Page 1121 – RTO Insider

July 31, 2018

Enviros, Industrials Challenge DOE Study on LNG Exports

By Rich Heidorn Jr.

Environmentalists and industrial gas consumers last week challenged a Department of Energy-funded study that concludes U.S. economic growth would be boosted by unlimited LNG exports — even if they double current natural gas prices.

More than a dozen comments were filed by the July 27 deadline in response to the June 7 study, performed by NERA Economic Consulting for the department’s Office of Fossil Energy. DOE said it plans to consider the study in responding to 25 pending applications for LNG exports to countries lacking free-trade agreements with the U.S.

Although there is a consensus that exporting too much domestic natural gas could expose U.S. consumers, industrial users and electric generators to much higher world prices, there is no agreement on what that tipping point is, or how soon the U.S. could get there. (See No Agreement on Tipping Point for LNG Exports.)

The NERA study — the fifth DOE has commissioned since 2012 examining the economics of LNG exports — suggests that policymakers should not worry about any price increases, finding “consistently positive relationships between LNG exports and measures of economic performance” such as gross domestic product and U.S. living standards.

The Natural Gas Act requires DOE to determine whether natural gas exports to countries without FTAs with the U.S. are in the “public interest.” Exports to countries with FTAs do not require such reviews.

The Industrial Energy Consumers of America (IECA) said the DOE study “confirms that excessive volumes of LNG exports to non-free-trade agreement countries is not in the public interest under the Natural Gas Act.”

The group, which represents 3,700 U.S. manufacturing facilities, said it is not opposed to LNG exports. “We are against excessive LNG exports which would result in U.S. prices being dictated by global demand like crude oil is today.”

IECA said the Supreme Court has defined “public interest” under the NGA as requiring “plentiful supplies … at reasonable prices.”

natural gas doe environmentalists lng exports — U.S. Henry Hub Prices Across the More Likely Range of U.S. LNG Exports in 2040 | *NERA Economic Consulting*

“The study’s most likely scenario assumes that LNG exports up to 30.7 Bcfd could increase prices 117% above today’s Henry Hub prices by 2040 and 44% above the [Energy Information Administration’s Annual Energy Outlook] 2018 price (which assumes only 14.5 Bcfd of LNG exports),” IECA said. “Such price hikes plainly threaten the plentiful supply of natural gas at reasonable prices for domestic consumers.”

Other Comments

The American Petroleum Institute said it agrees with the study’s conclusion of a “consistently positive relationship” between LNG exports and U.S. economic performance. “The study thereby confirms what multiple past studies have concluded, which is that U.S. LNG exports are a clear net benefit to the economy and are therefore in the public interest,” wrote Todd Snitchler, API’s director of market development.

The US LNG Association said the study should allow DOE “to grant approvals to all U.S. LNG export applications to non-FTA countries without the need for any further macroeconomic studies” for at least four years.

Environmental groups criticized the study for ignoring the costs of climate change and the growth of renewable energy.

“The study should be adjusted to give much greater emphasis to low demand scenarios that align with the Paris Climate Agreement,” said a coalition of more than 60 groups in the U.S., Canada and Europe, including Food & Water Watch, 350.org and the Center for Biological Diversity. “Even if minimal progress in international climate policy making was a robust assumption, the study fails to assess the real-world trends occurring with renewable energy and the threat they pose to gas demand. The study does not attempt to either account for substantial progress in renewable energy installations and cost reductions made in recent years or assess projections of substantial progress to come.” (See How Long a Bridge for Natural Gas?)

54 Scenarios

The DOE examined 54 scenarios based on four major sources of uncertainty affecting U.S. LNG exports: natural gas supply conditions in the U.S.; natural gas demand in the U.S.; and gas supply and demand in the rest of the world. None of the scenarios limited LNG export volumes.

It found a 68% probability that LNG exports will be between 9 and 30.7 Bcfd in 2040. DOE has approved 21.4 Bcfd of LNG exports to non-FTA countries. The DOE study said there is a 12% probability that exports will reach that level by 2030 and a 63% chance of hitting that level by 2040.

About 80% of the increase in LNG exports would be satisfied by increased U.S. natural gas production, “with positive effects on labor income, output and profits in the natural gas production sector,” the study said.

“The higher world prices that bring forth those supplies improve U.S. terms of trade, so that there is a wealth transfer to the U.S. from the rest of the world equal to the increase in prices received for LNG exports times the quantity exported. The transfers from natural gas related activity to the U.S. economy improve the average consumer’s ability to demand more goods and services leading to higher economic activity,” NERA said.

“These two factors more than make up for the dampening economic effects that are observed in these scenarios, including slightly slower output growth of some natural gas-intensive industries, costs of substituting other fuels for a small fraction of natural gas use in power generation, and infinitesimal reductions in natural gas use by households and other industries.

“Even the most extreme scenarios of high LNG exports that are outside the more likely probability range, which exhibit a combined probability of less than 3%, show higher overall economic performance in terms of GDP, household income and consumer welfare than lower export levels associated with the same domestic supply scenarios,” the study said. “It is also important to note that our analysis also shows that the chemicals subsectors that rely heavily on natural gas for energy and as a feedstock continue to exhibit robust growth even at higher LNG export levels and is only insignificantly slower than cases with lower LNG export levels.”

But IECA President Paul Cicio said the study “lacks credibility due to … the inability of the economic models to determine whether the oil and gas industry is consuming U.S. or imported goods to produce, transport and build LNG terminals, thereby overinflating economic growth and job projections due to LNG exports.”

IECA said the study’s conclusions conflict with that of a 2012 NERA study that acknowledged the difficulty of forecasting natural gas prices and that the new study uses proprietary NERA models that cannot be replicated by third parties.

Trump Administration Promoting Exports

The Trump administration has praised LNG exports as evidence of the nation’s “energy dominance.”

Last Thursday, Energy Secretary Rick Perry appeared at a ribbon cutting for Dominion Energy’s Cove Point LNG export facility in Maryland, the second in the U.S. Perry noted that the U.S. is exporting natural gas to 30 nations and last year became a net gas exporter for the first time in 60 years.

Also last week, DOE finalized rules to eliminate public interest reviews for “small-scale” LNG exports to non-FTA countries. The rules, effective Aug. 24, apply to applications to export no more than 51.75 Bcf/year.

July 31, 2018

FERC OKs DC Tie Operations Between Texas, Mexico

FERC last week granted AEP Energy Partners’ request to transmit power between ERCOT and Mexico over existing DC tie connections, easing concerns that the Texas grid operator might find itself subject to the federal agency’s jurisdiction (TX18-1).

The American Electric Power subsidiary made the request on behalf of Sharyland Utilities, AEP Texas and Electric Transmission Texas. The DC tie operators asked the commission to allow them to provide transmission service over the ties and to confirm that the ties’ use would not subject ERCOT or any of its market participants to FERC jurisdiction.

Texas officials have expressed unease that a pair of transmission projects along the U.S.-Mexico border could place ERCOT’s freedom from federal jurisdiction in jeopardy.

The ISO’s transmission grid is located solely within the state and not synchronously interconnected with the rest of the U.S. Under the Federal Power Act, FERC has no jurisdiction over transmission lines that cross international boundaries if they don’t also cross U.S. state lines. ERCOT has several synchronous (AC) and asynchronous (DC) ties with Mexico, but energy does not flow between Texas and other states through Mexico’s national grid.

ferc aep ercot mexico dc tie connections — | *Mexico Ministry of Energy*

Public Utility Commission Chair DeAnn Walker has said the federal agency could exert its jurisdiction over ERCOT through the U.S. Constitution’s Commerce Clause “if the commingling of power between ERCOT and the rest of the United States occurs.” (See Regulators Fear Cross-Border Tx Risks ERCOT’s FERC Exemption.)

Sharyland sister company Nogales Transmission has applied for a presidential permit to build an HVDC interconnection between Arizona and Mexico (OE PP-420). Nogales last year asked the Department of Energy to delay processing its permit until it can obtain “the necessary FERC disclaimer” of jurisdiction.

Further west, Mexico is considering a major project that would link the state of Baja California, which is part of the Western Electricity Coordinating Council, with the rest of the country’s grid and with California.

ERCOT said it was pleased with the FERC order. “[It] alleviates any current or future jurisdictional concerns resulting from new interconnection projects with Mexico and other neighboring states,” spokesperson Leslie Sopko told RTO Insider.

AEP asserted that if FERC granted the parties’ request, the DC ties would become facilities for the transmission and wholesale sales of electric energy in interstate commerce “solely by reason of” a commission order.

“The continuing operation of the ties in compliance with the requested Section 211 order would not cause the tie operators to become ‘public utilities’” as defined by the FPA, the utilities said.

Commission Eases 2006 Requirements on Westar Energy

The commission on July 27 granted Westar Energy’s request to remove mitigation measures and reporting requirements imposed in connection with its 2006 acquisition of a ONEOK Energy Services gas plant (EC06-48).

Westar asked FERC to remove the measures and quarterly and annual reporting requirements, saying that changes in the SPP market since the 2006 acquisition made the decade-old requirements no longer necessary. SPP went live in 2014 with its Integrated Marketplace, which included day-ahead, real-time and financial transmission rights markets, and a consolidated balancing authority that replaced 16 legacy BAs.

In approving Westar’s acquisition of ONEOK’s 300-MW Spring Creek facility and a 75-MW power purchase agreement from the Oklahoma Municipal Power Authority (OMPA), the commission ordered the utility to increase transfer capabilities into its BA to reduce its 42% share of the market.

Westar requested a clarification of the order, committing to not use 225 MW of network integration transmission service during the winter period. The commission granted the request, but OMPA in 2007 requested a rehearing. FERC asserted Westar had asked SPP to move Spring Creek from the Oklahoma Gas & Electric BA to Westar’s, undermining the mitigation alternative. FERC agreed, directing that Westar continue to model the facility in OG&E’s BA.

Westar filed its request in 2016, arguing that SPP’s consolidated BA meant its market share should be measured using the RTO’s entire capacity, rather than that of the utility’s former BA area. It also pointed out that the OMPA contract had expired in 2015.

SWEPCO ROE with East Texas Co-ops Reduced

FERC on July 26 approved a settlement agreement between Southwestern Electric Power Co. and two East Texas cooperatives, East Texas Electric (ETEC) and Northeast Texas Electric (ER18-1560).

The settlement reduces SWEPCO’s return on equity with ETEC from 11.1% to 10.1%, effective Sept. 1, 2017. It also revises the utility’s formula rate templates that govern its power supply agreements with the two co-ops.

— Tom Kleckner

July 31, 2018

PJM Ponders Advancing VOM Effort over Objections

By Rory Sweeney

VALLEY FORGE, Pa. — PJM’s effort to include variable operations and maintenance (VOM) costs in energy market cost-based offers appears to be on its way to FERC following a long-awaited vote to revise the current rules at last week’s meeting of the Markets and Reliability and Members committees.

Stakeholders rejected five proposals, including one of them twice, after which PJM’s Stu Bresler indicated the RTO might recommend its Board of Managers approve changes anyway. He said his starting point for the recommendation would be PJM’s proposal, which was twice rejected in its original form and also in a revised alternative motion.

Stakeholders said they would keep a close watch on what recommendation staff develop, and Brian Wilkie with Rockland Electric Co. (RECO) called Bresler’s plan “disappointing.”

PJM’s Melissa Pilong presented the issue and a comparison of the proposals. They had been put into a voting order based on how they came to be considered by the MRC. (See “VOM Update,” PJM Market Implementation Committee Briefs: July 11, 2018.)

The initial proposal was sponsored by American Electric Power and would allow use of default U.S. Energy Information Administration calculations for the amount of VOM costs allowed in offers. The proposal was rejected with a sector-weighted vote of 2.28 in favor and 2.72 opposed. Such sector-weighted votes have a threshold of 3.35 to be endorsed.

AEP’s Brock Ondayko had been promoting the proposal as preferable to a proposal from RECO because it used data that were independently developed and published.

“What we have proposed, and what was accepted earlier, is this concept of using data from an independent provider that has no agenda or opinion of PJM’s markets,” Ondayko said. “The point is there’s actual data. … Nothing is hidden from public view. … There’s no data with the potential defaults in the other package.”

PJM’s proposal remained unchanged from past discussions as the only one that would allow units to include fixed costs in their energy offers if they failed to clear in the year’s capacity auction. It was also rejected with 2.86 in favor and 2.14 opposed.

The Independent Market Monitor’s proposal would limit costs allowed in energy offers to “short-run marginal costs,” which would be defined. The proposal was rejected with 1.83 in favor and 3.17 opposed.

“This is about the prevention of market power,” Monitor Joe Bowring had said prior to the vote, noting that PJM’s manuals don’t clearly define several related components.

RECO’s proposal was meant to strike a compromise between generator-friendly and load-friendly proposals to ensure that stakeholders wouldn’t be stuck with the status quo if coalitions stood their ground and those proposals failed to win endorsement, Wilkie said. It would allow generators to recover VOM costs up to limits that would be posted into Manual 15. Almost all unit types would be capped at $3.50/MWh for the costs. Sub- and super-critical coal and biomass would be capped at $4/MWh; nuclear at $3/MWh; and wind, solar and hydro at $0/MWh.

“I agree. They’re not based on data,” Wilkie said in response to Ondayko’s comments. “They’re a compromise between the data the IMM thinks is reasonable and the data EIA thinks is reasonable.”

He said his customers would benefit most from the Monitor’s numbers, but he was particularly concerned with the appearance that generators were simply trying to increase revenues by moving the costs to the energy market as opposed to the capacity market, where they’re currently allowable.

“If it’s just and reasonable for these costs to be in the unit’s capacity offer, then it’s hard to understand how it can instead be just and reasonable for them to be in the energy offer. It can be one or the other, but toggling those costs back and forth based on where generators think there’s going to be the most money doesn’t seem like a sound market design principle,” Wilkie said.

market cost-based offers VOM PJM — Poulos | © *RTO Insider*

Greg Poulos, the executive director of the Consumer Advocates of the PJM States (CAPS), agreed with that perception.

“I would call that market shopping. … That’s a concern,” he said.

However, Exelon’s Jason Barker said many asset owners agreed RECO’s proposal “parrots” the Monitor’s proposal.

The proposal had a similar voting result with 1.97 in favor and 3.03 opposed.

Stakeholders next voted on an alternative proposed by Adrien Ford with Old Dominion Electric Cooperative. Ford had offered a friendly amendment to the PJM proposal to remove the language that allowed units to include fixed costs in their energy offers if they failed to clear in that year’s capacity auction so that the package aligned with the other three.

Staff wanted to “get a read” on favorability for the package that was originally endorsed at the Market Implementation Committee meeting, so they did not consider it friendly. Because it was the motion endorsed by the lower committee, a stakeholder had to object to the motion being friendly, so Citigroup Energy’s Barry Trayers did so.

Ford then offered it as an alternative motion, but it too was rejected, receiving 2.65 in favor and 2.35 opposed.

American Municipal Power’s Steve Lieberman motioned for a revote of the original PJM proposal, which was seconded by Trayers, but that was also rejected, receiving 2.93 in favor and 2.07 opposed.

Following the vote, Bresler informed stakeholders that PJM may not be satisfied with retaining the status quo and might consider making its own recommendation to the Board of Managers. He said he would “start” with PJM’s proposal as the basis for the recommendation.

Susan Bruce, representing the PJM Industrial Customer Coalition, promised “robust oversight” of staff’s development of the potential recommendation.

Wilkie called Bresler’s announcement “disappointing.”

Asked to opine on PJM’s rules for such situations, CEO Andy Ott said he felt the board being informed of stakeholders’ voting record on the issue would provide enough evidence of their preferences so that the board would be properly informed before considering staff’s recommendation.

At the Members Committee meeting that followed the MRC, stakeholders voted to adopt the MRC votes so that the board would be informed.

July 31, 2018

PJM MRC/MC Briefs: July 26, 2018

Seasonal Aggregation

VALLEY FORGE, Pa. — PJM stakeholders at last week’s meeting of the Markets and Reliability and Members committees unanimously endorsed proposed revisions for aggregating seasonal resources.

PJM’s Andrea Yeaton presented the revisions, which would allow for dispatching resources individually based on their seasonal ability but account for them cumulatively for the purposes of Capacity Performance. (See “Seasonal Aggregation,” PJM Market Implementation Committee Briefs: July 11, 2018.)

pjm mc mrc seasonal aggregation — Stakeholders at last week’s MRC and MC meetings considered various issues. | © *RTO Insider*

Independent Market Monitor Joe Bowring reiterated a request that the rules be amended to explicitly state that PJM has the authority and ability to call on resources without calling all resources in a zone and does not have to schedule the dispatch a day ahead.

“I think it’s less than clear” in the current language, Bowring said.

Default Details

PJM’s Suzanne Daugherty announced that the RTO submitted a request to FERC for waiver of rules requiring staff to liquidate “the large [financial transmission rights] portfolio of a recently defaulted PJM member.” The waiver would “reduce [PJM’s] liquidation of GreenHat’s portfolio to only the portion of the FTR portfolio that is about to become effective for the next calendar month, for each monthly auction for the period from the FTR auction conducted in July until the FTR auction conducted in October” (ER18-2068).

Staff had planned to liquidate the FTR positions in a way that minimizes the resulting burden on all other market participants, who will end up covering the remaining defaulted amount. (See “Credit and Default,” PJM MRC/MC Briefs: June 21, 2018.)

However, PJM said in its filing that it “has encountered adverse pricing effects of attempting to maximize the liquidation of this portfolio irrespective of price,” specifically in the most recent auction that closed on July 27.

“For periods with less liquidity … this large portfolio in combination with PJM’s obligation to offer a price designed to maximize the likelihood of liquidation, irrespective of a price floor, would essentially cause the prices to significantly diverge from the expected day-ahead price outcomes,” PJM said. “An unbounded liquidation of a large FTR portfolio for periods with less liquidity can and will cause a market disruption event and result in distorted market outcomes that may be unjust and unreasonable.”

The waiver “will provide PJM with time to further communicate with stakeholders regarding the concerns of the current Tariff-imposed liquidation process given the significant default allocations that will be incurred under the current liquidation process and to discuss any alternative liquidation process the PJM members may prefer be applied after the FTR auction conducted in October.”

Fuel Security

Because the MRC and MC ran late, a special MRC meeting scheduled to follow the meetings was postponed. A meeting of the now-sunset Transmission Replacement Process Senior Task Force was scheduled for July 31, so staff moved the fuel security session to that time slot. Staff plan to announce they have almost completed the base case for studying the impacts on the system from several fuel-security related contingencies, such as extreme cold weather or gas pipeline interruptions.

Manual Revisions Approved

Stakeholders endorsed by acclamation several manual revisions and other operational changes:

Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance (QA). Revisions developed to include or update technical specifications and procedures.
Manual 14A: New Services Requests Study Process and Manual 14G: Generation Interconnection Requests. PJM sought to split out part of Manual 14A into a new Manual 14G to better organize interconnection information. (See “Interconnection Procedure Split,” PJM PC/TEAC Briefs: June 7, 2018.)
Manual 11: Energy & Ancillary Services Market Operations. Revisions developed to address inconsistencies between PJM’s governing documents regarding price-based offers above $1,000. PJM plans to introduce additional system controls to improve validation of price-based offers by November. (See “Energy Market Caps,” PJM Market Implementation Committee Briefs: July 11, 2018.)
Revisions to the Reliability Assurance Agreement and Manual 18 associated with changes developed by the Demand Response Subcommittee to address issues identified with atypically low customer load during the winter peak load (WPL) calculation period. The Market Implementation Committee endorsed the changes in June. The proposal would use measurement and verification processes that already exist for a similar process and minimize administrative adjustments. It would define “low usage” days as less than 35% of the five-day WPL average and allow the exclusion of up to two such days from the WPL calculation. The measure was also endorsed at the MC via the consent agenda. (See “Now is the Winter of Our Discontent (with DR Rules),” PJM Market Implementation Committee Briefs: Sept. 13, 2017.)
Tariff revisions to implement a 10-cent/MWh minimum monthly credit requirement for FTR bids submitted in auctions and cleared positions held in FTR portfolios. Staff announced they will move the effective date up from October to Sept. 3. The measure was also endorsed at the MC via the consent agenda. (See “Credit Requirements,” PJM Market Implementation Committee Briefs: July 11, 2018.)
Problem statement and issue charge setting black start fuel requirements, which include pushing the anticipated start date for the stakeholder group back a month to December. Staff also added “critical non-fuel consumables” to the list of requirements to develop and minimum tank suction level to compensation-related issues to hash out. The measure was unanimously endorsed, but several stakeholders voiced concerns with adding another issue to the agenda when many have already expressed concerns about overscheduling. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: July 10, 2018.)

— Rory D. Sweeney

July 31, 2018

DC Circuit Denies Rehearing on Algonquin Pipeline

By Michael Kuser

A D.C. Circuit Court of Appeals panel on Friday declined to review FERC’s approval of plans to expand capacity on the Algonquin Gas Transmission natural gas pipeline.

The court also dismissed a petition from a group of elected Boston officials for lack of standing.

Circuit Judge Sri Srinivasan filed the opinion (Case No. 16-1081) for the three-member panel July 27, denying petitions from the Town of Dedham, Mass., Riverkeeper, and a coalition of other environmental groups that said the commission should have evaluated three separate Algonquin expansion projects in a single environmental impact statement.

The court noted that FERC approved the Algonquin Incremental Market (AIM) project in March 2015, that Algonquin submitted the application for the Atlantic Bridge project in October 2015 and that the company has yet to file its application for the Access Northeast project.

ferc rev d c circuit court of appeals natural gas — | *Algonquin Gas Transmission*

“The projects thus were not under simultaneous consideration by the agency,” and thus not improperly segmented, the court said. It also found FERC reasonably concluded that the projects were not interdependent, as they each had separate timelines for approval and commencing service.

The petitioners also contended that the commission failed to consider sufficiently the cumulative environmental impacts of the three projects. But the court said FERC took into account the AIM project’s EIS when evaluating Atlantic Bridge’s, and that Access Northeast is too early in development.

“The adequacy of an environmental impact statement is judged by reference to the information available to the agency at the time of review, such that the agency is expected to consider only those future impacts that are reasonably foreseeable,” the court said.

Indian Point Proximity

The $972 million AIM project includes about 5 miles of new pipeline, the West Roxbury Lateral, which would run adjacent to a quarry outside Boston, and larger-diameter replacement pipeline next to the Indian Point nuclear plant on the Hudson River in New York.

The petitioners questioned FERC’s reliance on testimony from the Nuclear Regulatory Commission and Indian Point owner Entergy that AIM — which will lay pipeline 2,370 feet from the plant’s security barrier — posed no increased threat to the nuclear plant.

“We disagree,” the court said, ruling that FERC had “permissibly decided to credit the NRC’s expert conclusions, and to accept that NRC’s ‘extensive formal responses’ had adequately addressed the opposing experts’ concerns.”

The court also said it lacked jurisdiction to consider petitioners’ contention that the third-party contractor preparing the project’s EIS, Natural Resource Group, had a conflict of interest, as they had not raised the issue with FERC.

Not Really Boston

Although the commission did not initially contest the Boston delegation’s standing, Algonquin raised the issue as an intervenor in the case, which led the court to address the issue. The delegation consisted of nine elected representatives from Boston, including the mayor, a congressman and two state legislators.

The delegation’s claim of injury for standing purposes rested on the West Roxbury Lateral’s allegedly adverse safety, health and environmental effects on the city. The delegation staked its standing primarily on the mayor’s participation in the petition, claiming that effectively made the city a party.

“We are unpersuaded by the delegation’s theory,” the court said. “While the city of Boston could in theory bring an action, the mayor does not act as the city when he files a lawsuit in his own name.

“The city code specifies the process by which a lawsuit is initiated on behalf of the city of Boston. … That process did not take place here.”

July 31, 2018

ERCOT Technical Advisory Committee Briefs: July 26, 2018

ERCOT stakeholders and staff last week discussed several alternatives to market price investigation announcements, following a July 20 market notice that raised anxiety levels during the height of the recent Texas heatwave.

The grid operator sent the market notice following discovery of inaccurate definitions of two double-circuit contingencies in its market systems. According to the notice, staff had begun “an investigation of market prices.”

The market’s shadow price at the time was $20/MWh, when it should have been around $24/MWh.

Reliant Energy’s Bill Barnes | *Admin Monitor*

“It happened at a very heightened time in the market. There was high anxiety when this was noticed,” Reliant Energy’s Bill Barnes said during the July 26 Technical Advisory Committee meeting. “I appreciate the market notice … but we were surprised to see how small the change in price was. Why the fire drill?”

Staff explained there is no threshold for issuing a market notice on price investigations and that they were only following protocols.

“There’s a tradeoff of me sending something out as soon as we’re investigating,” said Kenan Ogelman, ERCOT’s vice president of commercial operations. “If I try to understand what’s going on, there could be some delay.”

Citigroup Energy’s Eric Goff suggested staff could have sent an initial notice that a contingency had been found but that it wasn’t related to the market’s operating reserve demand curve.

ERCOT TAC price investigation — July’s ERCOT TAC meeting. | *Admin Monitor*

“[The notice] just said a price correction without the details,” Goff said. “That caused some uncertainty as we moved into high-priced periods.”

ERCOT sent the notice following the discovery of an error in the definition of two double-circuit contingencies east of Dallas. Only one of the contingencies was part of a binding transmission constraint that lasted only four hours.

The issue affected the July 18 real-time operating day and the July 20 day-ahead operating day.

ERCOT Technical Advisory Committee price investigation — | *ERCOT*

Corrected day-ahead prices were published on July 23. Staff will have to ask the Board of Directors for approval to resettle the real-time prices during its Aug. 7 meeting.

Staff said ERCOT is making “procedural changes” to ensure the error doesn’t happen again.

“I think there is a better answer out there,” Ogelman said. “We appreciate the conversation. We want to eliminate [that problem].”

TAC Endorses Long-Delayed Governing Amendments

The TAC unanimously endorsed proposed amendments to ERCOT’s articles of incorporation and bylaws, ending a monthslong series of delayed votes and redline exchanges.

“We’ve ended up with a very, very good work product,” said ERCOT Assistant General Counsel Vickie Leady.

The amendments include identifying the Public Utility Regulatory Act as the source for the board’s mandatory composition, and using Public Utility Commission rules to govern the distribution of assets and winding up provisions in the event ERCOT is decertified as an independent organization.

The amendments will be presented to the Human Resources and Governance Committee on Aug. 6, and then to the board Aug. 7. Staff plans to use an email vote to seek approval from its nearly 300 corporate members, and then file the amendments for the PUC’s approval in mid-September.

The ISO hopes to have the amendments in place by January.

Staff have created a website to store the different versions of the proposed changes. The amendments are the first updates since 2000.

New Leadership Confirmed to ROS

The committee confirmed new leadership for its Reliability and Operations Subcommittee.

Golden Spread Electric Cooperative’s Tom Burke will become chairman, replacing Oncor’s Alan Bern after he stepped down from the role in June. Tenaska’s Boon Staples will replace Burke as vice chair.

Committee Endorses 17 Revision Requests, Changes

The committee unanimously approved new language in a remanded Nodal Protocol revision request (NPRR) incorporating an intraday or same-day weighted average fuel price into the mitigated offer cap.

The TAC unanimously cleared NPRR847 in May, but the Board of Directors sent it back in June over concerns that the calculation of blended fuels was “vague and confusing.” (See “Board Approves 8 Change Requests,” ERCOT Board of Directors Briefs: June 12, 2018.)

Staff told stakeholders the original language did not define the calculation correctly, using the total fuel volume twice.

The NPRR is meant to ensure resources are capped at the appropriate cost during high fuel-price events and that LMPs reflect the true incremental cost of fuel.

The committee also unanimously approved 16 other changes, clearing a backlog produced by the cancellation of its June meeting: seven NPRRs, a revision to the Nodal Operating Guide (NOGRR), two changes to the Planning Guide (PGRRs), three revisions to the Retail Market Guide (RMGRRs), an update to the Resource Registration Glossary (RRGRR), a system change request (SCR) and a change to the Verifiable Cost Manual (VCMRR).

NPRR8 56: Clarifies that for day-ahead make-whole settlement purposes, the “offline but available for SCED deployment” status is considered an online status and will be considered an offline status after system implementation.
NPRR862: Incorporates a number of revisions addressing recent changes made by the PUC’s rulemaking related to reliability-must-run service (Project No. 46369).
NPRR866: Addresses two objectives related to mapping registered distributed generation and load resources to transmission loads in the network operations model by codifying the existing process for mapping a load resource or an aggregate load resource to its appropriate load point in the model; and by outlining how to map a registered DG facility to its appropriate load point in the model.
NPRR873: Outlines expectations for posting information pertaining to intra-hour wind power and load forecasts on the Market Information Systems public area. The NPRR also proposes two new definitions and acronyms for the intra-hour wind power and intra-hour load forecasts (IHWPF and IHLF, respectively).
NPRR874: Changes the net allocation to load settlement stability report by breaking out the load-allocated congestion revenue rights monthly revenue zonal amount from the other load-allocated charges, and by providing dollars per megawatt-hour by congestion management zone.
NPRR875: Adds clarifying language to sync the protocols with NPRR864, which modifies the reliability unit commitment engine to scale down commitment costs of fast-start resources with less than one-hour starts.
NPRR877: Allows for the use of actual metered interval data for initial settlement of an operating day for electric service identifiers that currently require BUSIDRRQ load profiles.
NOGRR174: Harmonizes the automatic voltage regulator and the power system stabilizer testing requirements with the recently approved NERC Standard MOD-026-1, Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions.
PGRR061: Includes locations for registered DG facilities in the annual load data request process.
PGRR062: Proposes new processes, communication and document sharing and storage requirements to be included in the new generation interconnection or change request application.
RMGRR152: Changes the cancellation method from the MarkeTrak cancel-with-approval process to the 814_08 cancel-request Electronic Data Interchange transaction.
RMGRR153: Removes references to Sharyland Utilities, which no longer operates as a distribution service provider in the retail market, and updates American Electric Power contact information.
RMGRR154: Removes references to the Lite Up Texas discount, which ended in August 2016.
RRGRR017: Supports NPRR866 by providing a process for mapping registered DG facilities to their appropriate load points in the network operations model.
SCR796: Modifies the Market Management System’s validation rules for bids and offers to exclude resource nodes within a private-use network site as valid settlement points for day-ahead market energy-only offers and bids, and for point-to-point obligation bids.
VCMRR022: Directs ERCOT to contract a coal index price with a fuel vendor and includes a methodology for calculating the quarterly fuel adder for coal-fired and lignite-fired resources based on that index.

— Tom Kleckner

July 31, 2018

NextEra to Close Duane Arnold Nuclear Plant

NextEra Energy Resources last week announced that it will close the 615-MW Duane Arnold Energy Center, Iowa’s only nuclear power plant, five years earlier than expected as a result of a buyout agreement with Alliant Energy.

Florida-based NextEra said that Alliant, the plant’s largest customer, will pay $110 million to NextEra in September 2020 to cover the last five years of their power purchase agreement. Alliant will instead buy 340 MW of power from four wind farms that NextEra plans spend $250 million to repower, part of a $650 million package of investments in Iowa renewables.

The deal is contingent upon Alliant getting approval from the Iowa Utilities Board to recover the buyout payment from ratepayers. Alliant said the deal will save its customers nearly $300 million over 21 years beginning in 2021.

NextEra Energy Duane Arnold Nuclear Plant — NextEra plans to close the Duane Arnold Energy Center in 2020. | *NextEra*

“Partially replacing energy from Duane Arnold with NextEra’s additional wind investments in Iowa will bring significant economic benefits to our customers,” Alliant CEO Patricia Kempling said in a statement.

NextEra said it expects to gradually reduce staff at the plant, which employs 500 now, over the next seven years as it decommissions it. It also said it is evaluating redevelopment opportunities for the plant site, including new solar energy, battery storage or natural gas facilities.

Duane Arnold is one of numerous nuclear power plants experiencing economic difficulties because of cheap natural gas and falling renewable generation costs. Bloomberg New Energy Finance Analyst Nicholas Steckler said in May that 24 of the 66 nuclear plants operating in the U.S. were either scheduled to close or wouldn’t make money through 2021.

— Peter Key

July 31, 2018November 30, 2023

FERC OKs GridLiance West Incentives, Questions ROE

By Robert Mullin

FERC last week granted GridLiance West incentive rate treatments for upgrades to a Nevada transmission line that connects to the CAISO grid, but it also ordered that the project’s overall 10.6% return on equity be subject to settlement judge procedures (ER18-1693).

The commission approved full recovery of GridLiance’s “prudently incurred” costs for its investment in upgrading the 14-mile, 230-kV Bob-Mead line if the project is abandoned for reasons outside the company’s control, as well as a 100% full “construction work in progress” incentive. FERC also granted the company a 50-basis-point “transco” adder made available to independent transmission developers.

GridLiance last year acquired Valley Electric Association’s 230-kV network in a deal valued at about $200 million, providing the company with 164 miles of transmission between CAISO and the interior West. (See GridLiance Gets OK to Acquire Valley Electric Tx Assets.)

The Six Cities group of Southern California public utilities protested inclusion of the adder, contending GridLiance had requested it just four months after reaching a settlement allowing for an overall 10.1% overall ROE, which included a 50-basis-point RTO participation adder.

Six Cities argued there was “overlapping justification” for the company’s prior request for a regulatory asset incentive (coupled with the RTO adder) and its current request for the transco adder because the latter “is designed to recognize the business model-related benefits provided by independent transmission companies,” similar to the rationale for the regulatory asset incentive already granted to GridLiance, the commission noted in its order.

But the commission rebuffed that contention, saying the functions of the transco adder and the regulatory asset incentive differ, and that it was “not persuaded that they rely upon overlapping justifications.”

“As an independent transco, GridLiance West satisfies the requirements for the transco adder. In contrast, the commission granted GridLiance West the regulatory asset incentive based upon a determination that GridLiance West had demonstrated that its request for that incentive satisfied the nexus test established in Order No. 679,” the commission said.

FERC also rejected as beyond the scope of the proceeding Six Cities’ request that GridLiance be ordered to disclose all authorized incentive adders in future transmission development proposals to CAISO because the adders could have a “material impact” on transmission projects in the ISO.

But while the commission favored GridLiance’s request for the adders, it also said its preliminary analysis indicated the overall 10.6% ROE for the Bob-Mead project might be too generous.

“Based on the record in this proceeding, the commission does not have a basis for determining whether GridLiance West’s overall ROE, inclusive of the transco adder granted above, falls within the zone of reasonableness,” FERC said in ordering settlement procedures.

July 31, 2018

MISO Informational Forum Briefs: July 24, 2018

MISO issued two maximum generation alerts and conservative operations declarations because of severe weather in June and a heatwave in July.

Both months were hotter than normal, and MISO recommended suspending transmission and generation maintenance in the North and Central portions of its Midwest region on July 5, when temperatures and loads were both above forecasts. The RTO said its system was stable throughout the event.

MISO spokesperson Mark Brown said staff coordinated closely with members and neighboring system operators during the event to manage generation and transmission resources. “MISO and our members train regularly and intensively to manage the power system in all types of conditions,” Brown told RTO Insider, adding that the alerts are meant to provide “situational awareness” to members.

The RTO also declared a hot weather alert for MISO South July 20-23 when the average temperature was 99 degrees Fahrenheit.

miso maximum generation alert severe weather — Rob Benbow | © *RTO Insider*

MISO Senior Director of Systemwide Operations Rob Benbow also said the system performed well during June despite above-normal temperatures and severe weather in the South region.

“We did see some hot weather alerts in the Central and North regions … at the middle to the end of the month, and we also experienced a transmission system emergency due to a forced outage in the South region in the early part of June, and that was followed by conservative ops and a max gen alert on the following day until that facility was returned to service,” Benbow said during a July 24 Informational Forum.

The day after severe weather on June 3, MISO declared a transmission system emergency in South with a maximum generation alert and conservative operations instructions. Benbow said the event caused real-time price spikes.

MISO’s June load peaked at 121 GW on June 29, up about 10 GW from last June’s peak. Average load was just under 77 GW, up 7 GW from a year earlier. Average real-time energy prices were $31.74/MWh, up 13%, which MISO attributed to localized congestion and higher demand.

MISO Reviewing Hartburg-Sabine Proposals

MISO has received multiple proposals for its second competitively bid transmission project, but it will not reveal the number of companies behind the proposals for at least another month — if at all.

The second request for proposals for the Hartburg-Sabine 500-kV junction project closed July 20, part of MISO’s 2017 Transmission Expansion Plan. The project will be in service by 2023 and is meant to alleviate system congestion in eastern Texas. The RTO opened the submittal window in early February.

However, MISO only identifies the number of proposals and their submitters once they’ve been judged and accepted as complete during an initial review expected to wrap up in early September, CEO John Bear said. The RTO will then post a list of finalists advancing to the evaluation process. Incomplete proposals are not revealed.

“MISO is pleased with the robust number of responses to the request for proposals,” Aubrey Johnson, executive director of competitive transmission, said in a statement. “This shows broad interest from qualified transmission developers and underscores the confidence in our competitive selection process. We look forward to moving to the next phase of the selection process to identify the best proposal for this important project.”

MISO plans to announce its selected developer for the project by Dec. 31. Bear said the project is expected to cost $129 million and have a benefit-to-cost ratio of 1.35:1. He added that it is the RTO’s first competitive project to include a substation.

— Amanda Durish Cook

July 31, 2018January 31, 2024

Overheard at Infocast’s SPP and MISO Markets Summit

KANSAS CITY — Infocast’s first SPP and MISO Markets Summit last week faced tough competition at its hotel, which was also hosting the U.S. women’s national soccer team, the Detroit Tigers, Journey and Def Leppard.

Still, the July 24-26 conference attracted participants and industry representatives from the RTOs’ footprints for panel discussions on resource mix, gas builds for reliability, competitive wind pricing, unlocking solar energy’s potential, demand response and energy efficiency initiatives, and the future of the Western grid.

Much of the focus was on the RTOs’ interconnection queues, which have ballooned in recent years as renewable developers chase expiring federal tax credits.

Renewable projects account for 78 GW of the almost 90 GW in MISO’s queue, and about 74 GW of the 77 GW in SPP’s queue. Neither RTO has a coal project on the books.

MISO and SPP are used to the growth of wind power, which supplies about 17-18 GW of energy for both RTOs. But the explosion of solar and battery projects (36 GW in MISO, 20 GW in SPP) has come as a surprise.

Vikram Godbole, MISO’s director of resource utilization, said solar projects now outnumber wind projects in a queue with an “historic” amount of generation. He said the generation is almost 7 GW higher than the “most extreme” staff forecasts of a year ago.

“I never thought that would happen,” Godbole said. “At what point does it end, I don’t know. We’ll continue to see a rise in solar the next few years, especially as the projects with wind [production tax credits] drop out.”

“The reason you’re seeing solar is because of the tax credits,” said Ameren’s Jeff Dodd. “That’s not a shock.”

“It’s mind-boggling when you look at it,” said Steve Purdy, SPP’s manager of generator interconnection. He compared the queue with the RTO’s summer peak load of 50 GW, saying, “You can see the challenge we have in squeezing that enormous amount of generation into a relatively small amount of load.

“That’s led to areas where we don’t have enough load to absorb all the requests,” Purdy said. “We’ve resorted to creative engineering and engaged our stakeholder group to help with those challenges, both in technical issues and the process issues.”

SPP stakeholders in April approved an overhaul of the generator interconnection process, leading to a simpler three-stage process that mimics MISO’s. (See “Members Approve Three-Stage Process for GI Requests,” SPP Markets and Operations Policy Committee Briefs.)

The grid operators say they hope recent changes to the GI process will help them work through the backlog of requests and weed out developers trying to manipulate the process. Godbole said MISO is just now processing 2016 February and August cycles.

“A lot of GI customers are getting anxious about being able to start construction on time,” Godbole said. “They need some idea of whether they’ll get a [GI agreement] before the summer of 2019.”

“It’s going to be very difficult for anything in the 2017 cycle to get a GIA in time, just based on the cycles,” Dodd said.

The simpler, three-stage study processes include heftier security deposits at each stage. That helps ensure only the most serious developers are involved, as studies have to be redone when a project is withdrawn.

“The interconnection process is becoming the long-delaying issue in the development cycle. We have to put more thought into how we enter these queues as a customer,” said Tradewind Energy’s Derek Sunderman. “We’re trying to stay ahead of those changes so that we can continue to have a pipeline of projects. Security deposits … have become the No. 1 driver on the budget side of this business.”

Sunderman said the changes seem to indicate the three-stage study process “is moving forward.” He said a Tradewind analysis of MISO’s recent study results showed fewer customers dropped out at the later stages, an indication of the more favorable results they were getting for their projects.

“That tells us the interconnection customers are becoming very educated,” Sunderman said. “The problem is the study length. It’s just not working as fast as we would like.”

Western Grid Hears the Markets Call

David Kelley, director of seams and market design for SPP, said improved renewable technology is not only evident within RTOs, but in the efforts to create markets and new services in the Western Interconnection.

“Many of the states and utilities are looking at integrating more renewables,” he said during a panel on Western grid regionalization. “RTOs and markets are very capable of providing the type of environment and economies of scale that facilitate that type of development. It’s hard to argue against how broader regions plan the system than individual companies doing it on their own.”

Kelley noted SPP had 3 GW of wind energy on its system in 2008. “Now, it’s 17 gigs,” he said. “Our robust transmission planning system helped do that.”

“The biggest hurdle of getting renewables to the market is the tariff’s ways [through pancaked rates] it takes to get the power to a load-serving entity,” said Swaraj Jammalamadaka, a former MISO staffer, now director of transmission for Apex Clean Energy. “MISO, SPP, PJM … they are definitely a benefit for integrating low-cost generation in the system.”

Markets also provide transparency into price, costs and benefits, said Kelley and Pat McGarry, managing director of The Energy Authority.

“The transparency is real in RTO markets,” McGarry said. “It can cause issues, because now, everybody can see what the prices are. If you self-commit a generating unit when the prices are low, it’s, ‘Why are you running?’”

“For us, the biggest struggle is the market no longer depends upon fixed [power purchase agreements],” Jammalamadaka said. “A significant enabler in markets like SPP’s is people are able to sell their power through very intelligent financial instruments. They can only be made available if you have a liquid market.”

SPP is among those attempting to offer market services in the West, having been working to integrate the Mountain West Transmission Group, a collection of eight Rocky Mountain-area entities, since January 2017. That deal has been on life-support since Xcel Energy, which accounts for 40-50% of Mountain West load, announced in April it was withdrawing from the group. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

“That certainly changes things from the cost-benefit perspective,” Kelley said. “[The remaining entities] are in a very deliberate process of calculating the benefits and costs of participating in SPP. We expect that process to take place over the next few weeks before they make a final decision.”

Grappling with Adding Value to Coal Resources

Without new coal-fired generation in their futures and with increasingly large amounts of renewable energy disrupting their fuel mix, how are SPP and MISO to incent new coal resources?

Casey Cathey, SPP’s manager of operations engineering analysis and support, said while the RTO is fuel agnostic, it does value flexibility. To ensure coal resources are valued, he said the grid operator is evaluating two products that may provide benefits for their generation: a multi-day economic commitment and a de-commitment enhancement.

“Coal unit parameters are too expensive for the day-ahead engine to pick up. It can cost $200,000 to start, so maybe we can disperse that cost over a period greater than 24 hours,” Cathey said. “A multiday economic commitment would be better able to assess coal and compensate it, instead of having to self-commit.”

He said a de-commitment enhancement isn’t as easy as it sounds, with day-ahead positions and financial obligations that must be accounted for.

“It will help coal in two ways. It will help to further optimize commitments instead of coal having to self-commit; it will help … maximize its revenue in the de-commitment process,” Cathey said of an action that’s up to the market participant. “It’s basically placing that decision in the hands of the RTO, which theoretically should make a little more money [for coal resources], through optimal cycling. If other resources completely de-commit, it could potentially inflate prices for those resources that stick around.”

“The real question may be how we incent the right resource characteristics,” said Laura Rauch, MISO director of resource adequacy coordination. “We commonly think of coal as the resource we know and love because of these attributes, but as Casey said, it’s about making sure we have the market signals to go and motivate people to build resources with the right characteristic. We have to have the forward projections with the states and load entities, so that we’re not just reacting, but that we’re getting the generation built to replace some of these retired units with the transmission to support it, and with the general attributes we need to keep the system reliable.”

Lincoln Electric System’s Dennis Florom, whose company owns interests in several coal plants, said there’s still a place for new coal generation, although “it’s going to be a tall order.”

“We need to look at new ways to clean it; we need to look at ways to change public perception. It’s not a resource people want to build,” he said. “As we bring in new resources such as storage, it’s actually going to have an interesting play. You’re going to see those storage resources placed in areas of high congestion … where prices are typically high. As you bring in resources that will eliminate congestion, you’re going to see a flattening of prices.

“That makes me wonder if, out in the distance, somewhere, maybe the next 10 years, we see prices flatten,” Florom said. “People will recognize that resources with higher fixed costs, but low variable costs, will be able to take advantage of those flattening prices.”

Gas Generation No Ordinary Bridge Fuel

Appearing on a panel discussing gas-fired generation’s role in grid resilience and reliability, Vectren Director of Regulatory Policy and MISO Affairs Justin Joiner asserted that gas is not a bridge fuel but, rather, “a highway.”

“[Gas units are] foundational to the adoption and use of the latest technological advances to meet load needs,” he said. “Gas is cost effective, flexible, reliable, resilient and fast ramping. Additionally, resiliency is a regional matter. How one meets its load needs in a resilient manner is a system-by-system consideration, unique to each LSE.

“If you look at the MISO queue and the amount of baseload retirements [20 GW recently, 12-20 GW forthcoming], there is a need for fast-ramping, dispatchable generation. Gas will meet that need,” Joiner said.

Scott Wright, MISO’s executive director of strategy, agreed with the critical role gas-fired generation can play. He pointed to the 10 GW of gas projects in the ISO’s queue, noting most will be used to address continued retirements of legacy resources.

“Due to its reliability and flexibility attributes, gas-fired generation will support future change,” Wright said. “Preliminary studies from our planning scenarios indicate that we’ll be calling on a comparable amount of total gas capacity in the future to provide ramping that is at least two to two-and-a-half times the amount of today’s gas ramping. This means we’ll need more capability, not less, from gas-fired generation, despite and related to the large growth expected in renewable resources.”

Natasha Henderson, who manages regulatory and market affairs for West Texas-based Golden Spread Electric Cooperative, said all generation types will continue to contribute to resilience. But given quick-start gas units’ ability to cover sudden drops in renewable energy, she said gas-fired generation should be compensated accordingly.

“At this juncture, gas generation is the most critical type of generation to meet reliability and resiliency needs, and flexible gas generation will become increasingly important as we see more and more renewables added to the system,” Henderson said. “As technology advances and the resource mix continues to change, wholesale market structures will need to not only react but proactively adjust. It’s critical that we both define the attributes of reliability and resiliency and ensure that markets properly compensate these attributes to incent the correct future generation mix.”

MISO, SPP Improving the Interregional Process

Cathey also engaged Jeremiah Doner, MISO’s director of seams coordination and membership services, in a friendly discussion over improvements to the interregional planning process and January’s “Big Chill.”

Having failed to agree on a single interregional project so far, the two grid operators are working to reduce hurdles, such as building a joint model and eliminating the $5 million threshold to qualify as an interregional project. To save time, SPP and MISO will now study potential projects within their own regional models. They have also added new benefit metrics, such as the avoided cost of other projects. (See MISO, SPP Loosen Interregional Project Requirements.)

“It doesn’t take an engineering power flow model to determine projects need to be built. We have artificial human barriers … because of the model build and barriers like the $5 million threshold,” Cathey said. “There’s no reason we shouldn’t build a $4 million project if it leads to benefits. SPP stakeholders are getting a little bit tired of talking about interregional projects. We should be building transmission across the seam.

“But give MISO kudos as well. They recognize the same thing,” Cathey said.

“We’re both on board and at the table working on these problems,” Doner said.

The two also talked about the Jan. 17 severe weather event, when generation shortfalls in MISO South led to heavy north-south transfers across SPP’s system and a maximum generation alert in the region.

Cathey, a Louisiana native, noted temperatures in his home state were 30 degrees Fahrenheit lower than they should have been. Older generating units, without proper cold-weather packaging, tripped offline, costing MISO 5 GW of capacity.

“It was a challenging day,” he said. “There are a number of things that could have been done differently that day. We could have been a little more proactive. We’re discussing with [MISO and neighboring Southern Co. and the Tennessee Valley Authority] how we can learn from it and better forecast these issues.

“We practice load shedding, but we don’t practice emergency purchases, which prevents load shedding. We’re working on that with the neighboring reliability coordinators. That alone would have helped MISO,” Cathey said.

“That’s a very accurate description of what happened that day,” Doner said. “It’s important to remember we kept the lights on. MISO is very appreciative of the emergency energy we had to purchase on that morning. We’re in this together to keep the lights on. We should support each other, and we did that day.”

Wind Developers Argue for Level Playing Field

A pair of wind developers said that while technological improvements continue to improve wind energy’s competitiveness, the loss of the PTC threatens to tilt what they say is now a level playing field.

“Yes, wind energy has evolved to where it’s cost competitive,” EDP Renewables’ Rorik Peterson said when asked what harm the PTCs’ expiration would cause. “But there’s no form of electric generation that doesn’t receive some sort of federal support. If the PTCs expire, that leaves wind without any form of support. As to fairness in the marketplace aspect, I take exception to that.”

“On a level playing ground, we compete quite well,” said Apex’s Mark Mauersberger. “Having us be the only generation that doesn’t benefit from a subsidy is unfair.”

Peterson said solar energy’s increasing competitiveness, as evidenced by its growing presence in the MISO and SPP interconnection queues, “will certainly change the landscape.”

“I would expect with the phaseout of the PTCs and the loss of their full value after 2020, the tariffs on solar panels rolling off, that solar will consume a greater share of the renewables market,” he said. “I would expect to see a decline of consumption of wind after 2020, but I still expect to see wind be a viable component of the generation mix going forward.”

If so, then technology will continue to play a key role.

“One of the largest cost components of the wind project is the turbine,” said Mauersberger, whose company’s Dakota Range Wind project in South Dakota will use 72 turbines to generate 300 MW of energy. “Using [fewer] turbines shrinks the footprint, reducing the cost of cabling, roads and other civil costs. That trickles down to really reasonable pricing. We’re seeing pricing down south [in Texas and Oklahoma] in the $15/MWh range. I think that’s where we’re headed pretty quickly.”

— Tom Kleckner