KANSAS CITY — SPP’s Strategic Planning Committee on Thursday endorsed a plan to make incumbent transmission owners responsible for providing cost estimates for non-competitive projects.
The plan recommended by the Competitive Transmission Process Task Force — Solution 2A — easily cleared the Markets and Operations Policy Committee earlier last week. It adds additional cost analysis of competitive-projects by transmission owners. SPP and third-party vendors would still evaluate competitive projects subject to Federal Energy Regulatory Commission Order 1000.
Although the overall timeline remains the same, Solution 2A adds three and a half weeks of study development, allowing for a better cost analysis, said Xcel Energy’s Bill Grant, the task force’s chair.
“For the projects that have been identified as non-competitive, we will receive the estimate from the transmission owner instead of the third-party vendor,” Grant said. “At this point in time, the project has already been selected. We’re just proving the estimate is non-competitive.”
Carl Monroe, SPP’s executive vice president and COO, said the additional screening “improves the estimating process, so we can give the [SPP] board better information” for selecting projects to build.
Because the process change could require revisions to the Tariff and governing documents, FERC approval will likely be required, along with the normal SPP approval process.
Load Responsibility White Paper
Golden Spread Electric Cooperative’s Mike Wise updated the SPC on the Capacity Margin Task Force’s Load Response Entity (LRE) white paper, which cleared the MOPC earlier in the week. The document is intended to ensure all load served by SPP’s balancing authority has sufficient capacity.
“If an entity is not responsible for a load forecast or contract,” Grant asked during the MOPC discussion, “should the customer be an LRE?”
“The first and most critical step is to make everyone adhere to the policy,” said Richard Ross of American Electric Power. “Secondly, we need to transfer the responsibility obligation to those with wholesale contracts. … It’s not my responsibility as a legacy BA.”
Developing a policy to enforce the requirement will take additional time, Wise said.
The task force asked that its charter be extended for an additional year to July 2016, a request approved by the MOPC and endorsed by the SPC.
Wise told the SPC that SPP staff is developing a deliverability study process that will allow for non-firm transmission service for planning reserves. The study will analyze all generators registered in the Integrated Marketplace and determine whether they are deliverable to all loads within the SPP balancing authority.
Engaging Prospective Members
The SPC also reviewed the final report from its Task Force on New Members and approved a recommendation to improve the process of engaging prospective transmission-owning and load-serving members.
The task force was commissioned in 2014 to develop formal processes to be followed during negotiations with prospective members.
Michael Desselle, SPP’s Chief Compliance and Chief Administrative Officer, said much of the task force’s work centered on how to involve the regulators on SPP’s Regional State Committee during the negotiation period. The task force tried to balance transparency with the need for confidential negotiations.
The report notes that SPP staff “remains solely responsible for the direct negotiations with the prospective member,” while stakeholders provide input on policy and changes to the governing documents.
The SPC discussed the legal costs for smaller entities and the threshold for “triggering events” when a prospective new transmission-owning member formally requests changes to SPP’s Tariff and governing documents or RSC bylaws.
The committee also considered the report’s definition of stakeholders: “Stakeholders include existing transmission owner members, transmission-using members and RSC members and their staffs.”
“Stakeholder means anybody and everybody in the world who feels affected in some way,” said SPP board member Phyllis Bernard, urging “SPP” be used as a modifier for “stakeholder” across all governing documents.
The task force will make several language modifications to the report before sending it to the SPP Board of Directors for its approval.
Behind-the-Meter Generation
Wise teed up a discussion on behind-the-meter generation by noting that the amount of such unaccounted-for energy is growing. “I know some market participants are not adding [behind-the-meter generation] back in[to the pool],” Wise said, “and it’s not fair.”
The Regional Tariff Working Group will take up the issue for further discussion during its Thursday meeting.
Integrated System
Monroe told the committee that SPP is continuing to incorporate members of the Integrated System and their facilities under the RTO’s Tariff. He said the majority of the IS load that would be placed under the Tariff has already been accounted for.
Monroe said that while the Northwest Power Pool has suspended its solicitation for bids to manage its energy imbalance service market, SPP continues to consult with the pool on EIS markets.
The Federal Energy Regulatory Commission ruled Thursday that a power plant owner must pay unnecessary capacity charges because it failed to correct ISO-NE records before a deadline set by the RTO’s Tariff (EL15-57).
GenOn Energy Management, a unit of NRG Energy, asked FERC in April to excuse it from buying replacement capacity to meet an obligation it was capable of fulfilling with its own resources.
GenOn said ISO-NE credited its Canal 2 generator in Sandwich, Mass., with capacity of only 303 MW — rather than the plant’s actual 556.5-MW output — in the March Annual Reconfiguration Auction for the 2015-2016 capacity commitment period that began June 1. (See ISO-NE Error Could Cost GenOn Millions.)
ISO-NE said, and FERC agreed, that the Tariff requires participants to file restoration plans for any capacity shortfall within 10 business days after notification of the ARA results. “The provision also makes clear that after they receive notification of their qualified capacity from ISO-NE, the onus is on resources to provide a restoration plan, as necessary, and if they do not do so, ISO-NE will procure capacity on their behalf and charge them for it,” the commission wrote.
ISO-NE also said it wasn’t obligated to find out why no restoration plan was filed. (See ISO-NE: Plant Owner’s Responsibility to Flag Capacity Error.) FERC concurred. “We agree with ISO-NE that it is not ISO-NE’s responsibility to second-guess the market participant’s failure to submit a restoration plan after being notified of its qualified capacity,” it wrote.
The commission said reopening the auction as an alternative remedy would create market uncertainty.
In order to administer the capacity market, “ISO-NE must ensure that the auction results are final, and that, once the auction is concluded, market participants are able to take actions and enter into transactions immediately, based on those auction results,” it concluded.
Personal finance website WalletHub has released a study that ranks the states and D.C. based on the average monthly cost of energy, with breakdowns by electricity, natural gas, vehicle fuel and home heating oil.
D.C. ranked lowest overall, followed by Colorado and Washington state. Connecticut, Wyoming and Massachusetts had the highest overall bills. D.C. residents also pay the least for electricity, followed by Illinois and New Mexico. Electricity costs are highest in Hawaii, South Carolina and Alabama.
Lower prices don’t always equate to lower bills, the study shows. Its authors used the states’ average monthly energy consumption in each category and multiplied it by the average price, adding each category to find the total cost. In Southern Louisiana, for example, where the summers are hot but the electricity is cheap, residents will pay more than in Northern California, where customers consume less because the weather is temperate.
DELAWARE
State Offers Rebates to Spur Electric Car Sales
The state has earmarked $2.7 million to fund the new Delaware Clean Transportation Incentive Program, which aims to encourage residents to buy electric, propane and natural gas vehicles.
The initiative will provide three rebate programs for consumers and two grants for the development of infrastructure to support alternative fueling. Rebates will run up to $20,000, and developers may qualify for grants up to $500,000.
District to Buy Output of Pa. Wind Farm in Record Deal
The district plans to purchase the entire output of Iberdrola Renewable’s 46-MW South Chestnut wind farm in Pennsylvania, which will provide 35% of the municipal government’s renewable power portfolio.
The 20-year power purchase agreement is the largest of its kind to be entered into by a U.S. city and is expected to save taxpayers $45 million over the next two decades. The district has a goal to meet half its government’s demand by 2032 with renewable energy.
The wind farm contains 23 turbines on private property in three townships in southwestern Pennsylvania.
The Commerce Commission is planning three public forums this month about the proposed Grain Belt Express direct-current transmission line. The line would run through the Illinois counties of Pike, Scott, Greene, Macoupin, Montgomery, Christian, Shelby, Cumberland and Clark.
Clean Line Energy seeks a certificate of public convenience and necessity for the 780-mile-long project, which would deliver wind power from Kansas to Indiana. Hearings are set for July 28-29 at various sites.
State Claims Global Domination in Airport Solar Generation
Indianapolis International Airport says it now operates the world’s largest airport solar farm.
Contractors recently completed a second phase of the airport’s solar farm, bringing total output to 17.5 MW, or enough to power 3,200 houses. Indianapolis Power & Light is buying the power from what now looks like a sea of blue-colored solar panels near the end of runways on the southwest corner of the airport.
The 161-acre site is to expand farther this year, with an additional 22 acres designated for solar generation. When all three phases are completed, the solar farm will consist of 87,000 panels.
Wind Could Meet 40% of State’s Energy Needs by 2020
An American Wind Energy Association report said the state could produce enough wind energy to meet 40% of its power needs by 2020 and all of its electricity demand by 2030.
The report acknowledges that a fuel mix will always be necessary, but it said wind, solar and energy-storage technologies are improving at a rapid rate. “Iowa is already a leader in wind energy, but this report shows the Hawkeye State has just scratched the surface of wind power’s benefit to the state,” said Tom Kiernan, AWEA’s CEO.
The report said the wind energy industry employs 7,000 in Iowa at 13 factories and assembly plants. Lease payments to landowners by wind energy companies could increase from the $17.1 million a year now to $55 million by 2030.
Report: State’s CO2 Emissions Highest in the Country
A new report looking at air pollution from the country’s power plants found that the company that emits the most carbon dioxide per megawatt-hour is Big Rivers Electric. Also in the top 10: East Kentucky Power Cooperative.
The study considered how much electricity the plants generate along with sulfur dioxide, nitrogen dioxide, carbon dioxide and mercury. Seven of the 10 companies with the highest emissions per megawatt-hour were energy cooperatives.
Kentucky’s ranking is largely due to the portion of coal in its energy portfolio, said Dan Bakal of Ceres, a sustainability advocacy group.
An initiative to boost the region’s natural gas supply would cost consumers more than it would save them, according to a study commissioned by the state Public Utilities Commission.
A cost-benefit analysis of the Maine Energy Cost Reduction Act, which was approved by the Legislature in 2013, shows the act may be counterproductive. Boston-based consultant London Economics International said the state’s plan to augment natural gas supply would be costly. “Maine simply does not use large amounts of gas and electricity,” it said.
The 2013 law is designed to lower energy costs for consumers by having the state enter into contracts to purchase up to 200 million cubic feet per day of natural gas at a cost not to exceed $75 million annually. Ratepayers in the state would foot the bill.
Texas-based Clearview Energy is attracting complaints for alleged aggressive sales tactics by its door-to-door teams in Central Maine Power’s service area. CMP and the Maine Public Utilities Commission say customers have complained that Clearview’s salespeople sometimes ask customers to show them their monthly bills.
The company says it’s doing nothing wrong and last week responded to a PUC request for information with details about its training and sales protocols. The company also blames CMP for stirring up trouble, charging that the utility’s staff is anti-competition.
The PUC, which licenses electricity suppliers, said it is evaluating the information submitted by Clearview and deciding what, if any, steps to take. It said that Clearview appears to be the first electricity provider using door-to-door sales in Maine, and it’s the first time the PUC has received complaints about the practice.
Pepco, SMECO Pair with Energesco in Efficiency Program
Pepco and Southern Maryland Electric Cooperative are partnering with Energesco Solutions to provide energy and water efficiency for multifamily buildings in the state under a new rebate initiative, the Commercial Multifamily Program.
Multifamily properties within Pepco’s 566 square miles of service area can apply for rebates for energy efficiency projects like LED lighting upgrades and HVAC enhancements.
Energy costs in such communities represent 25 to 35% of expenses and are highly controllable. Previously, multifamily owners and operators were restricted to rebates for upgrades in common areas.
Online Marketplace Would Allow Comparison Shopping for Rates
The state is planning to build an online marketplace where consumers can shop for competitive suppliers.
The Department of Public Utilities soon will begin soliciting ideas to build the website. Under the DPU proposal, companies initially would be allowed to offer only fixed-rate plans so consumers would be shielded from hidden charges and confusing contracts.
Several other states, including Ohio, Texas, Connecticut and Pennsylvania operate similar marketplaces. The state experienced a growth in customers shopping for suppliers after last year’s bone-chilling winter sent electricity prices soaring.
The Senate has begun hearings on a comprehensive energy plan governing how utilities and alternative suppliers may operate in the state and how renewable power and energy efficiency programs will figure into the equation.
Among other things, the Senate’s plan would offer incentives for utilities that already have met a renewable energy mandate to increase their energy efficiency programs.
The most controversial aspect of the plan would make it more difficult for electricity customers to opt in or out of the competitive retail supply market.
Straits of Mackinac Pipeline Report Shows ‘Gaps’ in Enbridge Info
A state report on the twin pipelines running under the Straits of Mackinac said operator Enbridge’s assurances that the pipelines are safe and don’t need replacement were unsupported by data.
The report said the yearlong inquiry by the state Department of Environmental Quality and the Attorney General’s Office was hampered by “gaps” in information provided by Enbridge. Dan Wyant, DEQ director, said Enbridge failed to provide comprehensive information in many areas, including inspections and the nature and result of heavy mussel encrustations that could be hiding significant corrosion.
“Substantial questions remain and can only be resolved by full disclosure of additional information and rigorous, independent review by qualified experts,” the report concludes. The report was spurred in part by the rupture of another Enbridge pipeline in 2010 that spilled oil into the Kalamazoo River.
Renewable Advocates Say Utility Blocking Small-Scale Solar, Wind
Montana-Dakota Utilities wants to assess customers with wind and solar generators a demand charge, but renewable advocates say the utility is using the fee to block small-scale generation.
MDU built the fee into a 21% rate increase it has proposed for about 26,000 customers in the state. The company said it needs the $1.50/kW demand charge to cover the cost of providing power to wind and solar customers when their self-generation isn’t sufficient to meet their needs. The fee would also pay for the costs of installing emissions controls at plants in Montana and South Dakota.
A Public Service Commission spokesman says it was the first time a utility has asked for a special fee for net-metering customers. The Montana Renewable Energy Association said the utility ignores the assertion that customers who generate their own power allow the utility to reduce transmission and distribution costs across the system as a whole.
Kinder Morgan has launched a website aimed at New Hampshire residents along the 80-mile proposed route of the Northeast Energy Direct natural gas pipeline.
The pipeline would deliver natural gas from the shale formations of Pennsylvania through New York and into New England to ease supply shortages. The new website is part of a public outreach campaign by Kinder Morgan to communicate the need for the project.
EnergymattersNH.com includes videos on the project, an up-to-date project blog, as well as a running list of upcoming project-related meetings.
Gulf, which entered the competitive electricity market with much fanfare in 2013, has quietly pulled out, the latest departure from a business sector that one competitive supplier says is on life support.
Competitive suppliers are having a hard time beating the utility prices for residential power supply. Bart Fromuth, a Republican state representative from Bedford and head of Resident Power, one of the earliest brokers to enter the residential space in 2012, said the pullback mostly affects the retail residential market.
“Commercial competition remains at healthy levels,” said Fromuth. “The regulatory environment for residential is absolutely suffocating. In the interests of beefing up consumer protection, the legislature and the PUC are quickly cementing New Hampshire’s position as the most unattractive place to do residential supply in all of New England.”
The Public Service Commission has adopted a public policy requirement related to the potential need for additional transmission capability in Western New York. The decision stems from a proceeding the commission initiated last year to establish procedures that it would use to identify any transmission needs driven by public policy requirements that would be referred to NYISO. The Federal Energy Regulatory Commission’s Order 1000 requires public policy be considered in system planning.
The commission determined transmission projects in Western New York that fulfill such public policy requirements will now become eligible for cost recovery through NYISO’s Tariff if they are selected by the RTO as the most efficient or cost-effective solution. Designating Western New York congestion relief as a public policy requirement will enable NYISO to solicit potential project solutions and undertake an initial analysis of the project’s viability. The PSC did not adopt other proposed public policy requirements for other regions.
Online retail giant Amazon plans to power its cloud-computing division with the $400 million Amazon Wind Farm US East, set to be built on 34 square miles in the eastern counties of Perquimans and Pasquotank.
The project will start with 104 turbines and will be built by Spanish wind farm developer Iberdrola Renewables. It is expected to begin generating power for Amazon’s data centers late next year.
The project has sidestepped obstacles that have felled such proposals in the past. The 208-MW farm is sited in isolated scrubland locally knows as The Desert where there are no homes, minimizing its impact on tourist areas, military flight paths and bird migration routes.
Study Shows Utica Oil and Gas Play Much Larger than Thought
A study by West Virginia University shows that the amount of recoverable oil and natural gas in the Utica Shale formation is much larger than first thought. The geologic formation, which includes parts of Pennsylvania, West Virginia, Kentucky, New York and Ohio, has about 782 trillion cubic feet of natural gas and about 2 billion barrels of oil, about 20 times the U.S. Geological Survey’s estimate from three years ago.
“This is a landmark study that demonstrates the vast potential of the Utica as a resource to complement — and go beyond — what the Marcellus has already proven to be,” said Brian Anderson, director of WVU’s Energy Institute. The study leans heavily on research conducted by the Appalachian Oil and Natural Gas Consortium.
“The revised resource numbers are impressive, comparable to the numbers for the more established Marcellus Shale play, and a little surprising based on our Utica estimates of just a year ago,” said Douglas Patchen, director of the consortium. The announcement came as low oil and natural gas prices continue to curtail new production.
Enbridge Pulls Its Appeal of Pipeline Insurance Regulation After State Legislative Action
Lawmakers amended the state budget to prohibit local governments from imposing higher insurance demands on pipeline operators, a move that handcuffs Dane County, which had demanded Enbridge boost its liability coverage. Enbridge immediately dropped an appeal of the local mandate.
Dane County officials were irked. “Enbridge filed an appeal properly, and we were set to hear that appeal and make a decision,” said Dane County Board Chairwoman Sharon Corrigan. “That’s how it’s supposed to work. But apparently Enbridge sent some lobbyists to make a different kind of appeal to the Legislature and the governor, and got some special treatment slipped into the budget.”
The Federal Energy Regulatory Commission last week declined to rehear DTE Electric’s contention that MISO rules put generation developers at a disadvantage in the competition for reliability projects.
DTE had sought review of FERC’s September 2014 ruling approving MISO’s requirement that a proposed generator must have filed an interconnection agreement to be considered as an alternative to a transmission solution. The agreement is due before the date MISO must initiate the transmission project to meet its required in-service date.
Comparable Treatment
The commission agreed with MISO that the requirement is comparable to those required for transmission solutions in its Transmission Expansion Plan process (MTEP). FERC also accepted MISO’s compliance filing in response to the commission’s Order 809 transmission planning requirements (OA08-53-005, ER15-133).
To allow generator proposals to progress through the interconnection process, DTE said more time is needed between when MISO identifies a system need and when it approves a transmission facility to meet the need. The time it takes MISO to complete interconnection studies “makes it more likely than not that a generation project could never even be considered by MISO as an alternative to a transmission project,” DTE said.
The company said generation developers won’t have the information they need regarding potential system needs until Sept. 15, when transmission owners must identify and submit new transmission projects within the MTEP process.
FERC said that developers should be able to identify system needs based on power flow models available in June. But DTE countered, “It is far-fetched to believe that a proponent of a generation solution would be able to use that data to determine that a transmission problem existed or even if it could, offer a generation solution to that problem in the allowed timeframe.”
The commission was not persuaded. DTE “does not explain why a generation developer must wait until a transmission facility is proposed before it can identify potential generation solutions to the needs the transmission facility is meant to address,” FERC said. “Just as the proponent of a transmission solution considers system needs to identify potential transmission facilities to meet those needs, so too can the proponent of a generation solution.”
Catch 22?
Developers have until April to submit generation projects — including executed interconnection agreements — as alternatives to transmission projects that were proposed the preceding September.
DTE disputed the commission’s finding that a generator that may mitigate a particular transmission need is likely being evaluated in the interconnection process long before the April deadline.
The company noted that generators in the interconnection process are considered operational. As a result, it said, any transmission projects identified in the MTEP process will be those needed in addition to generation in the interconnection process, and any new generation alternatives would be precluded from ever being evaluated against the newly identified transmission need.
FERC saw it differently. “If a generation solution that goes through the interconnection process and has an interconnection agreement filed with the commission does in fact address the need, MISO will not identify a transmission facility to meet the need and the generator alternative will have successfully replaced a transmission facility,” the commission said.
Not Viable
FERC agreed with DTE that MISO is unlikely to replace an approved transmission facility with a generation solution if the transmission developer has already begun right-of-way acquisition, completed design and engineering, ordered material and obtained permits.
“That means only that the generation solution did not have the necessary contractual commitments for MISO to consider it a viable alternative to the transmission solution before the transmission solution had to begin being developed,” FERC said.
KANSAS CITY — SPP’s Markets and Operations Policy Committee voted last week to change the annual auction revenue rights allocation system capacity to better match the annual transmission congestion rights (TCR) auction and reduce underfunding.
Acting on a recommendation by the Market Working Group, the MOPC changed the percentage for the ARR allocation from the original 60% of system capacity to 80% for the seasonal, or shoulder, months. The percentages are unchanged for June (100%) and July-September (90%). The modified revision request will now go before the Board of Directors for final approval.
Those pushing the 60% allocation for seasonal months said it was an aggressive number and would solve the TCR markets’ underfunding problem, but they recognized it would cause problems for some market participants.
SPP “staff felt it was really struggling to get this change in,” said Debbie James, SPP’s manager of market design. “While 80% is an incremental improvement, we really need to get rid of the carry forward. We need to match them up.” (Unsettled ARRs are carried forward to be settled in the monthly processes.)
In opposing the original 60% allocation, Xcel Energy’s Bill Grant said, “We thought 100% to 60% was overkill. Eighty percent is probably a better number in our minds.”
“I’m leery about making a change on the fly,” said Bill Dowling of Midwest Energy. “Eighty percent will still mitigate the problem, but it’s not a perfect fix.”
An ARR is a financial right that entitles the holder to a share of the auction revenues generated in the TCR auctions or the right to convert them into TCRs. ARRs were originally designed to be allocated in the annual process, meaning the full system capacity was allocated and only new entitlements were offered in the monthly allocation. In 2012, however, FERC required the monthly process be available to all existing candidate ARRs. However, updates to the full annual allocation were not made after the FERC order, resulting in the mismatch between percentages of ARRs and percentages of TCRs.
Under the current market design, ARRs are allocated based on 100% of system capacity, while TCRs are primarily awarded at 60% to 90%. That has made annual ARRs infeasible, as less available capacity is carried forward to the monthly processes. Many of the previously infeasible annual ARRs are still infeasible in the monthly process. Infeasible capacity held by these ARRs is guaranteed through limit expansion and goes to either the ARR holder as an ARR self-convert or another TCR auction participant.
The MWG recommendation will settle or convert all annual ARRs during the annual process. No ARRs would be carried forward, and infeasible TCRs would be reduced. All residual capacity would still be allocated and auctioned in monthly processes.
The MOPC had an easier time approving the MWG’s Revision Request 93 (Market Registration and Timeline Changes), which cleans up Tariff language and makes it easier to dispatch generation in the SPP footprint, and RR 99 (STRUC With QS Carve Out), which provides more accurate operational information than the current intraday reliability unit commitment process.
The MOPC approved another nine RRs recommended by the MWG as part of the consent agenda, along with four RRs from other working groups.
2017 ITP10 Update
ITC Great Plains’ Alan Myers, chair of the Economic Studies Working Group, updated the MOPC on the group’s work on the 2017 Integrated Transmission Planning 10-Year Assessment, just two months into its 18-month cycle.
“Our original intent was to bring you the [assessment’s] entire scope today, but we just have an update,” Myers said. “We expect to bring you something in October with better quality and [that is] more formulaic than we have in the past.”
Myers told members the ITP10 will implement new criteria for modeling future resources, defining bounds around specific resources stakeholders can submit for inclusion in ITP10 and ITP20 studies.
The 2017 study will also rank constrained flowgates’ congestion costs. Up to 25 constraints — with a minimum of $50,000 in annual congestion each — will be identified as economic needs.
The study will use financial advisory firm Lazard’s 2014 Levelized Cost of Energy Analysis, as well as other metrics such as 2012 hourly wind profiles; Department of Energy growth rates and NYMEX futures for natural gas prices; and ABB’s North American Electric Reliability Corp. data for coal, oil and uranium prices.
The ESWG has completed a load and generation review and a survey of anticipated renewable energy mandates and goals. It is currently working on developing the ITP10’s scope and futures, various resource plans and building an economic model.
The model will assume SPP’s 13.6% reserve margin, and 5% and 10% accreditation for future wind and solar resources, respectively.
The study will use three futures revolving around a regional Clean Power Plan solution: one assuming the rule’s regional implementation, a second assuming state-by-state implementation and a third assuming business as usual. Each future also assumes competitive wind, plentiful natural gas (due to hydraulic fracturing), normal load growth and large-scale solar generation development.
Prioritizing Revision Requests
The MOPC approved the creation of a more formal process for prioritizing RRs, including a scoring system and facilitated quarterly discussions open to all stakeholders. If approved by the board, the process would begin with the first two quarterly cycles of 2016.
“This will be transparency stakeholders have never had before,” said Xcel Energy’s Grant, the chair of the Stakeholder Prioritization Task Force, which recommended the changes.
Grant said the new prioritization process would not evaluate projects that don’t clear the working group process. The process would use a standardized scoring tool to rate RRs and enhancements, including capital projects and RRs initially scored by SPP staff and working groups. The results would be tabulated in a portfolio report listing projects, RRs, enhancements, defects and associated data (priority scores, initial cost estimates and target implementation dates).
An open stakeholder meeting would be held each quarter to discuss the report; an updated portfolio and written meeting summary would be published for each MOPC meeting. The committee would review and discuss during its regular member forum.
The SPTF’s proposal addresses a request for stakeholders’ increased transparency and input into the prioritization process.
The MOPC also approved the task force’s request to extend its charter an additional year. “We want to stick around long enough to make sure the process is providing the desired stakeholder input,” Grant said.
RCAR Remedies
The Regional Allocation Review Task Force updated the MOPC on its work on a business practice to correct imbalanced cost allocations. Potential remedies would be added to the Tariff as part of SPP’s Regional Cost Allocation Review (RCAR).
American Electric Power’s Richard Ross, the task force vice chair, said the RCAR II analysis needs to be completed by October 2016. That requires, in turn, transmission topology updates to the RCAR models be completed by Oct. 1, 2015, and member commitment to provide the necessary help.
“We need creative solutions, because the process is not working as well as it was intended,” Ross said.
SPP staff has been developing a strawman business practice in coordination with SPP’s Regional State Committee, documenting remedies and clarifying their implementation. Remedy requests and any changes to the business practice would go to the RARTF.
The business practice comes in response to FERC’s rejection of a February 2015 filing that would have added remedies to Attachment J of the Tariff.
Xcel Energy protested the filing, asking the commission to reject the proposed remedies and have SPP develop modifications to the existing methodology for new transmission projects. Rather than refile, the RARTF directed SPP staff to create a strawman business practice.
Transmission Planning Improvement Update
The Transmission Planning Improvement Task Force reported good progress since its formation in the spring. The team has met four times, said Jason Atwood of Northeast Texas Electric Cooperative, with a goal of making transmission planning’s model building, transmission assessment and engineering services “bigger, better and quicker.” It will spend the next few months looking at futures, scenarios and sensitivities.
The task force is discussing whether to conduct the 10-year, near-term and transmission-planning assessment studies at the same time in an 18-month overlapping process, which would produce study results on an annual basis. Atwood noted an annual basis could provide more accuracy.
Wind, Solar Ratings Unchanged
The Generation Working Group recommended no changes to SPP’s methodology for establishing net capability for wind and solar facilities. SPP currently requires that wind resources’ ratings correspond to the load-serving members’ peak hours. The GWG’s data indicate that the value varies from 5% to more than 50%, dependent upon location and timing of peak load.
“This confirms the methodology that the wind resource’s planning capability should be based both on location and tied to load,” the GWG’s report said. The report also confirmed the current default value of 5% used for facilities in commercial operation for three years or less “is reasonable.”
Charter Revisions OK’d in Preparation for Integrated System
The MOPC approved charter revisions for five working groups, allowing them to add Integrated System representation when the IS joins SPP on Oct. 1. Business Practices will go from 10 to 12 members, Economic Studies from 14 to 18, Operating Reliability from 12 to 17, Operations Training from 11 to 15 and Reliability Compliance from 15 to 17.
The committee also approved a name change for the Reliability Compliance Working Group — subbing “regional” for “reliability” — accurately reflecting the group’s purpose and scope. It also gave the go-ahead to a revised scope for the Economic Studies Working Group to allow for additional reviews and approvals of items that align with its knowledge base and current Tariff processes.
‘Incredible Improvement’ in Reliability
Noting a continued decreased trend in violations, Ron Ciesiel, general manager of SPP’s Regional Entity, reported to the MOPC only one category 1 event — a loss of an hour or more of monitoring or control at a control center — was analyzed in the second quarter.
Ciesiel also said the SPP RE has completed its ninth consecutive quarter without a vegetation-contact report. SPP was the last region in the NERC to report a contact, in the first quarter of 2013.
Ciesiel also noted that there are some days in which NERC has no reportable incidents in all of North America.
“That is an incredible improvement from where we were eight years ago,” he said.
KANSAS CITY — SPP’s Z2 credit project, years in development and the source of much member frustration, is on track to be completed in 2016. But those involved say they can’t estimate the size of the bills SPP may be handing out as a result.
“We don’t know if this is a bread box or a semi-trailer yet,” said Dennis Reed, chair of the Regional Tariff Working Group, who briefed the Markets and Operations Policy Committee last week.
The purpose of the project is to create software that would properly credit and bill transmission customers for system upgrades under Tariff attachment Z2. The problem has been trying to avoid over-compensating project sponsors and include a way to “claw back” revenues from members who owe SPP money for other reasons. Accounting for transfers of reservations has also been a challenge.
“This policy decision was made 10 years ago … we didn’t plan for [the bills] to build up over time,” said Kansas Power Pool’s Larry Holloway, one of several members expressing frustration. “I asked SPP at the time if they had enough Commodore 64s to get this done, and they said they did.”
Reed, director of FERC compliance for Westar Energy, said his group and SPP staff are working to estimate the amount of crediting, but he noted an accurate number can’t be made until the software is completed.
“We have to go through the bulk of the process before we know what the numbers will be,” explained SPP Chief Operating Officer Carl Monroe.
Reed said possible methods of phasing in catch-up payments are also being developed.
Reed said installment payments would help “the smaller entities who don’t have big budgets — say a small city — that all of a sudden [are] faced with a huge bill.”
Reed said the RTWG would bring back some ideas to the October MOPC meeting that “may or may not require” a Tariff filing.
Accenture, which helped SPP implement the Integrated Marketplace on time and on schedule last year, has been hired to manage the Z2 project. The company expects to have a production-ready system built and tested by the end of January 2016.
Following the system’s implementation, SPP will begin the process of calculating past billings and payments, billing customers and paying those who funded network upgrades. Monthly billing will be a change for current long-term service customers.
“The number is going to come out. We can’t predict it, but the cloud of uncertainty is there,” said Aundrea Williams of NextEra Energy Resources. “I need to get ready for the number and to start planning for it.”
KANSAS CITY — SPP members approved four over-budget transmission projects and sent three others back to the drawing board last week amid widespread criticism of the process used to estimate project costs.
SPP Director of Planning Antoine Lucas makes a presentation to the Markets and Operations Policy Committee as board members Harry Skilton and Phyllis Bernard (front row) listen.
Of 30 committed projects resulting from the 2015 near-term (ITPNT) and 10-year (ITP10) planning processes, 23 are facing cost estimate increases exceeding 30%, SPP officials told the Markets and Operations Policy Committee last week. Three projects are coming in more than 30% below estimates with only four within the 30% “bandwidth.”
Describing a 152% increase on the Hobart-Roosevelt Tap-Snyder rebuild in American Electric Power territory in Oklahoma, SPP Director of Planning Antoine Lucas said “it makes us question whether this was the right project.”
“I find this really appalling,” SPP Board Chairman Jim Eckelberger said. “We’ve taken a huge step backwards. We need a procedural adjustment.”
A third-party engineer estimated the project — rebuilds of a 10-mile, 69-kV line from Hobart to Roosevelt and an 18.7-mile, 69-kV line from Roosevelt to Snyder — would cost $14.3 million.
SPP now expects it to cost $36 million due to additional right-of-way acquisition; licenses and permits; additional substation work; and costs related to a crossing through Mountain Park Wildlife Management Area. SPP also cited AEP’s recommendation that the project be designed anticipating an eventual conversion to 138 kV.
Fire the Engineer
SPP should fire the third-party engineer “and never use him again,” Eckelberger said, drawing applause from many of the about 120 in attendance.
“I’ve seen this over and over again,” Director Julian Brix complained. “This is not a 69-kV project [as originally approved by SPP]. It’s a 138-kV project. This is not the first or second or third time we’ve seen this. This is why we get into trouble with the [Regional State Committee],” he said, referencing state regulators who must collect from ratepayers for transmission upgrades.
AEP officials said the use of 138-kV standards was responsible for only $400,000 of the additional costs. “A no-brainer,” AEP’s Richard Ross said. AEP’s Terri Gallup called complaints of “scope creep” unfair, saying the company had proposed the rebuild as a 138-kV project — that would initially be operated at 69 kV — to begin with.
Xcel Energy’s Bill Grant noted that incumbent transmission owners would become responsible for providing cost estimates for non-competitive projects under a plan approved by the MOPC earlier in the meeting. (See related story, “Initiative on Non-Competitive Studies Advances” in SPP Strategic Planning Committee Briefs.) “I think we have a solution,” Grant said.
Marguerite Wagner of ITC Holdings said transparency would improve the process, calling for release of cost estimates to stakeholders. “If a project is not competitive, how is releasing the cost estimate competitive information?” she asked.
Director Harry Skilton said the cost estimate increases represented a “lesson learned” as the RTO begins considering competitive projects. “We’re going to need a feedback loop” regarding costs, he said.
NTCs Withdrawn
SPP planners recommended that notifications to construct (NTCs) for seven projects with the largest overruns be suspended and the projects restudied, including the Hobart-Roosevelt project.
But Gallup said Hobart-Roosevelt and two other AEP reliability projects on the list had in-service dates that might not be met if they were delayed for more study.
The MOPC ultimately voted to retain the three projects and one in Westar territory, suspending NTCs for only three of the seven recommended by planners: South Shreveport-Wallace Lake 138-kV rebuild (AEP); Martin-Pantex North-Pantex South-Highland Park 115-kV reconductor (Southwest Public Service); and Iatan-Stranger Creek 345-kV voltage conversion (Westar/KCP&L Greater Missouri Operations).
KANSAS CITY — SPP’s Markets & Operations Policy Committee voted to move the deadline for day-ahead market offers up 90 minutes to 9:30 a.m. CT, following a lengthy discussion about whether the benefits justified the change and its price tag.
The committee approved the recommendation by the Gas Electric Coordination Task Force by voice vote.
Assuming approval by the Board of Directors and the Federal Energy Regulatory Commission, SPP will post day-ahead results at 2 p.m. CT, up from 4 p.m. It also shortens the reoffer period to 45 minutes, with reliability unit commitment (RUC) offers due at 2:45 and results posted by 5:15.
The Tariff changes are a first step in complying with FERC’s Order 809, which moved the timely nomination cycle deadline for gas to 1 p.m. CT from 11:30 a.m. and added a third intraday nomination cycle (RM14-2). The commission ordered RTOs to adjust the posting of their day-ahead energy market and reliability unit commitment process results “sufficiently in advance” of the revised gas cycles, or explain why it is not suitable for their markets.
‘Very Little Gain’
SPP’s northern members voiced their continued opposition to the recommendation, saying the adjustments did little to increase the knowledge of next-day gas prices.
“Most winter gas doesn’t trade until 10 p.m.,” said the Omaha Public Power District’s Troy Via.
“I’m really surprised we went down this route,” said Lincoln Electric System’s Dennis Florom. “We see very little gain. We’re making a lot of adjustments, but we’re not getting the key benefit — a timely nomination. By making this adjustment, we are moving further away from the next operating day.”
The Nebraska Public Power District’s Paul Malone, the MOPC’s vice chair, noted that while the GECTF’s recommendation was approved by four lower stakeholder groups, the votes were far from unanimous. The Market Working Group, for example, voted 7-5 in favor with five members abstaining. (See SPP Moving to 9:30 Day-Ahead Close.)
Malone contended FERC’s order was intended to address “critical” gas days.
“This is a change for all days,” Malone said. “The real value we see is better pricing discovery. To get a half-hour change … we’re just struggling with that.”
The revised timeline would not provide day-ahead market results before the 1 p.m. CT nomination deadline, but it would provide 30 minutes before the Intraday 2 nomination. RUC results would be available 45 minutes before the 6 p.m. evening gas nomination.
Enhanced Combined-Cycle Project
In presenting the GECTF’s recommendation, Oklahoma Gas & Electric’s Jake Langthorne said the changes would provide an opportunity to use the evening gas nomination period and provide some price formation in the morning before the day-ahead market closes.
Langthorne also said the move would allow for continued progress with the enhanced combined-cycle project, an effort to provide more sophisticated modeling that captures such plants’ flexibility. The board last year suspended work on the project until after the Integrated System entities join the RTO as full members in October, allowing time for a more thorough cost-benefit study. (See Combined-Cycle Model’s Cost, Benefit Uncertain.)
SPP has estimated it will take approximately $1.5 million and 14 months to implement the schedule changes next year, which would require new software.
SPP Director of System Operations Sam Ellis said “almost 100%” of the spending on the scheduling change would also benefit the ECC project.
“I think $1.5 million is more than enough money,” Ellis said. “Both projects are investments in reducing the market-clearing engine’s solution time.”
Dogwood Energy’s Rob Janssen, a member of the task force, seemed to sway some minds when he expressed a similar long-term view.
“I’m always concerned about costs, but I’m comfortable with this after discussions with staff,” Janssen said. “The staff believes this will improve the market over time. While $1.5 million shows up as a red light, it would be hidden over time the next three to five years. We might as well make the investment and get some value for gas-electric coordination in response to FERC’s order.”
Midwest Energy’s Bill Dowling suggested a shorter RUC process to get gas nominations in as early as possible for the next day. He added, “I do find it compelling to spend some of this money on the ECC project.”
Alliant subsidiary Interstate Power & Light is retiring or switching five Iowa power plants from coal to natural gas and upgrading two other Iowa coal-fired plants as part of a settlement with the Environmental Protection Agency and the U.S. Department of Justice.
Plants in Cedar Rapids, Dubuque, Burlington, Clinton and Marshalltown will be switched to burn natural gas or retired, and new emissions controls will be installed at its two largest coal-fired plants, in Lansing and in Ottumwa. “The terms we negotiated in this settlement are consistent with our long-term plan for clean energy,” said Doug Kopp, Alliant Energy president. “We settled with the EPA to avoid unnecessary delays and ongoing uncertainty associated with litigation.”
The settlement closes out litigation in which the EPA said Alliant upgraded plants in 2006 and 2009 without installing required emissions controls. The upgrades will cost about $620 million, the company said, on top of the $6 million it will spend on environmental mitigation projects and a $1.1 million civil penalty.
Kinder Morgan Board Gives Go-ahead for $3.3B Pipeline
The Kinder Morgan Board of Directors approved the $3.3 billion Northeast Energy Direct natural gas pipeline that will run from Wright, N.Y., to Dracut, Mass. But the pipeline will have a smaller capacity than originally estimated.
The 30-inch diameter pipeline to be constructed by Kinder Morgan’s Tennessee Gas Pipeline Company will carry up to 1.3 billion cubic feet per day, down from initial estimates of 2.2 bcf per day. The company said it would amend its application with the Federal Energy Regulatory Commission if circumstances dictated the need to increase capacity.
The project is designed to deliver Appalachian shale gas to New England utilities and power plants. The company said the lack of pipeline capacity caused customers of ISO-NE to pay $7 billion more for electricity during the past two winters than they did during the winter of 2011-12.
NRG’s Canal Generating Station in Sandwich, Mass., will be returning to service, fueled by natural gas, according to Sandwich town officials.
Town manager Bud Dunham said NRG confirmed that the plant would switch from fuel oil to natural gas. The 1,112-MW plant, formerly a Mirant asset, has been inactive for several years. The repowering project is expected to be completed in 2019.
“After many years of anticipation, NRG let us know they are formally announcing plans for a repowering project in Sandwich,” Dunham said. NRG has not yet made a formal announcement.
Xcel Energy, Dairyland Power Cooperative and WPPI Energy will have to submit a new construction plan to Wisconsin regulators for a high-voltage transmission line under construction near La Crosse to halt activity during a sensitive bird nesting season.
Construction stopped last month in an area where state-protected birds were nesting. The Wisconsin Department of Natural Resources said that a 1-mile section of the project must halt during nesting season, but work in areas outside of the nesting zone will be allowed to continue.
The $500 million, 345-kV line will run between La Crosse and Rochester, Minn.
Emera Investing $80 Million in Tiverton Power Station
Emera Energy is investing $80 million to upgrade its 265-MW Tiverton power station in Rhode Island, boosting the output of the combined-cycle gas plant by 22 MW and improving its efficiency.
The upgrades to the plant’s gas turbines will save an estimated $1 million per month in fuel costs, allowing it to be dispatched more often by ISO-NE. The project will be completed during a planned maintenance outage in April.
Alpha Natural Resources, a Bristol, Va.-based coal producer, says its shares will be delisted from the New York Stock Exchange because its stock price is too low.
The company said the exchange suspended trading of its shares, which were priced last at 24 cents. Alpha recently announced it was cutting 800 jobs.
Coal mining companies are under stress, especially those in the East, because of low coal prices, low natural gas prices and competition from other states. Patriot Coal in May filed for bankruptcy for the second time in three years.
WEC Energy Group, the newly created $9 billion merger of Wisconsin Energy Corp. and Chicago-based Integrys Energy, appears to be in no hurry to set up new corporate headquarters.
WEC hasn’t narrowed down a location nor has it hired commercial real estate brokers to assist in the search, WEC spokesman Brian Manthey told the Milwaukee Business Journal. For now, WEC’s center of gravity remains in Milwaukee, the home of the former Wisconsin Energy Corp.
Most of the management in the new WEC Energy consists of Wisconsin Energy executives, including CEO Gale Kappa. WEC said its new headquarters will be in the Milwaukee area but it will retain separate offices for operating units. Wisconsin Public Service Corp., which was owned by Integrys, will keep offices in Green Bay. Integrys’ former Peoples Gas unit will retain divisional offices in Chicago.
Xcel’s Monticello Nuclear Plant Running at Increased Output
The Nuclear Regulatory Commission has granted permission for Xcel Energy’s Monticello Nuclear Generating Plant to operate at a higher capacity following upgrades that cost $748 million.
The permission allows the plant in Monticello, Minn., to operate at 671 MW, up 12% from 600 MW.
The NRC action also means Xcel can include the upgrade costs in its next rate case. The cost of the project ballooned from $320 million to $748 million. The Minnesota Public Utilities Commission blamed the problems on Xcel’s “imprudent management” and didn’t allow the company to receive a return on its investment. Xcel wrote off $125 million, nearly half of its first-quarter profits.
Dynegy is on the hunt for corporate employees following a flurry of acquisitions over the last year. The company said it was looking to fill 113 jobs, with some of them needed at its Houston headquarters where about 300 people now work.
Dynegy has made a total of $6.25 billion in acquisitions in the last year. They include the purchase of EquiPower Resources and Brayton Point Holdings. It also snapped up $2.8 billion in commercial generating assets from Duke Energy.
Invenergy to Build 200-MW Wind Project in Minnesota
Invenergy announced plans to build a 200-MW wind energy facility near Albert Lea, Minn. The company has been working to obtain landowner agreements for seven years. Invenergy said the 29,000-acre site would have about 100 turbines.
At the same time, MISO is looking at plans to construct high-voltage transmission lines to deliver the power from southern Minnesota to markets.
Invenergy also owns and operates the 357-MW Cannon Falls Energy Center, a natural gas-fired plant that went into operation in 2008.
PSEG Long Island Remains Last in Customer Service Ranking
PSEG Long Island remains last in the country among major electric companies in residential customer satisfaction, but it managed to increase last year’s score by 10%, according to a J.D. Power survey.
PSEG Long Island scored 584 out of a total 1,000 points in the survey, which reviews factors such as power quality, billing, affordability and communications. The utility’s score was 52 points higher than in 2014, when Public Service Enterprise Group took over the Long Island Power Authority. In 2013, LIPA scored 519.
Daniel Eichhorn, vice president of customer services at PSEG Long Island, said the figures showed the utility was the most improved among a list of utilities with more than 750,000 customers. “The numbers tell us we’re very focused on customer satisfaction. We are trying to create a better customer experience, to make it easier to do business with us, and improve reliability.”
ISO-NE says June Saw Lowest Monthly Prices in 12 Years
Wholesale power prices in New England fell in June to under $20/MWh, according to ISO-NE. The regional grid operator said it was the lowest monthly price in the 12 years of the competitive power markets and nearly half of the $37.92 price last June.
“It’s supply and demand,” said Matthew White, chief economist at ISO-NE. “With June’s mild weather, demand for natural gas and electricity were both low, and the pipeline capacity was available to deliver a plentiful supply of exceptionally low-priced natural gas.”
White noted that the dip in prices illustrates the seasonal volatility of prices in the New England market, which he attributed almost entirely to natural gas pipeline constraints.
The Regional Greenhouse Gas Initiative provides substantial economic benefits and has not raised prices or impaired reliability, according to an independent study released at a meeting of state regulators last week.
The report by economic consulting firm Analysis Group said that RGGI added $1.3 billion in economic value, created more than 14,000 new jobs and saved consumers $460 million on electricity and heating bills from 2012 through 2014.
“Based on an analysis of years of hard data, RGGI shows that multi-state, market-based carbon control mechanisms work and can deliver positive economic benefits,” Analysis Group Vice President Paul Hibbard said. “That’s not to say programs designed to cut greenhouse gas emissions are economic development programs — their goals are different. But the data clearly show that cutting carbon emissions can be a net positive for the economy.”
The report’s authors said the findings “provide valuable lessons for states” preparing for the Environmental Protection Agency’s proposed Clean Power Plan. The report was released last Tuesday at the summer meeting of the National Association of Regulatory Utility Commissioners in New York.
RGGI regulates carbon emissions from power plants in the six New England states, New York, Maryland and Delaware. The states have received about $2 billion in auction proceeds over its existence, investing those funds in energy efficiency programs, low-income assistance and clean energy development.
The report said initial costs are more than recovered in customer savings. “Although CO2 allowances tend to raise electricity prices in the near term, there is also a lowering of prices over time primarily because the states invest so much of the allowance proceeds on energy efficiency programs,” the report said.
The region also cut annual carbon emissions by about a third, from 140 million metric tons in 2008 to 90 million tons in 2014, according to the report. RGGI also reduced dollars used to pay for fossil fuels imported from outside the region by more than $1.27 billion in 2012-2014.
“The implementation of RGGI over six years has not adversely affected power system reliability in New England, New York or PJM. The pricing of carbon in Northeast and Mid-Atlantic electricity markets has been seamless from an operational point of view and successful from the perspective of efficient pricing of emission control in regional markets,” the report said.
The report was funded the Barr Foundation, the Energy Foundation, the Thomas W. Haas Foundation and the Merck Family Fund.
