CARMEL, Ind. — MISO’s Independent Market Monitor last week floated a plan that would allow resources that are unavailable for the full planning year to offer into the RTO’s capacity auction.
Speaking during a May 9 Resource Adequacy Subcommittee meeting, the IMM’s Michael Chiasson said that capacity resources that become unavailable and fail to replace themselves — but are not needed for reliability — should incur a financial penalty rather than a Tariff violation. The penalty price should be baked into a resource’s facility-specific reference level calculation, he said.
Chiasson also proposed that MISO designate monthly limits on how much capacity can be disqualified without replacement in order to maintain reliability.
“If there’s not a reliability issue, let it be a penalty rather than it just being a Tariff violation,” Chiasson urged. “How many megawatts of room are out there? Then put a hard stop on it.”
But he said the treatment should not extend to generators that are unavailable during the summer peak.
“If they can’t be available for the summer peak, then they shouldn’t be a planning resource. That’s our view,” he said.
MISO’s Tariff currently requires capacity resources retiring or suspending prior to the end of the planning year to replace themselves with uncleared zonal resource credits. It allows credits from outside the local resource zone only when zonal import and export limits permit.
Chiasson said it may be difficult for generators to find 100% of their replacement capacity in their own zones.
“It could be that there’s nothing left to clear in your zone,” he said.
Failure to come up with replacement credits triggers a Tariff violation and counts against a resource’s physical withholding conduct threshold. However, MISO gives a pass on physical withholding consequences to capacity resources that cannot deliver after Feb. 28 because March 1 is viewed as the end of peak system conditions. Those resources are encouraged to obtain a facility-specific reference level that includes the cost of zonal resource credit replacement. Chiasson pointed out that MISO does not extend that option to partial-year capacity resources.
Some stakeholders note that a MISO monetary penalty determination might not be the end of the concerns for capacity resources available for part of the year, which could still face resource adequacy rule violations with their state regulators.
Alliant Energy’s Jamie Niccolls cautioned that the Monitor’s plan could introduce a new reliability risk by allowing offers from units that cannot perform for the entire planning year.
Chiasson said MISO could mitigate that risk by memorializing a monthly reliability limit calculation in its Tariff.
Niccolls also said it would be difficult for a resource owner to quantify the risk of being unable to replace capacity in setting the penalty cost in the unit’s reference level.
“All we expect people to do is to make a reasonable business decision,” Chiasson said.
January’s cold weather resulted in a sharp increase in natural gas and power prices in the first quarter, PJM’s Independent Market Monitor reported last week.
The load-weighted average real-time LMP rose to $49.45/MWh in the first three months of 2018, a 63% jump from the $30.28/MWh seen a year earlier, according to the Monitor’s quarterly State of the Market report. The increase reflected a nearly 136% jump in eastern natural gas prices versus the first quarter of 2017.
Day-ahead, monthly and annual, load-weighted, average LMP: June 2000 through March 2018 | Monitoring Analytics, PJM State of the Market Report, Q1 2018
Other metrics saw even bigger jumps, including energy uplift charges (up $57.7 million, 227%) and congestion costs (up $503 million, 318%).
PJM real-time, load-weighted, average LMP: January through March, 2018 | Monitoring Analytics, PJM State of the Market Report, Q1 2018
Revenues from auction revenue rights and financial transmission rights offset less than 62% of total congestion costs for the first 10 months of the 2017/18 planning period, the first in which new rules required the allocation of balancing congestion to load instead of FTR holders. ARR and FTR revenues had offset 98% of load’s congestion costs during the 2016/2017 planning period.
PJM reported monthly billings ($ Billion): 2008 through March 2018 | Monitoring Analytics, PJM State of the Market Report, Q1 2018
It was a good quarter for generators, as measured by net revenue. All types of generation saw higher margins, including combustion turbines (+324%); combined cycle (+61%); coal (+650%); nuclear (+70%); wind (+43%); and solar (+57%).
The Monitor made seven new recommendations in the first-quarter report:
Energy Market
Change the Tariff to allow generators to have fuel-cost policies that do not include fuel procurement practices, including fuel contracts. “Fuel procurement practices, including fuel contracts, may be used as the basis for fuel-cost policies but should not be required,” the Monitor said. (Priority: Low.)
PJM should change the fuel-cost policy requirement to apply only to units that will be offered with non-zero cost-based offers. The RTO should set to zero the cost-based offers of units without an approved fuel-cost policy. (Priority: Low.)
Energy Uplift
Uplift should only be paid based on operating parameters that reflect the flexibility of the benchmark new entrant unit in the capacity market. (Priority: High.)
PJM should eliminate the use of intraday segments to define eligibility for uplift payments and return to evaluating the need for uplift on a daily, 24-hour basis. (Priority: High.)
PJM should pay uplift based on the offer at the lower of the actual unit output or the dispatch signal. (Priority: Medium.)
PJM should implement a metric to define when a unit is following dispatch to determine eligibility to receive balancing operating reserve credits. (Priority: Medium.)
FTRs/ARRs
All congestion revenue in excess of FTR target allocations should be distributed to ARR holders on a monthly basis. (Priority: High.)
WASHINGTON — Should FERC should begin requiring supply curve analyses in its merger reviews? It’s a no-brainer to Cynthia Bogorad, who has attempted to submit them as an intervenor challenging acquisitions.
“I’ve got black and blue marks to show that that … has not been a very successful strategy, because you don’t have the data or the time to get the data in [the] 60 days” allowed for filing a protest, Bogorad, a partner at Spiegel & McDiarmid, said during a panel discussion at last week’s Energy Bar Association annual meeting.
“And the commission has in my experience been very reluctant to accept intervenor analysis. We’ve presented a strategic bidding analysis in a case that the commission just said, ‘No, don’t do that.’ So, I think …. the commission [requiring merging companies to provide the analyses] would be very important because it’s hard to get them in [evidence] otherwise.”
The commission said it was considering changes in its merger policy in a September 2016 Notice of Inquiry (RM16-21). It noted that its market power evaluation for mergers, which are regulated under Section 203 of the Federal Power Act, differs from that used in market-based rate applications under Section 205. The commission asked for input on several issues, including whether it should add supply curve and market share analyses to its reviews, and whether it should require applicants to submit consultant reports and other internal reports that assess the competitive effects of the merger, as the Justice Department does. (See FERC Considers Changes to Market Power Analyses.)
FERC currently requires merger applicants to perform a competitive analysis screen unless they can show that the acquisition does not increase their generation capacity in the relevant geographic markets or that the increase is de minimis. The screen includes a delivered price test (DPT), which has been essentially unchanged since its introduction in 1996 and generally focuses on the short-term energy market “with far less detail and attention given to the other relevant products,” FERC said.
Mike Naeve, a partner with Skadden, Arps, Slate, Meagher & Flom, said FERC’s screening already prevents acquisitions that have no competitive harm.
“If we decide on top of that we’re going to add three or four other screens … I think there would be a lot more false positives,” Naeve said. “And I also think the amount of time and money and effort to prepare and advise clients for these filings [will] go up astronomically. So, the question is: Is the current process so flawed that it needs to be fixed?”
Naeve also was not convinced that FERC needs to adopt DOJ’s tools.
“As long as I’ve been doing this, I don’t know [of] a transaction where the commission said this transaction looks fine with us … and the DOJ, using these other methodologies and tools … says, ‘Oh, there’s a problem there FERC that you missed because your methodology is too simple.’ I don’t think that’s ever happened.”
Amery Pore, an economist in FERC’s Office of Energy Market Regulation, disagreed with Naeve’s characterization of the potential changes, which the commission is still reviewing. The comment period in the NOI expired in December 2016.
Flexibility?
“I guess one way to read the NOI would be to see these additional tests as extra hurdles to jump through,” Pore said. “But alternatively, you could think of them as employing the flexibility that was actually considered back in 1996 when the DPT wasn’t intended, when it was implemented, to be the screen to use.”
“If these were alternative tools to show it really is a false positive and there aren’t competitive problems, then I think we would all say that’s worth doing,” Naeve agreed. “But I would also say you [should not] need to do it in your application unless you have a screen failure.”
Naeve said he’s seen intervenors opposing mergers submit “very simplistic” supply curve analyses.
“To do it right you have to take into consideration a lot of factors … like the [generators’] ramp rates [and] minimum run times and minimum down times; the fact that sometimes in an RTO-type market … a transmission constraint that raises prices on this side of the constraint actually lowers prices on the [other] side of the constraint, so if you have generation there you’re actually losing money. … There’s just a lot of factors [that affect] the profitability of withholding.”
“That’s why it’s hard for intervenors to do it in the 60 days they have to protest,” Bogorad replied.
Mark Niefer, deputy chief legal advisor in the Justice Department’s Antitrust Division, said it’s important to avoid inconsistencies between DOJ and FERC reviews because the potential harm to consumers is so high.
“You’re talking about markets that are tens of billions of dollars in size, such that a very, very small exercise of market power over a very short period of time can impose harm on consumers … that are in the tens of millions of dollars,” he said. “So, my own personal preference when conducting a merger analysis [is] to tend to try to avoid false negatives rather than false positives. I just think the stakes are too high. And I think history bears that out. If you look back at California — the exercise of market power [during the 2000-2001 Western Energy Crisis] pretty much put a damper on restructuring in the United States. … And I think that damper still is in place.”
The panel was moderated by Eric Korman, vice president of Analysis Group.
WASHINGTON — FERC’s delay in responding to a 2017 appellate ruling vacating its order on New England transmission rates has created the risk of an endless series of “pancaked” rate cases, a panel told the Energy Bar Association’s annual meeting last week.
The D.C. Circuit Court of Appeals’ April 2017 Emera Maine ruling overturned FERC’s 2014 order setting the base return on equity for a group of New England transmission owners at 10.57%. The court said the commission failed to adequately explain why the previous 11.14% rate was unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.)
“We’re in a huge amount of uncertainty right now. The Emera decision has essentially taken everything and flipped it up into the air, and now we’re all waiting to see what happens next,” said Nina Plaushin, ITC Holdings’ vice president for regulatory, federal affairs and communications. “It’s as close to a thriller as you get in doing utility regulation.”
In the 2014 ruling, the commission voted 4-0 to change the way it calculates ROEs for electric utilities, moving to a two-step discounted cash flow (DCF) process it has long used for natural gas and oil pipelines that incorporates long-term growth rates. But the commission split 3-1 over its first application of the new formula, tentatively setting the ROE for the New England TOs at three-quarters of the top of the “zone of reasonableness,” a departure from the prior practice that used the midpoint in the range (EL11-66-001). (See FERC Splits over ROE.)
FERC rejected the TOs’ argument that the commission lacked authority to change the ROE without showing it is outside the zone of reasonableness.
“There’s no protection from being in the range [of reasonableness], so any complaint can come in and [cite] a number that’s slightly lower than your number and then you’re in a hearing,” Plaushin said. “And that’s why this Emera remand is so important, because we need to figure out how we’re deciding what goes to hearing and what doesn’t. It can’t just be that I proved a number different than yours.”
Customers filed new complaints even as previous ones were still pending, she noted, because of the 15-month limit on refunds under the Federal Power Act. The clock starts on the date of the utility’s rate filing.
Plaushin said the zone of reasonableness can differ based on changes in interest rates and other inputs, or as utilities are added to or subtracted from the proxy group.
In June 2016, she noted, an administrative law judge determined 10.68% as the top of the range in a complaint against MISO TOs. This was little more than three months after another ALJ, ruling on the third complaint against the New England TOs, found the top of the range at 12.19%, with 10.9% as the midpoint.
“It just doesn’t seem to make sense. It just has to do with the fact of when they filed. … [New England] got lucky. They filed when there was a good number. And one of the things the commission will [have] to consider is: Do you really want to get into a situation where people are trying to game their ROEs by doing multiple filings just so they can track volatility?”
David E. Pomper of Spiegel & McDiarmid, who argued the Emera case for Massachusetts, predicted there will be more complaints challenging rates. “I’m certain of that,” he said. “There’s a lot of ROEs out there that are still way above the cost of equity.”
He agreed with Plaushin about the risk of a never-ending cycle of filings.
“I think that probably something we can all agree on is … if the results of the litigation changes dramatically from case to case, there’s something wrong with the way you’re reaching decisions,” he said. “That creates incentives to keep filing in the hope that you’ll get lucky.”
“The solution will be in the answer to the remand in Emera,” Plaushin said in an interview later, acknowledging FERC’s response was slowed by its loss of a quorum last year. “Hopefully that will establish better parameters, so we don’t have as many serial cases.”
Former FERC Commissioner Suedeen Kelly, a partner at Jenner & Block, who moderated the session, noted the increase in ROE challenges since 2011. The panel also featured Robert S. Kenney, Pacific Gas and Electric’s vice president of regulated affairs, who discussed the impact of ROEs on his company’s ability to adapt to distributed energy resources and protect the grid from cyber threats.
RTO technical staff are currently devoting time to creating a better market user interface — the nonpublic webpages MISO uses to accept energy bids and offers, MISO Senior IT Director Curtis Reister told the Market Subcommittee on Thursday.
The new interface is expected to work with Internet Explorer, Microsoft Edge, Chrome and Firefox. Reister said MISO sometimes forces users to use older versions of browsers for combability with the old interface.
He could provide no release date for stakeholders to peak at the new interface but said the RTO would keep them updated on progress.
MISO CEO John Bear last month said he expects about 200 employees to spend 100,000 hours total on the platform replacement project.
Final Uninstructed Deviation Proposal
MISO’s final proposal for dealing with generators’ uninstructed deviations from dispatch instructions appears to strike a balance between the views of RTO staff and stakeholders.
The plan calculates a generator’s uninstructed deviation by comparing the time-weighted average of its real-time ramp rate with its day-ahead offered ramp rate, while allowing for a 12% tolerance from set point instructions.
The proposal eliminates the RTO’s current “all or nothing” eligibility for make-whole payments, instead allowing generators to collect full payments when they respond to dispatch instructions at a rate of 80% or higher over an hour, while excluding payouts when performance rates fall below 20%. Units operating between those two thresholds would earn make-whole payments in proportion to performance. (See Monitor Backs MISO Uninstructed Deviation Proposal.)
The change would mean that a generator that fails four or more consecutive five-minute dispatch intervals within an hour by either providing excessive or deficient energy will not automatically lose its eligibility for make-whole payments.
In response to the concerns of some stakeholders that wind and solar resources would be flagged for producing excessive energy, MISO crafted an exception to its uninstructed deviation proposal. MISO Market Quality Manager Jason Howard said the RTO only plans to assess excessive or deficient energy charges on dispatchable intermittent resources during intervals when the resources are economically dispatched below the RTO’s forecast. Dispatchable intermittent resources that use their own forecasts will be charged for excessive or deficient energy like any other resource under the proposal.
Howard said the move could help eliminate any intentional under- or over-forecasting by intermittent resources in order to collect make-whole payments, an issue the Independent Market Monitor has repeatedly raised.
“I don’t think that we’re done here. We’re going to have other discussions about forecasting and intermittent resources,” Howard said.
MISO now plans to file with FERC to reflect the change by the third quarter of this year, with the new uninstructed deviation calculation in place by early 2019.
Multiple stakeholders thanked MISO staff for taking extra time to develop a compromise proposal.
MISO and PJM will pursue two separate interregional studies this year to identify potential joint transmission projects, the RTOs said last week.
One six-month study process would look for small cross-border projects, while a two-year effort would seek to uncover potential major interregional projects, stakeholders learned during a May 11 conference call held by the RTOs’ Interregional Planning Stakeholder Advisory Committee (IPSAC).
2nd Round of TMEPs
The shorter-term study will identify targeted market efficiency projects (TMEPs), a project category the RTOs created in 2017, subsequently approving a five-project portfolio in December. This category of smaller interregional projects is intended to target historical congestion along the RTOs’ seams.
Staff from both RTOs said the study would concentrate on historically binding flowgate constraints that have amassed at least $1 million in congestion charges. MISO and PJM have experienced about $500 million in congestion payments on more than 200 market-to-market flowgates in 2016 and 2017. PJM interregional engineer Alex Worcester said $200 million of that congestion will be addressed by planned upgrades, both by regional fixes and the five planned TMEPs.
“But there’s a bulk $300 million of congestion left on the seams that can be investigated,” Worcester said.
The second TMEP study will be conducted much like the first, and the RTOs hope to complete review of historical congestion along the seams by the end of June, Worcester said. The study will examine why flowgates were binding and determine whether transmission outages caused the problem.
The RTOs have committed to working with equipment owners associated with the congestion this July to zero in on which equipment is limiting the flow of electricity and discuss potential upgrades. By October, the RTOs hope to have completed an evaluation of project ideas and submit project recommendations for approval by their respective boards of directors.
TMEPs must cost less than $20 million, be in service within three years of approval and provide historical congestion relief that is equal to or greater than construction cost within the first four years of operation. The construction cost is divided between MISO and PJM based on the percentage of congestion relief benefits.
The two RTOs approved a $20 million, five-project TMEP portfolio last year, with projects in Illinois, Indiana, Michigan and Ohio; all are upgrades to existing systems. Project costs are on average allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million. (See FERC Conditionally OKs MISO-PJM Targeted Project Plan.)
Northern Indiana Public Service Co.’s Miles Taylor asked if MISO and PJM would consider speeding up the process to get projects approved by the end of summer.
MISO’s Adam Solomon said his RTO may be open to the idea, but he added it would be difficult to expedite the process, considering that the grid operators must complete an analysis and obtain approval from both boards before moving forward with TMEPs.
Some stakeholders asked the RTOs to consider generation retirements when studying historical seams congestion, as retiring generation could alleviate congestion on its own. Solomon said the study process is already equipped to collect that type of information.
2-Year IMEP Study
MISO and PJM have also agreed to begin a more traditional two-year coordinated system plan study to identify more expensive seams projects called interregional market efficiency projects (IMEPs), none of which have been approved by the RTOs.
For the more involved study, Worcester said each RTO will develop an economic regional model and study project suggestions submitted by stakeholders. IMEP proposals must be submitted to both regional processes, with the proposal window open from Nov. 1, 2018, to Feb. 28, 2019, according to PJM Tariff rules. Board approval of potential IMEPs would take place by the end of 2019.
Before approval, proposals will be reviewed multiple times: first to determine eligibility, then to calculate interregional cost allocation and the share of regional benefits. A third review tests the projects against each RTO’s regional criteria, while the fourth and fifth evaluations involve getting approval from both the staff and boards for both RTOs.
“It seems like one of the goals MISO and PJM have is to remove the triple hurdle. What I’m seeing here is a five-hurdle,” Wind on the Wires’ Natalie McIntire remarked. “It just seems like we should have less review.”
Worcester said only three of the reviews result in a pass/fail outcome for a project. The first review simply determines if the project would be eligible under IMEP requirements, while the second only serves to get an idea of project cost benefits, he said.
MISO and PJM last conducted a coordinated system plan in 2016 and 2017, ending the process without recommending any projects. One serious contender, a proposed 30-mile, 138-kV line near the Indiana-Illinois border, ultimately failed the joint 5% generation-to-load-distribution factor test, which requires each RTO to show that at least one of its generators has at least a 5% impact on the affected flowgate. (See MISO, PJM Ponder Interregional Study.)
Axe 5% GLDF Test
As a result of the last two-year study, the RTOs plan to revise their joint operating agreement to remove the 5% generation-to-load-distribution factor test, instead letting each of their regional processes determine flowgate impacts. Solomon said the edits will also remove references to a MISO-PJM joint model study requirement, as the joint model was eliminated in FERC compliance filings in response to a 2013 complaint from NIPSCO on the RTOs’ interregional process. (See “No Joint Model,” FERC Signals Bulk of NIPSCO Order Work Complete.)
Solomon said MISO and PJM want the revisions in place before opening the IMEP project proposal window in November. For that to happen, Solomon said the changes should be on file with FERC no later than July.
CARMEL, Ind. — A recent MISO study slightly overestimated actual capacity offers in the 2018/19 Planning Resource Auction, stakeholders learned this week.
The RTO’s loss-of-load expectation (LOLE) study predicted about 143.3 GW of capacity in the Planning Resource Auction, while the auction itself attracted about 141.8 GW in offers, MISO Resource Adequacy Senior Engineer William Buchanan reported during a May 9 Resource Adequacy Subcommittee meeting.
MISO said three factors played into the difference between the study results and auction outcome:
PJM completed its third Incremental Auction in early March after the LOLE analysis was complete, which increased exports.
The LOLE used forecasts submitted in November 2016, while the PRA relied on forecasts with reduced load growth submitted in November 2017.
The LOLE study was completed before the latest round of Attachment Y retirement notice submittals, which were not included in modeling.
Buchanan also said a year-over-year decrease in transmission losses shaved peak load by about 426 MW.
MISO cleared 135 GW of capacity during the 2018/19 PRA last month, with nine of its 10 local resource zones clearing at $10/MW-day. The lone outlier was Zone 1 — covering parts of Wisconsin, Minnesota and the Dakotas — which cleared at $1/MW-day. (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)
In more detailed results released this week, MISO cleared slightly less than 49 GW of coal capacity, down 3.3 GW from last year’s cleared volumes, while natural gas capacity was up about 2 GW at 51 GW. Cleared wind capacity remained relatively static at 2.2 GW, while solar capacity more than doubled from 180 MW to 461 MW. Nuclear capacity remained steady at 12.5 GW.
Capacity Import Limit Change
Some MISO stakeholders said they were caught off guard by an unexpected drop in capacity import limits used in the auction compared with preliminary auction data.
Consumers Energy’s Jeff Beattie asked why the auction’s actual CILs changed from the first published limits by “hundreds of megawatts.” He said the changes were a departure from previous years, when draft preliminary and final preliminary CILs remained relatively static.
“Zone 5 changed by more than 500 MW in the capacity import limit,” Beattie said.
Harmon said the RTO simply updated the limits for known exports out of the system to non-MISO load as it became aware of the changes. He said MISO may investigate requiring stakeholders to provide more information earlier.
From February to mid-March, when limits were finalized, MISO’s preliminary CILs fluctuated anywhere from 752 MW in Missouri’s Zone 5 to no change in Michigan’s Zone 7.
Vistra Energy’s Mark Volpe said MISO could do more to telegraph the limit changes to its stakeholders ahead of the auction.
“We did not hear a discussion as to why they changed. MISO needs to be more transparent,” Beattie said.
Laura Rauch, MISO manager of resource adequacy coordination, said the RTO would try to improve transparency in next year’s auction.
Exelon’s David Bloom said he was “begging” MISO to make preliminary PRA data easier to locate on its website.
MISO will meanwhile continue to make predictions for out-year capacity import and export limits, but it will use a new process of analyzing only those zones expected to bind on their import or export limits — or fall short of procuring local clearing requirements. MISO’s Matt Sutton said the RTO will now review those zones with its Loss of Load Expectation Working Group (LOLEWG) and then perform analyses on selected zones. Results will first be shared with the LOLEWG.
Sutton said the technical design of the new process will also be taken up at the LOLEWG.
MISO last month said it would revise its practice of forecasting long-term capacity import and export limits after proposing in early spring to discontinue them. (See “Reprieve for Out-year Import and Export Limit Estimates,” MISO Resource Adequacy Subcommittee Briefs: April 11, 2018.)
SACRAMENTO, Calif. — The California Energy Commission rocked the energy world Wednesday when it unanimously approved a mandate requiring new homes in the Golden State to include rooftop solar, making it the first state to move to adopt such a rule.
The 2019 Building Energy Efficiency Standards would apply to most newly constructed buildings and additions to existing structures built after Jan. 1, 2020, requiring builders to add solar panels and encourage battery storage systems and heat pump water heaters to improve energy efficiency. They also update standards for indoor and outdoor lighting by incentivizing maximum usage of LED lighting in non-residential buildings.
The proposed rules also include three other major components in addition to solar: updated thermal envelope standards that prevent interior/exterior heat transfer; residential and nonresidential ventilation requirements; and nonresidential lighting requirements. California for the first time extended the standards to health care facilities.
The package still requires approval from the state’s Building Standards Commission. CEC spokeswoman Amber Pasricha Beck told RTO Insider the building commission usually approves what the CEC sends over.
In discussion ahead of the vote, CEC members said the measure will cut energy bills and reduce greenhouse gas emissions, noting that the cost of solar panels has dropped dramatically in recent years. The vast majority of comments filed in the proceeding favored the changes.
CEC Chairman Robert Weisenmiller said that California has expanded its economy in recent years even while reducing greenhouse gas emissions. Implementing the standards will require close work between the commission and the building industry, which he said he wants to keep “vibrant.”
“This is just a milestone, but there is a hell of a lot of work to go between now and 2020, and we really have to keep our eye on the ball to make this work smoothly,” Weisenmiller said. “There will be some surprises, and we will need to stay on top of this, but the bottom line is we are going to focus on making this happen.”
“Once we get there, yeah, we can talk about the future,” he added.
The CEC’s Wednesday meeting drew an unusually heavy media interest for a commission decision, and by the evening even the BBC had picked up the story.
The measures will make it more expensive to build new homes in a state already known for some of the highest housing and construction costs in the country, but the commission said it will be worth the expense.
While the new standards will add about $9,500 to the cost of a new home, they will save homeowners $19,000 in energy and maintenance costs over 30 years, the CEC said. The changes would add about $40 to the average monthly mortgage payment but save $80 per month on heating, cooling and lighting bills. Nonresidential buildings will use about 30% less energy under the standards, mainly because of lighting upgrades, according to the agency.
The explosion of rooftop solar in California has led to massive amounts of solar output coming online and offline each day as the sun rises and sets, requiring increased use of fast-ramping generation resources to compensate for the variability. Asked about the impact on California’s “duck curve” that illustrates the steep ramps, CAISO spokesman Steven Greenlee said Thursday that zero-net energy home projections are included in the CEC’s Integrated Energy Policy Report (IEPR) forecasts, which the ISO uses in its transmission planning process.
“Our planning already takes into consideration state policies,” Greenlee told RTO Insider. “We have been managing increasing amounts of renewables coming onto the grid for many years and use the IEPR forecasts for transmission planning. However, as the amount of renewables on the system grows, grid operators need increased visibility into behind-the-meter resources, including developing practices for aggregated information sharing and operational coordination.”
Solar Energy Industries Association CEO Abigail Ross Hopper said: “This is an undeniably historic decision for the state and the U.S. California has long been our nation’s biggest solar champion, and its mass adoption of solar has generated huge economic and environmental benefits, including bringing tens of billions of dollars of investment into the state.”
California Building Industry Association CEO Dan Dunmoyer said the standards “struck a fair balance between reducing greenhouse gas emissions while simultaneously limiting increased construction costs.”
Parties issuing statements in favor of the proposal include the Natural Resources Defense Council, Habitat for Humanity San Joaquin County, California Solar & Storage Association, California Air Resources Board, Southern California Edison, Pacific Gas and Electric, and Tesla.
Opposition to the standards was mostly limited to individual commenters, some addressing aspects of the standards other than the rooftop solar mandate.
At the meeting, longtime Colorado-based energy attorney and consultant Peter Esposito said he only learned of the rooftop solar proposal on Tuesday.
“I initially thought it was ‘fake news,’ and I would like to add that I think you are making a big mistake,” Esposito said. He advocated against a technology-specific approach and said consumers should be able to choose how to meet greenhouse gas emission goals.
“Please don’t lock out other technologies,” he said, without being specific as to what particular technologies he was referring to.
The Public Utility Commission of Texas on Thursday delayed its final approval of Southwestern Public Service’s request to build a 478-MW wind farm in West Texas, allowing the company and other parties in the docket time to provide written answers to the regulators’ latest questions and recommend further revisions to the draft order (46936).
SPS said it could make a reply filing on May 16, clearing the way for the PUC’s final approval during its May 25 open meeting.
PUC Chair DeAnn Walker apologized for the two-week delay, saying she developed the questions as she reviewed the proposed order.
PUCT Chair DeAnn Walker (left) and Commissioner Arthur D’Andrea share a laugh. | PUCT
“I fully intended to get it done today,” she said. “If anything should be clear to anyone in this industry, it’s that I need to be comfortable with what I sign.”
The wind farm is part of a 1.23-GW project by SPS parent Xcel Energy that will provide renewable energy to SPS customers in Texas and New Mexico. The utility says the project will save its retail customers about $1.6 billion in energy costs over its 30-year life.
PUC staff filed a draft order on May 9 that revised its previous version, eliminating provisions rendered moot by a settlement reached in March between SPS and staff, the Department of Energy, the Office of Public Utility Counsel (OPUC) and seven other consumer groups, area cooperatives and landowners.
Walker filed a memo that same day outlining her concerns about SPS’ exceptions to the latest order. She said some rate-related findings suggested in the order would be more appropriately made in a future rate proceeding, and that some sections of the order “lack the clarity” necessary for inclusion in a PUC filing.
She focused much of her discussion on the order’s proposal to recover costs by flowing production tax credits through fuel, asking the parties to explain why the commission should deviate from its “well-established principles” of matching costs and benefits.
“The benefit of production tax credits flowing through fuel accrues to some customer classes more than the costs those same customers bear through their base rates,” Walker wrote. “Conversely, customers who bear more of the costs in their base rates receive less of the benefits, because they flow through fuel. This does not meet the commission’s typical matching principle.”
Attorney Rex VanMiddlesworth, representing Texas Industrial Energy Consumers, said the PTCs should flow through fuel as they are earned, pointing out that they are used when bidding into the markets.
“You’ve got to have those PTCs going through fuel, otherwise the fuel costs won’t reflect the actual [bid] … into the LMPs. You would be bidding in at -$28, and the customers wouldn’t be getting that -$28,” VanMiddlesworth said. “PTCs are kind of a classic energy allocation. When we have a rate case, if it’s litigated, I wouldn’t be surprised to say at least part of the PTC ought to be allocated on an energy basis.”
SPS President David Hudson reminded the commission that the utility has said the wind farm will be an energy resource, rather than a capacity resource.
SPS’ legal counsel Ron Moss, with President David Hudson to his left, answers questions. | PUCT
“Our intention all along is to allocate the base rate case cost on energy,” Hudson said. “It’s going to be consistent with how the fuel goes back and the PTCs go back. Everything is going to be synchronized. It’s just some parties thought there might be a capacity addition in the future.”
“We’ve never had a plant like this. Every other plant we had was to meet demand,” he said.
VanMiddlesworth said the SPS facility is being built “largely because of PTCs,” which make it profitable over the first 10 years.
“You have your decision then, we have our rights to address it at that time,” he said. “We don’t foresee it as a problem. We do want the ratepayers to get the PTCs as they’re earned.”
Rayburn Country Picks 44.6 Miles of Trinity Valley Assets
The commission also approved the transfer of certificate of convenience and necessity rights for 44.6 miles of existing 138-kV transmission lines in East Texas from Trinity Valley Electric Cooperative to Rayburn Country Electric Cooperative (Docket No. 47951).
Rayburn already owns or leases more than 360 miles of 138-kV lines that serve wholesale loads in both ERCOT and SPP. The transferred facilities are operated in ERCOT.
Connecticut’s General Assembly on Wednesday passed a bill that doubles the amount of renewable energy utilities must use to serve load — 40% by 2030 — while also revoking net metering guarantees that ensure rooftop solar owners earn retail prices for their excess electricity.
The bill now goes to Gov. Dannel Malloy, who said the legislation (SB 9) will help cut emissions and create “good jobs in the green economy, all while decreasing costs for ratepayers.”
Connecticut state capitol building in Hartford
The bill also extends $8 million in renewable incentives for commercial users and allows them to sell their output to utilities in 15-year contracts. The new law creates a 25-MW community solar program for residential customers who cannot afford to install their own solar panels.
Peter Rothstein, president of the Northeast Clean Energy Council, said in a statement that while the bill “contains a robust expansion of the state’s renewable portfolio standard,” it also includes “counterproductive provisions that will significantly harm the state’s rooftop solar market.”
Net metering “will essentially be dismantled,” Rothstein said.
A coalition of solar developers, solar proponents and environmental groups, including SunRun, Vote Solar and the Connecticut Citizen Action Group, had also urged state lawmakers not to pass the law without amending its net metering language.
“Instead of restricting customers’ ability to choose solar and imposing a cap on solar investment, the bill’s community solar program should be strengthened to expand solar access,” the coalition said. “Rather than building Connecticut’s local clean energy economy, the current bill language puts the future of solar in Connecticut and thousands of jobs at risk.”
