NYISO CEO Brad Jones said he is not convinced by any argument that the DER Roadmap pits the strength of a large grid against the resiliency of a small grid, as the system needs both to be robust. “Our goal is to find a way to bring both of those together to allow each of those different parts of the grid to provide efficiency for our operations and reliability for the overall grid.”
Audrey Zibelman, chair of the New York Public Service Commission, said, “We want the distribution markets to be optimizing distributed energy resources and optimizing load and co-optimizing that with the wholesale market, so that way will have a two-way seamless grid that is vertically coupled, that allows us to have a system that is more reliable, more dynamic, more efficient and more environmental.”
Cristin Lyons, partner at consultant ScottMadden, discussed the difficulty grid operators and utilities face in gaining visibility into the volume of distributed generation and how and when it is producing. There also are questions about whether they can be aggregated and how they will be compensated, she said. “Can you verify when they’ve operated? Do you even know if they are coincident with peak? Are they dispatchable? … At the end of the day, how do all these resources get paid? I think if we’re ever able to figure out the money, everything else will follow. We’re not there yet.”
Nick Tumilowicz, who manages the Electric Power Research Institute’s DER integration effort, discussed Consolidated Edison’s Brooklyn-Queens project, which is using battery storage and distributed generation to delay construction of a $1.2 billion substation. EPRI is performing a life-cost analysis. “What does it look like when we deploy battery storage in the field … to support peak demand and efficient transmission and distribution deferral?”
Kelli Joseph, director of market and regulatory affairs for NRG Energy, considered how uncertainty in the markets currently limits how different technologies could participate. “There’s a lot of uncertainty … about what rate design they’re going to have on the distribution side. For some projects, without a wholesale participation, they probably don’t pencil out.”
Mike DeSocio, NYISO’s senior manager of market design, devised what he said is a simple way to look at how generation assets can be classified as distributed. “If you have an asset that’s large enough to participate in the [wholesale] market today, you’re not a DER. If you have an asset that’s too small to participate in the market today and you think you’re going to need to aggregate it to participate, that’s a DER, whether it’s in front of the meter or behind the meter.”
The Brattle Group last week endorsed MISO’s proposed Competitive Retail Solution, conditioned on the RTO adopting a wider demand curve that the consulting firm developed.
Brattle’s demand curve, revealed in its latest analysis of MISO’s proposed forward auction, is capped at 140% of the net cost of new entry (CONE). The foot of the curve lands at 115% of MISO’s planning reserve margin requirement and a $0 net CONE.
Brattle said the net CONE cap is “slightly above” MISO’s requested $195/MW-day figure for Zones 4 and 7 and the $185/MW-day price elsewhere.
Brattle analyst Samuel Newell said the analysis concluded that MISO’s separate forward auction solution will address reliability concerns while inviting merchant investment. It projects volatility will be reduced by 6 to 15% compared to a status quo case Brattle researched.
Volatility
Newell said the wider curve Brattle recommends seeks to “absorb more structural volatility than other markets,” and the curve’s shift to the right is needed to accommodate a lower CONE price cap than what’s in use at other RTOs. Brattle said the curve “allows some shortage at high prices.”
He said Brattle has recommended caps ranging from 1.5 times to two times net CONE in other regions. The recommended sloped demand curve is less steep than other regions’ and extends farther to the right.
“A reason to have a higher cap is to put more money in the market, and it helps protect against the risk of under-procurement if you’ve underestimated CONE,” Newell said. “Yes, the pricing is going to be volatile because of all that uncertainty that goes into the system. But as long as you have enough money built into the curve and the curve is shifted far enough right, you will attract enough megawatts.”
Brattle’s analysis predicts the new capacity structure would meet or exceed the one-day-in-10-years loss-of-load expectation (LOLE) and attract an additional 1,800 MW of merchant supply. Brattle also said the forward auction on average is predicted to clear an extra 120 MW. The analysis results will be included as testimony in MISO’s FERC filing to win approval of the forward auction.
The firm also said use of the sloped demand curve in the long run should result in average forward prices that spur merchants to build; however, Newell said the analysis didn’t forecast prices under the new auction construct. “The reason we’re here isn’t to forecast prices. It’s to address the widespread belief — that I think is right — that current prices won’t support merchant supply meeting need.”
Status Quo Falls Short
Brattle did find that in the long run, use of the demand curve under the forward design reduces the instances of auction prices clearing at the demand curve cap to 39% of years. When Brattle tested a status quo scenario in retail-choice zones, clearing at the demand curve cap amount happens 65% of the time in Zone 4 and 67% of the time in Zone 7. Brattle maintains some capacity prices clearing at the cap is needed to keep average clearing prices closer to net CONE.
Newell said Brattle tracked enough merchant supply to assume a one-in-10 standard with the curve, but MISO can also assume its utilities own supply averaging 3% more than their individual requirements. Brattle found that continuing with the status quo would result in MISO falling 891 MW short of its planning reserve margin requirement in the long term in MISO North. The status quo auction, Brattle said, also results long-term in a one-in-5.2 LOLE “with frequent severe shortage” events and a majority of auction offers clearing at the price cap.
Bill Booth of the Mississippi Public Service Commission asked if Brattle did its own analysis of MISO’s CONE value. Newell said his firm did not test the accuracy of MISO’s net CONE. But even if MISO does revise its CONE values, Newell said, results wouldn’t be affected much, as Brattle’s higher, 1.4-times CONE cap “mitigates reliability risk of administrative error in estimating net CONE.”
“This aspect is exactly the same as the one we went through for PJM and New England. This aspect of it is very established ground,” Newell said.
Newell said the bigger issue is whether Brattle’s assumptions regarding cap and foot values and utilities’ ownership is correct. Brattle analyst David Oates said a lot of the modeling, including the Monte Carlo-style analysis, is similar to what was done in PJM and ISO-NE.
Brattle maintained the omission of MISO South was inconsequential, saying the 876 MW available for imports from the South is covered in varying megawatt amounts that utilities offer in the Monte Carlo analysis.
The company also modeled capacity import limits but not export limits and assumed utilities have a preference to build their own capacity instead of purchasing it from other utilities.
Zone 2 in Wisconsin and Michigan, which holds a small amount of participating demand, was initially included in the analysis, but Brattle found that it didn’t meet MISO’s materiality threshold.
In response to a question from Madison Gas and Electric’s Megan Wisersky, Newell said Zone 2 was initially included because it contains some competitive load. But MISO’s Mike Robinson said the inclusion was a relic of the RTO’s earlier work with Brattle and could be omitted altogether.
“It would be nice not to see that ever,” Wisersky joked.
The long saga of the Duke Energy coal ash spill that coated the Dan River with up to 39 million tons of toxic coal ash from a retired coal-fired plant in February 2014 came to an end Friday when the company agreed to pay a $6 million fine to the North Carolina Department of Environmental Quality. The company already settled federal pollution violations with a $102 million settlement in 2015.
The state first fined the company a $6.8 million civil penalty, which Duke called “entirely arbitrary and capricious.” The company did not say why it was now agreeing to a fine that is only slightly lower than the original, as it agreed with the DEQ not to make any public statements that were not mutually cleared.
The two sides did say that it is “in the best interest of the parties, the environment and the citizens of North Carolina that they enter into a compromise to avoid the time and expense of prolonged litigation.”
FERC granted American Electric Power’s request that its AEP Texas North and AEP Texas Central affiliates be combined into a single organization. The companies will operate under the name AEP Texas, with AEP Utilities, an AEP subsidiary, as its direct parent.
The commission dismissed the Oklahoma Municipal Power Authority’s request that it not address FERC’s jurisdiction over AEP Texas’ wholesale transmission service, finding “no evidence that either state or federal regulation will be impaired.”
AEP told the commission it expects the organizational changes to take place by year-end.
FERC on Friday approved ITC Holdings’ acquisition by Canadian utility operator Fortis and a Singapore-based investment fund. ITC, the largest independent transmission operator in the U.S., agreed to the $11.3 billion sale in February. (See Fortis to Acquire ITC Holdings for $11.3B.)
Fortis, which owns New York’s Central Hudson Gas and Electric and Tucson Gas & Electric, is purchasing most of ITC. GIC Ventures, an affiliate of an investment company that manages the government of Singapore’s foreign reserves, is purchasing the remaining 19.9%. ITC will remain a standalone transmission company.
FERC said the transaction raised no competitive concerns because ITC does not control any generating assets, and neither Fortis nor GIC own generation or natural gas assets in MISO, home to much of ITC’s transmission network. The deal, which the companies expect to close by the end of the year, had already been approved by state regulators in Wisconsin and Missouri.
Construction of NextEra Energy’s 87-turbine Brady Wind I project is 65% complete and concrete is being poured for the foundations of Brady Wind II, a nearby 72-turbine wind farm, according to the company.
Both projects are slated for completion by the end of the year. An 18.2-mile transmission line that will transmit the power to Basin Electric Power Cooperative, which signed a power purchase agreement with NextEra, will be completed in a few weeks.
PG&E last week announced the election of Eric Mullins to its board of directors and to the board of its Pacific Gas and Electric subsidiary.
Mullins is the managing director and co-CEO of Lime Rock Resources, a private equity fund specializing in the acquisition and operation of oil and natural gas properties. Before cofounding Lime Rock, Mullins worked for 15 years in the investment banking division of Goldman Sachs, where he served as managing director in the company’s energy and power group.
“As we position PG&E for continued long-term success, we welcome Eric’s expert counsel around our strategy and audit functions,” PG&E CEO Tony Earley said. “Eric’s deep financial background and familiarity with the energy sector will be invaluable assets for us.”
Alliant Energy has started construction of a 700-MW natural gas-fired generating station near Beloit, Wis., that will combine the power plant with an adjacent solar farm in the largest paired generation station of its type in the state.
The company’s Riverside Energy Center is already home to one solar farm. The $700 million project includes a second solar installation designed to offset power used by the new gas-fired plant, company officials said. When the second solar farm is completed, there will be 8,000 panels generating solar power.
The gas-fired plant is scheduled to be in service by 2020.
Xcel Announces Expansion of Wind Energy in Midwest
Xcel Energy says it is planning to invest $2 billion to build eight to 10 wind farms in Minnesota, the Dakotas, Wisconsin and Michigan, with an eye toward generating about 1,500 MW of electricity.
The company said it will own and operate some of the proposed wind facilities and enter into power purchase agreements with the operators of others.
“We believe this is one of the largest wind acquisitions in the country,” said Chris Clark, president of Xcel’s Upper Midwest Operations. He said the wind farms should come online between 2017 and 2020. Xcel is looking to renewable energy — primarily wind — to offset its planned retreat from coal-fired generation.
Dynegy was chosen as one of the winners of the Illinois Power Agency’s MISO Zone 4 capacity procurement auction for 2017/2018 and 2018/2019.
The company’s share of the auction was not announced, but the weighted average price was $143.20 and $137.25/MW-day, respectively. The total capacity from winning bidders was for 1389 MW for the first period and 465 MW for 2018/2019.
Shareholders voted overwhelmingly Monday to approve Great Plains Energy’s $12.2 billion acquisition of Westar Energy.
Shareholders cast their votes in separate meetings at Great Plains’ headquarters in Kansas City, Mo., and Topeka, Kan., where Westar is based. Company spokesmen said stakeholders approved all proposals necessary with at least 95% percent support.
Great Plains CEO Terry Bassham called the move “a great transaction” for stakeholders of both companies. Great Plains’ $12.2 billion offer includes $3.6 billion of Westar’s outstanding debt.
Westar CEO Mark Ruelle said the transaction would be completed next spring. Both CEOs said the acquisition will create a stronger company, with Ruelle adding that shareholder support “clearly demonstrates the value of combining Westar and Great Plains Energy.”
“The combined generation portfolio of the new utility will be more diverse and sustainable,” Bassham said. “Once this transaction is complete, more than 45% of our combined retail customer demand will be met with emission-free energy, and we will have one of the largest wind generation portfolios in the United States. This helps us maintain reliable, low-cost energy for all of the residential and business customers we serve.”
Westar’s 6,267 MW of generation is mostly coal-fired. Great Plains will walk away from the deal with 1.5 million customers in Kansas and Missouri, nearly 13,000 MW of generation and 10,000 miles of transmission lines.
Currently Great Plains and Westar jointly own the Wolf Creek Nuclear Generating Station and the La Cygne and Jeffrey power plants.
Westar’s shareholders will receive $60/share, paid in $51 cash and $9 in Great Plains common stock. Immediately after the vote, Westar stock was trending upward at $56.73/share.
Westar and Great Plains settled three lawsuits challenging the proposed merger, according to a U.S. Securities and Exchange Commission filing last week.
According to The Topeka Capital-Journal, a lawyer for one of the plaintiffs said the agreement will allow eight unsuccessful bidders to submit new bids. Attorney Derrick Farrell said the settlement required Westar and Great Plains to waive confidentiality provisions.
Andy Pusateri, a utilities analyst for Edward Jones, told the newspaper the settlement is unlikely to start a bidding war for Westar, saying Great Plains offered “a pretty significant premium.”
Westar also thinks the scenario is unlikely. Among other complaints, the lawsuits also alleged that the deal unfairly favored Great Plains Energy’s proposal while discouraging other and potentially better third-party bids.
“It is common to have someone file a lawsuit when mergers are announced. We were able to settle those lawsuits by simply modifying some of the language in the bidding documents. With that, the litigants agreed to stand down,” Westar wrote of the settlements.
The purchase still requires approval from the Kansas Corporation Commission, FERC, the Federal Trade Commission and the Nuclear Regulatory Commission.
The Missouri Public Service Commission wants in on the approval process, but Great Plains has said that Missouri regulators have no jurisdiction over the sale.
Westar would be the second acquisition in eight years for Great Plains, which acquired Missouri utility Aquila in 2008.
State Audit Reveals Faults In CPUC Contract Practices
The Public Utilities Commission failed to follow state rules for awarding noncompetitive contracts, did not guard against the appearance of improper influence from utilities when making decisions and failed to fully disclose important communications, according to a new state audit.
The audit focused largely on the CPUC’s contracting methods, which showed the agency spent $2.4 million on unexplained contracts and failed to monitor performance in a third of the contracts that were reviewed.
“The shortcomings we noted in CPUC contracting practices resulted from a lax control environment that the CPUC has allowed to persist,” the auditors said.
San Diego Gas and Electric is challenging state rules governing the manner in which a company-backed shareholder group can lobby against the creation of community choice aggregators (CCAs).
In August, SDG&E became the first utility in the state to get approval from the Public Utilities Commission to create such a lobbying group. But the company says the commission’s framework is too onerous and exceeds what is allowable under a state law.
CCAs allow elected city officials the authority to purchase power for ratepayers instead of utilities, which still operate the distribution system. They have become increasingly popular among cities seeking to service its load entirely through renewable energy.
A former Sedgwick County Electric Cooperative employee was sentenced to five years’ probation for embezzling thousands from the co-op.
Jamie L. Martin, 48, was ordered to repay the co-op about $187,000 and another $97,000 to cover the costs of the audit that uncovered the theft. She could serve 22 months in prison if she fails to abide by the terms of her probation.
Martin pocketed cash payments from customers, altering computer records to conceal the losses.
Bill Would Prevent Customers From Paying for Leaked Gas
Irwin
State Rep. Jeff Irwin (D-Ann Arbor) has introduced legislation that would block utilities from charging customers for gas that leaks from their systems before it can be sold.
Irwin said he was inspired to draft House Bill 5913 after he read a recent economic analysis that concluded utilities are less motivated to fix gas leaks when they can recover the cost of leaked gas in rates. “The public should not be subsidizing gas leaks,” Irwin said in a statement. “Charging customers for gas that they never get picks their pockets and pollutes the environment.”
Consumers Energy spokesman Dan Bishop said his utility was reviewing the bill. Bishop also called the wasted gas issue a de minimis problem, meaning it didn’t merit consideration.
The Albuquerque City Council unanimously approved a resolution that aims to power city-owned buildings and facilities 25% through solar energy by 2025.
The city’s Energy Conservation Council will put together a plan for the mayor and council with implementation options and recommendations to reach the 25% goal.
New Natural Gas-Fired Plant Approved by Siting Board
The Power Siting Board has approved plans from Advanced Power Services to build a $1.1 billion, 1,105-MW natural gas-fired power plant in Columbiana County. The location will give the plant direct access to the region’s shale gas resources.
Construction is set to begin in January, and the plant should be operational by 2020. The plant will replace about a fifth of the capacity that American Electric Power sold off in a deal announced last week.
The Burrillville Town Council voted unanimously to oppose the construction of a 1,000-MW natural gas power plant, ending its official silence on the controversial $700 million Invenergy project.
The council voted at a special meeting held in a high school auditorium to accommodate larger-than-usual attendance. Members said they took the stance only last week so as not to unduly influence the boards and commissions that had been asked to submit advisory opinions on the Clear River Energy Center, which would be located in woodlands near the town.
The town had told the state’s Energy Facility Siting Board that Invenergy’s application was incomplete. Additionally, local authorities that were counted on to provide cooling water for the plant have withdrawn agreements to do so. (See Proposed RI Power Plant Loses Cooling Water Source, Seeks Delay.)
State Approves Dominion’s Coal Ash Wastewater Plan
The State Water Control Board approved Dominion Virginia Power’s plan to treat the millions of gallons of coal ash wastewater stored in ponds and discharge it into the James River.
Dominion said that after the wastewater has been treated and discharged, it will no longer use wastewater ponds to store coal ash and will switch to a dry storage method in which the ash will be transferred to lined landfills.
The approval came over the objections of environmental groups. “We are just disappointed that the board did not take steps to further improve the permit,” said an attorney with the Southern Environmental Law Center.
WESTBOROUGH, Mass. — ISO-NE planners last week outlined the scope of a needs analysis that will determine whether the RTO will approve transmission upgrades to accommodate wind development in the Keene Road area in Maine.
An economic study found that the area could qualify for market efficiency transmission upgrades (METUs) — projects designed to reduce the total production cost to supply system load.
At Wednesday’s Planning Advisory Committee meeting, planners said the needs assessment will simulate production costs with the Keene Road export limit modeled at the existing 165-MW limit and three higher limits that top out at 255 MW.
The modeling will provide results for 2020, the projected in-service date for the upgrades, as well as 2025 and 2030. In addition to production costs, the simulations will predict metrics such as congestion, emissions and LMPs at several locations.
Draft results are expected to be brought to the PAC for stakeholder discussion by November, with final results posted in December. If the results show the upgrades qualify as METUs, the RTO could decide to issue a competitive solicitation.
A draft study in 2015 found that increasing the export limit to 225 MW could save $1.4 million to $5.7 million in production costs annually by allowing additional wind development in the area and displacing more expensive hydropower. (See “Draft Study Shows Greater Wind Penetration Benefits,” ISO-NE Planning Advisory Committee Briefs.)
Texas regulators last week accepted a proposal from ERCOT and SPP staff on how they will coordinate their separate studies on Lubbock Power & Light’s planned move to the ERCOT grid.
In a joint letter to the Public Utility Commission of Texas, Warren Lasher, ERCOT’s director of system planning, and Lanny Nickell, SPP’s vice president of engineering, said their studies will use “consistent input assumptions” and “rely as much as possible upon their existing study processes” (Docket No. 45633).
SPP said it will use models from its most recent Integrated Transmission Planning Near-Term (ITPNT) assessment and its 10-year ITP study. ERCOT will use models from its most recent Regional Transmission Plan and its Long-Term System Assessment.
Both RTOs will also conduct near-term reliability studies and longer-term economic studies. “Both parties will analyze their systems with and without the portion of LP&L that is part of the proposed transition,” Lasher and Nickell wrote.
LP&L announced last September it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. An ERCOT study completed in June indicated it will cost $364 million and take 141 miles of new 345-kV rights of way to incorporate LP&L into ERCOT. (See “LP&L Integration Could Unlock More Panhandle Wind Energy,” ERCOT Board of Directors Briefs.)
At a meeting Thursday, PUC Chair Donna Nelson said she agreed with the grid operators’ approach, but she expressed concern over who would pay for the studies. “Either LP&L should fund the studies, or we should leave the issue open pending the outcome of the studies,” Nelson said. “I don’t think it’s fair for the ratepayers in ERCOT to pay for that study.”
ERCOT and SPP said they had not come to a conclusion on funding the studies, but they would discuss with the commission “the appropriate allocation of the costs.”
ERCOT said it could complete its assessments before the end of the year, while SPP said it would complete its 2017 ITP10 in January and the 2017 ITPNT in April.
Lasher and Nickell wrote their staff does not have “the expertise or the necessary data” to determine the cost and reliability impacts as separated by customer class. They also deferred to LP&L “to describe measures necessary to ensure that there will be no commingling of electrical energy from the two regions as a result of the proposed transfer.”
At the same time, LP&L is conducting its own study. The utility’s attorney, Chris Brewster, asked the PUC to request ERCOT and SPP disclose their assumptions “to ensure we’re talking about the same things.” LP&L said it had had discussions with ERCOT, but not with SPP, and questioned the latter’s “scheduling constraints.”
“I don’t know what their scheduling constraints are, but they have a lot of employees. They have a lot of smart employees,” Nelson said, pointing out Nickell and SPP attorney Sam Loudenslager’s presence in the audience. “It’s in their best interest that ratepayers don’t end up paying for being unfairly advantaged when Lubbock leaves.”
Any PUC rulemakings will wait until the results are all in next year.
“We want to make sure we can get it right,” Nelson said. “We have people concerned about costs within the SPP system, and we have people concerned about costs in the ERCOT system. Clearly, we ought to be concerned about that.”
A proposal by MISO and ITC Holdings to allocate the costs of phase angle regulating transformers (PARs) to entities outside of MISO is not just and reasonable, FERC ruled last week.
The commission’s Sept. 22 order upheld Administrative Law Judge Steven Sterner’s 2012 decision prohibiting MISO and ITC from allocating the costs of ITC’s two 700-MVA PARs on the Michigan-Ontario border to NYISO and PJM (ER11- 1844-001, ER11-1844-002). The commission also denied as moot requests by several parties for rehearing.
Source: MISO
Failure to Show Benefit
FERC said MISO and ITC “failed to show that NYISO or PJM will benefit from the operation of the ITC PARs.” The commission noted that two NYISO and PJM witnesses testified that the two grid operators could “actually be harmed by the planned operation of the ITC PARs.”
“For example, a reduction in counterclockwise loop flow that may benefit MISO might, at the same time, harm NYISO if both transmission systems are experiencing congestion on transmission facilities that are affected by loop flow,” FERC wrote.
MISO and ITC proposed allocating 49.6% of the PARs cost to MISO, 19.5% to PJM and 30.9% to NYISO, based on each region’s contribution to the loop flows that would occur over the Michigan-Ontario interface without the PARs. Unscheduled loop flows around the Lake Erie region have been a problem since the late 1990s.
FERC ordered MISO and ITC to refund, with interest, all amounts collected pursuant to their Oct. 20, 2010, filing in excess of rates in effect prior to Jan. 1, 2011. MISO also has 30 days to revise parts of its Tariff that pertain to the cost allocation of PARs.
Reversal
FERC, however, reversed Sterner’s ruling that MISO and ITC were precluded from unilaterally filing proposed solutions with the commission. “While the commission has made clear its preference that interconnected utilities strive to resolve loop flow-related issues among themselves rather than resort to unilaterally filing proposed solutions with the commission, a public utility is legally permitted to make a unilateral filing to address loop flow,” FERC said.
PJM opposed the PAR cost allocation, saying that ITC’s two PARs replaced a single failed 800-MVA PAR that was “planned, developed and placed into service to meet local system needs.” NYISO objected to paying cost allocation for the ITC PARs because they “were not developed pursuant to a commission-approved regional planning process.”
ITC and MISO’s case for allocating the costs rested on Lake Erie’s loop flows no longer presenting a problem for PJM and NYISO. In a 2014 report, MISO, PJM and Ontario’s Independent Electricity System Operator (IESO) found that all five of the Lake Erie PARs were able to keep actual flows within 200 MW of scheduled flows most of the time.
Plans on Hold
After completing a yearlong observation of the ITC PARs and three other PARs at the Michigan-Ontario border in 2013, PJM and MISO incorporated the PARs into their market-to-market process on July 28. For now, PJM has put on hold plans to use the PARs for congestion management.
Marcus Hawkins, a senior engineer in the Division of Regional Energy Markets at the Wisconsin Public Service Commission, has joined the Organization of MISO States as its director of member services and advocacy. Hawkins will assist OMS Executive Director Tanya Paslawski.
Marcus Hawkins Courtesy of Marcus Hawkins
Hawkins, who has a bachelor’s in nuclear engineering and a master’s in mechanical engineering from the University of Wisconsin at Madison, considers his engineering experience to be an asset in his new role.
“It’s a very interesting position because it isn’t all technical all the time, but it helps to have the technical background,” Hawkins said. “Working at the commission was that same sort of sweet spot between the technical side and the policy side.”
Hawkins said his previous position with the Wisconsin PSC afforded him multiple opportunities to work with OMS. “I hope to enhance representation of the members of OMS both at MISO and FERC, and I’m excited to get started,” he said.
SANTA MONICA, Calif. — Optimizing distributed energy resources and reducing greenhouse gas emissions cost effectively will require improved forecasting and the elimination of regulatory silos, speakers told Infocast’s California Distributed Energy Summit last week.
Margie Gardner, executive director of the California Energy Efficiency Industry Council, opened the two-day conference with a question that framed the big picture: “What’s the purpose of integrating DERs into long-term procurement?”
The three speakers on the first panel offered variations on a theme.
For Pacific Gas and Electric, “integration means selecting that set of resources” that provides the least-cost solution to reduce GHGs while also maintaining system reliability, said Antonio Alvarez, renewable integration manager for the utility.
The California Public Utilities Commission believes that DER can help the state meet its carbon reduction goals while providing “safe reliable service at just and reasonable rates,” said Pete Skala, deputy director of costs, rates and DER.
“The question is, to what extent and where do they provide costs and benefits?” Skala said. The regulators’ goal is developing the “right amount of DER” to allow ratepayers, utilities and DER providers to all see benefits.
Costs and reliability “are definitely major drivers” for the Southern California Public Power Authority (SCPPA), said Ted Beatty, director of resource and program development for the joint planning agency, which represents the Los Angeles Department of Water and Power and 11 smaller municipal utilities.
“We have some small utilities, too, so we kind of have a wide range of needs there,” Beatty said. “But in general, they all have needs to look at planning for DERs.”
SCPPA’s members meet monthly to discuss issues around forecasting — a process becoming more difficult because of the unpredictability of DER penetration. DERs don’t connect to the grid via the traditional utility planning process.
Members are trying to grasp the technical and financial implications of increased DERs and understand customer trends to gauge the potential distributed solar capacity in their service territories. That effort has been hampered by the fact that some SCPPA members haven’t installed smart meters at customer sites.
“If you don’t have [customer data], you don’t really know what’s going on in your system,” Beatty said. “All you see is the net load that moves up and down, but you don’t know exactly why.”
Alvarez said that his utility’s long-term planning process relies on demand forecasts from the California Energy Commission (CEC), which factors in energy efficiency and distributed generation gains as well as energy consumption.
Recent forecasts put California power consumption growth at less than 1% per year, but that number could turn negative with increased energy efficiency mandates embedded in legislation passed last year (SB 350). That could exacerbate the forecasting complexity brought on by increased DERs.
“This is not new,” Alvarez said. “We’ve seen energy efficiency cutting in half — or more — the growth in demand.”
Next year, the CPUC will require each of California’s load-serving entities to file an integrated resource plan that prioritizes emission reductions alongside other more standard requirements, such as resource diversity, reliability and cost-effectiveness. (See Integrated Resource Planning on the Horizon for California.)
The revised IRP will provide the industry an opportunity to improve forecasting of DER, Alvarez said.
The IRP is an “optimization process” that seeks to determine the least-cost mix of resources to reliably meet California’s goals for energy efficiency, renewable generation and electrification of transportation. “I think at the end of the integrated resources plan, you actually have a demand forecast and a DER forecast,” Alvarez said.
Utilities have to look at more of a range than rely on specific forecasts, added Beatty, who suggested the industry should be employing scenario planning.
“When you’re looking at a forecast, you have to look at the different paths that are out there,” Beatty said. “Today I can’t predict five years ahead how much solar is going to come in [to the system], how much storage is going to be added to the system — or anything, for that matter.”
Skala said that although traditional “utility-scale, one-directional flow” grid planning is adapting to recognize the bidirectional flows stemming from DER, additional changes are still needed.
Utility planners “are a conservative bunch by nature.” When you talk about “safe and reliable service at just and reasonable rates while we achieve the state’s carbon goal, they only hear the word ‘reliable,’” Skala joked.
The variety of distributed resources and energy efficiency efforts adds “thousands of measures to the planning process,” he continued. “It becomes a very messy beast for conservative grid planners to try to figure out and incorporate into their work.”
Gardner asked the panelists to pick the most important thing that could be done to better incorporate DERs into the planning process.
“We need to have better models that analyze customer decision-making [and] factor all those together to figure out where the customer is going to go,” responded Beatty. “Once we know that, I think we can kind of follow along with them.”
Solar is the most significant DER for SCPPA utilities, with some members having already reached their net energy metering caps under state rules. Those utilities also control a large amount of utility-scale solar, which undermines the cost-effectiveness of distributed solar that generates during the same intervals.
“It’s a challenging market for these guys, and it’s difficult to figure out where we’re going and which DERs are the customers’ choice,” Beatty said.
“There needs to be a lot more alignment within the state agencies and the California Independent System Operator in terms of all the various planning activities that are ongoing,” Alvarez offered.
Alvarez would like to see the California Air Resources Board, CEC and CPUC coordinate their efforts to produce more reliable demand and DER forecasts, eliminating the agencies’ planning “silos.”
“It would be helpful to get some of those results as an input into the electric IRP process, so we can actually see the interaction between the different sectors of the economy — where you can get the best reductions in emissions,” Alvarez said. “If you’re trying to find what’s the optimal solution for the state and the electric sector, you need to have a common set of metrics.”
Skala concurred with Alvarez’s view on the need to align regulatory proceedings that require utilities to procure separate types of resources — such as energy storage, demand response and energy efficiency — under different state programs.
“The more we can get process alignment in place, the easier it’s going to make on markets,” Skala added.
The overlapping nature of California’s regulatory proceedings and the complication of integrating DER inspired a humorous analogy from Skala about the “nanny state” approach of setting various resource targets and the rules that apply to them.
“That caused me — in thinking about nannies — to think about the the grid in the child-rearing sense,” said Skala, the father of a 14-year-old daughter.
Historically, the grid — or demand, rather — has been a baby that’s been fed since the first light bulb, Skala said.
“And now we’re squarely in the adolescent period … so it’s a very confusing time, but it’s also a really important time developmentally,” Skala continued. “It’s really important to have clear and simple rules … that are designed to help customers and grid planners and everybody in that relationship make healthy choices.”
That will require sending clear signals to market participants, he added.
“But we also need to figure out what the utility model of the future looks like in that world, because if we don’t — to carry the analogy — we will have an empty-nester syndrome,” Skala said. “We’ve got to work it out in a way that works for the parent too.”
Construction of NextEra Energy’s 87-turbine Brady Wind I project is 65% complete and concrete is being poured for the foundations of Brady Wind II, a nearby 72-turbine wind farm, according to the company.
The Public Utilities Commission failed to follow state rules for awarding noncompetitive contracts, did not guard against the appearance of improper influence from utilities when making decisions and failed to fully disclose important communications, according to 
San Diego Gas and Electric is challenging state rules governing the manner in which a company-backed shareholder group can lobby against the creation of community choice aggregators (CCAs).
A former Sedgwick County Electric Cooperative employee was sentenced to five years’ probation for embezzling thousands from the co-op.
The Albuquerque City Council unanimously approved a resolution that aims to power city-owned buildings and facilities 25% through solar energy by 2025.
The Power Siting Board has approved plans from Advanced Power Services to build a $1.1 billion, 1,105-MW natural gas-fired power plant in Columbiana County. The location will give the plant direct access to the region’s shale gas resources.
The Burrillville Town Council voted unanimously to oppose the construction of a 1,000-MW natural gas power plant, ending its official silence on the controversial $700 million Invenergy project.
