NEW ORLEANS — Two consultants on either side of MISO’s rejected capacity auction redesign faced off in a post-mortem debate at the Gulf Coast Power Association’s MISO South Regional Conference last week.
Kathleen Spees, a principal adviser at The Brattle Group who endorsed MISO’s forward auction design for the RTO’s retail-choice areas and worked on a simulation analysis for the RTO, said some of MISO’s design elements could be revised to win FERC approval. But Independent Market Monitor David Patton pressed for a reconsideration of the hybrid prompt proposal he designed with the RTO last year.
The rejected auction proposal was an attempt to provide investment price signals to incent generation in retail choice areas in southern Illinois and Michigan. (See FERC Rejects MISO’s 3-Year Forward Auction Proposal.)
Spees, who joked that she and Patton should have come dressed as Hillary Clinton and Donald Trump for the debate, said FERC’s unusually short order lacked commission guidance on how MISO’s proposal could be salvaged. The order was among more than 60 the commission issued in the last week before losing its quorum with the resignation of former Chairman Norman Bay.
“I think that leaves many of us scratching our heads about what to do next,” Spees said at the Feb. 16 conference. She said she thought a compromise could be reached over how far into the future the auction is held and suggested that, in a new proposal, MISO keep a sloped demand curve for its retail-choice areas while regulated utilities maintain vertically integrated statuses.
Patton said MISO “dodged a bullet” with the rejection. “You operate the system as a whole. You can’t pretend that 10% of your footprint operates separately,” he said.
The Monitor continued to advocate for his own proposal, which would apply a sloped demand curve to deregulated areas and produce separate clearing prices for retail-choice and regulated load.
Spees said MISO’s proposal failed because it did not maintain an integrated market or contain a transmission allocation plan between two markets. “MISO has a uniquely challenging situation where there are two business models in conflict,” she said. There is “a not-so-small-it-can’t-be-ignored portion of the system that relies on market signals.”
Patton said current rules only buoy regulated utilities, which continue to expand generation even when wholesale prices don’t support construction.
“We exist in an environment where only a regulated market can afford to build anything,” he said. “We’ve designed a capacity market in MISO that doesn’t set efficient prices; it sets inefficiently low prices, especially in MISO South.”
Patton said while he monitors both prompt and forward markets, he prefers a prompt design. He said while it’s “nifty” for future resources to be able to sell capacity, an owner of a plant with a 30-year lifespan won’t usually make decisions on the viability of their generation based on clearing prices in year one.
Spees, however, said a three-year forward auction provides more of an opportunity for supply and demand to reach equilibrium and avoid “boom and bust” cycles with volatile clearing prices. However, she said accurate load forecasting in a three-year market presents a challenge. “In my view, we’ve seen both prompt and forward markets do well…They both can be workable constructs,” she said.
The two were in agreement in opposing MISO’s adoption of New England’s Pay-for-Performance capacity bonuses and penalties. PJM adopted similar rules in its Capacity Performance construct. Patton said he preferred incentives to stay in the energy market. (See FERC Defends PJM Capacity Performance Model Before DC Circuit.)
“If it ever hits on days where no one is expecting it, it can cost people a heck of a lot of money,” Patton said, adding that unpredictable load is not the fault of the generator.
Spees also said performance incentives belong in the energy market, not the capacity market. However, she said there is no MISO enforcement for capacity underperformance, and she said the penalty should be “something north” of $0/MW-day.
Water levels behind the FERC-regulated Oroville Dam have continued to decline in recent days, falling to nearly 50 feet below the height of a severely damaged emergency spillway, according to the California Department of Water Resources (CDWR), the dam’s operator.
On Feb. 12, local officials ordered the evacuation of about 188,000 residents after the erosion of a hillside beneath the dam’s emergency spillway threatened to flood areas near the Northern California town of Oroville, located about 75 miles north of Sacramento. CDWR was required to use that spillway for the first time since the dam’s completion nearly 50 years ago after heavy flows out of the reservoir tore a massive hole in the concrete lining of the main spillway.
Residents have since been allowed to return to their homes but face the potential for another evacuation if weather conditions once again destabilize the ground around the dam.
Criticism for FERC, California Agency
The spillway failure has generated criticism of both CDWR and FERC for their failure to heed previous warnings by three environmental groups who — during the dam’s 2005 FERC relicensing proceeding — requested that the state pave the hillside below the emergency spillway to avoid the kind of erosion experienced earlier this month.
CDWR and the commission rejected the request, with a FERC engineer writing that the emergency spillway could safely handle 350,000 cubic feet of water per second (cfs). The flow was only 6,000 to 12,000 cfs when the spillway was damaged, according to a report from the Bay Area News Group.
Outflows are outpacing flows into the reservoir despite stormy conditions, and CDWR said it will continue to prioritize bringing the depth of the reservoir to a target level of 895 feet. The agency said Feb. 20 that it had increased outflows from 55,000 cfs to 60,000 cfs in anticipation of increased inflows from recent rains.
“As runoff flows into the reservoir, water levels will likely fluctuate but will remain within acceptable and typical depths during times of storm activity,” the agency said in a Feb. 19 incident update.
CDWR said work crews continued to place rock and cement slurry into the areas affected by erosion, as ordered by FERC in a letter Feb. 13. In addition to ordering emergency repairs, FERC also ordered the state to convene an independent board of consultants to review current conditions and risk-reduction measures and to later conduct a forensic analysis to determine the cause of the failure.
“We have people there 24/7 from our San Francisco office as well as our Washington, D.C., office working with state officials … to protect public safety,” acting Chairman Cheryl LaFleur said in remarks at the winter meeting of the National Association of Regulatory Utility Commissioners on Feb. 14.
Rainy Winter
After years of drought, the region has experienced unusually high levels of precipitation this winter, which has filled the reservoir to capacity and left the lake’s elevation at about 900 feet above sea level. Snowpack in the Sierra Nevada mountains currently stands at about 175% of normal ahead of the spring melt, which tends to peak at the beginning of April, sending additional flows into the lake.
The 770-foot-high Oroville Dam in Butte County is the tallest in the U.S. and impounds one of California’s largest manmade lakes, a key source of water for farms in the state’s Central Valley and residents in Southern California, hundreds of miles to the south.
The dam’s Edward Hyatt and Thermalito generating facilities, which have a combined 933 MW capacity, remain offline, and three 230-kV transmission line segments in the area under CAISO control have been de-energized. The ISO said it had reoptimized its dispatch system to maintain reliability while continuing to meet demand within its balancing authority area.
“The loss of the Edward Hyatt power plant at Oroville dam is handled as we do with all generator outages,” the ISO told RTO Insider. “The outage, as well as the line outages, do not threaten grid reliability.”
County Seeks FERC Help
Officials from Butte County last week urged FERC to order CDWR to immediately establish its own public safety program to relieve the county of the “severe strain” on its “limited resources” (P-2100).
The county asked that the CDWR be ordered to provide law enforcement and other personnel needed to ensure public safety in the face of threats attributable to the dam, “including not just flood hazards but also fire, crime and other emergency services.”
Those personnel “should have the capacity to organize and implement all necessary public safety measures to prevent death from a failure of the dam spillways, including the orderly evacuation of the hundreds of thousands of people from the area downstream of the dam,” the county said in its Feb. 15 filing.
The filing also called out FERC for its failure to address Butte County’s previous entreaties, including a 2009 complaint in which the county argued that CDWR was in violation of its federal license for not contributing to covering the costs of ensuring adequate public safety at the Oroville site.
The commission rebuffed that complaint, and later denied the county a rehearing, after determining that the dam was in good condition and that the county had not pointed to any direct license violations.
“Because the commission has refused to order DWR to do what DWR is legally and morally obligated to do, and what other similarly situated licensees have done, Butte County has no choice but to request the commission to exercise its authority … to order DWR to take actions to effect its obligations as a Federal Power Act licensee, to protect public health, safety and welfare,” the county said.
WASHINGTON — A recent survey of state cybersecurity practices provided some surprising results, New Jersey Board of Public Utilities President Richard Mroz told the National Association of Regulatory Utility Commissioners’ winter meeting last week.
“We found most of the states actually do have a fusion center of some sort, so states are taking that seriously,” Mroz said, referring to locations at which state agencies share intelligence on security threats. “On the other hand we hear … from our colleagues that they don’t know what the best [cybersecurity] practices are — what’s working elsewhere.”
Mroz is chairman of NARUC’s Critical Infrastructure Committee, which sent the survey last year to the 34 states that are members of the committee; 19 had responded as of January. The committee is now seeking responses from the remaining states, including those not on the panel. The results will be included in what NARUC intends as a “living” catalog of information about state regulators’ efforts on critical infrastructure resilience. The survey is also referenced in the latest edition of NARUC’s cybersecurity primer, which was released Jan. 31.
Also speaking on the NARUC General Session panel Tuesday was former Sen. Rick Santorum (R-Pa.), who expressed concern over the shortage of cybersecurity personnel and their lack of preparation for “war.”
“These are people who went to school for computer service or a whole variety of other things and they’re the people who are our quote ‘war fighters.’ They’re not trained as war fighters … and yet they’re in the middle of a battle,” said Santorum, an unsuccessful presidential candidate in 2012 and 2016.
“So they don’t take the approach of ‘How do we comprehensively deal with this problem?’ … We seem to be saying just ‘How do we defend ourselves?’ instead of ‘How do we really put a strategy together to attack the enemy to make sure they aren’t attacking us?’
“I’m not too sure we want corporations out there attacking those who might attack them, but I think we have to start thinking about innovative ways in which to deter people from coming at us,” he added.
In conversations with former colleagues on Capitol Hill, Santorum said, he has proposed “retasking” the National Guard for a cyberdefense role. “We need these people to be out across America to be almost like a Minute Man type of operation to be able to respond to some of these threats we have.”
Jonathon Monken, PJM’s senior director of system resiliency and strategic coordination, a West Point graduate and former director of the Illinois State Police, responded that officials need to “de-conflict … the lanes of effort” by clearly defining roles and responsibilities to determine “who’s best suited to do what.”
Monken said the electric industry also needs to improve the security of its tools.
“Recognizing the fact that our systems are interconnected. Our [information technology] configurations are very, very similar. They’re not identical. It’s not if you breach one that you get access to everybody. But it’s not like there’s that many different [energy management system] providers out there. It’s just a handful of system types and the architectures are very similar.”
Separately, acting FERC Chairman Cheryl LaFleur talked about the importance of collaboration between government and industry and of not relying on just meeting NERC’s standards on critical infrastructure protection.
“While mandatory standards are important, the cyber challenges are evolving so quickly, you can’t really regulate your way out of it. You can’t do a standard fast enough for some new piece of malware or ransomware that comes along,” she said. “The non-mandatory piece is becoming more and more important.”
WASHINGTON — Choices made by customers on issues ranging from carbon dioxide to technology could rank alongside decisions made by policymakers in shaping the future of the grid, RTO officials said last week.
McCoy | Smartwires
This was a recurring theme during a Feb. 16 briefing by WIRES, the House Grid Innovation Caucus, the National Electrical Manufacturers Association (NEMA) and the Environmental and Energy Study Institute (EESI). “Unlike ever before, the electric customers are actively participating in the industry,” said Adriann McCoy, a vice president of Smart Wires, which makes advanced power flow control technology. The growing clout of end users is reflected in rooftop solar, plug-in electric vehicles and consumers’ purchasing of renewable power from alternative suppliers, she said.
“Anytime consumers start playing more actively in a market,” it brings about innovation, McCoy said.
Coal plant retirements, such as the recently announced plans to close the Navajo power plant in Arizona, will require that electricity be moved from other sources, McCoy said. The utility owners of the Navajo plant said Feb. 13 that they don’t plan to operate the facility beyond December 2019.
Speakers said people’s choice about where their power is coming from is driving the transmission system. This includes decisions favoring renewable energy and less-carbon-emitting sources.
“The planning is only slightly less complicated than the engineering” these days, said former FERC Chairman Jim Hoecker, counsel to WIRES. “It’s a challenging time, it’s a transformative time, for the electricity business.”
At the same time, a robust transmission system will save consumers billions every year in avoided power disruptions, Hoecker said. “That’s not pocket change,” he added.
Moeller | MISO
MISO Executive Vice President Clair Moeller said it is resilience and the need to move power from new low-carbon resources that is driving new transmission. “There is essentially no load growth in the nation,” he said. “My job at MISO is mostly about planning,” Moeller said. Sometimes “you get cheaper electricity from your next-door neighbor,” rather than from the generating unit in your own area, Moeller said.
Congress in 1992 said it wanted to see more electric competition, said Craig Glazer, PJM vice president for federal government policy. But even since the Energy Policy Act of 1992, lawmakers still engage in picking winners and losers, Glazer said.
The wind production tax credits and state bailouts of struggling nuclear plants can make things complicated, Glazer said. But Glazer cautioned against too much market tinkering, noting that the goal of competition was to shift risk from ratepayers to shareholders.
Ross | SPP
Innovation happens quickly, but “Congress doesn’t move very fast,” said former U.S. Rep. Mike Ross, senior vice president for government affairs at SPP. Congress needs to ensure its laws “don’t get in the way” of innovation, Ross said.
Many panelists said while the concept of regional planning is popular in the abstract, it often runs into roadblocks in the real world. For example, states are all over the board on issues like renewable mandates, Moeller said.
“States have not wanted to relinquish their regulatory authority over utility operations. This is a tremendous burden to interstate commerce,” Hoecker said.
“We want to make sure this [electric transmission issue] is front and center … that people know how important this is,” said Rep. Jerry McNerney (D-Calif.), who co-chairs the House Grid Innovation Caucus along with Rep. Bob Latta (R-Ohio).
NEW ORLEANS — Three years after the region’s integration, MISO South, with its plentiful gas generation, constrained interface into the North and capacity for severe weather, still doesn’t feel fully “in” the RTO, speakers told the Gulf Coast Power Association’s MISO South Regional Conference on Thursday.
Jennifer Vosburg, president of Louisiana generating at NRG Energy, said MISO’s North-South transfer constraint under the RTO’s settlement with SPP limits South’s participation in North. “It’s a challenge to how competitive MISO South continues to be,” Vosburg said.
“The drive to integrate into MISO was, ‘We’re going to be fully in MISO,’” Vosburg said. “We’re proud that the Planning Resource Auction limit is 600 MW more this year. That’s not fully integrated … MISO South is not on the same playing field as MISO North.”
Multiple panelists said the constrained North-South interface has exacerbated an “illiquidity” issue in MISO South.
Plentiful capacity in South is unable to help shortage conditions in North, Vosburg said, and South will remain isolated until it can fully participate in the market. She added that since integration, it is often easier to sell in the PJM capacity market than participate in MISO’s capacity market.
Vosburg said MISO’s once-thriving independent power producers have become “a lonely table.”
Paul Zimmering, an attorney at Stone Pigman who has represented the Louisiana Public Service Commission, said the North-South transfer limit should have been examined by MISO much earlier than its currently underway footprint diversity study. “This is 2017, and we were hoping this would have been looked at earlier. We thought that we would get an evaluation earlier on, but it’s happening now and it’s great,” Zimmering said.
However, Zimmering said MISO is doing a good job through its Transmission Expansion Plan playing catch-up on other transmission projects in the Entergy territory that were ignored prior to the incorporation of MISO South. He said 86% of Public Utility Regulatory Policies Act qualifying facilities in South now participate in the MISO market.
“One MISO is a goal, and I don’t think we’re there just yet,” he added.
Zimmering also said regulation challenges exist in MISO South, where states — Louisiana, Texas and Arkansas — are located in both SPP and MISO. “There are a lot of — I wouldn’t call them divided loyalties — but different interests to look out for,” he said.
MISO President and CEO John Bear pointed out the $2.3 billion in transmission investment since MISO South’s addition in 2014 and said the RTO has created almost $2.5 billion in total savings over the region’s three years of existence.
The value “is real and it’s happening, and I think it’s a really good story,” Bear said.
Although the region hasn’t experienced a hurricane since integration, operations have withstood significant weather events, Bear said: tornados in northern Arkansas in 2014; a Texas dam at risk because of heavy rains in 2015; flooding in eastern Texas and Louisiana; and persistent regionwide heat in 2016.
Matt Brown, vice president of federal policy at Entergy, said MISO’s footprint-wide climate differences are a benefit to MISO South, allowing lower planning reserve margins. Brown said Entergy operating companies saved about $412 million in 2014 and 2015 after joining the RTO. Transmission investment in MISO South has doubled from $359 million in MTEP 14 to $886 million in MTEP 16.
Jim Schott, vice president of transmission for Entergy Louisiana, said the company has noticed that the RTO can better identify congestion for future projects and has sounder congestion management practices, decreasing instances of transmission loading relief (TLR).
“Since December of 2013, TLR and [local area procedures] have hardly been uttered once,” Brown said.
Schott also said MISO membership means Entergy plans projects further in advance to fit into the annual MTEP schedule.
He also made a case for allocating costs of economic transmission upgrades to benefiting local resource zones alone. The RTO is considering changing cost allocation for economic projects in time for 2018, when costs can be shared with MISO South. “Benefits generally flow to some region, and the region should bear those costs,” he said. (See MISO Stakeholders Propose Changes to Market Efficiency Cost Allocation Process.)
Ted Kuhn, consultant at Customized Energy Solutions, said integration has brought pricing transparency — and added bureaucracy — to MISO South. “It takes time to get things through a larger process. It takes time to know which stakeholder meetings to go to, which person to talk to. It’s a process that will kill you if you don’t know it,” he said.
SPP Seam and MISO South
Laurie Dunham, vice president and manager of regional planning for Duke-American Transmission Co., said SPP and MISO need better coordination of the models in their joint studies. She urged stakeholders to get involved in interregional planning meetings.
Dunham said large-scale transmission projects aren’t always needed to resolve reliability issues, and, in some cases, the addition of “2 to 5 miles of line and a reactor” eliminates a problem.
Patrick Clarey, a FERC attorney adviser, noted that SPP is facing challenges with greater wind penetration. MISO and SPP’s possible overlay study, designed to last through 2019, could produce transmission projects to solve SPP’s problem, he said. (See related story, SPP Eyes 75% Wind Penetration Levels.)
Ted Thomas, chairman of the Arkansas Public Service Commission, said his state is in a good position — for now.
“It’s easy to be in my position when gas prices are low. Our utilities aren’t stirred up, our customers are satisfied, the legislature is calm,” Thomas said. However, he added, “if the last three weeks are any indication of the next three years, administrations will change, federal policies will zig-zag … and the consumer needs to be protected throughout.”
MISO South and the Climate
Thomas said the electric industry’s long 30- to 40-year capital cycles create a high risk of stranded costs. He said with Arkansas, Texas and Louisiana’s low-cost energy when compared to California’s prices, MISO South can wait to implement more expensive and experimental carbon-reduction measures.
“We can’t stick our heads in the sand. But we can wait and see. We don’t have to take the risk that the high-cost states take,” Thomas said. “I know that carbon is a long-term problem, and I question if we have a solution. I know that some states have a political appetite to reduce carbon, but I also know that Arkansas, and I suspect Louisiana, aren’t those places,” Thomas said. He added that even if Arkansas eliminated carbon emissions by 2018, it would not be enough to impact global temperature rise.
Other panelists maintain that MISO South is ripe for increased renewable penetration and more energy efficiency programs.
Siobhan Foley, the City of New Orleans’ FUSE Executive Fellow for Climate Action, said solar has come down dramatically in price and now is viable in terms of cost. She said MISO South can reduce carbon through several smaller solar projects. “It really is about smaller wedges and more of them, sharing and distributing in different ways,” Foley said.
Dunham said that the Clean Power Plan’s uncertain future should not stop the adoption of renewables and storage. “I don’t think it’s ever ‘pencils down.’ We need to be always modifying and adapting,” she said.
Low Rates, High Bills
Some officials think MISO South could do with more energy efficiency programs to reduce the region’s high energy consumption.
“We have low rates, but we have really high bills,” said Logan Atkinson Burke, CEO of consumer advocate Alliance for Affordable Energy. She said Entergy New Orleans customers have among the highest energy use rates in the country. Mississippi, Alabama and Louisiana rank among the worst in the country in available energy efficiency programs.
Thomas said energy efficiency programs can help defer “big decisions” and capital expenses by keeping demand low.
Jeff Baudier, chief development officer of Louisiana-based Cleco Holdings, said the company’s addition of a heat recovery steam generator to the Cabot coal plant in the St. Mary Parish in Franklin, La., will add 50 MW of capacity with no additional emissions. The project is expected to be in service in the first quarter of 2018.
Ted Romaine, director of origination for renewable generation developer Invenergy, said commercial and industrial customers, especially Internet companies like Google, Amazon and Facebook, are increasingly making off-site renewable energy deals such as virtual power purchase agreements.
“This is a market that’s really picked up steam in the last few years. … We see more buyers come into the market, and interest continues to grow. This isn’t a Silicon Valley-exclusive market,” Romaine said.
ERCOT, SPP and PJM lead in corporate off-site renewable deals with a 77% share of the U.S. and Mexico, Romaine said. He said although MISO doesn’t have any such contracts, it will in the future. He expects more than 20 first-time corporate renewable buyers nationwide in 2017. He added that vertically integrated MISO South utilities might bend to pressure from big energy users such as Google to create green tariffs — renewable energy purchasing programs — even if they have no legal obligation to do so. He said there is “strong potential” for solar-based virtual power purchase agreements in MISO South.
“If we don’t start recognizing that multinational corporations have sustainability agendas, they’re going to go somewhere else,” Baudier said.
PPL’s earnings from ongoing operations rose 11% to $1.67 billion last year, boosted by a 39% jump in the fourth quarter as the company benefited from a strong performance by its utilities and gains on currency hedges.
Reported earnings more than doubled to $1.9 billion ($2.79/share) for the year, compared with $682 million ($1.01/share) in 2015, which included a $921 million loss from discontinued operations, primarily the spinoff of its competitive supply business to Talen Energy.
PPL workers raising an osprey nesting platform at Owl Creek Reservoir near Tamaqua, Pa. | PPL
The company’s results exceeded the high end of its 2016 reported earnings forecast range of $2.55 to $2.70/share.
Reported fourth-quarter earnings were $465 million ($0.68/share), compared with $399 million ($0.59/share) in 2015. Eliminating special items, fourth-quarter earnings from ongoing operations were $409 million ($0.60/share) versus $294 million ($0.43/share) a year earlier.
CEO William Spence said the company made $3 billion in infrastructure investments last year and plans an additional $16 billion over the next five. “We are confident in our ability to deliver our projected 5 to 6% compound annual earnings growth range from 2017 to 2020 even if the exchange rate declines well below current levels,” Spence said in a statement.
The company announced that it is increasing its quarterly common stock dividend from 38 cents/share to 39.5 cents/share, payable to shareowners of record as of March 10. The increase is PPL’s 15th in 16 years.
Duke Energy saw its 2016 earnings drop more than 20% to $2.15 billion ($3.11/share) from $2.82 billion ($4.05/share) in 2015 largely because of a loss on the sales of its international energy operations.
For the fourth quarter, Duke reported a loss of $227 million ($0.33/share), compared to a profit of $477 million ($0.69/share) for the same period in 2015.
The company’s adjusted earnings were $3.24 billion ($4.69/share) for the year up from $3.15 billion ($4.54/share) a year earlier. Adjusted earnings exclude merger costs, severance charges, asset impairments, a 2015 charge associated with the Edwardsport IGCC regulatory settlement, and the loss on the sale of its hydroelectric and natural gas generation plants, transmission and natural gas processing facilities in Central and South America.
The company said results were bolstered by favorable weather, cost controls and the early close of its acquisition of Piedmont Natural Gas.
Nashville CNG Fueling Station | Piedmont Natural Gas
“2016 was a transformational year for Duke Energy as we acquired Piedmont Natural Gas and exited our international business,” CEO Lynn Good said.
Duke has realigned its reporting segments into three major categories: Electric Utilities and Infrastructure; Gas Utilities and Infrastructure; and Commercial Renewables.
The Electric Utilities segment earned $483 million in the fourth quarter, down from $569 million in the last quarter of 2015. The company blamed higher operations and maintenance expenses, tax rates, interest expenses and depreciation and amortization costs.
The Commercial Renewables unit earned $10 million in the fourth quarter, down from $17 million a year earlier, because of lower investment tax credits resulting from lower solar investments, partially offset by higher production tax credits from additional wind facilities placed in service.
MISO is seeking stakeholder input on improving how it estimates costs in its competitive bidding process.
The RTO is proposing separate approaches for transmission lines and substations, MISO transmission design engineer Devang Joshi said at a Feb. 14 Planning Subcommittee meeting.
For transmission lines, MISO will consider length, voltage, structure and conductor type, terrain type and right-of-way cost.
For substations, the RTO will take into account the number of new lines and major equipment positions added; bus and breaker arrangement; land cost, grading, fencing, any equipment to ground the lines and a control enclosure; and major equipment additions such as a reactors, capacitors or transformers.
MISO uses cost estimates to calculate benefit-to-cost ratios on potential market efficiency and multi-value projects. Before Order 1000, transmission owners or other stakeholders provided the estimates. But with the advent of competition for such projects, TOs’ cost estimates are now confidential information.
In evaluating bids, MISO will continue to weigh cost and design at 30%, project implementation at 35%, operations and maintenance at 30% and transmission planning participation at 5%.
Senior Substation Design Engineer Alex Monn said once feedback is received, the RTO will put together a guide on its cost estimation process.
Rules on Non-Transmission Alternatives Ready for PAC Review
After two years of work, Business Practices Manual language on non-transmission alternatives is nearing completion and ready to move to the Planning Advisory Committee for review, principal adviser Matt Tackett said.
Under the new process in BPM 020, once transmission issues are identified for the annual Transmission Expansion Plan, ”the planning process will explore alternative solutions to those issues with the objective of recommending the best overall solutions.” MISO will provide developers minimum planning requirements “to provide for the consideration of both transmission and non-transmission alternatives.”
The RTO said it will “defer, de-scope or cancel the transmission project previously proposed” if a non-transmission alternative is selected over a traditional transmission project.
“I think as we approach the MTEP 18 planning season, most of us would agree to move this on. The vetting isn’t over, but it’s a good time to make a transition to the PAC,” Tackett said.
Generators Identified in MISO Retirement Analysis
MISO has compiled generator data for its MTEP 17 retirement sensitivity study scope.
The study will use 378 forecasted generator retirements from 2004 through 2027 and 30 planned generator additions in MISO, SPP, PJM and SERC Reliability territory to determine transmission system needs.
MISO engineer Anton Salib asked stakeholders to submit any changes to the generator retirement list by Feb. 22. At the beginning of March, the RTO will post the final list of retiring generators and future resource additions to be used in the study. Results will be reviewed in the spring during sub-regional planning meetings.
Salib said the retirement analysis is only an informational study and MISO will not recommend any project in the MTEP 17 cycle based on the study.
The MTEP study will share information with the RTO’s Regional Transmission Overlay Study and market congestion planning study. (See “Studies Could Assist in Relieving North-South Constraint,” MISO Planning Advisory Committee Briefs.)
WASHINGTON — U.S. Rep. Greg Walden (R-Ore.) said the agenda of the House Energy and Commerce Committee that he chairs will hew close to traditional party positions, emphasizing the importance of letting states and market forces guide development rather than policies and regulations.
Walden | NARUC
Walden made the comments while addressing the National Association of Regulatory Utility Commissioners at its annual winter meeting. He requested the opportunity to roll out the agenda to the conference, according to NARUC President and Pennsylvania Public Utility Commissioner Robert Powelson. “With a unified government, we actually have a rare opportunity to enact reforms that build on energy abundance, modernize our energy infrastructure and promote domestic manufacturing and job growth,” Walden said. “You can be certain that we will ensure our efforts focus on the issues that matter most to consumers.” (See Interdependence Key to Cyber Efforts, Congress Told.)
The country has been held back by a “Washington-centric, regulatory and environmental agenda,” he said, that was “picking winners and losers, putting reliability at risk and driving up costs.”
The committee will review the interaction between federal and state government on resource planning, such as the Public Utility Regulatory Policies Act, and address “recent efforts by the EPA to erode states’ authority through the Clean Power Plan.”
He called on the new administration to install new commissioners at FERC quickly and indicated the nuclear industry would be a major focus of the committee.
“The Yucca Mountain project must remain central to our nuclear waste-management system,” he said, adding that plans could include authorizing an interim storage facility, along with moving forward on fuel reprocessing. (See related story, Panelists Weigh Prospects for Nuclear Waste Solution Post-Obama.)
Georgia Public Service Commissioner Tim Echols asked Walden’s view on how reprocessing might make the national energy policy more sustainable.
“It’s something, obviously, that other countries do pretty effectively, and I see no reason why we can’t take a look at that seriously in this country,” Walden said. “It’s about time.”
He noted that while the Yucca Mountain project was canceled by the Obama administration, the total future liabilities and payments paid by the U.S. Treasury for nuclear-waste storage doubled to nearly $30 billion over the last eight years. The federal government can no longer collect a nuclear waste fee from ratepayers, he said, but the fund already has $36 billion and collects $1 billion in interest annually.
WASHINGTON — While FERC has given states a wide berth for determining the avoided-cost rate for qualified facilities under the Public Utility Regulatory Policies Act, other regulatory inconsistencies and utility “recalcitrance” have hindered the law’s implementation, a panel of experts told regulators this week at the National Association of Regulatory Utility Commissioners’ winter meeting.
PURPA was established in 1978 to diversify the country’s energy supply, increase efficiency, reduce dependence on fossil fuels and develop a market for independent power producers. It requires electric utilities to purchase the output of cogeneration and small power-production “qualifying facilities” (QFs) at the cost a utility would incur for supplying the power itself or by obtaining supplies from another source. The law leaves it to each state’s utility commission to formulate those “avoided costs.”
No Second-Guessing
“We have been very explicit about this: We are reluctant to second-guess a state’s determination on avoided costs,” said Lawrence Greenfield, a senior attorney at FERC.
The Energy Policy Act of 2005 amended PURPA to allow termination of the must-buy requirements if FERC finds that the QF has nondiscriminatory access to make market sales. The commission has ruled that includes QFs of more than 20 MW that participate in RTO markets. (See FERC: Entergy not Required to Buy from Large QFs.)
Greenfield noted that the most recent litigation over PURPA has been in non-RTO regions.
“I’m not sure what that says exactly about RTO markets, whether they are more efficient or less efficient, more pro-QF or less pro-QF, but it is an interesting observation that the litigation seems to be concentrated in non-RTO markets,” he said.
He later added that retail choice and resource diversification might draw consumers to other generators “and that might indirectly impact QFs, but we certainly haven’t seen it in the cases we have had.”
Irene Kowalczyk, director of global energy at paper and cardboard manufacturer WestRock, said it’s “probably harder” to get PURPA-based contracts in open-access states because the utilities don’t own the generation and aren’t issuing major requests for proposals.
‘Black Box’ Avoided-Cost Formulas
“In regulated markets, PURPA is somewhat working,” Kowalczyk said, though she added that states’ avoided-cost formulas are often a “black box,” with inconsistent methodologies and no overall framework.
“Notwithstanding the complaint about FERC’s 1-mile rule, today’s complaints about PURPA are nothing new and echo complaints made 30 years ago, when PURPA was initially implemented,” said Ari Peskoe, a senior fellow in electricity law at the Harvard Law School.
The “1-mile rule” requires developers to maintain a 1-mile buffer between projects to qualify them as separate QFs. The commission implemented the provision to prevent developers from “disaggregating” large generation projects into smaller units to qualify under PURPA.
Peskoe argued that much of the blame for slow implementation should be focused on utilities.
“When a utility today claims that it has an abundance of QF energy, I suggest it’s worth investigating how the utilities actions may have contributed to that situation,” he said, noting that many utilities continue to overestimate demand growth in their integrated resource plans. “To what extent utilities’ inaccurate load forecasts, failure to account for those mistakes and lack of foresight about the development of renewable energy technologies contribute to their perceived abundance of QF energy, should the utility be held accountable for these mistakes? How can regulators do so while protecting ratepayers? These are obviously not easy questions to answer, but I suggest they are worth asking.”
Combined Heat and Power
Kowalczyk, who also represented the Industrial Energy Consumers of America, said the rules need to be revised, clarified and standardized across all states so that utilities regard QFs in the proper context.
“The RTO rules treat industrial CHP [combined heat and power] and waste-heat recovery QFs as if they’re merchant power plants that sell power as their primary business,” she said. “To achieve the lowest cost possible for the ratepayers, states should encourage utilities to develop technology-specific avoided cost rates for each resource type. … The minimum term for QF contract should include 10 to 12 years of capacity payments for QFs of all sizes in fully regulated non-RTO areas and in RTO markets for smaller QFs.”
Kowalczyk added that it’s hard for CHP units to perform as capacity resources because their output is entirely dependent upon the steam requirements of plant’s primary manufacturing process. The rule’s inconsistencies have reduced enthusiasm for such projects. “I don’t think any new CHP-type facilities have been installed in those RTO markets … because they can’t get the financing. The RTO markets aren’t sufficient to provide sufficient compensation that is certain to enable those QFs to be built. So what we’ve seen since the passage of the Energy Policy Act of 2005 is a significant reduction in the amount of CHP and waste-heat recovery-type facilities being built.”
Payments to QFs in PJM are often based on energy and capacity clearing prices, she said, though Peskoe noted that courts have ruled that the avoided-cost rate can’t be based on spot-market prices.
Greenfield said FERC prefers that utilities and QFs negotiate mutually agreeable terms, but that it’s also interested in seeing QFs sign long-term agreements. He added that FERC doesn’t have any specific revisions to the law that it would like to see made to the law.
“We at FERC are largely agnostic about changing PURPA,” he said. “Our view is: Whatever Congress tells us to do, that’s what the hell we’re gonna do.”
In a separate NARUC session, acting FERC Chairman Cheryl LaFleur had the same message. Changes that people have asked FERC to make to PURPA rules “are really legislative changes,” she said.
The RTO is proposing separate 
MISO uses cost estimates to calculate benefit-to-cost ratios on potential market efficiency and multi-value projects. Before Order 1000, transmission owners or other stakeholders provided the estimates. But with the advent of competition for such projects, TOs’ cost estimates are now confidential information.
