VALLEY FORGE, Pa. — PJM is expecting “typical” temperatures and almost 50,000 MW of capacity beyond its projected peak load for the first winter using Capacity Performance, PJM’s Chris Pilong told the Operating Committee last week.
While recent winters were impacted by anomalies such as El Nino, weather this season is likely to be about “average,” he said. PJM’s installed capacity for the winter is 183,665 MW, with 177,525 MW committed through the Reliability Pricing Model. The forecasted peak load is 135,548 MW.
“Average temperatures aren’t going to be what’s driving us as far as peak-load days,” he said. “It’s going to be the outliers.”
Natural gas-fired capacity has increased by 17,225 MW since the polar vortex nearly three years ago to 61,513 MW, he said, about 35% of committed capacity. Of that, about half — 31,946 MW — is committed through CP.
| PJM
An Operations Assessment Task Force assessment of pipeline-disruption sensitivity found no reliability issues for base and N-1 analyses, Pilong said. “The good news was even under the worst-case scenario, everything was solid,” he said.
By the end of the year, an additional 2,800 MW of generation will have been brought online since this summer, he said. The system also will have the benefit of transmission upgrades on the Baltimore Gas and Electric, Dominion, Commonwealth Edison and American Electric Power systems.
PJM Moves to Cut Operator-Training Grace Period in Half
The grace period for dispatchers at utilities’ market operations centers and small generation plants to complete initial training will be reduced from 12 months to six months in revisions PJM is proposing for Manual 40.
“Our long-range plan is to get that number [for the allowable grace period] to zero,” PJM’s Glenn Boyle said. “What we’re saying is that’s too much exposure risk.”
He said PJM is hoping to have the grace period removed entirely by next year.
Regulation Requirement Changing from ‘Peak’ to ‘Ramp’
PJM is proposing to change the way it sets regulation requirements, replacing the targets for on- and off-peak periods with those for on- and off-ramp intervals to better capture seasonal system conditions.
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The revisions, which will be incorporated in Manuals 11 and 12, were recommended by the Regulation Market Issues Senior Task Force.
The lower regulation requirement of 525 effective MW, which currently applies during off-peak hours of midnight to 04:59, would apply during off-ramp hours. The requirement for the on-peak hours of 05:00 to 23:59 would be applied to the on-ramp and increase from 700 to 800 effective MW.
On- and off-ramp periods will vary by season. From Sept. 1 through Nov. 30, for example, the on-ramp period will be hours ending 6:00 through 8:00 and 18:00 through 24:00. For the winter, the morning ramp starts one hour earlier and ends one hour later while the evening ramp begins an hour earlier.
The seasonal periods will be posted on the RTO’s website. PJM’s Eric Hsia said he plans to also announce them at the Operating Committee meetings starting two months prior to the beginning of the affected season.
PJM Won’t Pay for Frequency Response Under FERC NOPR
FERC’s Nov. 17 rulemaking that would require most new generators to have primary frequency response capability left it to individual RTOs to decide if compensation is warranted for the service, and PJM currently believes it’s not, Hsia said.
The rule would apply to both synchronous and nonsynchronous facilities as a condition of interconnection. Nuclear units are exempt.
Hsia said he didn’t agree with the argument that generators should be compensated for lost-opportunity costs, noting that the Notice of Proposed Rulemaking would not require them to preserve “headroom” for the frequency response when offering their output for sale (RM16-6). (See FERC: Renewables Must Provide Frequency Response.)
He acknowledged “ongoing conversation” on the topic, however. Comments on the NOPR are due to FERC on Jan. 24.
Members Question Redundancy of Pseudo-Tie Efforts
Members asked PJM staff why the RTO is seeking to create a pro forma pseudo-tie agreement when the issue of pseudo-ties is already being discussed by the Underperformance Risk Management Senior Task Force.
“The lack of this agreement has resulted in a lack of uniformity,” PJM’s Jacqui Hugee said.
Staff wanted to develop such a document for the task force but couldn’t complete it fast enough to avoid delaying the task force’s progress, she said. The effort to develop a pro forma document is being done in coordination with the task force, she said, and PJM doesn’t plan to make multiple filings on the topic with FERC. (See related story, MISO Stakeholders Narrowly Support New Pseudo-Tie Rules.)
FERC on Thursday ordered hearing and settlement procedures in a dispute between Entergy and its customers over the company’s accounting for income taxes and post-retirement benefits in its formula rates tariff (ER16-1528).
The commission said the dispute raised unresolved factual issues and that Entergy’s proposed formula rate changes may be unjust and unreasonable. It made the changes effective June 2015 and June 2016 but suspended them pending the settlement proceedings. The order consolidated two dockets, ER15-1436 and ER15-1453, with ER16-1528.
The multiple dockets stem from February 2013, when Entergy first filed proposed transmission formula rate templates to recover its transmission revenue requirements as a MISO member. The proposed rates were modeled on MISO’s Tariff but incorporated practices established under Entergy’s previous tariff for its operating companies.
In July 2015, Entergy reached a partial settlement on the formula rate templates with several customers, including the South Mississippi Electric Power Association and Arkansas Electric Cooperative Corp. By then, however, Entergy had already proposed two changes to the rate templates related to income taxes and retirement costs that were not reflected in the settlement.
The customers protested, contending that the changes did not reflect established practices under the Entergy tariff and were unsupported by its “grossly deficient” filing. They said Entergy’s claim for recovery of $612.7 million in prepaid pension costs was unjustified and could increase its transmission revenue requirement by $8 million annually.
Entergy said the pension costs would increase rates by only $1.3 million per year.
GridLiance moved one step closer to joining CAISO as a participating transmission owner after the ISO’s Board of Governors voted Dec. 15 to approve the company’s membership.
GridLiance says its purchase of Valley Electric’s 230-kV network represents a long-term commitment to the co-op and California’s energy development. | Valley Electric Association
Nevada-based Valley Electric is the ISO’s only transmission-owning member outside California. The cooperative provides power to about 45,000 customers in a 6,800-square-mile service territory along the California-Nevada border.
The transmission assets being transferred include 164 miles of 230-kV lines linking Valley Electric’s base in Pahrump, Nev., with both Las Vegas and the Mead substation — a major delivery point for power wheeled into California. Valley Electric completed the network in 2013 in order to improve reliability for its sprawling but sparsely populated service area.
As part of the deal, GridLiance has said it will reinforce the ISO’s interconnection with Nevada’s Eldorado substation, another major wheeling point into California.
Valley Electric saw the value of its network increase significantly after the co-op joined the ISO in 2013. It will recover about 2.4 times its investment.
Chicago-based GridLiance acknowledged that it is paying top dollar for the assets, saying they will provide the company with a foothold in an area that bridges the California market with the interior West.
“We did pay a premium to enter this relationship,” GridLiance CEO Ed Rahill told the CAISO board ahead of its vote. “And if you think about that, it’s only because our commitment is so many decades into the future that it becomes insignificant.”
Under the agreement, Valley Electric will still operate and maintain the system. The acquisition is not expected to affect the co-op’s distribution system.
“Our relationship with Valley is going to continue as a long-term partnership to help the region and the community through economic development and energy projects that benefit not just Valley but the California ISO and California,” Rahill said.
Valley Electric CEO Thomas Husted said the co-op joined the ISO because it is a “strong proponent” of regionalization.
“The sale of those assets does not change that position,” Husted said. “We will continue to be a load-serving entity and a [participating transmission owner] within the California ISO.”
Husted said the network was built to serve Valley Electric’s load, provide reliability and foster development of renewable assets that will continue to support regionalization.
“That [regionalization] now is growing beyond Valley Electric’s original mission and beyond our charter,” Husted said.
The board’s approval is conditioned on GridLiance executing a transmission control agreement with the ISO and FERC accepting the company’s transmission owner tariff and revenue requirement.
GridLiance would be the 17th transmission owner to join the ISO.
Launched in March 2015 with backing from the Blackstone Group, GridLiance bills itself as the nation’s first competitive transmission company focused on collaborating with public power entities. It made its first two acquisitions — 420 miles of 69-kV and 115-kV lines in Missouri and Oklahoma — a year ago. (See GridLiance Makes First Acquisitions.)
VALLEY FORGE, Pa. — PJM is preparing several proposed rule changes in response to FERC Order 825, which requires RTOs to align their settlement and dispatch intervals and implement shortage pricing.
PJM’s Ray Fernandez walked the Market Implementation Committee through planned Operating Agreement and Tariff revisions that would be part of a compliance filing planned for Jan. 11. The changes would calculate balancing operating reserve deviations in five-minute intervals but aggregate charges and credits daily for allocations. (See “More Adjustments for Five-Minute Settlement,” PJM Market Implementation Committee Briefs.)
Fernandez’s presentation included an example in which a unit with no net deviations during a day would have incurred balancing charges under the current process but wouldn’t under the proposed one.
“With the proposal that PJM has, we wouldn’t be breaking down [imbalances] to the bus level,” he said. “It minimizes the pot of dollars that we’re charging.”
Stakeholders, however, voiced skepticism on multiple points. Brock Ondayko of American Electric Power expressed concern that units might not be able to follow generation signals so precisely and risk incurring additional penalties.
Generators are “basically chemical factories whose byproduct is energy” and “don’t necessarily follow things perfectly,” he said. “We’re never right on. … I’m concerned that the quantity of operator imbalance could be increased significantly.”
Other members questioned who would lose out on the changes, noting that reduced charges for one unit implies reduced credits for someone else.
“Whether it’s a positive impact on balancing congestion or a negative one is unclear,” Direct Energy’s Jeff Whitehead concluded. “I’m trying to understand the tradeoffs.”
In a separate presentation, PJM’s Lisa Morelli unveiled proposed revisions to the operating reserve demand curve, which PJM believes are necessary to appropriately implement Order 825’s five-minute interval requirement. PJM hopes to submit the revisions as a Section 205 filing around March 1.
| PJM
The revisions would add an additional step in the curve at the $300 penalty factor that would allow the reserves to be “extended,” or increased. Currently, reserve requirements can only be extended in specific situations related to the issuance of hot or cold weather alerts.
PJM increased the day-ahead scheduling reserve requirement for 901 hours between January 2015 and September 2016, almost 6% of total hours. On average, PJM increased the requirement by 5,000 MW.
While Order 825 specified a May 11, 2017, implementation date, PJM plans to request implementation of its proposals on five-minute settlements and shortage pricing simultaneously on Feb. 1, 2018. It would seek a response by Feb. 15.
If FERC approves the delayed implementation date, PJM would relax its timeline for the 205 filing until April. Otherwise, it will keep its March 1 target for the 205 filing and request shortage pricing be implemented simultaneously with five-minute settlements.
Rules on Fuel-Cost Policy Revocations Continue to Hang Up Approval
Despite assurances from PJM that the revocations are very unlikely to be used and are meant as a last resort in the event of fraud or some other egregious problem, members were not satisfied.
“I think we’ve spent more time talking about this than we will ever spend using it,” PJM’s Steve Shparber said. “This is not expected to occur likely ever.”
“From a culture standpoint, it strikes me as something we should not be doing to write things up that we think will never occur,” countered American Municipal Power’s Ed Tatum. “I just think it’s inappropriate. It’s impossible. And if we’re going to do it, let’s do a good job of it. … What we’re talking about right now is some language that is unclear as to how it’s going to work.”
He and other stakeholders argued that PJM hadn’t clearly defined parameters for issuing a revocation. Bob O’Connell of PPGI Fund A/B Development expressed concern that PJM appeared to be implying it would be making judgments about whether operators were committing fraud.
Joe Bowring, PJM’s Independent Market Monitor, questioned the RTO’s insistence on getting the fuel-cost policy revisions approved prior to any requirement from FERC.
“Why wordsmith it now when there’s no order?” he asked.
Bowring also said his office is “remaining agnostic” on variable operations and maintenance costs and “not focusing on VOM primarily at the moment.” He later clarified that he was talking about whether it should be included in fuel-cost policies, not whether he planned to investigate them as part of validating cost-based offers.
“We haven’t done a lot of work on validating” offers, PJM’s Adam Keech said. A multi-phased approach may be adopted, depending on the result of the fuel-cost policy proposal, he said.
The rule’s effective date is Feb. 21, but PJM’s compliance filing isn’t due until May 8, so the RTO intends to implement its final plan immediately following the compliance filing.
Bowring suggested asking FERC to clarify its wishes on the topic. The current plan “doesn’t seem like a great process,” he said.
Exelon’s Sharon Midgley spoke passionately in opposition to PJM’s proposed alternative to the current credit requirements for participation in financial transmissions rights auctions, but she found no other vocal support.
Under current rules, FTR credit requirements are calculated in two parts: one based on price and the adjusted historical values of individual FTRs, and the second a portfolio-based “undiversified credit adder” applied to net counterflow portfolios.
Some FTR holders sought an alternative, saying the undiversified adder caused clearing delays and credit uncertainty.
The alternative, previously approved by the Credit Subcommittee, eliminates the portfolio adder in exchange for increasing the historical adjustment factor in underlying credit calculations for historically counterflow paths from 10% to 25%.
“We do think they increase our credit requirements,” Midgley said. No one shared her concern, however, and the proposal was endorsed 88-34 with 15 abstentions.
PJM, IMM Partner on Capacity-Replacement Revision
In a swift response to rule changes they felt weakened market safeguards, PJM and the Monitor presented a jointly developed proposal to again revise Manual 18.
At November’s Markets and Reliability Committee meeting, members ignored objections from both PJM and the Monitor and approved Manual 18 revisions that allowed for immediate replacement of capacity obligations. PJM had offered an amendment to the proposal that would have addressed its concerns, but it never came to a vote, as the original proposal was endorsed. (See “Citigroup Wins Change on Capacity Resales,” PJM Markets and Reliability and Members Committees Briefs.)
The Monitor filed a complaint with FERC in response and joined PJM in proposing the newest revision, which is similar to their original amendment. At least some stakeholders were receptive.
“The IMM has convinced Calpine that we do need to put something in place,” said David “Scarp” Scarpignato in noting his company’s support of the new proposal.
Bowring said it was “not as strong as the optimal rules” and suggested returning to the previous protocols if the current proposal wasn’t satisfactory, but stakeholders said the proposal broached issues that needed to be addressed.
Operating Parameters, ARR Enhancements Endorsed
Members endorsed by acclamation and with little discussion new definitions for operating parameters and rule changes regarding residual auction revenue rights.
The updated definitions for “soak time” and “minimum run time” affect several manuals and governing documents. (See “Monitor Concerns Delay Operating Parameter Revisions,” PJM Market Implementation Committee Briefs.)
The changes on residual ARRs, proposed by Exelon and Direct Energy, will require PJM to run another simultaneous feasibility test proration with all negatively valued bids removed. (See “Stakeholders Debate ARR Changes,” PJM Market Implementation Committee Briefs.)
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
NOTE: There is no Members Committee meeting this month.
PJM Manuals (9:40-10:10)
Members will be asked to endorse the following proposed manual changes:
Manual 10: Pre-Scheduling Operations. Revisions reflect periodic review and clarify rules around maintenance outage recalls.
Members will be asked to endorse revisions to Manual 18: Capacity Market regarding the immediate replacement of capacity obligations. (See “Citigroup Wins Change on Capacity Resales,” PJM Markets and Reliability and Members Committees Briefs and “PJM, IMM Partner on Capacity-Replacement Revision” in this edition’s PJM Market Implementation Committee Briefs.)
Residual ARR Enhancements (10:40-10:55)
Members will be asked to endorse a rule change concerning residual auction revenue rights that was approved last week by the Market Implementation Committee. The changes, proposed by Exelon and Direct Energy, will require PJM to run another simultaneous feasibility test and pro rata distribution with all negatively valued bids removed. (See “Stakeholders Debate ARR Changes,” PJM Market Implementation Committee Briefs.)
FTR Undiversified Credit Adder (10:55-11:15)
Members will be asked to approve proposed revisions to the undiversified credit requirements for participation in financial transmissions rights auctions that were approved last week by the Market Implementation Committee. Under current rules, FTR credit requirements are calculated in two parts, one based on price and the adjusted historical values of individual FTRs, the second a portfolio-based “undiversified credit adder” applied to net counterflow portfolios — a process that some said caused clearing delays and credit uncertainty. The new rules eliminate the undiversified portfolio adder in exchange for increasing the adjustment factor in underlying credit calculations for historically counterflow paths from 10% to 25%.
Market Implementation Committee Charter (10:25-10:30)
Members will be asked to approve the updated MIC Charter, which eliminates references to “working groups.” (See “‘Working Groups’ Removed from MIC Charter,” PJM Market Implementation Committee Briefs.)
Summer resources in PJM’s market are approaching a tipping point. After April 2017, resources such as demand response and solar generation will effectively no longer be able to participate in PJM’s capacity market. As a result, they will no longer be able to earn the revenues that many rely on to stay in operation and to remain available during periods of peak customer demand.
This outcome is precipitated by PJM’s requirements that all resources meet strict winter performance requirements, or otherwise partner with winter-performing resources like wind generation, in order to bid into its next three-year forward capacity auction.
PJM has recognized this problem regarding retention of seasonal resources, and they have made moves to prevent the undesirable outcome. (See PJM to Seek FERC OK for Seasonal Capacity Proposal.) Under a recent proposal pending before FERC, PJM would make certain modifications to its summer-winter resource aggregation approach (ER17-367). However, past auctions have not yielded any viable participants in its resource aggregation program.
Musical Chairs
Even if all seasonal resources participated, aggregation can never fully solve the problem: Nearly 10,000 MW of summer-only DR and approximately 300 MW solar generation currently participate, in contrast to the 2,300 MW of available wind generation.[1] In the best-case scenario, with perfect aggregation, up to 8,000 MW of summer-performing resources are left with no winter aggregation partner. Like a game of musical chairs, when the music stops, some participants have no place to land. A mismatch exists, and the issue cannot be fully solved by aggregation.
The loss of summer resources will likely result in a significant cost impact to customers. PJM’s Independent Market Monitor estimated that without seasonal resources, costs could increase between $1 billion to $5 billion across PJM. Besides the customer impacts, the market will also lose some of its cleanest sources of generation. Unlike year-round DR resources that typically have backup generators, summer-only DR often relies on reductions in onsite consumption, such as by lowering air conditioning. Solar generators previously allowed to participate based on their higher summer output also will be excluded, absent pairing with scarce winter resources.
These cross-cutting issues motivated Rockland Electric to join environmental groups, including the Natural Resources Defense Council and the DR industry group Advanced Energy Management Alliance, in a joint protest at FERC. In separate responses, state agencies and other energy companies also expressed displeasure with PJM’s proposal and the loss of summer resources.
FERC Support Should not Waver
FERC has historically supported demand-side resource and renewable generation participation in wholesale markets. FERC proposed a rule in November that would open up access for smaller resources like batteries, which often have limited runtimes, to wholesale market revenues. In Orders 719 (2008) and 745 (2011), FERC enabled market participation by DR, while recognizing its benefits for creating just and reasonable rates. Through Order 764, FERC encouraged promulgation of market rules to better include variable energy resources. Allowing PJM to block access to these summer-only resources would undermine past efforts and effectively dismantle one of the country’s largest DR markets. Instead of allowing PJM’s untested approach, FERC should direct PJM to return to their summer, winter and annual resource comparability standards.
Shelly Lyser and Joel Yu are senior energy policy advisors for Rockland Electric. Rockland Electric, a wholly owned subsidiary of Orange and Rockland Utilities, which in turn is owned by Consolidated Edison Inc., is a transmission owner within PJM.
In a MISO first, the RTO has integrated a solar farm into its day-ahead and real-time markets.
North Star, a $180 million, 100-MW solar farm outside of Minneapolis, joined MISO’s wholesale markets on Dec. 16. Xcel Energy will purchase power generated by the facility in a 25-year deal that helps the utility meet its 1.5% solar energy requirement in Minnesota.
North Star Solar Farm | D.E. Shaw Renewable Investments
The RTO said months of planning and testing went into the project to ensure a “smooth integration of solar power into MISO’s day-ahead and real-time markets.” MISO tapped forecasting firm Energy and Meteo Systems — the same firm already handling the RTO’s wind forecasting — to forecast day-ahead solar.
“This project furthers the integration of renewable resources into our markets,” said Todd Ramey, MISO vice president of system operations.
MISO said that while several large-scale solar farms have been built in the footprint in the past few years, North Star is the largest in the Midwest, with more than 440,000 solar panels on 1,000 acres of former corn and soybean fields.
“Solar power from North Star is a key element in Xcel Energy’s plan to deliver more than 60% carbon-free energy for our customers by 2030,” said Chris Clark, president of Xcel Energy-Minnesota, North Dakota and South Dakota.
MISO filed the generator interconnection agreement between North Star and Xcel on Nov. 9 (ER17-329).
The solar facility is not allowed to exceed 100 MW. The project entered MISO’s interconnection queue as a variable energy resource last September. MISO mandated about $2.2 million in network upgrades, including grading, two new 115-kV breakers and four 115-kV switches as a condition of the agreement. Xcel spent about $260,000 for interconnection facilities.
Xcel and project partners D.E. Shaw Renewable Investments and Community Energy Solar reported completing the project in mid-October after six months of construction.
MISO said this year that it has about 1,700 MW of solar generation at various stages of its interconnection queue.
Following a dramatic all-night session, Michigan lawmakers Thursday approved legislation that increases the state’s renewable portfolio standard, preserves its limited retail choice and assigns state regulators to referee battles over net metering and capacity charges.
Governor Snyder on YouTube
Gov. Rick Snyder, who had been pushing revisions to the state energy policies since 2015, personally helped broker a compromise over retail choice, meeting with legislators overnight into early Thursday morning, then shaking hands on the Senate floor after its members voted 33-4 for the package (SB 437, SB438). The House approved the bills 79-28 and 76-31 earlier Thursday afternoon, the last day of the state’s two-year legislative session. (See Michigan Senate Increases RPS; Keeps 10% Retail Choice Cap.)
The first major change in Michigan energy policy since 2008, the legislation:
Sets a 15% renewable standard by 2021, up from the current 10%, while broadening the eligibility to include geothermal and pump storage;
Sets a nonbinding goal of meeting 35% of the state’s energy needs through renewables and energy efficiency by 2025;
Maintains the state’s 10% retail-choice cap;
Creates a “backup plan,” in case MISO’s proposed forward capacity auction for its competitive retail areas is rejected by FERC or proves too expensive;
Adds cost controls to the utilities’ required integrated resource plans; and
Allows utilities to offer competitive “value-added” services to supplement rate-base revenue.
Snyder took to his official YouTube channel Thursday to tout the bill, which he said would address concerns of a capacity shortfall. The state expects to lose 5,000 MW of coal-fired generation over the next seven years — pushing the state’s reserve margin down to 15%. Over the next 15 years, the state could lose 30% of its generation.
“What we’re in is a huge transition in how we get our energy,” Snyder said. “We’ve got a lot of aging coal plants that are beyond their useful life, and it’s not worth investing in them anymore. … We can transition to both natural gas and renewables and let the markets sort of define the balance between those two, so we’re moving away from an old energy source [where] we had to import all of this coal.”
Snyder also said he hoped the legislation would lead to more investment in solar power.
Capacity ‘Backup Plan’
To ensure the state has adequate capacity, the legislation requires a “much more robust” integrated resource planning process, said Greg Moore, legislative director for state Sen. Mike Nofs, one of the authors. Utilities will have to prove generation they build or buy is “the most reasonable and prudent” alternative. The IRPs, which must be filed every five years, will be expected to include provisions for energy efficiency, distributed generation and demand response, Moore said.
| Tradewind Energy
The bill also requires the Public Service Commission to conduct a contested hearing on whether a state capacity charge is “more cost-effective, reasonable and prudent” than MISO’s proposed forward capacity auction in meeting the RTO’s local clearing and the planning reserve margin requirements. If FERC fails to approve the forward auction by Sept. 30, 2017, the PSC will establish a “state reliability mechanism,” including a capacity charge. (See related article, MISO Forward Auction Filing Draws Protests.)
The commission would make separate findings for each utility service territory. If the commission implements a state capacity charge, it would remain in effect for at least four planning years unless that conflicts with the FERC ruling on MISO’s proposal.
MISO spokesman Jay Hermacinski said the RTO had no comment on the bill. “We really need to see what FERC’s going to do,” he said. “Once FERC’s made its decision then we’ll move forward. As we’ve done the last year and a half, we’ll be working with Michigan to come up with the best solution possible.”
The PSC also was directed to conduct a proceeding within one year on whether customers participating in net metering or distributed generation program should be charged a grid usage fee. It will consider both the costs net metering customers impose on the grid and the benefits they provide, said Moore.
Retail Choice Compromise
| DTE Energy
Some House Republicans had threatened to oppose the bill, fearing that a proposed capacity charge on competitive suppliers would kill the state’s retail-choice program. The state’s dominant utilities, DTE Energy and Consumers Energy, had sought the charge, accusing their competitors of being free riders.
“The question is how do you balance these all out, and I’m proud to say we got all of these groups largely to come to a strong agreement by finding some good middle ground,” Snyder said.
The legislation bars retail customers who return to their home utility after using an alternate supplier from returning to a competitor for six years. It also stipulates that if competitive suppliers lose customers and demand dips below the 10% threshold, the new, lower retail-choice percentage would become the new cap for six years. The competition program reportedly has a waiting list of about 11,000 customers.
Notwithstanding the cap, customers currently receiving all of their power from competitive suppliers would be able to increase their competitive loads at the existing or adjacent facilities.
Utilities would be allowed to supplement their rate-base revenues through “value-added” programs and services “if those programs or services do not harm the public interest by unduly restraining trade or competition in an unregulated market.”
Reaction
Consumers Energy Headquarters | Consumers Energy
DTE and Consumers both commended the bills’ passage.
DTE praised the increased renewable mandates and preservation of the state’s retail-choice market while adding reliability obligations. “It addresses these issues in a fair and constructive way and provides a framework for the state to plan for its own energy future,” DTE said in a statement.
Consumers said the “sound energy policy legislation [ensures] that our state has a comprehensive plan for ensuring electric reliability and affordable and sustainable energy going forward.”
The Michigan Environmental Council said the final bill was a “vast improvement” over earlier proposals that would have eliminated the RPS. “This deal will save millions of dollars a year for Michigan residents by continuing to eliminate energy waste and increasing investments in wind and solar power, which are the cheapest ways to produce electricity,” the group said.
The conservative Michigan Freedom Fund said the revised package “eliminates every anti-choice ‘poison pill’” in earlier versions of the legislation.
Although the bills ultimately won broad bipartisan support, not everyone was happy with the result. Republican Sen. Patrick Colbeck told Detroit station WXYZ that the bills were rushed through and that he did not support leaving electricity cost decisions in the hands of the PSC.
MISO’s proposed three-year forward auction in its retail-choice areas attracted more than 40 comments and protests, with critics calling the proposal costly and ill-conceived.
Executive Director of Market Services Jeff Bladen has said the proposal, which would take effect in the 2018/19 planning year, is designed to provide equally valued capacity from both merchant generators and regulated utilities (ER17-284). The comment period on the FERC filing closed last week; MISO expects a decision from the commission by March. (See MISO Files Forward Capacity Auction Plan with FERC.)
Among critics of the plan are MISO’s Market Monitor, which says the auction, with a sloped demand curve for competitive retail areas, will not accurately represent the marginal value of capacity. “The proposal is highly likely to result in unstable prices that are either too low to retain existing supply that is needed or excessively high, attracting new resources that are not needed,” Monitor David Patton said.
The Brattle Group’s sloped demand curve in red | The Brattle Group
In his protest, Patton included a proposal for a two-stage prompt auction for FERC consideration. Competitive retail supply would still use a sloped demand curve and regulated utilities would use a vertical demand curve.
Premature?
The Illinois Office of Attorney General objected to the bifurcation of the capacity market. “By separating Illinois from the rest of MISO through the use of a three-year forward auction, as opposed to the prompt auction applicable to the remaining 90% of MISO load, Illinois consumers would pay higher prices for capacity,” the office said.
Watchdog group Public Citizen said MISO did not have enough conversations with state lawmakers on their resource adequacy plans before making the filing, which he said will increase the cost to ratepayers. “This whole filing is a solution in search of a problem,” Tyson Slocum, the group’s energy program director, said in an interview. “That’s the whole problem with holding stakeholder meetings, it’s whoever shows up.”
“At a minimum, FERC should suspend issuing an order in this docket until the legislative actions of Illinois and Michigan to address long-term resource adequacy can be independently analyzed and incorporated into this docket,” Public Citizen wrote, referring to Illinois’ financial support for Exelon’s Clinton and Quad Cities nuclear plants and energy legislation approved by Michigan last week. (See Illinois Lawmakers Clear Nuke Subsidy and related story Michigan House Passes Energy Bill, Preserves RPS, 10% Retail Choice Cap.)
‘Blind Faith’
The Coalition of MISO Transmission Customers and the Illinois Industrial Energy Consumers filed a joint protest asking FERC to reject the filing because MISO did not fully include the results of The Brattle Group’s study, which the RTO relied on to justify the forward auction. The filing instead contained a MISO description of the study, demand curve diagrams, presentations made to MISO stakeholders by Brattle and testimony from three Brattle employees.
“The commission should not accept, on blind faith, that the Brattle study appropriately supports MISO’s endeavors,” the groups said. They also challenged Brattle’s analysis as biased. Alliant Energy and others challenged MISO’s reliance on the results of the OMS/MISO survey, which forecasts generation shortfalls in 2018. The company said the survey is not a “complete reflection of the future capacity needs in the MISO region.”
Results of the 2016 MISO-OMS Survey | OMS, MISO
A group of transmission-dependent utilities in the Midwest — Madison Gas and Electric, Missouri Joint Municipal Electric Utility Commission, Midwest Municipal Transmission Group, Missouri River Energy Services and WPPI Energy — argued the proposal is “fraught with inconsistencies, errors and ambiguities” that could cause the provisions of the forward market to bleed into noncompetitive areas. The group asked FERC to reject it.
Interference
Power marketer Direct Energy, which offers competitive natural gas plans for Michigan ratepayers in Consumers Energy and DTE Energy territory, objected to MISO’s Tariff revisions to allow retail-choice states to opt out of capacity provisions via the auction design’s prevailing state compensation mechanism. The company is challenging the filing on the basis it “impermissibly” interferes with wholesale markets.
Ron Carrier, Direct Energy’s director of government and regulatory affairs, said he isn’t sure if the limited amount of participating generation and load from retail choice areas would make the forward auction economic, although he said forward auctions in general “allow some price certainty into the future.”
“Our main concern is the state shouldn’t be granted authority over something FERC should have authority over,” Carrier said.
MISO Transmission Owners said they had no opinion on the filing, but they asked FERC to make sure the RTO does not intrude on state jurisdiction over resource adequacy. They also asked FERC to require MISO to give annual reports that analyze the impact of the forward auction on the entire footprint for the next three years.
The Organization of MISO States also argued for protecting state jurisdiction, but the group took a step further, asking FERC to reaffirm the stance it took in a 2012 order that capacity markets are not necessary in vertically integrated areas (ER11-4081-001). “The [competitive retail solution] should not be viewed as the default means to maintain [resource adequacy] within retail-choice areas. It is imperative that state regulators maintain maximum flexibility and authority over the resource adequacy decisions within their jurisdiction,” OMS wrote.
AUSTIN, Texas — ERCOT celebrated a trio of memorable anniversaries Tuesday by getting part of the band back together for its Annual Membership Meeting.
ERCOT, which became the first ISO in the U.S. 20 years ago, also marked its 15th anniversary as the single control area for the state’s competitive market and the 75th anniversary of the Texas Interconnected System, when the state’s utilities banded together to ship power to the shipyards and refineries on the Gulf Coast during World War II.
“We remain the only independent, state-controlled system operator,” ERCOT CEO Bill Magness told the membership, “and we like it that way.”
To mark the occasion, ERCOT unveiled a historical video and brought back its first Board of Directors chairman, former Oncor president Mike Greene, to introduce one of the primary architects of the state’s electric restructuring bill as the meeting’s guest speaker. Steve Wolens, a retired 12-term Democratic state representative, worked with Republican State Sen. David Sibley to push Senate Bill 7 through the Texas Legislature in 1999 against only four opposing votes.
Greene name-dropped former Texas PUC commissioner and current ERCOT Director Judy Walsh, former FERC and PUC commissioner Pat Wood and others from the past before eventually introducing Wolens.
“My role has been reversed. I’m standing at the microphone, and Steve is in the audience wondering what I’m going to say,” Greene said, before taking a pause. “I’m actually starting to enjoy this.”
“It’s an honor to be back,” said Wolens, pegged by Texas Monthly in 1999 as the “Intellectual Gladiator” for his legislative work. The magazine noted Wolens “produced an electricity deregulation bill that won the support of consumers, environmentalists and utilities.” When the bill passed, Wolens’ colleagues honored him with a standing ovation.
Wolens, who also led a push to reform ethics laws before retiring from the Legislature in 2005, was recently named by Texas House Speaker Joe Straus to serve on the Texas Ethics Commission. His term will last until November 2019.
Recounting SB7’s history, Wolens said “there was no reason to restructure in the 90s,” given Texas had the lowest electric rates in the country. However, the state also had some of the highest bills ($1,064 annually for the average residential customer, he said) and a reserve margin that was predicted to drop below 8% by 2004.
“And here we were in Texas, boasting about the state and boasting about our growth.”
Wolens said the inability to get energy companies to invest and Ohio-based American Electric Power’s announcement that it would acquire Dallas-based Central and South West Corp. in 1997 gave the restructuring legislation a boost.
“We had to bring more certainty, more reliability to the market,” he said. “Our goal was to reduce the risk to private investment and do whatever we could to keep the local companies we had.”
The key to SB7 was its price-to-beat (PTB) measure, Wolens said. The bill required incumbent utilities to take a 6% rate cut and hold that for three years, or until they lost 40% of their previously regulated market share.
This was to discourage what Texas had seen in other restructured markets, Wolens said. “We had seen it all,” he said, referring to trucking, banking and airline deregulation. “Once you deregulate, the incumbent in that particular industry, the powerful player, cuts rates and drives everyone else out of business. The three years allowed new competitors to come in.”
And that’s exactly what happened in the ERCOT market. Wolens noted nearly 200 residential retail electric providers currently operate in the state, offering in his estimation some 2,000 plans to choose from. The ERCOT market will record its lowest average energy prices this year ($24.64/MWh) since the market opened ($25.64/MWh in 2002).
“The PTB was the DNA of the entire bill,” Wolens said.
SB7 and the ensuing $7 billion Competitive Renewable Energy Zone transmission project, which connected windy West Texas with the growing urban population centers to the east, has given the state almost 18,000 MW of installed wind capacity. If the Lone Star State were its own country, it would rank sixth in the world in wind capacity.
The Texas market is so strong, Wolens said, it will survive a future that may include the country’s withdrawal from the Paris Agreement, the loss of wind and solar tax credits and “installing a climate denier” at EPA.
“All those issues aside, it’s not going to make a difference because the market is vibrant,” he said. “It’s exactly what we hoped for in 1999.”
Magness Celebrates ERCOT’s Achievements
Magness listed ERCOT’s 2016 achievements before the luncheon began, including maintaining a reliable system and efficient market, upgrading the Energy Management System, revising the criteria for reliability-must-run studies, completing transmission improvements in the Rio Grande Valley and integrating wind generation.
The ERCOT market generated more than 15,000 MW of wind energy for the first time in 2016, setting a new record of 15,033 MW in November. It also recorded three new marks for wind penetration during the year, topping out at 48.28% of load in March.
Magness credited stakeholders’ collaboration with staff and their forward thinking with making the records possible.
“We’ve always said if we can see it, we can integrate it,” he said. “When we hit 15,000 MW of wind and high penetration levels, people asked, ‘How do you do that? How is that possible?’ It’s possible because in ERCOT, when those things start to happen, we talk about it. That’s the value of thinking ahead while still in real time.”
ERCOT also set a new system peak (71,110 MW on Aug. 11), two monthly demand highs (during a warmer-than-normal September and October) and a new weekend peak (Aug. 7). The ISO’s annual Capacity, Demand and Reserve report released Thursday foresees demand rising to more than 77,000 MW by the summer of 2021. (See related story, ERCOT Sees Increased Load Growth, Shrinking Margins.)
Increasing Demand Boosts Finances
The high demand in the fall means the ISO should go into 2017 — the second year of its two-year spending plan — with net revenues as much as $13 million above budget. Also helping ERCOT’s finances are savings in resource management costs (primarily staffing management and project work), expected to come in $3.9 million under budget, and computer hardware purchases, at $1.9 million under budget.
“We challenged ourselves as a management team to maintaining some flexibility for ourselves, going into [the] second year,” Magness said. “We’re committed to keeping a flat [administrative] fee for at least two years. Keeping that budget discipline is going to be really important in maintaining that. One year in, we feel like we’re in a pretty good place.”
Magness also said ERCOT’s “technology refresh” to update aging computer technology is well underway. The four-year project began in 2015 and is forecast to come in at or under its $48 million budget. Magness said 60% of the contracts are locked in place, with 21% of the hardware already deployed.
Board Passes Transmission Planning Change
The board easily passed the only contested revision request before it, a planning guide change revising the criteria used to determine the need for new transmission projects that faced some pushback at the Technical Advisory Committee earlier this month. (See ERCOT Addresses Transmission Planning Challenges with New Rule.)
Valero Services’ Jack Durland, representing the Industrial Consumer sector, cast the lone dissenting vote. He questioned the planning guide revision request’s (PGRR) “bounded higher of” load forecast methodology, in which ERCOT will compare its load forecast with the summed bus-level forecast for each weather zone, and the need for two additional staffers to work on the planning process.
“Does one size fit all the [ERCOT] regions?” Durland asked. “If it doesn’t, we’ll end up with constraints, specifically in Houston. We’d like to see maybe some backcasting to understand this higher boundary methodology actually does fit most scenarios.”
PGRR042 defines considerations for selecting the most appropriate demand forecast in planning studies and how to model certain generation resources, such as mothballed units or those that can be also be connected outside the ERCOT region, in planning cases. It also describes how to incorporate new generation units in sensitivity analyses when they have interconnection agreements but have not met all the requirements to be included in transmission planning studies.
Warren Lasher, ERCOT’s senior director of system planning, told the board the ISO will “grey box” the PGRR’s language before formally codifying it for 2018. In the meantime, he promised staff would work closely with stakeholders throughout next year “to ensure we have an appropriate mechanism to make sure we have adequate transmission.”
“We have been having discussions with stakeholders about doing backcasts for the forecasts in the planning working groups,” Lasher said, “and we will continue to have those discussions … to make sure that the needs of customers, especially in the Houston region, and other regions of the state are met.”
“I can tell you with confidence that we can move around folks,” Magness said, addressing the staff additions. “Two [full-time employees], we can handle.”
Magness reminded stakeholders that PGRR042 came from a Public Utility Commission of Texas request to re-evaluate ERCOT’s planning process, part of the commission’s approval order for the Houston Import Project, a $590 million initiative due to be completed by summer 2018.
“This planning guide became the vehicle for the analysis,” he said. “Our folks feel comfortable they have sufficient flexibility and options for making sure the change works. It was a successful accommodation … of something we could work with, and we felt like folks in the market could work with, as well.”
New Board, TAC Members Approved
The ERCOT board approved Calpine’s Randy Jones and Source Power & Gas’ John Werner as new members of the board for 2017. The two, who served as alternates last year, will represent the Independent Generator and Independent Retail Electric Provider segments, respectively.
Jones is switching places with E.ON Climate and Renewables’ Kevin Gresham, while Werner replaces Direct Energy’s Read Comstock.
The board has yet to fill the unaffiliated position vacated by Jorge Bermudez, who resigned from the board in October when his pending marriage created a conflict of interest. (See “ERCOT’s Bermudez Resigns from Board Position,” ERCOT Briefs.)
“We were distressed to find out you love someone more than us,” joked Board Chair Craven Crowell, before presenting Bermudez with a resolution honoring his service.
The board also approved the Lower Colorado River Authority’s John Dumas and Golden Spread Electric’s Mike Wise (Cooperatives), SESCO’s David Hastings (Independent Power Marketers) and Direct Energy’s Sandra Morris and Noble Americas Energy Solution’s Clint Sandidge (Independent Retail Electric Providers) as new TAC members.
Ancillary Service Changes, NPRRs Sail Through
The directors unanimously approved “very minimal” changes to the minimum ancillary service requirements, after two years of more substantial changes.
Staff limited its changes to regulation service. It proposed removing the exhaustion rate feedback metric from the regulation-procurement analysis, estimating five-minute net load variability by including solar generation and making annual updates to the 2013 General Electric study’s tables reflecting incremental installed wind generation.
The board also unanimously approved a clean Statement on Standards for Attestation Engagements (SSAE) No. 16 audit report, modifications to forms ensuring the credit worthiness of market participants and five changes to the 2016 list of key performance indicators used to drive organizational performance.
The board consent agenda, which passed unanimously, listed eight nodal protocol revision requests (NPRRs):
NPRR773: Broadens the scope of acceptable letter of credit issuers, allowing electric cooperatives to post letters from the National Rural Utilities Cooperative Finance Corp. with ERCOT.
NPRR783: Revises a requirement for an independent audit to confirm the consistency of ERCOT operations models. The change is to comply with NERC reliability standard MOD-033-1 requiring a documented data-validation process for power flow and dynamic models.
NPRR790: Adds phase angle equipment limitations to real-time monitoring, real-time assessments and operational planning analysis, as required by NERC standards. ERCOT will collect this information through the network operations modeling process.
NPRR791: Clarifies the initial estimated liability (IEL) description to specify that it is based on estimated sales between qualified scheduling entities; restores the IEL for traders (inadvertently omitted from NPRR741) and corrects errors to the minimum-current exposure formula mistakenly overwritten by NPRR743.
NPRR792: Aligns the nodal protocols with NERC’s definition for special protection system (SPS) and uses “remedial action scheme” and “automatic mitigation plan” in place of SPS for consistency purposes, when applicable. The approval resulted in the TAC conducting an email vote on a related nodal operating guide request, NOGRR164, which was approved Thursday, 21-0.
NPRR797: Creates a new report and display for the actual system load by forecast zone, similar to the capability for weather zones.
NPRR801: Revises the physical responsive capability (PRC) calculation to include all load resources and align operating reserve demand curve (ORDC) reserves with the PRC change. It also aligns the ancillary service imbalance settlement with the change to the ORDC reserves.
NPRR803: Removes un-codified language from NPRR439, which was approved four years ago to allow counterparties to increase their credit limit for the day-ahead market’s current day.
