Page 1274 – RTO Insider

July 17, 2017January 15, 2024

Divide Evident Between SPP Tx Owners, Users

By Tom Kleckner

DENVER — The divisions between SPP’s transmission owners and their customers could not have been starker than they were during the Markets and Operations Policy Committee meeting last week.

Twice, load-serving transmission owners overwhelmingly endorsed voting items favorable to their customers and companies. One was a revision to SPP’s transmission zone placement process. The second was a motion to reject staff’s recommended scope for a high-priority study that didn’t address their concerns with the RTO’s transmission planning process, which they say hasn’t resolved systematic congestion on certain parts of the system.

Both times, the larger number of transmission-using members — 77 of the committee’s 95 voting members — resulted in the TOs coming up on the short end after hours of back-and-forth comments.

“We had a good discussion. I’ll leave it at that,” MOPC Chair Paul Malone, of the Nebraska Public Power District, told the Strategic Planning Committee during its post-MOPC meeting Thursday.

Transmission Planning Process

Large load-serving entities complain that they are footing most of the bill for transmission expansions that also benefit transmission developers, wind developers and small municipal utilities and cooperatives.

Several members questioned the need for the high-priority study of congestion in the Texas Panhandle and western Oklahoma, pointing to recent changes to SPP’s transmission planning process. Staff have streamlined the number of assessments into a single 10-year study that will produce an annual expansion plan addressing reliability, economic and policy needs. The process’s first results will be shared in October 2019. (See “SPC, MOPC Approve Improvements to SPP’s Tx Planning Process,” SPP Strategic Planning Committee Briefs.)

A frustrated Greg McAuley of Oklahoma Gas & Electric told the MOPC that while the TOs weren’t in lockstep, they all want to protect customers from additional costs.

“What you see are those that have companies that have to pay for these things are being outvoted. That’s a concern this organization needs to reconsider,” McAuley said. “Our customers have just paid for [transmission planning process] improvements. What I’m hearing today is we’re asking [our customers] to pay another million dollars for another ad hoc study, because our process does not work.”

Transmission Zonal Placement

Kansas City Power & Light’s Denise Buffington, who shepherded the zonal-placement revision request (RR172), tried to take the MOPC’s rejection of her proposal in stride. While waiting for a runner to bring her a microphone during the SPC’s discussion of the proposal, she asked wryly, “Can I just scream?”

Buffington urged board members in attendance to consider adding additional municipalities and cities as members besides the large membership expansions, such as the Integrated System and Mountain West Transmission Group.

“Obviously, the votes that happened at MOPC show those that are paying the bills have less of a vote than those that aren’t paying the bills,” she said. “I encourage you to consider in your strategic-analysis plan all types of membership expansion that affects the pool and members.”

The load-serving TOs approved Buffington’s revision request by a 15-3 margin, with the Basin Electric and Western Farmers cooperatives joining Grand River Dam Authority in opposing it. However, the transmission-using owners voted down the motion 30-12, with seven abstentions, leaving the proposal 11 percentage points short of the necessary 66% approval.

“I just want to put everyone on notice that we will be appealing to the board,” Buffington said immediately after the vote. The Board of Directors and Members Committee meets July 25 in Denver.

“Shocker!” responded Heather Starnes, legal counsel for the Missouri Joint Municipal Electric Utility Commission and a nay vote.

Buffington has been working on RR172 for two and a half years to address what she says is a gap in the SPP Tariff.

Staff currently determine which of 18 transmission pricing zones to place new TOs in, which can result in cost shifts for those in the incumbent zone. (See SPP Advances KCP&L Cost Shift Proposal.)

The revision request was modified after “robust” stakeholder debate at the SPC and Regional Tariff Working Group, Buffington said. She said the modified RR172 is a “middle ground” and improves transparency in the new member zonal placement decisions by providing advance notice to TOs and their customers, allowing potentially affected entities to provide feedback before SPP makes a decision.

Buffington said RR172 also mitigates costs of zonal-placement decisions and protects both existing and new customers from cost shifts.

“This RR is primarily focused on the cost-shift issue … when SPP creates or expands multi-owner zones,” Buffington said. “KCPL has tried to come up with compromise but hasn’t been able to gain consensus. The alternative is litigation. To me, that’s a lot of risk on both parties.”

Some of those opposing the measure said there wasn’t enough time to study the revisions to the proposal. Others questioned whether the MOPC should be voting on a Tariff change without any working group’s approval. Some cited the “radical new policies” network customers would face in becoming TOs and fears of encroaching on FERC’s rate-setting authority.

“Does this group, as a Markets and Operations Policy Committee, really want to pass a Tariff revision when FERC should be the decision-maker? Rates are in the FERC purview,” said South Central MCN’s Brett Hooton. “We’ve had a lot of long SPC meetings on this topic. I don’t know that rehashing all that is going to change anyone’s opinion today.”

Starnes agreed with Hooton.

“We’ve beaten this horse until it’s bloody and no one recognizes it anymore,” she said, calling for the vote.

July 14, 2017

FERC Staff OK MISO Interconnection Queue Refund Plan

By Amanda Durish Cook

FERC staff have approved a MISO proposal to allow generators to withdraw from the RTO’s interconnection queue penalty-free after undergoing a three-stage evaluation process.

MISO FERC Interconnection Queue — | © *RTO Insider*

The commission’s Office of Energy Market Regulation on Wednesday accepted MISO’s plan in a three-page order containing little comment (ER17-156-003).

In approving MISO’s new interconnection queue rules in January, FERC required the RTO to devise a method to allow refunds of milestone payments if “significant” change affects cumulative network upgrade costs while a project is in the interconnection queue’s definitive planning phase (DPP) — the final phase of the queue before generation interconnection agreements are finalized. The commission also told MISO to define the degree of change needed to trigger a penalty-free exit. (See FERC Accepts MISO’s 2nd Try on Queue Reform.)

Under the new rules, MISO will evaluate cost increases across all three stages of the DPP and assign different thresholds to activate refunds depending on the stage of the project. Refunds will be triggered if:

From the first stage of the DPP to the second, network upgrade costs increase by at least 25% — and a minimum of $10,000/MW — between the publication of the preliminary and revised system impact studies. For upgrades on transmission systems outside of MISO, a 30% cost increase is required.
From the second to third stage, upgrade costs increase by at least 35% — and more than $15,000/MW — between the revised SIS to any phase three studies. For outside transmission system upgrades, a 40% increase is needed.
From the first to the third stage, upgrade costs increase by a cumulative 50% — and at least $20,000/MW — from the preliminary SIS to any phase three studies. Outside transmission system upgrades require a 55% increase.

While acknowledging that the three-step approach was “admittedly more complicated than other solutions,” MISO said it believed the proposal “best balances key interests for both interconnection customers and MISO.”

The gradually increasing thresholds and floors “encourage projects to withdraw earlier in the queue process at a point where restudy is already incorporated in the process and discourages queue gaming,” the RTO said, reducing the need for cascading restudies — a point FERC also asked MISO to address in accepting the new queue rules.

July 14, 2017

California Zero-Carbon Power Bill Advances

By Jason Fordney

SACRAMENTO, Calif. — A California State Senate bill that would require utilities to obtain 100% of their electricity from zero-carbon sources by the end of 2045 advanced through a key committee in the legislature’s lower house on Wednesday.

The Assembly Utilities and Energy Committee voted 10-4 along party lines to pass SB-100, which the Senate passed on a 25-13 vote in May.

zero-carbon power bill california — | *California Assembly Staff*

The bill retains qualifying resources such as wind, solar, geothermal and others currently under the state’s renewable portfolio standard for the first 60% of the requirement, a threshold power sellers must meet by 2030. It does not specify what resources will qualify for the additional 40% target after 2030, except that they be zero carbon. This would keep hydroelectric plants larger than 30 MW in the mix.

Natural gas-fired generation currently accounts for about 36% of California’s electricity mix, followed by renewables (25%), large hydro (10%) and nuclear (9%), according to state data. Imports of coal-fired power still make up about 4% of sales.

While many building trade, renewable energy and public interest groups spoke in favor of the bill at a July 12 hearing at the state capitol, utility representatives complained that their companies will be responsible for dealing with the challenges of implementation.

“None of those stakeholders have all that much skin in the game to how this all actually works,” Southern California Edison lobbyist Ryan Pierini said, adding that utilities are held responsible if blackouts occur. The utility doesn’t oppose the goal but has concerns about the methods of getting there, he said.

A Sacramento Municipal Utilities District representative said the utility does not have a position on the bill, but that transmission constraints will make it difficult to attain. The utility hopes to be granted some “flexibility” in reaching the goal because there are worries over grid reliability and costs.

During the hearing, committee Chairman Chris Holden (D) and Vice Chair Jim Patterson (R) debated the number of jobs and companies leaving California, which Patterson said is losing economic development because of energy costs.

Patterson said that the legislature had not considered the impact on ratepayers struggling with high electricity bills and facing utility cut-offs.

“We are … going full-blown into an area in which we have no definitive information about the costs,” Patterson said.

Holden told Patterson that “we have different perspectives on this issue.”

The bill also requires the California Energy Commission and California Air Resources Board to incorporate the policy into all relevant policies and programs. If passed, the law will oblige those agencies and CAISO to provide legislators with an implementation report every two years beginning Feb. 1, 2019.

July 13, 2017

California Democrats Move to Extend Cap-and-Trade

By Jason Fordney

California Gov. Jerry Brown and Democratic lawmakers on Monday unveiled a legislative package intended to combat air pollution, including a measure to extend the state’s greenhouse gas (GHG) cap-and-trade program by another 10 years.

california cap-and-trade — Brown | *State of California*

The proposed legislation modifies and renews the cap-and-trade program, which is due to expire in 2020. The state’s Supreme Court recently declined to review a court challenge against the initiative launched by business groups. (See California High Court Upholds Cap-and-Trade.)

The measures are included in amendments to two bills: AB-617, introduced by State Assemblymembers Cristina Garcia, Eduardo Garcia and Miguel Santiago, and AB-3 98, sponsored by Eduardo Garcia. It is not clear when a vote might be taken, but Brown’s office has indicated he wants to move quickly.

The program mandates that large industrial facilities such as oil refineries upgrade emissions equipment by December 2023, and it increases penalties for pollution. It also requires pollution reductions from mobile and stationary sources, and provides for neighborhood air monitoring — an attempt to placate environmental justice groups seeking to improve conditions in low-income areas.

The cap-and-trade program will help the state meet its goal of reducing GHG emissions to 40% below 1990 levels by 2030, Brown’s office said in a statement.

The new package is “the product of weeks of discussions between the administration and legislative leaders with Republican and Democratic legislators, environmental justice advocates, environmental groups, utilities, industry and labor representatives, economists, agricultural and business organizations, faith leaders and local government officials,” the statement said.

The measure “extends the program by 10 years in the most cost-effective way possible,” according to Brown. It will ensure that carbon pollution will decrease as the emissions cap declines and reduces use of out-of-state carbon offsets, while decreasing free carbon allowances by more than 40% by 2030, he said.

Under the cap-and-trade program, large emitters of greenhouse gases must purchase emissions credits at the California Air Resource Board’s quarterly auctions to cover emissions not accounted for with free credits. Extending the program would keep auction proceeds flowing to environmental initiatives around the state, the governor’s office said.

“To date, these investments have preserved and restored tens of thousands of acres of open space, helped plant thousands of new trees, funded 30,000 energy-efficiency improvements in homes, expanded affordable housing, boosted public transit and helped over 100,000 Californians purchase zero-emission vehicles,” the office said.

Brown said he will continue to pursue climate change policies despite President Trump’s pledge to withdraw from the Paris Agreement on climate change, which Trump says is unfair to the U.S. Brown recently announced that California will host global leaders in September 2018 for a Global Climate Action Summit to support the agreement.

Brown on Wednesday also announced the “America’s Pledge” program with businessman and former New York Mayor Michael Bloomberg. The governor’s office described the program as “a new initiative to compile and quantify the actions of states, cities and businesses in the United States to drive down their greenhouse gas emissions consistent with the goals of the Paris Agreement.” The initiative will produce a report on aggregate climate change commitments by states, cities, business and educational institutions, and a “roadmap for future climate change ambition.”

July 13, 2017

NY, Ill. Cite Allco Ruling in Defense of ZECs

By Michael Kuser

Illinois and New York state officials filed briefs this week saying a recent appellate court decision upholding two Connecticut renewable energy programs vindicates their zero-emission credits for nuclear plants.

A coalition of generation owners opposing the nuclear subsidies countered that the 2nd U.S. Circuit Court of Appeals’ June 28 ruling rejecting Allco Finance’s challenge to a Connecticut renewable energy credit (REC) program and renewable portfolio standard did not support the legality of the ZECs (Allco v. Klee, 16-2946, 16-2949). (See Second Circuit Upholds Conn. Renewable Procurement Law.)

zero-emission credits zecs allco — The New York State Supreme Court courthouse at 60 Centre Street (left) and the Thurgood Marshall United States Courthouse at 40 Centre Street (right) on Foley Square. On the right a bit of the Municipal Building can be seen.

The generation owners sued New York in December 2016 and Illinois in February 2017, arguing that the ZECs intrude on FERC’s jurisdiction over wholesale electric markets. In both complaints, the generators cited the Supreme Court’s 2016 decision in Hughes v. Talen, which found Maryland’s attempt to subsidize construction of a natural gas-fired generator encroached on FERC’s authority under the Federal Power Act. (See Federal Suit Challenges NY Nuclear Subsidies and IPPs File Challenge to Illinois Nuclear Subsidies.)

The Illinois ZEC case (17-cv-1163, 17-cv-1164) is being heard by Judge Manish S. Shah of the U.S. District Court for the Northern District of Illinois, Eastern Division, and the New York ZEC case (1:16-CV-8164) is being heard by Judge Valerie Caproni of the U.S. District Court for the Southern District of New York.

All the nuclear plants expected to receive the ZECs in the two states are owned by Exelon.

Injunction Sought

The generators sought an injunction on the ZEC program in Illinois, which Shah declined to rule on, preferring instead to consider first the defendants’ motion to dismiss. He heard oral arguments on May 22.

Attorneys for Illinois noted that the court approved the Connecticut RPS “even though the program differs from the Illinois ZEC program by authorizing the state’s agencies to direct utilities to enter into contracts with renewable power generators for the purchase of electric power and capacity, not just the environmental attributes of renewable power.”

In their July 10 brief, attorneys for the New York Public Service Commission said the Allco ruling “is the first appellate decision construing Hughes, and confirms that the decision is ‘limited’ and establishes a ‘bright line’ proscribing only state-sponsored payments for electric sales into wholesale energy auctions.”

The PSC said the New York ZECs are “even further removed from Hughes than Allco.”

“New York has neither ‘“command[ed] generators to sell capacity” into the FERC-approved interstate auction,’ nor premised the receipt of ZEC revenues on selling into and clearing the wholesale auction, and the ZEC program ‘thus lack[s] the “fatal defect” that triggered Hughes pre-emption,’” the PSC said.

“Compared to the Allco power purchases, the ZEC program is more clearly on the state side of the jurisdictional line, as it involves the purchase and sale of environmental attributes separate, i.e., ‘unbundled,’ from any electricity sale. [FERC] has already held — in the REC context — that such sales do not directly affect wholesale energy transactions.”

As in Allco, the PSC continued, the state’s program is not pre-empted by the Federal Power Act because FERC retains the ability to review any bilateral contracts that arise out of the program or — if the nuclear power sells in NYISO auctions — can regulate the terms of market participation and resulting clearing prices.

Caproni heard oral arguments on New York’s motion to dismiss on March 29 and is expected to rule soon.

Plaintiffs’ Response

The plaintiffs contend that the Connecticut program survived the court challenge because the state’s solicitation “did not require forced purchases, but rather allowed [load-serving entities] discretion to accept or reject bids. LSEs have no right to decline to enter into ZEC purchase contracts” under the New York and Illinois programs, the plaintiffs said.

In Illinois, the generator coalition’s July 10 brief alleged, “Exelon’s nuclear plants will receive ZECs only to the extent they produce electricity and that all electricity they produce must be sold in the FERC-regulated PJM or MISO wholesale auction markets. Moreover, the ZEC price is directly tethered to those market prices and is necessarily payable only for electricity that clears the auctions.”

Commerce Clause

The generators claimed that ZECs going only to in-state nuclear plants violates the dormant Commerce Clause’s prohibition on geographic discrimination.

The 2nd Circuit ruled in Allco that it was not discriminatory for Connecticut to recognize renewable energy credits only from generators that could deliver energy into the New England grid, finding the distinction compatible with the state’s legitimate aim of ensuring a reliable power supply. The state discriminates “only insofar as it piggybacks on top of geographic lines drawn by ISO-NE and the [New England Power Pool], both of which are supervised by FERC — not the state of Connecticut,” the court said.

The generators’ Illinois brief argued that “Connecticut’s program did not require utilities to purchase RECs at all; it simply permitted LSEs to use RECs to meet their renewable energy portfolio requirements, which they otherwise had to satisfy by generating renewable energy themselves.”

In contrast, “the Illinois ZEC program affords no such flexibility in responding to market conditions, because it requires LSEs to purchase ZECs from specified in-state nuclear plants,” the generators said.

The New York PSC addressed this point, saying that “if an out-of-state nuclear plant were to provide electric energy to New York and later suffer financial difficulty jeopardizing its ability to continue providing its zero-emission attributes, the plant could seek ZECs in future tranches. Thus, there is no geographic discrimination.”

Hughes ‘Key’ to NY Case

Ari Peskoe, senior fellow in electricity law at Harvard Law School, said the 2nd Circuit ruling directly affects the New York case because of its interpretation of the Hughes ruling. “One of the key issues in Allco was what does the Hughes decision mean, and that’s the key issue in this case too,” he said. “So I think [Caproni] really had to wait to see what the 2nd Circuit was going to say before she issued her decision. It potentially could have been nullified by the 2nd Circuit decision.”

While he doesn’t like to speculate on the outcome of any case, Peskoe said, “Intuitively, to me, the states’ reading of Allco is more straightforward than how the plaintiffs are trying to spin it. But that doesn’t mean the judges see it that way. It’s tempting to read into the oral arguments, but it’s not always ‘what you see is what you get.’”

Peskoe predicted that if New York wins a dismissal from Caproni, “the generators would likely appeal to the 2nd Circuit.”

[Editor’s Note: An earlier version of this story incorrectly quoted attorneys for Illinois as saying the Connecticut REC program survived the legal challenge although it allows the state to direct utilities to sign contracts for electric power and capacity, and “not just the environmental attributes of renewable power.” Illinois’ reference was to Connecticut’s renewable portfolio standard, not its REC program.]

July 12, 2017

Former Energy Future Holdings Exec Named MISO North Director

MISO has named a Texas energy executive to head its North Region external affairs division.

energy future holdings miso north — Tulloh | *MISO*

A former public policy vice president at Dallas-based Energy Future Holdings, Brian Tulloh is now MISO’s “primary liaison with members, stakeholders and policymakers in the north footprint.” He will be based in the RTO’s Eagan, Minn., office.

Prior to his four years with EFH, Tulloh spent a decade at TXU Energy in executive positions. He was also a senior energy consultant for consulting firm McKinsey and Co. He has a bachelor’s degree in chemical engineering from Purdue University and an MBA from Southern Methodist University.

Tulloh said he is excited to join MISO, calling the RTO’s collaboration with members and stakeholders “critical.”

MISO spokesman Mark Adrian Brown said Tulloh fills a role previously held by Priti Patel, who became Great River Energy’s new vice president and chief transmission officer last month.

— Amanda Durish Cook

July 12, 2017

EIM Members Seek More Details on GHG Accounting Plan

By Jason Fordney

Western Energy Imbalance Market (EIM) participants are generally supportive of CAISO’s plan to account for greenhouse gas emissions of external resources but requested more information on market tools the grid operator plans to implement.

The EIM received about a dozen comments before the July 6 deadline in response to CAISO’s revised draft final proposal for the GHG accounting system.

CAISO must develop a GHG accounting system that enables the ISO market to track and price emissions from all participating resources (such as the Jim Bridger plant shown above) | *Pacificorp*

CAISO is working with the California Air Resources Board (CARB) to address concerns that the EIM market design is not capturing the climate effects from imports serving ISO load. EIM energy transfers that serve ISO load are subject to CARB regulations, and the air quality agency relies on the ISO’s market data to identify participating resources’ emissions.

CARB’s concern, according to CAISO, is that “the market optimization’s least cost dispatch can deem or attribute low emitting resources to the ISO, but not account for the resulting ‘secondary’ dispatch or backfill of other, possibly higher emitting resources to serve external demand.”

After consulting with market participants, CAISO proposed a “two-pass” market tool to determine which generation resources support EIM transfers serving ISO load. The first pass would determine the optimal schedule across the EIM footprint while not allowing net transfers into the ISO. The second pass would allow transfers into the ISO, limiting each EIM resource’s GHG bid quantity to the difference between the resource’s upper economic limit and the optimal schedule determined in the first pass, according to the ISO.

CAISO is initially planning to implement the two-pass solution only in the real-time market but said it could extend the approach to the day-ahead market.

A group of market participants — including Seattle City Light, Portland General Electric, Idaho Power, Arizona Public Service and PacifiCorp — requested more information on the impacts of the proposal.

The companies said they “believe it is critical to the success of the ISO’s proposal, and the EIM in general, that prices for electricity to serve load outside of California are not inappropriately impacted by this proposed change to the market optimization.”

The group added that it “is not able to assess, however, whether this principle will likely be met based on the current information provided.” The ISO did not provide much detail on price impacts inside or outside California from the two-pass approach, they said.

In separate comments, Seattle City Light said the two-pass proposal “will result in a more accurate accounting of GHG emissions attributable to California, while also preserving the resource-specific cost and GHG attribution components within the [market] optimization.”

The American Wind Energy Association’s California Caucus supported the two-pass solution, as did the “Six Cities” (Anaheim, Azusa, Banning, Colton, Pasadena and Riverside) in a joint filing. “The cities look forward to the outcome of the ISO’s simulations of the two-pass optimization methodology and may identify and comment on implementation concerns based on the simulation results,” they said.

EIM participant PacifiCorp, a non-California entity, was more cautious, saying it “needs additional information and analysis, and greater assurances from the ISO that least-cost dispatch will be preserved and that PacifiCorp’s customers outside of California will not be negatively impacted in an unwarranted way by this change driven by California’s environmental policies.”

The multistate utility said it is concerned that aspects of the proposal will disrupt the market. “Given the complexity of introducing a two-pass optimization, PacifiCorp is concerned that there will be additional unforeseen and unintended consequences associated with this approach,” it said.

CAISO said it will issue a report in the fourth quarter of this year based on simulations analyzing how effective the proposal would be in minimizing secondary dispatch.

The EIM Governing Body and CAISO Board of Governors are Due to Review New GHG Rules in Q1 2018 | *CAISO*

The EIM Governing Body is due to review the proposal at its meeting Thursday and make a decision in the first quarter of 2018. The CAISO Board of Governors is due to review it in the first quarter of 2018, with implementation expected around fall of next year.

July 11, 2017

Rhode Island Looks to Sustain Clean Jobs Gains

By Michael Kuser

Rhode Island is seeking ways to sustain a recent surge in jobs stemming from the growth of renewable and distributed energy resources.

Clean energy jobs in the Ocean State have increased by 66% since 2014, with more than 15,300 people now working in the sector, according to a recent report from the state’s Office of Energy Resources (OER). Solar employment alone has grown 16% during the past 12 months. Energy efficiency currently represents the largest portion of the clean energy sector, with almost 9,000 workers across the state.

clean energy jobs rhode island — | *Rhode Island Office of Energy Resources*

In 2014, the state’s legislature established the Renewable Energy Growth (REG) program to promote installation of grid-connected renewables and encourage growth of DERs (Act H 7727). Supervised by the Rhode Island Public Utilities Commission, the REG program is forecast to account for 160 MW of renewable energy development — valued at $390 million — by its 2019 end date.

But OER’s 2017 Clean Energy Industry report revealed that the small firms that dominate the distributed generation market are having trouble hiring qualified workers, in part because of the state’s high cost of living, competition and the relatively small number of available college graduates.

State officials are working to improve the sector’s labor situation. The OER is developing a program to provide funding for clean industry interns and another initiative offering free college tuition for state residents. Gov. Gina Raimondo has proposed the Rhode Island Promise Scholarship, which would include two years of free college at the state community college, but funding is contingent on the fiscal year 2018 budget, which has not been enacted.

Because most of clean energy employment is in installation, some initiatives will be aimed at vocational schools and high schools.

‘Real Jobs’

The Real Jobs RI program, for example, brings employers and educators together to design training courses that focus on the skills needed by the industry.

Carol Grant, head of OER, told RTO Insider about several grants her office is seeking under the program. One focuses on fuel delivery and the other works with the University of Rhode Island to enhance its existing fellowship program.

In partnership with the solar PV industry, OER also applied to the Department of Labor and Training for a grant to increase the pipeline of electricians skilled in PV technology and increasing the number of certified salespeople.

Other policy initiatives will facilitate ties between the marine research and development centers at URI and the Newport Naval Base. The OER is already working with the U.S. Navy on clean energy issues.

Other Administrative Efforts

The OER also is supporting legislation that would:

Simplify electrical and building permits by establishing one statewide solar permit application process beginning in 2018.
Extend and expand the REG program, which helps homeowners, businesses, farmers and municipalities pursue renewable energy projects.
Continue the state’s electric vehicle rebate program, which helps reduce costs for residents purchasing EVs.

A separate Brattle Group report commissioned by the OER said the REG program will add close to 500 new jobs to the economy annually from 2016 to 2019 because of construction but provide nearly no net gains between 2020 and 2040. The report notes that “while operations and maintenance jobs grow, they are offset by losses in service jobs resulting from modestly higher electricity prices until late in the period.”

July 11, 2017May 29, 2024

Reed Smith Adds Honorable, 2 Others to Boost FERC Practice

By Rich Heidorn Jr.

Former FERC Commissioner Colette Honorable has joined Reed Smith as a partner in the law firm’s D.C. office, along with Regina Y. Speed-Bost, former chair of Schiff Hardin’s Energy Group.

The two will join Reed Smith’s energy and natural resources (ENR) practice, “spearheading the firm’s FERC offering,” Reed Smith said in a press release. Debra Ann Palmer, a colleague of Speed-Bost’s at Schiff Hardin, also is moving to the firm’s ENR practice as counsel.

“This addition underscores our commitment to building out our stateside energy offering in order to meet our energy and commodities clients’ needs, which include responding rapidly and proactively to fluid policies, regulations and enforcement initiatives,” said ENR Chair Prajakt Samant. Founded in 1877, Reed Smith has more than 1,700 lawyers in 27 offices in the U.S., Europe, Asia and the Middle East.

Honorable, a former Arkansas Public Service Commissioner and past president of the National Association of Regulatory Utility Commissioners, joined FERC in December 2014 and left June 30 at the expiration of her term. President Trump has nominated Richard Glick, general counsel for the Democrats on the Senate Energy and Natural Resources Committee, to replace her. (See Trump Taps Senate Aide, Former Lobbyist for FERC.)

Former FERC Commissioner Colette Honorable (L) and former Schiff Hardin attorneys Regina Speed-Bost and Debra Ann Palmer (R) have joined law firm Reed Smith to bolster its FERC practice.

Before joining the Arkansas PSC, Honorable served as chief of staff to then Arkansas Attorney General Mike Beebe, and as an assistant attorney general handling consumer protection, civil litigation and Medicaid fraud. She is a graduate of the University of Memphis and the University of Arkansas at Little Rock School of Law.

Speed-Bost, a former FERC trial attorney and adviser to former Commissioner William Massey, is a graduate of Dartmouth College and Georgetown University Law Center.

Palmer, a graduate of Case Western Reserve School of Law, has expertise in natural gas pipeline regulation and Commodity Futures Trading Commission rules, and has represented clients before FERC’s Office of Enforcement.

July 11, 2017

Dominion Plans 12-MW Offshore Wind Project, 2nd in US

By Rich Heidorn Jr.

Dominion Energy announced Monday it will build the second offshore wind project in the U.S.: two 6-MW turbines about 27 miles off the coast of Virginia Beach.

The Coastal Virginia Offshore Wind project, which would be the first offshore project connecting to PJM, follows the 30-MW, five-turbine Block Island Wind Farm off Rhode Island, which went into operation in December.

Dominion Energy Coastal Virginia Offshore Wind Project | *Dominion Energy*

Dominion said DONG Energy of Denmark will begin engineering and development work immediately on the project. The turbines should be installed by the end of 2020, assuming no delays from weather or protected species migration.

The project will build on preparatory work performed under the Virginia Offshore Wind Technology Assessment Project and be located on a 2,135-acre site leased by the state Department of Mines, Minerals and Energy. Power will be delivered via a buried 34-kV distribution line to a connection point near the Virginia National Guard’s Camp Pendleton.

The state’s site is adjacent to the 112,800-acre site leased by Dominion from the U.S. Bureau of Ocean Energy Management (BOEM), an area with the capacity for 2,000 MW.

“Today marks the first step in what I expect to be the deployment of hundreds of wind turbines off Virginia’s coast that will further diversify our energy production portfolio, create thousands of jobs and reduce carbon emissions in the commonwealth,” said Gov. Terry McAuliffe, who attended the announcement at the Portsmouth Marine Terminal in the Hampton Roads area of Virginia. “Hampton Roads has the ideal port assets and talented workforce to attract and house the offshore wind business supply chain to support not only Virginia’s commercial wind area but also wind farms under development in Massachusetts, New York and Maryland.”

“While we have faced many technological challenges and even more doubters as we advanced this project, we have been steadfast in our commitment to our customers and the communities we serve,” Dominion CEO Thomas Farrell II said.

Left to right: Virginia Governor Terry McAuliffe; Thomas F. Farrell, II, Dominion Energy’s chairman, president and chief executive officer, Francis Slingsby, Dong Energy’s head of strategic partnerships in North America; Paul Koontz, executive vice president and president and CEO – Power Generation Group | *Dominion Energy*

Dominion lost $40 million in federal grants for the project last year when the U.S. Department of Energy said it wasn’t moving fast enough. In addition, bids on construction came in at about $400 million, almost double Dominion’s $230 million projection. The project was revived after DONG agreed to build it under a fixed-price contract of about $300 million.

Farrell’s comment also seemed an apparent response to critics who had worried that the utility would not develop its wind energy area, which it won in a BOEM lease auction in September 2013. (See Will an Old Utility Learn New Tricks?)

The company’s 2017 integrated resource plan, filed May 1, estimates the cost of offshore wind at $339/MWh, more than triple that for onshore wind ($99/MWh) and almost five times the cost of a 3×1 combined cycle plant ($70/MWh).

The high cost of offshore wind is particularly challenging in Virginia: The state does not have a mandatory renewable portfolio standard nor retail choice, which could create a niche for a green alternative. Despite that, Dominion has set a voluntary goal to obtain 15% of its power from renewables by 2025.

Excluding pump storage (9%), renewables represent 3% of its current capacity.

“We welcome the news that Dominion is making steps to bring offshore wind to Virginia. But this should have happened years ago,” said Mike Tidwell, executive director of the Chesapeake Climate Action Network. “Dominion already lost a federal grant for $40 million for dragging its feet on the project. Will ratepayers have to foot that bill?

“Meanwhile, Dominion continues to push for dangerous climate-warming fossil fuel projects like the Atlantic Coast pipeline, along with the support of Gov. Terry McAuliffe,” he continued. “The offshore wind pilot project is nowhere near what’s needed to bring us to a clean energy economy. If McAuliffe and Dominion were truly serious about helping Virginia become a leader in clean energy, they would stop pushing for fracked-gas pipelines and start focusing on expanding clean energy.”

Eileen Levandoski, assistant director of the Sierra Club’s Virginia Chapter, also criticized the pace of Dominion’s progress. “While the commitment to 12 MW by 2020 is helpful, the crisis we face with climate change demands that Dominion also engage aggressively on the commercial lease area and immediately commit to 400 [MW] by 2022 and 2,000 by 2030,” she said.

Dominion officials say the initial project will test whether the turbines can withstand hurricanes, and that it will not interfere with marine life and whale migrations. If turbine prices continue to decline, a larger project will begin operating by the mid-2020s, they said.

[Editor’s Note: An earlier version of this article incorrectly stated that the Dominion’s offshore distribution line would connect with the utility’s grid near “Marine Corps Base Camp Pendleton,” which is in California.]