Oil and gas producer Swift Energy has appointed Robert J. Banks as interim CEO. He replaces Terry E. Swift, who retired as the company’s CEO earlier this month, according to a statement.
Banks is Swift’s executive vice president and chief operating officer and will continue in those roles.
Terry Swift led the company for 15 years. He succeeded his father, Aubrey Swift, who founded the company in 1979.
http://logo.clearbit.com/entergy.com”>Entergy is seeking to build a $1 billion natural gas-fired power plant to serve the Montgomery County, Texas, area beginning in 2021.
The proposed 993-MW plant would serve 27 southeastern Texas counties primarily to the north and east of Houston. Entergy hopes to begin construction in early 2019.
GE to Spend $1.65B to Acquire Wind Turbine Blade Maker
General Electric announced last week that it plans to spend $1.65 billion to acquire LM Wind Power, a maker of wind turbine blades.
The deal will accelerate growth in GE’s renewable energy unit, which was established last year when the company acquired Alstom SA’s power operations for $10 billion.
LM Wind Power will run as a standalone business within the unit, the companies said in a statement.
Ranger Solar Takes First Steps to Develop Maine’s Largest Solar Farm
Ranger Solar has signed a lease for more than 600 acres at the former Loring Air Force Base in Maine to develop what could become the state’s largest solar farm, producing up to 100 MW of electricity.
The company would like to obtain the necessary regulatory approvals and power purchase agreements to begin construction before 2019.
“We know we have a long road ahead of us, but we’re committed to it. We’re hoping to bring new renewable energy to the region and new economic investment to northern Maine,” said Aaron Svedlow, the company’s director of environmental permitting.
Duke: Plant Operating Safely After Cooling Pond Wall Break
Duke Energy said its H.F. Lee Plant in Goldsboro, N.C., is operating safely after experiencing a break 50 to 60 feet wide in its cooling pond wall.
The pond is about 545 acres and does not contain coal ash, Duke said in a press release. An actively used ash pond across the Neuse River is also safe, the company said.
Duke expects the event to contribute less than one inch of water to the Neuse River.
Dynegy Delays Mothballing Illinois Power Plant Unit
Dynegy has delayed mothballing Unit 1 of its Baldwin power plant in Illinois after scoring a winning bid in the Illinois Power Authority capacity auction held in late September.
Unit 1 was scheduled to go offline on March 31, 2017, but will now remain in operation through September 2018. Unit 3 is scheduled to be mothballed on Oct. 17.
Coal company Alpha Natural Resources has sold one of its two remaining Eastern Kentucky mines to Kingdom Coal, a subsidiary of Keystone-Kingdom Resources.
Kingdom has expressed interest in restarting the mine, which Alpha shut down in July, said Alpha CEO David Stetson in a statement.
Alpha had 11 mines in Eastern Kentucky in 2012. It announced last month that it would shut down its last active mine — Sidney Coal’s Process Energy — in November.
NIPSCO Forecasts 24% Rise in Customer Heating Bills
Northern Indiana Public Service Co. customers should brace for a 24% rise in their winter heating bills, based on the utility’s forecast last week.
NIPSCO indicated that although higher natural gas costs are the primary driver of the hike, its gas infrastructure modernization plan is also a contributing factor.
On the same day as NIPSCO’s announcement, the U.S. Energy Information Administration predicted utility bills would increase an average of 22% across the nation this winter for households using natural gas.
ERCOT on Monday released the results of planning studies under new reliability-must-run rules approved by the Board of Directors last week, confirming that Greens Bayou is still needed to support reliability in the Houston area until the new 1,100-MW, gas-fired combined cycle Colorado Bend Generating Station becomes operational in July.
The ISO also determined that removing Calpine’s 344-MW Clear Lake cogeneration facility from the system will not cause reliability concerns under the new rules, which went into effect the day after the board meeting.
The board approved three rule changes intended to improve ERCOT’s management of its RMR processes. Two of the nodal protocol revision requests (NPRRs 793 and 795) were included in the board’s consent agenda. The third, NPRR788, was unanimously approved in a separate vote after receiving four opposing votes from the investor-owned utility sector. (See “Stakeholders Send Three RMR Revisions to ERCOT Board,” ERCOT Technical Advisory Committee Briefs.)
NPRR788 requires ERCOT’s RMR planning studies to include forecasted peak loads and that a potential RMR unit must have “a meaningful impact on the expected transmission overload” to be considered for an agreement.
At last week’s board meeting, Jeff Billo, ERCOT’s senior transmission planning manager, quantified “meaningful impact” as the unloading effect a potential RMR unit would have on the transmission constraint. The unit would also need a shift factor of at least 2% and an unloading factor of at least 5% on the constraint.
“I recognize we need to make improvements in the contract analysis surrounding RMR agreements,” said American Electric Power’s Wade Smith, whose company opposed the Technical Advisory Committee’s endorsement of the NPRR. “We need to continue to work on our planning and … build transmission solutions quickly.”
Beth Garza, director of ERCOT’s Independent Market Monitor, pegged Greens Bayou’s contract — projected to cost the market $63.9 million over the course of its 25 months — as equivalent to almost 18 hours of firm load shed in the Houston area, assuming a $9,000/MWh cost of load curtailment.
“If I drive a $10,000 car, it’s ridiculous for me to pay $10,000 in premiums for the full replacement of that car,” Garza said. “Frankly, I believe the decision we made on this RMR unit is to pay the full replacement cost — the full value of the potential risk of load shed — for this unit.”
Garza noted that the Public Utility Commission of Texas has opened an RMR-related rulemaking that offers guidelines mitigating involuntary load curtailment (45927). The PUC will hold a public hearing on the issue Nov. 30.
“So things are ripe for discussion at the commission and ERCOT,” she said.
Board Approves West Texas Tx Projects
The board approved a pair of transmission projects addressing reliability concerns in West Texas resulting from load growth in the Permian Basin oil fields. The Texas-New Mexico Power rebuild of 69-kV facilities to 138 kV is projected to cost $50.6 million, while the AEP-Oncor 54-mile, 138-kV line is estimated to cost $77 million. The latter project passed with one abstention.
Luminant, TXU Energy Provisions OK’d
The board also unanimously approved staff’s acceptance of Texas Competitive Electric Holdings’ (TCEH) request that its Luminant and TXU Energy companies not be recognized as affiliates of any ERCOT member companies. The vote clears the way for the subsidiaries to seek a corporate membership in the ISO’s independent generator segment and an associate membership in the independent retail electric provider segment, respectively, replacing their prior memberships.
Jorge Bermudez, who resigned as an unaffiliated member of the board two weeks ago, made his presence felt with his absence. (See “ERCOT’s Bermudez Resigns from Board Position,” ERCOT Briefs.)
Because ERCOT’s legal staff determined Bermudez’s recent marriage made him ineligible to be on the board before its Aug. 9 meeting, the directors were forced to vote again on three items he moved in that meeting: the consent agenda and two proposals related to the ISO’s 401(k) plan.
Bermudez’s tenure will be celebrated during December’s annual meeting, when all directors leaving the board are honored for their service.
Board Approves 14 NPRRs, Other Changes
The board unanimously approved NPRR760, which received opposing votes from American Electric Power and Luminant last month and abstentions from CenterPoint Energy and Sharyland Utilities. The change ensures that operating days with no activity are captured in the calculation of credit variables.
The consent agenda included 13 additional NPRRs, three revisions to the Planning Guide (PGRRs) and a revision to the Retail Market Guide (RMGRR).
NPRR755: Allows an entity to register as a data-agent-only qualified scheduling entity (QSE) to connect to ERCOT’s wide area network (WAN) as an agent for another QSE, without meeting applicable collateral and capitalization requirements.
NPRR769: Clarifies the alternative-dispute resolution process to note the proceeding is the next level of appeal following ERCOT’s denial of verifiable costs. Also clarifies the confidentiality of data submitted in connection with a verifiable-cost appeal.
NPRR775: Strengthens the limits on fast responding regulation service (FRRS) to address future operational issues. A previous revision request (NPRR581) added limits of 65 MW to FRRS up and 35 MW to FRRS down but lacked implementation details regarding self-arrangements in the day-ahead market and restrictions on providing the service in real time without a day-ahead award.
NPRR778: Changes competitive retailer rules regarding move-in or move-out date changes to prevent inadvertent errors. The change should eliminate two-thirds of manual interventions currently required.
NPRR779 and PGRR048: Clarifies references to the Texas Reliability Entity (Texas RE) and the Market Monitor. Current protocols refer to the Texas RE in both its capacity as the Regional Entity and the Public Utility Commission of Texas Reliability Monitor. The NPRR also removes the 24-hour deadline for ERCOT to notify the reliability monitor of a failure to provide ancillary services. The new language clarifies that the Market Monitor is an included party in several provisions related to the ERCOT stakeholder process.
NPRR781: Addresses the market’s growing use of advanced metering systems (AMS) by updating protocol language to clarify purpose and definitions, update processes and methodologies and remove outdated ones.
NPRR782: Removes inconsistencies in protocol language by changing the equations governing the settlement of ancillary services. The change affects resources unable to deliver on their ancillary service obligations because of transmission constraints.
NPRR785: Allows ERCOT to automatically prepopulate current operating plans (COP) for wind and photovoltaic resources with the most recent forecast for the next 168 hours. QSEs representing these resources can either submit the prepopulated forecast as the COP by default or submit a lower number.
NPRR786: Corrects the allocation of transmission losses, distribution losses and unaccounted-for energy (UFE) so that negative loads do not result in the loss of UFE allocations.
NPRR787: Removes the requirement that the QSE receiving a verbal-dispatch instruction confirmation include the name of the individual that received the confirmation within the electronic acknowledgement.
NPRR789: Requires ERCOT to publish all its midterm load forecasts for market participants and note which one is currently being used by operations. The ISO currently publishes several forecasts per weather zone but only makes one at a time available to the market.
NPRR793: Adds several responsibilities for RMR unit owners, revises RMR formulas and makes other clarifications to ensure RMR units are not accidentally committed as a reliability unit before other resources.
NPRR795: Creates a mechanism to refund capital expenditures funded by ERCOT under an RMR agreement.
PGRR047: Requires energy developers seeking an interconnection agreement to include among their materials a signed affidavit that they have notified the Department of Defense of their proposed project and have requested a review.
PGRR049: Removes the option to submit generation interconnection or change request (GINR) applications through standard mail or fax and updates the mailing address for GINR payments to ERCOT’s treasury department.
RMGRR134: Gives non-modeled generators the option to use the AMS data-submittal process and clarifies processes for unregistered distributed generation versus registered non-modeled generators.
VALLEY FORGE, Pa. — PJM is considering giving demand response participants injection rights in its effort to expand distributed energy resources’ access to wholesale markets.
The effort is being overseen through special Markets and Reliability Committee sessions that began in April. At the most recent session last week, PJM officials discussed what they called “demand response with injections,” a practice ISO-NE has been using since last year.
PJM’s interconnection rules restrict DER system designs and limit their full capability use. | A.F. Mensah
DR resources eligible to inject past their meters would have to do so without creating problems for the distribution system. To avoid double counting, DR resources would not receive payments for regulation or synchronized reserves if they are reducing their energy bills through net energy metering (NEM).
Accounting, Jurisdictional Questions
Allowing DR injections raises jurisdictional and accounting questions, PJM said. If DR is treated as a non-wholesale energy injection akin to NEM, “does the DR resource get paid LMP and keep the NEM credit? Does PJM adjust the energy payment to the DR resource to reflect NEM credit? Does the [load-serving entity] keep the cost reduction?”
PJM’s Aaron Berner also reviewed the small generator interconnection process and whether the alternate queue for small projects should be eliminated or modified. The proposals, presented by Berner, included an alternative queue process designed to reduce the study and review times as well as a reorganization of grid-upgrade cost allocations for projects costing less than $5 million.
The sessions are in response to a problem statement brought by battery storage system designer A.F. Mensah, which was approved by stakeholders in February. (See “Faster Path to Market for Distributed Resources to be Studied,” PJM MRC & Members Committee Briefs.)
In the problem statement, A.F. Mensah outlined the limitations created by PJM’s current market participation rules that require battery systems to commit to a single purpose rather than provide multiple services. To participate in PJM’s markets, versatile resources like battery systems must choose to interconnect either as a generation resource through the RTO’s standard queue or as a DR resource.
Cost Prohibitive
The standard queue is cost prohibitive, requiring a long review and analysis process, along with requirements to install redundant equipment that increase each project’s complexity and cost. Additionally, that path limits storage systems to participating in the wholesale market, so retail customers with small-scale renewable systems, such as rooftop solar or residential-size wind turbines, have to account for each system separately and can’t store renewable power created now to offset demand later.
However, the DR pathway only allows resources to offset their owners’ current demand, which negates renewables’ ability to provide power to the grid when they are producing more than the system owner needs.
“Distributed resources are often installed as part of a wider behind-the-meter system, which includes solar panels that produce more power than consumed by the load on an instantaneous basis,” A.F. Mensah wrote in the problem statement. “The provision limits the DR value opportunity based on the amount of instantaneous load, which therefore severely limits the value the DR resource can provide to the market.”
PJM’s issue charge set up the special MRC sessions in acknowledgement of no other cross-committee forum existing to address the topic.
‘Next Wave’
“I can see DER participating in PJM as the next wave of a resource that at some point is going to reach critical mass,” said Dave Pratzon, who consults for generators and energy marketers. “It’s going to have to be dispatchable. PJM’s going to have to know its output. I think that part of the work of this group has to be forward looking.”
PJM also presented its initial considerations on the topic, suggesting there could be a hybrid rule. Calling it “demand response with injections,” PJM’s Andy Levitt said ISO-NE instituted a similar rule in 2015 that allows load to “go negative” — i.e., inject excess generation into the grid. This model would necessitate changes to accounting and settlement procedures to ensure participants are paid appropriately.
PJM staff asked if stakeholders would allow them to focus on one issue, such as allow DR injections for ancillary services, so as to not overload the committee and “boil the ocean,” as MRC secretary Dave Anders put it. Stakeholders, however, didn’t want the other issues to be forgotten and said ancillary services might be one of the harder issues to address.
“I don’t think this is a quick one that we can overlook in a hurry,” FirstEnergy’s Bruce Remmel said. “It complicates itself quickly.”
PJM staff are analyzing the feedback from the meeting and will be presenting recommendations on how to proceed. The next meeting on the issue is scheduled for 9 a.m. Nov. 22 at PJM’s Conference and Training Center.
LITTLE ROCK, Ark. — Kansas City Power & Light’s proposal for addressing cost shifts led to a free-wheeling discussion on transmission pricing and the unintended consequences of proposed Tariff changes at SPP’s Strategic Planning Committee meeting Thursday. It ended with the committee agreeing to defer action pending an alternative proposal by the RTO.
Revision request RR172 would create a process for determining where to place a new SPP transmission owner’s facilities and how to submit the owner’s annual transmission revenue requirement (ATRR) or formula rate to FERC for inclusion in the Tariff. It would also create a 365-day review period before the new TO could seek FERC approval of its revenue requirement.
The committee accepted SPP CEO Nick Brown’s suggestion to allow staff to propose “straw” Tariff language or a business practice and bring it back to the SPC in January. “Staff certainly has a decade and a half of dealing with this issue on a case-by-case basis,” said Brown, adding staff would take stakeholder input into consideration and support both that recommendation — “based on experience, FERC precedent and what we believe is the best overall solution” — and why it didn’t recommend alternatives.
At the same time, several stakeholders will continue work on the revision request.
Sponsor Surprised
Denise Buffington, KCP&L’s corporate counsel and director of energy policy, said she was surprised the request came before the SPC, complaining she wasn’t notified or given a chance to present the revision request to the committee.
Buffington said the proposal was a response to her company having been “blindsided” by SPP’s decision to put the City of Independence, Mo., in its transmission pricing zone.
“That was a $4.6 million cost shift to our customers,” she said. “Our main concern is the historic cost of entities paid for by historic customers. We’re more than willing to share in the costs of anything that’s planned for and goes through the SPP process. What we think is patently unfair is for someone to build out their system and then come to SPP and socialize the costs.”
Heather Starnes, counsel for the Missouri Joint Municipal Electric Utility Commission (MJMEUC), spoke for the non-jurisdictional and smaller entities, which could face hold-harmless obligations should they be placed in an existing transmission zone as a sub-zone. She noted forcing smaller TOs into their own pricing zones can cause difficulties, using City Utilities of Springfield’s struggles with SPP’s highway/byway cost allocation as an example.
“If [a city] had transmission facilities and decided to put them under SPP’s Tariff, SPP would look at the size of the load and, based on internal criteria, decide whether it goes into a new zone or an existing zone,” Starnes said. “If it’s placed in an existing zone, [the city] would be required [under the proposed revision] to hold everyone else in that zone harmless.”
‘What’s the Benefit?’
“If the small entities have to bear the entire cost of their ATRR and then [base-plan funding], what incentive is there for these small entities to join SPP if it only adds obligations, including losing functional control of their facilities?” Starnes asked. “What’s the benefit?”
“This is a cost shift, or a question of who bears what costs,” said Oklahoma Gas & Electric’s Jake Langthorn. “There are many areas where we’ll have the question come up over which zone should pay. I think it’s time to see how a postage-stamp rate affects everyone. If we had it, frankly, most of these problems would disappear.”
On Monday, a still-frustrated Buffington said SPP “hijacked” the stakeholder revision-request process by pulling RR172 from the Regional Tariff Working Group and placing it on the SPC’s agenda. She said KCP&L, as the sponsor, was not given the opportunity to present the revision request to the committee, and that the background document prepared by SPP staff only included comments from South Central MCN, one of seven opponents to the proposal, and none from its three supporters.
“No one else was given that opportunity,” said Buffington, noting the RTWG’s minutes do not indicate a vote sending RR172 to the SPC. “This whole process runs counter to the existing revision-request process.”
“While no vote was taken, the Regional Tariff Working Group understood RR172 policy issues would be considered by the SPC,” SPP Chief Compliance and Administrative Officer Michael Desselle said on Tuesday. “Because the RTWG does not make policy, they agreed to defer discussion of RR172 until after the SPC’s discussions.”
Buffington said she would work with Starnes and ITC Holdings’ Marguerite Wagner to revise the revision request. “I don’t think we’re that far apart,” she said, reserving her right to bring new language back and rebut staff’s proposals to the SPC in January.
“This is the kind of discussion I was hoping we would have at this level,” said South Central MCN’s Noman Williams. “In my view, it’s a change of policy … [that] needs to be done. We need to come together and define the policy as a group.”
“This still leaves us options to consider how this might be resolved,” SPP Director Phyllis Bernard said, tossing out postage-stamp rates as one alternative. “These are conversations we’ve been having as of late, but it hasn’t made it to the table or in the record, but I think it’s reaching critical mass.”
ALBANY, N.Y. — New York regulators on Thursday refined their rules on how municipalities can aggregate customers to purchase gas and electricity and rejected a request that the program abandon its opt-out structure (14-M-0224).
| Wikipedia
The New York Public Service Commission’s Community Choice Aggregation program is part of the state’s Reforming the Energy Vision initiative to encourage the greater use of cleaner and distributed energy resources. The CCA was approved in April, building on a pilot program that was still being organized but did not fully launch until June. (See NYPSC OKs Municipal Aggregation for Energy Purchases.)
Opt-In vs. Opt-Out
The commission rejected complaints that the CCA program is premature. “Given the potential benefits of CCA programs, and the continued operation of retail energy markets while the commission considers further action, delaying the authorization of CCA programs is unnecessary and even potentially harmful,” the order said.
Thursday’s order denied National Fuel Gas Distribution’s request to switch the CCA from an opt-out to an opt-in process. The company said the PSC should require customers to opt into the program because uncertainty exists over the development of the retail market.
In an opt-out program, all customers are enrolled and, after an outreach program run by the municipality is launched, customers are required to notify it if they want to remain with the host utility.
“If we required opt-in, we’d be killing this idea before we gave it a fair chance to succeed,” Commissioner Gregg Sayre said at the PSC’s Thursday meeting.
“Our experience in the retail market and in other states is that the opt-out is necessary for CCA programs to be successful,” Assistant General Counsel Ted Kelly said. New Jersey’s aggregation program failed to gain traction until it switched from the opt-in model, he said.
New York City Wins Clarification
The commission also granted New York City’s request for clarification that the original order did require the CCA to be implemented citywide. The commission agreed with the city that rolling out a new program in large geographic areas with dense populations would prove unwieldy, allowing the city to introduce the changes in stages.
The PSC said the CCA order was intended to provide municipalities flexibility. “Allowing municipalities to implement CCA programs on a partial or phased basis is consistent with this design. Municipalities may choose a partial or phased approach as a pilot of CCA, to manage the implementation process given a large geographic footprint or overlapping jurisdictions, or for another reason beneficial to their program,” the commission said.
The commission also clarified that each implementation plan submitted by a municipality or CCA administrator will be open to public comment and said utilities can exclude customers’ phone numbers from data sent to municipalities, bowing to privacy concerns. The PSC said a multicounty CCA has been proposed by the Municipal Electric and Gas Alliance to eventually serve roughly 500,000 residents in 11 counties from the Finger Lakes to the Hudson Valley.
Westchester Pilot Operating
Meanwhile, the state’s first pilot program, by Sustainable Westchester, has been operating for three months, officials said.
The pilot, dubbed Westchester Power, has about 91,000 customers in more than 20 municipalities. Westchester Power has negotiated to buy electricity at a bulk, fixed price and started enrolling customers in June.
LuAnn Scherer, acting director of the PSC’s Office of Consumer Services, said the commission asked Consolidated Edison to provide an early glimpse of consumer reaction. The company sampled about 1,500 customers. While savings are not guaranteed, customers have saved an average of $10/month in the pilot program, Scherer said.
She said the program has received 14 complaints, mostly related to customers misunderstanding some line items on their new utility bills.
“One of the lessons is that municipalities are going to have to do more for customer education,” Scherer said.
Sustainable Westchester’s first report to the PSC is due in June 2017.
“It’s early, but at least we know we’re headed in the right direction,” PSC Chair Audrey Zibelman said.
Commissioner Diane Burman – who opposed the original CCA order, saying a statewide rollout was premature – abstained Thursday. “While my concerns still are there, I do embrace working through them in a robust way on the work ahead,” she said.
FERC last week rejected MISO’s attempt to exempt external generators from interconnection milestone payments, saying the fees should be applied equally to all classes of customers (EL16-12, et al.).
MISO had exempted from its M2 milestone payments external network resource interconnection service (E-NRIS) customers and NRIS-only customers. NRIS allows a generator to deliver power over MISO’s grid with the same rights as any other network resource. E-NRIS service allows generators outside the RTO to participate in capacity auctions and deliver their output into the system.
MISO said the M2 payment should not be assessed to E-NRIS customers because it is intended to deter speculative projects and is refunded once a generator begins commercial operations. E-NRIS customers are either in-service, under construction or have an executed interconnection agreement with the transmission provider to which they directly interconnect.
MISO’s position was challenged last year by EDF Renewable Energy, E.ON Climate & Renewables North America and Invenergy, which contended the RTO’s policy created a competitive disadvantage for new internal generation, which is required to make the milestone payments.
In its order last week, FERC said MISO’s defense that the M2 milestone payment was only needed to deter speculative projects was unconvincing.
“To the contrary, we find that the reduction of late-stage terminations and the resultant restudies, as well as the mitigation of potential cost increases to lower-queued customers due to any restudies, are equally important goals of the M2 milestone payment,” the commission said.
“We find that it is just and reasonable that all interconnection customers post the M2 milestone payment in order to protect other customers from the potential harm that any interconnection customer may cause by a late-stage withdrawal,” it added.
FERC gave MISO 30 days to make the Tariff changes and set an April 5, 2016, refund date.
In a separate order, the commission also rejected MISO’s request for rehearing on the basis that existing and external customers are not “similarly situated” to other interconnection customers and forcing them to pay the milestone payment would be fraught with “practical difficulties” (EL15-99, et al.). FERC said its April order “only found that it may be unduly discriminatory to exempt existing generators” and did not constitute a final determination, so it could not be challenged.
LITTLE ROCK, Ark. — SPP’s Strategic Planning Committee on Thursday endorsed the Competitive Transmission Process Task Force’s recommendations for improving the competitive solicitation process for transmission projects under FERC Order 1000.
SPP’s first run-through of its transmission owner selection process resulted in the award of a competitive project, only to have the project’s notice-to-construct (NTC) withdrawn in July because of falling load projections.
The task force recommended raising the minimum threshold for competitive projects from $100,000 to $3 million, seating the selection panel sooner and requiring it to quickly publish its selection criteria. It also said SPP should allow restudy requests before an NTC is issued. The SPC unanimously approved all the recommendations.
The SPC also approved using a consistent template for annual transmission revenue requirement (ATRR) responses, based on the expected rate recovery under the SPP Tariff.
Much of the remaining work will be handed off to other stakeholder groups and SPP legal staff, who will draft the revision requests, revise business practices, prepare FERC filings and revise the ATRR template. The finished products are scheduled to be brought to the Markets and Operations Policy Committee in January.
The task force’s chair, Bill Grant of Southwestern Public Service, said the group discussed a higher threshold before settling on $3 million. SPP Director Harry Skilton proposed a $5 million threshold, with the idea that FERC would accept a lower number.
“The risk in starting out with a high number is that FERC flat out rejects it and sends it back to you,” Sunflower Electric Power’s Tom Hestermann said.
Board Chair Jim Eckelberger said he was comfortable with the lower $3 million threshold, assuming it’s “defendable.”
“I think that number is defendable, because that’s what we’re going to spend just to seat the [selection] panel,” Grant said, referring to the $300,000 projection to train and seat the industry expert panel (IEP). A company bidding on competitive projects is required to put down 10% of the project’s cost — $300,000 for a $3 million threshold.
Grant said seating the IEP early in the solicitation process and requiring the panel to publish its scoring criteria as early in the process as possible would allow transmission companies to submit more focused bids, reducing potential cost variances.
| SPP
The task force determined developing “a more robust” ATRR template that includes special modeling needs for various business models would negate the need for a standard, regionwide formula rate. The template will include incremental costs specific to the RFP project.
“My biggest concern is not the highway projects this will be applied to. My biggest concern is with the byway projects,” Grant said. “When you evaluate based on incremental basis, everyone’s on the same playing field.”
The withdrawal of the NTC on SPP’s first Order 1000 project, a 115-kV line from Walkemeyer to North Liberal in southwest Kansas, led to the recommendation that the solicitation process be suspended to allow for re-evaluations in the case of a significant load change. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)
“Under the Tariff, the developer had to get an NTC before it could be re-evaluated,” Grant said. “If there’s been a substantial change, we don’t want to have to wait to go through the RFP process and get an NTC.”
FERC last week agreed to consider whether the failure of some power sellers to file compliant price reports contributed to unreasonably high rates for long-term electricity contracts filed during the Western Energy Crisis of 2000-2001 (EL02-71-052).
| FERC order EL02-60-007, April 12, 2016.
The case, which involves Shell Energy North America, TransCanada Energy, Koch Energy Trading, Allegheny Energy Supply, Merrill Lynch Capital Services and other sellers of energy and ancillary services into the CAISO market during the crisis period, was remanded to FERC last year by the 9th U.S. Circuit Court of Appeals (12-71958).
FERC’s decision breathes life into California’s contention that reporting deficiencies may have helped conceal market manipulation and create a “pricing umbrella” under which California’s Department of Water Resources was compelled to sign overpriced contracts near the conclusion of the crisis.
“We agree with California parties that evidence regarding a pricing umbrella theory could be relevant to the 9th Circuit’s instructions on remand to examine the nexus between reporting deficiencies, market power and market outcomes, including evidence of how reporting deficiencies may have masked manipulative behavior by sellers,” the commission wrote.
The California parties — which include the Public Utilities Commission, Attorney General Kamala Harris, Pacific Gas and Electric and Southern California Edison — asserted that the sellers’ quarterly reports did not meet requirements during the crisis period because they contained no hourly transaction detail or any information on the timing or location of the trades. The reports provided only aggregate quarterly or monthly sales data along with a range of prices, the parties contended.
As a result, FERC will allow California to introduce relevant evidence at a future hearing — evidence that could “provide greater context and depth” into the examination of factors that enabled sellers to charge the state exorbitant rates.
Mobile-Sierra Caveat
Embedded in FERC’s ruling, however, was one important qualification: that the commission disagreed with the state’s contention that evidence of a reporting violation alone could overcome the Mobile-Sierra presumption of the “justness and reasonableness” of any of the bilateral contracts at issue.
“The Mobile-Sierra analysis requires more than just an unlawful act,” the commission said.
In support of that determination, the commission cited the Supreme Court’s 2008 decision in Morgan Stanley Capital Group Inc. v. Public Utility District No. 1 of Snohomish County, which stated that a contracting party’s engagement in unlawful activity in the spot market does not automatically strip its forward contracts of Mobile-Sierra protections.
“We find that the California parties’ argument, if accepted, would require us to abrogate the contracts at issue based solely on an unlawful act itself (i.e., the misreporting), without the required causal connection between an unlawful act and an unjust and unreasonable rate, as required by the Supreme Court,” the commission wrote.
In the words of the 9th Circuit, the commission concluded, the purpose of the remand is to determine whether “reporting deficiencies fostered the subtle accumulation of market power and resulted in an excessive rate.”
LITTLE ROCK, Ark. — Heather Starnes, counsel for the Missouri Joint Municipal Electric Utility Commission, briefed the Strategic Planning Committee on Thursday on the work that the Billing Determinant Task Force she chairs has done in developing a business practice for behind-the-meter generation.
The task force has produced a revision request (BRR158) that sets guidelines to determine a customer’s network load and define the parameters for what should be considered BTM generation.
However, the Regional Tariff Working Group remanded the change back to the task force in June to address SPP’s request to delineate responsibility for reporting network load. With the consolidation of SPP’s legacy balancing authorities into one, Starnes said the RTO has been having difficulty gathering complete zonal information from the transmission zones’ lead transmission owners.
“SPP’s position is they would like to see something created that mimics what it did before we created the consolidated balancing authority,” she said.
Under the revision, network load would include all network service, including the sum of generators’ metered values behind the delivery point. If the generator’s meter data is not available when it’s online, network customers would use its nameplate rating.
Starnes said the task force meets later this week and hopes to send BRR158 back to the RTWG for final consideration.
LP&L Task Force Looks at Precedent
SPC Chair Mike Wise, senior vice president of commercial operations and transmission for Golden Spread Electric Cooperative, encouraged the task force studying the migration of Lubbock Power & Light’s load to ERCOT to identify any strategic implications of the municipality’s exit. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)
“This is an entirely new study process,” he said.
“Certainly there are broader implications beyond just Lubbock,” said Oklahoma Gas & Electric’s Jake Langthorn, the Exit Study Task Force’s chair. “It’s kind of an absence of facts … no one’s given much more thought at this point to what happens, but we’ll certainly pursue that as well.”
SPP and ERCOT are conducting separate studies on LP&L’s proposal to move 430 MW of load into the Texas market in June 2019. The grid operators will file a joint report to the Public Utility Commission of Texas next spring, though it has yet to be determined who will pay for the studies.
“Where’s Lubbock?” one member asked pointedly. PUC Chair Donna Nelson has said she doesn’t believe ERCOT ratepayers should pay for the studies, a sentiment shared in ERCOT.
“I didn’t get the sense from anyone in the group that SPP should pick up the costs,” Langthorn said. “We believe the party that wants to get it done, Lubbock, should pick up the costs.”
Judge Recommends Pause To TEP’s Rooftop Solar Plan
An administrative law judge has recommended that state regulators defer approval of Tucson Electric Power’s plans to expand company-owned solar energy programs pending findings of a separate proceeding on the value of rooftop solar.
As part of a renewable energy plan filed last year, TEP wants to expand a program in which it installs solar panels on the roofs of customers who pay a flat monthly fee for power. It also seeks to build neighborhood-scale solar farms and offer nearby customers the power at a flat rate.
Judge Jane Rodda found that expansion should wait until the results of technical studies and potential modifications to net metering tariffs are known.
SolarCity Spent $140K on Corporation Commission Election
SolarCity last week disclosed that it has spent $140,000 on an independent campaign to re-elect Republican Bob Burns and elect Democrat Bill Mundell to the Corporation Commission.
The commission is expected to decide as early as 2017 the rate structure for utility customers who generate some of their own power through solar. The disclosure comes as the commission debates whether to force Arizona Public Service, which is fighting net metering in the state, to disclose how much it spent to influence the election of two Republicans to the commission. Burns has issued a subpoena to APS for its records, but the state attorney general has said that would require a majority vote from the commission.
Mundell and fellow Democrat Tom Chapin have said they would deliver the necessary votes if elected. But Mundell last week lamented the spending on both sides. “I wish everyone would stay out of the race,” he said.
SoCalGas Down to Final Safety Tests at Aliso Canyon
Southern California Gas is nine safety tests away from reopening its Aliso Canyon natural gas storage facility in Los Angeles, which it shut down in October 2015 following a massive methane leak.
The state Division of Oil, Gas and Geothermal Resources must approve the company’s safety testing of 114 wells at the facility before SoCalGas can request authority to resume injecting fuel into the field.
Twenty-seven wells have passed all safety tests, nine await results and 78 are temporarily out of operation, according to a report issued by SoCalGas in early October.
Environmentalists May Receive $72K ‘Interveneor’ Award in San Onofre Case
Environmentalist group Friends of the Earth could receive $72,000 for participating in the investigation of the San Onofre nuclear plant failure, making it the most recent recipient of so-called “intervener” funds. If approved by the Public Utilities Commission, the award would be significantly less than the $483,503 the group sought.
The commission has awarded more than $600,000 to participants in the case, which is the subject of a criminal investigation into improper contacts between regulators and utility executives.
The intervenor compensation program awards money to groups that contribute meaningfully to commission decisions. The program is funded by utility companies, which pass the cost along to customers.
‘Wiring Error’ Blamed for Flare-Off at Torrance Refining
| Source: Torrance Refinery
A “wiring error” associated with an ongoing equipment upgrade project in the South Bay has been blamed for a flare-off last week at Torrance Refining and a power outage affecting some 100,000 Southern California Edison customers.
Torrance Refining was shut down and partially evacuated, according to the Torrance police and fire departments.
Power was restored to the affected customers in parts of Gardena, Hawthorne, Hermosa Beach, Manhattan Beach, Redondo Beach and Torrance.
Committee Recommends Monterey County Join Power Collaborative
Monterey County’s alternative energy and environmental committee took initial steps last week to take local control over electric power purchasing from Pacific Gas and Electric and promote renewable energy.
The committee recommended that its Board of Supervisors sign a resolution to join the Monterey Bay Community Power agency. The agency calls for a collaborative, including Santa Cruz, Monterey and San Benito counties, which would combine their purchasing power to increase renewable energy in their portfolio and use savings from lower-cost power to invest in renewable energy projects.
If the board approves the resolution, the county could start developing a governing joint powers authority agreement and address financing.
Villages Agree to Joint Defense, Confidentiality for Power Line Fight
| Source: Wikipedia
Five villages bordering the Elgin-O’Hare Expressway are fighting a proposed Commonwealth Edison power line project and have agreed to individually approve a joint defense and confidentiality agreement.
Leaders in Schaumburg, Elk Grove Village, Hanover Park, Roselle and Itasca claim that the West Central Reliability Project, which calls for a transmission line stretching about 9 miles between substations in Bartlett and Itasca, would lower property values and create unpleasant views without serving their residents and businesses.
ComEd spokesman David O’Dowd said he wasn’t familiar with any precedent for similar agreements.
Residents overpaid more than $125 million for power for the 12 months ending in May 2016, according to an annual report issued by the Commerce Commission.
Residents of municipalities that contracted with alternative electrical suppliers other than Ameren and Commonwealth Edison rarely saved money.
Customers who used alternative carriers overpaid an average of $57 more per year, compared with rates offered by ComEd, the report found. Ameren customers using alternative providers largely broke even depending upon where they lived in the state.
Covanta will receive $562,000 in Pittsfield Economic Development funds to upgrade its solid waste-to-energy and recycling facility to meet state and federal environmental standards and remain profitable.
The Pittsfield City Council approved the funds to pay for a state-mandated recycling enclosure and upgrades to Covanta’s fossil fuel boiler.
Covanta, which had announced in July that it planned to close the facility, will sign a four-year contract extension with the city until June 2020.
Regulators Approve Shutdown of Xcel’s Coal-Fired Generators
State regulators approved last week Xcel Energy’s plans to shut down its coal-fired Sherco plant by 2026 but rejected the company’s plan to build a large gas-powered generation plant on the site as a partial power replacement.
The Public Utilities Commission asked Xcel to explore renewable energy options in conjunction with its proposed gas plant. The commission also told Xcel to consider more demand-side management.
The Sherco plant generators are the state’s largest emitters of greenhouse gases.
Community solar took a step forward last week when the Public Service Commission approved Ameren’s proposal to build one, and possibly two, 500-kW solar arrays, which could provide residential and small business customers with up to half their energy.
Ameren has indicated that it will not begin construction on the first array until it is fully subscribed.
“I think it sends a very good signal to industry and consumers that utilities are starting to invest more in renewable energy, and are allowing customers to invest in it also,” said Caleb Arthur, chief executive officer of Missouri Sun Solar and president of the Missouri Solar Energy Industries Association.
Data company Switch filed a September application with the Public Utilities Commission seeking to bypass middle-man NV Energy when it powers a new industrial center it is building in Storey County.
Switch wants to go competitive and have a choice in the energy market, according to Adam Kramer, executive vice president of strategies.
The company, which powers all its facilities with 100% renewable energy, is presently in litigation against the Public Utilities Commission and NV Energy over a ruling denying its application two years ago to leave the utility.
Voters Seek to Invalidate Energy Choice Ballot Question
Two voters filed suit in Carson District Court to invalidate a ballot question intended to deregulate the state’s energy market regardless of whether voters approve retail choice on Nov. 8.
The question “directs the Legislature to enact legislation providing for the establishment of an open, competitive electricity market by not later than July 1, 2023.”
The lawsuit claims that the ballot question improperly binds the Legislature and governor by mandating they enact specific legislation.
Four protesters carrying food, water and sleeping bags locked themselves inside the Algonquin Incremental Market Project pipeline for 16 hours last week at a worksite near the Indian Point nuclear power plant.
The protest, which coincided with Columbus Day (or Indigenous Peoples’ Day), showed solidarity with groups like the Standing Rock Tribe, which is protesting the Dakota Access oil pipeline.
Regulators Predict Decrease In Natural Gas, Energy Prices
| Source: Public Service Commission of Wisconsin
State regulators predicted natural gas and electricity will be cheaper this winter compared with recent years.
The average residential electric customer will pay 14% less than the five-year winter average, while gas bills will be 10% less, according to an analysis by the Public Service Commission.
Notwithstanding, the commission predicts heating bills will be slightly higher this winter compared with last year because of last year’s unseasonably warm weather.
Developers are expected to build some 4 GW of commercial-scale solar panel capacity in the state by the end of the decade, up from 559 MW this year, according to a report issued last week by Bloomberg New Energy Finance.
The report predicts that by 2020, solar power will cause a $2.58/MWh price drop during peak hours in the state’s west hub.
“Just having this new influx of daytime energy production is going to bring down energy prices on average during the day,” said Nicholas Steckler, an analyst at BNEF.
Regulators Approve $15.6M Decrease for Electricity Customers
The Public Service Commission approved a $15.6 million rate decrease for Rocky Mountain Power’s electricity customers after the utility beat forecasted fuel and electricity costs. The overall rate decrease is 0.8%, which includes about $6.84 in annual savings for a typical residential customer.
Iberdrola Offers to Pay for Favorable Wind Project Vote
Iberdrola Renewables has offered to pay 815 registered voters in two towns $14.1 million over 25 years if a wind project consisting of 24 turbines that would generate 82.8 MW of power wins voter approval on Nov. 8.
Iberdrola is seeking to build the state’s largest wind project on land spanning Windham and Grafton.
The offer does not violate state law, said Michael O. Duane, senior assistant attorney general. “The proposal doesn’t say that the funds go only to those people who signed a sworn statement that they had voted for it,” he said.
For the first time in the U.S., state residents will vote in November on whether to levy a carbon tax on polluters for the greenhouse gases they produce.
The proposed tax would start at $15/ton beginning in July and jump to $25 in 2017. Incremental increases would follow.
A La Crosse County judge heard arguments last week on whether to uphold state approval of a high-voltage power line with a $580 million cost that will be passed on to MISO ratepayers.
The 180-mile line is a joint venture of American Transmission Co. and several regional utility companies. It was not presented to the state as a project necessary to meet supply demand, but rather as one that would make the electric grid more resilient and ultimately save ratepayers millions of dollars.
The town of Holland argues the project violates state law because the need for it was not established, the environmental review was insufficient and existing poles should be used to route it through the town.
Banks is Swift’s executive vice president and chief operating officer and will continue in those roles.
General Electric announced last week that it plans to spend $1.65 billion to acquire LM Wind Power, a maker of wind turbine blades.
Community solar took a step forward last week when the Public Service Commission approved Ameren’s proposal to build one, and possibly two, 500-kW solar arrays, which could provide residential and small business customers with up to half their energy.
Four protesters carrying food, water and sleeping bags locked themselves inside the Algonquin Incremental Market Project pipeline for 16 hours last week at a worksite near the Indian Point nuclear power plant.
A La Crosse County judge heard arguments last week on whether to uphold state approval of a high-voltage power line with a $580 million cost that will be passed on to MISO ratepayers.