Page 1270 – RTO Insider

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.”

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