with the issue, including adopting coordinated transaction scheduling (CTS), which reduces uneconomic flows across RTO borders by allowing traders to submit “price differential” bids that would clear when the price difference between the regions exceeds a threshold set by the bidder.

NYISO has been using CTS with PJM since November 2014 and began it with ISO-NE in December. PJM and MISO plan to launch CTS later this year. (See “MISO-PJM Coordinated Transaction Scheduling Delayed,” MISO Market Subcommittee Briefs.)

Staff is also evaluating RTO-to-RTO energy transfers similar to the CTS and market-to-market processes, multiday economic commitments, and ramp products, among others, as possible solutions.

February 21, 2017

Overheard at NARUC Winter Meeting

WASHINGTON — A record 1,600 people attended the National Association of Regulatory Utility Commissioners’ winter meetings last week, where speculation about the Trump administration’s energy policies was Topic A. Here’s some of what we heard.

Infrastructure Bill Must Wait its Turn, House Transportation Chief Says

NARUC clean power planNARUC clean power plan — Shuster | © *RTO Insider*

Rep. Bill Shuster (R-Pa.), chairman of the House Transportation and Infrastructure Committee, told NARUC’s General Session on Tuesday that he’s excited by the Trump administration’s call for expanded infrastructure spending but that a proposal won’t come until after Congress replaces the Affordable Care Act and develops a plan for overhauling corporate taxes.

“You’re not going to see the infrastructure package in the next month or two,” Shuster said.

“The order of things will be replacing Obamacare. … Tax reform will go next, and within that we have to figure out how to pay for infrastructure. It’s not all going to be federal dollars.

“One of our goals on the Republican side is to lower tax rates for corporations so they can keep more of their own money. So when it comes to pipelines and electric grid and broadband, let those corporations keep more of their money and then let’s get the regulatory barriers out of their way so that they can go build.”

Increasing the debt, he added, “is not an option in this Congress.”

Shuster said public-private partnerships can contribute but that the concept is “not the silver bullet … that some folks claim it is,” feasible only in instances in which private businesses can earn a return on their investments.

Uncertainty over Clean Power Plan Remains

NARUC clean power plan — LaFleur | © *RTO Insider*

Although the D.C. Circuit Court of Appeals is expected to rule soon on legal challenges to EPA’s Clean Power Plan, the ruling won’t be the last word, meaning RTOs and state policymakers will be facing uncertainty for the foreseeable future.

“If its upheld, then I think we’ll be looking to the new administration to make any proposals for change that they make and put them through the regulatory process,” acting FERC Chairman Cheryl LaFleur said. “It seems they’re going to make a change, but I am not privy to what it is.”

Arkansas Public Service Commissioner Ted Thomas noted that under the plan, the tougher emission targets — and increased costs — would hit in the second half of the next decade.

“The election didn’t change all that much about carbon risk,” he said. “If you’re saying, ‘OK, new administration, I don’t have to worry about carbon anymore,’ you might be making a mistake.

“Of course the elections are decided on issues non-energy related. We’re kind of like the flea that rides on the dog. The dog goes in the mud; we go in the mud with it. And if the next three years are like the last three weeks, we might be wishing we had the Clean Power Plan. There is real risk of federal policy that we deal with. We do that all the time. We’re state policymakers and federal policy takers.”

Crane Presses Case for Nukes, Calls for Unifying Environmental and Energy Policies

Exelon CEO Chris Crane agreed with NARUC President Robert Powelson, who said he had never seen a “more dynamic phase” in the electric industry.

“It’s a huge, huge issue to know where public policy is going to drive us,” Crane said during a panel discussion with leaders from the water, natural gas and telecommunications industries moderated by Powelson. “One of the more reliable baseload generating assets in the country, the nuclear assets, [face] significant challenges with current market design.”

Last year, officials in Illinois and New York approved controversial rescue plans for Exelon’s nuclear plants in their states. The zero-emission credit programs, which are being challenged in court and before FERC, recognized nuclear’s carbon-free production and the plants’ jobs and tax payments. (See IPPs File Challenge to Illinois Nuclear Subsidies.)

“This country for too long has separated an environmental policy from an energy policy, and [conflict between federal and state policies] has made it very difficult for markets to be formed efficiently and made it very difficult for predictability of investments going forward,” he said. “The leadership at the federal level [should] either come up with a common policy or get out of the way. Have the states be allowed to work with the RTOs and design the markets of state desires. The states we serve want affordable, reliable [energy], but they also want clean power. And how … you build a market signal around that to adequately compensate all the generators in the stack is very important.” (See related story, LaFleur Plans Tech Conference on State Generator Supports.)

He remained focused on the nuclear fleet, calling them “solid baseload units” and noted that they do not experience the issues that caused outages for 22% of PJM’s generation capacity during 2014’s extreme cold snap known as the polar vortex. Exelon’s nuclear units last year had a 95% capacity factor, he said.

“Renewables are an important part of the stack and they should continue to be part of the stack, but we need to look at defining outcomes. If the outcome is a higher-reliability, diverse fuel stack, then how do you create a market design that compensates for that?” he said. “It’s whatever the outcome is versus pitting technologies against technologies.”

He pointed to NO_x, SO_x and mercury emissions standards as successful governmental regulation. “It said, ‘here, fix your stack and clean up the air.’ The market took care of the rest. Some plants didn’t make it, some plants were built, some plants were modified,” he said. “Hopefully, with some clarity coming from this administration, some clarity coming from FERC, the states and the RTOs can do what they need to design a reliable, affordable and — where they want it — a clean stack.”

– Rich Heidorn Jr. and Rory D. Sweeney

February 21, 2017

Entergy Beats Expectations Despite 80% Drop in Earnings

By Tom Kleckner

Entergy reported an 80% drop in 2016 fourth-quarter earnings, but the company soothed investors by beating analysts’ expectations and focusing on the wind-down of its merchant nuclear energy business.

The New Orleans-based corporation said Wednesday its fourth-quarter operational earnings were $55.5 million ($0.31/share), as compared to $282.6 million ($1.58/share) in 2015. That still beat analysts’ projections of 11 to 13 cents/share.

Entergy’s CFO Drew Marsh attributed the as-reported $9.88/share loss to previously disclosed impairment charges and “special items” related to the sale or closing of Entergy Wholesale Commodities’ (EWC) nuclear plants. In recent months, the corporation has announced plans to close or sell the business’s five nuclear units. (See Entergy, Consumers Announce Closure of Palisades Nuke and Entergy to Shut Down Indian Point by 2021.)

entergy earnings nuclear plants — Entergy announced in December that it will shut down the Palisades nuclear plant in Michigan in 2018. | *Nuclear Regulatory Commission*

Marsh also reminded financial analysts during a conference call that 2015’s quarterly earnings results included “significant” income tax benefits related to the combination of two Louisiana operating companies.

Entergy CEO Leo Denault called 2016 a “pivotal year for our company,” saying it had achieved a “critical milestone” in shutting down EWC and eliminating “the risk associated with the merchant power business,” which has been hurt by low energy prices and increased operating costs.

“We have finalized plans … through a deliberate, planned and orderly process to cease all merchant nuclear operations by 2021,” Denault said. “I think this year will probably be a negative cash flow year because we have three refueling outages in the business.”

Denault said as its merchant nuclear plants “sequentially go away,” Entergy will continue “rightsizing” the organization, which began with its decision to shut down Vermont Yankee in 2014.

The company noted Moody’s had placed the corporation under review for a potential credit upgrade and that Standard & Poor’s had revised its outlook to “positive” from “stable.”

Entergy also reported year-end earnings of $1.27 billion ($7.11/share), beating Zacks’ consensus estimate of $6.83/share. Investors responded by driving Entergy’s share price to $73.55 at Friday’s close, up $2.59/share since Wednesday’s open.

The company affirmed its guidance for 2017 at $4.75 to $5.35/share, saying it expects positive rate cases for its various operating companies.

February 21, 2017

Pruitt Begins Hostile Takeover at EPA

By Rich Heidorn Jr.

WASHINGTON — EPA Administrator Scott Pruitt will address agency workers Tuesday in a bid to convince them he is not their enemy, despite having repeatedly sued the agency as Oklahoma attorney general.

scott pruitt EPA — Sen. Ed Markey (D-Mass.) was among the Democrats who criticized Oklahoma Attorney General Scott Pruitt during an all-night session before Pruitt’s confirmation as EPA administrator.

Pruitt was sworn in by Supreme Court Justice Samuel Alito on Friday after the Senate voted 52-46 to confirm him. He was supported by all Republicans except Sen. Susan Collins of Maine. Every Democratic senator except two — Sens. Joe Manchin of West Virginia and Heidi Heitkamp of North Dakota, both from coal-producing states — opposed him.

The vote came after Democrats argued on the Senate floor overnight Thursday in opposition, saying action should be delayed until Oklahoma officials release emails detailing Pruitt’s communications with oil and gas companies during his tenure as attorney general.

Democrats criticized Pruitt’s campaign contributions from the oil and gas industry and his 14 lawsuits against EPA as attorney general, including challenges to the agency’s Clean Power Plan, Cross State Air Pollution Rule, the Mercury and Air Toxics Standards, regional haze rule and emission regulations on new power plants.

‘False Paradigm’

At his confirmation hearing in January, Pruitt said he will seek only to ensure predictable regulation that respects states’ jurisdiction. He said he would seek to end a “false paradigm that if you’re pro-energy, you’re against the environment.” (See Dems Unmoved by EPA Pick’s Charm Offensive.)

Pruitt rejected calls that he recuse himself as EPA administrator from any lawsuits he filed as attorney general, saying said he would consult with EPA’s ethics counsel on a case-by-case basis.

He defended letters he sent to EPA and other federal officials — on state government stationary and signed by him — that had been authored by oil and gas companies. He insisted he was “representing the interests of the people of Oklahoma,” noting that the oil and gas industry is responsible for one-quarter of the state’s budget.

Last week, an Oklahoma judge ordered Pruitt to release thousands of emails related to his communication with the oil, gas and coal industries. The judge ruled in favor of the Center for Media and Democracy, which has been seeking the correspondence under public records laws for more than two years.

Hostile Work Environment?

Pruitt’s plans for the agency are certain to be met with skepticism, if not hostility, by many in the EPA bureaucracy.

Last Monday, about 300 people, including dozens of EPA employees, held a lunch hour rally outside the agency’s Chicago regional headquarters in opposition to Pruitt’s appointment.

In addition, more than 400 former EPA officials signed a letter to Congress opposing Pruitt’s confirmation.

“Our perspective is not partisan. Having served under both Republican and Democratic presidents, we recognize each new administration’s right to pursue different policies within the parameters of existing law and to ask Congress to change the laws that protect public health and the environment as it sees fit,” they wrote. “However, every EPA administrator has a fundamental obligation to act in the public’s interest based on current law and the best available science. Mr. Pruitt’s record raises serious questions about whose interests he has served to date and whether he agrees with the longstanding tenets of U.S. environmental law.”

As attorney general, they said, Pruitt had “shown no interest in enforcing environmental laws,” noting that while he issued more than 50 press releases celebrating lawsuits to overturn EPA rules, he issued none referring “to any action he has taken to enforce environmental laws or to actually reduce pollution.”

“We are most concerned about Mr. Pruitt’s reluctance to accept and act on the strong scientific consensus on climate change,” they added.

What’s Next for CPP?

epa democrat boycott scott pruitt — Pruitt | © *RTO Insider*

Inside EPA reported last week that President Trump is planning to attend a swearing-in ceremony for Pruitt at agency headquarters, where the president will sign executive orders.

The Washington Post reported Monday that one executive order will direct EPA to rewrite the Clean Power Plan and the Interior Department’s Bureau of Land Management (BLM) to eliminate a moratorium on coal leasing on federal lands.

A second order will direct EPA and the Army Corps of Engineers to rewrite the 2015 Waters of the United States rule, which gives the federal government authority over wetlands, rivers and streams that feed into major water bodies. Trump signed legislation last week undoing the Stream Protection Rule finalized by the Office of Surface Mining in December, which prohibited coal mines from dumping waste in waterways.

Pruitt, who led a legal fight by states against the Clean Power Plan, told the Senate Environment and Public Works Committee that climate change is real but that the impact of human activities and how to fix it are the subject of “continued debate and dialogue.”

Pruitt acknowledged the Supreme Court’s finding in Massachusetts v. EPA that carbon dioxide was a pollutant under the Clean Air Act. “I think the court has spoken very emphatically about this issue, and the EPA has a legal obligation to respond,” he said.

He said he challenged the CPP because the agency created emission limits that coal-fired generators can’t meet — thus requiring a switch to other generation sources and exceeding its authority to regulate “inside the fence line.”

The D.C. Circuit Court of Appeals, which heard arguments on the challenges to the CPP in September, has yet to issue a ruling. If the rule is ultimately upheld — an appeal to the Supreme Court is likely — it will not be a simple matter to undo. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)

“Decades of law, much of it created by conservatives’ judicial heroes, requires presidents and agencies to abide by the rule of law and justify regulatory reversals. They have to take a hard look at science and other underlying facts,” Georgetown University Law professor William W. Buzbee wrote in December.

February 21, 2017

Overheard at the 3rd Annual Energy Storage Policy Forum

WASHINGTON — Nearly 200 energy policy and market experts gathered at the National Press Club on Wednesday for the Energy Storage Association’s 3rd annual Energy Storage Policy Forum. Here’s some of what we heard.

Storage in the States

Several state regulators spoke at the conference, after having just gone through what Washington Utilities and Transportation Commissioner Phil Jones called “NARUC hell,” referring to the winter meetings of the National Association of Regulatory Utility Commissioners.

The regulators spoke about how they view their role in setting policies on energy storage and how they communicate with elected officials about the technical aspects of energy markets and technology.

The Washington UTC has been working on a policy statement on modeling energy storage through the integrated resource planning process. Jones said the statement, which he noted is short of a rulemaking, will be released in about two weeks.

The commission has “been a little bit reluctant to do too much in storage, and certainly not a mandate, without legislative blessing, if you will.” But while the commission defers to the State Legislature and Gov. Jay Inslee to make energy policy, Jones said that he emphasizes to them the state’s need to stay ahead of the curve — specifically California’s duck curve. “Unless Washington state acts, California’s duck curve … is going to overrun us,” he said, referring to the state’s drop in net load during the day because of rooftop solar and its sudden increase after the sun sets.

The increase in intermittent resources in other states in the Western Interconnection puts pressure on Washington’s grid. “Storage is certainly a solution to this,” Jones said.

The Arizona Corporation Commission — one of about 10 state regulatory bodies elected rather than appointed — is less deferential, said Commissioner Doug Little. “We are the energy policymaking body in Arizona,” he said. “We certainly solicit feedback from the governor’s office and the legislature, but they … rely on us to take a policy leadership role.”

Like Jones, Little said his commission also spends a lot of time educating Arizona legislators about the effects of California’s energy dynamics on the state. The economic benefits CAISO’s Energy Imbalance Market provides ratepayers “gets their attention pretty quickly,” he said.

Will Lauwers, emerging technology director for the Massachusetts Department of Energy Resources, said that the department must “take the ratepayer benefit as our primary cause and consideration” in its development of policy. He said the department also understands that, as part of ISO-NE, the state’s policies will affect other states in the RTO.

Lauwers said Gov. Charlie Baker has been extremely supportive of storage, highlighting the administration’s $10 million Energy Storage Initiative and recent clean energy legislation that authorized the department to set a storage resource procurement goal.

That legislation made Massachusetts the third state in the country to allow its regulators to set such a goal. The first was California, where regulators in 2013 set a target of 1.325 GW by 2020. (Oregon was the second.)

California Public Utilities Commissioner Carla Peterman said the commission originally came up with a number less than 1 GW, but she said a gigawatt “just sounded better.”

She recalled she said, “‘Let’s put out a number and see if it sticks.’ And eventually it did. So sometimes, you know, that’s how the sausage is made,” prompting laughter from the audience. “You use the best analytics that you can, but ultimately you put something out and then if no one laughs … then you know you might as well move forward.”

Peterman was asked how fast other states should move on storage.

“Very quickly,” she replied. “I can’t emphasize enough that there are so many different things you can do. Just requiring the utilities to do some evaluation is a big step.”

Bay Makes an Appearance

Many at the conference expressed their enthusiasm for the Notice of Proposed Rulemaking that FERC issued in November requiring RTOs to allow storage resources above 100 kW to participate in their energy, capacity and ancillary services markets. (See FERC Rule Would Boost Energy Storage, DER.)

Bay (left) and Jason Burwen, ESA policy and advocacy director | © *RTO Insider*

On hand to fete the staffers in attendance who worked on the NOPR was former Chairman Norman Bay, who asked them to stand and be recognized before a discussion with Jason Burwen, policy and advocacy director of the ESA.

“Storage clearly has unique characteristics,” Bay said. “It’s not like traditional resources in the markets. Traditional resources fell into one category or another. … Storage can play in” generation, load, transmission and distribution. “So it seems to me that the market rules have got to recognize those unique characteristics.”

RTOs: We Support Storage

Representatives from four grid operators in the Eastern Interconnection said their markets offer ways for energy storage resources to participate, even as FERC in its NOPR said that some existing rules are unfair to storage.

Left to right: Levitt; Bladen; Christopher Parent, ISO-NE director of market development and DeSocio | © *RTO Insider*

“The notion that energy storage should be able to participate in all markets is one that PJM supports,” said Andrew Levitt, PJM senior market strategist. “That is, from my perspective, a basic mission of PJM: opening all markets to resources that are technically capable of serving those markets.”

“In MISO’s case, we had some anachronistic things in our Tariff that we’re going to be getting rid of and, in fact, had been planning to for some time,” said Jeff Bladen, MISO executive director of market services. But even before FERC’s recent order in response to a complaint by Indianapolis Power and Light, “we had many paths for storage to participate in the markets.”

FERC, however, concluded that MISO prevents storage from fully participating, ordering it to revise its Tariff. In the event that MISO’s compliance filing conflicts with a final ruling on storage participation, the RTO would have to make further revisions, the commission said. (See MISO Ordered to Change Storage Rules Following IPL Complaint.)

Burwen pushed back, pointing out FERC’s NOPR was premised on the fact that there are barriers to participation for storage. He asked what RTOs need to change in order to recognize storage resources’ unique attributes.

“What we really need from you folks is help,” said Michael DeSocio, NYISO senior manager of market design. “We need your help to figure out what are these parameters that are missing, that are necessary.”

– Michael Brooks

February 21, 2017

MISO Endorses 2 Michigan Projects for Expedited Review

MISO is recommending two of three Michigan projects requested for expedited review be approved before its 2017 Transmission Expansion Plan.

miso michigan transmission expansion plan — METC Project Map | *MISO*

The RTO recommended that transmission developer Michigan Electric Transmission Co. (METC), an ITC Holdings subsidiary, move ahead with a new $12 million, 120-kV substation and 2 miles of new double-circuit 120-kV structures in east Michigan, and a new $6.6 million, 120-kV station to serve 5 MW of new DTE Energy load in southeast Michigan.

In submitting the request, METC had argued that waiting until December 2017 to get regular MTEP approval did not allow enough time to support the projects’ early 2018 planned in-service dates. (See “Four Expedited Review Projects Under MISO Inspection,” MISO Planning Advisory Committee Briefs.)

After an independent study and a Technical Study Task Force review, MISO agreed.

A third project, a 138-kV station to serve 35 MW of new Consumers Energy load in western Michigan, was withdrawn from expedited review after Consumers delayed the needed in-service date to Jan. 1, 2020, because of a request from the load customer. The project will move into the normal MTEP 17 cycle for evaluation.

— Amanda Durish Cook

February 21, 2017

New Jersey Went All in on Solar, but was it a Good Bet?

By Rory D. Sweeney

NEW BRUNSWICK, N.J. — A panel of experts discussing New Jersey’s energy future agreed Wednesday that the Garden State has made great strides on installing renewable generation resources but differed on whether the progress is sustainable.

“We’re at where we thought we’d be in 2028 [on the state’s renewable portfolio standard], but at a substantial cost,” said Stefanie Brand, the director of New Jersey’s Division of Rate Counsel.

A study commissioned by the rate counsel found that the state’s current solar RPS will cost ratepayers $5.2 billion through 2028 (net present value). A bill proposed last year would ramp up the state’s RPS faster, adding another $276 million (NPV) in costs, the advocate told legislators last year.

new jersey solar — Gabel | © *RTO Insider*

Steven Gabel of Gabel Associates, an industry consulting firm, pointed to the “saw-tooth” nature of the clearing prices from recent PJM Base Residual Auctions to argue that the RTO’s price signals “aren’t doing the job” to incentivize generation development. The grid operator’s implementation of Capacity Performance was a “titanic event” to increase reliability, Gabel said, yet clearing prices in the auctions since then have provided ambiguous signals.

Aggregating winter and summer resources won’t solve the issues, either, he said, because the payments go to the resource that gets used instead of being distributed to both.

The discussion was hosted by Rutgers University’s Center for Energy, Economic & Environmental Policy, part of the Edward J. Bloustein School of Planning and Public Policy.

Andrew Hendry, the president of the New Jersey Utilities Association, prognosticated on the state’s potential return to the Regional Greenhouse Gas Initiative following the 2017 gubernatorial election. Republican Gov. Chris Christie pulled the state from RGGI in 2011.

“I think it’s very likely that if a Democrat wins, we’re going to be back in RGGI,” he said.

Gabel said state Sen. Bob Smith, a Democrat who chairs the Environment and Energy Committee, has a “big appetite” and “pent-up demand” for energy reform in the state.

He said state policy has not changed much from the state’s 1980s-era energy plan. “For 32 years, we’ve been talking about it,” he said. “We have to turn this around. … For me, the needle points more toward ‘let the market sort this out.’”

Brand was skeptical of a market-driven focus, saying that’s why the state’s solar renewable energy credits (SRECs) are being sold for $250 when they’re much cheaper in other states. Solar developers are receiving “windfall profits” because “we’re over-incenting,” she said.

New Jersey has the second highest subsidies for rooftop solar, behind California, she said. By comparison, North Carolina and Arizona are growing solar capacity but with subsidies that are “more in line” with other states.

“The fact is I don’t think we need $250 SRECs,” she said. “I don’t buy it. … We get less solar, not more.”

Gabel said that’s what the market will bear. “We moved away from an administrative structure for SRECs to a market.”

Brand cautioned that it won’t be long before ratepayers can’t afford to purchase electricity. “Our prices are high and they’re very volatile,” she said. “Not all good things deserve a subsidy.”

She included nuclear in that, noting that PJM’s analysis on Artificial Island’s three reactors found that Delaware stands to receive the most benefit from planned transmission upgrades for the nuclear complex. “Much of the electricity that comes out of these plants doesn’t go to New Jersey,” she said. “Before we subsidize these plants, we have to figure out if we’re subsidizing Delaware.”

Left to right: Hendry, Gabel and Brand | © *RTO Insider*

The Garden State remains heavily dependent upon its nuclear fleet, receiving 56% of its power from such sources, she acknowledged. “I don’t think we’ll see any offshore wind in the immediate short term,” she added.

Hendry said that data analytics will be an important part of the state’s energy future, but Brand argued that advanced meters aren’t helping consumers. “The primary benefit you get in advanced meters is lost jobs” because companies need to employ less people as meter readers, she said.

“We cannot afford to give everybody net metering” because it reduces the number of customers who pay for social-benefit charges, like low-income subsidies, she said. “We have to make sure everybody has access to heat, electricity. … Everybody has to pay their own way.”

She also questioned the FERC-approved rate adder utilities get for joining PJM: “At this point, it’s a free 50 basis points.”

February 21, 2017

PGE Sees Future Growth Tied to EVs

By Robert Mullin

Pacific Gas and Electric will continue to be a “critical partner” in California’s efforts to meet its ambitious greenhouse gas reduction goals despite “uncertainty at the federal level,” the company’s top executive said last week.

The company’s key area of focus in that effort: capitalizing on the electrification of transportation as the state strives to put 1.5 million electric vehicles on the road by 2025.

PG&E electric vehicles — PG&E is positioning itself to capitalize on California’s push to reduce greenhouse gas emissions through increased adoption of electric vehicles. | *City of Pasadena*

“With the transportation sector accounting for about 40% of California’s greenhouse gas emissions, we expect to play a significant role in helping the state address these emissions by investing in the infrastructure necessary to enable electric vehicle adoption,” PG&E CEO Tony Earley said during a Feb. 16 call to discuss fourth-quarter earnings.

The utility earned $692 million during the fourth quarter of 2016, compared with $134 million during the same period a year earlier. Full-year earnings came in at $1.39 billion, up 60% from the previous year. Operating revenues for the year increased 5% to nearly $17.67 billion on rising electric (+2%) and natural gas sales (+20%), largely the result of rate increases over the previous year. The company also booked an additional $325 million in out-of-period gas revenues based on a 2016 California Public Utilities Commission decision related to a previous under-collection of gas transmission fees.

Earley noted that the PUC in December authorized PG&E to spend $130 million over the next three years to build the infrastructure to support about 7,500 automobile charging stations. The company last month filed an additional request to lay out $250 million to support the charging of medium- and heavy-duty vehicles, such as transit buses.

“We are confident in our ability to execute on a strong growth plan through continued investments in upgrading and modernizing our system, as we help the state achieve its clean energy goals,” said PG&E electric division President Geisha Williams, who will assume the company’s top spot later this year upon Earley’s retirement.

PG&E’s electric transmission business is coming under pressure from slow load growth across the state, which has reduced the need for new transmission projects, according to CFO Jason Wells.

But the company said the reduction in incremental transmission projects should be offset by spending to interconnect new utility-scale renewable projects developed to meet California’s 50% by 2030 renewable portfolio standard — helping to keep 2018 and 2019 outlays equal to current levels.

Wells roughly quantified how the increased use of electric vehicles could help the utility counter the trend of decreasing retail loads stemming from energy efficiency measures and the wider adoption of rooftop solar. A plug-in electric car consumes about half the electricity of an average household.

“So you can think of for every two electric vehicles we add to the system, essentially we’re offsetting the decline that we see from distributed generation,” Wells said.

Based on state agency estimates, the utility expects to have about 600,000 electric vehicles and 150,000 charging stations within its service area by 2025, Wells added. There are currently about 5,000 public chargers in the region.

Williams said PG&E should be somewhat buffered from the expected statewide growth of community choice aggregators (CCAs), which directly draw customers away from the state’s three investor-owned utilities.

“Our service area is made up of many small municipalities and counties,” Williams said. “So, in our case, we think that that transition to higher levels of CCA adoption are going to take a little bit longer.”

But PG&E is still preparing for that potential shift by maintaining a “flexible” energy portfolio, according to Williams. The utility procures more than half of its energy supplies from third parties under long-term agreements, 40% of which represent output the company is under no obligation to take after 2021.

“So, we believe, we’ve got the triggers that we need to be able to meet the load over time,” Williams said.

February 21, 2017

PJM Markets and Reliability and Members Committees Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees meetings 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 in RTO Insider.

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 (9:10-9:30)

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

A. Manual 22: Generator Resource Performance. Revisions developed as part of a periodic review of the manual.

B. Manual 27: Open Access Transmission Tariff Accounting and Manual 13: Emergency Operations. Revisions will add Mid-Atlantic Interstate Transmission Co. as a transmission owner in PJM. MAIT is a new subsidiary of FirstEnergy that owns and operates the company’s transmission assets in the Met-Ed and Penelec utility territories. (See NJ Opposition Derails FirstEnergy’s Tx Reorganization — but not Projects.)

3. FERC Order 825 – Shortage Pricing (9:30-9:50)

Members will be asked to endorse the proposed shortage pricing and operating reserve demand curve solution and associated manual revisions. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)

4. Transmission Substation Equipment in FERC Order 1000 (9:50-10:05)

Members will be asked to endorse proposed a Regional Transmission Expansion Plan process changes related to the treatment of transmission substation equipment under FERC Order 1000, and associated Operating Agreement revisions. (See “Endorsements Sail Through by acclamation,” PJM Planning Committee and TEAC Briefs.)

5. Draft Pseudo-Tie Agreements (10:05-10:20)

Members will be asked to endorse a pro forma pseudo-tie agreement and a reimbursement agreement for pseudo-ties into PJM, along with related Tariff and Operating Agreement revisions. (See “Committee Endorsements,” PJM Operating Committee Briefs.)

6. Replacement Capacity (10:20-10:40)

Members will be asked to endorse a proposed problem statement and issue charge regarding procurement of replacement capacity in the Incremental Auctions. (See “PJM Has No Objection to IMM’s ‘Paper Capacity’ Report,” PJM Market Implementation Committee Briefs.)

Members Committee

Consent Agenda (1:20-1:25)

Members will be asked to endorse:

B. Tariff, Operating Agreement and Reliability Assurance Agreement revisions to clean up definitions.

C. Revisions to the PJM Tariff regarding operating parameters.

1. Transmission Substation Equipment in FERC Order 1000 (1:25-1:45)

Members will be asked to endorse changes to RTEP processes. See MRC item 4, above.

2. Energy Market Uplift Senior Task Force (EMUSTF) (1:45-2:15)

Members will be asked to endorse proposed Phase 1 and Phase 2 proposals endorsed by the MRC in January. (See “Work on Uplift Moves Forward Despite NOPR,” PJM Markets and Reliability and Members Committees Briefs.)

– Rory D. Sweeney