Page 1276 – RTO Insider

September 14, 2017

CAISO Regionalization, 100% Clean Energy Bills Stall

By Jason Fordney

SACRAMENTO, Calif. — State legislation that would regionalize CAISO and mandate 100% zero-carbon retail electricity sales statewide by 2045 sputtered with just days left in the legislative session and will not pass this year, a key legislator told RTO Insider on Wednesday.

caiso zero-carbon bill — Assemblymember Chris Holden (D) Says He Will Take Up Regionalization Next Year | © *RTO Insider*

State Assemblymember Chris Holden (D), who sponsored two bills that would regionalize CAISO, said he plans to go forward with the regionalization effort next year. His main vehicle for regionalization, AB 726, was kicked back to the Senate Rules Committee yesterday and would need to be approved by a policy committee before returning to the State Senate floor.

That won’t happen, Holden said, because it was not assigned to a committee and will not be heard. Another bill with regionalization language, AB 813, was amended last week by the Senate and referred back again to the Rules Committee.

“What we wanted to do on the regionalization piece is make sure there was legislative review of whatever came out of a committee evaluation,” said Holden, who chairs the Assembly Utilities and Energy Committee. “We wanted that committee to be unanimous. The strategy was then to move to the legislature where people who represent all parts of California had a chance to sign up and speak. It is big legislation, and we wanted to make sure everybody had a say in it.”

Both bills also contain a provision that would require California electricity sellers with more than 100,000 customers to procure “tax-advantaged” renewable generation above that required by the state’s renewable portfolio standard and recover costs from retail ratepayers. The measure is intended to encourage the development of new renewable resources within the state before the expiration of federal production tax credits in 2020.

Holden said his focus initially was taking advantage of expiring tax credits on wind and solar, and there were also concerns in the geothermal community.

“Regionalization was introduced into the conversation around the bill, which I had no problem with doing, as long as it was broken into two pieces — multiple pieces — so it’s not like ‘here’s what we’re going to do and we are cutting everybody out,’” he said.

Independent Energy Producers Association CEO Jan Smutny-Jones said that regionalization would make it easier to export excess solar from California and allow access to lower-cost renewables around the West.

“Obviously, we have spent a lot of time on these issues this year. It’s unfortunate that we couldn’t quite get it out of the legislature this first year, but we look forward to working on it when we come back in January,” he said.

The ISO has allowed for more efficient use of transmission, and the same would be true with regionalization, Smutny-Jones said.

“From a market efficiency perspective, it will work a lot better,” he said. He noted that the Western Energy Imbalance Market (EIM) is working well on a regional basis, but it is only a five-minute market and does not allow day-ahead transactions like a full ISO.

CAISO itself also favors regionalization. It did not return a request for comment as of press time.

The zero-carbon bill, SB 100, introduced by Senate President pro Tempore Kevin de Leon and widely anticipated by the renewable energy community, faces strong headwinds, according to Holden. (See California Zero-Carbon Power Bill Advances.)

Of SB 100, Holden said, “That is not going to move — there is overwhelming opposition to it. And there is not time to work that out.” He is hoping to integrate the various proposals so there is “a global fix to everything. But we are out of time.”

September 14, 2017

Late Changes to Texas Project Frustrate MISO Participants

By Amanda Durish Cook

MISO is recommending a new version of a transmission project intended to alleviate constraints in the West of the Atchafalaya Basin (WOTAB) area straddling Texas and Louisiana, but some stakeholders are balking at assumptions underpinning the proposal.

The $129.7 million project involves construction of a new substation in eastern Texas equipped with a 500/230-kV transformer. The facility would accommodate a new 500-kV line running from Hartburg, Texas, as well as a reconfiguration of the existing Sabine-McFadden and Sabine-Nederland 230-kV lines. The expanded voltage is expected to fully relieve area congestion and reduce the amount of voltage and local reliability make-whole payments needed in the WOTAB load pocket.

MISO WOTAB miso west of the atchafalaya basin — New WOTAB Project | *MISO*

“We’ve looked at this project every which way … and this is robust and cost-effective, even under conservative assumptions,” said Arash Ghodsian, MISO manager of economic studies.

Flowgate Oversight

An earlier $137.6 million proposal called for a new 500-kV line from Hartburg to Sabine and an expansion of two existing substations. That project was identified in MISO’s annual Market Congestion Planning Study, which this year focused exclusively on possible MISO South projects.

After local transmission owner Entergy increased a flowgate rating in March, the project no longer met the 1.25 benefit-cost ratio required to qualify as a market efficiency project for this year’s MISO Transmission Expansion Plan. While TOs can increase or decrease line ratings without permission from MISO, they must update facility ratings with the RTO.

MISO initially overlooked the spring flowgate rating change. The RTO waited until July to model that change and study three project alternatives, eventually settling on the revised 500-kV proposal. Some stakeholders objected to last month’s last-minute unveiling of possible projects, noting that the Board of Directors reviews MTEP projects in early December.

Two other smaller projects resulting from the Market Congestion Planning Study — also in the WOTAB load pocket — were unaffected by Entergy’s flowgate change. (See Congestion Projects, Siting Review on MISO Slate.)

Last-minute Concerns

Xcel Energy expressed concerns about MISO’s decision to change the modeling and weighting of MTEP futures for the study after having developed and approved the study’s supporting models and initially identifying congestion in the area. While stakeholders last year agreed on the relative weight of MTEP futures in planning studies, the RTO allowed a unique weighting for MISO South after the region’s TOs and state regulators asked for reduced emphasis on a future scenario involving accelerated alternative technologies. (See MISO Changes MTEP Futures Weighting for South.)

Xcel said that MISO — in the spirit of openness — should have reopened the planning study’s project submission window after changing the weighting.

“Without reopening the entire development process and reopening the window after the new models and weights were decided, MISO set a very concerning precedent which introduced gaming of the study results by allowing this unacceptable change to happen without a sufficient level of stakeholder involvement,” Xcel said in comments filed with the RTO.

NRG Energy also cautioned MISO against making last-minute modeling changes.

“New or changes in modeling assumptions can be requested at the beginning of each Market Congestion Planning Study cycle,” the company said in comments. “However, last-minute modeling changes should not be allowed unless they are necessary to correct gross errors. Otherwise, this would set a dangerous precedent and the process could well become a ‘free-for-all’…

“All modeling changes should be thoroughly vetted in the stakeholder process for approval and implementation.”

‘No Process is Perfect’

Ghodsian said the new project has been subject to open and transparent vetting despite the change in modeling criteria. Other stakeholders, including DTE Energy, LS Power, Apex Clean Energy and ITC Holdings, supported MISO’s analysis behind the project alteration.

Apex said it’s clear that the load pocket needed a high-voltage project to mitigate voltage and local reliability issues.

“The transmission system needs expansion. Lack of high-voltage solutions for WOTAB has inhibited growth in an area of the country which has seen unrivaled increases in petrochemical manufacturing in addition to the production and export of LNG,” Apex said.

Some stakeholders did take issue with MISO modeling a $1,000/MWh emergency energy price in the study when it currently caps prices at $3,500/MWh. Entergy’s Matt Brown called for aligning the emergency pricing in the models for MTEP 17 with the RTO’s actual cap.

“We can’t just continue to kick this can down the road. … This issue has been with us for a while now, and at some point, we have to address it,” Brown said.

Ghodsian said MISO will address new emergency energy pricing in the models starting with MTEP 18.

“No process is perfect, and we welcome suggestions on improving [it],” Ghodsian said.

The three projects arising from the Market Congestion Planning Study will go before the board’s System Planning Committee next week and the Planning Advisory Committee later this month.

September 14, 2017

Controversial Ameren Efficiency Plan Wins Ill. Approval

By Amanda Durish Cook

The Illinois Commerce Commission on Monday conditionally approved Ameren Illinois’ request to lower the utility’s energy-efficiency goals established under the state’s recently enacted Future Energy Jobs Act.

The commission’s approval came despite extensive pushback from consumer and environmental nonprofits — who accused Ameren of attempting to bypass efficiency targets — and a preliminary ruling from an administrative law judge denying the requested change (17-0311).

Ameren Illinois energy-efficiency — | *Ameren Illinois*

The judge last month issued a preliminary order rejecting the utility’s plan, saying Ameren could shift money and priorities around to meet its annual energy savings goal while staying within the law’s budget cap. (See State Could Reject Ameren Illinois Efficiency Target Reset.)

Still, the commission approved Ameren’s plan despite its relatively high costs for each unit of energy saved. Under the plan, Ameren expects to spend 32 cents/kWh saved, compared with the 21 cents/kWh saved for residential customers and 13 cents/kWh for business customers during 2016.

Critics had wanted Ameren to squeeze more energy savings out of the $114 million per year the utility has allocated to the program, but the commission agreed with the company that the “unique circumstances” of its “largely rural” service territory — in which many customers are exempt from the efficiency provisions — made it difficult to achieve higher savings.

The proposed measures “promote the objectives of the statute,” the ICC found.

Conditions Apply

The commission’s approval also came with some strings attached.

“Ameren Illinois’ request for approval of modified goals is conditionally granted, provided that the company present to the commission, as a compliance filing, amendments to its plan design that provide additional annual savings that will assist more Ameren Illinois customers,” the ICC said in its ruling.

Among the conditions: Ameren will be required to attend at least three workshops hosted by commission staff where “stakeholders may offer proposals to aid Ameren Illinois in achieving statutory savings goals” in future plans. Commission staff will make a report following the workshops.

The commission also said it will reassess Ameren’s goals and performance after a year and required that the utility donate any performance incentives from meeting its modified savings goals to nonprofits that assist low-income communities with energy-efficiency measures.

“By proposing to donate any performance incentives it might realize, Ameren Illinois satisfactorily addresses any concern that it is attempting to profit by manipulating savings goals so that it will be certain to achieve them,” the commission said.

Under the Future Energy Jobs Act, Ameren is required to meet 9.8% in cumulative annual energy savings by 2021, but the utility is planning for 8.24% in savings. The utility had allocated $114 million per year for the program, the maximum budget under the law, but it claimed it still could not meet the savings goal. A maximum budget triggers the ICC’s authority to reduce annual incremental savings goals.

Ameren said it remains committed to achievement of the agreed upon savings target of 13% by 2025.

“Based on our initial understanding of the order, we are in agreement with the commission on many points. Our innovative energy efficiency plan will result in customer cost decreases,” Ameren Illinois spokesperson Marcelyn Love told RTO Insider.

Rehearing?

The Environmental Defense Fund said it would seek a rehearing on the issue after learning of the decision, citing the ALJ’s preliminary order. EDF, the Natural Resources Defense Council and the Citizens Utility Board “provided numerous suggestions for Ameren to meet its efficiency goals and provide maximum savings to a greater number of customers,” EDF said.

“Ameren is abandoning its energy-efficiency commitments, meaning fewer customers will get help lowering their energy bills, and those who do will be saving less. … The decision robs people in Central and Southern Illinois of the cleaner air, lower bills and clean-energy job opportunities they were promised by the Future Energy Jobs Act,” said EDF’s Christie Hicks.

The Illinois Clean Jobs Coalition also expressed disappointment with the order, saying the ICC disregarded the opinion of its own ALJ.

“Ameren’s plan to scale back savings from energy-efficiency services will prevent people in Central and Southern Illinois from reaping the same benefits that people in Chicago and Northern Illinois will receive under the Future Energy Jobs Act,” the coalition said. “Disadvantaged communities should be prioritized for investments, and we believe that Ameren can and should also provide the same quality of services.”

September 13, 2017

UPDATE: Last-minute Bill Boosts CAISO Regionalization Effort

By Jason Fordney

Last-minute legislation that would transform CAISO into a new regional system operator appeared to stall in the California State Senate yesterday after being kicked back to the Rules Committee.

CAISO regionalization — Holden | © *RTO Insider*

Lawmakers drew criticism this week for moving ahead with legislation close to the end of the session that could spur the process of regionalizing CAISO starting in late 2018. The regionalization language was inserted late last week into two bills sponsored by State Assemblymember Chris Holden (D), chairman of the Assembly Committee on Utilities and Energy, which held a June hearing to look at CAISO expansion. (See California Lawmakers Take Up CAISO Expansion.)

One bill, AB 726, was amended on the Senate floor and essentially became a new bill that now requires waiver of procedural rules to be reviewed by a policy committee and then sent back to the Senate for a vote. But time is short, with the legislative session ending Friday and a heavy volume of other legislation under consideration before the legislative deadline. Similar language was inserted into a separate bill, AB 813, which was sent back to Rules Committee on Sept. 8.

The legislation could set in motion a dramatic restructuring of CAISO — an expansion that has been discussed since 2015 — by requiring the ISO’s Board of Governors to develop and approve governing documents for a new RTO by Oct. 31, 2018.

The nature of Tuesday’s amendments is not yet clear, but the proposal as written would create a Commission on Regional Grid Transformation, charged with determining whether the new governance structure adheres to principles set out in the legislation, including:

Acknowledging and preserving state authority over matters traditionally regulated by the participating states, such as resource procurement, resource adequacy, utility planning and “other policy issues,” including those related to greenhouse gas emissions;
Allowing participating transmission owners (PTOs) to withdraw from the RTO, including at the behest of a state of local regulatory authority; and
Creating a process to transform the current board into a new, independent board.

The bill also stipulates the creation of committees drawn from CAISO stakeholders to advise the new ISO governing board. They would include representatives from each state with a PTO under CAISO control, TOs, transmission-dependent utilities, publicly owned utilities, consumers, environmental groups, exempt wholesale generators, emerging technologies and labor organizations.

The governance structure would not become effective until getting approval from the transformation commission, which will consist of representatives from the governor’s office, the legislature and state agencies. The commission must issue its decision by Dec. 31, 2018.

If the commission approves the expansion, the bill would void existing provisions on the formation of ISO advisory committees, the adoption of transmission maintenance, repair and replacement standards, requirements that the ISO conduct performance reviews following certain major outages, and establishing the Electricity Oversight Board.

Opponents warned that the proposed law dilutes California’s role in controlling its energy future and subjects the state to more oversight from President Trump’s appointees at FERC. While regionalization would help the state export excess renewable generation stemming from its aggressive carbon reduction policies, it would also bring coal-fired generation operated by PacifiCorp into a market that would not be governed by California entities.

The Consumer Watchdog group on Monday issued an open letter to state senators, referencing the Western Energy Crisis of 2000/01 that led to gaming, blackouts and skyrocketing electricity costs.

“In this last week of session, Gov. [Jerry] Brown is asking you to take the first steps toward a similar bargain with an even more pernicious devil, Donald Trump and other billionaires with power to sell, much of it dirty,” the group said in the letter.

The Utility Reform Network, which represents retail ratepayers, tweeted: “Is CA going to give away its energy future again? We’ve barely recovered from deregulation, [why] give away control to FERC and Warren Buffet?”

PacifiCorp, one of the holdings of Buffet’s Berkshire Hathaway Energy, and other out-of-state sellers already participate in CAISO’s Western Energy Imbalance Market (EIM), which does not function as an ISO.

CAISO favors regionalization, saying it could save up to $1.5 billion annually by 2030. (See Study Touts Benefits of CAISO Expansion.)

Brown moved to delay regionalization last summer in the face of opposition both within and outside California, but earlier this year he reaffirmed that ISO expansion could help the state address climate change. (See Gov. Brown Reaffirms Commitment to Expanded CAISO.)

AB 726 was originally written to require utilities with smart meters to provide automated alerts and notifications regarding energy usage and billing to retail customers unless they opt out, while AB 813 initially included now-deleted language regarding education.

While sponsors of the measure acknowledge that new renewable builds are not needed in the state over the next few years because of existing surpluses and expected RPS compliance among load-serving entities, they pointed to a California Public Utilities Commission finding showing that the state will save $633 million over the long term by allowing renewable developers to take advantage of the PTC.

September 12, 2017

ISO-NE Visits Vermont to Discuss Tx Planning

WOODSTOCK, Vt. — ISO-NE officials came to Vermont on Thursday to discuss how FERC Order 1000 has affected transmission planning in the region.

ISO-NE ferc order 1000 — George | © *RTO Insider*

ISO-NE Vice President for External Affairs and Corporate Communications Anne George gave a presentation on the grid operator’s role in implementing Order 1000, along with updates on the RTO’s preparations for Forward Capacity Auction 12, the Integrating Markets and Public Policy (IMAPP) initiative and its 2018 budget.

Vermont Gov. Phil Scott also addressed the Sept. 7 meeting of ISO-NE’s Consumer Liaison Group.

Here are the highlights of what we heard.

Order 1000 and Public Policy Tx Projects

In April, the D.C. Circuit Court of Appeals rejected separate challenges by New England Transmission Owners and state officials to Order 1000, including FERC’s elimination of federal rights of first refusal (ROFR) for incumbent transmission owners and one aspect of the public policy transmission planning process. (See Court Rebuffs New England TOs, Upholds FERC ROFR Order.)

ISO-NE FERC PJM Insider TXU Corp. — Marshall | © *RTO Insider*

Jason Marshall, general counsel for the New England States Committee on Electricity (NESCOE), said during a panel discussion that the ruling on the public policy process, while denying the petition, had “at least provided what we wanted: a ruling that ISO New England does not have to choose a public policy project as part of the Order 1000 process.”

The court also ruled that “ISO-NE has no role in setting public policy for the states.”

Liaison Group Chair Rebecca Tepper, chief of the energy and telecommunications division in the Massachusetts attorney general’s office, brought up the transmission projects proposed in response to the Massachusetts solicitation for 9.45 TWh a year of Class I renewables (wind, solar, hydro or energy storage). (See Hydro-Québec Dominates Mass. Clean Energy Bids.)

“What’s confusing to people is that none of these projects are ‘public policy’ projects that have gone through the Order 1000 process,” she said. “People are trying to understand what kinds of projects these transmission projects are [under the FERC Order 1000 construct] and who’s going to pay for them.”

Marshall responded that if a transmission project arises out of a state-run request for proposals, it would be one of two types. “It could be a public policy upgrade, which has to go through the Order 1000 process. Alternatively, it could be an elective transmission upgrade, and that’s a separate category that’s not regionalized, not socialized across New England to all consumers. That’s the difference.”

Colin Owyang, general counsel of Vermont Electric Power Co. (VELCO), said he believed that the Massachusetts projects were mostly outside the three categories. “I think of the public policy upgrades as regional public policy decisions, so if there were a New England governing body … and if they were to collectively agree on a mutually acceptable public policy, then it would go through the [Order 1000] process.”

In addition to its own RFP, Massachusetts has teamed with Connecticut and Rhode Island on a separate solicitation. (See Second Circuit Upholds Conn. Renewable Procurement Law.)

Owyang said that states may have believed that if they went through FERC’s process, they would lose control of projects. As a result, he said, that’s why he thinks they run their own RFPs “over on the side.”

Developer Balancing Act

VELCO negotiated the compensation to Vermont — a total of $136 million spread evenly over 40 years — for the New England Clean Power Link, which includes a submarine cable under Lake Champlain and a smaller overland section connecting with a substation in Ludlow. Transmission Developers Inc. has fully permitted the project to bring 1,000 MW of hydropower, solar and wind from Canada with its partner, Hydro-Québec. The Vermont section of the line is 154 miles long.

Another developer, Stephen Conant of Anbaric, asked how developers could justify making Massachusetts residents pay a “tax” to Vermont for letting energy cross the latter state. Owyang said he would not put it so “flippantly,” calling the payments fair compensation and a necessary cost of doing business.

“As a developer, what you have to balance is how do you get your project developed [and] how do you get it built on time,” added TDI CEO Donald Jessome. “There’s going to be costs, whether those are capital costs or operating costs, property taxes — you could go down a whole laundry list of different issues that you have to take into account. Ultimately, if the benefits don’t outweigh the costs of the project, you’re just not going to go forward.

“There are going to be costs, there are going to be community issues and we have to take all of that into account,” Jessome continued. “If we priced it wrong, we will lose the [Massachusetts] RFP.”

Mary Ellen Paravalos, vice president for ISO, siting and compliance at Eversource Energy, also appeared on the panel moderated by Guy Page, communications director of Vermont Energy Partnership.

Vermont’s Clean Energy Economy

Gov. Scott said that one in 16 workers in Vermont are employed in clean energy, the highest ratio of any state in the U.S., he said.

“We’re going to need all those workers and all that knowledge because we have a goal of getting 90% of our energy needs from renewable resources by 2050,” he said. “As daunting as that might sound, I believe it’s achievable.”

Scott highlighted how investments in clean energy are also changing the state’s electric grid, which frequently sees its lowest net load in the middle of the afternoon because of the amount of solar on the system. The peak hour is now after sunset, once the solar resources stop producing.

As the state encourages people to switch to electric vehicles, the resulting increase in electrification calls for smarter load management and rate design, partly “to ensure that we don’t increase peak demand or make the Northeast less competitive than it already is in terms of rates,” Scott said. “Also, when we talk about changes in how people consume power, we need to be certain we aren’t hurting the most vulnerable. We can’t have regressive policies that add costs onto people who can’t afford to pay, or hurt folks who are working third shift, for instance, and can’t change the timing of their electrical usage.”

Scott said that while modernizing the grid and how people use electricity, planners shouldn’t ignore more traditional resources such as baseload hydroelectric. Vermont has a long history of working with Hydro-Québec, he noted.

“We first started importing power from Quebec in the late 1980s through Highgate, Vt.,” Scott said. “A few years later we hosted the first DC line into New England from Quebec through the Northeast Kingdom of Vermont [Essex, Orleans and Caledonia counties], and through to northwestern New Hampshire. We now have a number of companies looking to use Vermont as a conduit to transfer more power from Quebec to help our friends and neighbors in Massachusetts. And as unbelievable as this may sound to anyone who has done work in this state, Vermont has already fully permitted one of those projects, TDI’s Power Link.”

Scott said that TDI worked with host communities and “now enjoys significant support in our state and a clear path to construction. In my view, the Clean Power Link is a smart, common sense and very affordable solution for Massachusetts and New England. It provides economic and environmental benefits for both states, and it shows how a region can work together to accomplish energy goals.”

— Michael Kuser

September 12, 2017

ISO-NE Planning Advisory Committee Briefs; Sept. 6, 2017

Stakeholders will have 15 days to comment on ISO-NE’s reorganized transmission planning guide, which will reduce the existing guide’s more than two dozen sections to four. It will be organized like a transmission needs assessment or solutions study report: Introduction; Modeling Assumptions; Reliability Criteria and Guidelines; and Analysis Methodology.

Lead engineer for system planning Steve Judd, who presented the new guide to the ISO-NE Planning Advisory Committee on Wednesday, said the need for the reorganization became apparent when staff found it difficult to identify the proper section for adding a new probabilistic methodology for creating base case dispatches.

Since the guide’s creation in 2013, Judd said, new information was added as additional sections at the end of the document. As a result, the current guide’s 26 sections are “in no cohesive order,” he said.

The new methodology (section 2.2.2 of the revised guide) aims to develop a “same-probability” curve to describe the combined likelihood of certain levels of load and generation unavailability.

Planners will use the curve to determine the representative amount of generation in megawatts to be modeled as out of service in the transmission needs assessment for the study area. Instead of modeling a particular number of generators out of service, the new concept models a representative quantity of generation as being unavailable.

Planners based the load level probability on the most recent capacity, energy, loads and transmission (CELT) forecast and 17 summer weeks of distribution curves.

The 15-day comment period will be triggered when the guide is posted, Judd said.

Stakeholders Seek Briefing on SOARES

Analysts conducting ISO-NE’s 2017 System Operational Analysis and Renewable Energy Integration Study (SOARES) will brief PAC stakeholders at a future meeting, Director of Regional Planning and Coordination Michael Henderson said.

ISO-NE transmission planning — ISO-NE’s System Operational Analysis and Renewable Energy Integration Study (SOARES) will address the reduction in traditional thermal generation that provide inertia and other reliability services, such as regulation, ramping and reserves. | *Thayer School of Engineering at Dartmouth*

Stakeholders requested the briefing by professor Amro M. Farid and his team at the Thayer School of Engineering at Dartmouth after Henderson reviewed the SOARES scope of work Wednesday.

ISO-NE spokeswoman Marcia Blomberg called SOARES “a key element” of Phase II of the 2016 New England Power Pool Scenario Analysis/Economic Study, which is focused on regulation, ramping and reserves. The study will address the reduction in traditional thermal generation that provide inertia and other reliability services.

No date has been set for the briefing. The SOARES project is expected to be completed by the end of the year.

Eversource Spending $22.7M to Replace 3 Transformers

Eversource Energy presented its plans to replace three aging transformers at a cost of a cost of about $22.7 million.

Eversource Director of Transmission System Solutions Bob Andrew said the three are among eight General Electric transformers aged 30 to 45 years in its system, half of which have shown significant deterioration. One, at Scobie Pond, N.H., was replaced after it failed in March following a short-lived refurbishment. Two new units will replace transformers at Littleton and Deerfield, N.H. In addition, a new spare transformer will be purchased to replace one that took the place of a fourth aging unit.

Cost allocation for the new transformers will be subject to review by the RTO’s Reliability Committee, Andrew said.

The four transformers’ internal insulation had deteriorated, resulting in the formation of methane and ethane in the transformers’ oil. Eversource will monitor the remaining four GE units for future trouble.

Andrew said the RTO has discussed the issue with GE. “The response was typical of the [original equipment manufacturer] with 30-year-old equipment: ‘Of course, you should buy one of our new transformers and replace it.’”

— Rich Heidorn Jr. and Michael Kuser

September 12, 2017

Monitor Critical of CAISO Commitment Cost Mitigation Plan

By Jason Fordney

CAISO’s Department of Market Monitoring on Friday amplified its opposition to a fundamental aspect of the ISO’s plan for mitigating market power in generators’ commitment costs.

The department told the Market Surveillance Committee on Friday that it “fundamentally disagrees” with the Commitment Cost and Default Energy Bid Enhancements (CCDEBE) initiative. The program, which CAISO Senior Market Policy Developer Cathleen Colbert outlined in a presentation, is designed to better reflect unit commitment costs and overhaul how the ISO calculates the default energy bid (DEB) used for units with market power.

CAISO commitment cost mitigation — | *CAISO*

The Monitor had previously raised concerns with the CCDEBE proposal, which would apply to both the ISO and the Western Energy Imbalance Market (EIM). (See CAISO Monitor Says Bid Rule Changes Flawed.)

The debate has large financial implications for EIM power sellers subject to default bidding, such as Berkshire Hathaway Energy entities PacifiCorp and NV Energy, which last month asked FERC to lift their DEB restrictions. (See Berkshire Companies Request EIM Rate Authority.) The restrictions also apply to Arizona Public Service.

“We think there are a lot of questions left on the dynamic mitigation,” the department’s Michael Castelhano said. The Monitor has urged splitting the proposal into two parts and getting a new process for reference levels in place by fall 2018. Then commitment cost bidding and mitigation could be addressed “in a more robust way than we have been able to do so far,” Castelhano said.

The ISO has suggested it will use a static competitive path assessment (CPA) on a seasonal basis to determine which constraints should be tested for commitment cost market power. In other CAISO proceedings, stakeholders have proposed eliminating the CPA because it is designed for the seasonal level and not a daily or hourly market.

The static CPA often fails to capture market power for commitment costs, which potentially has more financial impact than missing market power for energy costs, Castelhano said. “You will never get the models right,” he told ISO officials.

“Conceptually, we would support the opposite approach,” he said, which would assume the paths are competitive unless proven otherwise. “We really think that is the right thing to do in this situation.”

“We think it is really important that this is vetted and [discussed] in the stakeholder process,” Castelhano added. He said it appears the ISO is adapting energy market mitigation methods for commitment costs.

Energy market mitigation has to do with the effect of market power on LMPs, while commitment cost mitigation asks how different constraints affect the likelihood of a resource to be committed, he said in the presentation. “You are not starting with the right question,” he told ISO officials.

CAISO says its goal is to submit the proposal to the EIM Governing Body for an advisory vote on Oct. 10 and to the Board of Governors for approval on Nov. 1.

September 12, 2017

ERCOT Briefs

ERCOT’s latest resource adequacy forecasts project the Texas grid will have sufficient installed generating capacity this fall and winter, despite the destruction wrought by Hurricane Harvey.

Pete Warnken, ERCOT’s manager of resource adequacy, said staff studied several scenarios that could affect the availability of generating resources. The results were favorable.

“[We] do not currently anticipate any systemwide issues,” Warnken said in a statement Thursday. “Even in the most extreme scenarios considered, there were ample operating reserves.”

The fall seasonal assessment of resource adequacy (SARA) report shows nearly 86 GW of capacity available for a predicted peak demand of just over 56 GW. The final fall SARA, covering October and November, includes 3 GW of new generation added since the preliminary report in May.

Exelon accounted for 2.2 GW of the new generation, adding gas-fired combined cycle units at plants near Houston and Dallas. More than 837 MW of new wind and solar resources are expected to contribute 374 MW to covering the fall peak, based on capacity factors.

ERCOT resource adequacy William Scherman — Exelon gas turbines | © GE

The preliminary winter SARA report projects a record peak of more than 61 GW, beating ERCOT’s all-time record of 59.7 GW, set in January. The report, covering December through February, anticipates almost 85 GW of capacity being available.

ERCOT will release the final winter SARA in early November.

Harvey Restoration Efforts Continue, but Numbers Down

ERCOT said last week that while Hurricane Harvey’s restoration efforts will continue for an “extended period” in some areas, the number of affected transmission facilities and generation resources has decreased considerably since the storm hit the Texas Gulf Coast on Aug. 25.

The ISO said Friday that one 345-kV line still remains out of service. However, the grid has remained stable and the competitive markets have continued to operate normally, it said.

Most of the remaining outages are in Rockport and Aransas Pass, where the storm’s eye made landfall. AEP Texas said 15,000 of its remaining 16,600 outages were in the Rockport-Aransas Pass area as of Friday afternoon. The utility said it may take an “extended amount of time” to reconnect power to some homes and businesses damaged by Harvey.

CenterPoint Energy said about 3,200 customers remained without power in the Houston area Friday afternoon. The utility has been forced to route power from a flooded distribution substation to a nearby temporary substation in west Houston.

Most of CenterPoint’s customers without service live near the overloaded Barker Reservoir. The U.S. Army Corp of Engineers has been releasing water to save the reservoir’s structural integrity.

Entergy reported about 2,300 customers out of service in Southeast Texas as of Friday afternoon.

Southern Cross Offers Suggestions for its Market Participation

Stakeholders on Thursday discussed potential definitions and market participant categories during a workshop for the Southern Cross Transmission Project, which could become ERCOT’s first merchant DC tie operator.

The ISO does not currently include DC tie operators as market participants, but the project’s developer is working to define language that would allow the proposed DC tie with the Eastern Interconnection to take part in the market. The HVDC transmission project would be capable of shipping more than 2 GW of electricity between the Texas grid and Southeastern markets.

“There’s a way to do this that would probably make sense,” Cratylus Advisors’ Mark Bruce said, speaking for Southern Cross Transmission (SCT). “We have a bunch of boxes that Southern Cross can’t check [on the market participant agreement form]. [The tie] doesn’t serve load, [and] it doesn’t buy or sell energy. ‘DC tie operator’ would describe the function we’re registering for. We think that’s a good place to start.”

The project would link ERCOT to the Eastern Interconnection through a 345-kV line, owned by Garland Power & Light, that connects with a convertor station just across the Louisiana border. SCT would build a 400-mile, 500-kV DC line to connect with Southern Co.’s existing 500-kV system in Alabama.

SCT envisions ERCOT qualified scheduling entities (QSEs) buying capacity on the line similar to how they do on the ISO’s existing five DC ties. The company would not participate in the settlement process, but the QSEs would. Southern Cross would not have a Texas tariff or collect transmission rates, leaving the QSEs responsible for paying transmission service charges for use of the ERCOT system.

“Users of the Southern Cross line are going to pay for this equipment in the capacity charge. ERCOT ratepayers aren’t going to be paying for any of this,” Bruce said.

He suggested protocol language for a DC tie operator as a market participant that “has completed applicable registration and approval for the purpose of operating a DC tie interconnected to the ERCOT transmission grid.” Bruce also drafted bylaw language for a definition of an independent DC tie operator, suggesting it be any transmission and distribution entity or affiliate that “owns or operates” a DC tie interconnected to ERCOT’s grid or is “preparing to own or operate” such a tie.

Bruce said SCT would fit best in ERCOT’s investor-owned utility segment. He pointed out the company is investor-owned and a “public utility” under the Federal Power Act, although not under Texas law. Its only function in ERCOT is operating a high-voltage transmission facility, he said.

ERCOT staff will now work with SCT to develop and submit the appropriate revision requests to the Protocol Revisions Subcommittee for its November meeting. Market participants were invited to provide feedback and input from the workshop, along with other comments for consideration prior to sponsoring the appropriate revision requests.

The Public Utility Commission of Texas opened a pair of dockets for the SCT proposal. Docket 45624 approved Garland P&L’s application for the 345-kV line, which has an established route. Project 46304 establishes the PUC’s 14 directives for integrating and operating the project as a part of the ERCOT system and within its market construct.

Southern Cross obtained final FERC 210/211 orders and agreements in 2014 for interconnection to and transmission service in ERCOT that maintain its FERC jurisdictional status quo.

Developers hope to begin construction in 2019 and commercial operation in the third quarter of 2022. They are working to obtain a siting certificate for the line’s Mississippi portion from the state’s Public Service Commission. Louisiana does not require a siting certificate.

— Tom Kleckner

September 12, 2017

Vogtle, the Law of Holes, and Two Modest Proposals

Counterflow

By Steve Huntoon

The Vogtle nuclear project in Georgia is looking like an object lesson in the failure of regulation (and a vindication of competition).

What went wrong? Traditional regulatory policy is that new utility investment didn’t get billed to utility customers unless and until it’s actually in service and thus “used and useful” to utility customers.

But nuclear advocates argued that the lead time and risk of nuclear plants were so great that construction costs ought to be guaranteed, and in some cases charged to utility customers, long before the plants are completed.

This fundamentally and completely changed the investment calculus for utilities interested in nuclear plants, with the potential for enormous returns on billions of dollars. The key was to get legislators and/or regulators to go along.

Once they did, nuclear plant development became a no-lose proposition for the utility.

Selling Vogtle

Vogtle is an example of the problem. If you go to Southern Co.’s Georgia Power website right now (at least when this column went to print), the utility tells you: “There are many great benefits to nuclear power: it’s inexpensive…”^[1]

Inexpensive? Lazard’s highly regarded “Levelized Cost of Energy Analysis” of different energy sources shows nuclear at about twice the cost of the major competitors: natural gas combined cycle, wind and utility-scale solar.^[2]

Georgia Power also claims Vogtle is needed because of future electric demand: “By 2030, electrical demand is projected to increase 27% in the Southeast.”^[3]

Here’s the Energy Information Administration’s projection of Southeast electric demand through the year 2030.

PSC Steve Huntoon Nuclear Power — | *EIA*

Do you see the 27% increase? Me neither.

If Vogtle ever made sense, that ended years ago when it became evident that natural gas prices would stay relatively low, that load growth would slow, and that Vogtle costs would escalate.

How Competition is Different

Competitive businesses pull the plug all the time on investments that aren’t working out (as NRG Energy did for its proposed nuclear plant in Texas in 2011 — six years ago — at no cost to consumers). But utilities don’t have a reason to pull the plug if they win either way.

This is the fundamental difference from competitive markets, where bad investments are investor burdens, not utility customer burdens.

The Georgia (Vogtle) and South Carolina (V.C. Summer) utilities kept on spending billions of dollars that their customers are on the hook for.

The Westinghouse Electric bankruptcy ripped the veil off the likely cost of completing the projects. Since the “inexpensive” and “load growth” justifications for the plants have disappeared, pulling the plug is the obvious resolution.

But as seen in South Carolina with the Summer project cancellation, there can be political blowback against cutting losses because so much has been spent already.^[4]

This ignores the law of holes: If you’re in one, stop digging.

$23.6 Billion in Excess Costs

Sunk costs are sunk (maybe they never should have been sunk, but they’re sunk now). So they shouldn’t be considered in deciding whether to keep digging — either as a reason to keep digging or as a reason to stop. Only future costs should matter.

Here’s how to look at the “go”-“no go” decision on Vogtle: We start with Georgia Power’s forecasted project cost for its 45.7% share, $12.17 billion,^[5] and subtract its project costs incurred to date (sunk costs), $5.844 billion, for a net of $6.326 billion in “cost to complete” from this point forward.^[6] Scale Georgia Power’s cost to complete up for the other owners’ shares to get the total project cost to complete, from this point forward, of $13.842 billion.

Add $700 million in income tax allowance for Georgia Power’s return, to get $14.542 billion.^[7]

Subtract a $745 million cancellation cost (avoided if Vogtle is not canceled) to get a $13.797 billion cost to complete less avoided cancellation cost. Do not subtract the Toshiba parent guaranty payments, because they are owed regardless of whether the project is canceled or not.^[8]

With me so far? Net project cost to complete, from this point forward, is $13.797 billion. Divided by 2,204 MW of net electrical output is $6,260/kW.

With that we can use Lazard’s LCOE analysis to get a levelized cost of energy for completing Vogtle. The $6,260/kW cost to complete Vogtle is way above the low of $5,400/kW in Lazard’s nuclear capital cost range.

So being favorable to a case for completing Vogtle, we can take the low end of Lazard’s nuclear LCOE range, $97/MWh, and compare it to the midpoint of Lazard’s natural gas combined cycle LCOE range, $63/MWh, for an excess cost of Vogtle of $34/MWh.

We can take that excess cost for Vogtle of $34/MWh, times 8,760 hours, times Lazard’s 90% capacity factor, times Vogtle 2,204 MW net capacity, times 40 years, and conclude that the cost to complete Vogtle, from this point forward, would impose excess costs of $23.6 billion on Georgia consumers over the next 40 years.^[9]

Non-Economic Justifications

With the economics of Vogtle long gone, non-economic justifications have emerged. For example, a Georgia Public Service Commissioner argued in an Aug. 18, 2017, Wall Street Journal op-ed that “nuclear reactors produce isotopes needed for medical imaging and cancer treatment.”

The fact is that virtually all medical isotopes are produced in specialty reactors — not utility nuclear units.^[10] The existing Vogtle units have never produced medical isotopes, and there are no plans for new Vogtle units to do so.

Then there is the fuel diversity argument. But Georgia Power says that it has “A Diverse Portfolio” now.^[11] With little load growth (as shown above), and major coal plant retirements behind it, Georgia Power can’t possibly need Vogtle to maintain a diverse portfolio.

And as for nuclear having carbon-free emissions, if that is a major consideration, wind and solar are about the half the LCOE under the Lazard analysis.

Two Modest Proposals

If the Vogtle owners and Georgia think nuclear power has unique and important value, here’s a modest proposal. It is staggering in its simplicity: Exelon throws the Vogtle owners the keys to its Clinton and Quad Cities nuclear plants. The plug is pulled on Vogtle.

Think about it. Illinois consumers save $2.35 billion they no longer have to pay to save Clinton and Quad Cities, which Exelon would have closed without the subsidies.

Georgia consumers avoid $23.6 billion in excess costs they would bear by completing Vogtle.

Win-win.

Don’t like that one? Here’s another. Suspend Vogtle for 10 years. Georgia Power’s consultant, Black & Veatch, estimated that would cost $112 million,^[12] which is a dirt cheap way to hold off making a possible huge mistake. Georgia Power said it rejects that option because Westinghouse’s AP1000 design isn’t being pursued anywhere else “in the United States,” and therefore Westinghouse would not maintain the design and vendors would stop making components.

Assuming for the sake of argument that design and component capability would be forever lost by deferral if no AP1000 reactors were to exist anywhere, that just won’t be the case. Four AP1000 reactors are being completed in China right now, and more AP1000 reactors are planned elsewhere in the world.^[13]

They just don’t make sense here.

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.

https://www.georgiapower.com/about-energy/energy-sources/home.cshtml ↑
https://www.lazard.com/media/438038/levelized-cost-of-energy-v100.pdf (page 2). Lazard does not adjust for the capacity value of non-dispatchable intermittent resources like wind and solar. But the price difference between nuclear and wind/solar is so vast that even after adding some capacity cost, wind and solar would remain much cheaper than nuclear. ↑
https://www.georgiapower.com/about-energy/energy-sources/nuclear/overview.cshtml ↑
One Georgia Public Service Commissioner is quoted as saying: “I do want to see this project completed. I do not like to see failure.” http://www.ajc.com/business/georgia-power-told-its-homework-vogtle-nuke-options/mnHqeJ7BdDza0U25xAxfbP/. I would submit that failure is making a decision that is not in the interests of Georgia consumers. ↑
Using Georgia Power’s latest forecasted project cost is being favorable to a case for completing Vogtle, given the long history of underestimating project cost. The Vogtle owners recently selected Bechtel Corp. as the new construction contractor. It appears Bechtel has provided no cost or schedule guarantees. ↑
These figures are from Table 1.1 of Georgia Power’s Aug. 31, 2017, filing with the Georgia Public Service Commission in Docket No. 29849, except that financing costs to date of $1.4 billion come from Southern’s Form 10-Q for Q2 2017 (page 38). Financing costs must be included because capital isn’t free. If financing costs are ignored, then among other things, two projects costing $1 billion in capital — one which takes 12 years to construct (like Vogtle) and one which takes three years to construct (like a natural gas combined cycle plant) — would be treated as equivalent. ↑
The Atlanta Journal-Constitution reports that Georgia Power’s estimated financing costs, $3.4 billion, do not include an income tax allowance; the newspaper estimates financing costs with income tax allowance of $4.1 billion. http://www.myajc.com/business/georgia-large-power-users-save-hundreds-millions-plant-vogtle-charges/HDujkq5qiDx3GVotFcIS9L/. The income tax allowance is not applicable to the other Vogtle owners because they do not pay income taxes, so it is added to the total project cost to complete rather than scaled up for the other owners’ shares. ↑
“The guarantee obligations continue to exist in the event of cancellation.” Southern’s Form 10-Q for Q2 2017 (page 38). ↑
Georgia Power presents completely different results in its recent filing with the Georgia PSC (referenced in a preceding footnote). But its numbers come out of a black box. And no analysis by a third-party economic consultancy is provided to inform or support the “go” decision of the Vogtle owners. ↑
http://www.nature.com/news/reactor-shutdown-threatens-world-s-medical-isotope-supply-1.20577 ↑
https://www.georgiapower.com/about-energy/ ↑
Exhibit 6 of above-referenced Georgia Power’s filing with the Georgia PSC. ↑
http://www.reuters.com/article/us-westinghouse-nuclear-idUSKCN11M1Q7 ↑

September 12, 2017April 9, 2024

Witnesses Offer Alternate Realities on Need for PURPA Reform

By Rich Heidorn Jr.

A House energy panel last week heard two alternate realities on the need for reforming the 1978 Public Utility Regulatory Policies Act (PURPA).

The solar energy industry told members of the House Energy and Commerce Committee on Sept. 6 that the law remains as important as ever, despite federal subsidies, competitive markets and falling PV prices. Utility witnesses, who contended the bill is obsolete and an albatross for consumers, cited abuses of FERC’s 1-mile and 20-MW thresholds for must-purchase requirements.

Rep. Fred Upton (R-Mich.) said the hearing would be “the first step in re-evaluating whether the intent and purpose of PURPA is still being met or if it has already been fulfilled.”

For PURPA critics who were hoping for quick legislative action following the hearing, Clearview Energy Partners analyst Timothy Fox had bad news. He reduced Clearview’s odds that Congress will enact changes to the law in 2017 from less than 30% to less than 10%.

“Yesterday’s hearing reinforced for us the lack of consensus on, and narrow congressional interest in, PURPA reform,” he wrote in an analysts’ note. “We consider its best prospects for enactment to be in the context of a broad energy or energy and infrastructure package that we don’t expect to see action on until 2018. In the meantime, we do not anticipate that the Federal Energy Regulatory Commission (FERC) will change its current light-handed approach to PURPA issues, allowing states to continue their efforts to modify their administration of the program.”

Sen. Lisa Murkowski (R-Alaska), chair of the Senate Energy and Natural Resources Committee, also cautioned against expectations of quick action. Following the confirmation hearing for FERC nominees Richard Glick and Kevin McIntyre on Thursday, Murkowski told reporters that PURPA reform is too complicated to be dealt with as an amendment to the broad energy bill she and ranking member Maria Cantwell (D-Wash.) are sponsoring. She added that FERC has leeway to address some of the concerns over the act.

New FERC Commissioners Neil Chatterjee and Robert Powelson said at their confirmation hearing in May that it was up to Congress to authorize any major changes in PURPA. (See No Fireworks for FERC Nominees at Senate Hearing.) PURPA was barely discussed at Glick and McIntyre’s hearing. (See related story, McIntyre to Senate: ‘FERC does not Pick Fuels’.)

Abuses Cited

The hearing by the Subcommittee on Energy was the committee’s fourth in its “Powering America” series of fact-finding sessions that began last year on potential revisions to the 1935 Federal Power Act. (See RTOs to Congress: Don’t Lose Faith in Markets.)

Several witnesses said PURPA, born out of the 1973 energy crisis, is no longer necessary in an era of bountiful natural gas supplies, low load growth and competitive wholesale energy markets.

The utilities invited to testify came with wind and solar generation bona fides to make the case that renewables have accomplished the competitiveness PURPA was intended to create.

Terry Kouba, vice president of operations for Alliant Energy in Iowa, said his company has more than 1,000 MW of wind capacity from its generation and power purchase agreements and plans to spend $1.8 billion to add another gigawatt of wind by 2020. “Despite the market-driven deployment of renewable energy in Iowa, Alliant Energy is still subject to PURPA’s mandatory purchase obligation, the federal implementation of which has increased electric costs for our Iowa customers,” he said. “The law, therefore, can result in the deployment of less economic renewable generation in lieu of more cost-effective renewable generation procured in an open market.”

Also testifying was Frank Prager, vice president of policy and federal affairs for Xcel Energy, the top wind generator in the U.S. with almost 6,700 MW operating and 3,400 MW under development. “Fully 65% of these existing and planned resources are owned by independent power producers,” said Prager. “We are also a leading solar provider and expect to add 900 MW of solar to our already growing solar portfolio.

“PURPA represents an energy policy from another time and is inconsistent with the realities of today,” Prager said. “PURPA incentivizes developers to build generation that is not needed and site it in locations where it provides no value to the grid. PURPA thwarts the opportunities of other independent power producers.”

Gaming FERC Thresholds

FERC has ruled that wind farms of 20 MW or larger within ISO/RTO regions are presumed to have access to competitive markets and thus ineligible to force PURPA’s must-purchase obligation on incumbent utilities. (See related story, EKPC Gets PURPA Exemption; Still on Hook for 2 QFs.)

But witnesses said qualifying facility (QF) developers are circumventing the 20-MW cap by creating separate corporate entities for individual turbines or small groups of turbines, or disaggregating large projects by siting turbines more than 1 mile apart. FERC has ruled that QFs located within 1 mile of each other are considered to be “located at the same site.”

Kouba cited a 30-MW wind farm in central Iowa that was broken into 10 separate limited liability companies each owning a 3-MW turbine; a 28-MW wind farm with 14 LLCs; and a proposed 24-MW farm operated by 11 LLCs. “In none of the above examples is Alliant Energy able to challenge the presumption that these QFs are separate because of the safe harbor provided by FERC’s 1-mile rule, which is irrebuttable,” said Kouba.

He said that the 30-MW project is charging customers a 20% premium over market rates on a 10-year contract, while the developer of the proposed 24-MW project is seeking a rate of $49.50/MWh for 25 years rather than Alliant’s avoided cost rate of about $25/MWh. “If they are successful, Alliant Energy’s customers will pay more than $45 million more for energy than if Alliant Energy were to enter into a PPA obtained through a competitive process,” he said.

Prager said Congress’ addition of Section 210(m) to the FPA in the Energy Policy Act of 2005, which allows utilities in RTO markets to obtain an exemption from PURPA if the QF has nondiscriminatory access to the market, has been “helpful” but “inadequate” to address gaming.

“It does not apply to states in the West or South or other states that have not joined organized markets. Further, even in organized markets, FERC’s 20-MW safe harbor still allows relatively large resources to avoid the discipline of the market and put their energy to the utility.”

Impact on System Planning

In addition to imposing high-cost PPAs, critics say, QF developers also undermine system planning by connecting their generation at locations providing quick, cheap access, regardless of their impact on the grid. “The size and scale of these new PURPA projects often virtually guarantees the backflow of energy from the distribution system to the transmission system,” Kouba said.

Prager cited a QF developer planning 480 MW of wind and solar power in a remote area of Colorado. “All of the transmission capability in that area is already fully subscribed by five solar facilities that are already under contract. This developer’s QF projects could cause our customers to pay potentially hundreds of millions of dollars in transmission upgrades to deliver the QF’s energy and cause us to curtail the output from the five existing solar facilities already in this area.”

Utilities’ Recommendations

The utilities called for repealing PURPA Section 210’s must-purchase requirement, or expanding the exemptions from the requirement to non-RTO states with least-cost resource planning or competitive solicitation processes or where the utility does not need additional generation.

They also called for removing the 20-MW safe harbor or reducing it to 2 MW in organized markets. They said unsolicited QFs should be required to pay for transmission upgrades necessary to deliver their output.

And they said FERC should make it easier for utilities to challenge abuses of the 20-MW and 1-mile thresholds.

Idaho Public Utilities Commissioner Kristine Raper also was critical, saying PURPA contracts should be shorter to ensure avoided cost rates reflect changing energy prices and that FERC’s 20-MW threshold should be expanded to include the Western Energy Imbalance Market (EIM).

She also questioned the value of QFs. “Even with the addition of large QF resources, the QF energy rarely displaces the need for a utility-scale project because renewable QF energy is largely intermittent — requiring baseload resources to ensure reliable service,” she said. “So, the question must be asked: What costs are being avoided and how are ratepayers held harmless?”

She rejected developers’ demand that PURPA support financing of QF projects. “Neither PURPA nor FERC regulations mandate that the terms of a QF contract allow the project to be financeable,” she said. “If the market cannot support the cost of the project, then the project should not be built.”

Industrials: We’re Different

Testifying for the Industrial Energy Consumers of America, Stephen Thomas, senior manager of energy contracts for paper manufacturer Domtar, called on policymakers to “recognize the differences between the types of qualifying facilities and only alter PURPA in a way that supports how the manufacturing industry uses PURPA.”

Thomas said that even manufacturers with on-site power are net energy purchasers and thus worry about above-market avoided-cost contracts.

IECA said states should deduct the cost of natural gas back-up generation, transmission and other costs caused by renewable generators in developing QFs’ avoided-cost rates. It also said renewable energy QFs should not be allowed to include production tax credits or the value of renewable energy credits into their price-based energy bids because it creates unfair competition for unsubsidized generation.

Waste-to-Energy Concerns

The committee heard a very different story from Darwin Baas, director of public works for Kent County, Mich., who said utilities are violating PURPA to the detriment of waste-to-energy (WTE) facilities like the one run by his county.

There are 76 WTE plants with capacity of 2,547 MW nationwide. But Baas said only one new greenfield plant has opened in the last 20 years because utilities refuse to sign PPAs with QFs or to offer pricing and contract lengths WTE facilities need.

“PURPA’s purpose (and the FERC’s corresponding oversight authority) to ensure that small QFs continue to have access and fair compensation are as necessary today as when PURPA was first implemented,” Baas said. “The commission’s policies implementing PURPA should strive to increase the ability of small QFs to provide baseload renewable power to energy markets.”

Baas said his county’s utility is attempting to reduce its PURPA contract price by 24%. “This will not allow me the revenue necessary to make routine capital refurbishments, forcing me to seriously consider premature closing,” he said.

“Avoided costs paid to WTE QFs by utilities should incorporate short-run and long-run avoided costs for capacity and energy and include the value of other environmental and operational externalities such as the value of baseload renewable energy, diversity of generation mix, proximity to load centers for voltage and VAR support, [greenhouse gas] mitigation, landfill diversion, [and] reliable and resilient power.”

Baas said the 20-MW threshold should be raised to 80 MW for WTE QFs.

Solar Industry Weighs in

Attorney Todd G. Glass of Wilson Sonsini Goodrich & Rosati, who testified for the Solar Energy Industries Association, said PURPA remains “fundamental to the ability of independent power, including the solar industry, to compete.”

“Even under workable competition, some of PURPA’s goals may be lost if left solely to the marketplace,” he said. “As they seek to compete, independent developers are facing a return of the same tactics by the utilities and the state commissions as they experienced almost 40 years ago when the idea of independent generation was presented as a potential competitive solution to utility dominance.”

He said some utilities refuse to negotiate with IPPs and instead require them to participate in solicitations that occur infrequently and whose terms may be drafted to disadvantage the utility’s competitors. Utilities also can engage in discriminatory practices where they control the interconnection process, he said.

Glass disputed opponents’ claims that PURPA forced utilities to purchase overpriced energy, saying it is a misconception that arose “before current technological innovations and efficiencies of scale drove down solar power prices.”

He said PURPA remains essential to financing renewable projects. “Just as utilities can benefit from a 20-year depreciation schedule to finance the construction of their owned power plants, independent producers rely on the capital markets to provide long-term capital to support construction and development of generation projects. The PURPA backstop supports financing for almost every one of these projects, even projects that do not have a sales arrangement under the PURPA construct.”