CAISO Seeks Rapid Response to SoCal Gas Restrictions

By Robert Mullin

CAISO has kicked off an “expedited” stakeholder process to help Southern California’s gas-fired generators mitigate the financial impact of proposed pipeline restrictions stemming from the closure of the Aliso Canyon gas storage facility.

The initiative seeks to identify what measures the ISO can implement to allow those generators to recover — or avoid — penalties for violating new daily balancing requirements that SoCalGas has proposed for the region’s pipeline system.

Under the requirements, any customer whose daily gas burn deviates from nominated pipeline flows by more than 5% would face per-unit penalties as high as 150% of daily gas indices. Generators say those penalty costs would put them out of the money in instances when the grid operator’s dispatch instructions force their units to burn more or less gas than scheduled.

Leak Forced Closure

SoCalGas and San Diego Gas & Electric asked state regulators to approve the requirements ahead of summer to support reliable gas delivery during the region’s peak season for electricity consumption. SoCalGas said it needs more precise scheduling to ensure proper pipeline pressure without the ability to backfill from Aliso Canyon.

The storage facility north of Los Angeles was closed following a leak that spewed massive amounts of methane between October and February.

Aliso Canyon Relief Well Source: SoCalGas (CAISO, gas restrictions) — Aliso Canyon Relief Well *Source: SoCalGas*

The new requirements are expected to take effect May 1, pending approval by the California Public Utilities Commission. That makes a rapid response essential for CAISO’s most exposed market participants, who worry about the costs they will incur in the period between that date and the implementation of any necessary ISO market mechanisms.

“The gap [in time] could be disastrous for us,” said NRG Energy Director of Market Affairs Brian Theaker during a March 23 teleconference to discuss CAISO’s response. “We’re very concerned about our exposure in that gap.”

For its part, CAISO supports the tighter balancing requirements as a way to prevent last-minute gas curtailments to generators called on to respond to unpredictable summer cooling loads.

“Depending on the scope of curtailment, the ISO’s ability to redispatch might be hindered,” said Mark Rothleder, CAISO vice president of market quality and renewable integration.

But CAISO also recognizes the reliability risks that come with the balancing penalties, which could deter some gas-fired units from committing to the short-term market when most needed.

“When it comes to commitment, that’s where we see the disconnect,” said Erik Johnson, principal energy trader with the city of Pasadena. “It’s not the hardest thing to figure out when a unit is going to be out of compliance with SoCalGas.”

Better Gas-Electric Coordination

CAISO is taking a twofold strategy in response, considering both ways to prevent pipeline penalties and revised rules to allow generators to recover the fines. Cathleen Colbert, CAISO senior market design and regulatory policy developer, said any solutions will be “interim” — lasting until Aliso Canyon reopens.

The first approach would seek to prevent pipeline penalties through improved coordination of ISO market instructions with gas balancing requirements. That could entail posting a “two-day-ahead” forecast to inform gas procurements as early as possible or moving the day-ahead market to earlier in the day in advance of the timely gas nomination cycle, when supplies are most liquid.

Market participants are skeptical about the effectiveness of those measures.

“The idea of doing a two-day-ahead forecast is appealing,” said NRG’s Theaker. “But in summer, when loads can get blown pretty high, that could leave you exposed.”

Generator participants also point out that earlier gas procurements — even in the day-ahead cycle — would incur additional costs that might not be recovered under current market rules.

“Does the ISO understand that Intra-day Cycle 3 [day-ahead evening gas procurement] requires storage?” said Pasadena’s Johnson. “We have the ability to procure for day-ahead, but we’ll be paying a premium.”

Johnson also noted that, under the new balancing requirements, it will be impossible to economically cover last-minute gas needs in light of a CAISO Tariff provision that caps gas cost recovery at 125% of daily gas indices.

“Get into the second half of tomorrow [real-time], and it’s going to be impossible to get gas,” Johnson said. “Any dispatch you force on us is going to put us outside the 5%. The 125% [cost cap] doesn’t give enough room.”

David Francis, vice president of West power for EDF, said it is difficult to obtain gas close to real-time operation, a potential strategy to avoid incurring overscheduling penalties. “The amount of volumes that are traded in the cycles after the daily are fairly limited,” he said. “It becomes more challenging to get more [gas] into the [Los Angeles] basin as you get into the cycle.”

Market Changes on the Table

CAISO’s second approach to the new requirements would require revising market rules, both to make dispatch more predictable and to allow generators to recover the cost of the penalties after the fact. Among the multiple options CAISO is putting on the table for stakeholder consideration:

Enforcing day-ahead commitments for all resource types as binding in the real-time market;
Constraining dispatch decisions around day-ahead market schedules;
Limiting real-time market instructions to exceptional dispatches (manually issued orders used when reliability requirements cannot be resolved through market software); and
Allowing resources to request outages to manage their fuel constraints.

Market-based solutions include allowing energy bids to reflect intraday gas prices and including the gas balancing penalties in bid cost estimates, both of which would likely require Tariff revisions. CAISO said it could ask FERC for a waiver of 50-day notice to expedite any such changes.

“Including these costs in the market optimization is great,” said NRG’s Theaker. “Not just including it in the market, but allowing generators to recover it [after the fact].”

Pasadena’s Johnson concurred: “After-the-fact recovery through [bid cost recovery] resettlement sounds more appropriate.”

Whatever the solutions, CAISO has set an ambitious schedule to arrive at an outcome. The ISO plans to issue a straw proposal on the subject April 1, with a draft final proposal scheduled for April 15. Final stakeholder written comments are due April 29. But even that aggressive timeframe is causing some discomfort among market participants.

“At the risk of stating the obvious, SoCalGas has asked for the daily balancing to be implemented May 1, and the stakeholder process runs right up to that,” Theaker said. “What does CAISO plan to do?”

“This timeline could be compressed even further,” said CAISO’s Colbert.

March 28, 2016

DOE Agrees to Join Clean Line’s Plains Eastern Project

By Tom Kleckner

The dream of transporting wind energy east from the Great Plains took a major step toward reality Friday with the U.S. Department of Energy’s approval of Clean Line Energy Partners’ Plains & Eastern project.

The Energy Department issued a record of decision, saying it would “participate in the development” of the 700-mile, HVDC transmission project and designated a preferred route through Oklahoma and Arkansas. The decision caps nearly six years of study and evaluation by the department.

Clean Line says the $2.5 billion, privately funded project will deliver 4,000 MW of wind power — enough to power more than 1 million homes — from the Oklahoma Panhandle through Arkansas to the Mississippi River. The Plains & Eastern line would interconnect with the Tennessee Valley Authority near Memphis after first dropping off 500 MW at a converter station in central Arkansas.

DOE: Need for Transmission

The Energy Department said development of the panhandle’s “consistent and lowest-cost [wind resources] in the nation” has been constrained by a lack of “cost-effective transmission capacity to major load centers.”

“The project would, therefore, unlock the potential for significant new development of wind energy and deliver that energy to a region of the United States that has seen relatively scarce wind development,” the department said. “By increasing the availability of renewable energy from the Panhandle region across a wide geographic area, the project will facilitate market competition that will ultimately benefit consumers and the renewable energy industry as a whole.”

Clean Line President Michael Skelly welcomed DOE’s participation. “The Department of Energy’s decision shows that great things are happening in America today,” he said, calling Plains & Eastern the “largest clean-energy infrastructure project in the nation.”

DOE RFP

Clean Line proposed the project in response to the Energy Department’s 2010 request for proposals for transmission projects under Section 1222 of the Energy Policy Act of 2005, which authorizes the department to participate in “designing, developing, constructing, operating, maintaining or owning” new transmission.

With major regulatory approvals in hand, Clean Line says construction can begin in 2017.

The department’s involvement could help Clean Line in acquiring the right of way for the line, although it said the company will need to demonstrate the commercial viability of the project by executing “significant” firm transmission service agreements before obtaining land through eminent domain. It will also need to complete technical studies required by SPP, MISO and TVA.

Clean Line says the project “will support thousands of jobs in Oklahoma, Arkansas and Tennessee, including hundreds of manufacturing jobs.” Clean Line has a $300 million contract with Pelco Structural, of Oklahoma, to build the project’s tubular steel transmission towers and has selected three Arkansas companies to build related infrastructure such as transmission conductors and glass insulators.

The American Wind Energy Association said the project will “create the opportunity” for $7 billion in new wind farm development. “The project supports economic opportunity, often in rural areas that need it most, and potential energy bill savings for Americans,” said AWEA CEO Tom Kiernan. “Over 99% of all installed utility-scale wind capacity is located in rural areas.”

Opposition to Project

As a condition for its approval, the department required Clean Line use environmental-protection measures during the development, construction and operation of the project “to minimize impacts to landowners and the environment.”

Still, the project has drawn opposition from landowners and political figures. (See DOE Issues Favorable EIS on Plains & Eastern Project and Plains & Eastern Tx Line Foes Cry Foul over DOE Review.)

The Arkansas congressional delegation issued a statement lamenting the Energy Department’s involvement. “Today marks a new page in an era of unprecedented executive overreach, as the Department of Energy seeks to usurp the will of Arkansans and form a partnership with a private company — the same private company previously denied rights to operate in our state by the Arkansas Public Service Commission,” the legislators said. “Despite years of pushback on the local level and continuous communications between our delegation and Secretary [Ernest] Moniz, DOE has decided to forgo the will of the Natural State and take over the historic ability of state-level transmission control through this announcement.”

Although Clean Line won public utility status in Oklahoma and Tennessee, its request was rejected by Arkansas. “They couldn’t find a way to regulate [an] interstate transmission provider,” Clean Line General Counsel Cary Kottler said in an interview. The department’s imprimatur allows the company to overcome that hurdle, he said.

The department will participate in the project through the Southwestern Power Administration, a federal agency that markets hydroelectric power from 24 dams in six states.

It will not make any financial contribution. Instead, Clean Line will pay any Energy Department costs in advance, as spelled out in a participation agreement that also obligates the developer to contribute 2% of its revenues to federal hydropower-infrastructure improvements.

March 28, 2016

Generators to FERC: Expand MOPR for Subsidized FE, AEP Plants

By Suzanne Herel

Eleven generating companies, including Calpine, Dynegy and NRG, have asked FERC to expand PJM’s minimum offer price rule in time for May’s 2019/20 Base Residual Auction, as the Public Utilities Commission of Ohio is poised to rule on power purchase agreements for FirstEnergy and American Electric Power.

ohio ppas — Sammis power plant *Source: Chris Dilts via Creative Commons*

“Complainants respectfully request that the commission expand the MOPR to prevent the artificial suppression of prices in the Reliability Pricing Model (RPM) market by below-cost offers for existing resources whose continued operation is being subsidized by state-approved out-of-market payments,” the companies said (EL16-49).

The companies also voiced support for related complaints asking FERC to void the waivers it granted AEP and FirstEnergy regarding affiliate power sales to ensure commission review of the proposed eight-year agreements, which are supported by PUCO staff. The Ohio commission is expected to rule on the requests in the coming weeks. (See PJM Joins EPSA’s Call for FERC Review of Ohio PPAs.)

Similarly, the complainants have asked that FERC address the waiver issue in time for the May BRA.

Currently, the MOPR applies only to certain new resources.

Recently, the generators argue, “a new threat has emerged in the form of subsidies to existing resources that create incentives for noncompetitive offers and that may prevent the exit of uneconomic resources.”

The proposals from AEP and FE would have “just that effect with respect to over 6 GW of capacity in PJM,” they said.

The companies said they recognized that PJM stakeholders have not had a chance to discuss changes to the MOPR and that Tariff revisions addressing the upcoming BRA might not be an appropriate permanent remedy. Therefore, they are requesting narrowly tailored revisions and a directive to PJM to develop a long-term solution by Nov. 1.

Regardless of whether the PPAs are approved, PJM should initiate a stakeholder process to expand the MOPR, the generators said.

The companies invoked testimony to PUCO by Independent Market Monitor Joe Bowring saying the PPA proposals “highlight the fact that the MOPR needs to be expanded to address all cases where subsidies create an incentive to offer capacity into the PJM capacity market at less than an unsubsidized, competitive offer. This would include offers from all new and existing units that receive subsidies.”

Other parties to the filing are Eastern Generation, Homer City Generation, Carroll County Energy, C.P. Crane, the Essential Power PJM Companies, GDF SUEZ Energy Marketing, Oregon Clean Energy and Panda Power Generation Infrastructure Fund.

March 28, 2016

ISO-NE Forecast for 2024 Boosts Solar 30%

By William Opalka

WESTBOROUGH, Mass. — Load growth remains low in New England while solar power generation is expected to grow even faster than previously predicted, according to a draft study of the region’s power trends.

ISO-NE staff presented the draft of its annual Capacity, Energy, Loads and Transmission forecast at the Planning Advisory Committee meeting on Tuesday.

“The draft forecast [for solar] is 30% higher than last year’s final forecast,” said Jon Black, ISO-NE’s manager of load forecasting. He cited increased state support for the resource along with Congress’ unexpected extension of the investment tax credit last year.

The 2015 forecast predicted 1,620 MW of solar PV at the end of this year, rising through 2024 to 2,449 MW. In the preliminary 2016 draft, the forecast for the end of this year is essentially flat but rises to 3,092 MW at the end of 2024, an increase of 26%.

The new forecast extends a year further, through 2025, when 3,214 MW of solar is predicted, 31% above the final year in last year’s forecast.

Black said the forecast has been refined to include more comprehensive data from distributed asset owners, as well as policy changes. For example, Connecticut’s renewable energy credit program is expected to encourage the development of 300 MW of solar and Vermont’s renewable portfolio standard has a carve-out for 25 MW of PV, Black said.

This year’s forecast, which includes behind-the-meter PV for the first time, also reduces load forecasts and net energy use.

The new study forecasts a 50/50 summer peak of 28,966 MW for 2016, a slight reduction from last year’s forecast for the year. It forecasts a 2024 summer peak of 31,493 MW, a 2% reduction from last year’s study and a 1.1% compound annual growth rate over 2016.

(The 50/50 estimate represents the mean value in a normal probability distribution, meaning there is a 50% chance the load will be higher than the forecast and an equal chance of being lower.)

Net of passive demand response and behind-the-meter solar, the 50/50 peak for 2024 is forecast at 27,060 MW, down almost 3% from last year’s study and a compound annual growth rate of 0.1%.

Energy efficiency, as reported by state utility commissions, is expected to remain stable. Minor increases of its use in some areas were offset by decreases in other parts of the region, according to ISO-NE.

The final CELT report for 2016 will be published on May 1.

March 28, 2016

IPL, MidAmerican: MISO Misallocating Upgrade Costs in GIA

By Michael Brooks

Two Midwest load-serving entities are challenging a generator interconnection agreement filed by MISO that they say would result in one company paying too much for $5.7 million in transmission upgrades because the RTO is misapplying a provision in its Tariff.

Interstate Power and Light (IPL), which is building the 650-MW Marshalltown Generating Station in Iowa, joined MidAmerican Energy last week in protesting the GIA that MISO filed for the combined cycle plant. The companies told FERC that MidAmerican would end up paying the majority of costs for the transmission upgrades in the agreement, while IPL would only pay the installed cost of capital of the shared network upgrades and not its full portion of the monthly facilities charges contained in MidAmerican’s facility service agreements with transmission owner ITC Midwest (EL16-1083).

The upgrades in the Marshalltown agreement were previously included in GIAs filed for two MidAmerican wind farms. ITC had elected to fund the upgrades itself and agreed with MidAmerican that if they became shared upgrades, ITC would determine each interconnection customer’s cost responsibility for them.

Instead, the companies said, MISO believes that Attachment FF of its Tariff requires IPL to make a one-time cost of capital payment to MidAmerican. The companies argued that Attachment FF only applies to when an interconnection customer, not the TO, is funding the upgrades.

“The MISO Tariff language is silent regarding the instant situation, where ITC Midwest as the transmission owner elected to self-fund the network upgrades,” IPL and MidAmerican said. “MISO has refused to recognize the difference between a situation where the first interconnection customer funded the shared network upgrades and the situation here where the transmission owner self-funded” them.

“The distinction is important because … MISO’s requirement that the second interconnection customer simply make a one-time payment for the cost of the shared network upgrades to the first interconnection customer results in unequal and inequitable treatment of the two interconnection customers for the same upgrades,” the companies said.

The companies said IPL should pay 32% of the costs for a $2 million transformer upgrade and 51.4% for a $3.72 million line rebuild. They asked FERC to order MISO to revise the Marshalltown GIA to reflect these cost allocations.

“Parties should be paying their fair share,” Cortlandt C. Choate Jr., senior attorney for IPL parent company Alliant Energy, said in an interview.

They also asked that MISO be required to revise its Tariff to clarify interconnection customers’ cost responsibilities for upgrades funded by the TO.

March 28, 2016

SPP Briefs: New Trustee Chairman, Wind Record

The SPP Regional Entity trustees elected Dave Christiano as their new chairman during a special board meeting last week, replacing the resigned John Meyer.

Meyer announced his resignation the week before, during the SPP RE’s spring workshop in Little Rock, Ark. Because there are only three RE trustees, Christiano and Gerry Burrows moved quickly to “expedite” Meyer’s replacement, they said in an email to members.

During the March 22 call, Burrows nominated Christiano for chairman, then joined him in a 2-0 vote.

Christiano told members the RE doesn’t expect to fill Meyer’s vacancy until July at the earliest. The Russell Reynolds Associates executive search firm has been contracted to help.

“Gerry and I decided we couldn’t go four months without a chairman,” Christiano said.

Alluding to Meyer’s nine years as chair of the RE trustees, Christiano told members they will see little change.

“I will pledge, and I’m sure Gerry will pledge too, that we’re not going to change any directions,” said Christiano, who has been a trustee alongside Meyer since the RE’s inception in 2007.

The RE trustees operate separately from SPP’s Board of Directors, providing oversight of RE decisions on regional standards, compliance enforcement and penalties. Only the trustees and certain RE staff members have the authority to make compliance and enforcement decisions.

An electrical engineering graduate from Clarkson College in New York, Christiano began his industry career with Consolidated Edison in New York City in 1971 and took part in an analysis of the 1977 blackout. He spent 28 years with City Utilities of Springfield in Missouri before becoming an RE trustee. Christiano has served on numerous SPP and NERC boards and committees.

Meyer resigned from the RE because of a conflict with the bylaws of Western Interconnection reliability coordinator Peak Reliability, where he is vice chair. The Western Area Power Administration, which joined SPP last year, is partly in the Western Interconnection, requiring SPP to register with the Western Electricity Coordinating Council as a planning authority and transmission-service provider.

To ensure independence, Peak’s bylaws prohibit its board members from serving on other boards in the WECC.

Christiano said Meyer chose to stay with Peak, where he only has two years of service. “He felt he had a lot more to offer there,” Christiano told RTO Insider.

SPP Sets New Wind Peak Record

The RTO set a new wind peak at 6 a.m. March 21, relying on about 87% of the wind capacity in its footprint to generate 10,783 MW. The previous record of 10,280 MW was set Feb. 17.

The RTO has 12,397 MW of installed and available wind capacity in its footprint, with another 33,819 MW of capacity in various stages of development.

Brown Honored with International Award

SPP CEO Nick Brown will be honored by the University of Arkansas at Little Rock’s (UALR) College of Business for his recent Business Achievement Award from the Beta Gamma Sigma.

The society annually recognizes achievement in business and ethical leadership. The UALR College of Business nominated Brown for the award and will hold an invitation-only reception in his honor in Little Rock. Brown said he was “humbled” by the award and thanked SPPs employees, “who are the foundation of our corporate success.”

Beta Gamma Sigma is an international honor society serving business programs accredited by the Association to Advance Collegiate Schools of Business.

– Tom Kleckner

March 28, 2016

Texas Commission Approves Oncor REIT Structure

By Tom Kleckner

The Public Utility Commission of Texas on Thursday approved Hunt Consolidated’s proposed acquisition of Oncor, the state’s largest transmission and distribution utility and the most valuable remaining piece of troubled Energy Future Holdings (Docket # 45188).

The PUC’s March 24 order would split Oncor into two companies, one of which would operate as a real estate investment trust (REIT) under the state Public Utility Regulatory Act. The commission gave the parties a Nov. 30 deadline to complete the transaction.

As a REIT, Oncor AssetCo would own the transmission and distribution facilities, while Oncor Electric Delivery Co. (OEDC) would rent the facilities to provide electric delivery services. OEDC would house most of Oncor’s management and employees and the remainder of the assets.

Oncor AssetCo would avoid paying federal income taxes as part of the transaction if it derives at least 75% of the its gross income from property rents. Hunt has taken a similar tack with its Sharyland Utilities, which provides services to 53,000 customers, primarily in West Texas and the Rio Grande Valley.

The commission agreed with the proposal, saying “payments received from OEDC, as the lessee and operator of the assets, will constitute rents from real property under the meaning of the Internal Revenue Code.”

The plan has drawn criticism from a disparate group that includes former Texas Gov. Rick Perry, a coalition of cities served by Oncor, the AARP and PUC staff. Much of the criticism centers on the REIT conversion and whether it would provide a windfall for the company at the expense of ratepayers.

Two Texas state senators, Kelly Hancock and Royce West, called into the meeting to add their objections, saying the REIT should not be able to collect taxes in its rate structure if it doesn’t intend to pay them. The tax benefit is worth about $250 million, and the Hunt group had been looking for a guarantee it could take full advantage of the benefit.

“I am not against the acquisition,” West said from China through heavy static. “I understand a REIT has to distribute [funds to shareholders]. The question in my mind is should [the REIT] be allowed to use dollars earmarked for taxes … to shareholders.”

The commissioners discussed whether to add a separate accounting treatment for the taxes, with one proposal to immediately credit ratepayers $100 million. However, Chair Donna Nelson stepped in to say adding too many restrictions to the deal might make it unmanageable.

“It sounds like you’re punishing them now,” she said. “If we’re going to deny it, why don’t we just deny it? If you’re going to keep attaching these things to it, it’s going to die anyway. All we’re doing is wasting time.”

In the end, the PUC’s order said the tax-savings issue will be “addressed by commission staff and intervenors in the next rate proceeding of Oncor AssetCo and OEDC.”

While siding with Anderson and Commissioner Brandy Marquez on the order, Nelson dissented from the majority’s decision “regarding the timing and treatment of the income tax expense.” Nelson’s position throughout the Hunt-Oncor process has been to oppose customer refunds.

Geoffrey Gay, legal counsel for about 150 cities served by Oncor, said he expects his clients to file rate cases by the end of April, bringing about the rate case a year earlier than the current schedule.

Oncor expects the proposed transaction, “if funded by investors,” to close on or before year-end.

“While there are a number of hurdles left to clear, we look forward to working with the parties involved to reach a conclusion in this change-in-control proceeding,” said Geoff Bailey, Oncor’s director of communications, in a statement.

Hunt did not respond to a request for comment on the order. However, a Hunt representative issued a statement after the PUC meeting saying it would “continue to work with all parties in the EFH bankruptcy proceeding over the coming months to reach a successful closure of the transaction consistent with the order approved today.” The company is a Dallas-based oil and gas, real estate and power company, owned by the wealthy Hunt family.

Oncor delivers power to more than 3 million homes and businesses over about 119,000 miles of transmission and distribution lines in North and West Texas. Determining its fate is central to resolving EFH’s Chapter 11 bankruptcy reorganization, which was filed in April 2014.

EFH was the result of a $48 billion leveraged buyout of TXU Corp. in 2007, when the utility faced strong public opposition to its plan to build 11 coal plants in Texas. Private investors led by KKR and TPG Capital bet on rising energy prices but found themselves instead saddled with $42 billion in debt following the 2008 global financial crisis and plunging gas prices due to the fracking boom.

A U.S. bankruptcy judge in December approved EFH’s plan to split into two separate companies — Oncor and the unregulated power generation and retail arms, Luminant and TXU Energy, respectively — wiping out the LBO sponsors’ equity. The Luminant-TXU Energy businesses would go to senior lenders owed about $24 billion.

The decision assumes creditors would not incur a multibillion-dollar tax bill. The IRS is reviewing whether the transfer of assets to creditors represents a taxable sale.

March 28, 2016

Federal Briefs

The Nuclear Regulatory Commission sent a letter to the Tennessee Valley Authority outlining allegations of a “chilling effect” at its Watts Bar Nuclear Plant, where control room operators have expressed concerns about raising safety issues. NRC earlier this month said it was looking into the issue, but sending the letter formalizes its intent to investigate.

“While we believe TVA management understands these issues, the chilling effect letter documents the NRC concerns and our expectations that TVA fully address them and ensure that all plant employees feel free to raise any safety problems,” NRC Region II Administrator Cathy Haney said in a statement. The letter gives TVA 30 days to respond.

“I think it’s important to note that neither NRC nor TVA have found evidence of any actual retaliation, but both have found that just the perception that retaliation has happened can have the same effect,” TVA spokesman Jim Hopson said. “This is just as serious to us as any type of actual retaliation.”

More: Knoxville News Sentinel

Protesters Arrested at FERC ‘Pancakes not Pipelines’ Event

A documentary filmmaker and six others were arrested after they blocked the garage entrance of FERC headquarters to protest a pipeline project that would deliver Marcellus Shale natural gas to Northeastern markets.

Josh Fox, the maker of the anti-drilling film “Gasland,” was part of the protest, in which FERC commissioners were invited to sample pancakes topped with maple syrup produced from trees that were cleared for the Constitution Pipeline in Pennsylvania.

“It is clear to me that FERC has to be the most destructive agency in the United States right now,” said protester and syrup producer Megan Holleran. “They are faceless, nameless, unelected and ignore citizen input.”

More: Beyond Extreme Energy

Circuit Court Gives Sierra Club Chance to Obtain Entergy Records

A federal appeals court will allow the Sierra Club to make its case in federal court to obtain records that Entergy supplied to EPA about two Arkansas coal plants and a third plant in Louisiana.

The 5th U.S. Circuit Court of Appeals ruled in favor of the Sierra Club’s efforts to obtain the documents, which concern the 1,700-MW Independence and White Bluff coal plants in Arkansas, which operate without major emission-reducing scrubbers. The third plant is a 30-year-old coal plant near Lake Charles, La.

Glen Hooks, director of the Sierra Club of Arkansas, said his organization uses such emissions documents to monitor whether Clean Air Act violations are occurring. “I don’t think we’re going to have a lot of trouble getting the documents now,” he said.

More: Arkansas Democrat-Gazette

Tennessee Gas Seeks Pipeline Challenge Dismissal

Tennessee Gas Pipeline has asked FERC to dismiss an attempt by an advocacy group to block construction of a 4-mile pipeline spur that cuts through a state-protected forest in western Massachusetts.

The filing opposes a motion by Sandisfield Taxpayers Opposing the Pipeline to prevent immediate tree-cutting. The regulators approved the pipeline project on March 11. The loop is part of a 13-mile, $87 million Connecticut Expansion Project that would provide additional natural gas to three utilities.

The state of Massachusetts is also trying to delay the project, arguing that the state constitution protects the woodlands unless lawmakers grant an exemption, which they have declined to do.

More: The Berkshire Eagle

Energy Companies Bid $156M For Gulf Drilling Leases

Thirty exploration companies bid $156 million to lease 128 oil and natural gas tracts in the central section of the Gulf of Mexico. The area covers nearly 700,000 acres 3 to 230 nautical miles off the coasts of Louisiana, Mississippi and Alabama.

While bidding was heavy for the central section, no bids were received for the Eastern Planning Area, according to the Bureau of Ocean Energy Management.

More: World Oil

Feds Approve Research Wind Facility Offshore Virginia

The Bureau of Ocean Energy Management approved construction of two 6-MW wind turbines to be installed 27 miles off the coast of Virginia as part of a research project to test how the turbines hold up under harsh conditions.

“Data collected under this research lease will help us better understand the wind potential, weather and other conditions off of Virginia’s coast,” BOEM Director Abigail Ross Hopper said.

Dominion Resources issued a request for bids for the research turbines last year. The bids came back between $375 million and $400 million, about twice as high as expected, so Dominion delayed the project’s start date from 2017 to 2018. Dominion has a lease on 113,000 acres for offshore wind development.

More: The Associated Press

EPA Believes it has Mapped Extent of Nuclear Waste

Radiation from nuclear waste that was buried in the 1970s has migrated farther than once thought, according to EPA. The waste in the West Lake Landfill near St. Louis comes from uranium processing of material for the Manhattan Project in the 1940s.

EPA said mapping shows some of the waste products seem to be about 600 feet further than thought, but the agency downplayed the risk. “While the footprint of the [radiologically impacted material] has changed … there’s still no significant health risk posed by the radioactive waste at the West Lake Landfill,” EPA’s Brad Vann said.

EPA is mapping the waste as part of an investigation to determine how to build a barrier to contain the material.

More: St. Louis Post-Dispatch

March 28, 2016

MISO, Stakeholders: Reforms Needed, but ‘Seamless’ Seam an Illusion

By Amanda Durish Cook

MISO stakeholders say they do not expect perfect procedures at the seams with neighboring balancing areas, but they do want the

Robert-Gee-(copyright-RTO-Insider)-web — Gee (with Bloodworth in the background) *© RTO Insider*

RTO to implement reforms to address price deviations, remove obstacles to interregional transmission projects and improve cost allocation among those projects.

Seams issues were the “hot topic” at last week’s Advisory Committee discussion moderated by consultant Robert Gee.

Remove ‘Triple Hurdle’

Several times during last week’s discussion, stakeholders called for removal of the “triple hurdle” faced by interregional projects, which must meet a specific interregional cost-benefit standard as well as comply with the internal standards of the two RTOs involved.

Stakeholders also repeated a request that MISO and SPP lower the minimum 345-kV requirement for interregional projects. In comments filed ahead of the meeting, the Power Marketer sector noted that of the 300 interconnections between the two RTOs, only 12 meet that standard.

The Competitive Transmission Developer sector recommended that MISO create a new interregional project category with a separate, singular benefit calculation. “MISO should conduct outreach to neighboring regions to advocate for adoption of the proposed interregional criteria in both [joint operating agreements] and in MISO’s regional Tariff as a separate project category,” the sector wrote.

It noted that RTO boundaries are “artificially imposed and do not reflect natural barriers to the flow of power throughout the region.”

The Environmental Sector urged MISO and PJM to expedite their initiative on targeted market efficiency projects, formerly called “quick hit” projects. The sector also urged MISO to resolve disagreements with other RTOs over the future scenarios that should be studied.

Letting Go

The Independent Power Producers sector predicted a dire future for MISO’s market if the RTO failed to improve its market-to-market locational energy pricing and settlements.

The IPPs said MISO’s “uncompetitive” capacity construct and abundant wind resources would incentivize energy exports. The sector criticized MISO and its Independent Market Monitor for endorsing concepts rejected by other RTOs, such as the proposed two-season capacity construct. It also criticized MISO’s efforts to discourage generators from exporting power under pseudo-tie arrangements with PJM. (See MISO Delays Seasonal, Locational Capacity Constructs.)

“MISO staff and the MISO IMM seem to have a hard time letting go of some of their proposals that have been evaluated and subsequently rejected by their seams partners and their seams partners’ constituents and stakeholders,” the IPPs said.

The Public Consumer sector declined to recommend specific changes but observed that “transmission from region to region … is a major way that [operational] efficiency across seams can be realized.”

The Transmission Dependent Utilities sector said RTOs should improve data exchange to better coordinate outages and update firm flow entitlement calculations. “As additional flowgates are determined to be significantly impacted by the dispatch in neighboring regions and interregional transactions, the modeling detail of neighboring systems must expand,” the sector wrote.

The TDUs also said RTOs should “seek middle ground rather than holding out for the ideal solution” and consider mediating seams issues when necessary.

Chris Plante, of TDU member Wisconsin Public Service, said the best way to improve the efficiency of the seam is to operate seams dispatch from two RTOs as if they were “under a single commitment and dispatch algorithm.”

The Transmission Owners sector wrote in favor of coordinating congestion hedges with other RTOs, improving real-time coordination with SPP and altering generator pseudo-tie requirements to synch with PJM’s market.

MISO Board: Cooperation is Key

MISO Advisory Committee (Copyright RTO-Insider) — MSIO Advisory Committee *© RTO Insider*

MISO officials and stakeholders generally agreed that better interregional cooperation is essential to addressing seams issues but opinions varied about what to expect from that cooperation — and what outcomes are actually desirable.

NRG Energy’s Tia Elliot pointed out that MISO struggles with project cost allocation even among its own stakeholders. “I think it could be difficult when it comes to interregional planning,” she said.

Calpine Vice President of Market Design Brett Kruse advocated “reasonable expectations with the guy on the other side of the seam,” noting that RTOs will not have identical cost allocations and flowgates. “The other RTOs have already considered [other market operations], determined it’s not for them and moved on,” he said. “It’s best to leave that stuff alone and work on the common areas.”

FERC Action Needed?

MISO Chair Judy Walsh asked, “We know the problem … but are [RTOs] going to be able to work this out, or is it going to take FERC stepping in and ordering this for the common good? Are we kidding ourselves that we will be able to work this out?”

“Your question, I think, is right on target,” Plante replied. “Now we’re dealing with topics and issues that are heavily ingrained in each RTO’s process.” He said mutual respect for different market implementations will be instrumental in “bridging the gap.”

Director Phyllis Currie said RTOs must seek compromise. “What I’m hearing here is not that different from what I’ve heard in California … and I’ve seen it over the years across different industries,” she said. “If everybody keeps coming at the problem the same way they’ve come at the problem time and time again, you don’t get anywhere.”

Megan Wisersky of Madison Gas and Electric said RTOs should not be required to have uniform rules. “I say, vive la différence!”

“My takeaway is we may not ever get to the idea of a seamless seam, but that shouldn’t dissuade us,” said board member Thomas Rainwater.

Plante agreed. “A seamless seam is an oxymoron,” he said.

March 28, 2016

Retailers Ask for Rehearing of NY Guaranteed Savings Order

By William Opalka

Electricity retailers in New York on Friday asked for rehearing of an order that would overhaul retail customer choice in the state.

The Impacted ESCO Coalition and the National Energy Marketers Association separately asked for a rehearing of the New York Public Service Commission’s Feb. 23 order that mandated customer savings under most contracts (98-M-1343).

The order mandates that customers be guaranteed an electric rate lower than what their host utility offers, with the exception of “green” offerings that must include a minimum of 30% renewable energy. The commission said the order was intended to combat deceptive practices and boost consumer confidence. (See Zibelman: Rules Meant to Enable Markets.)

The retailers say the reforms were ill-considered and hastily enacted. “Contrary to well established commission policy and practice in support of the development of competitive retail markets, and without notice or meaningful opportunity to be heard, the February order adopted requirements for ESCO [energy service company] service to mass market customers, which would effectively shut down the market for the majority of ESCOs and their customers,” the NEMA wrote.

The PSC had required ESCOs begin compliance within 10 days, or March 3. However, a state court stayed the order, scheduling a show-cause hearing for April 14. (See Court Delays New York ‘Guaranteed Savings’ Rules.)

Among the complaints by the ESCOs is that the rules were enacted without adequate notice under the State Administrative Procedures Act and that the price guarantee is improper rate-setting by the PSC.

The NEMA also said the order amounts to an illegal taking of its members’ accounts. “All of the ESCOs that cannot comply with the order will be forced to give their hard-won customers, which the ESCOs incurred significant costs to acquire, to the competing monopoly utility. The utilities will unfairly acquire these ESCO customers for free,” it wrote.

“The improperly noticed rules represent a sweeping set of changes that threaten to destroy hundreds of businesses and affect millions of New York residents,” wrote attorneys for the IEC, which describes itself as representing “small to medium” ESCOs, many of whom who operate primarily in New York.