Pacific Gas and Electric’s second-quarter profits fell sharply because of a series of one-time costs — most related to the company’s natural gas business.
Still, the company sees bright prospects for its electricity business as California moves to aggressively reduce greenhouse gas emissions and increase reliance on renewable generation.
The company reported net income of $206 million, down from $402 million a year earlier. Earnings per share fell from 83 cents to 42 cents. Adjusted earnings came in at 66 cents, far short of the average analyst estimate of 93 cents.
Photo Source: PG&E
The one-time items included penalty costs stemming from the San Bruno pipeline explosion in September 2010. The company’s federal criminal trial for the incident went to a jury last week.
“We continue to believe that no PG&E employee knowingly and willfully violated the law,” CEO Tony Earley said during a call with analysts to discuss earnings. “But now it’s in the hands of the jury.”
Earley said mandates stemming from last year’s passage of California SB 350 “will influence both our procurement needs and investment opportunities.” The law raised the state’s renewable portfolio standard to 50% by 2030 and imposed increased energy efficiency requirements for buildings.
Efficiency gains will translate into declining energy demand in PG&E’s service area, Earley noted. The company also expects to lose some customers to community choice aggregators, which could seek to procure electricity from other suppliers.
PG&E will also have to cope with the rapid adoption of residential rooftop solar in California.
“We’ll have to continue to upgrade the distribution grid to handle increasing amounts of distributed generation,” Earley said.
On top of that, the company will require new and upgraded transmission lines to support the utility-scale renewables necessary to meet the state’s 50% RPS. The company is seeking an additional $100 million in capital expenditures through its 2018 transmission owner rate case filed with FERC last week, Earley said.
In April, PG&E established a strategic alliance with TransCanyon — a joint venture between Berkshire Hathaway Energy and Pinnacle West — to pursue competitive transmission projects solicited by CAISO. The arrangement “will allow us to compete in not just our service area, but the broader CAISO,” PG&E President Geisha Williams said.
“We’re well positioned to help drive California’s clean energy future through sustained investment,” Earley said.
NASHVILLE, Tenn. — Regulators and utility officials commiserated over the difficulty in overcoming public opposition to large energy infrastructure projects during a panel discussion at the National Association of Regulatory Utility Commissioners summer conference last week. About 1,000 people attended.
Iowa Utilities Board member Libby Jacobs, who moderated the session, said she had become the target of vitriol following her vote in June approving the Dakota Access Pipeline, which will carry crude oil from North Dakota’s Bakken field through South Dakota and Iowa to Illinois. The week before the NARUC meeting, an activist group staged a street theater performance outside IUB offices called “In Bed with the Bakken,” in which one protester portrayed Gov. Terry Branstad bottle-feeding an oil pipe.
“I’m also very familiar with the anti-infrastructure protesters,” offered FERC Commissioner Cheryl LaFleur from the audience, referring to the monthly protests at FERC open meetings.
Opposition to infrastructure projects has been a challenge “since I’ve been in the industry,” she continued. “But I sense something different happening.
“I’m a little concerned … with the growing thought out there that maybe we don’t need any infrastructure at all,” LaFleur said. “‘We’re just going to close what we have and replace it with everything distributed.’”
Jacobs, a former corporate communications executive, said protesters have benefited from social media as an organizing tool.
Aakash Chandarana, regional vice president of rates and regulatory affairs for Xcel Energy’s Northern States Power, said utilities need to do a better job of educating their customers.
“Often times we as a utility are trying to talk to our customers at the most intense period in our relationship — either through storms or during a rate case or something like that. … We have to approach our customers at a period of time where maybe there isn’t as much emotion.”
Robert Kenney, vice president of state regulatory relations for Pacific Gas and Electric, agreed. “I’m not sure that utilities or regulators have done [a good] job in helping customers understand why certain investments need to be made,” he said.
He lamented the utility’s decision, announced in June, to retire the Diablo Canyon nuclear plant when its current operating licenses expire in 2024 and 2025, noting it “has been a source of greenhouse gas-free energy for the last 30-some odd years.” (See PG&E to Shut Down Diablo Canyon, California’s Last Nuclear Plant.)
“The political climate in California was such that being able to relicense that beyond 2024 and 2025 made it a huge challenge,” Kenney continued. “I say that as an example of the fact that we have technologies that will allow us to meet climate goals but then you have conflicting political goals that prohibit the running of nuclear generating facilities.”
Exelon CEO Talks Capital Allocations, New Products
NARUC President Travis Kavulla conducted an interview with Exelon CEO Chris Crane that touched on subjects from capital allocations and new utility products to the struggles of its nuclear generation fleet and cybersecurity.
Kavulla asked Crane whether Exelon, which now operates in five states and D.C. following its acquisition of Pepco Holdings Inc., favors states with higher returns on equity in determining where to allocate capital.
Crane said each of the company’s six utilities maintains its own balance sheet and cash flow and that the company makes investments based on reliability requirements.
“It does at times require equity infusion from the parent. PHI right now, and for the next five years, will have equity infusions … on an annual basis.
“We don’t find that as a conflict,” Crane said. “We’ve never had to make a decision that a dollar goes into one jurisdiction versus another … there is enough capital and our balance sheets are strong.”
Crane said Exelon’s decisions on what “utility of the future” products to offer is based on “understanding what is a trend and what is a fad.”
“We have to differentiate. Technology is changing faster than it ever has in our industry,” Crane said. “We have to watch what the consumer wants versus what the commercial side wants to sell.”
Commercial Customers Will Go it Alone to Meet Sustainability Goals
Commercial customers would like utilities’ help in meeting their sustainability goals but “will pursue their goals with or without” them, according to the Critical Consumer Issues Forum’s latest report released last week.
More than 80 state regulators, consumer advocates and utility representatives took part in meetings that resulted in the report, developing “consensus principles,” such as providing flexibility to consumers seeking new technologies and products while protecting nonparticipating consumers from cost shifts.
To be responsive to customers, Arizona Public Service will initiate some innovative projects without getting regulatory approval first, said Barbara Lockwood, vice president of regulation.
“We have taken the approach that there are some projects that we’re going to embark on and we’re not going to ask the commission [in advance]. We’re going to go do it and then we’re going to ask for recovery of those costs. We’re taking some risk that we never took in the past,” she said.
Lockwood cited a 25-MW microgrid the utility is building with the U.S. Navy at Marine Corps Air Station Yuma. The microgrid’s diesel generator can provide peak power to APS customers during normal operating conditions and is large enough to power all base operations during a grid disturbance. “We didn’t seek preapproval for that project,” Lockwood said. “It was important to move quickly.”
Federal-State Battle over Plains & Eastern Transmission Line
Jordan Wimpy, an attorney representing landowners opposed to Clean Line Energy Partners’ Plains & Eastern transmission line, said he is likely to file a court challenge seeking to block the Department of Energy’s record of decision supporting the project. “We are prepared to file and we are moving in that direction,” Wimpy said.
The department said in March that it would partner with Clean Line on the $2.5 billion, 700-mile HVDC transmission project, which would deliver 4,000 MW of wind power from the Oklahoma Panhandle to MISO and the Tennessee Valley Authority. The department acted after Clean Line was unable to win approval from Arkansas regulators. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.)
Mark Bridgers, a principal with Continuum Capital, a Raleigh, N.C., investment banking advisory firm, presented a forecast indicating utilities need to add 50,000 new transmission and distribution workers. By 2018, Bridgers said, all of New England, much of the Mid-Atlantic and several Western and Midwest states will face shortages in T&D workers.
Bridgers gave a plug to the Underground Construction Workforce Alliance, which is building a coalition of industry associations, unions, suppliers, engineers, contractors and utilities to develop training programs and regulatory approaches to develop the workforce required.
NASHVILLE, Tenn. — PJM’s Capacity Performance rules got little love last week during a panel discussion on the role of states versus markets in procuring electric generation.
Other Eastern RTO capacity markets and New York’s planned nuclear subsidies also came under fire in a discussion at the National Association of Regulatory Utility Commissioners summer conference.
Economist William Hogan, of the Harvard Kennedy School, and Allison Clements, a Natural Resources Defense Council representative to the Sustainable FERC Project, led the criticism of PJM’s Capacity Performance rules.
Clements said the environmental community does not have a preference between wholesale markets and bilateral trading. “But if [markets are] going to exist, we want to make sure that the rules are fair so that clean energy resources can compete to provide services,” she said.
Aside from FERC Order 745, which helped demand response resources enter the wholesale markets, she said, “we haven’t been that successful, and we’ve come to this point where the energy/capacity market construct, at least in the Eastern Interconnect RTOs … [is] broken.”
Clements said PJM’s Capacity Performance rules, which favor baseload generation available 24 hours a day year-round, “locks in this traditional, outdated resource mix view” that favors nuclear energy over renewables and DR, a case NRDC and other environmental groups made last month in asking the D.C. Circuit Court of Appeals to review FERC’s approval of PJM’s rules. (See Clean Energy Advocates Appeal FERC’s Capacity Performance Rulings.)
While CP rules allow summer and winter resources to aggregate a single capacity offer, no aggregate offers were submitted in the first Base Residual Auction with CP for delivery year 2018/19. In the second auction under the new rules in May, only 6% of cleared DR resources qualified as CP, compared with 9% of wind and one-tenth of 1% of solar.
“Because renewables can’t provide baseload Capacity Performance … the capacity they do provide doesn’t get counted, which means that your state policy to encourage clean energy that your customers are paying for isn’t getting full value,” Clements said.
Hogan also was critical of CP and of FERC’s oversight. He said the commission needs to ask the question: “‘Are the changes we’re making in market design going in the right direction?’ And when it’s not, to stand up and face it squarely and don’t succumb to double talk.”
PJM’s CP penalty mechanism means generators could face penalties of $5,000/MWh for shortfalls while the demand side will be seeing prices that are only $500/MWh, Hogan said.
“This can’t make sense,” he said. “You should be able to test these designs against [a] Platonic vision … and where there’s a dramatic difference like that you should be able to ask ‘Why are we doing this? Why are we sending signals to the generators and not to the load when we get into critical capacity situations?’”
Clements said it’s not necessary to abandon capacity markets and go to shortage pricing, as in ERCOT. “I think there’s something in between there,” she said, praising the “flexibility products” being offered in CAISO and MISO.
Jay Morrison, vice president of regulatory issues for the National Rural Electric Cooperative Association, also contended that RTO capacity markets aren’t working.
“Where’s the tangible evidence that they’re failing in their mission?” asked panel moderator and NARUC President Travis Kavulla, noting the new resources that have cleared PJM and other capacity markets.
“My litigation budget,” Morrison quipped. “I could save a lot of money if these markets were working properly.”
But Morrison also challenged Hogan. “There’s no Platonic ideal of a market out there,” he said. “Markets are designed for specific purposes. These markets should be designed to meet the needs that the consumers express through the utilities that serve them, through their politically elected or appointed officials.
“The market should be designed to meet the needs that the consumers want,” he continued. “The consumer shouldn’t be asked to buy the product that the market says is the right product. We need to remember which is the dog and which is the tail.”
Morrison said states have intervened — sometimes running afoul of FERC jurisdiction — “because there are important values that they are trying to pursue … that aren’t important to the market operators and aren’t incorporated into the market design.”
“Yes there are new resources [from capacity markets], but are they the right resources?” Morrison asked. “Yes, there are new resources, but are some of the people investing in them risking that they’re going to pay twice? Both for the resource in which they’re investing and the one that the market operator says they’re supposed to buy.”
RTOs have developed valuable new products for managing system operations but have not responded with the environmental or risk management products sought by consumers and state policymakers, he said. “Those are the kind of products for which bilateral markets are ideally suited,” he said. “And so long as we have the minimum offer price rule [and] buyer-side mitigation, we have trouble accessing those resources.”
The only panelists to offer much support for RTO capacity markets were Michael Haugh, assistant director of analytics for the Ohio Consumers’ Counsel, and Sarah Novosel, senior vice president and managing counsel for Calpine.
Haugh said PJM’s markets have brought new generation to serve Ohio and encourages sharing of resources among states, which reduces costs.
Novosel said her company would prefer capacity markets in all regions. She reserved her criticism for state interventions, such as proposals in Illinois, Connecticut, New Jersey and New York to subsidize nuclear plants. She said New York’s zero-emission credit program for its upstate nuclear fleet is discriminatory, will hurt markets and intrudes on federal jurisdiction, in violation of the U.S. Supreme Court’s ruling in Hughes v. Talen. (See related story, New York Adopts Clean Energy Standard, Nuclear Subsidy.)
“We’re troubled by all of these proposals because all of them, we feel, are going to undermine the wholesale markets, which competitive generators rely on for our revenue,” she said. “And once you start to pull the string and start to unravel these wholesale markets, you’re going to end up with having other generators who rely on the wholesale market needing a subsidy or long-term contract in order for them to also receive sufficient revenue to continue operations. … And by entering long-term contracts, you’re putting the risk back onto the ratepayers.”
Novosel acknowledged that “we don’t have any answers — yet.” But she said she is encouraged by the efforts being taken by RTOs to address the challenges. She cited PJM’s white paper in May and its Aug. 18 Grid 20/20 forum on public policy goals and market efficiency, and the New England Power Pool’s planned stakeholder meeting on Aug. 11 on how to preserve markets while also reducing states’ carbon footprints. “We’ve got a lot of smart people in this industry. We can come together and come up with a solution that works,” she insisted.
The simplest fix for the plight of nuclear generation and the desire for less polluting resources, the panel agreed, was to internalize the cost of carbon into the markets — a no-brainer to economists but a nonstarter for many politicians.
“I just don’t believe that” enacting a carbon tax is impossible, Hogan said, noting that he heard similar warnings before ERCOT’s move to scarcity pricing.
“I’ve been involved in lots of things that were ‘politically impossible’ when we first started talking about them,” he said. “And now they’re old hat and conventional wisdom.”
American Electric Power CEO Nick Akins said last week the Columbus-based energy giant is seeking only a partial “restructuring” of Ohio’s energy market, not full reregulation.
After FERC ruled in April that it would review state actions to guarantee income for some of AEP’s Ohio power plants, Akins had said the company would lobby Ohio lawmakers for reregulation of the state’s electricity market while also considering selling off its Ohio fleet. (See All Eyes on AEP, FirstEnergy with Ohio PPAs in Doubt.)
AEP Dresden Gas Plant in Ohio Source:AEP
Asked during a July 28 call with analysts whether AEP was de-emphasizing “reregulation” of the market, Akins said, “Reregulation just has a larger connotation to it and actually is a much heavier lift to put the entire genie back in the bottle.
“With FERC’s order essentially taking the Ohio [power purchase agreement] proposal approved by the Ohio commission off the table, which I discussed last quarter, AEP is addressing the situation by pursuing restructuring in Ohio,” he said. “Note this is restructuring, not reregulation.”
Akins said state lawmakers and other power generators are discussing the company’s proposed legislation that would transfer its competitive power generation to its AEP Ohio subsidiary. The legislation would also allow AEP to invest in new natural gas and renewable energy power sources.
“The proposed legislation strikes a balance between our ability to invest and maintain generation in the state and the customers’ ability to choose generation suppliers,” Akins said.
AEP has said it won’t build new gas plants in the state and would sell all its Ohio plants if the legislature is unable to come up with a solution. The Public Utilities Commission of Ohio had approved the earlier guaranteed-income proposal after almost two years of debate.
The company reported a quarterly profit of $502 million ($1.02/share), up from $430 million ($0.88/share) a year ago. It reported sales of $3.9 billion, up slightly from $3.8 billion. Akins said AEP’s focus on process improvement, cost discipline and capital allocation “gives us confidence that we can achieve operating earnings within our guidance range of $3.60 to $3.80 per share for 2016.”
AEP stock closed up at $69.30 Friday, an increase of 43 cents since the earnings announcement.
Negotiations with MISO over the exchange of day-ahead firm flow entitlements “are proving to be more difficult than originally expected,” SPP told FERC in its third informational report on the RTOs’ market-to-market coordination (ER13-1864).
The RTO said it continues to review MISO and PJM’s new day-ahead FFE exchange process and collect daily data from MISO. However, “SPP’s experience with the real-time market-to-market coordination procedures and the ensuing negotiations with MISO to try to improve those procedures has reinforced SPP’s belief that it would be premature to implement a day-ahead firm flow entitlement exchange process at this time,” it told the commission. (See “Regions Begin FFE Exchanges,” MISO/PJM Joint and Common Market Meeting Briefs.)
SPP said it was concerned about the potential impacts on its transmission congestion rights markets. “SPP needs to be reasonably certain that the firm flow entitlements being exchanged will result in equitable and efficient operational and settlement outcomes,” it said.
The RTOs have fared little better on implementing interface bus pricing, SPP said. It attended preliminary analysis presentations given by both MISO and PJM and discussed the issue separately with staff members of each RTO. The results, SPP said, make it unsure that the PJM-MISO seam is comparable with SPP and MISO’s.
Instead, SPP said, the RTOs are planning a study that would examine interface consistency, gaming opportunities, equity concerns and flow issues. The study is expected to begin in September and wrap up by the end of the year.
Despite the apparent lack of progress, SPP said it was interested in continuing its analysis of the MISO-PJM processes and working with both RTOs.
SPP’s informational reports were mandated by FERC in a January 2015 order. Reports are due every six months until the RTOs reach an agreement.
WILMINGTON, Del. — PJM needs to increase its fees to cover rising expenses and rebuild its diminishing operating reserve, officials told the Members Committee on Thursday.
Staff presented a first reading on five options for revising the administrative rate used to collect fees from members and market participants.
PJM is looking for member approval to increase the rates to $0.41/MWh of load served, up from the current $0.34/MWh. The options presented include a single change to a $0.41 rate, a 2.5% annual increase starting in 2018 through 2023 or an annual $0.01 increase through 2022. The 2017 rate in all options is $0.36/MWh.
A new method is necessary because PJM has been below its authorized operating reserve of $15 million since 2013. Staff had expected to rebuild the reserve to $17 million in 2015. Instead, it saw the reserve fall to $7 million because of lower-than-expected revenues. Although it trimmed expenses by $10 million below budget, to $273 million, it generated revenues of only $269 million.
PJM has changed the way it charges members and market participants several times over the past 20 years.
Before 1999, the RTO charged members a single formula rate based on load served. From then until May 2006, the RTO moved to multiple formula rates based on both load and market activity.
In 2006, PJM added a rider to cover the cost of the Advanced Control Center (AC2), and in 2011 it decreased service category rates by 3%, citing economies of scale. All proposals assume an early retirement of this rider because the debt attached to it will be paid off in September
The Finance Committee is expected to make a recommendation to the Members Committee and Board of Managers at its meeting Aug. 24.
CFO Suzanne Daugherty said she expected the committee to choose an option calling for a 2.5% annual increase from 2018 through 2023, which would restore the reserve to full funding by the end of 2017 and maintain it through 2026.
PJM will return to the Members Committee in September for an endorsement vote. It will then make a filing with FERC with a target effective date of Jan. 1.
(Editor’s Note: An earlier version of this story incorrectly stated that PJM’s expected administrative rate for 2017 will be $0.37/MWh.)
Grid Remains Strong During Recent Heat Wave
PJM canceled maintenance outages for the first time under Capacity Performance rules as the system experienced seven days of hot weather beginning July 21, Mike Bryson, vice president of operations, told the Markets and Reliability Committee on Thursday.
The peak load for the period — 151,882 MW — occurred July 25. That was the RTO’s 13th-highest ever and the highest since July 2011, when PJM set an all-time record of 165,492 MW.
The daily average LMP for July 25 was almost $36/MWh, Bryson said. Forced outages for the period were less than 13,000 MW.
“The transmission system has been very strong on the voltage side,” he said. During the period, however, two 765/345-kV transformers tripped in different parts of the system, causing local congestion.
The Dumont T2 line in Indiana tripped July 21, and the Cloverdale-Joshua Falls line in Virginia tripped July 26 because of storms, Bryson said.
PJM Moves Toward Order 825 Compliance Filing
The MRC approved a problem statement to begin work on compliance with FERC Order 825, which set new rules for RTO settlement intervals and shortage pricing triggers. Staff will begin work at the Aug. 10 Market Implementation Committee meeting to identify and address potential impacts. (See “Members Prepped for Problem Statement on Settlement Intervals, Shortage Pricing,” PJM Markets and Reliability and Members Committees Briefs.)
The order requires settling transactions in the same time intervals they are scheduled, priced or dispatched, along with aligning shortage pricing to work in the same intervals. While PJM already incorporates shortage pricing, staff realized the current system requires changes to ensure pricing signals aren’t unnecessarily erratic. The RTO’s problem statement goes beyond the requirements of the order to address these issues as well.
The original language of the final key work activity didn’t sit well with some participants, who were concerned it might open the door for revising the demand curves rather than simply adjusting the pricing intervals within them. The language was updated prior to approval to read: “Develop a new set of steps within the demand curves to be implemented in the final rule, if necessary.”
The debate went on for nearly an hour, leading PJM CEO Andy Ott to weigh in and assure members that the point was to avoid wild price fluctuations, not to adjust the overall rate structure.
PJM’s plan is to smooth out the pricing signals over time so they only trigger shortage pricing when it’s a trend.
“The look-ahead engine looks out over time, and it has to see the shortage for a persistent period of time before it will pass the indicator over to the [real-time schedule] engine,” PJM’s Rebecca Carroll said.
PJM has only had one incident of shortage pricing in recent memory, on Jan. 6-7, 2014.
Susan Bruce, who represents the PJM Industrial Customer Coalition, supported the focus on shortage pricing. Under the current demand curves, she said, consumers can be charged higher prices for a whole hour for a shortage that might last only five minutes.
Work on Fuel-Cost Policy Updates Moves Ahead
PJM market analysis manager Jeff Schmitt presented a timeline for the days remaining before the RTO’s Aug. 16 deadline for making a FERC compliance filing on its fuel-cost policy protocols.
The Market Implementation Committee held a special meeting on July 27 and has another scheduled for Aug. 4. Schmitt said he hopes to have the language updated prior to the committee’s regular meeting on Aug. 10. He asked that any additional feedback be sent to him.
In June, FERC ruled that PJM “lacks provisions for sufficient review of cost-based offers and could permit a resource to submit inaccurate cost-based offers.” It ordered PJM to add to its Tariff and Operating Agreement a requirement that generators submit fuel-cost policies that are approved by the RTO prior to submitting cost-based offers, including a penalty structure for those that file inaccurate information (ER16-372).
Feedback from the MIC meetings will be used to update PJM’s Manual 15. Schmitt said PJM has asked for a Dec. 1 effective date but that implementation of the new language will be based on when FERC responds.
MRC Endorses Manual Changes
Members unanimously approved the following manual changes:
Manual 29: Billing. Clarifications and updates are the result of a regular review.
Manual Changes Clarify ‘Physicality’ of Transactions
MRC members endorsed changes to Manual 18 clarifying the rights and responsibilities involved in auction-specific bilateral transactions. (See “Members OK Clarifications to Preserve ‘Physicality’ of Auction-Specific Bilateral Transactions,” PJM Market Implementation Committee Briefs.)
WILMINGTON, Del. — PJM stakeholders rejected a pair of dueling measures Thursday, leaving a new senior task force to decide whether to reconsider a formula key to calculating nonperformance penalties under the new Capacity Performance rules.
The sector-weighted votes capped more than an hour of heated discussion at the Markets and Reliability Committee that included allegations of political maneuvering and a call for one member to be sanctioned for “ad hominem attacks.”
The debate was sparked by the proposed charter of the Underperformance Risk Management Senior Task Force (URMSTF), an item that had been approved by lower committees with little to no discussion, despite months of controversy over the problem statement that created the group. (See PJM Generator Risk Proposal Faces Resistance.)
In recent task force meetings, however, some members had raised the question of whether the RTO was using an unrealistic number in figuring its performance assessment hour (PAH) charge rate. They worried it would artificially lower penalties in the new regime, under which generators are eligible for bonus payments and exposed to financial penalties depending on their performance. Lowering the penalties, some members argued, would weaken generators’ incentive to perform under the new market model.
Thus ensued speculation over whether such a discussion fell within the task force’s scope.
Calpine Offers Problem Statement
Fearing that the issue might be determined to be beyond the group’s mandate, David “Scarp” Scarpignato of Calpine brought a problem statement to the MRC to ensure the formula would be discussed somewhere.
“PJM had suggested that maybe it could be covered under the” task force, Scarp said. “I had indicated that I wasn’t sure that was the group to cover it because they seem intent on reducing the incentives for performance.”
According to the problem statement, informed by data from the Independent Market Monitor, “The current PAH number used in the denominator of the nonperformance charge rate does not reflect the expected number of PAHs as intended. The use of 30 hours is not adequately supported. The average of the RTO-wide PAH in the last three years was 14 hours, including the 30 hours in delivery year 2013-2014 that resulted primarily from January 2014, an outlier year.
“Too low of an expected PAH value avoids confronting capacity resources with the intended nonperformance disincentives under CP philosophy.”
The penalty nonperformance charge rate is the net cost of new entry ($/MW-day) multiplied by 365 days and divided by the 30-hour PAH value. Thus, if the value were reduced from 30 hours to 14, the penalties would more than double.
Scarp said that he had raised this issue at the last task force meeting.
“People talked at least five minutes about what’s in the scope and out of scope with this charter. There were varying opinions. People for the most part wanted to go past managing the risk and talk about the penalties you’d be exposed to. … If the group is looking at risk, it can’t be only one side, to make CP weaker.”
If the task force is limited to hedging risk, he said, its charter might as well be called the “reduce the CP effectiveness proposal.”
Incentives Key to CP
Dan Griffiths, executive director of the Consumer Advocates of PJM States, said it was important to guard performance incentives.
“If the incentives are, in fact, less, we feel like we are losing ground here,” he said. “That’s the only thing [consumers] got out of this — it’s in the interest of consumers to have strong incentives.
“You can’t quintuple the actual rate, but there is a discussion to be had here.”
Mitigating Risk for Generators
On the other side of the debate was Bob O’Connell on behalf of PPGI Fund A/B Development, who authored the problem statement that begat the task force. PPGI is the parent company of Mattawoman Energy, which is building a combined cycle plant near Brandywine, Md., in Prince George’s County.
O’Connell introduced the initiative in October, saying CP allows companies with multiple generators to offset poor performance with over-performing units but does not allow after-the-fact offsets, such as bilateral trades, that could help smaller generators. (See Generators Seek to Reopen PJM Capacity Performance Rules.)
At Thursday’s meeting, he proposed a motion to put off reassessing the PAH charge rate formula until after PJM has submitted an annual informational filing mandated by FERC in approving the charge rate. It was seconded by Jason Cox of Dynegy.
Countered Scarp: “Putting this off into limbo is a terrible thing to do to a fellow stakeholder, and something I have never done.” He accused O’Connell of using “procedural moves to prevent voting on this order” and being “disingenuous,” which elicited a call from O’Connell to have him sanctioned for “ad hominem attacks.” Committee Chair Suzanne Daugherty did not formally act on his request.
Breaking a Rule of Thumb
Indeed, most members prefaced their comments by saying as a rule of thumb, they do not oppose problem statements. It’s highly unusual for them to be rejected.
But after O’Connell’s measure failed with slightly less than 49% approval, members also voted down the Calpine problem statement, which was endorsed by slightly more than 44% of the votes.
Members subsequently approved the task force charter by acclimation.
The votes cut across sector lines, with generators split on the issue but more favoring O’Connell’s motion. The only sector to unanimously support Calpine’s initiative was the End-Use Customers (albeit with one abstention).
Jason Barker of Exelon had provided the “second” needed for a vote on the problem statement.
“The data shows quite strongly that 30 hours … is vastly overstated,” Barker said.
He joined Scarp in criticizing his colleagues for “procedural shenanigans and weak arguments” and encouraged them to put aside politics, saying that no one got everything they wanted out of the CP construct. “Let’s be honest around the table,” he said.
FERC Has Spoken
Some members said they were hesitant to revisit the issue because FERC had approved the charge rate using the 30 PAH hours.
Although the commission approved the 30-hour proposal as a “reasonable approximation of the upper bound” of hours during which PJM is likely to experience emergency actions, it also required the RTO to submit informational filings for five years evaluating the impact of the 30-hour assumption on resource performance. “We also encourage PJM, as it gains more experience under its new capacity construct, to reassess the assumed number of performance assessment hours and file with the commission if it believes a revision is warranted,” the commission said.
Scarp noted that FERC’s order hasn’t stopped stakeholders from questioning other aspects of the ruling, including operating parameters and seasonal capacity. The 30 hours, he said, is an error.
Carl Johnson, of the PJM Public Power Coalition, said, “We do not like to oppose a problem statement — that’s how we got to move forward with the URMSTF and seasonal capacity. But in this particular case, we’re talking about something so specific that FERC gave us a directive on.”
He referenced PJM’s recent experience spending months hammering out consensus on a ramp rate for the CP product, only to have FERC reject it.
“I’m not inclined to use our time on this,” he said. “I don’t want to spend time taking things to them that aren’t going to go anywhere.”
Susan Bruce, of the Industrial Customer Coalition, agreed that the charge rate was a core issue of CP, but she said it was just one and hesitated to approve re-evaluating it without looking at others.
“If you say we can’t talk about those other components, I think it’s a conversation to be had in a vacuum,” she said.
Scarp responded, “If you think that there are other numbers that are incorrect, I’m happy to look at them. I am not redesigning CP in any way. I’m probably one of the few people in the room who has never tried to redesign CP.”
NASHVILLE, Tenn. — There are more than 50 million smart meters and more than 1,000 phasor measurement units (PMUs) deployed in the U.S., the product of a rollout funded in part by federal Recovery Act spending following the 2008 financial crisis.
What have we gotten for our money?
High bill alerts, proactive service calls, peak shaving abilities and self-healing transmission, among other things, a panel of technology executives told the National Association of Regulatory Utility Commissioners summer conference last week.
Now, with smart grid technologies more widely deployed, it is slower-moving regulators and utility procurement practices that are hindering innovation, Silver Spring Networks’ Eric Dresselhuys said.
“If you’ve got energy technology cycles that are happening in 12-, 18- and 24-month cycles and utility adoption cycles and regulatory proceedings that are happening in the three- to five-year range, ultimately what you do … is by the time you make a decision, that decision is outdated, because [technologies] have moved on,” said Dresselhuys, executive vice president of global development for the company, which provides smart grid networking platforms.
High Bill Alerts
Alex Laskey, president and founder of Opower, said utilities have reported a 20% drop in customer calls regarding high bills following a smart meter-enabled program that alerts ratepayers of spikes in energy use. Opower provides “customer engagement” platforms for utilities, a niche growing so fast that technology giant Oracle agreed in May to buy the company.
“Not unlike those fraud detection alerts [used by credit card companies], we alert customers on behalf of their utility via text or email or a phone call. … ‘You’re on track for a high bill. It’s only eight days into the month, but you’re on track for a bill that’s 30% higher than your typical bill this time of year and here are some things you ought to do to try and reduce your usage,’” Laskey explained.
“Customers like it because instead of getting [a large] bill at the end of the month when it’s too late, you’re being alerted in advance that something is amuck and you can make a change,” he continued. “Particularly for low-income customers — for whom electricity represents 8 to 10% of their income — the ability to give them predictability and transparency on what their costs are going to be is critical.”
Laskey also cited Baltimore Gas and Electric’s peak time rebate tariff, which rewards customers for saving energy on the hottest days.
“PJM has measured more than a 15% reduction now at peak for BGE,” Laskey said. “This is just by giving customers better information and a financial incentive.
“You can do that across the country. [Rocky Mountain Institute] estimates $60 billion a year in customer benefits and none of it is possible without regulatory incentives and reform … but on the same hand it can’t be enabled without reliable software.”
The Value of Power Quality
Commonwealth Edison is using big data analysis to identify areas on its grid where customers are receiving voltages below the nominal 240 V, allowing it to “drop in better voltage regulation,” Dresselhuys said.
“When you combine this with things like conservation voltage reduction and other advanced analytics that are being done, the amount of optimization that can be built into the grid on a daily basis is pretty dramatic.”
But Dresselhuys said “the ratemaking and procurement processes within utilities really struggle with the idea of futures or what is the option value that comes from technology.”
“What’s the value of good consistent power quality? The utility doesn’t make more money on that and they didn’t show savings by doing that. And so it doesn’t get put into the rate case and if you don’t put it into the rate case, it doesn’t make the technical requirements because you can say, ‘Well you’re gold-plating the system,’” Dresselhuys said. “So one of the things we have to figure out is, if we’re implementing techs that we expect to last for five, 10, 15 or 20 years, how can we make sure that we’re building platforms … that will continue to add value to consumers over time?”
Proactive Service Calls
Dresselhuys recalled the beginning of smart meter deployment. “Ten years ago people said, ‘Why would we ever need hourly data?’ Now people are cranking that up to five-minute data and one-minute data in some cases.”
He said one Silver Spring customer has been able to use the increasingly granular data to change its maintenance procedures from the “break-fix mentality of ‘let’s just wait until there’s an outage and we’ll go there and fix it.’”
The utility, which serves a seaside location, can identify momentary outages at customer locations, an indication that their service drop — the wires running from the utility pole to the house — has suffered corrosion.
“Worst-case scenario, it starts a fire. The best-case scenario, they just lose power,” Dresselhuys explained. “The customer wouldn’t even notice this because it’s just maybe a flicker if anything.”
The diagnostics allow the utility to schedule proactive service calls to replace the defective wiring.
Tim Healy, CEO and co-founder of demand response provider EnerNOC, said the increase in data is crucial to large customers, such as the 700 commercial real estate firms that are now reporting their Global Real Estate Sustainability Benchmark (GRESB) scores on more than a trillion dollars’ worth of assets.
“It is one of the key metrics that investors are using in order to make investments in the real estate sector,” Healy said. “What we’re seeing with our customers is they have an acute need that goes not just right to the bottom line but it goes to their access to capital to run their businesses. The information technology and the needs of the financial reporting organization need to intersect more than ever before.”
Dave Kolata, executive director of the Citizens Utility Board in Illinois, said consumer advocates are having to become more tech savvy to determine the costs and benefits of new technologies and avoid stranded costs resulting from the replacement of systems that have not been fully depreciated.
“Traditionally, IT investment has been something of a black box,” he said. “It’s not something that … we have much expertise in.”
The western Energy Imbalance Market continued to boost demand for California’s surplus renewable generation last quarter, extending a trend observed during the first three months of 2016, according to CAISO’s quarterly economic benefits report.
The eight-state EIM — comprising the CAISO, NV Energy and PacifiCorp balancing authority areas (BAAs) — absorbed 158,880 MWh of renewable supply that would have otherwise been curtailed, reducing carbon emissions by 67,970 metric tons through the displacement of thermal generation, the ISO estimates. Avoided curtailments increased by more than 40% compared with the first quarter.
The report showed that CAISO monthly exports into NV Energy increased by an average of 56% over the previous quarter. Much of that energy was wheeled into the PacifiCorp East (PACE) BAA, which has limited direct links with the ISO. Transfer capacity between the ISO and PACE increased from about 200 MW to 570 MW when NV Energy joined the EIM late last year.
While the report did not describe the specific reason for the uptick in transfers, PacifiCorp shut down four coal plants in April and May because of the EIM, according to Jonathan Weisgall, a vice president with Berkshire Hathaway Energy, PacifiCorp’s parent company.
“It is also worth noting that a significant level of energy exported by the ISO consisted of renewables,” CAISO said, although the report did not break down exports by resource type. ISO exports peaked in May, when increased solar output typically coincides with mild weather and modest loads in California.
The EIM provided participants with $23.6 million in gross financial benefits during the second quarter, compared with $18.9 million the previous quarter, the report said. PacifiCorp realized the largest share of benefits at $10.5 million, followed by CAISO at $7.9 million. NV Energy’s take increased threefold over the first quarter to $5.2 million.
Benefits can take the form of either cost savings — such as from reduced need for reserves or greenhouse gas credits — or increased profits from merchant operations. The benefits calculation nets out inter-BAA transfers that were scheduled ahead of the EIM’s 15- and five-minute market runs to avoid attributing contracted flows to the market.
CAISO also estimated the EIM’s effect on the procurement of flexible ramping capacity — resources equipped to respond to system variability stemming from the intermittency of renewable resources.
“Because variability across different BAAs may happen in opposite directions, the flexible ramping requirement for the entire EIM footprint can be less than the sum of individual BAA requirements,” the ISO said, resulting in “flexible ramping diversity savings” stemming from a reduced procurement of flexible resources. It said the EIM produced a 26% reduction in the need for those resources during the quarter.
The EIM has accrued $88.2 million in benefits for its participants since it commenced operation in 2014, according to CAISO. Arizona Public Service and Puget Sound Energy are preparing to enter the market in October 2016, followed by Portland General Electric in October 2017 and Idaho Power in April 2018.
With only hours to go at the end of its session, the Massachusetts legislature Sunday night passed a major energy bill that boosts Canadian hydropower and offshore wind as sources to meet the state’s clean energy goals.
Legislative negotiators worked through the weekend to reconcile House and Senate bills that differed over the volume of offshore wind, the inclusion of the Cape Wind project and support for new gas pipelines.
The final bill (H.4568) requires utilities to annually obtain 9,450 GWh of energy that qualifies for the state renewable portfolio standard, including onshore wind and Canadian hydropower.
It also orders procurement of 1,600 MW of offshore wind by 2027 — a compromise between the House’s 1,200 MW and the Senate’s 2,000 MW. It excludes Cape Wind, which the Senate would have included, because it has not won a competitive lease auction from the federal government.
First Mover
In January 2015, the U.S. Bureau of Ocean Energy Management awarded offshore leases to RES America Developments (lease area OCS-A 0500 for 187,523 acres) and Offshore MW (lease area OCS-A 0501 for 166,886 acres) in the Massachusetts Wind Energy Area, which starts about 12 nautical miles offshore. Last June, BOEM approved the assignment of RES America’s lease to DONG Energy Massachusetts.
Source: Dong Energy
BOEM said the area leased could support approximately 2 GW of wind generation.
Thomas Brostrøm, general manager of North America for DONG Energy Wind Power, said the legislation “will allow the creation of a viable offshore wind energy industry here in Massachusetts.”
The company said it plans to install capacity of up to 1 GW in the form of what it is calling Bay State Wind, a project it said will create 1,000 new jobs in Massachusetts during construction and approximately 100 new jobs to support the wind farm during its life.
“With world-class wind speeds and ideal water depths of between 130-165 feet, Massachusetts will be able to garner the economic benefits and supply chain development of being the first mover to site utility-scale offshore wind energy on the East Coast of the United States,” the company said.
DONG Energy, based in Denmark, operates 19 offshore wind projects totaling more than 3 GW with another 3 GW under construction.
Offshore MW, which is partnering with the nonprofit Vineyard Power Cooperative on its project, could not be reached for comment.
Other Provisions
In addition to jumpstarting offshore wind, the Massachusetts bill:
Promotes energy storage, authorizing the Department of Energy Resources to develop procurement targets and incentives for utilities, households and businesses;
Requires utilities to fix their most serious gas leaks; and
Expands energy efficiency and clean energy financing options for commercial customers under the Property Assessed Clean Energy program.
Lawmakers rejected the Senate’s proposed increase in the RPS, incentives for electric vehicle adoption and a prohibition of the so-called “pipeline tax,” which would allow electric distribution companies to assess ratepayers for construction of the extra capacity needed by natural gas pipeline owners to supply power plants.
Power plant owners and marketers oppose the policy, but state officials say the capacity is needed to mitigate price spikes caused by tight supplies.
The state Department of Public Utilities has already determined that such supply contracts are allowed under existing state law. An LNG supplier and an environmental group, supported by the Massachusetts attorney general, have challenged that interpretation. A ruling is expected soon from the state’s Supreme Judicial Court. (See More Pipelines for New England: ‘Gold-plating’ or Necessity?)
The energy legislation was one of several bills that required last-minute action at the Capitol before the July 31 deadline, after the legislative calendar was cleared for the Republican and Democratic national conventions.
Both houses had agreed that Massachusetts needed to significantly increase the amount of clean energy used to comply with its Global Warming Solutions Act, passed in 2008. Nuclear and coal-fired generation have been closing in recent years, and ISO-NE says the region is facing tight energy supplies. (See Massachusetts Clean Power Bill Hit from All Sides.)
Gov. Charlie Baker, a Republican, had opposed the Senate’s inclusion of Cape Wind and the “pipeline tax” prohibition. The governor issued a statement Monday thanking lawmakers for completing the energy bill and other legislation before the deadline.
“As our administration carefully reviews all of the legislation that lawmakers worked diligently to reach consensus on, I will continue to work across the aisle with our partners in the legislature to make Massachusetts a better place,” Baker said.
Enviros Supportive; Generators Dismayed
The New England Power Generators Association criticized the bill, saying it would “dramatically increase costs for consumers and undermine billions of dollars in energy investments” in the state.
“This energy bill represents the single biggest step away from a competitive electricity market ever taken in New England,” NEPGA President Dan Dolan said. “Power plant owners in Massachusetts will now be barred from competing for nearly 60% of the commonwealth’s electricity market. Instead, consumers will be forced to pay for huge amounts of power at above-market prices, eliminating opportunities for innovation and cost containment.”
Members of the Alliance for Clean Energy Solutions, a coalition of clean energy companies, environmentalists and consumer representatives, had a different perspective.
“This bill is a huge step on the path to a clean energy future,” said Peter Shattuck, Massachusetts director of the Acadia Center. “The legislation solidifies the commonwealth’s leadership in reducing carbon pollution and will help reduce our growing over-reliance on natural gas.”
Source: Dong Energy
Janet Gail Besser, executive vice president of the Northeast Clean Energy Council, said the bill “will not only accelerate the deployment of clean energy, but will also serve to accelerate our economy by providing a stable policy framework for investors and developers of clean energy.”
Emily Norton, director of the Sierra Club’s Massachusetts chapter, praised the legislature for its boost to offshore wind and “for forcing utilities to fix methane leaks that are warming our planet, killing trees, jeopardizing safety and wasting consumer dollars.”
“However the bill does not go far enough in terms of transitioning us to a clean energy economy and a transportation sector powered by clean electricity rather than petroleum,” she continued. “It is also very disappointing … in spite of a unanimous Senate vote to prohibit a pipeline tax, to see that language missing from the final version. We look forward to making further gains toward climate justice in the next legislative session.”
