Western U.S. utilities procured three times more wind capacity in 2003-2014 than planned, showing there is a limited relationship between electricity resource planning and procurement, according to a new Department of Energy study.
Actual and planned nameplate capacity additions by resource and contract type for 12 load-serving entities in the West. | Lawrence Berkeley National Laboratory
Expansion of nameplate wind capacity by 2015 was expected to be about 15% but was actually about 50%, likely coming from power purchase agreements, the analysis of 12 Western load-serving entities showed. Changes in load growth, regulation and contracting led to adjustments in resource planning, and differences in resource mix came largely from renewable portfolio standards and demand-side management, as well as fuel price changes.
The study considered what types of economic and regulatory information is used in planning and procurement, and examined the value of the planning process in light of its relationship to actual practice. The analysis compared integrated resource plans filed in the early and mid-2000s to the actual procurement that followed.
Although IRPs are designed to ensure that utility investment decisions are as cost-effective as possible, there had been no previous “empirical assessment on the effectiveness of IRP implementation,” said the study, conducted by the Lawrence Berkeley National Laboratory.
“We find that most information produced in the planning phase is generally disconnected from the procurement phase,” the researchers said.
Western Wind Farm | SPP
After 2008, adoption of less efficient simple cycle combustion turbines correlated with dropping natural gas prices, which might also have been needed to provide balancing power because of higher usage of intermittent renewables. There was also less usage of coal-fired generation than planned, as difficulties in getting coal plants permitted were mentioned by several LSEs in their resource plans; natural gas was likely used as a baseload power substitute.
The researchers said only some of the forecasts, least-cost/risk portfolios and other information produced during the long-term planning processes were used during the procurement processes, and that procurement decisions relied “extensively on the most recent information available for decision making.”
“These findings suggest that states’ IRP rules and regulations mandating long-term planning horizons with the same analytical complexity throughout the planning period may not create useful information for the procurement process,” the study says.
The study found “in aggregate … a general alignment between planned and procured supply-side capacity. However, there are significant differences in the choice of supply-side resources and type of ownership for individual LSEs.”
Avista, Puget Sound Energy, Seattle City Light and Public Service Company of New Mexico procured less capacity than planned, possibly because of lower load growth, while Idaho Power, PacifiCorp and Portland General Electric procured more capacity than was planned. Idaho Power procured two to three times more wind capacity than planned. Although PacifiCorp had not planned for any wind in 2004, more than half of its procured nameplate capacity was wind.
For the Los Angeles Department of Water and Power, Sierra Pacific, Nevada Power and Public Service Company of Colorado, the largest difference between planning and procurement was substituting natural gas units for coal.
There is no formalization of how utilities should use inputs from their IRPs in their procurement, and there is little evidence regarding how sensitivity and risk analyses used in the IRPs are actually applied in procurement decisions, the study says.
It called for a “more careful” definition of the links between IRPs and procurement, calling it “an important problem as energy technologies, markets, and policy and regulatory goals evolve and become more complex.”
CAISO is seeking comment from market participants on three proposed modifications to the Western Energy Imbalance Market (EIM).
The grid operator on Tuesday kicked off the stakeholder process for the proposals, which include allowing third-party transmission providers to receive congestion revenue when they make unused capacity available between EIM balancing authority areas (BAAs).
| CAISO
In response to questions during a call on the initiative, CAISO said transmission owners will not have to turn over control of their transmission facilities to participate and would receive payment only if there is congestion on the system.
CAISO says the measure would increase transfer capacity among members, which the ISO’s internal Market Monitor has pointed out reduces congestion and limits the ability of any single participant to wield market power within its BAA. (See Increased Transfer Capacity Reducing EIM Congestion.) EIM entities can currently collect congestion revenue through an offset, but that functionality is not extended to third parties.
The ISO plans to use its existing functionality for transmission contributions, known as “energy transfer system resources” that are used to track, tag and settle EIM transfers. It will need to establish a pro forma agreement that enables scheduling coordinators to submit transmission contributions on behalf of a third party, and create a new make-whole mechanism that would guarantee a payment from congestion revenue. The ISO is seeking stakeholder input on what level of interval granularity those payments should be calculated and how their associated costs should be allocated.
CAISO also wants to correct an inequity that occurs when an EIM BAA wheels power between other BAAs. Wheel-through BAAs receive some revenue when congestion occurs but are not compensated if there is no congestion. In that circumstance, only the source and sink BAAs accrue benefits when a wheel-through transfer occurs.
“How should we quantify the benefits of providing EIM transfers through an EIM BAA?” CAISO asked in its meeting materials.
The ISO has also proposed a new policy for situations in which market participants change their bilateral schedules after submitting their hourly base schedules. Under current practice, changes made after submission are exposed to real-time imbalance settlement payments.
Settlement can result in either charges or payments, but there is no way for market participants to know the cost beforehand. Proposed changes would allow them to manage their exposure to imbalance settlement charges, CAISO said.
After the comment period ends June 30, CAISO will post a straw proposal on the initiative by July 27 and hold stakeholder meetings in August and September. The EIM Governing Body is set to review the proposals in October, ahead of a decision by the CAISO Board of Governors in November.
BRANSON, Mo. — MISO wants to spend $130 million over the next five years to construct a new market platform before its existing one becomes outdated, but its Board of Directors is insisting on a thorough stakeholder review of the project’s cost.
Jeff Bladen, MISO executive director of market design, said the upgrade would involve a “piece-by-piece replacement of components” resulting in a “far more modular platform” compared with the rigidity of the current system, which hinders market changes.
Swapping out market software incrementally instead of introducing a new platform all at once is the safer option, Bladen said.
“The risk of a misstep is far less using an incremental process,” he said during a rare June 20 joint meeting of the board’s Markets and Technology committees.
MISO’s current platform is “inflexible,” and even simple market changes require testing and retesting because of possible effects on other software, according to MISO Technology Executive Kevin Caringer. He likened the new design to Microsoft PowerPoint, which can recognize and accept fonts and graphics from other sources.
Looming Obsolescence
The RTO evaluated its market system last year and concluded it had five to seven years before evolving cybersecurity standards and increasing market complexity render the system — designed in the late 1990s — obsolete and no longer able to clear the day-ahead market. (See MISO Reaffirms 2023 End Date for Market Platform.)
“The time is now to begin long-term investment,” Bladen said. “Findings and conclusions drawn from the evaluation resulted in a clear call to immediately initiate a system upgrade.”
Caringer said MISO will spend about $3 million on cybersecurity to extend the life of the current platform for the five years needed for the switch to a new platform.
MISO is asking for an additional 25% contingency budget for unforeseen expenses in addition to the expected $130 million plan. Staff said it will present final cost estimates to the board in September. The board’s Audit and Finance Committee will decide whether to approve the spending in October, and a full board decision on the budget is set for December.
MISO staff predicts the project will yield a 4-to-1 return on investment, with $201 million in benefits, $254 million in cost avoidance and $111 million in risk mitigation.
Director Baljit Dail asked how MISO will prove the benefits and savings to its stakeholders.
Bladen said the RTO can share a recent benefits report once it removes nonpublic information from the document.
“I don’t want this to be jammed into December. At some point, I’m going to ask, has this report been scrubbed and has it been shared with stakeholders? I don’t want that to happen in December,” Dail warned.
Director Paul Bonavia wondered if MISO will give stakeholder groups a chance to collaborate to develop a process for responding to the benefits report.
Bladen responded that MISO expects to follow its normal annual budget process with stakeholder review occurring in the Finance Subcommittee.
“I appreciate that, but the budget process usually doesn’t have $130 million to $160 million in additional spending. One director’s strong counsel to you all is make sure the usual process can handle [this],” Dail said.
Other directors pointed out that the project’s benefits may play second fiddle to the market failure that looms if MISO does not implement a new market platform.
“I’m not too captivated by the benefits. We need to move,” Director Michael Curran said. “I’d love to see the benefits, but we have to spend the money. … It’s a burning platform; it’s a slow burn, but it’s coming.”
“My comment is, however you want to justify the benefit, it needs to be put before the stakeholders,” Dail replied. He suggested that MISO convene a special stakeholder committee to discuss the investment and consequences of not reconstructing the market platform.
“I’d like to see [the stakeholders’] fingerprints all over this,” Curran agreed.
Bladen said MISO could initiate stakeholder workshops to discuss building the platform.
In response to a question from Curran, Caringer said MISO could reach out to developers of its original market platform to help improve the transition. Some longtime MISO employees also have knowledge of the system, he said.
Curran said he wanted to require any potential project vendors to have contact with developers of the original system. CEO John Bear said the board would address that topic in a closed session that immediately followed the meeting.
The D.C. Circuit Court of Appeals on Tuesday denied eight challenges to PJM’s controversial Capacity Performance market rules, potentially cementing fundamental changes to the RTO’s capacity market that critics believe were hastily enacted and unjustifiably increase costs (16-1234).
CP was implemented following a blackout scare in January 2014 when the polar vortex dipped unusually low across the northern U.S. and created record-low temperatures. As much as 22% of PJM’s fleet failed to operate when dispatched, despite being contracted through the capacity market.
The new rules introduced year-round performance requirements for capacity resources along with incentives to perform and steep penalties for failing to do so.
Critics of the new rules argued they would increase the cost to secure capacity by billions of dollars. After FERC approved the changes in June 2015, challengers petitioned the commission for a rehearing, which the commission denied.
Nine organizations challenged FERC’s denial in court. The ensemble is a somewhat unusual partnership of environmental groups (the Natural Resources Defense Council, Sierra Club and Union of Concerned Scientists), representatives of utilities (the American Public Power Association, the National Rural Electric Cooperative Association and the Public Power Association of New Jersey), the Advanced Energy Management Alliance, which represents demand response resources, American Municipal Power, which represents both utilities and resources, and the New Jersey Board of Public Utilities.
FERC’s Reasoning Upheld
The ruling by Judges A. Raymond Randolph, Janice Rogers Brown and David B. Sentelle was unanimous. The court ordered the clerk to withhold issuance of the mandate resulting from the ruling to give the plaintiffs time to file petitions for rehearing before the three-judge panel or the full court.
Left to right: Judges A. Raymond Randolph, Janice Rogers Brown, David B. Sentelle | U.S. Courts
The court’s decision points out that FERC acknowledged the increased capacity costs but cited a study that estimated the new rules would create an annual net savings of potentially billions of dollars starting in 2016. The fact that the study used a penalty that was higher than FERC approved was immaterial, the court found.
“The savings come from the penalty successfully increasing reliability,” the court said in its decision. “Even with a lower penalty, the net savings may be substantial.”
FERC “does not have to find net savings” to approve proposed changes, the court found, and higher costs can be warranted if they increase reliability. FERC said the revisions would do that and also help avoid energy price spikes.
Year-Round Resource Requirement
PJM’s requirement that all CP resources be year-round attracted opposition from numerous groups.
NRDC, Sierra Club and UCS said that the requirement discriminated against seasonal generation such as wind and solar — despite the RTO’s offer that winter-only resources could aggregate with summer resources — because aggregation imposed “transactional costs.”
Utility Scale Solar in Maryland | Constellation
AMP, meanwhile, said aggregation should also be open to traditional resources.
The judges said none of the challenges persuaded them to question the commission’s judgment. “The commission’s policy decision to assess reliability through a year-round capacity commitment is the type of policy judgment to which we afford deference, and that deference is justified by the record,” they said. “The law provides no basis to claim the commission cannot approve uniform performance requirements simply because those requirements will be easier to satisfy for some generators than for others.”
Demand Response
AEMA had problems with CP’s impact on DR, challenging PJM’s proposal to use separate formulas for calculating expected consumption during summer months and non-summer months.
The group said it supported the “peak load contribution” method for the summer, which is based on a DR customer’s contribution to the five hours of the previous year when systemwide demand peaked. It opposed the “customer baseline load” method for non-summer months, which is based on the customer’s contribution to the system’s load for the four days of peak systemwide load during the most recent 45 days.
“Because it was reasonable for the commission to accept PJM’s proposal to use the recent-peak method for non-summer months and any alleged departure from past practice was adequately explained, we defer to the commission’s determination on this issue,” the court said.
AEMA Executive Director Katherine Hamilton said the court rebuff means consumers will face reduced choices and higher prices because residential DR and renewable resources “could be forced out of the market altogether.”
“In the recent auction, the amount of demand resources — both offered and cleared — fell by thousands of megawatts compared with previous years. PJM has now effectively ceded jurisdiction for monetizing these competitive products in the capacity markets, and it will be up to state commissions located in PJM to determine how these products will be operated going forward,” she said in a statement. “As AEMA considers legal options moving forward, we will continue working within the PJM stakeholder process on wholesale competitive market issues and with state commissions on demand response solutions for consumers.”
Procedural Challenge
The court also rejected challenges by APPA, NRECA and PPANJ to PJM’s filing of proposed changes to the capacity market under Federal Power Act Section 205 and its simultaneous Section 206 complaint proposing replacements for energy market rules it said were no longer just and reasonable.
PJM could not file changes to the Operating Agreement under Section 205 because it did not seek stakeholder approval of the changes.
The public power groups argued that the commission could not accept PJM’s Section 205 filing as just and reasonable while simultaneously finding that the filing rendered the Operating Agreement unjust and unreasonable under Section 206. “In effect, FERC found that PJM had created the factual premise and legal basis for FERC to order a change in rates that PJM could not have unilaterally made,” the groups said. “This bootstrapping of results is impermissible.”
The court said the petitioners failed to “explain why PJM’s Section 205 filings regarding the capacity market necessarily must complement existing energy market agreements to be just and reasonable” and cited “no precedent for their theory that the commission was required to act ‘under Section 206 alone.’”
“We therefore see no reason why the commission was not entitled to approve changes under Section 206 in anticipation of the impacts of the Section 205 filing rather than wait for those impacts to be realized,” the court ruled.
Penalties Too Low
PPANJ and the New Jersey BPU contended the CP penalties for resources that fail to meet their capacity commitments during an emergency hour were too low to ensure performance.
The commission approved a penalty rate equal to one-thirtieth of the net cost of new entry per megawatt-hour of shortage. The petitioners said the 30-hour denominator — based on the number of emergency hours in 2013-2014 — was too high, resulting in a penalty that was too low.
“The commission had good reason to conclude that the formula results in a high enough penalty to encourage resources to meet their capacity commitments,” the judges said. “The commission decided the penalty was also low enough to avoid introducing ‘excessive risk’ into the capacity market. Too high a penalty could discourage even reliable resources from entering the market. We defer to the commission’s balancing of these competing concerns.”
Default Offer Cap
Also rejected was a complaint by the BPU and four organizations representing utilities that PJM’s default offer cap, meant to reflect the CP penalties and bonuses, is too high. PJM would only include an offer above the cap in the capacity auction if it determines it is cost-based.
The court rejected complaints the cap could increase capacity costs, saying “increased capacity prices are necessary” to encourage entry of new, reliable resources. “Resource owners need to be able to offer capacity at a higher price in order to recover the costs of improvements,” it said.
Unit-Specific Constraints
AMP challenged the imposition of penalties on CP resources that fail to perform because of unit-specific constraints, saying it was inconsistent with energy market rules, which require PJM to cover resources’ costs if it schedules the them to run outside of their parameter limits.
“Given the different purposes of the capacity market and the energy market, there is no inconsistency in treating the operating-parameter limitations differently in the two markets,” the court said.
PJM on Monday secured U.S. Department of Energy approval to dispatch Dominion Energy’s recently shuttered Yorktown coal-fired plant to address potential reliability issues on Virginia’s Middle Peninsula.
Dominion, which closed the plant in April to comply with an EPA mandate, said it anticipated the department’s order and is prepared to restart both units at the plant as necessary.
Yorktown Generating Station | Dominion
Energy Secretary Rick Perry granted PJM’s request for a 90-day window to dispatch the units as necessary to “maintain grid reliability,” and the order can be renewed upon request indefinitely if the situation remains unchanged. PJM and Dominion are required to create a dispatch methodology and submit what dates the units are operated, along with estimated emissions and water usage, to the department.
“While this is not a long-term solution to the reliability issues, Dominion Energy supports PJM’s action and the DOE decision, and will work to ensure the units’ availability as required,” Dominion spokesperson Bonita Billingsley Harris said in an emailed statement.
Stalled Project
The order stems from Dominion’s difficulty in gaining approval for the proposed Surry-Skiffes Creek 500-kV transmission line across the James River, which has for years faced opposition from local and environmental activists. Approved by the PJM Board of Managers in 2012, the transmission project remains stalled pending permit approval from the Virginia Marine Resources Commission (VMRC) and a waiver from the state Department of Environmental Quality for water quality certification. The U.S. Army Corps of Engineers issued a conditional permit earlier this month that requires approval from both agencies.
Map of transmission system at Virginia’s middle peninsula | PJM
The project will additionally require a special-use permit from the James City County Board of Supervisors. Members of the public will have the opportunity to weigh in during both the VMRC and county permit hearings, Harris said.
Dominion estimates the line would take at least 18 months to construct after all permits are approved. The company had hoped to complete the project prior to closing the Yorktown units, which are among the few generators able to serve load in the populous but isolated North Hampton region.
While Dominion sought to shutter Yorktown by 2014 to avoid expensive emissions upgrades required by EPA’s Mercury and Air Toxics Standards, PJM required the units to remain operational to maintain reliability on the peninsula in the absence of the proposed line. State and EPA approvals extended the shutdown deadline several years, but applicable extensions finally ran out on April 15 and Dominion closed the doors.
Dominion warned that failure to build the line before shutting down the units could result in blackouts, an assertion opponents dismissed as scare tactics. In February, the company provided PJM a regional remedial action scheme that calls for dropping service to approximately 150,000 customers in the event of an emergency in order to prevent potential voltage collapse from N-1-1 contingencies. (See Opposition to Va. Tx Line May Trigger Unintended Consequences.)
No Surprise
The order didn’t catch Dominion by surprise.
“When it became apparent we would not receive approvals in time to complete the new transmission line before the coal units had to be retired, we pursued an aggressive plan of equipment upgrades, enhanced inspections, maintenance scheduling and contingency preparations to protect energy reliability on the Virginia Peninsula until the permanent solution could be put in place,” Harris said.
While the company was prohibited from running the Yorktown units after April 15, its contingency plans included keeping them in operating condition in case of an emergency, she added.
Despite its potential open-ended approval to run the units, Dominion said it remains committed to shutting them down and building the transmission line.
“This law protects PJM and Dominion from civil or criminal liability or citizen suit, but it is our intention to continue moving forward as quickly as possible to build and energize the transmission project limiting the time these units will operate to ensure the best environmental outcome,” Harris said.
ALBANY, N.Y. — Regulatory oversight of distributed energy resources is better fully mapped out at the beginning of the process rather than built piecemeal, more than a dozen industry stakeholders told staff of the New York State Department of Public Service on Monday at the second of two technical conferences on DER oversight.
New York PSC Technical Conference on DER Oversight
The first conference was held June 12 to explore how the Public Service Commission can best regulate utilities and protect consumers through the application of uniform business practices and marketing standards in the new era of rooftop solar and residents becoming “virtual” DER providers through membership in community distributed generation programs.
“What we have done in other areas is we’ve erred on the side of being more generous in the initial phase, trying to support new markets, but then you go to try to introduce new rules [and] people go crazy,” said Erin Hogan, director of the state’s Utility Intervention Unit. “So in my mind, it almost seems better to start with a more comprehensive structure and take away, as opposed to trying to add when you’ve discovered a problem.”
The PSC in March adopted a new “value stack” pricing mechanism for solar and other DER, along with two other orders to transition utilities into “distributed system platforms” and align their incentives with DER providers. The Value of Distributed Energy Resources order approved March 9 (Case NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)
Benefit of the Bargain
Weiner
Scott Weiner, DPS deputy for markets and innovation, chaired the June 19 roundtable discussion and emphasized that “we’re dealing with not the purchase of bread or the repair of a car, which has its own protection, but with the provision of electricity and the opportunity of companies to enter into a marketplace, an expanded marketplace that has been created by the commission. The underlying question is, what responsibility does the commission have to make sure that end-use customers receive the benefit of the bargain that they’re agreeing to?”
“Oversight is important to build consumer confidence,” said Sara Margaret Geissler, manager of customer operations regulatory performance at Consolidated Edison. “We all want to create a market that they can have confidence in … and a core part of that is making sure, or having enough guidelines to ensure, that they understand what they’re signing and they know who to call if they have an issue.”
Geissler represented the joint utilities at the technical conference, which also include Central Hudson Gas & Electric, National Grid (which owns New York State Electric and Gas, and Rochester Gas and Electric), Orange and Rockland Utilities, and Rockland Electric.
Differentiate the Customers
Strauss
Valerie Strauss, policy director at the Association for Energy Affordability, noted the importance of differentiating between residential and commercial customers — and between different levels of commercial customer.
“We need to look at this in terms of the risk to the consumer,” Strauss said. “The current proposal is a blanket [that] kind of covers everybody. … We would suggest that that be revisited and some changes made for the provisions to more reflective of the risk.”
Strauss suggested that commercial customers could be differentiated by the number of units they control: “Certainly a mom-and-pop owner who has five buildings with 10 units each is not a sophisticated [commercial and industrial] customer. A property manager who owns 100 buildings that have 100 units each probably is.”
Community DG is new in New York but not in other markets, according to Hannah Masterjohn, policy vice president at the Clean Energy Collective.
“We have pretty substantial markets in Massachusetts, in Colorado, where we’ve already got thousands of customers participating in projects,” Masterjohn said. “When we look at our experience … we find low complaints overall, and the vast majority are related to utility billing issues. When we’re talking about community solar, the customer’s paying a third-party provider, but what they’re paying for is bill credits on their utility bill, so that benefit that’s getting delivered to them, that’s where they have most challenges.”
David Sandbank, director of the New York Sun program at New York State Energy Research and Development Agency, has overseen 64,000 solar installations since 2012 and said that his program doesn’t have any oversight over community DG.
“Right now, our focus is really on system performance of the main system itself,” Sandbank said. “There’s no specific protections for community solar subscribers in New York. … We have provided a lot of customer education on our website and we’ve launched a very robust digital marketing campaign to educate potential solar customers.”
Zack Dufresne, communications director at the Alliance for Clean Energy New York, asked whether the state could afford to regulate heavily.
“These regulations will take significant resources on the part of the PSC,” he said, “and I’m wondering if starting off with this maximalist position, [will] the DPS staff have the resources in place for that?”
“Let’s not have the tail wag the dog,” Weiner said. “If we feel there are certain activities that commission staff should be engaged in, we’ll make sure we have the resources.”
The FERC commissioner has said she would not seek a second term when her current one expires June 30. What she has not said is whether she will leave on that date or stay on until a replacement is nominated. (See No 2nd Term for FERC’s Colette Honorable.)
Honorable alluded to the uncertainty during a Monday luncheon address to fellow regulators, friends and attendees at the Mid-America Regulatory Conference. It was her only appearance during the conference, but it kept her long MARC attendance streak alive.
“I should have had a T-shirt made up: ‘I haven’t announced when I’m leaving, and I haven’t announced what I’m doing,’” she said.
One thing’s for sure: Honorable will spend at least the next two years in D.C. Call it returning the favor to her 16-year-old daughter, Sydney, who is still in high school.
“She loves it [in D.C.],” Honorable said. “I owe it to her. She was very good when I moved there.”
Honorable was nominated by President Barack Obama in August 2014 to fill the remainder of former Commissioner John Norris’ term. She was unanimously confirmed to the post by the Senate later in the year.
Honorable — who announced her departure in April — and acting Chairman Cheryl LaFleur have held down the fort at the quorum-less commission since February, when Chairman Norman Bay resigned.
Pennsylvania Public Utility Commissioner Robert Powelson and Neil Chatterjee, senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), were only recently nominated to fill two of the three vacancies. Both easily cleared the Senate’s Energy and Natural Resources Committee, but have yet to be confirmed by the full body. (See FERC Nominees Easily Advance to Full Senate.)
Powelson is president of the National Association of Regulatory Utility Commissioners, a post Honorable once held.
“I’m looking forward to when Rob joins us at FERC, or joins Cheryl,” Honorable said, a sly comment some in the audience missed.
An Arkansas native, Honorable was named to the state’s Public Service Commission in 2007. She chaired the PSC from January 2011 until January 2015, succeeding Paul Suskie, now SPP’s executive vice president of regulatory policy and general counsel, and one of her “work husbands.” (Her real husband died shortly before her FERC nomination.)
Acknowledging “uncertain times for regulators,” Honorable had some words of advice for those in her profession.
“We absolutely must protect our ability to work independently, no matter who is in office,” she said. “I want to urge you to stay true to that. I would have been shocked if the White House called and asked me to vote on something in a certain way. Keeping the lights on, reliably and safely, does not have a political or ideological bent.”
Honorable’s fellow regulators responded with a standing ovation, perhaps her last as a FERC commissioner.
She has no regrets about her decision.
“At the end of the day, I’m proud I kept the consumers first in my work,” she said. “It doesn’t mean I’ve been anti-business. In fact, I was shocked to read an article that described me as pro-business. It just shows I can work pragmatically by bringing together people from both sides of the aisle.”
For some time, PJM has found itself in a no-win situation, pitting stakeholders valuing market consistency against those seeking flexibility to integrate changing ideas and technologies.
From technological advancements that have reduced demand, to the shale gas boom that has upended the supply stack, to governmental actions that have artificially buoyed preferred technologies, what’s an RTO to do?
| PJM
“Increasingly, public policies seek to recognize value associated with generation plants beyond their cost effectiveness and reliability attributes,” PJM said in an explanatory document released last week. “The most recent iteration of state policies has involved explicit, legislatively driven subsidies for specific generating units. These types of subsidies can suppress wholesale electricity market prices and threaten these markets’ basic design mission.”
But through that document and three supporting papers, PJM believes it has found a way forward. The RTO published the document along with the last two of three working papers that each focus on addressing different aspects of the issue.
The first, published the same day as a May FERC technical conference analyzing the viability of energy markets, offered guidelines for how states could work with PJM to develop carbon pricing rules that integrate with existing market structures. (See PJM Stakeholders Offer Different Takes on Markets’ Viability.)
The second, published last week as an update of a proposal PJM floated last year, outlines a two-phase capacity auction that would allow subsidized resources to be counted as available reserves without influencing the clearing price. (See PJM’s Grid 20/20 Ponders Mixing Public Policy, Competitive Markets.)
Also published last week was a third paper containing ideas initially advanced in PJM’s response to its Independent Market Monitor’s 2016 State of the Market report. In it, the RTO proposes tweaks to its energy market design to address complaints that market factors — both naturally developing and artificially introduced — have improperly depressed clearing prices so that true real-time costs aren’t being accurately reflected. The grid operator argues that its price-setting logic should be revised to allow inflexible units to set LMPs. (See PJM Differs with Monitor in State of the Market Response.)
“Since the inception of competitive wholesale electricity markets, the industry has evolved significantly and in ways that could not have been fully anticipated,” the document said. “Technological disruptions … have altered the economics of electricity supply, creating new opportunities and challenges. … These shifts in economic trends and market dynamics could lead to an unintended bias in the energy markets favoring lower capital cost resources … [putting] financial stress on all units, but particularly large units with high capital costs.”
The proposals face an uphill battle for acceptance. Stakeholders have criticized PJM for filing some of the ideas with FERC as additional testimony during the technical conference. The Monitor opposes the proposed changes to the LMP-setting logic.
| PJM
Market participants have also expressed concerns with the RTO’s two-phase capacity-auction proposal. And carbon pricing was a tough sell long before President Trump set out to eliminate his predecessor’s signature Clean Power Plan. (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.)
PJM acknowledges the work ahead. The capacity proposal, it said, “likely will be evaluated with other potential solutions” by the Capacity Constructs/Public Policy Senior Task Force, which has been meeting regularly since January and remains mired in foundational discussions on the basic goals of a capacity construct. (See PJM Capacity Task Force Debates the Value of Price Transparency.)
The other proposals haven’t found a home for discussion yet, but the RTO is confident something must be done.
“I certainly think a do-nothing approach going forward puts the goals of the markets in general at risk,” Stu Bresler, PJM’s senior vice president of operations and markets, said at PJM’s Grid 20/20 conference on the issue last August. “The risk of a do-nothing approach is a detrimental effect on the long-term price signal.”
Steve Huntoon’s March 13 column “Microgrid Kool-Aid and National Security” reviews the Noblis report “Power Begins at Home: Assured Energy for U.S. Military Bases” and raised a number of issues that he claims invalidate the study’s conclusions. Huntoon’s claims and conclusions are seriously flawed.
Huntoon cites a recent Government Accountability Office report that found outages can be attributed to on-base problems as opposed to the utility. He states that outages attributed to on-base issues cannot be solved: “if they were easily avoided, they would be.” From this statement he concludes, incorrectly, microgrids cannot be the solution.
Our report specifically acknowledges that problems with on-base distribution systems must be corrected prior to using a microgrid and in most cases this can easily be accomplished. Currently, some outages on military bases are completely due to the utilities that serve the base (Fort Irwin), while others are due to on-base infrastructure issues (Camp Lejeune). Fixing these on-base problems is well understood and routinely done. Simple activities such as tree trimming, routine maintenance and, when needed, undergrounding of distribution systems can and do reduce the issue to near zero. Fort Belvoir has demonstrated this through these actions over the last several years.
The main reason it has not been done at all bases is well recognized at the Defense Department and is the driver for utility privatization. Maintenance of on-base utility systems has been underfunded for decades. Fort Belvoir is a perfect example. Upon privatizing the on-base utilities, the frequency of outages attributed to on-base issues began to rapidly decline to near zero.
Huntoon argues that microgrids place military installations at risk to cyber threats. He implies that this risk should not be taken.
As the report explicitly states, cyber risks are real and must be addressed, but this was not the focus of our study. If you believe that cyber risks should be always avoided, then you cannot have advanced meters, smart buildings or network anything (including weapon systems). You network things because it buys performance advantages, as in the case of microgrids, and if you own the network you can manage that risk. Huntoon seems unaware that cyber protection for microgrids exists. Cybersecurity solutions for microgrids have been demonstrated on bases by the government’s Environmental Security Technology Certification Program and its Smart Power Infrastructure Demonstration for Energy Reliability and Security (SPIDERS) program.
Huntoon says, “please note one other glaring oversight in the study. This one involves the estimated cost of microgrids.” He claims the study’s estimated costs are grossly wrong by comparing numbers he incorrectly quotes from the report with recent costs for a project at Marine Corps Air Station Miramar.
His comparison of our estimates and a real-world example at Miramar are grossly in error. He quotes our number for the capital costs of an all diesel generator system rather than the costs for one that is half natural gas and half diesel like Miramar. The numbers he should have quoted from the report, which are relevant to Miramar, are twice the numbers he does quote. In addition, he ignored the costs of two microgrid control stations as well as other upgrades. In fact, our cost estimates, constructed prior to the award of the Miramar contract, when compared apples to apples is within 10% of the actual costs.
In the conclusion, Huntoon states, “And speaking of fact, the nation’s ‘flagship’ microgrid at the University of California, San Diego flunked its acid test in the Southwest Blackout of 2011. The campus shut down with the rest of San Diego.” He implies that microgrids don’t work.
UC San Diego Microgrid | UC San Diego
No one in the microgrid technical community believes that the U.C. San Diego microgrid is the “flagship” example. Using a decade-old, university-based microgrid as an example is strange at best. Dozens of microgrids have been demonstrated in recent years. They all operate as designed during outages and provide assured power. For example, the White Oak microgrid, which is described in the report, has maintained power during dozens of outages, never experienced a failure and is saving money each year.
Jeffrey Marqusee, Ph.D., is chief scientist for Noblis, a nonprofit science, technology and strategy organization whose clients include many federal government agencies.
CAISO on Monday called on consumers to voluntarily conserve energy this week as scorching heat drove up electricity usage and caused outages in Pacific Gas and Electric’s service territory.
The ISO issued a “flex alert” effective 2 to 9 p.m. on Tuesday and Wednesday, with peak load expected to break 47,000 MW both days in the face of triple-digit temperatures. The alerts are issued when the grid is “under stress” from generation or transmission outages, or persistently high temperatures, the ISO said.
This week’s expected peaks would be more than 90% of CAISO’s all-time peak demand of 50,270 MW, set on July 24, 2006.
By late Monday, the ISO forecast that the day’s peak demand would hit about 44,600 MW, well short of an earlier forecast of 46,500 MW.
Temperatures soared up to 110 degrees in California’s interior, the most intense heat wave to hit the state since the summer of 2013. Multiple days of extreme heat are stressing equipment and causing some outages. PG&E still had 4,200 customers without power as of Monday morning, with about 189,000 customers initially affected.
“This is a heat wave, and we have got all our generation that we can make available made available to us,” CAISO spokesman Steven Greenlee said during a media call held jointly with PG&E.
An extended period of very hot weather is expected across the interior portions of southwest California through the middle of the week, and temperatures could reach 112 degrees in parts of the state, the National Weather Service said as it issued a heat advisory.
