NYISO announced Wednesday that its Board of Directors has selected Bradley C. Jones, senior vice president and COO of ERCOT, to replace Stephen G. Whitley as president and CEO, effective Oct. 12.
Jones is a distinguished energy industry executive with 29 years of wide-ranging experience, including grid operations, power plant operations, generation development, project finance, wholesale and retail market design, and regulatory and legislative affairs.
At ERCOT, Jones had responsibility for operations, grid planning and commercial operations.
Jones (left), Whitley (right) (Source: NYISO)
Jones joined ERCOT from Luminant, the competitive generation subsidiary of Energy Future Holdings, where he was vice president for government affairs. He previously worked at TXU Corp., rising from a plant engineer to become vice president for generation development.
A licensed professional engineer, Jones has a bachelor’s in mechanical engineering from Texas Tech University at Lubbock and an MBA from the University of Texas at Arlington.
“Brad has a strong commitment to reliability and a firm belief in the power of markets to benefit consumers,” NYISO Chairman Michael Bemis said in a statement. “His talent, experience and demonstrated commitment to excellence make him a great choice.”
Jones was chosen following a nationwide search conducted by Heidrick & Struggles. He could not be immediately reached for comment.
Whitley, appointed CEO in 2008, will remain with the ISO during the transition and then act as an advisor to the board.
The developers of the abandoned PATH transmission project would be denied recovery of more than $10 million of their $121.5 million claim under an initial decision by a FERC administrative law judge Monday.
Judge Philip C. Baten recommended that the commission deny the developers, American Electric Power and the former Allegheny Energy (now FirstEnergy), recovery of lobbying and advertising costs as well as part of their legal costs and losses on the sale of the property they acquired (ER09-1256-002, ER12-2708-003). The commission can accept the recommendations in whole or in part.
The proposed 765-kV “coal by wire” Potomac-Appalachian Transmission Highline project was approved by PJM in 2007 to run from AEP’s John Amos coal generator in St. Albans, W.Va., to New Market in Frederick County, Md.
By 2011, however, PJM said the need for the line had moved several years beyond 2015 due to reduced load growth following the recession. The PJM Board of Managers ordered transmission owners to suspend work on the line pending a more complete analysis in 2011 of all upgrades in its regional transmission plan and terminated it in 2012.
Victory for Pro Se Interveners
Although the developers would recover most of their request, the judge’s ruling was a victory for two PATH opponents from West Virginia, Keryn Newman and Allison Haverty, who filed a pro se intervention challenging the companies’ request for recovery of $6 million in spending on lobbying and advertising campaigns intended to win political support for the project. The judge denied recovery of any of the expenses.
Baten also said $3.6 million in losses that the companies incurred on past land sales are not recoverable and that recoveries from any future land transactions “must be accomplished by commercially reasonable procedures.”
The judge also denied recovery for part of $3.9 million in legal expenses, for which the companies’ failed to provide documentation, and cut the companies’ proposed 10.4 % return on equity for the abandonment costs to 6.27%.
But Baten approved recovery for the purchase of property for a planned substation in Maryland and rejected a request by state consumer advocates to reject $29 million in spending incurred in 2010-2012 as imprudent.
The advocates said that the PATH companies should have recommended to PJM that the project be terminated by the beginning of 2010 and that expenses between that point and the actual termination should be denied.
The judge ruled that the expenses were recoverable because the PATH companies had a contractual obligation to construct the transmission projects as assigned by PJM. “The PATH companies did behave as a prudent utility by proceeding with their assigned obligations until otherwise instructed by PJM,” he wrote.
First Impression
Baten said that the case “presents significant issues of first impression” on FERC Order 679, a 2006 initiative that sought to accelerate transmission investment through incentives.
“This case addresses some new issues and gives the commission a unique one-stop opportunity to review and set policies for the comprehensive litigation scheme arising from Order No. 679,” Baten wrote.
The PATH project was initiated with PJM’s 2007 Regional Transmission Expansion Plan, and in 2008 FERC accepted a formula rate that entitled the developers to recover all prudently incurred costs if the project were cancelled.
In 2012, the companies filed for recovery of $121.5 million in abandonment costs. After settlement attempts with opponents failed, hearings in the case were held in March and April.
Lobbying Campaign
The pro se interveners contested spending on public relations agencies, advertising and public coalitions intended to influence public officials during the zoning and certificate of public convenience and necessity (CPCN) proceedings in Maryland, Virginia and West Virginia.
“When utilities are seeking selection or CPCN approvals from governmental entities, the utilities should rely on the established governmental approval processes to persuade the officials and not indulge in collateral efforts such as public education, outreach and advertising activities,” the judge ruled. “… If the selection or CPCN application has merit, the governmental selection process provides a sufficient vehicle for the utilities to present their engineering, marketing and economic studies and thereby hope to merit the vote of approval from these officials. In this regard the PATH companies spent over $8 million on attorney fees to prosecute the CPCNs before the respective governmental bodies, which begs the need for these collateral expenses.”
Among the spending rejected was $332,000 on a public opinion poll, $2.7 million in advertising and $94,000 paid to the then head of the West Virginia Democratic Party, Larry Puccio.
The judge said that the “nature and origins of the PATH companies’ business relationship with Puccio are somewhat amorphous” and that the companies paid him $31,000 “before his assignments were even formulated.”
“The invoices of record provide little description of his services. When the PATH companies were asked in discovery to provide additional details, their response was that such records are not available. While the PATH companies make protestations that Puccio’s services were not to lobby and instead were to educate the public and public officials, without proper documentation the only factual inference that can be drawn is that his services were to influence public officials, and the PATH companies have failed in their burden of proof to show otherwise.”
Load representatives said Thursday they will oppose PJM’s proposal to increase the installed reserve margin (IRM) to 16.6%, from 15.7%.
“There’s going to be a lot of push back on this,” said James Wilson, a consultant to state consumer advocates, who criticized what he called PJM’s “arbitrary” choice of a load model. “There’s quite a lot of load models that would fit equally well” but result in lower reserve margins, Wilson said.
Ed Tatum said the proposal prompted a “fairly violent” reaction among his colleagues at Old Dominion Electric Cooperative and threatens to renew the “IRM wars” of previous years.
Tatum said the increase in the IRM was “counterintuitive” given the higher performance expectations of PJM’s new Capacity Performance product. As a result, he said, load representatives will challenge the “overly conservative” assumptions PJM used in calculating the figure.
PJM’s Patricio Rocha-Garrido said the increase resulted from changes in 2015 capacity and load models as well as a decline in the capacity benefit of ties (CBOT) — expected capacity imports.
Rocha-Garrido noted that seemingly large increases in IRM may not have that much impact on the forecast pool requirement (FPR), which determines the amount of capacity procured in the annual Base Residual Auction.
The reliability requirement is calculated based on the 50/50 peak load forecast for the delivery year multiplied by the FPR. The FPR is increasing from 1.0847 to 1.0881 (from 8.47% to 8.81% above the peak load forecast.)
The increase is a result of a new load model (2003-2012) that better represents the coincident peak distribution in the 2015 load forecast, Rocha-Garrido said.
The CBOT was reduced because the “rest of world” peak demand is becoming more coincident with the PJM peak, he said.
PJM will seek members’ endorsement of IRM and associated parameters for delivery years 2016 through 2019 beginning in October, with final approval by the PJM board expected in December or January.
New Methodology Could Lower Summer 2018 Forecast by 2.6%; Winter down 1.8%
PJM could lower its 2018 summer peak load forecast by 2.6% as a result of new forecasting methodology that incorporates more recent economic data, a shorter weather simulation and the energy efficiency of air conditioners and electric appliances.
The new methodology also would reduce the winter 2018 forecast by 1.8% over the current official projection.
The forecast outlined to the PC last week will be finalized after an additional update to economic data, equipment index trends and any additional equipment “saturation” data by zones.
Manual language documenting the new methodology still needs to be developed and presented to the PC and MRC.
PJM said the new methodology will reduce the error rate for forecasts three years into the future to 1.5%, compared with the current method’s 6.6%.
One significant change is the RTO’s effort to improve its weather forecasts to reflect a trend of higher peak temperatures.
The RTO has based its forecasts on temperature and humidity data from 26 weather stations dating back to 1973. But a new analysis revealed that peak readings for 1993-2013 were higher than those for 1973-1993.
As a result, PJM’s Andrew Gledhill said, the RTO plans to exclude the earlier data and rely on that from 1994/95. It will reevaluate the historical base about every five years. (See “Climate Change Impact? Higher Highs has PJM Adjusting Weather Forecasts,” in PJM Planning Committee Briefs.)
ODEC’s Tatum said PJM’s plan to reevaluate the time sample for the weather forecasts could inject subjectivity into the modeling, creating a temptation to make changes “to get the answer you want.”
But PJM’s Tom Falin said the weather analysis will be done independently and not evaluated based on its impact on the forecast load.
At the Oct. 1 Markets and Reliability Committee meeting, PJM officials will discuss how they plan to incorporate the new methodology into its capacity auctions. Stu Bresler, senior vice president of markets, said adjustments will have to be made to ensure the RTO is not double counting energy efficiency, which can offer into the auction as a capacity resource.
Action Delayed on Voltage Threshold for Competitive Projects
PJM delayed a vote on a plan to exclude transmission reliability projects below 200 kV from competition, saying it wants to refine the proposal in response to stakeholder comments.
PJM said reliability projects below 200 kV are almost always allocated to one zone and thus automatically assigned to the incumbent transmission owner. The “voltage floor” would allow the RTO to eliminate the cost of evaluating competitive proposals in cases where the likely solution is a transmission owner upgrade. It would not apply to market efficiency projects.
Competitive developers expressed reservations about the proposal at the August PC meeting. (See “Developers Wary of ‘Voltage Floor’ on Competitive Projects” in PJM Planning Committee Briefs.)
At last week’s PC, PJM distributed an expanded chart for how the RTO would handle projects between 100 kV and 200 kV and those above 200 kV or below 100 kV. PJM’s Sue Glatz said the chart “narrows the scope of discretion” for PJM in determining whether or not to open a project to competition.
ITC Holdings’ John Kopinski said the chart made his company more comfortable with the proposal, which he said was consistent with the FERC-approved process for deciding which projects are competitive and which are reserved for incumbents. “You’re not really changing what’s competitive and what’s not,” he said.
Paul McGlynn, general manager of system planning, said PJM will modify the chart and proposed Operating Agreement language to reflect stakeholder comments from the meeting. PJM would like to implement the change in time for the 2016 Regional Transmission Expansion Plan.
Winter Peak Reliability Study
PJM planners last week outlined new rules for separately modeling winter reliability as part of the RTEP.
The changes to Manual 14B: PJM Region Transmission Planning Process would require planners to conduct a reliability analysis to ensure that the grid can deliver enough generation to meet the 50/50 winter peak. It will model generators by fuel class based on historical operation during winter peak loads.
In the past, PJM has planned for reliability based only on its summer peak load.
The changes will be brought to an endorsement vote at the PC next month, with plans to incorporate the study in the 2016 RTEP.
At the Transmission Expansion Advisory Committee meeting later Thursday, planners presented the results of their first study under the new rules, which defines winter as December through February. (See pp.11-24 of the presentation.)
The analysis looked at thermal and voltage violations both with and without consideration of gas contingencies. The North American Electric Reliability Corp.’s transmission planning standard (TPL-001-4), which takes effect Jan. 1, requires PJM to consider extreme system events such as the loss of a large gas pipeline serving significant generation.
PJM analyzed 30 gas pipeline and compressor failure contingencies that could result in the loss of 1,000 MW or more of generation.
Two contingencies, for pipeline outages in EMAAC, suggested the potential loss of 10,000 MW of generation, although officials said the generation would not go offline immediately because of the ability to burn “line pack” gas.
McGlynn said the results of the winter study did not suggest “the sky is falling” but reinforced the need for criteria to capture problems not seen in the light load or summer analyses.
Manual Language on Multi-Driver Projects OK’d
Members approved manual changes documenting how PJM will oversee transmission projects that have multiple benefits. The new rules on multi-driver projects are documented in manuals 14B and 14A: Generation and Transmission Interconnection Process.
Multi-driver projects have benefits in at least two categories, including baseline reliability upgrades, market efficiency and public policy.
States seeking to meet public policy objectives could sign on to projects after they have been approved. But once rights of way or equipment such as transmission towers have been acquired, states would be liable for costs “even if they didn’t go forward with the solar farm or wind farm,” said PJM’s Fran Barrett.
Long-Term Firm Transmission Service Study
The PC approved the charter for a group considering changes to the way PJM conducts studies for long-term firm transmission service.
The group, which resulted from a problem statement approved in April, has met twice, with a third meeting set for Sept. 24.
It will determine if changes are needed to:
Modeling practices for long-term firm transmission service requests (TSRs) in RTEP power flow cases;
Study methods used in RTEP and new service queue studies; and
Cost allocation requirements associated with long term TSRs.
PAR Transmission and Withdrawal Rights
Planners gave stakeholders the first read on rules governing how phase angle regulators (PARs) that redirect energy flows can qualify as controllable AC merchant transmission facilities.
The proposal resulted from a problem statement proposed last November by PSEG Energy Resources & Trade.
PJM currently awards withdrawal and injection rights to controllable AC and DC merchant transmission facilities using only variable frequency transformer (VFT) technology, which excludes PARs. (See “PSEG Seeks Injection Rights for PARs” in PJM Planning Committee Briefs.)
The task force appointed to review the issue endorsed a PJM staff recommendation after staff determined through flow control analyses that PARs “did not show any significant deviation from other controllable AC or DC type installations.”
The task force said that PARs did not harm holders of existing injection and withdrawal rights “assuming reinforcements identified for PAR installations were made.”
PAR owners will be required to comply with rules governing allowable deviations for all resources that are self-scheduled. The operators must be able to control their flows automatically, with the ability to manually adjust.
PJM will allocate costs for PAR facilities consistent with the methodologies used for HVDC and VFTs.
The new rules will be added to Manual 14E: Merchant Transmission Specific Requirements; no Tariff change is required.
None of the 10,017 MW of additional capacity committed in the 2017/18 transition auction will be calculated in this week’s incremental auction for the delivery year, PJM said.
“Originally, we said yes, the new commitments — the incrementally additional committed megawatts — would be rolled into capacity,” Stu Bresler, PJM senior vice president for markets, told the Market Implementation Committee. However, he said, “The Tariff will not allow us to do that. It’s very specific in the calculation of how many megawatts we procure or release.”
But, he said, PJM believes that incorporating new capacity into the incremental auctions is “the right thing to do” and will be introducing a Tariff change at the Oct. 1 meeting of the Markets and Reliability Committee.
If a load forecast changes between a Base Residual Auction and the corresponding delivery year’s incremental auction, PJM adjusts its reliability requirements, Bresler said.
“Conceptually, if the reliability requirement goes up, PJM could buy more capacity. If it goes down, which has been the trend, the requirement drops, and PJM could sell off previously committed capacity in the incremental auction,” he said. “Participants could buy that as replacement.”
Bresler said that if the Tariff change is approved, PJM expects to include additionally committed capacity in the third incremental auction for the 2016/17 year, to be held in February. The transition auction for that year procured 4,246 MW of additional capacity.
The operator of the R.E. Ginna nuclear plant in western New York has reached an agreement to keep the financially stressed generator operating.
Administrative law judges for the New York Public Service Commission said Wednesday that a joint proposal for the PSC-ordered reliability support services agreement between Constellation Energy Nuclear Group and Rochester Gas & Electric is expected to be filed by Sept. 23.
The judges posted a revised schedule calling for comments on the agreement by Sept. 30, with an evidentiary hearing to be held on Oct. 14 (14-E-0270).
Parties to the agreement in principle include the PSC staff, the New York Division of Consumer Protection and a group of interveners representing commercial and industrial customers.
Entergy Nuclear, which has plants in western New York and the Hudson Valley, and NRG Energy have opposed the RSSA throughout the 14-month proceeding. The companies will neither support nor oppose the agreement, the filing said.
Environmental groups Alliance for a Green Economy and Citizens’ Environmental Coalition will oppose the agreement in part, but the objectionable sections were not identified.
The out-of-market contract is expected to raise rates for customers in the Rochester area. The PSC recently adopted a temporary rate surcharge to lessen rate shock when a final agreement is sent to the commission. (See NYPSC Approves 5.2% Ginna Rate Surcharge.)
SPP is preparing for the Environmental Protection Agency’s Clean Power Plan by beginning outreach to state officials and planning to form a task force under its Strategic Planning Committee.
The RTO scheduled a two-hour webinar to kick off the effort on Friday, Sept. 18. Lanny Nickell, SPP’s engineering vice president and point man for CPP compliance, told the SPC during its August meeting that all 14 states in the RTO’s footprint have been invited.
While there have been no requests for SPP to develop a plan or trading rules, the RTO says a regional approach would be easier to implement.
The SPC tabled a motion to form a CPP task force and instead asked staff to work with Golden Spread Electric Cooperative’s Mike Wise, the committee chair, to draft a scope document to better understand and pursue the regional-trading issue.
Nickell said SPP will include modeling futures based on the final EPA rule in its 2017 Integrated Transmission Plan’s 10-Year Assessment to determine how it impacts the RTO’s transmission needs.
SPP’s regulatory staff is currently meeting with key state legislators, according to an update given to another task force responsible for gas-electric timeline coordination.
SPP-MISO Settlement to be Filed Oct. 9
David Kelley, SPP’s director of interregional relations, told the RTO’s Seams Steering Committee last week that SPP and MISO plan to file a settlement agreement with FERC on Oct. 9 that could bring an end to their dispute over the latter’s use of a 1,000-MW contract path between its North and South regions.
“There’s not a lot I can share publicly,” Kelley said, “but I can discuss the schedule.”
The proposed settlement also was discussed by MISO members at meetings last month. (See “Settlement with SPP over 1,000-MW Limit Will Eliminate ‘Hurdle Rate’” in Markets Committee Briefs.)
SPP RE Reliability Assessment Webinar
SPP and the SPP Regional Entity have scheduled a 30-minute webinar on the 2015 winter reliability assessment for Sept. 23. SPP RE staff will present an overview of the draft assessment and solicit feedback before it is finalized with the North American Electric Reliability Corp.
Registrants will receive the draft assessment and presentation for review.
CAMBRIDGE, Mass. — Speakers at the Northeast Energy and Commerce Association’s dinner meeting last week discussed pending legislation in Maine, the future of the proposed Northern Pass Transmission project and net metering.
The state’s Site Evaluation Committee has a 10-step process for approving such projects. “The governor has been clear that she is waiting for the site evaluation process to play out,” Allegretti said.
Christopher Sherman, president of New Hampshire transmission for NextEra Energy, said one of the investor-owned utilities in Massachusetts earlier this year reached the 4% limit on the integration of net-metered generation onto the grid.
“The governor’s own bill [which would raise the cap to 6%, with future increases left to state regulators] will be considered at a hearing by the end of this month, with the possibility the legislature will pass a bill later in the fall,” Sherman said.
Sandi Hennequin, vice president of U.S. public affairs for Nova Scotia-based Emera Energy, mentioned a bill backed by Maine Gov. Paul LePage that would allow local distribution utilities, which were divested after restructuring in 2000, to own some generation assets.
The bill would require the Public Utilities Commission to determine “that ownership is beneficial to the utility’s ratepayers” and to “impose terms, conditions or requirements the commission determines are necessary to protect the interests of the utility’s ratepayers.” The bill was introduced last session and has been held over for consideration during the coming session.
Patrick C. Woodcock, director of the governor’s energy office, said LePage saw the need for the legislation because of ambiguity about whether affiliates of local utilities can own generation. Woodcock said neither the state’s restructuring law nor a recent court ruling provided clarity. The case involved a proposed $333 million joint venture by Emera and First Wind to finance wind farms in the state.
“The governor asked, ‘Does it really make sense to have this iron-clad prohibition?’” Woodcock said in an interview after the dinner. He said limited utility ownership of generation could help the state modernize older hydro facilities.
“I think there’s an opportunity there for some of the utilities to benefit from generating from solar,” said Maine Rep. Larry C. Dunphy, who introduced the bill on the governor’s behalf. “There’s a number of motivations.”
FERC Chairman Norman Bay named a long-time associate from New Mexico as FERC general counsel, replacing David Morenoff.
Max Minzer, who served as Bay’s special counsel in 2009-10 when the latter headed FERC’s Office of Enforcement, joined the chairman’s staff as an advisor in June.
Minzer met Bay while working as a law clerk at the U.S. Attorney’s Office in New Mexico almost 20 years ago. Bay was U.S. Attorney for New Mexico in 2000-01 after serving as an Assistant U.S. Attorney in D.C. and New Mexico from 1989 to 2000.
Like Bay, Minzer is a former professor at the University of New Mexico School of Law, where he won the university’s 2013-2015 Presidential Teaching Fellowship, an award recognizing teaching excellence. He previously taught at the Benjamin N. Cardozo School of Law in New York. A graduate of Brown University and Yale Law School, Minzer has been published in the Harvard Law Review, the Texas Law Review and the William & Mary Law Review.
Bay praised Morenoff even as he moved him aside. “It is a testament to the high regard in which David is held that he is one of the few general counsels who has served three different chairmen as either the acting general counsel or as general counsel,” Bay said in a statement.
Morenoff, who joined FERC from Troutman Sanders, formerly served as a legislative aide to U.S. Sen. Jack Reed (D-R.I.). He is a graduate of Brown University and Harvard Law School. In addition to his work in the general counsel’s office, he also served as senior legal and policy advisor to former Chairman Jon Wellinghoff.
FERC granted a waiver to a New England power generator that missed the deadline for a payment to increase the plant’s offer for the next Forward Capacity Auction.
The commission majority said Northeast Energy Associates had made a “good faith” effort to comply with ISO-NE rules once it discovered an administrative oversight (ER15-1934).
NEA sought a 25-MW increase in the capacity of its Bellingham Energy Center in Massachusetts but failed to make a $50,000 interconnection deposit for FCA 10 by the March 3, 2015, deadline.
It discovered the error that day but was unable to make a bank transfer before the Federal Reserve’s 5:30 p.m. deadline. The funds were transferred the following morning.
“We find that NEA acted in good faith by submitting its interconnection deposit as soon as possible after it discovered the omission … [and] the request for waiver is limited in scope, because it allows a one-time, finite waiver of a procedural deadline under the narrow circumstances of this case,” the majority said.
FERC said the company filed an otherwise valid request to increase its capacity and the delay in submitting its interconnection deposit would not affect the qualification process for FCA 10.
ISO-NE had opposed the request for relief, saying that it would be unfair to other project sponsors who submitted invalid interconnection requests and did not seek a waiver. The RTO also said NEA had not shown the resource would be needed in the newly proposed Southeastern New England capacity zone that will be created in the reconfigured zones in the 2018-2019 capacity commitment period.
Commissioner Philip Moeller agreed with the RTO, saying granting the waiver violates FERC precedent and will create future headaches.
“Such requests will present the commission with an enormous challenge to ensure that all market participants are treated similarly after missing [a Forward Capacity Market] or other deadline,” he wrote.
GridLiance arrived on the RTO scene in March billed as the nation’s first competitive transmission company focused on collaborating with public power entities. It came with a pedigree of experienced transmission executives from ITC Holdings and the deep pockets of private equity giant The Blackstone Group.
Now, the company has made its first two acquisitions — 420 miles of 69-kV and 115-kV lines in Missouri and Oklahoma — and announced plans to bid on SPP’s first competitive transmission project.
Incorporated last year, the company unveiled its business plan in March with the announcement that it and its affiliates had entered into 30-year development agreements with the Missouri Joint Municipal Electric Utility Commission (MJMEUC) and the Oklahoma Municipal Power Authority (OMPA), giving them the exclusive right to jointly plan, construct and operate the agencies’ transmission infrastructure in SPP and MISO.
On Sept. 1, GridLiance announced a pair of acquisitions that will give it ownership of the transmission assets of Nixa, Mo., a member of MJMEUC, and of Tri-County Electric Cooperative in the Oklahoma panhandle. Both acquisitions are expected to be completed by year’s end.
ROE Request
On the same day as the announcement, GridLiance subsidiary South Central MCN filed a request with FERC seeking a return on equity of 11.4%, including a 50 basis points (bps) adder for RTO participation and a 100 bps adder as a standalone transmission company (ER15-2594). The company asked for approval of an initial capital structure of 60% equity and 40% long-term debt.
South Central said FERC should grant the incentives to the company, “given its unique business model, which will provide benefits to current and future customers of the wholesale electric grid, including its public power partners.”
The company said it intends to submit a bid to SPP to build the North Liberal-Walkemeyer 115-kV project and requested commission approval to collect construction work in progress if it wins the solicitation. (See SPP Issues RFP for 115-kV Transmission Project.)
South Central will be the operating company for GridLiance in SPP. In MISO, the company will operate under the Midcontinent MCN.
Investment Opportunities, Reliability Benefits
In announcing the acquisitions, GridLiance president and CEO Ed Rahill said the deals allow Nixa and Tri-County to shift their operations and regulatory risk to GridLiance while gaining access to investment opportunities and funding for previously unaffordable transmission projects, including access to — and delivery of — wind energy.
Participating systems will see reliability benefits, according to Rahill, because public power systems are often excluded from regional planning models, leaving many served by a single radial feed, vulnerable to outages if that connection is lost.
“Operating and maintaining transmission infrastructure is expensive without scale, often taking valuable resources away from other core municipal responsibilities,” Rahill said.
Experienced Team
Rahill is one of several transmission and public power veterans who comprise the leadership team of the company, which has offices in Chicago, Kansas City and Austin, Texas.
Rahill was part of the of the management team that acquired ITC Transmission from DTE Energy in 2003 and managed its initial public offering in 2005. As president of ITC Grid Development, he oversaw ITC Great Plains’ greenfield start-up and the development of $500 million in transmission in SPP.
Noman Williams, GridLiance’s senior vice president of engineering and operations, is former vice president of transmission policy and compliance for Sunflower Electric Power, which runs six rural electric distribution cooperatives in central and western Kansas. He has filled several key leadership roles within SPP, and currently serves as chair of the RTO’s most important member body, the Market and Operations Policy Committee.
Like Rahill, Senior Vice President of Business Development Carl Huslig comes from ITC, where he was president of ITC Great Plains. He has worked extensively with SPP and MISO stakeholder groups during his 20-plus years in the industry, leading an SPP task force that paved the way for independent transmission companies.
General Counsel Beth Emery held the same titles at CAISO and San Antonio’s CPS Energy, the nation’s largest municipal utility. (Emery was joined in the company’s Sept. 1 filing to FERC by former Commissioner William L. Massey, now with Covington and Burling.)
Blackstone
The company is being financed by Blackstone Energy Partners, which has invested more than $8 billion of equity globally across a broad range of energy industry sectors. Blackstone Senior Managing Director Sean Klimczak, who oversees the firm’s investments in the transmission and power sectors, said the company saw an opportunity to fill an underserved market for 40 million public power customers.
Public power has “been largely excluded from participating in the planning of and investment in new transmission infrastructure as well as the financial and service reliability benefits they provide to customers,” Rahill said at the announcement of GridLiance’s incorporation in March 2014.
GridLiance’s partnerships with public power allow it to compete with investor-owned utilities that are building most transmission in MISO and SPP, the company says. About 90% of transmission projects in MISO have been awarded to ITC, Xcel, MidAmerican Energy, Ameren and American Transmission Co., the company says. In SPP, IOUs have been responsible for all but a few projects.
Meanwhile, public power rates have been increasing, with MJMEUC’s rates doubling under SPP’s highway-byway cost allocation. And 70% of public power transmission lines and transformers are at least 25 years old.
“Working together, we will have the necessary scale and resources to more effectively invest in, develop and construct new transmission infrastructure,” Rahill said.
Outsourcing
The deals announced Sept. 1 will give GridLiance operational responsibility for Tri-County’s 410 miles of transmission and Nixa’s 10-mile, 69-kV transmission line between Springfield and the Southwest Power Administration.
Jack Perkins, CEO of Tri-County, which has about 23,000 customer meters in the Oklahoma Panhandle, said the deal will allow the co-op to complete transmission reliability projects that it could not have otherwise afforded while outsourcing transmission operations. “Additionally, we will be able to reallocate funding and resources to upgrade our distribution system,” he said.
Doug Colvin, public works director for Nixa, said it no longer makes sense for the city of 21,000 to own its transmission infrastructure. “As regulatory requirements became increasingly complex, the city evaluated a number of options to protect our residents against rising costs and, at the same time, maintain our high reliability standards,” he said. “The GridLiance transaction ensures that we can meet these important requirements, as well as opens the door for our involvement in new transmission projects that can offset rate increases and provides us a much needed seat at the planning table.”
