Page 1278 – RTO Insider

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.”

September 12, 2017

FERC Approves Powerex EIM Agreement

By Jason Fordney

FERC last week approved CAISO’s agreement for integrating Canadian power marketer Powerex into the Western Energy Imbalance Market (EIM) (ER17-1796).

According to the Sept. 7 order, the ISO is working with Powerex to develop a participation framework that addresses the company’s unique situation as a Canadian entity. Powerex is the marketing arm of provincially owned BC Hydro, a generation owner and transmission provider that operates under the jurisdiction of the British Columbia Utilities Commission.

CAISO EIM Powerex — Powerex markets BC Hydro Generation such as the 2,480-MW Revelstoke Dam

“CAISO explains that BC Hydro will not assume a participant role or undertake commercial activities in the EIM,” FERC said. “However, CAISO states that BC Hydro will supply certain data and information directly to CAISO that is needed for Powerex’s participation.” CAISO is developing a data sharing agreement for that purpose.

FERC staff last month provided qualified approval for Powerex’s EIM implementation agreement but cautioned the plan could be subject to further scrutiny after restoration of the commission’s quorum. (See Wary FERC Approval for Powerex EIM Agreement.) Powerex, which currently markets power across the U.S. and as far south as Mexico, brings the EIM increased access to about 17,000 MW of generating capacity, about 12,000 MW of which is hydro.

Powerex is slated to join the market in April 2018 and will pay a fixed implementation fee of $1.9 million, a figure based on the company’s portion of the estimated $19.6 million CAISO would incur if it were to reconfigure its real-time market to incorporate all balancing authorities in the Western Electricity Coordinating Council.

Southern California Edison, Pacific Gas and Electric and other EIM participants raised concerns about provisions in the implementation agreement that could require modification to include participation by additional parties, as well as potential changes to the EIM framework needed to integrate the company into the market.

FERC said those concerns are “premature, given that CAISO and Powerex have not yet developed or proposed the specific terms and conditions of the framework under which Powerex will participate.”

“We expect CAISO to follow through with its commitment to consider the issues raised by commenters and to engage in outreach and dialogue with interested stakeholders as the framework is developed,” the commission said.

The participation agreement framework will allow voluntary offers from residual BC Hydro generation, intra-hour deviations in load and generation in the BC Hydro balancing authority area and transmission arrangements to support EIM transfers.

September 11, 2017

EIM Body Approves Generator Loss Modeling Plan

By Jason Fordney

SEATTLE — The Western Energy Imbalance Market (EIM) Governing Body on Wednesday approved a CAISO proposal allowing market participants to take part in a program that models generator outages and the impact of remedial action schemes (RAS) on market operations.

CAISO EIM remedial action schemes RAS — Cooper | © *RTO Insider*

The current market structure only addresses cases in which a transmission line goes down, potentially causing overflow on other lines. The new method reflects how the system will react to the loss of generation, CAISO Manager of Market Policy Design Brad Cooper said at the Governing Body meeting.

“It should result in a much more efficient market solution than just using offline tools and manual actions,” Cooper said, and be “more efficient and transparent as to what is happening.” The CAISO Board of Governors will vote on the rule changes later this month, after reviewing a more comprehensive package that would bring the measures into the ISO’s day-ahead market. The changes must also be approved by FERC.

The ISO currently uses manual, out-of-market dispatches to manage generator contingencies and RAS, which are protective processes that automatically disconnect generators or load in order to prevent transmission line overload in the event that another line goes out. The new method will update the ISO’s security constrained economic dispatch by modeling the loss of generation within the dispatch, as well as modeling the loss of transmission and generation because of RAS operations. The program effectively incentivizes generator participation in RAS.

“The proposed changes result in an update to the congestion component of the locational marginal price so that it considers the cost of positioning the system to account for generator contingencies and remedial action scheme operations,” the ISO said in its final proposal. “A remedial action scheme-connected generator will potentially receive higher energy prices than generators not connected to a remedial action scheme at the same bus because a remedial action scheme-connected generator does not contribute to binding emergency limits.”

CAISO says the new method will better reflect congestion in localized prices and improve generator dispatch.

Market participants had some misgivings about the new functionality when it was unveiled by CAISO. (See Stakeholders Wary of CAISO Contingency Modeling.) The ISO first presented the proposal in an April 2016 issue paper and drafted a final draft proposal on July 25 of this year.

Allowing EIM entities to model generator contingencies and RAS falls within the Governing Body’s “primary” approval authority, while it approved the general design of the proposal under its “advisory” capacity. CAISO’s Market Surveillance Committee and Department of Market Monitoring support the new program.

Southern California Edison expressed concerns over what it considered to be the anomalous effects of the changes on CAISO’s interconnection process — but that would not apply to EIM entities not subject to that process, Cooper said.

“We disagree with Southern California Edison in any case,” regarding the effects of the new functionalities, he said.

Governing Body Chairman Doug Howe asked if the modeling would be totally voluntary and queried Cooper as to the trade-off between the benefit and cost of the proposal.

“That is something we consider in everything we develop,” Cooper said. “We are convinced that the benefits justify the costs.” He confirmed the program is voluntary and is part of larger improvements to market operations.

September 11, 2017

EIM Participants Seek Resource Test Tweaks

By Jason Fordney

SEATTLE — Western Energy Imbalance Market (EIM) resource sufficiency tests are generally working, but fluctuating load forecasts are a major challenge in passing the tests, market participants said in a regional forum Thursday.

Participants in CAISO’s regional EIM market must pass a series of resource sufficiency tests, including a balancing test for energy, a capacity test and a flexibility ramping test. Market participants discussed possible enhancements at the Regional Issues Forum held in conjunction with the EIM Governing Body meeting the day before.

The forum meets three times a year and includes 10 representatives from various sectors who discuss topics outside of the normal ISO stakeholder process. The sectors include transmission-owning utilities; power producers and power marketers; public interest groups; publicly owned utilities; and neighboring balancing authorities.

The EIM is integrated with CAISO’s market but only includes the ISO’s real-time functionality and not that for the day-ahead market. The sufficiency test is one of a series of processes meant to ensure that EIM entities have sufficient generation to supply the real-time market in the absence of providing day-ahead schedules. (See CAISO: Don’t Lean on EIM for Capacity.) The ISO performs the test ahead of the market run for each operating hour.

While the general structure of the resource sufficiency framework is sound, it could be enhanced, said Powerex trading manager Mike Goodenough. Powerex does not yet participate in the EIM but is slated to join next April. FERC on Thursday approved the company’s implementation agreement for joining the market, which was first conditionally approved by FERC staff in August. (See Wary FERC Approval for Powerex EIM Agreement.)

Goodenough said the level of required resource sufficiency should not be changed because different balancing authority areas (BAAs) have different capacity and flexibility challenges. Raising the requirement might increase costs for entities that don’t have surplus capacity, and decreasing it might reduce flexibility costs but remove opportunities to sell capacity and energy.

The workability of the program could be improved, and “we think we should work toward getting more transparency and metrics around those tests,” Goodenough said.

Possible improvements include adjusting the timelines of the tests so entities know their specific requirements and can obtain needed capacity or flexibility. There are questions as to whether some BAAs are failing in hours when they should have passed, and others are passing when they should have failed, he said. He suggested more granular data from CAISO and historic analysis by the Department of Market Monitoring on whether the required quantities have been consistent with demand and imbalance requirements in BAAs.

Arizona Public Service’s EIM project manager Moe Sakkijha said his utility worked with CAISO to address the fact that the ISO’s load forecasts can fluctuate up to 300 MW. APS in June also began providing the ISO with hourly load forecasts to assist in modeling. CAISO has agreed to freeze the load forecast to help with the resulting uneconomic dispatch, Sakkijha said, but he is not sure when the ISO plans to implement the change.

“A very important issue for the EIM entities was freezing of the load forecast,” he said. APS is also bidding solar and wind resources into the EIM to improve the results for the sufficiency tests for capacity, balancing and flexibility. The company is working with some utility scale solar sources to be able to automatically respond.

Kathy Anderson, Idaho Power system operations leader, said that her company has not begun participating in the EIM but already has some concerns. (See Idaho Power Inks Agreement to Join Western EIM.)

“A lot of conversations with the entities that are live [in the EIM] give me some concerns, especially when we start talking the moving target of the load, and chasing that,” she said. Idaho Power has hydro, wind, natural gas and coal, but a lot of EIM resources will be non-run-of-river hydro.

Idaho Power also plans to have one coal plant and some natural gas participate in the EIM, but not its wind and solar. The hundreds of megawatts of wind and solar in its BAA under Public Utility Regulatory Policies Act contracts can only be dispatched for reliability. Hydro flexibility limitations because of fish protection requirements and other regulations at its 1,400-MW Hells Canyon facility will be one challenge in passing resource sufficiency tests, and the plant is also affected by seasonal challenges, and regulations.

The changing load forecast is a big issue, she said, and “it is hard enough to be a balancing authority without continually chasing a number just to pass the test,” she said.

September 11, 2017

SPP Seams Steering Committee Briefs: Sept. 6, 2017

SPP stakeholders last week endorsed a proposed interregional project to be developed in partnership with MISO, despite the project’s dim prospects.

The Seams Steering Committee unanimously agreed with staff’s recommendation to endorse the $5.2 million Split Rock-Lawrence project in South Dakota, identified through the interregional process. It would have been the RTOs’ first-ever interregional project, but staff told the Planning Advisory Committee last month that it no longer recommended moving forward with the initiative. (See SPP Glum as MISO Axes Last Interregional Project.)

SPP MISO interregional project — | *MISO & SPP*

MISO said its latest analysis of the project indicates the congestion on the 115-kV line is still manageable and that an alternative project could provide the RTO with at least the same benefit at a lower cost.

“It seems odd to endorse a project when we don’t have a partner,” said Jeff Knottek, director of transmission planning and compliance for City Utilities of Springfield, Mo., during the committee’s Sept. 6 conference call.

“We were aware we could come down on different sides on this,” said Adam Bell, SPP’s interregional coordinator. “We didn’t come to a point knowing MISO’s decision until we were done with a majority of the analysis.”

GridLiance’s Bary Warren, who chaired the meeting, said the RTOs’ coordinated study process identified a good project “from the SPP and MISO perspective.”

“MISO stakeholders don’t agree this is the best solution,” Warren said. “From SPP’s perspective, it appears this is a better solution for both RTOs.”

David Kelley, SPP’s director of interregional relations, said the South Dakota project could surface again in a future study. However, SPP’s Tariff prevents the RTO from approving an alternative interregional project other than the one that advanced from the interregional study out of a regional review.

“We’re recommending to you what we feel we’re obligated to do under the process,” he said.

Staff Prepping Response to AECI Project’s Protests

SPP staff is preparing comments due to FERC on Sept. 12 in response to protests lodged by Xcel Energy Services and Westar Energy over a proposed interregional project with Missouri-based Associated Electric Cooperative Inc. (See “Board Reaffirms Seams Project with AECI,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)

Last month, the RTO filed with FERC the terms and conditions of a cost-sharing and usage agreement among SPP, AECI and Springfield, as well as Tariff changes that would regionally allocate costs to the RTO’s transmission customers (ER17-2257).

The $13.75 million project involves installing a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a related 161-kV line, both near Springfield.

Westar asserts a lack of transparency regarding SPP and AECI’s cost-sharing methodology and their negotiations.

Xcel protested the proposed allocation of the Morgan transformer’s costs, noting the project is outside SPP’s footprint and being allocated to members on a regional load-ratio share basis. It also says SPP’s filings do not justify “a departure from the cost allocation methodologies” currently stipulated by the RTO’s Tariff.

SPP Sends MISO $1.2M for M2M Settlements

SPP sent MISO $1.2 million in market-to-market (M2M) payments for June congestion on flowgates along the seam between the two RTOs. The payments reduced the net amount of settlements SPP has collected from MISO to $20.5 million — as of June — since the two began the process in March 2015.

SPP MISO seams interregional project — | *SPP*

Temporary flowgates accounted for most of the congestion, binding for 214 hours, 32% less than the month before, and resulting in almost $1.2 million in M2M settlement charges to SPP. Permanent flowgates were binding for 27 hours, giving MISO an additional $59,339.

More than half of the M2M settlements came over a MISO flowgate in northwest Iowa near the Nebraska and South Dakota borders. SPP was unable to commit enough generation during low-wind periods to compensate for outages in the area, resulting in 23 hours binding and $676,332 in charges.

— Tom Kleckner

September 11, 2017

FERC Blocks MISO Plan to Shorten Queue Negotiations

By Amanda Durish Cook

FERC has rejected a MISO plan to shorten the number of days allowed to customers negotiating a generator interconnection agreement during the interconnection queue process.

The commission on Thursday ruled that MISO did not provide “sufficient support” for Tariff revisions that would have required that GIAs be negotiated and executed within 90 days, down from the current 150 days (ER17-1728). Negotiation and execution represent the last steps in the RTO’s interconnection queue process, occurring after impact and feasibility studies have been completed.

FERC said MISO failed to demonstrate that the shorter agreement process would give interconnection customers sufficient time to sort out final details on new generation projects.

In its filing with FERC, MISO said that, after the commission’s January acceptance of a leaner 460-day interconnection queue (ER17-156), the RTO realized that it also must “proportionally” reduce the amount of time allotted to crafting and signing GIAs — or risk exceeding the new queue timeline by about two months.

“Without reducing this piece of the timeline, the [generator interconnection process] will last for 520 days instead of 460,” MISO claimed.

MISO FERC generator interconnection agreement — | © *RTO Insider*

The RTO had sought approval to pare down all three queue stages, with negotiation cut from 60 days to 45; execution of a customer agreement reduced from 60 days to 30; and transmission owners given 15 days to sign off on an agreement instead of 30 days.

MISO had argued that the 460-day timeline approved by FERC “specifically contemplated a reduction in the [agreement] negotiation and execution timeline from 150 days to 90 days.”

The commission responded that a diagram proposing a general, 90-day agreement process was only attached to testimony in the queue reform changes, and not reflected in MISO’s Tariff changes. FERC also said its approval of the new queue process hinged on shortening the definitive planning phase of the queue — where restudies most often occur — and did not focus on altering the interconnection agreement process.

MISO’s filing framed the changes as “limited revisions … to improve and clarify the language implementing the commission’s recently approved interconnection queue reforms.” But FERC responded that the RTO’s characterization of the filing as merely a “cleanup” filing to reflect Tariff revisions was incorrect.

Several MISO members — including multiple wind developers — protested the shorter deadlines, arguing that the RTO was attempting to put the entire onus of a shorter queue on interconnection customers while making no sacrifices itself. Those members pointed out that they have already agreed to increased financial milestones and shorter time frames to review the results of system impact studies, and that MISO should now focus on shortening the timeline it gives itself to conduct studies during the definitive planning phase. The wind developers also said MISO is already failing to implement the more streamlined queue, with a backlog similar to that which dogged the old queue process now threatening the 2020 commercial operation deadline imposed on developers seeking the production tax credit.

Other members said the back-to-back 60-day negotiation and execution periods are crucial because that’s when facility costs are finalized and the companies obtain board approval of the project.

MISO last month told stakeholders to prepare for imminent delays while it studies an unprecedented influx of prospective projects that last year entered the queue. (See FERC Accepts MISO’s 2nd Try on Queue Reform.)

MISO also asked FERC for permission to give interconnection customers fewer days in which to modify their selected level of network resource interconnection service so that any change did not occur after the conclusion of the final system impact study. FERC did not address the proposed change in its decision to reject the RTO’s broader proposal.

September 11, 2017

EKPC Gets PURPA Exemption; Still on Hook for 2 QFs

By Rory D. Sweeney

FERC last week granted East Kentucky Power Cooperative an exemption from being required to purchase power from Public Utility Regulatory Policies Act qualifying facilities larger than 20 MW — but not in time for the cooperative to avoid such purchases from two solar projects within its territory.

The 1978 federal law requires that utilities — including municipals and cooperatives — purchase electricity from QFs at the utility’s “avoided cost.” QFs were defined as cogenerating plants and small power producers under 80 MW. FERC Order 688, issued in October 2006, granted utilities the ability to disregard the requirement for QFs over 20 MW if they can prove the facilities have nondiscriminatory access to the wholesale markets. As a PJM member, EKPC argued that QFs in its territory have that access.

east kentucky power cooperative EKPC FERC PURPA — EKPC CEO Tony Campbell speaks in May at the ground-breaking for a 60-acre solar farm on EKPC’s headquarters property in Winchester | *EKPC*

FERC agreed, but it declined to backdate the approval far enough for EKPC to avoid contracting with two solar projects.

“Until a utility applies for termination of the PURPA mandatory purchase obligation, and the commission grants such application, a QF has the statutory right to pursue a contract or other legally enforceable obligation with that utility,” FERC said.

The 80-MW Bluebird Solar and 60-MW Blue Jay Solar projects notified EKPC in December and March, respectively, of their intention to sell their entire output to the cooperative at the avoided cost rate.

EKPC argued that it first requested an exemption from the PURPA rules last November, which would have relieved the cooperative of any responsibility to buy from the solar projects. However, the commission’s lack of a quorum earlier this year caused the request to languish and eventually be denied by FERC staff once its 90-day time frame for action had passed.

The cooperative refiled the request on June 9, arguing that the effective date for the exemption should start from the November filing because it was reasonable to believe that FERC would have approved it with a quorum.

The commission rejected EKPC’s argument and set the effective date for June 9.

September 11, 2017

NYISO Stakeholders Talk Details of Carbon Charge

By Michael Kuser

ALBANY, N.Y. — NYISO stakeholders on Wednesday offered broad support for incorporating a $40/ton carbon charge into the ISO’s markets, but some expressed concern over how the costs of New York’s decarbonization effort would be allocated.

NYISO FERC carbon charge — Rhodes | © *RTO Insider*

The comments came at a Sept. 6 public hearing jointly run by NYISO and the New York Department of Public Service (DPS).

Both New York Public Service Commission Chair John Rhodes and NYISO CEO Brad Jones, who opened the hearing, signed off last month on a much-anticipated Brattle Group report on pricing carbon into generation offers and energy clearing prices. (See NYISO Study Sees Little Cost Impact from Carbon Charge.)

NYISO FERC carbon emissions Clinton nuclear plant — Jones | © *RTO Insider*

Brattle’s Sam Newell presented a summary of the report, saying more than 90% of the increased energy costs could be offset through carbon rebates to customers, reduced prices for renewable energy credits and zero-emission credits (ZECs), and improved investment signals. The report predicts the net impact on customer electric bills will be between a 1% reduction and a 2% increase.

Steps Forward

Scott Weiner, DPS deputy for markets and innovation, said the plan being developed by his agency, the ISO and the New York Energy Research and Development Authority envisions fossil fuel generators incurring a penalty based on carbon emissions levels. The carbon adder idea was prompted by the PSC’s decision to subsidize the state’s nuclear plants through ZECs.

Jones noted that New York hopes to implement the plan in the markets within three years, a time frame that Weiner called reasonable. Weiner said officials will have a clearer picture in January, after additional outreach.

As first steps, Weiner said, the DPS would seek stakeholders’ comments on, and alternatives to, Brattle’s proposal by Nov. 1. NYISO and the department will hold a series of technical conferences on the issue, with the first likely to be held around Thanksgiving, he said.

“The exact format has yet to be determined, but we have zeroed in on two topics. One is the issue of borders and seams … and the second topic is revenue allocation,” Weiner said.

Underselling Offsets?

During the hearing, Mark Younger of Hudson Energy Economics contended that the Brattle report understated the volume of expected offsets. Brattle did not account for the New York Power Authority, “which has a lot of green resources also [selling] a fair amount of generation at market prices,” he said.

The Brattle report concluded that a $40/ton carbon charge would raise energy prices by approximately $19/MWh on a load-weighted average basis, but that after accounting for static energy price offsets, net customer costs would rise only $6/MWh.

“And so, this is a source of revenues, certainly to the state, that could be used either to reduce taxes or to be rebating people, but that’s not included anywhere in [the report’s] estimate of savings and offsets against this $19/MWh cost,” Younger said.

“As we get rid of net metering, we end up with a value stack, and part of the stack is a credit for CO₂ savings,” he said. “And obviously the more the market represents the CO₂ savings, the less you have to essentially subsidize this behind-the-meter stuff, and that would be another savings because that would bring an out-of-market payment more directly into the market, and that’s not captured anywhere.”

While Newell conceded Younger’s “good point,” he said Brattle’s goal was to make reasonable assumptions in the middle of the range of predicted outcomes.

NYISO carbon charge — | *The Brattle Group*

Kelli Joseph, director of New York market and regulatory affairs for NRG Energy, pointed to the major challenge of the state trying to achieve a variety of goals through different methods. Among them: RECs, ZECs, the Clean Energy Standard and Reforming the Energy Vision.

“And is the $40 price sufficient to not only handle ZEC, but get 50% renewable and achieve whatever the REV goals are?” she asked.

Informing FERC

Matthew Schwall, director of market policy and regulatory affairs for the Independent Power Producers of New York, referred to FERC’s interest in price formation, a subject brought up at a May technical conference on harmonizing public policy with wholesale markets. (See NYISO Sees Carbon Adder as Way to Link ZECs to Markets.)

“FERC is looking for guidance,” Schwall said. “Would it be possible for NYISO to work through its stakeholder process to come up with a conceptual filing to submit to FERC — prior to any Tariff filing, prior to coming to a complete market design — in order to get some guidance from FERC?”

NYISO Chief Information Officer Rich Dewey responded that in May the commission said that any proposal would require “a great deal of stakeholder support” to be successful.

nyiso carbon charge ferc — Dewey (left) and The Brattle Group’s Sam Newell

“And we want to have the most thoroughly vetted design before we go down to FERC,” he said.

Weiner added, “Importantly, nobody should assume that FERC is not aware of what we are doing here today and going forward. The DPS staff and NYISO staff have ongoing conversations with FERC staff, so they’re well aware of this process, and I think it’s fair to say they’re encouraged by it.”

Reconciling Competing Interests

David Clarke, director of wholesale market policy for the Long Island Power Authority (LIPA), questioned the allocation of carbon costs, saying they might be disproportionately borne by consumers in southeastern New York.

“Right now, everyone has a pro rata share of REC requirements,” Clarke said. “LIPA takes on a proportional share of those renewable energy requirements. … Those collections are going down because the costs of the RECS are going down, but the collections from locational-based marginal prices are going up because you’re [reducing] carbon. Those effects are not remaining in the same proportion and they have different effects for downstate New York than for upstate.”

Newell said New York may want to consider allocating carbon revenues evenly to make up for the non-proportional impacts.

“The total wholesale cost, if it goes up about $20/MWh times about 150 TWh, that’s about $3 billion in total wholesale costs, and then the carbon fund is about half of that, or about $1.5 billion,” Newell said. “The incidence of who’s seeing prices increase more or less is not even, and that is why you might want to consider [proportional rebates],” Newell said.

Weiner said the topic of revenue allocation is key. “How do you divide it up? Is there a way to reconcile these competing interests? The status quo is the status quo, but maybe that’s not the best way, either.”

Reliability is Job One

Stuart Nachmias, Consolidated Edison’s vice president for energy policy and regulatory affairs, said “markets have worked well in meeting the reliability needs of customers in the state but haven’t yet incorporated clean energy goals.”

The capacity markets address reliability, and Con Ed spends a lot of time trying to figure out how the energy market price impacts the capacity market, Nachmias explained. “And more importantly, how does that affect the resources we need for reliability to manage a variable future?” he said.

Dewey said reliability is always the grid operator’s first concern.

“The reality is there’s a lot more renewables coming onto our system, so we need to look at what changes might be necessitated in our existing market products and our existing capacity markets, energy markets or ancillary services to be able to accommodate that grid in the future,” he said.

Nuclear Power not ‘Clean’

Manna Jo Greene, environmental action director for Hudson River Sloop Clearwater, said, “I implore you not to use the word ‘clean’ when talking about nuclear energy. I ask you to think about the communities who had the benefit of the goose that laid the golden egg for so many years and are now faced with massive amounts of high-level radioactive waste.”

Jessica Azulay, program director at Alliance for a Green Economy, echoed Greene’s view and suggested that the DPS and NYISO consider a charge on other greenhouse gases, such as methane.

Erin Hogan, of the New York Department of State’s Utility Intervention Unit, asked if Brattle could share the study’s spreadsheet model, which might help the formation of independent proposals. Weiner said he didn’t want to put Newell “on the spot … but I think that’s a very good point.”

Hogan said she knew people had different perspectives: “Those who don’t want combined cycle, those who don’t want nuke, and there’s those who don’t want transmission, but they want the emissions to go down. The reality is … the most challenging part is to maintain reliability, and the other part is to achieve the environmental goals, and the third part is trying to do this in the most cost-effective way possible. … I’m asking people to come at it with a pragmatic perspective. Often people look at it as if we’re going to optimize to achieve the perfect evolved frame. I think what we really do is choose the least imperfect solution.”