The Indiana Utility Regulatory Commission on Wednesday accepted a settlement negotiated between Duke Energy and local consumer groups on a statewide infrastructure upgrade plan.
The seven-year, $1.4 billion plan results in an average 0.93% increase in Duke Energy Indiana customer rates annually over the next seven years. Individually, the year-long increases range from 0.58% to 1.35% until 2023.
The IURC found that “public convenience and necessity require” Duke’s planned transmission, distribution and storage improvements.
The settlement was reached in March among the Indiana Office of Utility Consumer Counselor, Duke Energy Indiana, steelmaker Companhia Siderurgica Nacional, Steel Dynamics, Wabash Valley Power Association, Indiana Municipal Power Agency, Hoosier Energy Rural Electric Cooperative and the Environmental Defense Fund.
“We are happy with the settlement,” said Anthony Swinger, director of external affairs for the IOUCC. “We believe the settlement strikes the right balance between ratepayer protection and the utilities’ need to make infrastructure improvements in order to provide safe, dependable service.”
“We have an aging energy grid — some equipment that is decades old — and our work will focus on replacing some older infrastructure to reduce power outages,” Duke Energy Indiana President Melody Birmingham-Byrd said. “We’ll also be building a smarter energy structure with technology to provide the type of information and services that consumers have come to expect.”
Duke plans to invest in line sensors and “self-healing” systems, as well as replace aging substations, utility poles, power lines and transformers.
A little over a year ago, the IURC denied Duke Energy Indiana’s original proposal, causing the utility to trim $400 million from the plan, including the elimination of a $192 million project to install smart meters. The company now says that if it pursues smart meters using the settlement, it is “committed to exploring energy efficiency pilot programs that are now possible with smart meter technology.”
The New York Green Bank wants to increase its portfolio by two-thirds over the next year, mostly by investing in larger clean energy projects.
In its annual business plan released last week, the state’s clean energy investment arm said it wants to invest $200 million, or $50 million per quarter, in projects that otherwise might not attract enough private capital on their own.
The bank invested $120.5 million in nine transactions over the past year, which was leveraged into a project portfolio valued at $518.3 million. These commitments are expected to result in 128 MW of new capacity.
The Green Bank is administered by the New York State Energy and Research Development Authority as part of the state’s $5.3 billion Clean Energy Fund. (See NYPSC OKs $5.3B Clean Energy Fund.) The bank has a short-term goal of deploying private capital at a rate of 3-to-1 above its own funds, with a longer-term goal of an 8-to-1 ratio when the fund ends in 2025.
The bank is seen as a way to jump-start projects to achieve New York’s goal of obtaining 50% of its energy from clean sources by 2030.
So far, the bank has received $220 million from the state. Now it wants to scale up the project pipeline.
“NYGB has identified two potential opportunities to accelerate market transformation via the creation and introduction of targeted financial products. In both cases, the market is potentially large, but currently suffers from fragmentation, lack of standardization and lack of scale,” the plan says.
Based on input submitted by project developers, financiers and other stakeholders in response to a recent request for information, the Green Bank expects to issue two requests for proposals. Its new targets are commercial real estate and multi-family solar and/or energy efficiency systems that would be owned by the building owner instead of third parties, and ground-mounted solar systems for corporate or industrial end users.
On the same day the business plan was released, the Green Bank closed a $25 million loan for residential solar installer Sunrun. The loan is intended to accelerate construction of more than 5,000 solar projects across the state. It comes on the heels of a separate $25 million loan from the Green Bank in May that was part of a $340 million credit facility Sunrun executed over the past several months.
The bank has been capitalized at $1 billion with support from ratepayer funds and New York’s proceeds from its participation in the Regional Greenhouse Gas Initiative. It has a goal of becoming self-sustaining by 2018 through returns from its project portfolio. (See Project Interest Overwhelms New York’s Green Bank.)
ERCOT’s Technical Advisory Committee canceled its scheduled June 30 meeting but held an email vote to unanimously approve a nodal operating guide revision request removing references to the provision of responsive reserves across DC ties.
The operating guides have included the references to responsive reserves — operating reserves ERCOT maintains to restore system frequency within the first few minutes of an event that causes a significant deviation — since at least 1997. Staff said there are no systems or procedures in place to award ancillary services to the DC ties, and no project to add this functionality has ever been proposed.
Staff said that without any funding for the necessary system changes, ERCOT has no mechanism for allowing the provision of responsive reserves over the DC ties.
FERC pushed back the timeline for an environmental impact statement on the Mountain Valley Pipeline, delaying construction of the $3.5 billion shale gas pipeline crossing Virginia for at least six months.
The developers of the 301-mile pipeline project applied for the environmental certificate in October, but FERC staff has repeatedly asked for more information, and now it says the EIS won’t be ready until March. The commission has 90 days after that to decide whether or not to issue final permits. That means construction is more likely to get underway in June of next year, rather than December 2016.
Congresswoman to Propose Stiffer FERC Pipeline Reviews
Coleman
In a move applauded by pipeline foes, U.S. Rep. Bonnie Watson Coleman (D-N.J.) said she will introduce a bill in the House requiring FERC regulators to be more critical when reviewing proposed pipelines.
Her proposal will introduce stiffer environmental reviews of pipeline projects and require them to explore “less environmentally disruptive alternatives.”
Coleman is wading into controversy surrounding the PennEast Pipeline, a project that would deliver shale gas from Pennsylvania primarily to New Jersey utilities. Opponents have cited PennEast an example of lax FERC review. The 119-mile, $1.2 billion pipeline is currently under review by FERC, but opponents said the commission is allowing PennEast to use routing and construction methods that are harmful to the environment.
Monthly Coal Generation Falls To Lowest Level Since 1978
The Energy Information Administration reported that coal use for electric power generation in April fell to its lowest level since 1978, while natural gas was the top fuel for the third straight month.
Plants fueled by coal generated 72.2 million MWh in April, the lowest since 1978. Natural gas-fired plants produced 100 million MWh in April.
Gas accounted for 34% of total generation in April, while coal came in at 31%, nuclear at 20% and renewables at 7%. Ten years ago, coal-fired plants produced 50% of the nation’s electricity and natural gas only 19%.
The newly expanded Panama Canal locks will be able to handle 90% of the world’s LNG tankers, reducing shipping time and expense for shipments to Asia from Gulf Coast terminals, according to the Energy Information Administration.
Before Panama opened the widened canal last month, the waterway could only accommodate 30 smaller LNG tankers, representing about 6% of the global fleet of tankers equipped to handle the super-cooled fuel.
The widened canal means it will take 20 days for shipments to reach Asian markets from Gulf Coast terminals, compared to the 34 days previously when large vessels to Asia were required to round Cape Hope or transit through the Suez Canal.
Having completed his second term at the end of June, Nuclear Regulatory Commissioner William Ostendorff is leaving the commission to teach at the U.S. Naval Academy in Annapolis.
Ostendorff, former director of the commission’s Committee on Science, Engineering and Public Policy, was first named to the commission in 2010. He began his second term in 2011.
Ostendorff’s departure creates a second vacancy on the five-member commission. Allison M. Macfarlane resigned as chair in December 2014, and that slot has remained open. President Obama nominated Jessie Roberson, a Democrat who serves as vice chairman of the Defense Nuclear Facilities Safety Board, a year ago. Senate Environmental and Public Works Chairman James Inhofe (R-Okla.) said in April he wanted to wait until Obama nominated a Republican so both vacancies can be filled at the same time.
Interior Changes Rules on Federal Coal Lease Payments
Jewell
The Interior Department will change the rules on how it collects royalties on coal mined on federal land to more accurately reflect its market value.
The rule change eliminates a loophole that allowed mining companies to pay royalties calculated on the price they charged their own subsidiaries, which often resold the coal at higher prices to end users. Coal mined from federal lands accounts for 44% of all coal mined in the U.S and generates about $1 billion annually in royalty revenue, but critics said that is artificially low.
“These improvements were long overdue and urgently needed to better align our regulatory framework with a 21st century energy marketplace,” Secretary of the Interior Sally Jewell said. The new rules take effect Jan. 1.
Senate Committee Approves $500 Million for Climate Fund
Merkley
The Senate Appropriations Committee approved $500 million for a fund that provides money for poor nations to combat climate change, a reversal of an earlier proposal that blocked the State Department from spending any money on the program.
The committee approved the funding through an amendment that removes language from the bill authorizing the State Department’s budget. The Obama administration had promised $3 billion for the program, called the Green Climate Fund, by 2020.
“We know we can’t take on this challenge by ourselves, so it’s part of the partnership in global leadership to address this … global issue,” said Sen. Jeff Merkley (D-Ore.), who led the effort to approve the amendment. “This is a real effort in bipartisan cooperation to present this amendment before the committee.”
ND PSC Commissioner Kalk Named to National Coal Council
Kalk
North Dakota Public Service Commissioner Brian P. Kalk has been named to the National Coal Council by U.S. Secretary of Energy Ernest Moniz. The council provides the secretary with advice on policy on coal and the coal industry.
“It’s important to remember that while renewable energy presents unique opportunities, coal is a strategic resource that heats millions of homes and provides low-cost reliable power,” Kalk said. “If the United States hopes to have true energy security, coal must be in the resource mix.”
The 6th U.S. Circuit Court of Appeals, rejecting a Sierra Club challenge, has ruled that an Enbridge oil pipeline that crosses a national forest in Michigan doesn’t need a new permit to keep operating.
The Sierra Club sued the U.S. Forest Service, saying it should have required Enbridge to prepare an environmental analysis before renewing the company’s right-of-way permit for Line 5. The 30-inch pipeline starts in Wisconsin and ends in Canada.
The court determined that there was nothing that required a new look at the pipeline, which runs through the Huron-Manistee National Forest.
TVA Aims to Cut 3,500 Jobs Through Voluntary Reductions
A month after the Tennessee Valley Authority celebrated the start-up of its new Watts Bar 2 nuclear reactor, it has announced plans to offer 3,500 nuclear staff members the option to voluntarily leave.
Employees at four locations — the Brown’s Ferry, Sequoya and Watts Bar nuclear stations and the nuclear services group in Chattanooga — have between July 11 and 29 to apply. Anyone who has been with the nuclear unit for at least a year can apply.
TVA said the workforce reductions are just the latest step in its ongoing effort to cut operation and maintenance costs, which has led to reducing 2,000 positions across all business units in the past three years. “This is a continuation of TVA’s efforts to ensure we have the right number of people for the roles we currently have,” a spokesman said.
Members Prepped for Problem Statement on Settlement Intervals, Shortage Pricing
WILMINGTON, Del. — The PJM Markets and Reliability Committee will be asked to approve a problem statement on first read next month regarding rule changes to comply with FERC Order 825, which requires RTOs to align their settlement and dispatch intervals and implement shortage pricing during any shortage period.
PJM has until Jan. 17 to file its compliance with the June 16 order, PJM’s Adam Keech said. After that, the RTO has four months to implement shortage pricing provisions and 12 months for settlement provisions.
While FERC did not order the changes be implemented simultaneously, members may consider requesting coincident start dates because the issues are related, he said. (See FERC Issues 1st RTO Price Formation Reforms.)
Charter for Underperformance Risk Management Senior Task Force Presented
Members heard the first reading of a draft charter for the Underperformance Risk Management Senior Task Force. The committee will be asked for its approval at the July meeting.
The charter reflects two separate issue charges. The first, managing the risk of underperformance under Capacity Performance, was approved in December. (See “Ways to Mitigate Risk in CP Market to be Studied,” PJM Markets and Reliability Committee Briefs.) The task force will seek to develop ways that CP resources can manage their risk during performance assessment hours.
The second, concerning external CP enhancements, passed in May. (See MRC Approves Charter for Seasonal Capacity Effort.) The group will seek to better align the requirements for internal and external resources.
PJM’s Rebecca Carroll said the task force is looking to implement changes for the 2020/21 Base Residual Auction next May. The task force expects to return to the MRC with recommendations by September.
On a related issue, CEO Andy Ott urged the Seasonal Capacity Resource Senior Task Force to be realistic about changes to allow seasonal resources to participate in CP. In particular, he discouraged them from moving to a seasonal product from an annual one.
“We need to work on aggregation, work on verification standards,” he said. “But to try to completely revamp the definitions would distract from the goal of trying to make change that is attainable,” he said.
More Flexible PLS Process Approved
The MRC approved a proposal to make the parameter-limited schedule exception process more flexible.
With the change, generators can request exceptions after the Feb. 28 deadline. They also will be permitted to seek extensions of a temporary exception (to a period or persistent exception) after that date.
It also gives PJM and the Independent Market Monitor more time to review requests and respond to market sellers. (See “More Flexible Parameter Limited Exception Process Approved,” PJM Market Implementation Committee Briefs.)
PJM Delays Endorsement of Manual Changes
PJM delayed an endorsement vote on two manual changes in response to members who wanted more time to discuss the issues.
Regarding Manual 14C: Generation and Transmission Interconnection Facility Construction, the tie line issue will be lifted out and returned to the Planning Committee for discussion, PJM’s Jason Shoemaker said. The changes were sought to support the inclusion of Order 1000 processes.
As for proposed revisions to Manual 15: Cost Development Guidelines, PJM delayed asking for endorsement to give members more time to discuss aspects related to the fuel cost policy approval process. The issue is expected to return to the Market Implementation Committee next month before being presented again to the MRC.
Manual Changes
Members unanimously endorsed the following manual changes:
Manual 7: Protection Standards. Clarifications were recommended by the Relay Subcommittee as part of its biennial review of the manual.
Manual 10: Pre-Scheduling Operations. Changes make clear that outage reporting rules apply to both capacity and energy resources.
Manual 14B: PJM Region Transmission Planning Process. Updates light load and winter peak reliability analyses to align with current practices, among other updates.
Manual 18: PJM Capacity Market. Changes are the result of a periodic review; conforming changes relate to Capacity Performance and the “deploy all resources” action.
Members Committee Adopts Project Queue Submittal Changes, Elects Finance Committee Member
The Members Committee approved Tariff revisions requiring earlier submittal of documentation in order for projects to secure a place in the interconnection queue.
Applications that have not cleared deficiencies by the close of the queue window will be terminated and withdrawn.
The committee also elected Gary Greiner of Public Service Enterprise Group to the Finance Committee. He will take the place of Frank Czigler, who retired from PSEG.
FERC on Thursday rejected CAISO’s proposal to prohibit Energy Imbalance Market participants from implementing economic bidding at the market’s external interties until the ISO can develop “appropriate rules and procedures” to manage the transactions (ER16-1518).
The ISO’s Tariff currently stipulates that each balancing authority area (BAA) that joins the EIM can determine for itself whether to allow resources located outside the market to submit economic bids at the BAA’s transmission seams.
CAISO sought to change its Tariff in part because EIM participants PacifiCorp and NV Energy had expressed concerns that implementing the practice would add complexity to their initial participation in the market.
The ISO cited another reason for the change: “The CAISO’s experience with 15-minute bidding at its own interties suggests that the extent of the benefits from allowing such bidding is questionable,” it said in an April filing with FERC that included a raft of other EIM-related Tariff changes. The ISO cited the low liquidity in the 15-minute market at the ISO’s own seams — suggesting a lack of market interest — and the potential for EIM participants to incur increased transaction costs from external bids.
EIM participants will continue to have the choice of allowing external intertie bidding along their seems in light of FERC’s ruling.
CAISO also envisioned a “problematic” scenario in which EIM transmission flows could shift as a result of only one EIM participant requesting economic bidding at its interties. While the market consists only of three BAAs today, Arizona Public Service and Puget Sound Energy are scheduled to begin participating later this year, while Portland General Electric will join next year.
The Western Power Trading Forum (WPTF) — an industry group representing power marketers — filed the only protest against the proposal, calling the revision an “attempt to codify” an “effective roadblock to market evolution” that discriminated against third-party participation in the EIM. The organization accused CAISO and the other EIM participants of resisting making the changes required “to incorporate external resources [into] the EIM with efficient, flexible market-based mechanisms.”
The group also criticized the open-ended nature of the Tariff change, asking the commission to dismiss the proposal until the ISO provided a plan to implement EIM intertie bidding by a specific date. The organization suggested that FERC direct the ISO to undertake an “open and transparent” stakeholder process to develop the necessary rules and commit to implementation within a year.
Although the WPTF didn’t win the one-year deadline it sought, the group’s arguments largely found support with the commission.
“As an initial matter, we find it inappropriate for CAISO to include in its Tariff an indefinite placeholder,” the commission wrote, referring to CAISO’s failure to propose a timeline for resolving the intertie issue.
While acknowledging that CAISO “identified issues that warrant further evaluation,” the commission ruled that the ISO had not “sufficiently described” those issues or met its burden under the Federal Power Act to alter the Tariff in a way that would remove from EIM participants the discretion for implementing intertie bidding.
“Moreover, WPTF raised concerns about unduly delaying the ability of external resources to participate — concerns that CAISO does not full address,” the commission said.
WPTF won another concession: The commission called for further discussion of the issue, directing FERC staff to convene a technical conference to gather information about the challenges of implementing economic bidding at the EIM’s interties — with an eye to determining how to overcome impediments. Details for the conference will be set out in a subsequent notice.
The commission’s June 30 ruling did approve CAISO’s other proposed EIM-related Tariff revisions, which included:
Modification of the ISO’s method for assigning congestion revenues to EIM participants to more accurately reflect those participants’ contributions to congestion at an intertie. The current rule allocates revenues based on the number of participants that share ownership of the intertie.
A provision allowing CAISO to submit outage information to the regional reliability coordinator on behalf of each EIM participant.
An alteration to the calculations underpinning the start-up/minimum load costs and default energy bids for EIM generators that would exclude CAISO’s grid management charge, which EIM-only generators do not pay. Instead, they pay EIM administrative charges, which they can continue to include in their costs.
A requirement that EIM participants accept approved, pending and adjusted e-Tags as the only valid means to convey an import/export base schedule to another participant for the purposes of imbalance settlement.
The Monitor reiterated his suggestion that MISO and PJM scrap pseudo-ties in favor of firm flow entitlements, advice that PJM has recently turned down.
“I don’t know how anyone who understands dispatch could think this is a good idea, but there seem to be a lot of people on the other side of the border that think this is a good idea,” said Patton, who added he’d be interested in checking in with PJM “in a few months” to see if their footprint is weary from high prices.
Dynegy’s Mark Volpe asked Patton if MISO’s pseudo-ties “far from the seam” are a main contributor to higher congestion.
“The farther you are from the seam, the more constraints you’re going to impact, and it’s harder for PJM to model all those constraints,” Patton said. He said MISO’s $302.2 million worth of real-time congestion in the first quarter is up 51% from winter but still down 17% from spring 2015.
Stakeholders asked if MISO could list all pseudo-tied units. Jeff Bladen, executive director of market services, said the RTO doesn’t publicly post information on which resources are pseudo-tied, but market participants could access the nonpublic information using MISO’s commercial model, which provides inputs to the real-time and day-ahead markets.
Patton also told stakeholders the RTO should “close some loopholes” in the Planning Resource Auction design by applying physical withholding thresholds on a company basis, rather than a market participant basis, to address companies with affiliates.
Stakeholders asked if the recommendation would break up local resource zones; Patton said that would be an entirely different recommendation.
Patton also suggested MISO apply a “reasonable” transfer capability in the next PRA. He said the binding transfer constraint of 874 MW between MISO South and Midwest used in the April auction caused the uniform $72/MW-day clearing prices in zones 2, 3, 4, 5, 6 and 7. Patton wants the limit set “based on the expected ability to reliably transfer power in real-time operations.”
Subcommittee Chair Kent Feliks said the session was the beginning of stakeholders’ review. “I think the point of this today was to get the recommendations on the table to start picking them apart,” he said.
MISO, Monitor Seek Change to Contingency Reserve Selection
MISO may change the economic selection and dispatch behind contingency reserves in an effort to reduce uplift charges.
Akshay Korad, an engineer with MISO’s market evaluation and design department, told stakeholders MISO historically experiences “significant uplift” when contingency reserves are deployed. The current logic seeks to minimize scheduling costs and not production costs.
Type I demand response providing spinning reserves received about $900,000 per year in uplift charges from 2010 to 2015 because of high curtailment costs — which are not accounted for when the RTO selects the resources.
Offline supplemental generators deployed for contingency reserves were paid an average of $275,000 per year in uplift from 2010 to 2015, with last year’s costs totaling $720,000. Korad said offline resources are selected based solely on their reserve capacity offer. “Minimum runtime and commitment costs are not considered in the selection,” he said.
MISO and the Monitor are proposing different solutions, but both would add deployment-cost considerations.
The Monitor advocates the creation of a supply curve for contingency reserves with a deployment risk adder for each resource. The approach would require a Tariff change to ban negative contingency reserve offers.
MISO proposes adding deployment cost considerations to its scheduling logic.
Thomas Sikes of WPPI Energy asked if MISO could offer deployment cost historical data with its proposal. Korad said such information hadn’t been collected. Other stakeholders pointed out that work on dispatch of contingency reserves has consistently been rated a low priority on MISO’s project selection process.
Stakeholders were asked to provide input on the two proposals within a few weeks.
MISO Moving to 3-Hour Clearing Window by November
MISO’s David Savageau said the RTO is on track to “consistently” solve the day-ahead market within three hours.
Savageau said work will continue on the day-ahead and reliability assessment commitment software over the next four months. MISO is “confident it will meet the three-hour window in November,” he said.
MISO Sends Out Customer Survey
MISO has sent its 2016 customer satisfaction survey to 1,200 potential respondents, MISO spokesperson Jay Hermacinski told stakeholders, urging their participation. The survey, independently administered by Opinion Dynamics, is open for responses until Aug. 5.
“We take the results seriously. We analyze the data geographically, we share results with the Board of Directors, we post results to our website,” Hermacinski said.
FERC’s technical conference last week on Order 1000’s performance produced a mix of feedback, with some participants suggesting complete overhauls of the landmark rule and others saying it’s too early to tell if any changes would be useful. But nearly every participant urged the commission to improve transparency in transmission planners’ decision-making processes (AD16-18).
FERC Commissioners lead technical conference on Order 1000
Issued in July 2011, Order 1000 sought to increase transmission development by eliminating incumbent utilities’ monopolies and creating incentives for more innovative, cost-effective and efficient projects.
The order — and its 2012 sequels, 1000-A and 1000-B — have caused heated debate as well as confusion about how the order is to be applied.
Transparency and ‘Evaluation Risk’
Dawe
George Dawe, vice president of Duke-American Transmission Co., said one of his biggest challenges as a competitive developer is what he called “evaluation risk.”
“I have no idea what the RTO is going to do. I have a general framework for how they plan to evaluate my project after I’ve spent ‘X’ amount of dollars, but no real idea because they’re not being real specific. We need that kind of clarity to keep the developers engaged.”
Those on the customer side also called for transparency.
Gulley
Donald L. Gulley, president of the Southern Illinois Power Cooperative, said his members are not only asking for transparency but also the opportunity to review the results so they can understand what is working and what isn’t. “What it comes down to for us is … what is the consumer ultimately going to pay?” he said.
However, increased transparency poses a litigation risk for RTOs, said Craig Glazer, PJM vice president of federal government policy.
“Order 1000 is driving transparency, so it is driving us to put more and more things in our Tariff. We’ll have to sort of step back when trying to balance between transparency and specificity in the Tariff with not so much specificity that we have taken away the judgment and discretion part of planning,” he said. “When we document every part of the process, that, to me, is creating the ‘gotchas’ that we will have to deal with.”
Ivancovich
CAISO Deputy General Counsel Anthony Ivancovich added that “a wrong decision that can be corrected by litigation is much better than a wrong decision that’s embedded in your tariff and can’t be resolved by litigation because it’s the filed rate.”
Cost Containment
Williams
Another recurrent topic during the two-day conference was cost caps. Noman Williams, the chief operating officer and senior vice president of engineering and operations for GridLiance, said caps change the standard transmission development process by transferring the risk of overruns from ratepayers to the builder. “It brings value back to the consumer,” he said. “It is incumbent on us, when we say we want those opportunities and we don’t want to have structure, that we also explain how the cost-containment, cost-cap bids can be applied.”
Sharon Segner, vice president of LS Power Development, lauded PJM and CAISO for figuring out “how to make the cost caps enforceable and not just a PowerPoint presentation.” Developers who fail to stay within their caps risk both the project and the approved rate, she said, and “that is a lot.”
Hanemann
Kim Hanemann, senior vice president for delivery projects and construction for Public Service Enterprise Group, said cost-containment provisions “are of limited value.” PSEG “does not view Order 1000 right now as improving the transmission planning process or bringing value to our customers” because it focuses too exclusively on costs, she said.
“Projects with the greatest overall value may be more expensive in the short term, but they might provide other ancillary benefits, such as reducing congestion and replacing aging infrastructure,” she said. “Simply put, the project with the lowest bid-cost is not necessarily the best project or value for our customers.”
In 2014, PJM planners recommended PSEG’s Public Service Electric and Gas to construct a stability fix for the company’s Artificial Island nuclear complex in New Jersey. However, the PJM board reopened the bidding and ultimately awarded much of the project to LS Power, citing the developer’s lower cost and inclusion of a cost cap.
Mroz
Richard S. Mroz, president of the New Jersey Board of Public Utilities, said cost and cost caps shouldn’t factor into decision-making until the end of the process.
The process must focus on the scope of the project and what needs to get done, he said, before it can determine how much that will cost. “That’s something that can get lost in the process. That sense of cost consciousness is what drives me and what should drive the process for everyone.”
Lucas
John Lucas, general manager of transmission policy and services for Southern Company Services, who was also representing Southeastern Regional Transmission Planning, asked that the region — which isn’t overseen by a grid manager — be excused from any rules on cost-containment.
“We would note that [cost caps are] voluntarily adopted processes … that were not required in Order 1000,” he said. “Therefore, if the commission feels the need to make adjustments in those regions, we would just ask that you direct changes to the regions where those processes have been adopted.”
Debate over Incentives
There was also debate regarding project incentives, with consumer advocates saying some should be eliminated while industry members asked for more and said they wanted several — including construction work in progress and abandonment incentives — standardized for all projects.
Bernardy
That brought strong opposition from Peggy Bernardy, staff counsel with the California Department of Water Resources. “The commission should resist the urge to standardize incentives that might be calcified and set in stone for perpetuity,” she said. “That is a risk to us.”
Hughes
“The commission is perhaps unwittingly complicit in creating an investment environment in which nothing gets done without some form of ‘incentives’ — but which, in reality, are subsidies that only create the illusion of success,” said John Hughes, CEO of the Electricity Consumers Resource Council (ELCON). “Subsidies to promote responses by independent transmission companies to the competitive solicitations mandated under Order No. 1000 do not achieve competitive markets.”
Developers, however, said the potential revenue offered by incentives are key in larger companies getting projects supported by their executives.
Sponsorship or Competitive Model?
Raja Sundararajan, vice president of transmission finance, strategy and siting for American Electric Power, said the order is largely working well, containing both necessary flexibility and transparency. Of the two project-selection methods — sponsorship or competitive bidding — he greatly favored the latter.
Sundararajan
CAISO, MISO, SPP and WestConnect have adopted the competitive bidding model, in which transmission planners, with stakeholder input, identify the projects they want and then solicit bids from developers. The winners are eligible for regional cost allocation.
Under the sponsorship model, in contrast, transmission planners and stakeholders identify transmission needs and allow developers to propose potential solutions. PJM, ISO-NE, NYISO, South Carolina Regional Transmission Planning, Florida Reliability Coordinating Council, Southeastern Regional Transmission Planning, Northern Tier Transmission Group and ColumbiaGrid have adopted the sponsorship model.
CAISO’s competitive solicitations have a six-month window that allows time to put together a “real” proposal, Sundararajan said. The sponsorship model is “great for generating ideas” but “doesn’t lend itself” to preparing a comprehensive proposal because it doesn’t allow enough time for the necessary research, he said.
Sheehan
“When the rules are known and the methodology is consistently applied, business works best,” said Michael Sheehan, executive director of NextEra Energy Transmission. California is “getting repeated bidders coming back to competitions in that market because it is clear, transparent, consistently applied and you’re getting feedback.”
ELCON’s Hughes called the project-approval process “nothing more than a food fight” within the RTOs, saying that his membership is seeing transmission costs rise each year without any benefits to show for it.
Southern Co.’s Lucas said there hasn’t been enough information gathered yet to suggest any changes to the order, while Omar Martino, director of transmission for EDF Renewable Energy, said there are many changes that need to be implemented. RTOs are holding onto “historical ways of doing things” that are increasing congestion and hampering grid efficiency, he said.
Planning vs. Regulation
Glazer
PJM’s Glazer said that by factoring cost into their project approvals, RTOs are effectively setting rates. That movement into a regulatory role “is what makes us nervous,” he said, suggesting the RTO be allowed to take tough decisions to FERC for a second opinion.
PSEG’s Hanemann said grid operators don’t have adequate proficiency in several project development considerations, such as environmental permitting requirements, industry practices, local regulations and equipment procurement.
CAISO’s Ivancovich warned against installing rigid mathematical formulas for decision-making, saying it doesn’t allow for evaluating each proposal on its facts. “You need to establish integrity and credibility that we will be fair in looking at” each proposal, he said.
The entire proceeding was guided by the FERC commissioners’ questions on the positive and negative impacts of the order. Commissioner Cheryl LaFleur said she attempts to follow what she called the “regulatory Hippocratic Oath: Don’t make things worse.”
LaFleur
In a statement before the hearing, LaFleur noted that FERC has dealt with ratemaking and incentive issues resulting from the order on a case-by-case basis and asked for feedback on whether it should issue a policy statement or rulemaking to address the issues generically. “I also hope to address how to harmonize requests for incentives, particularly regarding return on equity, with competitive proposals that include cost caps or other limits on a developer’s ability to recover costs,” she wrote.
After more than two contentious years of ordering ISO-NE and the New England Power Pool to design sloped zonal demand curves for its constrained zones, FERC last week accepted a compliance filing that does that and also modifies the systemwide demand curve.
The changes will be effective for February’s 11th Forward Capacity Auction for delivery year 2020/21 (ER16-1434).
The RTO and NEPOOL filed Tariff revisions April 15 in response to a commission order Dec. 28, which said the use of vertical demand curves in constrained zones failed to address concerns over price volatility and market power.
The commission had approved the RTO’s systemwide sloped demand curve in May 2014, conditioned on its promise to develop sloped zonal curves in time for FCA 10 in February 2016. The commission granted extensions as the RTO, NEPOOL and stakeholders attempted to reach consensus. But it grew tired of the delays after the RTO said last year that it would be unable to institute sloped zonal curves for the 2016 auction. (See FERC Orders Sloped Zonal Curves for FCA 11.)
The April 15 filing asked the commission to approve both the zonal curves and changes to the systemwide demand curve.
The parties said the new demand curves will significantly improve the performance of the Forward Capacity Market by setting prices that more accurately reflect the locational marginal reliability impact of capacity — how an increment of increased capacity affects the risk of falling short of demand, as measured in hours per year.
The new design relies on two steps: an assessment of the reliability improvement from procuring incremental capacity for each possible capacity level in each zone, and establishment of the prices for each demand curve proportional to the improvement.
Generators opposed the introduction of the systemwide change, arguing it was beyond the scope of the proceeding. They also said that frequent changes in the FCM, including the Pay-for-Performance program that begins in 2018, introduced uncertainty.
“We appreciate desire for certainty of market design as expressed by” generators, the commission wrote. “We balance it with our stated concerns regarding the potential exercise of market power and unnecessary price volatility, while also meeting ISO-NE’s own objectives to achieve reliability, sustainability and cost-effectiveness in its capacity procurement.”
FERC also said that even if the proposed Tariff changes were found to be outside the scope of the proceeding and filed separately, they would have been accepted.
State regulators on Friday approved Public Service Company of New Hampshire’s divestiture of the Merrimack Station and other generation assets, ending a 20-year odyssey that began with the state’s Electric Utility Restructuring Act of 1996 (DE 11-250, DE 14-238).
The New Hampshire Public Utilities Commission’s order approves a settlement negotiated last year between the utility and regulators in which PSNH, a subsidiary of Eversource Energy, would recover $415.5 million from ratepayers for the cost of a scrubber at the 439-MW coal-fired plant.
Merrimack Station Source: Wikimedia
Eversource shareholders would forego $25 million in deferred equity. (See Eversource to Sell New Hampshire Plants.) The order also said the company “prudently incurred” the costs associated with the installation of the scrubber, which was approved by legislators in 2014.
The order also approves the sale of all Eversource generation assets in the state through an auction, which is expected to net $165 million in customer savings from 2017 through 2021.
More than a year ago, a state report said the Merrimack plant sale could net $225 million. In the meantime, however, cheap natural gas has strengthened its position as the dominant fuel source in ISO-NE and power prices have dropped dramatically. (See ISO-NE: Power Prices Fell by One-Third Last Year.)
In addition to Merrimack, and nine hydroelectric plants totaling 69 MW, the sale includes the 400-MW oil-gas Newington Station, built in 1974, and the 63-year-old, 150-MW Schiller Station, which burns coal, oil and biomass.
The plants are the last utility-owned generators in the state. PSNH challenged the 1996 restructuring law, which required retail choice and the divestiture of all utility generation, resulting in years of litigation. In 2003, the state legislature approved a bill delaying PSNH’s sale of its fossil or hydro assets until 2006.
Eversource must transition to competitive procurement for default energy service within six months of the sale of the assets. The agreement also calls for the company to provide tax stabilization to the host communities of the sold plants for three years if the plants sell for less than their assessed values.
The settlement also approves the sale of rate reduction bonds, which will finance the stranded cost balance at a lower interest rate lower than the return on equity that Eversource would receive if its generation remained in rate base. Eversource shareholders will also contribute $5 million to establish a clean energy fund for initiatives throughout the state.
The PUC said the settlement “involved a balanced compromise and resolved technically complex issues arising from the divestiture of Eversource’s generation assets.”
The newly expanded Panama Canal locks will be able to handle 90% of the world’s LNG tankers, reducing shipping time and expense for shipments to Asia from Gulf Coast terminals, according to the Energy Information Administration.
The 6th U.S. Circuit Court of Appeals, rejecting a Sierra Club challenge, has ruled that an Enbridge oil pipeline that crosses a national forest in Michigan doesn’t need a new permit to keep operating.
