State Briefs

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.

More: NewsWorks

DISTRICT OF COLUMBIA

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.

More: Executive Office of the Mayor

ILLINOIS

State Sets Public Forums for Power Line Project

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.

More: Illinois Commerce Commission

INDIANA

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.

More: Solar Power World

IOWA

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.

More: Des Moines Register; AWEA

KENTUCKY

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.

More: WFPL

MAINE

Study: Supply Boost to Cost More than it Saves

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.

More: Portland Press Herald

Power Marketer Draws Complaints

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.

More: Portland Press Herald

MARYLAND

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.

More: EnergyEfficiencyMarkets.com

MASSACHUSETTS

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.

More: Boston Globe

MICHIGAN

Legislators Eye Energy Market Regulation

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.

More: Detroit Free Press

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.

More: MLive

MONTANA

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.

More: The News Tribune

NEW HAMPSHIRE

Kinder Morgan Starts Promotional Website

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.

More: New Hampshire Union Leader

Another Electricity Supplier Pulls Out

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.”

More: New Hampshire Union Leader

NEW YORK

Transmission Policy Requirement Adopted

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.

More: NYPSC

NORTH CAROLINA

Amazon to Build Major Wind Farm

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.

More: News and Observer

OHIO

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.

More: Columbus Business First; National Research Center for Coal and Energy

WISCONSIN

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.”

More: Wisconsin State Journal

July 21, 2015June 15, 2023

FERC Rejects Claims that MISO Snubs Generation Alternatives

By Chris O’Malley

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.

July 21, 2015June 15, 2023

SPP Markets and Operations Committee Briefs

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.

— Tom Kleckner

July 21, 2015

SPP Z2 Project Team Still Grappling with Problem’s Size

By Tom Kleckner

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.”

July 21, 2015June 15, 2023

SPP Frustrated over Transmission Project Overruns

By Rich Heidorn Jr.

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 — 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).

July 21, 2015

FERC Rejects Bid to Broaden Scope of Gas-Electric Info Sharing

By Suzanne Herel

Federal regulators last week rejected a request by a natural gas distributor to relax restrictions on its sharing of non-public information received from electric utilities.

The Federal Energy Regulatory Commission dismissed National Fuel Gas Distribution’s request in two rulings. In one, FERC dismissed the company’s request for clarification on communication allowed under Order 787, saying it was beyond the purview of its rulemaking (RM13-17-002). The other rejected NFG’s rehearing request on rules adopted by PJM under the order (ER14-1469-002).

With Order 787, the commission in 2013 opened up the sharing of non-public operational information between interstate natural gas pipelines and public utilities, saying that increased coordination would benefit reliability. (See Talk among Yourselves: FERC Urges Gas-Electric Coordination.)

Impact on Local Distribution Companies

It did not codify, however, how utilities could share such information with local distribution companies, leaving the issue to RTOs and ISOs to address individually through tariff changes. Subsequently, FERC received filings from PJM and NYISO amending their rules. (See FERC OKs Gas-Electric Talk.)

NFG is an LDC serving western New York and northwestern Pennsylvania.

FERC ultimately approved a PJM Operating Agreement change requiring LDCs and intrastate pipeline operators to promise not to disclose non-public, operational information received from PJM to third parties “or in an unduly discriminatory or preferential manner or to the detriment of any natural gas or electric market.” It also barred sharing of the information through a “conduit.”

No intervenors opposed PJM’s proposal, which was approved by FERC in July. But a month later, NFG came forward to say that a blanket restriction forbidding LDCs from disclosing such information to any third party “may inhibit appropriate sharing of operational data and discourage LDCs and intrastate pipelines from maximizing use of the data to improve reliability.”

It pointed out that “third parties” would include pipelines already qualified to receive information under Order 787 and others with whom LDCs need to coordinate to increase reliability.

For example, it said, if an expected increase in a generator’s use of natural gas in one part of the pipeline could affect a load pocket of the LDC, the company would want to be able to warn large customers in that area of an imminent capacity constraint.

NFG also took issue with the notion of requiring LDCs to guarantee their use of data would not be “to the detriment of any natural gas or electric market,” contending that “changing capacity use inevitably affects some retail customers negatively just as changing upstream supplies may affect market participants negatively.”

‘Very Broad’

In denying NFG’s request, FERC said it intentionally made the scope of information-sharing under Order 787 “very broad.” Quoting from the order, FERC added, “The commission is intentionally permitting the communication of a broad range of non-public, operational information to provide flexibility to individual transmission operators, who have the most insight and knowledge of their systems, to share that information [that] they deem necessary to promote reliable service on their system.”

It said that the potential for competitive harm under that broad scope warranted limiting it with a blanket authorization.

When Order 787 was announced, several commenters called the no-conduit rule too restrictive and offered modifications, including exclusions from the third-party restriction. FERC denied those requests.

“PJM states that it intended its restrictions on LDCs and intrastate pipelines to be an extension of the commission’s no-conduit rule to non-FERC jurisdictional facilities, applied in a manner that mimics, as closely as possible, those restrictions,” it said.

‘Untimely’

As for NFG’s request for a rehearing, FERC determined it “untimely and thus statutorily barred.”

It also noted that nothing in PJM’s Tariff precluded NFG or any other entity from sharing non-specific information needed to ensure the reliability of system operations.

“As long as NFG Distribution does not reveal, directly or indirectly, the non-public, operational information shared by PJM (e.g., information concerning a particular electric generator), NFG Distribution can request or direct its customers and operational counterparties to perform specific actions based on such information,” it said.

July 21, 2015June 15, 2023

Talen Entering NYISO in $1.2B Deal

By Rich Heidorn Jr.

Talen Energy announced its first post-spinoff acquisition Monday, agreeing to spend $1.175 billion to purchase 2,500 MW of combined-cycle generation that expands the company’s presence in ISO-NE and marks its entry into NYISO.

The company, which completed its spinoff from PPL and Riverstone Holdings on June 1, announced it will acquire three generators from MACH Gen: the 1,080-MW New Athens plant in Athens, N.Y.; the 360-MW Millennium plant in Charlton, Mass.; and the 1,092-MW New Harquahala plant near Tonopah, Ariz.

The key to the deal for Talen is the two plants in NYISO and ISO-NE, regions in which the company had previously said it was setting its sights. The acquisition will increase its geographic diversity, reducing PJM’s share of its fleet from 83% to 71% while doubling ISO-NE’s share to 2%.

It also reduces its dependence on coal and nuclear power, with coal’s share of the fleet dropping from 40% to 34% while natural gas increases from 22% to 33%.

All of those numbers will change as a result of the company’s need to divest 1,300 MW to meet market power concerns. Pre-divestiture, the company’s fleet would total 17,600 MW. (See PPL, Riverstone Accept FERC Mitigation Plan on Talen Spinoff.)

Immediately Accretive

Talen said the acquisition brings substantial tax benefits and will be immediately accretive to earnings despite poor “market dynamics” that have limited the Arizona plant to less than a 20% capacity factor, resulting in losses. All three plants are powered by Siemens 501G engines installed between 2001 and 2004.

Talen also said it expects the economics of the Athens plant to improve with the completion of pipelines that will give the plant access to low-cost Marcellus shale gas and electric transmission improvements expected to reduce congestion in NYISO’s Zones F and G.

‘Powder’ for Future Deals

Importantly, said CEO Paul Farr, the deal will retain flexibility to make additional acquisitions. “We still have dry powder given the mitigation process underway,” Farr said in a conference call with stock analysts.

The purchase will be financed with a combination of debt and cash but the precise mix would depend on interest rates and the status of its divestiture efforts, Talen said. The company said earlier this month that it had a $1 billion “war chest” for future acquisitions.

The company is believed to be considering the acquisition of American Electric Power’s merchant fleet in Ohio and Indiana, which AEP announced in January it was putting on the block. (See AEP Considering Sale of 8,000 MW in Ohio, Indiana.)

UBS Investment Research says there is a 50% probability Talen will purchase AEP’s assets. It said Talen could swallow AEP’s assets even after the MACH Gen deal because an AEP deal is not likely to occur until late 2015 or early 2016 because of pending Ohio regulatory proceedings.

Arizona Plant a Throw-In

It appears that taking on the money-losing Arizona plant was a condition for acquiring the assets Talen did want. Talen, which has no other assets in the region, said it may move the plant elsewhere or sell it for parts.

MACH Gen, which was owned by affiliates of Credit Suisse Group and Bank of America among others, filed for Chapter 11 bankruptcy protection in March 2014, saying it had assets of $750 million and liabilities of $1.6 billion. The company said it had a net loss of $120 million on $350 million in operating revenue in 2013.

The company said the Federal Energy Regulatory Commission’s rejection of its plan to sell the Harquahala plant had undermined its efforts to cut its debt. FERC said the sale — to investors that also owned two of the four natural gas generating units in Gila Bend, Ariz. — would have harmed competition within the Arizona Public Service balancing authority area (EC13-11).

The company said most of its creditors had agreed to a prepackaged reorganization that would give its second-lien debt holders 93.5% of the restructured company and reduce about $1 billion of debt. FERC approved the restructuring in April 2014 (EC14-46).

July 21, 2015June 15, 2023

FERC Rejects Rehearing on SPP Congestion Rights

By Tom Kleckner

The Federal Energy Regulatory Commission last week rejected multiple requests for rehearing of its October 2014 order finding fault with SPP’s interpretation of long-term congestion rights (LTCRs).

SPP had joined with Kansas City Power & Light to request a rehearing in November. Also requesting rehearing were five transmission-dependent utilities.

FERC did conditionally accept SPP’s January compliance filing, saying the RTO had partially complied with the October order (ER14-2553).

In the October order, FERC ruled that SPP’s response to Order 681 did not meet the order’s requirement that long-term transmission rights made feasible by transmission upgrades or expansions must be available to any party that pays for the improvements under prevailing cost-allocation methods.

The commission said SPP’s proposal did not grant LTCRs to “‘any party’ that funds upgrades,” but instead awarded transmission-service revenue credits, “which are only available to transmission service customers and are not based on the value of congestion revenue.”

FERC also found SPP’s filing did not fully comply with Order 681’s requirement that load-serving entities have priority over non-LSEs in the allocation of long-term firm transmission rights supported by existing capacity.

No Opportunity for Profit

In denying SPP’s request for rehearing, the commission said it disagreed with the RTO’s contention that Attachment Z2 credits are “reasonable equivalents to LTCRs for financial entities.”

“SPP’s Attachment Z2 crediting process awards transmission service revenue credits up to the cost of the facility, but the value of a LTCR could exceed the cost of the facility,” FERC said. “Z2 credits up to the cost of the facility may be a reasonable incentive for some market participants to sponsor upgrades … However, the Attachment Z2 credits would not serve as an incentive for financial entities that fund transmission projects to sponsor any upgrades because the most they could receive is their initial investment with no opportunity to make a profit.”

The commission also denied SPP and KCP&L’s claims that the October 2014 order questioned the justness and reasonableness of Attachment Z2. “SPP’s decision to use tariff language that already existed in a prior context” to satisfy Order 681’s requirements, FERC said, did not absolve the commission of its responsibility to determine whether the proposed language is just and reasonable.

FERC also denied a rehearing request by the City of Independence, Kansas Power Pool, Missouri Joint Municipal Electric Utility Commission, Missouri River Energy Services and West Texas Municipal Power Agency (filing as TDU Intervenors).

The group expressed concern that adoption of a nomination process will not ensure LSEs obtain sufficient LTCRs. The commission said that SPP’s use of a nomination process before the simultaneous feasibility test “addresses TDU Intervenors’ concerns and render their proposed revisions unnecessary.”

The commission added that the intervenors failed to demonstrate how SPP’s process would result in their being unable to nominate LTCRs at a level equal to their “reasonable needs.”

Compliance Filing

Boston Energy Trading and Marketing protested SPP’s proposal to provide incremental LTCRs, in lieu of revenue credits, to entities that fund upgrades. SPP proposed network upgrades costs of $5 million or more be compensated with candidate incremental LTCRs, if elected, but Boston Energy said that inclusion is contrary to Order 681 and more restrictive than other ISOs and RTOs.

FERC conditionally accepted SPP’s proposal for awarding incremental LTCRs but required it to remove the $5 million threshold.

FERC also directed SPP to separate the provision of incremental LTCRs from the proposed nomination process and to establish a new process providing incremental LTCRs when the sponsored upgrade goes into service. The commission also asked SPP to inform FERC whether the LTCRs’ initial allocation will be implemented in the 2016 ARR/TCR year, and to explain how its process will treat the provision of LTCRs and incremental LTCRs for network upgrades funded through a combination of rolled-in transmission rates and directly assigned charges.

The American Wind Energy Association and the Wind Coalition had requested clarification on how the LTCR process will affect future transmission in the RTO’s planning and interconnection processes. They also requested clarification on how incremental LTCRs resulting from transmission capacity created by upgrade sponsors would impact transmission service customers.

FERC responded by saying SPP’s compliance filing showed its transmission-planning process “ensures the continued long-term feasibility of awarded LTCRs and incremental LTCRs, and therefore has complied with the transmission planning and expansion requirements of Order 681.”

July 21, 2015

‘Shared Renewables’ Approved in New York

By William Opalka

The New York Public Service Commission on Thursday approved rules designed to allow low- and moderate-income apartment dwellers to own renewable energy projects (15-E-0082).

New York PSC Bars Utility Ownership of Distributed Energy Resources.)

“Shared Renewables places customers who do not own homes on an equal footing with traditional single-home customers and creates opportunities for low- and moderate-income families who don’t have access to electricity generated from renewable resources,” PSC Chair Audrey Zibelman said.

Customers can band together to form larger groups that share in the benefits of renewable energy projects, such as solar energy installations and wind farms.

The plan contemplates “community solar” projects, where solar panels are erected on a shared site, such as a vacant lot, with the economic benefits shared among its participants.

Under the first phase of the program, from Oct. 19 through April 30, 2016, projects will be limited to those that site distributed generation in areas where it can provide the greatest benefits to the power grid or support economically distressed communities (at least 20% participation by low- and moderate-income customers).

A second phase beginning May 1, 2016, will make shared renewable projects available throughout entire utility service territories.

The program was proposed in Gov. Andrew Cuomo’s 2015 State of Opportunity Agenda. “This program is about protecting the environment and ensuring that all New Yorkers, regardless of their zip code or income, have the opportunity to access clean and affordable power,” he said.

July 21, 2015June 15, 2023

FERC OKs MISO Tariff Change on Remote Network Loads

By Chris O’Malley

MISO has won approval to revise its Tariff to provide common treatment for network customers seeking to serve network load not physically interconnected with the RTO.

The tariff mechanism sought by MISO and approved by the Federal Energy Regulatory Commission last week is expected to eliminate the need for filing specific non-confirming network integration transmission service agreements on a case-by-case basis (ER15-1745).

The change stems from two non-conforming NITS requests: a 2013 request to allow South Mississippi Electric Power Association to take network service to serve a network load pseudo-tied to SMEPA but not physically interconnected with a transmission owner or independent transmission company within MISO (ER13-2008), and a 2014 MISO request to allow Arkansas Electric Cooperative Corp. a similar right to serve pseudo-tied load (ER14-684).

A pseudo-tie is a mechanism for operationally transferring a resource from the balancing authority in which it is physically located to another BA, which becomes responsible for it for system reliability.

Some MISO transmission owners filed comments in those cases, raising concerns that the two utilities could be receiving special treatment. The transmission owners asked FERC to order MISO come up with a global solution to the issue through changes to its Tariff.

In response, FERC said it expected MISO to offer non-conforming service on a non-discriminatory basis to other transmission customers in similar situations.

After discussions with transmission operators, MISO proposed several changes to Section 31.3 of its Tariff, which required that network load be physically interconnected with a MISO transmission owner or independent transmission company.

The revised Tariff requires that the non-interconnected network load “be part of a pricing zone in MISO, so that the network customer is subject to a rate for network service.”

One way to meet such eligibility requirements is if a non-interconnected network load is pseudo-tied into the MISO balancing authority. MISO stated that provision is necessary because otherwise there wouldn’t be a mechanism to charge the network customer for network service, “meaning the network customer could receive this service for free.”

MISO noted that in its NITS agreements with SMEPA and AECC, it required them to pay a rate for network service based on the MISO zone in which the physically interconnected portion of their load is located.

The revised Tariff also requires network customers to have coordinating arrangements in place with the host transmission owner or independent transco for reporting network load.

The revisions are effective July 19.