FERC last week conditionally approved revisions to the MISO-PJM Joint Operating Agreement on cost allocation for cross-seam transmission projects, while denying rehearing requests from PJM and the RTOs’ transmission owners (ER13-1944, et al.).
In rejecting the rehearing requests, the commission said the grid operators and TOs chose the avoided-cost-only method for allocating the costs of such projects, so any issues that method creates should be addressed within the operators’ stakeholder processes.
In a previous filing, PJM and MISO settled on a cost-allocation method that is based on how much the cross-border project saves each grid operator on regional projects it supplants. The commission, however, said the method didn’t consider regional projects that have already been selected, nor did it explain how it would measure if an interregional project is more efficient or cost effective than a regional one.
Tie lines between MISO and PJM | PJM
MISO’s TOs asked for the rehearing because they were concerned that displacing projects that had already been selected wouldn’t allow them to recover millions of dollars in development costs incurred on those projects prior to them being abandoned. MISO’s Tariff, they noted, does not explicitly provide for such recovery.
“To the extent that MISO transmission owners are requesting that the commission mandate full cost recovery for transmission projects selected in a regional transmission plan but displaced by an interregional transmission project, we reject their request as outside the scope of the Order No. 1000 compliance proceedings,” the commission said.
“If MISO transmission owners continue to believe that these costs are not treated appropriately under MISO’s Tariff, they may pursue changes through the MISO stakeholder process and make a filing to amend the MISO Tariff or else file a complaint with the commission pursuant to [Federal Power Act] Section 206.”
FERC approved portions of the grid operators’ compliance filings, including how projects can be categorized, but it ordered additional changes to eliminate some inconsistencies. (See “MISO Order 1000 Compliance,” MISO Planning Advisory Committees Briefs.)
MISO and PJM have 30 days to make additional filings to fully comply with the order.
APS, SolarCity to Air TV Ads to Support Favored ACC Candidates
The fight between the parent company of Arizona Public Service and rooftop solar company SolarCity to elect their favored political candidates to the state Corporation Commission continues, as both are spending big to air advertising on television.
Pinnacle West Capital, which owns APS, is planning to spend $1 million through a newly formed political committee to get three Republicans elected to the five-member commission. SolarCity has spent about $1.4 million supporting one Republican and two Democrats, according to financial disclosures.
It is widely believed that APS spent $3.2 million in 2014 to help elect the present all-Republican commission — an allegation that APS has neither confirmed nor denied. The FBI confirmed in June that it is investigating APS and a former regulator for issues involving the 2014 elections.
State Ends Effort to Increase Natural Gas Capacity Following Neighboring Court Decisions
State officials announced last week that they are abandoning their effort to increase natural gas capacity through an upgrade to existing transmission pipelines owned by Spectra Energy.
The decision came after courts in Massachusetts and New Hampshire ruled that the cost of upgrading pipelines could not be passed along to ratepayers in those states.
“If you can’t spread the cost across the entire region, it doesn’t make any sense to continue on,” said Dennis Schain, a spokesman for the state’s Department of Energy and Environmental Protection.
Proposed Bill Asks Ratepayers for Up to $265M to Save Nuclear Plants
Exelon may be shuttering two of the state’s six nuclear plants beginning in 2017 unless ratepayers statewide pay up to $265 million per year to save them.
Representatives of the power giant and its subsidiary, Commonwealth Edison, are seeking to pass a bill in the Legislature’s November fall veto session that would save the Clinton plant from closure in 2017 and the Quad Cities plant from closure in 2018.
A draft version of the bill — which proposes the state’s most far-reaching energy policy changes since deregulation in 1997 — also would tap ratepayers to fund new wind farms, solar installations, programs to cut power consumption and other items.
Senate Could Vote in Two Weeks On Compromise Energy Bill
State senators could vote in two weeks on a compromise bill requiring state utilities to generate at least 15% of their electricity from renewable energy sources through 2012 — a 5% increase over what the law presently requires.
Additionally, the bill sets a goal that utilities achieve 35% of their power from a combination of renewable sources and energy efficiency savings by 2030. It also allows alternative energy suppliers to offer competing plans when utilities propose to build new power plants.
The bill ends a logjam between Republicans, who favor letting the market dictate utilities’ choices, and Democrats and environmental groups, who believe utilities will not pursue sources such as wind or solar without a statutory requirement.
NEP Solar Plant Lawsuit Against Aberdeen Postponed
A lawsuit over a solar plant that was to be built in Aberdeen has been postponed for 30 days to allow plaintiff National Energy Partners to retain new attorneys.
Belle
In December 2012, NEP signed a contract with Aberdeen to build a solar power system and sell electricity to the city over a 25-year period. In September 2014, NEP was assigned the rights for the project. Then-Mayor Cecil Belle subsequently canceled the contract when little progress was made over the next 12 months.
NEP argues that the contract required Aberdeen to make any complaints in writing and allow it time to correct any problems. The city argues that the contract — although signed by Belle — is invalid because the city board did not formally approve it.
Montana-Dakota Utilities has filed a request with state regulators for a rate increase of $13.4 million per year, which amounts to 6.6%.
MDU also asked the state Public Service Commission to implement within 60 days of its filing an interim rate increase, which would be subject to refund if the final authorized increase is less than the interim.
The utility cited increased investments in facilities, depreciation, operation and maintenance expenses and taxes as the reasons for the proposed increase.
Report: Clean Energy Policies Good for Job Growth, Consumers
Two national environmental groups issued a report last week forecasting that the state would gain tens of thousands of jobs and consumers would reap millions in savings if the state increases its support for clean energy policies.
The report, issued by the Nature Conservancy and the Environmental Defense Fund, came at a time when some Republican lawmakers are seeking to extend a two-year freeze on the state’s clean energy standards, which are scheduled to be lifted at the end of this year.
The report forecasts that by 2030 state support for clean energy policies would create an increase in jobs ranging from 82,300 to 136,000 and a reduction in consumers’ electricity bills ranging from $28.8 million to $50.9 million per year.
Utilidata, National Grid Strike Deal to Expand EE Technology
Technology company Utilidata has announced an agreement with National Grid for a statewide expansion of its energy-efficiency pilot program.
Utilidata has developed technology that lowers the voltage of electricity from substations to distribution lines. In 2013, Utilidata and National Grid signed a $500,000 deal for installation of the technology on its lines in Smithfield.
For this new agreement, the state Public Utilities Commission will need to approve the cost of equipment before National Grid can spend money, said David Graves, utility spokesman. The projected cost will be included in public documents when National Grid files its capital-expenses budget anticipated in late November, Graves said.
The state Public Utilities Commission has scheduled an evidentiary hearing for April 11-14 to determine what price NorthWestern Energy should pay for electricity from three of Juhl Energy’s wind farms.
Under the Public Utility Regulatory Policies Act, NorthWestern must purchase the electricity — but the companies sharply disagree as to the purchase price, which is supposed to be equal to what the NorthWestern would pay for the power through its own generation or bought from another source. Juhl calculated $60.70/MWh, while NorthWestern calculated $24.35/MWh.
The commission is willing to pay up to $38,000 to an outside consultant to assist with the pricing analysis.
Governor Candidates Differ on Where They’ll Go for Energy
Scott
Both major candidates for governor say they want to achieve the state’s goals of meeting 90% of its energy needs from renewable sources by 2050 — but differ sharply on where they won’t go for energy.
Republican Phil Scott said during a televised debate that he would veto any bill calling for a tax on carbon-based fuels. He also does not want to see more wind power turbines on the state’s mountaintops.
Democrat Sue Minter said during the debate that she would not rule out a carbon tax to reduce emissions if other Northeastern states joined in. She does not want more fossil fuel pipelines, but she has said a new technology for “decarbonized natural gas” under development by a California utility could possibly change her position.
PacifiCorp reaped more than half the $26.16 million in gross benefits yielded by the Western Energy Imbalance Market (EIM) during the third quarter, market operator CAISO said in a report released Wednesday.
| CAISO
The Portland-based utility earned $15.1 million in benefits — versus $5.6 million for NV Energy and $5.4 million for the ISO. Last quarter, PacifiCorp took in a 45% share.
The EIM’s total benefit increased by $2.56 million over the second quarter.
The benefits represent either cost savings — for example, the reduced need for reserves and greenhouse gas credits — or increased profits from merchant operations. The market’s ability to reduce curtailments also enables participants to collect renewable energy credits that would not otherwise be issued.
The benefits calculation nets out inter-balancing authority area (BAA) transfers that were scheduled ahead of the EIM’s 15- and five-minute market runs to avoid attributing contracted flows to the market.
Transfers from the PacifiCorp East (PACE) BAA into NV Energy’s territory increased sharply during the period, as did transfers from NV Energy into CAISO — reversing a pattern seen during the previous quarter, when California was able to export a significant volume of surplus solar generation because of low springtime loads.
The drop-off in exports was largely a function of the change in seasons, Khaled Abdul-Rahman, the ISO’s director of power systems and smart grid development, told the Board of Governors during an Oct. 27 meeting. “This is because of increased [summer] load,” which absorbed more solar production, he said.
Even in their reduced state, those exports enabled the ISO to avoid curtailing 33,094 MWh of renewable generation.
CAISO also touted the EIM’s impact on the procurement of flexible ramping capacity — resources equipped to respond to the variability of intermittent generators.
Because variability can decrease in one BAA at the same time that it’s increasing in another, the EIM enables its participants to share flexible resources — allowing each BAA to procure fewer resources than would have been necessary on a standalone basis. These “flexible ramping procurement savings” were about 35% of total savings during the third quarter, the ISO reports showed.
The next quarterly report will include figures for Arizona Public Service and Puget Sound Energy, which began trading in the EIM at the beginning of October.
Abdul-Rahman gave the two utilities high marks for their market performance so far, noting that both have been coming into hourly intervals with balanced schedules more than 96% of the time.
“They are doing very well in managing their system,” he said.
He also pointed out that interconnected balancing areas within the EIM are seeing steady bidirectional transfers, indicating a true sharing of resources.
“We’re happy to see this kind of transfer — and that sometimes they’re importing or exporting,” Abdul-Rahman said. “That means the EIM is doing its job.”
WILMINGTON, Del. — Both manual revisions on the agenda won Markets and Reliability Committee approval by acclamation without objection.
The revisions to Manual 14A: Generation and Transmission Interconnection Process were recommended by the Earlier Queue Submittal Task Force. They include changes to the assignment of queue priority; timing, including scheduling of deficiency reviews; criteria for inclusion in feasibility studies; and fee structures.
IRM Study Approved but Criticized for Lack of Winter Analysis
The MRC endorsed the 2016 Installed Reserve Margin study results. However, Tom Rutigliano of Achieving Equilibrium, who consults for demand response provider WeatherBug Home, announced his abstention because the study doesn’t make any indications about winter reliability. (See No Consensus Among PJM Stakeholders on Seasonal Resources.)
| PJM
Credit Policy Changes Approved
The MRC endorsed proposed clarifications to the credit policy in Tariff Attachment Q that reorganize provisions and make five minor changes to them, none of which affects credit requirements. (See “Attachment Q Modified; Credit Requirements Unaffected,” PJM Market Implementation Committee Briefs.)
A special protection scheme Dominion Resources used to minimize N-1 overloads and allow for a higher pond level at a pumped storage facility is no longer needed thanks to a number of regional system upgrades.
Dominion plans to retire the Bath County thermal SPS by Dec. 1, but it says the stability SPS there will remain in place.
Tariff Changes Pass Members Committee Easily
The Members Committee endorsed by acclamation two sets of Tariff changes:
A Tariff revision authorizing use of a straight-line offer curve for selling back excess capacity in February’s third incremental auction for the 2017/18 delivery year. (See “Proposal Chosen for Capacity Release,” PJM Markets and Reliability and Members Committees Briefs.)
SPP’s Regional State Committee last week approved a process for reviewing new members’ effect on regional cost allocation, but not before rejecting language that stakeholders have been unable to agree on since July.
The RSC approved the Cost Allocation Working Group’s New Member Cost Allocation Review Process after deleting an introductory paragraph that dealt with the effective date for highway/byway cost sharing. The committee asked the working group to revise the paragraph and bring it back in October after SPP staff raised objections in July.
John Krajewski, a consultant with the Nebraska Power Review Board, said the CAWG never reached consensus on whether to include the paragraph in the document but felt the language was “reasonable” if the RSC decided to keep it. The revised paragraph specified that “the effective date of cost sharing is an area over which the RSC has primary responsibility.”
At issue was whether the language “tied the hands” of the RSC.
The RSC tied 5-5 on following the CAWG’s recommendation to include the language. The committee then unanimously approved the document without the introductory paragraph.
The document creates a roadmap for the RSC and CAWG to follow when a potential new member asks for significant changes to the Tariff or membership agreement that would affect the committee’s regional cost allocation.
The process became necessary after the Integrated System joined SPP last October, when much of the negotiation over the integration took place between the new members and staff. The parties agreed to propose to current members and the RSC a method to include the new system under SPP’s highway/byway funding methodology, while also providing the Western Area Power Administration’s Upper Great Plains Region a federal service exemption from regional funding.
Committee Elects 2017 Officers
The meeting was New Mexico Public Regulation Commission Chairman Patrick Lyons’ last as RSC chair; he will relinquish the gavel at the end of the year.
“It’s been a learning experience,” Lyons said. “I’ve learned people really do care what the ratepayers have to pay.”
The committee unanimously approved Missouri Public Service Commissioner Stephen Stoll as its chair for 2017, Kansas Corporation Commissioner Shari Albrecht as vice chair and South Dakota Public Utilities Commissioner Kristie Fiegen as secretary and treasurer.
Members also approved a 2017 budget of $321,700, an $8,400 increase over this year’s because of higher travel expenses.
AUSTIN, Texas — Texas regulators on Friday signed off on ERCOT’s plan to review its reliability standards and replace its loss-of-load expectation (LOLE) methodology for determining its reserve margin with one based on economics.
The Public Utility Commission agreed that a letter filed with the commission by ERCOT Director of System Planning Warren Lasher on Oct. 24 outlined a sound process. “Go forth and do good,” Chairman Donna Nelson said.
Commissioner Ken Anderson pointed out the project’s (Docket 43202) intention is to replace ERCOT’s LOLE methodology with the economic optimal reserve margin (EORM).
The LOLE is “not really baked into any of our rules, but it is baked into the protocols at ERCOT,” Anderson said.
ERCOT staff will go through its protocols to find language that needs to be modified and make changes “at the appropriate time,” Lasher replied.
In 2013, The Brattle Group and Astrapé Consulting conducted a study of the market’s EORM, which it defined as minimizing total system costs by weighing the cost of more generation to achieve higher reserve margins against decreasing scarcity-event-related costs.
Higher reserve margins help to avoid load shedding, reserve shortages, demand response calls and other emergency event costs, the study said.
The firms had to customize the study’s methodology, Lasher wrote, “to reflect the region’s unique energy-only deregulated wholesale market design and region-specific market behavior.”
The study simulated ERCOT’s recently implemented operating reserve demand curve. Lasher said that methodology and other study assumptions will need to be reviewed by ERCOT and stakeholders “if the results of future EORM studies are to be used in place of the existing target reserve margin.”
Lasher’s proposal involves conducting workshops with market participants in the first half of 2017 and completing its next EORM study in 2018 based on the documented methodology. He recommended future EORM analyses be conducted every other year coincident with NERC’s required LOLE studies.
Following the 2018 EORM study, Lasher said ERCOT would amend its market rules as appropriate to accommodate the move to a target reserve margin based on EORM criteria, and away from the one-event-in-10-years LOLE.
“Currently, NERC has two numbers that go to them,” Lasher told the PUC. “First, what the region says is an appropriate reserve-margin expectation. That’s whatever the region wants to define it as. Some regions use the economic optimal number.
“NERC also has a standing data request every year for the region to say, given our expectations for the reserve margin, what will actually be the expected unserved energy with that margin.”
Lasher said ERCOT conducted loss-of-load probabilistic studies in 2014 and 2016 to comply with data requests from NERC and the Texas Reliability Entity. The ISO worked directly with Astrapé to complete the studies, using the same models and assumptions comparable to those employed for the 2013 study.
The commissioners debated whether to have ERCOT continue providing its regular capacity, demand and reserves (CDR) report until the new reliability standards are in place, without coming to a decision.
“The CDR is at the heart of the problem, because its load assumptions are beyond four years,” Anderson said.
Anderson suggested ERCOT take the 2013 study results and incorporate them in the CDR, using the economical, optimal and expected equilibrium as information data points. Lasher noted ERCOT’s May CDR didn’t provide data for a target reserve margin, but he said staff could include the Brattle study’s results.
MISO is requesting a 4% increase in operating expenses for 2017 while moving away from a one-year forecast in favor of a five-year business plan.
The requested increase will bring the 2017 operating budget to $289.6 million, said Mitch Myhre, chair of the MISO Finance Subcommittee, who presented the budget to the Advisory Committee during an Oct. 26 conference call.
The operating budget includes:
$229.6 million in “base” spending;
$51 million in structural expenses (including amortization of membership integration costs, depreciation of cybersecurity investments and infrastructure upgrades and funding of the Independent Market Monitor and Organization of MISO States); and
$9 million for strategic initiatives, including the Competitive Retail Solution, seasonal and locational capacity, improving gas modeling, and automatic generation control enhancements.
MISO forecasts it will end 2016 with operating expenses of $225 million — its budgeted amount — to $227.3 million, which would be 1% over budget.
Myhre said MISO’s new five-year budget approach will be an “evolving, rolling” budget. The RTO is predicting a 1.9% compound annual growth rate for the next five years. The subcommittee and MISO staff are still working on the details of the five-year plan, Myhre added.
The plan projects an identical $289.6 million spend in 2018. In 2019, the figure increases to $293.5 million, then $299.5 million in 2020 and $306.7 million in 2021. In every budgeted year, MISO plans to spend exactly as much as it brings in.
MISO also is requesting a 2017 capital budget of $29.9 million — a drop from 2016’s $31 million — and an average capital spend of $32.9 million over the next five years.
However, the RTO said it might request out-of-cycle budget approvals in 2017 for initiatives in the works, including the construction of a new security operations center, more software quality control, improved server utilization, positioning an off-duty police officer at MISO control sites and insourcing some outside contracts. For those possible expenses, the Finance Subcommittee recommended MISO create business cases to present to the appropriate stakeholder groups.
American Electric Power’s Kent Feliks thanked Myhre and MISO for the budget work. “A lot of this work isn’t very exciting, but it’s vital to MISO,” he said.
Final approval of the 2017 budget and adoption of the five-year spending plan will take place at the Board of Directors meeting in December.
AC to Approve One of Two Sets of 2017 Priorities
The Advisory Committee will adopt one of two revised sets of priorities for 2017, choosing between one that is a slight revision of existing priorities and another that takes its cues from subcommittee mission statements.
| MISO
Gary Mathis, representing MISO’s Transmission-Dependent Utility sector, said the committee’s approved priorities for this year are unclear and hard to remember. Mathis said the subcommittees’ mission statements could become the committee’s overarching priorities themselves. He presented five proposed priorities: implementing best planning practices; preserving and enhancing reliability; improving market efficiency; ensuring resource adequacy; and ensuring equitable cost allocation.
Advisory Committee Chair Audrey Penner presented the alternative, which was slightly changed from the 2016 priorities list. It moves the gas-electric coordination priority under a broader environmental policy and portfolio evolution priority. A strategic guidance priority was added in its place that includes hot topic discussions and a broad current issues subcategory. (See “Committee Endorses 5 Final Priorities,” MISO Advisory Committee Briefs.)
Penner said both priority documents capture “the essence of what the priorities should be.”
The committee will vote to adopt one of the two approaches at its December meeting. Penner said committee leadership hopes to keep the committee’s priorities on the books for multiple years while performing six-month “check-ins” to assess their continued relevance.
AC’s Strategic Session Prompts Possible ‘Hot Topic’ Change
Advisory Committee members noticed that the committee spent quite a bit of time on this year’s stakeholder redesign and said it looked forward to paying more attention to other issues in 2017, reported Penner, who gave an overview on the committee’s strategic planning session held at the end of September in San Antonio.
Penner also said the committee is looking to change its hot topic forum back to its original format, with wider stakeholder participation in drafting questions, instead of MISO facilitating the discussion. Director of External Affairs Kari Bennett said the RTO had no problem with re-establishing the old arrangement.
The Advisory Committee is considering holding hot topic conversations in 2017 that focus on transmission, including cost allocation, pseudo-ties and the competitive bidding process. Penner said the committee would solicit votes by email to its voting sectors to decide on a March topic. She added that the committee might suggest MISO hold an educational session prior to sectors submitting their written positions on hot topic subjects.
Penner also urged stakeholders to attend a Nov. 3 Stakeholder Governance Guide workshop. During the Oct. 26 Steering Committee conference call, Chair Tia Elliott said agenda items could include conference call logistics; meeting procedure education; an overview on Robert’s Rules of Order; criteria for establishing closed groups; and the creation of a definition for task teams with a process for creating and retiring them.
Xcel Energy reported an increase in earnings for the third quarter as the company said its “steel-for-fuel” strategy of replacing fossil fuel plants with wind turbines will provide a solid blueprint for future growth.
The company reported third-quarter earnings of $458 million ($0.90/share), up 7.5% from the $426 million ($0.84/share) a year earlier. The results bested analysts’ expectations of 87 cents, according to Zacks Investment Research.
“The whole premise of steel-for-fuel is you can do things on an economic basis cheaper than the fossil alternatives,” CEO Ben Fowke told analysts during a conference call Thursday. “In reality, the environmental benefits will be icing on the cake. So, when you’re not impacting customer builds and you’re driving environmental leadership, it’s really a unique position for us to be in.”
Xcel proudly points to its designation by the American Wind Energy Association as the nation’s No. 1 utility wind-energy provider for 12 years running. Wind energy accounted for 17% of the energy Xcel generated in 2015, and it projects that figure to grow to 24% by 2020.
| Xcel Energy
Much of that has been produced by long-term contracts with third parties, but the Minneapolis-based company announced earlier this week it would build four new wind farms in Minnesota and North Dakota with a total capacity of 750 MW.
In September, Colorado regulators approved Xcel’s plans to begin construction on its $1.1 billion, 600-MW Rush Creek Wind Project, allowing Xcel to claim $443 million in federal tax credits. The Rush Creek project is expected to come online in 2018.
“We expect [these] wind projects will generate hundreds of millions of dollars in fuel savings for our customers, which will more than offset the capital cost [to build them],” Fowke said.
CFO Bob Frenzel told analysts the company has updated its five-year capital forecast and now expects to invest $18.4 billion through 2021, including $3.5 billion on renewables. That includes the Rush Creek project and the Minnesota-North Dakota wind farms.
“When you look at the economic price point … that we are seeing with wind, I think we have opportunities potentially in Texas and New Mexico too, just on the economic merits alone,” Frenzel said.
Analyst Angie Storozynski of Macquarie Capital questioned whether adding renewables to the rate base in a time of no load growth is the “low-risk” growth strategy the company claims.
Vice President of Investor Relations Paul Johnson acknowledged that the company will be adding capacity that might not be needed until it retires coal plants. “We’re just taking opportunity to capture the full” production tax credit, he said.
“This is our resource plan. … We can build wind competitively, and I think we’ve earned the right to own wind in our backyard,” Fowke added. “It does require alignment with your regulators, but I think we have it.”
Xcel narrowed its 2016 earnings guidance to $2.17 to $2.22/share, down from the previous estimate of $2.12 to $2.27/share. “Our year-to-date weather-adjusted electric sales remain relatively flat,” Frenzel said, explaining the company’s caution.
The company’s stock price opened at $40.33/share before Thursday’s earnings announcement. It closed Friday at $40.68.
Earnings call transcript courtesy of Seeking Alpha.
LITTLE ROCK, Ark. — The SPP Board of Directors and Members Committee decided last week to take no further action on the contentious Z2 crediting issue, leaving unhappy stakeholders likely to seek redress from FERC or the courts.
The board discussed the Markets and Operations Policy Committee’s recommendation to “follow the Tariff” and reject requests that $114.1 million in directly assigned Z2 network upgrades be allocated to SPP’s base plan. However, it took no votes on the matter Oct. 25, which let stand the MOPC’s decision, which was supported by 83% of members voting. (See MOPC Rejects Z2 Waivers; Task Force Seeks Changes.)
The board in July formed a task force to review requests from members who SPP staff had said didn’t qualify for waivers from $36.9 million in directly assigned upgrade costs, while also addressing “equity concerns.” The group also reviewed another $77.2 million in direct costs from members who didn’t request waivers.
Les Evans, COO of Kansas Electric Power Cooperative (KEPCo), one of the companies requesting a waiver, once again expressed his dissatisfaction with the process after being “wrongly assigned” $6.2 million because its resource-to-load ratio exceeded a 125% threshold.
“The 83% that voted to follow the Tariff does indicate that 17% of us feel disenfranchised and that things are not equitable,” Evans said.
Evans argued KEPCo was granted four transmission service requests from a 2012 aggregate study, and that there were no directly assigned costs in the agreements.
Pointing to the directly assigned costs he said KEPCo was assessed four years later, Evans said SPP’s treatment of his company fails the RTO’s “but-for” test, which requires transmission customers to fund transmission improvements that would not be required but for their additional load. The test is triggered by a 3% increase on a line’s directional flow in the same direction as the power flow that caused the upgrade.
“Under the process we’re using right now, a sponsored upgrade can be put back into a model from years ago, and if I have a 3% flow on that facility, I would be responsible for directly assigned upgrade costs under that possibility. I would say that is not fair, it’s not equitable and I don’t think there’s anybody that can stand here with a straight face and say that passes a ‘but-for’ test.”
Evans worked with staff to draft language for two different motions addressing his arguments. One required transmission reservations assigned a payment obligation for an upgrade be included in the original aggregate study model. The other would mandate that service agreements explicitly include directly assigned upgrade costs in order to be directly assigned to a transmission customer.
Evans failed to get a second on either motion, the only two offered up by the board and committee.
“We have an opportunity here, as a group, to solve the problem,” Evans said. “If the problem’s not solved [today], from my perspective and KEPCo’s perspective, we’ll seek other solutions. SPP loses control of how the problem is resolved. This is the place to do it.”
Staff pointed out either motion would cause about a six-week delay to calculate the historic Z2 credits and obligations, which date back to 2008. Invoices settling charges and credits under Attachment Z2 for the March 2008-August 2016 period are to be issued this week.
“Following the Tariff should be clear, but how clear can 5,275 pages be?” Director Phyllis Bernard asked. “Perhaps it’s time for … alternative dispute-resolution with a possible third party, or to go to FERC.”
“We’ve been waiting eight years to get this done. Let’s get it done,” said The Wind Coalition’s Steve Gaw, noting SPP’s transmission-dispute resolution process could still provide an avenue for members to plead their case. “I would encourage us to move forward.”
“I’d love for consensus to be unanimous, but that’s not what we have,” SPP CEO Nick Brown said. Reversing the MOPC’s endorsement would mean “we’ll be supporting 17% at the expense of 83%.”
“Bottom line, this will go to FERC,” Brown said. “I have no doubt what KEPCo’s response to this will be.”
Evans’ response was terse. “KEPCo is evaluating all possible venues for a remedy to its issues,” he told RTO Insider on Friday.
Staff told members Thursday it is billing almost $110 million in regionwide, aggregate net payable historic amounts. It said $94.8 million will be invoiced as a lump sum, and the remaining $15.1 million will be billed in 20 installments through August 2021 to those members who chose the payment plan approved in April.
Duke Energy Renewables has signed a five-year deal to provide remote monitoring, control and dispatch services to Block Island Wind Farm — the nation’s first offshore wind facility.
The 30-MW wind farm, located off the coast of Rhode Island, is expected to begin producing electricity in November.
Duke Energy presently provides control and monitoring services to non-Duke projects totaling about 2,000 MW.
PG&E Applies for Rate Increase Spurred by Diablo Canyon Closing
Pacific Gas & Electric is applying to the California Public Utilities Commission for a 1.6% rate increase after promising earlier this year that closing its Diablo Canyon nuclear facility would not raise customers’ rates.
The proposed increase amounts to $1.766 billion to be collected over an eight-year period.
PG&E spokesman Blair Jones said last week that the “short-term rate increase will be offset in the long term.”
Sunrun Partners with LG Chem to Offer Solar Panels with Batteries
Sunrun will offer solar arrays paired with in-home batteries thanks to a partnership announced last week with LG Chem, which supplies batteries to 16 of the world’s largest automakers.
The Korea-based battery builder will supply lithium-ion batteries for Sunrun’s BrightBox system, which allows homeowners to store solar energy generated during the day for use in the evening.
Sunrun began offering BrightBox this year in Hawaii, using batteries made by Tesla Motors. It wants to expand the system into California beginning in 2017.
Sims to Serve on Pinnacle West, Arizona Public Service Boards
Paula Sims has been elected to Pinnacle West Capital’s board of directors and also will serve on the board of directors of Arizona Public Service, Pinnacle West’s principal subsidiary.
The appointment is effective immediately and increases the number of Pinnacle West directors from 10 to 11 members, 10 of whom are independent.
Sims is a former senior executive at Progress Energy.
Dominion Virginia Power Sees Peak Demands for Electricity
Dominion Virginia Power is seeing peak demands for electricity, with its customers having used 28.2 million MWh from July 1 to Sept. 30 — breaking an 11-year record.
“We are now seeing peak demands for electricity in both the summer and winter,” said Robert M. Blue, president of Richmond-based Dominion.
The company has proposed building a transmission line over the James River from its Surry Nuclear Power Station to address increased demands.
EnergySource Testing Process to Extract Lithium from Geothermal Brine
EnergySource is testing a new five-step process to extract lithium from underground brine at its Featherstone geothermal plant by the Saltine Sea in California.
The company purchased several existing extraction techniques and is using its knowledge of the Saltine Sea brine to tweak those technologies, CEO Eric Spomer said.
A Texas investment firm just purchased a 38.5% interest in EnergySource and is funding more thorough testing of the extraction project, which Spomer expects will take about six months.
Xcel Energy Planning Four Wind Farms for Minnesota, North Dakota
Xcel Energy announced last week that it plans to build four new wind farms in Minnesota and North Dakota — a move that will increase its wind generation capacity by 60% in the Upper Midwest.
The four wind farms, which still require regulatory approval, will generate 750 MW.
The projects are part of a plan that Xcel announced in September to invest $2 billion to add 1,500 MW of new wind generation — or eight to 10 wind farms — by 2020.
Shareholders File Suit to Stop Spectra’s Merger with Enbridge
Shareholders have filed five separate lawsuits against Spectra Energy to stop its $28 billion deal to sell itself to Enbridge.
The suits, which were filed in the U.S. District Court in Houston, all allege that Spectra should have sought other merger partners who might pay more for the company.
Under the deal, Spectra stockholders would trade each of their shares for a 0.984 share of the combined company, which will keep the Enbridge name.
Idaho Power Project Lowers Temperature of Snake River
Idaho Power is lowering the temperature in areas of the Snake River in order to comply with regulations.
In July, the utility began work to narrow and deepen a channel by widening two islands just downstream of Walters Ferry. It will replace noxious weeds on the two islands with native trees that will help cool the water.
The project is the first of many planned for areas along the Snake River and is expected to end this month.
Idaho Power Requests Early Exit from Nevada Coal Plant
Idaho Power filed a request with state regulators on Oct. 21 to accelerate its exit to 2025 from the coal-powered North Valmy Generating Station near Battle Mountain, Nev.
The utility, which owns 50% of the power plant, previously said it wanted to wean itself off of Unit No. 1 by 2031 and Unit No. 2 by 2035.
The accelerated exit would result in a $28.5 million cost increase, which would include decommissioning costs and capital investments forecast for the remaining life of the plant, Idaho Power said in its filing with the Public Utilities Commission.
New Reliant Plan: No Panels Needed to Purchase Solar in Texas
Reliant Energy is offering Texas customers the opportunity to purchase solar energy for 12 months at a fixed rate without installing solar panels. Reliant’s 100% Solar 12 plan allows the company to procure the rights to solar energy through renewable energy credits.
Pinnacle West Capital, which owns APS, is planning to spend $1 million through a newly formed political committee to get three Republicans elected to the five-member commission. SolarCity has spent about $1.4 million supporting one Republican and two Democrats, according to financial disclosures.
Exelon may be shuttering two of the state’s six nuclear plants beginning in 2017 unless ratepayers statewide pay up to $265 million per year to save them.
