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December 27, 2024

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FERC Again Rebuffs Brayton Point Union

FERC on Wednesday denied rehearing of its June decision certifying the ninth Forward Capacity Auction results in ISO-NE, dealing another blow to a utility union’s claim that supply of the Brayton Point plant was illegally withheld to raise prices (EL15-1137).

The Utility Workers Union of America, which represents workers at the Massachusetts plant, in July asked FERC to void the auction results. (See Fourth Time the Charm? Brayton Point Union Again Challenges ISO-NE Auction.)

Energy Capital Partners, former owner of the 1,517-MW plant, did not offer it in capacity auctions for 2017/18 and 2018/19 after announcing the plant would close in 2017. Brayton Point was sold last year to Dynegy, which said it would close the plant as scheduled.

FERC previously rejected the union’s challenge to results of FCA 8 on similar grounds. FERC said a non-public investigation by its Office of Enforcement failed to uncover any evidence of wrongdoing.

“This conclusion remains valid for FCA 9,” FERC wrote.

The commission also reiterated its acceptance of the conclusion of ISO-NE’s Internal Market Monitor that no anti-competitive behavior existed before the auction.

FERC also rejected the union’s contention that the ISO-NE Tariff requires a determination that a unit is uneconomic before it is allowed to retire.

“The Tariff contains no provision requiring a resource to demonstrate that it is uneconomic before it is allowed to retire, and UWUA does not point to any such provision. There is no test as to whether the unit can economically provide capacity, nor is there a mechanism by which ISO-NE can compel the resource to continue operating under any circumstances,” the commission wrote.

— William Opalka

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FERC Accepts Order 1000 Compliance Filing

FERC has accepted NYISO’s fourth Order 1000 compliance filing, turning aside the protests of transmission developers that claimed it unfairly favored incumbent transmission owners (ER13-102-007).

LS Power and NextEra had protested the ISO’s right to terminate development agreements if a force majeure event prevents a non-incumbent developer from completing its project by the in-service date. (See Tx Developers Challenge NYISO, SPP, ISO-NE Order 1000 Filings.)

NYISO and the New York Transmission Owners submitted their fourth Order 1000 compliance filing in May. It included a pro forma development agreement for NYISO’s reliability transmission planning process.

“NYISO argues that it must have the option to terminate the development agreement and identify alternative means of satisfying an identified reliability need if a developer cannot complete its project by the required project in-service date,” FERC wrote on Dec. 23.

The commission cited a similar provision at PJM, ordering NYISO to add comparable language in its development agreements with incumbent transmission owners to prevent discrimination.

In a second order Dec. 23, FERC rejected a NYISO filing that the commission said was unfair to competitive transmission developers (ER15-2059).

FERC said the proposal “subject[s] nonincumbent transmission developers to an interconnection process with different requirements than the interconnection process that applies to incumbent transmission owners.” While all interconnection customers are required to obtain system impact and facility studies, the nonincumbents were required under the proposal to additionally submit a feasibility study and deposits for all three studies.

NYISO had argued the incumbent would have already conducted a feasibility study in its normal planning process, but FERC said that would create two different processes that are not comparable.

— William Opalka

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FERC Orders Tech Conference on PJM FTR Rule Changes

By Rich Heidorn Jr.

FERC on Monday ordered a technical conference to sort out conflicting claims over PJM’s proposed rule changes to reduce underfunding of financial transmission rights.

PJM’s proposed changes, filed in October, were challenged by the Financial Marketers Coalition and others, who said they would be ineffective and discriminatory. The commission said the conference was needed to develop more evidence before it rules (EL16-6-001, ER16-121).

The conference will explore PJM’s claim that its existing rules on FTRs and auction revenue rights are unjust and unreasonable and that the problems would be remedied by its proposed changes. Specifically, the conference will look at ARR modeling and allocation processes; treatment of portfolio positions in allocating underfunding or surplus among FTR holders; and the potential for market manipulation.

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Crews install towers as part of Commonwealth Edison’s Grand Prairie Gateway project, which is expected to go into service in 2017. PJM said the need for the project might have been approved earlier under its proposed FTR rule changes.

An FTR entitles its holder to credits based on LMP differences in the day-ahead energy market when the transmission grid is congested. FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.

PJM improved funding under current rules by modeling more transmission outages, clearing more counterflow FTRs and improving its modeling of loop flow, the alignment of the FTR, day-ahead and real-time energy markets, and market-to-market coordination with MISO.

PJM said the changes raised FTR revenue adequacy from as low as 69% during planning years 2010/11 through 2013/14 to at least 110% since the 2014/15 planning period.

However, PJM said the changes resulted in an unfair shift of revenues from ARR holders to FTR holders. It said the load-serving entities receiving reduced Stage 1B ARRs are largely different from the LSEs receiving the over-allocation of infeasible Stage 1A (10-year) ARRs.

To correct the cost shift, PJM proposed eliminating the netting of negatively valued FTRs against positively valued FTRs within portfolios. It also proposed increasing current ARR results by 1.5% annually — equal to the average ARR 10-year growth rate since 2007 — in the Stage 1A 10-year simultaneous feasibility process. (See PJM to File FTR, ARR Rule Changes with FERC.)

PJM said the changes will increase the likelihood of infeasible ARRs, potentially identifying needed transmission upgrades such as Commonwealth Edison’s Grand Prairie Gateway project sooner. The 60-mile 345-kV line through four counties in northern Illinois began construction in the second quarter of 2015 and is expected to begin service in 2017. The company says it will allow the import of cheaper wind power from the west, saving customers about $250 million net of all costs within the first 15 years.

Commenters including utilities and the Independent Market Monitor told FERC they generally supported the proposed changes. But the Financial Marketers Coalition (representing DC Energy, Inertia Power, Saracen Energy East and Vitol), Shell Energy N.A. and others protested the elimination of netting, saying PJM failed to show the current rules are unjust and unreasonable and that the change would cure underfunding.

Without netting, the coalition argued, underfunding risks would shift to those that take on counterflow FTR obligations and could encourage market manipulation.

Opponents also questioned whether the proposed 1.5% escalation would be as effective in preventing ARR infeasibilities as claimed by PJM.

[Editor’s Note: An earlier version of this article mistakenly reported that J. Aron & Co. is a member of the Financial Marketers Coalition.]

 

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PJM Seeks Changes to AEP, FirstEnergy PPAs

By Suzanne Herel

Power purchase agreements proposed by American Electric Power and FirstEnergy need changes to preserve competition and Ohio’s ability to attract merchant generation, PJM said this week.

The RTO made the recommendations in testimony to the Public Utilities Commission of Ohio (14-1693-EL-RDR, 14-1694-EL-AAM, 14-1297-EL-SSO).

The filings were virtually identical and offered two amendments to the eight-year agreements. The first would define a “reasonable bidding practice” as offering the output of units covered by the deals into PJM’s markets at no lower than their actual cost, with no consideration of offsetting revenue being provided by Ohio retail customers.

“Bidding at actual cost, consistent with the definition of acceptable costs included in the PJM Tariff and manuals, ensures that the PPA does not have the effect of artificially suppressing prices in any of PJM’s markets,” Stu Bresler, senior vice president of markets, said in the AEP case. The phrasing for the FirstEnergy case was changed only to reflect the term that company is using for its request, a retail rate stability rider (RRS).

Bresler also recommended that if the commission accepts the agreements, it should make clear in its order whether generation owners or their customers would bear the risk of non-performance under the new Capacity Performance model, which aims to ensure reliability by rewarding over-performing units and penalizing under-performing generators.

Bresler said PJM takes no position on the proposed stipulations but felt it necessary to weigh in on aspects that could affect its wholesale markets.

The consequences of “unreasonable” actions when selling AEP’s and FirstEnergy’s output would be “severe,” yet the agreements do not clarify “reasonable” or “unreasonable” actions, Bresler said.

“This provision, more than any other in the stipulation, has the potential to impact the PJM marketplace as a whole and the marketplace in Ohio for new investment, depending on how the provision is implemented,” he said.

PJM’s recommendations are in Ohio’s interest because the output of units covered by the agreements falls substantially short of the companies’ peak loads — 10,500 MW in AEP Ohio’s case and 11,900 MW for FirstEnergy, Bresler said. New generation resources are critical to Ohio’s future, he said, but they would be discouraged from investing in the state if others were allowed to bid below their costs.

Bowring: PPAs Inconsistent with Competition

PJM Market Monitor Joe Bowring also filed testimony, saying that the retail rate stability rider requested by FirstEnergy and AEP’s proposed power purchase agreement both “constitute a subsidy which is inconsistent with competition in the PJM wholesale power market.” He urged the commission to reject them.

The purpose of the AEP agreement, he said, “is to shift costs and risks from shareholders to customers, to remove the incentives to make competitive offers in the PJM capacity market and to provide incentives to make offers below the competitive level in the PJM capacity market.”

The agreement also does not explicitly address how AEP plans to operate within PJM’s new capacity market design.

However, Bowring said, “I would expect that the proposed PPA rider would require ratepayers to pay any performance penalties associated with the assets included in the PPA rider. I would also expect that AEP would retain any performance payments at other AEP units not included in the PPA rider, even if paid for in part by these ratepayer penalties.”

That removes the risk from shareholders, along with the incentive to manage the performance of the units, he said.

Like Bresler, Bowring expressed concern about the agreements enabling the companies to offer output into the market at artificially low prices, edging out competition.

AEP’s request, he said, indicates that PJM should expand its minimum offer price rule to include any new units with subsidies, requiring them to bid into the market at a level no lower than the cost of new entry.

Bowring also testified that the rider requested by FirstEnergy would transfer all “historic and future costs” for certain plants to ratepayers and set up the same paradigm involving its participation in PJM’s capacity market.

Together, the agreements essentially would re-regulate about 6,300 MW of generation. AEP announced its PPA on Dec. 14. FirstEnergy released its proposal Dec. 1. PUCO is expected to rule on the cases in early 2016.

In addition to its testimony, PJM plans to issue a market analysis of both deals this spring. (See PJM Looking at AEP, FirstEnergy PPAs; Critics Join Forces.)

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FERC Allows CAISO EIM to Identify Adjacent Capacity

By Michael Brooks

FERC last week approved Tariff revisions that will allow CAISO’s Energy Imbalance Market to automatically recognize the capacity that participants outside of the ISO’s footprint use to maintain reliability in their own territories (ER15-861-006).

In its filing proposing the change, CAISO told the commission that its software’s inability to recognize this “available balancing capacity” was creating false scarcity in the market, resulting in price spikes. The changes will ensure prices reflect the true nature of the deployed capacity, the ISO said.

caiso eimUnder the revisions, each EIM participant will be required to identify the available balancing capacity of all its resources, even if it does not bid those resources into the market.

“We agree that the available balancing capacity proposal will reduce the potential for imbalance energy price spikes by providing for greater visibility of the capacity each EIM entity has available to it to resolve power balance violations within its own [balancing area authority], even when that capacity is not being offered into the EIM,” FERC said. The changes also allow EIM participants flexibility to determine what capacity they should retain outside of the market to maintain reliability, the commission said.

Beginning in November 2014, CAISO expanded its EIM to Western Interconnection utilities outside its territory. PacifiCorp — with territory in Oregon, Idaho, Utah and Wyoming — was the first to join, followed recently by Nevada-based NV Energy. Arizona Public Service and Washington-based Puget Sound Energy are projected to join early next year, followed by Portland General Electric in 2017. (See CAISO Expands Reach to 7 States with Imbalance Market.)

NV Energy

In a related order, FERC dismissed requests for rehearing of its approval of certain Tariff revisions by NV Energy to allow its participation in the EIM (ER15-1196-002).

Powerex, a power marketer that operates in the western U.S. and Canada, and Truckee Donner Public Utility District, a municipal utility in California, objected to the commission’s approval of NV Energy’s use of CAISO’s LMPs to settle imbalances for transmission customers who opted out of the EIM. Powerex also asserted that NV Energy’s participation in the EIM would jeopardize resource adequacy in the Nevada utility’s balancing area.

The companies based their complaints in part on price spikes and other problems in the market when PacifiCorp first joined. FERC said, however, that “CAISO has taken tangible steps to resolve the underlying problems that contributed to the price spikes” in PacifiCorp’s territory. The commission pointed to the steps the ISO has taken to resolve those problems — including the recognition of available balancing capacity.

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FERC Briefs

FERC denied MISO’s request for clarification and rehearing of a May 2015 order concerning the RTO’s request for waivers from the requirements of Order 676-H, which incorporated into commission regulations the North American Energy Standards Board’s latest Standards for Business Practices and Communication Protocols (ER15-548-001).

“We disagree with MISO’s argument that the commission’s policy regarding the point at which a redirect customer loses rights to its original path was unclear until the issuance of Order No. 676-H,” the commission said, adding that the policy was announced in 2002.

FERC Directs MISO to Specify SSR Cost Allocations, Interconnection Transfer Rights

FERC denied rehearing but granted clarification of a July 2014 order that conditionally accepted MISO’s Tariff revisions regarding system support resource procedures (ER12-2302).

The commission agreed with MISO that its order was unclear, clarifying that the RTO’s Tariff must “provide specific guidance about the contractual commitments required of generation and demand-side resource alternatives, and general guidance about how MISO will evaluate whether contractual commitments required for additional types of resources are comparable to the commitments that apply to transmission solutions.” The commission said MISO’s September 2014 compliance filing generally met the directive.

“However, we note that MISO’s proposed revisions providing that a ‘generator alternative may be a new generator, or an increase to existing generator capacity’ do not address the situation where an existing generator, which is not available at the time of SSR designation and is subsequently made available, can be selected as an alternative solution,” FERC said. It ordered MISO to submit a compliance filing within 45 days revising its Tariff to allow an existing generator to be considered as a generator alternative.

The commission also granted Wisconsin Electric Power’s request for clarification, ruling that MISO must allocate SSR costs to the load-serving entities that require the operation of the SSR units for reliability. FERC said it agreed with Wisconsin Electric’s concern that MISO’s method for cost allocation “can produce results that are not consistent with MISO’s Tariff or cost-causation principles.”

PATH Ruling on RTO Adder Affirmed

The commission denied Potomac-Appalachian Transmission Highline’s (PATH) request for rehearing of a November 2012 order denying the transmission developer continued application of the 50-basis-point incentive for membership in PJM (ER12-2708-002, ER09-1256-001).

The commission said that PATH — a joint venture formed by American Electric Power and Allegheny Energy (now FirstEnergy) to build a $1.8 billion transmission line between West Virginia and Maryland — was no longer eligible for the adder after PJM canceled the project in 2012.

The commission said its earlier order was consistent with existing policy, denying PATH’s complaint that it had acted retroactively.

In September, a FERC administrative law judge recommended the developers be denied recovery of more than $10 million of their $121.5 million project recovery claim. The judge recommended the commission deny recovery of lobbying and advertising costs as well as part of their legal costs and losses on the sale of the property they acquired.

The commission, which can accept the recommendations in whole or in part, has not acted on the ruling. (See FERC ALJ Rejects $10 Million in PATH Transmission Project Recovery.)

— Amanda Durish Cook and Rich Heidorn Jr.

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MISO Unveils Queue Rule Transition as Wind Advocates Seek Delay

By Amanda Durish Cook

CARMEL, Ind. — MISO has settled on a transition plan for its new interconnection queue rules and intends to file Tariff changes with FERC by the end of the year, despite wind advocates’ complaints that the process has been rushed.

MISO said it plans to stagger implementation, “processing some projects under the existing rules and transitioning certain projects to a portion of the new process.”

Between Feb. 20 and May 20, MISO plans to finalize existing generation interconnection agreements and facilities studies, with GIAs completed for the latter by late August. These GIAs will be at the top of the queue for all study cycles to follow.

The RTO will also finish all incomplete system impact studies by Aug. 27 and give the owners of those projects an option by early September to either move into phase three of definitive planning under the existing rules, paying an M4 milestone, or enter phase one of definitive planning under the revamped queue without having to pay another M2 milestone fee.

Projects that haven’t yet entered into a system impact study by Feb. 20 will be rolled into the reformed queue.

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Vikram Godbole, senior manager of MISO’s generator interconnection planning group, said interconnection customers with pending GIAs as of Feb. 20 will be targeted first to complete negotiations.

“It’s a tall order, I realize that,” Godbole said of the dates outlined in the transition plan.

Throughout the process, staff representing Minnesota-based Wind on the Wires have complained that the adoption of the new queue timeline and rules has been rushed. The wind advocacy group says that costs remain too high under the new rules and wants MISO to eliminate the M4 milestone payment and create a cost cap on network upgrades. It has asked that MISO delay implementation of the rules until it reaches an agreement with the group.

Godbole said that the new queue will be implemented despite any future required Tariff changes to the interconnection process that may arise due to resource adequacy Tariff revisions. He said those will be handled in the future “as necessary.”

He added, “Any aspects from a technical perspective will be done at the [Business Practices Manuals] level. We’ll take those on next year.”

MISO will use the M2, M3 and M4 milestone payments surrendered by owners of non-viable projects to compensate other interconnection projects that were negatively impacted by the withdrawals.

Godbole said the new queue rules are intended to reduce the number of customers who keep non-viable projects in the queue until the “tail-end.”

“We’re doing this for interconnection customers,” Godbole said. “We want to make sure that people who come into the process ready are rewarded.”

In early December, stakeholders said interconnection customers should be able to use their M2, M3 and M4 payments to fund their initial milestone payment in the 30 days following completion of a generator interconnection agreement. Although MISO denied the request, the grid operator offered a willingness to discuss the option with stakeholders and, depending on the outcome, file Tariff revisions sometime in 2016.

During the last round of comments on Dec. 7, stakeholders requested the addition of a third penalty-free withdrawal option if estimated costs increase more than 25% between MISO’s system impact study and facilities study. Godbole said that MISO evaluated the merits of a third off-ramp “intensely” but ultimately determined not to provide it because the proposed queue reform is more economical for interconnection customers than the queue currently in place.

Stakeholders also criticized the M3 and M4 milestone floors of $2,000/MW, arguing that the cost never actually dips to $2,000, so the threshold is “illusory.” MISO declined to raise the floor, saying that the limit was FERC-approved and costs could come down in the future. (See MISO Cuts Queue Admission, Adds ‘Off-Ramps’.)

 

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MISO Planning Advisory Committee Briefs

CARMEL, Ind. — The review process for MISO’s Business Practices Manuals has been rewritten to clarify the RTO’s obligations and the Planning Advisory Committee’s role.

The revised language directs MISO to identify “outstanding or unresolved issues” when presenting BPM changes to the PAC, adds “timing concerns” to the process and allows the committee to modify changes to manuals brought forward by subgroups, instead of delegating work back to the original subgroup.

Matthew Tackett, a MISO principal adviser, said the goal was to make the steps of the evaluation clearer. The language rework was first brought up at the Nov. 11 PAC meeting.

MISO is asking for stakeholder comments on the edits through Jan. 22. A finalized version of the language will return to the February PAC meeting for approval.

MISO Adds Conditions for Stakeholder Notification and Advice into Expedited Review Process

MISO reviewed with the PAC proposed revisions to BPM 020 governing the expedited review process, which will replace out-of-cycle reviews.

The revisions require MISO to “promptly” notify stakeholders of expedited projects whose voltage, cost and other criteria would otherwise make it subject to competitive bidding under FERC Order 1000. Projects will be ineligible for expedited status if they meet criteria for market efficiency projects and “are not needed to meet the obligations or requirements of the transmission owner.”

Tackett said the size criteria was instituted so stakeholders wouldn’t be notified too many times in a cycle. “I use the analogy of junk mail. You get too many and you start saying ‘Oh I don’t care about that,’ and you miss the $300 million one,” Tackett said.

Chris Plante with Wisconsin Public Service Corp. said that an “open, collaborative process requires that stakeholders know what’s going on.” Plante pointed out that in the past there’s been “at least one” large out-of-cycle project that didn’t continue in the process once stakeholders had the opportunity to weigh in on its usefulness and urgency.

The changes also require MISO staff to consider the PAC’s input in deciding whether to bring the requested project to the attention of the Board of Directors’ System Planning Committee. “Stakeholders may also provide advice relative to the project to the SPC and/or the board in accordance with the protocols of the Advisory Committee,” the manual says.

“We realize this is a very controversial subject. There’s a time to move on and then there’s consensus, and this may be an example of that,” said Tackett, explaining that MISO is allowing further rounds of discussion.

Final Review on Minimum Project Requirements for Competitive Bidding Pushed Back

MISO asked for another round of comments by Jan. 12 on BPM 029, which defines the requirements of transmission projects eligible for competitive bidding.

Tackett said he didn’t think any conflicts would arise between the manual and the competitive bidding process for the Duff-Coleman project. He said the manual would be a living document and subject to further improvements but couldn’t foresee a needed change over the next six months as bids are prepared.

“It deals with topics where there’s lots of different opinions on how to do things,” Tackett commented. “I like to call it ‘version one final.’”

Nearly Half of All MTEP Projects in Service, MISO Reports

Almost half of all projects included in the MISO Transmission Expansion Plan were in-service as of the third quarter of 2015, Senior Transmission Planning Engineer Matt Ellis told the PAC in the bi-annual MTEP status update.

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MISO reported that 47% of the $22.5 billion in MTEP projects given the go-ahead since 2003 are in service, while 39% remain in the planning stages. Another 8% are currently under construction and the remaining 7% have been withdrawn. The latest numbers do not include projects in the recently approved MTEP15. (See MISO Board of Directors Briefs.)

Ellis said the latest cost estimates on economic-based projects were positive, with benefit-to-cost ratios above projections. He also said almost all of MISO’s baseline reliability projects are on schedule.

“MISO’s post-approval role is to provide transparency,” Ellis said of the update. He added that MISO’s transparency goal will become more challenging with the introduction of competitive bidding, since transmission cost estimates submitted in the developer selection process are considered commercially sensitive information.

Loss of Load Working Group to be Absorbed Under Redesign

PAC Chairman Bob McKee said the committee is “getting off light” compared to assignments doled out to other MISO groups under the stakeholder redesign, with only a short to-do list. The PAC will absorb the Loss of Load Expectation Working Group into a broader, yet-to-be-formed Resource Adequacy Committee. There is no timeline yet on when the move will happen.

“It’s was a nice interactive approach between the stakeholders and MISO,” McKee said of the redesign.

— Amanda Durish Cook

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Manitoba-Minnesota Tx Line Granted Rate Incentives

By Amanda Durish Cook

ALLETE won FERC approval last week for rate incentives on the Great Northern Transmission Line between Manitoba and Minnesota.

FERC’s order allows ALLETE to recover 100% of construction work in progress (CWIP) for the 220-mile, 500-kV line. It also will recover all of its “prudently incurred” costs if the project is abandoned or canceled due to factors beyond ALLETE’s control (ER16-118).

“Including 100% CWIP recovery in the rate base will provide ALLETE with steady cash flow during the construction period, protecting ALLETE’s financial metrics and relieving downward pressure on its credit rating,” FERC explained.

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(Click to zoom)

The commission said that using CWIP recovery as opposed to employing allowance for funds used during construction (AFUDC) would help “insulate” ALLETE’s ratepayers against sticker shock. FERC also said ALLETE’s proposed accounting and tracking procedures are “sufficient” to ensure that customers won’t be double-charged under the recovery and AFUDC.

According to FERC, ALLETE claims the Great Northern project “presents substantial physical risks and challenges because it is a large new cross-border transmission project that requires dozens of federal and state permits and local coordination.”

ALLETE’s Minnesota Power is building the southern portion of the line, which will run from the Minnesota-Manitoba border to the Blackberry Substation near Grand Rapids, Minn. It has yet to secure right-of-way easements and faces opposition from affected landowners.

The project has already undergone one re-siting, since the original proposed border crossing route was rejected following a review by state and federal agencies. “ALLETE argues that it may face similar siting challenges as [siting] proceedings progress,” FERC said.

The line will primarily deliver hydropower from Manitoba Hydro, which will own 49% of the project and pay $558 million to $710 million of the total cost. Minnesota Power will own the remaining 51% and estimates its cost at $158 million to $201 million.

The line is projected to go into service in 2020.

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MISO: Coal Retirements, Gas Prices, Flexibility Key to CPP Compliance Costs

By Amanda Durish Cook

CARMEL, Ind. — Additional retirements of coal-fired generation could increase MISO production costs by as much as $97 billion over 20 years, according to preliminary results of the RTO’s near-term analysis of the Clean Power Plan. The results were presented to the Planning Advisory Committee on Dec. 16.

misoThe study compared a base assumption — no additional coal retirements beyond the 12.6 GW expected under the Mercury and Air Toxics Standards (MATS) — with incremental retirements ranging from 7 GW (12.5% of MISO’s remaining nameplate capacity) to 28 GW (50% of capacity).

A loss of 7 GW would increase MISO’s production costs by a net present value of $87.3 billion over 20 years, increasing to $97.4 billion for 28 GW. MISO estimates the MATS retirements will increase production costs by $90.7 billion over 20 years.

The figures do not include costs of additional electric and natural gas infrastructure needed to support replacement generation. Those costs weren’t included in the scope of work for the near-term analysis but will be included in a long-term analysis that will run through late 2018.

The analysis found that the Clean Power Plan’s building blocks have the potential to reduce carbon emissions generated in the footprint from more than 500 million tons annually to below 350 million tons.

MISO ran 675 simulations assuming annual demand growth of 0.8% and natural gas prices ranging from $2.30 to $6.30/MMBtu. The RTO also made calculations based on renewable sources making up 14%, 20% and 30% of energy production.

Gas Price Impact

MISO said the price of natural gas could be the biggest variable in the cost of compliance. “Beyond gas prices, it’s hard to isolate the single biggest variable,” Jordan Bakke, senior policy studies engineer at MISO, told the PAC.

Bakke said MISO staff have found that the more flexible the compliance strategy — mixing generation resources and strategies such as trading programs — the lower compliance costs will be.

During the Advisory Committee’s “hot topic” discussion of the final rule Dec. 9, stakeholders were divided on how involved MISO should become in guiding compliance paths. (See Lead or Follow? MISO Stakeholders Split over RTO’s Role in CPP.)

Flora Flygt, strategic planning and policy adviser at American Transmission Co., said she appreciated MISO’s work and asked that MISO post materials as soon as they’re prepared so stakeholders can spend more time with the information ahead of meetings. PAC Chair Bob McKee said the early release of modeling information would lead to more productive meetings.

Based on a revised timeline, MISO’s near-term analysis will last until February, overlapping with the mid-term analysis slated to begin in January. Additional results from the near-term analysis will be presented at the January PAC meeting.

“It’s only an initial step into this suite of work,” Bakke summed up. “What’s on tap for the January [meeting] is looking at regional versus state compliance and rate-based versus mass-based compliance. So we have a huge trove of information coming out. The bulk of the analysis is yet to come.”