InsIde FeRC - Platts as 26 states are seeking to block EPA’s Clean Power Plan to reduce carbon dioxide emissions, Environmental Protection Agency Administrator Gina McCarthy sought

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electric Power

Natural, manmade magnetic pulses can devastate grid with coast-to-coast impacts: panel 7

Clean Power Plan compliance easier if states cooperate, set up emissions markets: panel 8

supply & demand

PJM resources significantly exceed winter load; forecast for mild weather hits peak load projection 18

Efficiency restrains New England demand growth; renewables gaining share of generation mix 19

As US production continues to displace exports, Canada looks to broaden gas customer base 19

November 16, 2015

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www.platts.com NATURAL GAS ELECTRIC POWER

Lawmakers steering key panels on energy said last week that they are eyeing reforms to a Jimmy Carter-era electricity market policy that may be burdening utility customers with unnecessary costs.

In a letter sent to FERC November 6, they asked the commission to convene a technical conference on its implementation of the Public Utility Regulatory Policies Act to “assist with the building of a public record and provide Congress with valuable insight into whether changes are warranted.”

The 1978 law requires utilities to buy

Lawmakers mull update of PuRPA, seek FeRC’s assistance in weighing need for reformpower from qualifying facilities — typically small cogeneration and renewable power plants — at a utility’s full avoided cost of replacing that power with other generation. FERC has the authority to enforce the statute’s requirements on state commissions when requested by generators, and can even take state commissions to federal district court to enforce those requirements.

“We live in a very different world than the one that precipitated PURPA, so a ‘check-up’ is probably in order,” FERC Commissioner Tony Clark told Platts November 9. (continued on page 17)

Natural gas inventories matched a record high in the week that ended October 30 and could swell to their highest level ever as injections of gas into storage continue over the coming weeks, the US Energy Information Administration said last week in its monthly outlook.

Inventories on October 30 were 10% higher than a year ago and 4% above the previous five-year average for that week, matching a record 3.929 Tcf, set November 2, 2012, EIA said in its November Short-Term

eIA posits gas storage could reach record 4 tcf; winter drawdrawn seen below averageEnergy Outlook November 10.

“US natural gas inventories could reach 4 [Tcf] for the first time ever in November, especially if above-normal temperatures reduce home heating demand,” EIA Administrator Adam Sieminski said November 10 in a statement.

The gas refill season began in April and is typically considered to end October 31, but inventory builds often continue into November, the report noted.

EIA added that the drawdown of gas (continued on page 16)

Even as 26 states are seeking to block EPA’s Clean Power Plan to reduce carbon dioxide emissions, Environmental Protection Agency Administrator Gina McCarthy sought to strike a cooperative note in addressing a large group of state utility regulators.

Delivering a keynote speech November 9 before the annual meeting of the National Association of Regulatory Utility Commissioners, McCarthy said that collaboration with states has made EPA’s rules “much stronger, much smarter and better” than they would otherwise be.

McCarthy left aside some of the more

McCarthy urges state collaboration despite lawsuits over CPPheated rhetoric about those battling the regulation in which she has accused critics of the plan as reviving “stale claims.”

She assured the state regulators that even as EPA deals with the litigation from states and others fighting the rule, it wants to continue dialogue and outreach. Some “might think that when someone sues us, it’s an opportunity for us to go into our own little corner,” she said. On the contrary, she said EPA would be looking to its regional offices to get every state engaged to the extent possible, and “to hear the diverse voices” that need to be heard.

“The passage of the act is now as close in time to Pearl Harbor as it is to the present day. Given the significant changes in the energy industry since FERC promulgated its rules under the law, I would support a technical conference,” Clark said. “The effort can help ensure that PURPA and FERC’s implementation of it are working for the benefit of American consumers.”

Republican Senator Lisa Murkowski of Alaska and Republican Representatives Fred Upton of Michigan and Ed Whitfield of

supplies in storage is expected to be slightly less this winter because of forecasts of warmer-than-normal weather. End-of-March inventories are projected at 1.862 Tcf, which, if realized, would be 240 Bcf above the five-year average, the agency said.

Such strong inventory builds, coupled with expectations of continued warm winter weather and production growth, aided in dragging gas prices over the past few weeks down to three-year lows, EIA said. Natural gas

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Many of the changes in the final rule stem from comments gleaned from outreach with states, she said, such as a two–year extension on the timeline for state plans.

The CPP aims to reduce emissions from the existing generation fleet to 32% below 2005 levels by 2030. Under the final rule, announced August 3, states are expected to create implementation plans to achieve interim CO2 reduction goals by 2022 and final goals by 2030.

McCarthy got some definite pushback at the conference from regulators in states that have argued the revised emissions targets they face in the final rule will be difficult, if not impossible, to achieve.

Julie Ferdochak, chairman of the North Dakota Public Service Commission, said that for ratepayers in her state, the shift in the state’s target from the proposed rule to the final, from an 11% reduction to 45%, was “anything but thoughtful. … Ratepayers in our state will be bearing the brunt of that. “

McCarthy responded by saying she has had conversations with the governor on that, and “I know it’s challenging.” But she defended the way the final rule was written to let states work across their boundaries to meet targets, and through EPA’s design of “trading-ready” emission reduction plans.

Stan Wise, a commissioner from Georgia, thanked McCarthy for the flexibility afforded to his state, pointing to an increase in the level of carbon, an extension of the timeline, and consideration of the impact of two nuclear plants under construction in formulating that state’s goals.

Ryan Sitton, a member of the Texas Railroad Commission, also pressed McCarthy on the role of Congress in formulating the standards, saying it seemed like Congress has been “put to the side.”

McCarthy described Congress’ role as having provided the Clean Air Act. The president has made clear that if Congress wants to provide an even more flexible approach that still results in significant emissions reduction, “everybody would welcome that. … Right now that does not seem to be where we are,” McCarthy said.

In comments to reporters on the sidelines of the conference, McCarthy said the higher targets that certain states are now facing result from additional comments following the proposed rule telling EPA that there are more regional renewable resources available, suggesting EPA needed to adjust the factual basis for the rule.

“We feel very confident that this final rule sets standards that every state can achieve,” she said.

In spite of the political and legal challenges the rule is facing, McCarthy also told reporters that the rule is final. “I think folks should feel very confident that EPA has finalized the rule, and that’s the rule that we’re implementing.”

In speaking to the NARUC commissioners, McCarthy also defended the regulation as fully supported by the Clean Air Act, and said “we’re really confident as we approach these legal challenges” that the rule will stand the test of time.

“Certainly we anticipated that litigation,” she said, quipping that “you don’t see 4.3 million comments” on a rule without understanding that “people are giving you hints on how they want it to come out.”

Publication of the rule in the Federal Register kicked off litigation of the matter, and congressional Republicans have begun work on resolutions of disapproval.

Nonetheless, McCarthy said, “overwhelmingly states are working with us in the planning process.”

— Maya Weber

mailto:[email protected]

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FeRC grants industry request for technical conference on proposed market surveillance ruleFERC will convene a staff-led technical conference on December 8 to get a better grasp on the industry’s concerns over a new reporting regime for regional market participants and operators that the commission proposed to aid its enforcement staff in detecting market manipulation.

FERC said in an order November 10 that it will also postpone the due date for comments on its proposed market surveillance rule until January 22, 45 days after the technical conference.

The order grants a request made last month by a group of companies engaged in energy trading. They argued that the proposal impacted market participants not traditionally regulated by FERC and required more guidance and time to understand the proposed regulation and provide meaningful comments.

While supporting the commission’s goal of eliminating manipulation in the wholesale markets, the companies participating in the October 28 filing said a technical conference “would help the commission carefully consider whether the reporting requirements — as currently drafted — will achieve the desired benefits commensurate with the burden that would be placed on [affected parties], or whether the reporting requirements could be drafted in a manner that eliminates some of the burden while preserving the commission’s goal of detecting market manipulation.”

FERC responded November 10 that it concurred “that a technical conference would be useful in understanding industry concerns and the extent of the burdens that would be imposed upon market participants under the draft regulatory language.”

The market surveillance rule (RM15-23) proposed in September would require market participants to obtain a common alpha-numeric identifier, list connected entities with which they have ownership, employment, debt or contractual relationships and briefly describe the nature of those relationships.

the connected entity data, through mandated tariff revisions, would be collected by the independent system operators and regional transmission organizations and then electronically furnished to the commission.

The uniform information would provide FERC’s enforcement staff with context to market data it already receives from the ISOs and RTOs, including insight into the incentives underlying market participants’ trading activities so staff may better differentiate between seemingly anomalous trading patterns for legitimate business reasons and for potentially manipulative reasons warranting investigation, according to the notice of proposed rulemaking.

Meghan Gruebner, an attorney with Sutherland Asbill & Brennan, told Platts November 11 that the burden and hefty compliance costs the proposal could saddle market participants with could outweigh the regulatory benefits.

“I do think that market participants support the underlying goal and objective of the NOPR … to prevent market manipulation, however, there’s a concern that these reporting requirements are not tailored narrowly or appropriately to attain that stated objective,” she

said. “We would like to see the rule be scrapped altogether, but at a minimum, FERC should limit and narrow the reporting burdens of the NOPR and engage in a more thorough cost-benefit analysis.”

She added that the cost-benefit analysis provided by FERC in the NOPR, “at first blush, appears to be unrealistic.” Gruebner, who represents clients that could be impacted by the proposed rule, said the NOPR “estimates the proposed costs to market participants as inconsequential,” which she does not believe is an accurate representation of the rule’s true compliance cost.

The rule, as drafted, is unclear on the level of detail market participants would be expected to provide in reporting connected entity data. More troubling, Gruebner said, is that market participants would have to certify the data they are reporting, attesting to its accuracy and completeness and opening themselves up to increased enforcement and compliance risk.

“Market participants have to be assured that they would not be responsible for certifying certain data that is not within their possession regarding the connected entities,” Gruebner said. “Perhaps the commission might want to consider a safe harbor where market participants reporting this data in good faith would be exempted from any violations for errors and omissions in the connected entity data they are reporting to the ISOs and RTOs.”

Further, Gruebner noted that much of the data FERC would receive through the NOPR would be duplicative and “wouldn’t provide any additional benefit to the commission, especially in light of the increased costs that market participants will face in compiling all of this data and submitting it in the form and manner the commission is going to require.”

While FERC-regulated public utilities are used to having reporting requirements with the commission, this rule would extend to market participants that are not historically or currently subject to FERC requirements, she said. “With respect to these companies that aren’t … subject to the commission’s regulations, they’re going to have to implement new systems and processes to comply with these reporting requirements,” Gruebner said.

Prior to joining Sutherland, Gruebner served as an attorney adviser to administrative law judges at FERC.

the companies that initially made the request to FERC for more clarity on the proposed rule were BP Energy, EDF Trading North America, GE Energy Financial Services, Iberdrola Renewables, Macquarie Energy, Morgan Stanley Capital Group, Tenaska Energy and TrailStone NA Logistics.

Among topics the companies suggested for discussion during a technical conference were an unambiguous definition of “connected entity” and “trader,” confidentiality issues associated with the data collected, and potential unintended consequences.

The request for a technical conference and extended comment period was supported in subsequent filings by an array of gas, electric and commodities trading groups and companies.

The full list of backers consisted of the American Forest & Paper Association, American Gas Association, American Wind Energy Association, ArcLight Capital Partners, Canadian Electricity Association, Cogentrix Energy Power Management, Commercial Energy

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Working Group, Edison Electric Institute, EDP Renewables North America, Electric Power Supply Association, Electricity Consumers Resource Council, Independent Power Producers of New York, Industrial Energy Consumers Group, International Energy Credit Association, Natural Gas Supply Association, New England Power Generators Association, PJM Power Producers Group, Private Equity Growth Capital Council and Retail Energy Supply Association.

— Jasmin Melvin

Bipartisan pipeline safety bill would press PhMsA to set priorities, regulate underground storageWork in the Senate on pipeline safety legislation began in earnest last week with the introduction of a bipartisan bill to reauthorize the Pipeline Safety Act introduced by Senators Deb Fischer, Republican-Nebraska, and Cory Booker, Democrat-New Jersey.

The SAFE PIPES Act would reauthorize the Pipeline and Hazardous Materials Safety Administration through fiscal year 2019. It follows up on an ambitious set of requirements imposed by the 2011 reauthorization in the wake of multiple high-profile pipeline accidents.

PHMSA has come under fire in Congress for its pace in issuing some 42 rules mandated by the 2011 act, and the new bill requires the agency to prioritize statutory requirements for rulemaking before pursuing new regulations. The Secretary of Transportation also would have to report to Congress on pipeline safety rules on which it is well behind schedule.

The legislation would also require new natural gas storage safety rules, seek to improve technology and communication related to data about pipeline locations, and require studies on pipeline integrity management and the definition of so-called high-consequence areas that trigger stiffer inspection requirements.

The legislation also seeks to speed hiring of federal pipeline safety inspectors by giving PHMSA direct hiring authority — rather than having to go through a lengthier process run by the Office of Personnel Management.

Fischer, a lead sponsor of the bill, is chairman of a key subcommittee with jurisdiction over the matter, the Senate Commerce Committee surface transportation and merchant marine infrastructure, safety and security subcommittee.

“Our bill would require the agency to prioritize significant safety objectives, facilitate the hiring of new pipeline inspectors, and bolster communication between PHMSA and the states, industry and safety stakeholders,” Fischer said.

Booker, ranking member of the Senate subcommittee, emphasized the need to make use of available technologies to pursue more efficient ways to keep pipelines safe.

“By implementing important oversight and accountability measures, promising more flexibility to PHMSA and deploying innovative technology, the SAFE PIPES Act will help ensure safer communities in New Jersey and around the country,” he said.

Other lead co-sponsors include Senators Steve Daines, Republican-Montana, and Gary Peters, Democrat-Michigan.

“We had asked Congress in our previous testimony for a modest

reauthorization bill this year that would allow PHMSA to continue to focus on getting out the rules and studies called for in previous Congressional mandates, asked for by the National Transportation Safety Board, and based on a rash of pipeline failures in recent years,” said Carl Weimer of the Pipeline Safety Trust.

“This bill from Senator Fischer appears to do exactly that. While it does hold PHMSA accountable by requiring continual reporting of the status of ongoing efforts, it does not add many new mandates that could delay rules that have already been in the works for years.”

In one area where the bill would expand regulation, the bill tells PHMSA to act within two years to set uniform safety standards for underground natural gas storage. It specifies, however, that the bill does not allow the Transportation Secretary to prescribe the location of storage facilities.

to help pay for the new regime, the bill would collect fees on underground storage facilities.

Interstate natural gas pipeline companies had been among those advocating for new gas storage rules by a date certain.

The legislation also seeks to reduce communication gaps between regulators over pipeline location data, requires that PHMSA assess integrity management programs for natural gas and liquid pipelines, and tells the agency to report on advanced mapping technologies for pipeline networks.

The Comptroller General would have to report to Congress, within 18 months of passage, on the extent to which the integrity management program has improved safety, and recommend any changes to prevent accidental releases, including possible changes to the definition of high-consequence areas. Population growth in rural areas and pipeline expansions have led some to question whether the current high-consequence area definition leaves vulnerable areas underregulated.

The bill would also require a similar report on the hazardous liquid integrity management program.

Getting at concerns from some lawmakers that federal pipeline inspection results are not shared promptly with pipeline operators, the bill would require briefings and final reports to occur no later than 30 days after a safety inspection.

In consultation with stakeholders, the Department of Transportation would also do a study on improving damage prevention through use of location and mapping technologies, as well as one-call systems and other communication initiatives.

It also calls for a look at the feasibility of a national data repository for pipeline excavation data, and for a working group with a wide array of stakeholders to look at information sharing, including on dig verification data.

The American Gas Association called the legislation a “positive step” and commended the lawmakers for a “good bill.”

The authors “acknowledged the incredible progress made through the programs set forth in the 2006 and 2011 pipeline safety legislation – bills that the American Gas Association supported,” the group said.

“The senators also recognized that the unanimously passed 2011 bill was substantive and addressed a series of important issues. Natural gas utilities are addressing the many regulations set forth in the 2011 bill and the Pipeline and Hazardous Materials Safety


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Administration continues to work towards promulgating many more.”The Interstate Natural Gas Association of America had no

immediate comment on the bill, saying the proposal was still under review.

Previous pipeline safety bills have passed with broad bipartisan support in the last decade. The SAFE PIPES Act kicks off work this Congress, with action also needed in two House committees: Energy and Commerce, and Transportation and Infrastructure. Fischer’s office did not immediately respond to request for comment on the schedule for committee action, although one industry source said a subcommittee markup is possible as early as this week.

— Maya Weber

new nARuC chief eyes ‘neutral’ role in examining distributed generation ratesThe new president of the National Association of Regulatory Utility Commissioners has set his sights on adding a “neutral and expert” voice into the volatile debate over how to price distributed generation.

In an interview with Platts, Travis Kavulla, vice chairman of the Montana Public Service Commission, said a key goal during his one-year term will be for the organization to develop a practical manual to help regulators set rates for distributed generation.

State regulators face a practical challenge “to understand pricing at the margins that doesn’t overcompensate or undercompensate” for the costs to hook onto the grid, or to establish price signals for customer-owned generation or home thermostats that encourage efficient uses.

“A great deal” of the manuals put out by interested parties have tended to be “self-serving,” he said, for instance, from utility interests that would set up “systemic under-compensation” for customer-owned generation — or from distributed generation interests that would lead to systemic overcompensation, he said.

In the world of telecommunications, emergence of a competitive market exposed latent cost shifts, he said, adding there are also opportunities for arbitrage as electricity is deregulated.

The NARUC manual would likely present a menu of options and candidly discuss the merits of each approach, he said. If, for instance, a regulator wanted to come up with a price for solar production from consumers, the manual could identify data needed to do that.

It is also meant as an exercise in “discerning the good from the ludicrous,” he said.

Kavulla discussed the need for the nARuC staff subcommittee to lead the effort in a speech November 10 before the group’s annual meeting in Austin, Texas.

“NARUC’s manuals have long been in use in certain regulatory settings, and we have an ability, through a staff subcommittee, to produce a practical, expert and most importantly ideologically neutral guide that offers advice to the dozens of states who are grappling with this question, and yet do not have the resources to do it themselves,” he said.

His speech also urged regulators to be watchful of “rent-seeking behavior” by special interests as plans are developed to comply with the Environmental Protection Agency’s Clean Power Plan for reducing

carbon emissions.As states develop plans, Kavulla called on the utility regulators to

play the role of “skeptic” of political logrolling and work to ensure environmental rules are implemented in the most economically efficient manner possible.

“We need to be wary of a so-called ‘solution,’ where interest groups line up for a dollar apiece of consumers’ money in order to accomplish something that should only take half that,” he said.

He also suggested states seek avenues of cooperation with other states to engage in trading, though he added in an interview that that statement was not meant to nudge states toward entering formal regional compliance plans. Compliance will be cheaper if states allow the fluid trading of CO2, he said in the interview, noting that the Clean Power Plan envisions trading even if states do not join in regional plans.

While saying he is “not a big fan” of the Clean Power Plan, he added it would be “irresponsible” for states not to think about how to develop their plans, even as legal challenges of the regulation are pending, at least to avoid having a federally designed plan imposed.

“I think you can walk and chew gum at the same time,” he said.He said he hoped NARUC’s role would be one of “convening and

showcasing” — for instance, highlighting and examining existing carbon regimes and identifying problems that require broader discussion.

“Candidly, there’s a lot of sound and fury signifying nothing,” with respect to some aspects of the debate, he said, suggesting nearly every state will decide that taking a mass-based form of compliance makes the most sense.

On wholesale markets, he emphasized in his speech the need for state regulators to be more engaged in developments in regional transmission organizations and independent system operators that ultimately affect consumer rates, he said, suggesting NARUC could help state regulators increase their advisory role in those organizations.

The conflict between sunk costs and marginal costs is at the heart of many hot topics before the commissions, such as how renewables play into the resource mix or the future of baseload generation such as nuclear power, he said.

“nARuC’s membership needs a better understanding and a more useful participation in the organized wholesale electricity markets. We need to understand that an RTO or an ISO can facilitate competition and the efficient use of resources that our consumers are already paying for,” he said.

“Yet we should be careful not to assume that these markets are free markets, and automatically result in efficient outcomes,” he said.

While some utility commissions may see an ISO or RTO as eroding their own authority, the right way to look at it is as an institution to supplant price-fixing regulation with a more complex set of regulations, and the commissions need to engage on details of the system of regulation, he added in an interview.

NARUC may play a role in educating membership about the wholesale markets and evaluating how well the state role is working, he added.

— Maya Weber



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eLeCtRIC POWeR

Big CO2 markets favored for new natural gas combined-cycle plants: consultantDevelopers of natural gas combined-cycle plants would likely choose to locate new facilities in larger markets with more liquidity in carbon emissions allowances under the Clean Power Plan, if other factors are equal, state utility regulators were told November 8.

During a meeting of the National Association of Regulatory Utility Commissioners’ Staff Subcommittee on Clean Coal and Carbon Management, one of the speakers was Paul Allen, senior vice president of the energy and environmental consultancy M.J. Bradley & Associates in Concord, Massachusetts.

The CPP treats new and existing natural gas combined-cycle plants differently. Existing NGCCs must hold CO2 allowances, known as emission rate credits, while new NGCCs are not required to do so, he said.

“That is the potential nub of a problem,” Allen said at the meeting in Austin, Texas.

New NGCCs already tend to be more efficient than existing plants, which allows them to be dispatched more frequently. Inasmuch as the CPP’s purpose is to switch power sources from plants that emit more CO2 to those that emit less, a switch to new NGCCs from existing plants with relatively similar emissions rates is counterproductive, he said.

Emily Fisher, Edison Electric Institute deputy general counsel for energy and climate, said that if this situation results in closing older NGCCs, “it will look like there’s a lot of ‘extra’ allowances without reducing total emissions.”

The Environmental Protection Agency calls this counterproductive switching “leakage” and requires states to address the problem in their compliance plans.

One way the EPA has suggested to address the issue of leakage is that states issue additional ERCs, described as “new source complements” to new and existing NGCCs, Allen said. An alternative would be to adjust a state’s ERC allocation method in some other way to level the playing field for new and existing NGCCs. A third option would be for a state to demonstrate that its unique circumstances make such leakage unlikely — perhaps by having an extraordinarily high level of renewable energy.

however, this whole issue of leakage in the CPP raises several questions, Fisher said.

“Does the EPA have the authority to require states to address leakage?” she said.

Another issue is whether giving extra ERCs to existing NGCCs might inappropriately discourage the development of new NGCCs, she said.

Alternatively, Fisher asked, “Would extra allowances to existing NGCCs really incentivize their continued operation?”

Muhsin Kasheef Abdur-Rahman, senior market strategist at the PJM Interconnection, advocated increased competition among generators as a way to enhance CPP compliance efficiency.

“Competition is not only good for ratepayers but also supportive of environmental objectives,” Abdur-Rahman said. “States have an incentive to trade with the largest market they can, because that market will be more liquid.”

An audience member asked the panelists to speculate about what type of market would be more likely to attract new NGCCs in relation to the leakage issue, whether it would be a state with new source complements or a state that addresses leakage by some other means.

Allen said the “strongest [option] is going to be the larger market.”In a state with new source complements, Fisher suggested the

question may be irrelevant. “It will be a situation where the more you operate, the more [allowances] you get, so you wouldn’t need them for compliance, so you are going to sell them,” she said.

NGCC site location has so many factors involved, such as tax treatment, that the question of how leakage is treated may seem a relatively minor part of the equation, Allen said.

— Mark Watson

Allco prods FeRC to enforce PuRPA against conflicting Connecticut state lawConnecticut’s energy regulators are running afoul of a landmark 1978 law that carved out a narrow role for states in regulating wholesale sales of electricity to foster renewable generation, a New York-based renewable energy firm said last week.

Under the Public Utility Regulatory Policies Act, utilities are required to purchase power from small renewable power plants and other so-called qualifying facilities (QFs) at the full avoided cost of replacing that power with other generation. States are empowered to tailor their own avoided cost rules, providing a limited exception to FERC’s exclusive authority over wholesale power sales.

Allco Renewable Energy, a qualifying small power producer under PURPA, contends that Connecticut state law has allowed the state to compel wholesale transactions with non-QFs in violation of the state’s obligation to implement PURPA.

The company, which operates solar farms across the US, petitioned FERC on November 9 to initiate an enforcement action against the Connecticut Department of Energy and Environmental Protection and the Connecticut Public Utilities Regulatory Authority (EL16-11).

Allco said in the petition that Connecticut’s DEEP solicited renewable energy project proposals in 2013 and, despite getting proposals from QFs including Allco, compelled the state’s electric utilities to enter into wholesale electricity contracts with Number Nine Wind Farm, a 250 MW generator too large to be a QF.

The DEEP commissioner intends to conduct another solicitation under a newer statute that requires proposals to come from renewable facilities of at least 20 MW or hydropower facilities of at least 30 MW — virtually excluding all QFs, Allco said.

Further, QFs would have to pay substantial fees to participate in the upcoming solicitation, “thus the solicitation is placing a significant state regulatory burden on the very specific generators that Congress sought to benefit when it allowed states some ability to regulate wholesale sales involving QFs,” Allco said.

“And, because states’ only authority to regulate wholesale electricity sales is derived from PURPA, any state rule that conflicts with PURPA is necessarily preempted,” it added.

Under PURPA, FERC has the authority to enforce the statute’s requirements on state commissions when requested by generators,


7



and can even take state commissions to federal district court to enforce those requirements.

But enforcement actions are rare as the commission generally relies on voluntary compliance or has let the parties themselves engage in the litigation, even when a violation of PURPA was found.

FERC filed suit to enforce the statute against a state for the first time in 2013. The suit was eventually dropped after FERC reached a deal with the Idaho Public Utilities Commission.

A FERC spokesman declined to comment on Allco’s petition.The commission, however, laid out its policy and process for

handling such petitions in a November 2012 order announcing its intent to act on the enforcement petition against the Idaho PUC.

“As the commission stated in its 1983 policy statement, we have discretion in choosing whether to exercise that enforcement authority under section 210(h)(2)(A) of PURPA,” FERC said in the order.

It continued, “We may choose to exercise our enforcement authority, or, where the commission refuses to bring an enforcement action within 60 days of the filing of a petition, under section 210(h)(2)(B) of PURPA, the petitioner may bring its own enforcement action directly against the state regulatory authority or non-regulated electric utility in the appropriate United States district court.”

Of note, FERC issued four declaratory orders directing the Idaho PUC to take corrective actions that were not heeded before it took the state commission to court.

Allco has asked FERC “to invalidate and permanently enjoin the Connecticut agencies’ compulsion of wholesale sales with other than QFs.”

The commission, in a notice issued November 9, opened Allco’s petition for enforcement to public comment through November 30. Per typical procedure, FERC will review the petition and any comments or protests filed, and issue a notice of intent either to act or not to act within 60 days of the petition being filed.

A notice of intent not to act would clear the way for Allco to initiate litigation if it so chooses, while a notice of intent to act means that at some point FERC would go to court to enforce PURPA.

Allco said that if the commission failed to initiate an enforcement action against the Connecticut agencies, it would file suit in federal district court to force the state to properly comply with PURPA.

Allco in December 2014 took DEEP Commissioner Robert Klee to court over the 2013 solicitation, asking that the resulting power purchase agreements be voided and that the commissioner be enjoined from violating PURPA in future procurement processes. The US District Court for the District of Connecticut dismissed that complaint as Allco lacked standing to sue and failed to state a claim. The US Court of Appeals for the 2nd Circuit upheld that decision on November 6 (Allco Finance Limited v.Robert J. Klee, 15-20).

— Jasmin Melvin

natural, manmade magnetic pulses can devastate grid with coast-to-coast impacts: panelOne day after the 50th anniversary of the blackout that spawned the North American Electric Reliability Corporation, state regulators were told that a similar event could result from natural or manmade

magnetic pulses, with devastating consequences.During a panel discussion November 10 at the National Association

of Regulatory Utility Commissioners annual meeting in Austin, Texas, Carolene Mays, Indiana Utility Regulatory Commission member, described geomagnetic disturbances and electromagnetic pulses, either of which can cause a blackout over a wide area, such as affected parts of Canada, New England and the Mid-Atlantic states on November 9, 1965.

A geomagnetic disturbance can result from solar flares or solar mass ejections, while an electromagnetic pulse can result from the high-altitude discharge of a high energy weapon, such as a nuclear device, Mays said. Their results fall into three categories. An E1 pulse, Mays said, creates a high voltage that can damage or destroy electronic equipment such as computers, cell phones and vehicles. An E2 pulse has an effect similar to lightning, from which most power grid elements are sufficiently protected. An E3 pulse distorts the earth’s magnetic field and can damage electrical infrastructure, Mays said.

the 1965 blackout was caused by human error that occurred days before, when a protective relay was set at an incorrect level, which, when loaded, resulted in cascading power outages across the Northeast.

FERC Commissioner Cheryl LaFleur was one of the panelists in the discussion of GMDs and EMPs. A blackout in Quebec in March 1989 has been traced to a coronal mass ejection, she said, but the events have been so rare that preparing for them is problematic.

“The consequences could be so devastating that it’s incumbent on us to do what we can now,” LaFleur said. “We definitely need more monitoring of what is happening on the grid than we have now.”

Denis Bergeron, Maine Public Utilities Commission director of energy programs, said his state’s legislators asked the commission to consider requiring industry to build a transmission system that could withstand a GMD or EMP, but the PUC determined that such an effort would be too expensive.

“New Hampshire is quite a bit more susceptible than we are,” Bergeron said. “Even if we were to spend [enough] to protect against a one-in-500-year event, you are only as strong as your weakest link. … If we built our system to be more robust, it could have negative effects on neighboring systems.”

Another issue is that merchant generators may have less modern and resilient equipment than those installed and maintained as part of a utility rate base, Bergeron said.

“One of the reasons our system [in Maine] has held up so well is the equipment is being refurbished,” he said.

Randy Horton, Southern Company transmission planning manager, said the power industry needs to study how equipment that did not exist during previous geomagnetic disturbances performs under similarly extreme voltage conditions.

“If you detonate a nuclear weapon in the atmosphere, you’ve had a bad day,” Horton said. “From an electric utility standpoint, you’d have a localized blackout. Some of your electronics are going to fail.”

LaFleur said water systems that depend on electricity would likely fail, which would create problems for steam generators.

One group researching how to defend against and recover from these extremely rare, extremely catastrophic events is the Electric Infrastructure Security Council, which was represented on the panel by


8



Chris Beck, the council’s vice president for policy and strategic initiatives.The possibility of an electromagnetic pulse from a high-altitude

weapon is shrouded in government secrecy, Beck noted. Clearly a high-altitude nuclear weapon explosion’s “impacts would be coast to coast,” but it would not “fry every light bulb.”

“If you can quickly reboot the electrical grid or water system, that’s OK,” Beck said. “You need to make sure your black-start system works.”

— Mark Watson

RG&e issues RFP for Ginna replacement power; analysts expect prices to rise after nukes retireRochester Gas & Electric has issued a request for proposals for supply to temporarily replace the electricity it is buying from Exelon’s Ginna nuclear plant.

Meanwhile, an analyst said November 6 that the retirement of Ginna and Entergy’s nearby Fitzpatrick nuclear plant would raise capacity prices in New York.

RG&E issued a request for proposals for 580 MW as a contingency alternative to the reliability support service agreement it has with Ginna that will end in March 2017. The plant is north of Rochester on Lake Ontario.

The solicitation is for a variety of resources, including generation, demand response, energy efficiency, energy storage or other resources that are able to meet the utility’s need.

“RG&E is issuing this RFP in the event that RG&E believes, in its sole discretion, that Ginna will no longer be operating and system upgrades will not be completed in a timely manner to avoid a continuing reliability need,” RG&E said.

In late October, Ginna’s owner, Exelon Generation, and RG&E reached a settlement with the New York Public Service Commission staff that would keep it operating until March 2017. The company had asked for a reliability support services agreement to keep the unit operating until October 2018.

The shortened contract is due to the utility’s assurance that it will have a retirement transmission alternative available one year earlier than had been anticipated, Exelon said in an October 22 statement.

The transmission upgrades should be completed no later than October 31, 2017, RG&E said in the RFP. The generation is needed beginning April 1, 2017, until the transmission upgrades are completed, the solicitation said.

exelon said the operation of Ginna until 2017 is only a temporary solution to a long-term problem. “Single unit nuclear facilities like Ginna face significant challenges brought on by poor market conditions and a lack of energy policies that properly value the clean and reliable energy that nuclear provides,” the company said in a statement.

Exelon said during its earnings call on October 30 that Ginna is one of three nuclear units it considers to be at the greatest risk for early retirement due to their current economic valuations and other factors.

A UBS analyst said November 6 that he expects New York Independent System Operator prices to rise as Ginna and Entergy’s 851 MW Fitzpatrick plant retire. Fitzpatrick, on Lake Ontario about 50 miles

east of Ginna, will retire in the fall of 2016.“We see prices heading materially higher across the state in the

near term, particularly in the upstate region,” Julien Dumoulin-Smith, the UBS analyst, said.

Dumoulin-Smith said he expects a conservative summer 2017 NYISO capacity price of $7/kW-month, up from about $3.50/kW-month in the summer of 2015. Taken together, UBS sees winter and summer capacity prices trending upward at more than $20/kW-year, year over year, in 2017.

The uplift from the retirement of the two nuclear units could be higher, but Dumoulin-Smith said offsetting effects, such as imports from adjacent regions, would backstop high-priced summer capacity obligations.

Dumoulin-Smith sees the retirements as likely pushing additional new gas-fired capacity in the Lower Hudson Valley, including Advanced Power’s proposed Cricket Valley project and Competitive Power Ventures’ Valley project. Dumoulin-Smith said he expects prices in the currently constrained area to clear lower in line with the rest of the state.

“Our prior forecast had called for a flattish profile in 2017, with a decline in 2018 with new [combined-cycle gas turbine] entry. We now see a $3/kW-month bump from our prior forecast setting out a higher overall level in 2018 despite new plant entry,” Dumoulin-Smith said.

— Mary Powers

Clean Power Plan compliance easier if states cooperate, set up emissions markets: panelCooperation among states in trading emissions allowances can make compliance with the Clean Power Plan easier, and an obstinate go-it-alone strategy can make it more expensive, state regulators were told last week.

For example, the Environmental Protection Agency has given states the option of basing their compliance on a rate of carbon emissions per megawatt-hour, known as the “rate-based” option, or on an equivalent total tonnage of carbon emissions over a period for the state as a whole, known as the “mass-based” option.

If most states use one option, those that are in the minority will find it more difficult to trade enough allowances to demonstrate compliance, said Doug Scott, Great Plains Institute vice president for strategic initiatives, during a panel discussion at the National Association of Regulatory Utility Commissioners’ annual meeting in Austin, Texas.

The discussion was entitled “Hang Together: 111d Multi-State Solutions” and occurred November 9. The application of carbon regulation to existing electricity generation comes under Section 111d of the Clean Air Act.

Joshua Epel, Colorado Public Utilities Commission chairman, said he has seen press reports of some states that have excess allowances, known as emission rate credits, hoarding them in order to induce other states to reduce their own emissions.

But Robert Wyman, an attorney at Latham & Watkins, said, “I think it is extremely important for states like California and other leading states to work with others.”



9



Joseph Goffman, EPA associate assistant administrator for the Office of Air and Radiation, said any state that hoarded such allowances would do so “at an extremely high avoidable cost.”

In the past, when any state has considered how to comply with an environmental regulation, Goffman said, “I don’t think I can think of an example when a less economic — as opposed to a more economic — option has been chosen.”

Epel asked what happens if a state or region lacks sufficient emission rate credits.

In response, Goffman said, “Sometimes, textbook economics does give a reliable answer. If, at some point in time, there’s an insufficient supply of allowances, that will be a signal into the system to those who need to invest in additional [emissions] reductions.”

However, Wyman said “there’s a lot of head room” in the Clean Power Plan.

“undoubtedly, there will be additional headroom we don’t now anticipate — from advances in storage, for example,” Wyman said.

When asked whether a formal emissions market offers an advantage over an informal bilateral market for CPP compliance, Kelly Speakes-Backman, a member of the Maryland Public Service Commission and chairwoman of the Regional Greenhouse Gas Initiative, said, “I would point to RGGI as an example of how it can and does work.”

“That said, there’s absolutely an opportunity for a less formal, trading-ready approach,” she said, as long as allowances are standardized so that counterparties understand their transactions.

One issue that RGGI has dealt with is how allowances are distributed. RGGI auctions off its allowances, while other states may decide to allocate a certain number of allowances to each emitter, based on its past or expected power production.

Wyman said he is ambivalent on this question.“One concern … is that [a state auction] essentially shifts capital

deployment from the private to the public sector … which ultimately will hurt ratepayers,” Wyman said. “There are redistributional effects and economic efficiency aspects.”

Scott said he expects some state regulators would prefer to issue allowances in such a way that they could avoid involving their state legislatures, and he does not know of a government situation involving large amounts of money that does not involve legislative action.

“Every state has to make a decision about what makes the most sense for them in the marketplace,” Scott said. “Think about what your state is and what you want your state to be, and these questions will be answering themselves.”

— Mark Watson

tRAnsMIssIOn

PJM utilities fighting Order 1000 call FeRC stance on applicability of Mobile-sierra ‘indefensible’FERC’s assertion that construction rights held by transmission owners in PJM Interconnection were not entitled to Mobile-Sierra protections presents “an untenable legal conclusion,” utilities said in a filing to a federal appeals court Thursday.

The utilities are fighting FERC’s landmark transmission planning and cost allocation rule as it eliminated the right of first refusal (ROFR) for incumbent utilities, a move they say trampled on their contractual rights under the 2005 consolidated transmission owners agreement that all transmission owners in PJM are required to execute.

Two sections of that agreement, they said in a lawsuit filed last year, provided them with a federal ROFR to construct transmission facilities, and those provisions should be protected by the public-interest standard of review, known by the name Mobile-Sierra (American Transmission Systems, et al. v. FERC, 14-1085).

Under Mobile-Sierra, FERC must presume that the rate set out in a freely negotiated power contract is just and reasonable. Under that doctrine, the presumption cannot be overcome unless FERC concludes that the contract harms the public interest in a particular way.

FeRC in 2013 rejected PJM’s argument for retaining ROFR and directed the grid operator to remove any language from its tariff that could be read to establish a ROFR. FERC upheld that decision on rehearing.

The commission last month argued that the DC Circuit Court of Appeals, where utilities in PJM brought the suit, lacked jurisdiction. But even if the court were to assume jurisdiction, the case would fail on the merits as the transmission owners agreement at issue is not entitled to Mobile-Sierra protection, the commission said (IF, 19 Oct, 9).

In a reply brief submitted to the DC Circuit Thursday, the utilities charged that FERC misstated “the history and record of this proceeding … to wrongly suggest that this court does not have jurisdiction to decide the Mobile-Sierra issue” in an attempt to “avoid having to defend its indefensible rulings on the merits.”

Further, the utilities said that FERC’s actions would essentially destroy the bargain that transformed PJM from a tight power pool to the regional transmission organization that it is today.

“As the PJM transmission owners have repeatedly explained, their agreement to transform PJM ‘was expressly made contingent upon the continuation of their pre-existing [rights of first refusal] being acknowledged and honored by PJM and all others,’ which was ‘their quid pro quo for making this RTO formation a reality,’” the utilities said, referencing language from a commission order.

“this unfair attempt to rewrite the bargain is prohibited under Mobile-Sierra,” they added in the reply brief.

FERC also argued last month that the transmission owners agreement at issue was more of a generally-applicable tariff than an individually-negotiated contract, and Supreme Court precedent restricted the Mobile-Sierra presumption of reasonableness to contracts only.

The commission alternatively argued that the Mobile-Sierra presumption did not apply here because the relevant provisions in the transmission owners agreement were not the result of arm’s-length bargaining but instead were part of an arrangement made in 1997 and have never been renegotiated.

The utilities contend that FERC simply invented “new hurdles to the application of the Mobile-Sierra presumption,” charging that no court has ever recognized an exemption from Mobile Sierra for generally-applicable contract terms.

“The only relevant distinction is between rates set by contract and unilaterally filed rates; it is not between contract provisions of general


10



or specific applicability,” they told the DC Circuit. “That FERC may deem some terms of a negotiated agreement to be generally applicable does not turn them into unilaterally imposed terms akin to those established by tariffs.”

Additionally, they challenged FERC’s conclusion that there was no arm’s-length negotiation associated with the agreement, countering that PJM’s governing agreements “represent a carefully balanced compromise in which the PJM transmission owners defined rights among themselves, gave certain rights to PJM, and retained other rights against PJM and one another.”

The reply brief contended that “only circumstances such as unfair dealing or illegality at the contract formation stage — i.e., conditions that make a contract void or voidable — take a contract outside the scope of Mobile-Sierra.”

Final briefs for the case are due to the DC Circuit December 14.— Jasmin Melvin

developers to offer capacity on southline, with solicitation planned for early 2016With key regulatory hurdles cleared, the developers of the 345 kV Southline transmission project between New Mexico and Arizona said November 9 they plan to hold a solicitation for capacity on the line by early next year.

The project’s developers contend that the planned transmission line will allow utilities in the Southwest to gain increased access to power supplies, open a path for renewable exports out of the region and reduce transmission congestion in the area.

Earlier in the month, the Bureau of Land Management and Western Area Power Administration issued a final environmental impact statement for the project and in September FERC approved plans to allocate up to all of the capacity on the transmission line to at least one anchor tenant selected through a solicitation process (EL15-65).

Two affiliated cooperative utilities, Arizona Electric Power Cooperative and Southwest Transmission Cooperative, have asked FERC to clarify that the sale of capacity on the line won’t affect WAPA’s transmission fees.

The 1,000 MW, bidirectional project includes building 240 miles of double-circuit 345 kV lines between the Afton substation, near Las Cruces, New Mexico, and the Apache substation, near Willcox, Arizona. It also calls for upgrading 120 miles of 115 kV lines owned by the Western Area Power Administration to 230 kV from the Apache substation to the Saguaro substation near Tucson.

The roughly $750 million project may include a substation in Luna County, New Mexico, where a 30 mile spur would be built to provide access to renewable generators.

The developers have an agreement with WAPA, which may take a stake in the project while providing debt financing under its transmission infrastructure program, according to the developers.

Southline, owned by Dallas-based Hunt Power, plans to start building the project next year and bring it online in 2018.

Public Service Co. of New Mexico said November 9 it has issued a request for proposals seeking a contractor to build an 80 MW to 120 MW natural gas-fired peaking power plant near the San Juan power plant in Waterflow, New Mexico.

PNM wants the simple-cycle plant to be operating in 2018 as part of the utility’s plan to retire two units at the coal-fired San Juan plant. PNM is seeking regulatory approval for its plan at San Juan.

Proposals for the peaking plant to be built on a turn-key basis are due January 19.

— Ethan Howland

Illinois approves Grain Belt transmission project to carry 4,000 MW of wind power to MIsO, PJMBy a 3-2 vote, Illinois regulators on Thursday approved that state’s portion of Clean Line Energy Partners’ proposed $2.2 billion Grain Belt Energy high-voltage transmission line that would be designed to carry 4,000 MW of Kansas wind power eastward to the Midcontinent Independent System Operator and PJM Interconnection regions.

The Illinois Commerce Commission’s decision still leaves the 600 kV, 780-mile line one state short of what the Houston-based company most likely needs to move the project forward to construction.

Earlier this year, the Missouri PSC twice rejected the controversial project, citing concerns over routing and property values. With the ICC’s action, Clean Line now has state approvals from Kansas, Indiana and Illinois.

The ICC followed last month’s recommendation by administrative law judge Jan Von Qualen. She concluded Grain Belt would assist in the creation of a competitive energy market.

The commission will require Clean Line to secure funds to cover total project costs before construction commences and prohibits expanding the project without ICC approval. Commission approval also would be necessary before Clean Line recovered any project costs from Illinois retail customers through regional cost-allocation.

The ICC also directed Clean Line to take specific actions to address landowners’ concerns that included potential impacts from the construction of the line on irrigation operations, soil compaction and erosion, wetland areas and timber land.

The project’s current development schedule calls for construction to begin in 2017 with completion in 2019.

Las Cruces

DemingAfton

El Paso

Saguaro/Tortolita

ArizonaNew Mexico

Tucson

Benson

Apache

MidpointNorth

Casa Grande

Phoenix

MEXICO

UNITED STATES

Lordsburg

Willcox

Source: Southline Transmission

SOUTHLINE TRANSMISSION PROJECT PROPOSED ROUTE

Substation End Point

Intermediate Substation Location

Proposed Substation Location

Upgrade segmentNew build segment



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Clean Line president Michael Skelly, in a statement, hailed the ICC ruling.

“The ICC approval brings the Grain Belt Express Clean Line one step closer to dramatically increasing the low-cost wind energy available to customers in Missouri and Illinois,” he said. “We appreciate the ICC’s careful review of our application and are encouraged by Illinois’ recognition of the public benefits brought forth by this critical infrastructure project.”

According to Clean Line, the project would deliver enough electricity to power approximately 1.6 million homes and reduce wholesale power prices in Illinois by an estimated $750 million in the first five years of operation.

In testimony filed with the ICC earlier this year, the commission’s staff voiced some concern over the impact that lower power prices could have on Exelon’s three money-losing nuclear plants in the state — Quad Cities, Byron and Clinton, representing more than 5,000 MW, as well as the future of new generation in Illinois.

Now, Clean Line’s emphasis returns to Missouri, company spokeswoman Sarah Bray said in an interview following the ICC vote.

“We’ve been 100% focused on Illinois,” she said. “We haven’t exactly determined what our strategy is” for Missouri. “We’ll have that decision early next year.”

One possibility, she acknowledged, is filing a new Grain Belt case with the Missouri PSC.

That case undoubtedly would include new information. As Bray observed, there have been important changes in the power industry in recent months, none more so, perhaps, than the Environmental Protection Agency releasing its final Clean Power Plan.

The CPP is aimed at slashing carbon emissions. One way to do that, Bray noted, is by developing more of the renewable energy that Grain Belt would facilitate.

— Bob Matyi

MARKets

some consider proposal to help alleviate FtR underfunding in PJM to be inadequateTariff revisions proposed to address underfunding of financial transmission rights in PJM Interconnection drew a mixed bag of comments last week, with even those supporting the plan acknowledging that it fails to tackle the root cause of the issue.

FTRs are financial instruments used to offset participants’ transmission congestion costs in the day-ahead market. FTRs entitle their holders to a stream of revenue or charges based on the day-ahead price difference across a transmission path.

PJM has struggled with FTR underfunding since 2010, with revenue adequacy consistently above 95% prior to 2010 and falling to between 69% and 85% for the 2010-11 through 2013-14 planning periods, according to the independent system operator.

In a filing (EL16-6) to FERC October 19, PJM sought to correct deficiencies in its auction revenue rights allocation and FTR auction processes in light of the persistent FTR underfunding.

ARRs are allocated to market participants who have firm transmission service. Companies that receive ARRs may hold onto them and receive revenue from the FTR auction or convert their ARRs into FTRs.

Conceding that there were many causes for FTR revenue inadequacy, PJM said that its proposal was primarily aimed at the over-allocation of ARRs that has exacerbated the revenue inadequacy problem.

PJM’s operating agreement requires it to allocate a minimum amount of ARRs for a 10-year period in its Stage 1A ARR allocation process even if the ARRs are not feasible.

Under its existing market rules, PJM addressed revenue inadequacy by taking what it called a more conservative approach to allocating Stage 1B ARRs.

This, and other steps, resulted in revenue adequacy at 110% for the 2014-15 planning period and at 116% for the first four months of the 2015-16 planning period.

But PJM’s independent market monitor, Monitoring Analytics, said the conservative approach was “a euphemism for the very significant under-allocation of Stage 1B ARRs which was implemented … despite its unknown and presumably unintended consequences.”

The shift from revenue inadequacy to having excess congestion dollars was a short-term fix, simply masking the problem rather than truly solving it, Monitoring Analytics said.

Therefore, PJM proposed to escalate the current ARR results using a zonal load forecast growth rate of +1.5% during the Stage 1A 10-year simultaneous feasibility process, and to eliminate the netting of positively and negatively valued FTR positions in a portfolio before determining payout ratios.

Monitoring Analytics said in comments due to the commission November 9 that PJM’s “transmission system is not currently adequate to support the required level of Stage 1A ARR allocations.”

The 1.5% adder would help PJM identify needed facility upgrades “slightly earlier and may eliminate future revenue shortfalls caused by the time it takes to implement these physical upgrades,” Monitoring Analytics said.

While “a positive development” to address the over-allocation of Stage 1A ARRs, it “does not affect the root cause of the issue,” the IMM said. “As long as PJM is required to provide Stage 1A ARRs at a predefined level, PJM should be required to build the transmission facilities required to do so.”

It suggested that a review of the historical basis for the allocations was needed as the reference year for allocations in some zones can date back to 2008. As a result, facilities that are no longer in service are still being allocated Stage 1A ARRs, the IMM said.

The more notable element of PJM’s proposal, Monitoring Analytics said, was the elimination of the ability to net negatively valued FTRs against positively valued ones. Under current market rules, this netting essentially requires market participants with positively valued FTRs to subsidize holders of negatively valued FTRs.

“The issue is not about the use of portfolios to offset risk which continues to be a good strategy,” the IMM said. “The winners in a portfolio will offset the losers in a portfolio, if all works well. But in the FTR payout process, it is as if the holder of a portfolio of stocks which


12



include some stocks that have lost value could require holders of portfolios with only winning stocks to pay for part of their losses. This would never be permitted in any rational market and should not be permitted here.”

Although the IMM said the proposed revisions should be approved by FERC as “an important step in the right direction,” it asserted that PJM has not done enough to implement steps it proposed to correct the FTR market.

“PJM has begun to address the topics of eliminating geographic subsidies, improved outage modeling and a reduction of FTRs on persistently revenue inadequate paths. However, the measures PJM has implemented regarding these topics are not sufficient and require more development and documentation to properly address the underlying issues,” the IMM contended.

Other comments in support of the proposed tariff revisions were filed by Public Service Electric and Gas, Dayton Power and Light, FirstEnergy Service Company, Direct Energy Business, Dominion Resources, Dominion Electric Cooperative and American Electric Power.

While urging FERC to accept the tariff filing, most of the supporters also noted the need for more consideration of underlying causes driving persistent FTR underfunding.

J. Aron said in comments to the commission that while it was not necessarily opposed to the two reforms proposed by PJM, it believed the two provisions were too narrow.

“The commission should find that the existing PJM tariff provisions on ARRs and FTRs require modification, but direct PJM to file more comprehensive reforms to its tariff to address the issues raised in this proceeding,” it said.

As for those prodding FERC to reject the proposal, Appian Way Energy Partners said the tariff revisions would have “poor public policy outcomes” and offered alternative approaches used by other grid operators to address the over-allocation of ARRs, while Shell Energy North America argued that the elimination of netting was “unduly discriminatory or preferential” and would do “nothing to ensure revenue sufficiency going forward.”

Elliott Bay Energy Trading as well as a consortium consisting of DC Energy, Inertia Power, Saracen Energy East and Vitol filed protests with FERC, challenging PJM’s proposal.

they argued that the IsO failed to show that the current tariff is unjust and unreasonable and that the proposed revisions would be just and reasonable. Further, the protests contended that PJM failed to identify and address the root causes of its FTR funding and ARR allocation issues.

PJM initially asked FERC for a January 1 effective date for its tariff revisions, but corrected that in an October 30 filing requesting a June 1 effective date.

“However, PJM still requests a commission order by January 1 … to ensure market participants have clarity as to the rules that will be in place for the 2016/2017 planning period, as well as to provide sufficient lead time necessary for PJM to develop its software to implement the changes if accepted,” the ISO said.

PJM’s annual ARR allocation and FTR auction beings in February 2016 for the 2016-17 planning period.

— Jasmin Melvin

new York IPPs seek market rule clarification to bar state entities from market power exemptionState entities have not only the incentive and ability to artificially suppress capacity prices in New York Independent System Operator markets but a track record of doing so, the Independent Power Producers of New York and Electric Power Supply Association charged in a filing to federal energy regulators.

For that reason, FERC must clarify that the New York Power Authority, Long Island Power Authority and other state entities are not eligible for an exemption from buyer-side market power mitigation rules approved by the commission in October.

“In the alternative, if the commission declines to grant clarification, IPPNY/EPSA respectfully requests rehearing of the commission’s decision not to explicitly exclude state entities such as NYPA from being eligible for a self-supply exemption,” the trade groups said in a filing to FERC November 6.

At issue is an October 9 FERC order (EL15-64) that directed NYISO to submit a compliance filing to revise its rules “to exempt a narrowly defined set of renewable and self-supply resources” from its BSM rules (IF, 19 Oct, 11).

Among the load-serving entities FERC listed as examples of those that would qualify for the exemption were municipalities, cooperatives and single-customer entities that self-supply the majority of their needed capacity. The commission reasoned that these entities procure a “relatively small” amount of capacity from the installed capacity (ICAP) markets and therefore would lack the ability to exercise buyer-side market power to artificially suppress ICAP market prices.

IPPNY and EPSA said that while they did not interpret the order as permitting NYISO to propose a more broadly defined self-supply exemption that would allow state entities to qualify, some could make such a case if FERC fails to explicitly bar state entities from eligibility.

“A state entity such as nYPA would have the incentive and ability to sponsor an uneconomic entrant to lower prices statewide and force the retirement of economic but unfavored generation, even though the state entity itself may not profit from the price suppression,” the groups said. “The state may elect to use entities such as NYPA and [LIPA] to suppress prices statewide even if the strategy would result in a net loss to that particular entity.”

They continued, “unlike the municipal entities the commission discussed as lacking the ability to artificially suppress ICAP prices, NYPA and LIPA have large amounts of load and can sponsor enough uneconomic new entry to artificially suppress ICAP prices significantly even if the NYISO proposed narrow net-short and net-long thresholds.”

Further, IPPNY and EPSA pointed to the Astoria Energy II and Hudson Transmission Partners projects as evidence of NYPA’s ability to artificially suppress prices.

“Both of these uneconomic entrants obtained subsidized contracts with NYPA pursuant to discriminatory procurement processes that excluded existing resources, and such contracts were conditioned on construction of the projects,” IPPNY and EPSA said. “These NYPA contracts were exactly the type of ‘state decisions to subsidize


13



resources that are owned or contracted for by a self-supplied load serving entity’ — decisions that must encompass actions taken by state public power authorities — about which the commission expressed concern in the October order.”

The filing added that the AEII facility, initially exempted from mitigation, adversely impacted the market for 16 months before a FERC order made it subject to mitigation. Further harm to the market was prevented by the HTP project being correctly mitigated from the start.

IPPnY and ePsA concluded that “the nYIsO must narrowly define the resources eligible for a self-supply exemption from its BSM measures, limiting eligibility to those resources that lack the ability and incentive to artificially suppress prices and specifying that state entities … that have the ability and incentive to, as well as a history of, artificially suppressing prices by supporting uneconomic entry into New York’s markets are ineligible for the self-supply exemption.”

The October order stemmed from a May 8 complaint filed by the New York Public Service Commission, NYPA and New York State Energy Research and Development Authority.

The agencies sought to limit application of the BSM rules to new oil- or gas-fired units greater than 20 MW. They requested that the rules no longer apply to renewable resources, controllable transmission lines, nuclear resources and special case resources like demand response, and that exemptions be provided to self-supply resources, resources needed for reliability and repowered resources.

FERC denied exemptions for all of the resources listed in the complaint except for renewables and self-supply resources.

The New York agencies who filed the complaint argued in a filing to FERC November 9 that “the exceedingly narrow exemption granted for renewables will impede state efforts to increase reliance on renewable generation” and squash attempts to speed the development of large-scale renewable projects, putting FERC’s decision in conflict with the aims of the Obama administration’s Clean Power Plan to reduce emissions.

“The commission instead should approve a general, uncapped exemption for all new renewable resources,” the agencies said in their request for rehearing.

they also urged the commission to reconsider its rejection of an exemption for demand response resources. “Mitigating DR resources will act as a disincentive to current and prospective DR providers and restrict the growth of DR programs in New York,” they argued.

This request was reiterated by a group of transmision owners who prodded FERC to “grant rehearing and require the NYISO to add a DR resource exemption to its BSM measures.”

“DR resources, like renewables, are a small proportion of capacity market resources and it is not feasible to use them to suppress capacity market prices. Moreover, any risk that providers of DR resources would act in a way that could result in undue capacity price suppression can be eliminated through the implementation of an appropriate cap,” a said the November 9 filing from Consolidated Edison Company of New York, Orange and Rockland Utilities, New York State Electric and Gas, Rochester Gas and Electric and Central Hudson Gas and Electric.

Under the existing rules, new capacity resources entering the ICAP markets set up in New York City and the surrounding Load Zones G, H, I and J must meet a floor price until their capacity has cleared 12 monthly auctions. Resources may forego such offer pricing if they are able to pass a mitigation exemption test, which requires their forecasted capacity prices to be higher than either the default offer floor for 12 months or their net cost of new entry for three years.

On the other hand, Entergy Nuclear Power Marketing and a group of suppliers — including Astoria Generating Company, TC Ravenswood, the NRG Companies and Cogen Technologies Linden Venture — argued that FERC went too far.

“Both exemptions will become tools to artificially suppress capacity prices. And the guidance offered by the commission, while an important first step, nevertheless lacked adequate specificity,” Entergy contended in a November 9 request for rehearing. “The commission should reverse itself and deny the complaint in full, rejecting new exemptions from buyer market power mitigation for all self-supply and intermittent renewable resources,” it said.

The group of suppliers pushed back mostly on the self-supply mitigation exemption, saying that it posed a “severe threat ... to NYISO’s capacity market.”

They said that “just and reasonable rates are not a one-way ratchet that are solely aimed at achieving the lowest rates for consumers; rather, they must also ensure that existing suppliers have a reasonable opportunity to recover of, and on, their invested capital.”

— Jasmin Melvin

Georgia retail market seen defying assumptions; high consumer switch rate, weak link to costsDeregulation of the retail natural gas markets has defied expectations in Georgia, among them the presumption that industrial switching would outpace that of residential consumers and that low prices would be the main driver of residential consumers’ selection of providers.

That was the assessment offered by attorney Mark Caudill at the National Association of Regulatory Utility Commissioners meeting in Austin, Texas, November 9.

Caudill, who was speaking during a panel examining the evolution of the competitive retail natural gas markets, was actively involved in deregulation efforts as a representative of AGL Resources.

Looking at the retail gas markets across the US, he said, of nearly 70 million residential gas customers, only about 10% participate in retail choice, and about 58% of those who could choose, do not.

Only two states had high rates of eligible customers and high rates of participation: Georgia and Ohio, according to Caudill. Eleven states with high eligibility rates had fewer than 50% who chose to switch. On the other hand, two states with low eligibility rates had high participation: Florida and Nebraska, he said.

Georgia’s effort to bring in residential customers was by design. Many other jurisdictions put tremendous emphasis on serving large customers, whose volumes could translate into large profits even at small margins, he said.

“We wanted to invert that” and make residential customers “far


14



more valuable,” he said. To do so, Georgia created a system in which the benefit of access to assets needed to serve the customers would be assigned to end-use customers and would travel with the customers if they switched marketers.

In addition, in Georgia, retail customers that didn’t select a new supplier were randomly assigned to a marketer. Often, those people, preferring not to have the choice made for them, then took action to switch, he said.

States that had higher than average bills were the first movers to take competition to the residential level he said; 87% of states with high bills pursued unbundling; and 31% of states with low retail bills did the same, Georgia among them, Caudill said.

Georgia proposed its retail gas restructuring legislation in 1996 and started competition in 1998, he noted. Once Georgia put retail restructuring into effect, Caudill said, “we were a bit shocked by how fast we moved to competitive rates,” adding that the 10 months taken trounced the predictions, particularly for rural areas.

“We were told by all the best minds ... it would take three, five or 10 years for the market to move. It took 10 months, which I think caught us all off guard,” he said.

One myth shattered in Georgia is that industrials would switch at a greater rate than residential customers, Caudill contended. He showed graphs of monthly switch rates showing a higher percentage of eligible firm residential customers than firm industrial customers making the change. “So mom and pops really do care about having these choices,” he said.

Another myth to fall victim to Georgia’s experience was that those marketers offering bigger discounts would get higher market share.

In fact, in Georgia, there was a “very poor correlation” between the amount of savings and how much of the market a company was able to attract,” he said.

In general terms, market rates produced savings; 75% of the time, the median market rates were lower than projections of what the regulated rates would have been, he said.

It was possible to pay less, if customers did their homework, but also possible to pay more if they did not, he said.

Another finding in Georgia was that “choice hasn’t been huge” and many marketers in Georgia that entered the game dropped out. From 30 entrants, there are now 13 left offering 63 unique contract options, including variable and fixed-rate plans, he said.

the challenge, he said, for regulators, is how to find a balance in regulations to bring marketers into the game without being so stringent that you keep out “scrappers,” who ultimately make prices more competitive, or so lenient that you end up with a series of marketer bankruptcies. In designing the markets, he suggested regulators hang onto authorities so that assets can be picked up and are available after a bankruptcy.

Reflecting on federal restructuring from the mid to late 1990s, he said prices were lowered and price signals from the burner tip were felt almost immediately at the wellhead. The beneficiaries were large customers, he added. From 1983 to 1995, large industrials in Georgia saw their delivered gas prices cut by 39%, while residential customers had a 13% increase, he said.

— Maya Weber

ReneWABLes

Incorporating more renewables into power grid seen testing economics, reliabilityIntegrating increasing levels of renewable power into the nation’s transmission infrastructure presents economic and reliability challenges, state regulators were told last week.

During the National Association of Regulatory Utility Commissioners Committee on Electricity meeting in Austin, Texas, November 9, Nancy Lange, Minnesota Public Utilities Commission member, asked panelists to list the key reliability challenges of incorporating more renewables into the fuel mix.

David Boyd, Midcontinent Independent System Operator vice president for government and regulatory affairs, said the answer depends on the particular location and circumstances of a grid operator and market participant.

“In MISO, we benefit from diversity,” Boyd said. “We benefit from fuel-mix diversity, from geographic diversity, in that we can see the weather coming farther off, and from weather diversity, in that when it’s hot in the south, it’s likely to be not so hot in the north.”

Michael Nasi, an attorney in the environmental and legislative practice group of the Austin office of the Jackson Walker law firm, cited the first 11 days of this August as an example of the challenges facing the Electric Reliability Council of Texas, which has about 13,000 MW of wind generation.

During the record peaks of early August, only about 10% or less of that wind nameplate capacity was available, as demand hit a peak of 69,783 MW on August 10. The question, Nasi said, is “how do you keep that other 68,000 MW operating?”

Warren Lasher, ERCOT director of system planning, suggested that the high risk of price volatility in ERCOT, which has a systemwide offer cap of $9,000/MWh, may be encouraging retail electricity providers to develop creative ways to shave peak demand during scarcity conditions.

“As a result of our high systemwide offer caps, what we see is a lot of creativity on the retail side,” Lasher said.

Aakash Chandarana, Xcel Energy vice president for rates and regulatory affairs, said his firm has been able to reduce uncertainty by improving its wind forecasts, with help from the National Renewable Energy Laboratory.

“Wind forecasting error has precipitously dropped off over the past several years,” he said.

Chandarana, however, acknowledged that increasing reliance on renewables puts “more pressure on baseload units.”

For example, some retailers offer free nighttime and weekend power, he said, which shifts demand away from peak hours when scarcity conditions are more likely.

Todd Lucas, Southern Company general manager for bulk power operations, said grid operators need more time to analyze how to integrate more renewable power into the grid.

“We can deal with the technical issues … given the proper amount of time,” Lucas said. “It’s just that time and resources don’t seem to be in abundance.”

Lucas said the system is “asking units to do things they weren’t


15



designed to do,” such as ramp up and down on relatively short notice.“What we’ve got today is not going to work,” Lucas said. “We’re

going to have to do something different.”— Mark Watson

southeast looks to source more wind and solar power, lauds diversity in generationWind proponents, solar advocates and a top state regulator in the Southeast agreed earlier in the month that neither locally sited utility-scale solar projects nor wind power “imported” into the region from the Great Plains holds a clear advantage over the other, and that solar and imported wind actually complement each other and should both be pursued.

“I don’t think it’s an either/or,” Michael Skelly, founder and president of Clean Line Energy Partners, said when asked whether utilities in the Southeast will be more likely to opt for local solar power or imported wind power as they expand their renewables portfolios in preparation for Clean Power Plan compliance.

Great Plains wind power can be delivered into the region bounded by North Carolina, Florida, Louisiana and Arkansas at about 4 cents/kWh, slightly lower cost than large-scale solar power installed in the Southeast, Skelly said, but more solar power is typically delivered during peak demand periods in summertime afternoons.

There are pros and cons to both wind and solar for utilities in the Southeast, the Clean Line executive said, noting that “at certain penetration levels solar gets more difficult to integrate” in the grid. As a variable power source, “wind is less than perfect as well. But [with wind] you do get generation spread throughout the year,” and higher wind production at night can coincide with peak demand during winter nights.

Earlier this month, the Department of Energy released the final environmental impact statement for Clean Line’s first major project,

the 700-mile Plains & Eastern transmission project, a direct-current merchant line that by 2020 will be capable of efficiently moving up to 3,500 MW of wind power from the Oklahoma panhandle to near Memphis, Tennessee, plus 500 MW to Arkansas. From the line’s Memphis-area terminus, the wind power will run through utility-owned lines throughout the Southeast.

Skelly said Clean Line expects wind farm developers and utilities to lock up Plains & Eastern’s transmission capacity by the end of 2016, allowing construction to begin in 2017.

“diversity needs to rule the day,” Chuck Eaton, chairman of the Georgia Public Service Commission, said in an interview when asked whether Georgia Power and other utilities in the Southeast should focus their renewables efforts on large-scale solar projects built within the region or wind power imported from Oklahoma, Kansas and other states to the west.

Eaton, whose PSC has encouraged Georgia Power to add more than 800 MW of utility- and distribution-scale solar by the end of 2016, said that he is “not passionate about any particular type of generation. I’m agnostic on that. What I am passionate about is diversity. These are 20-, 30-, even 60-years decisions we’re making” when new capacity of any sort is added to the grid, he said, adding that installing a mix of generation types minimizes long-term risk.

At the Georgia PSC’s direction, Georgia Power in the past three years has issued requests for proposals to help select the lowest-cost solar projects. The utility has said that the average cost of the power to be provided from those projects is less than 6.5 cents/kWh, far less than it would have paid a few years earlier.

Sean Gallagher, vice president for state affairs for the Solar Energy Industries Association, said that solar power in the Southeast “is increasingly cost-effective. We’re seeing utilities procuring solar at less than what they’d pay for conventional generation.” He added that solar

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Source: Clean Line Energy Partners

PLAIN & EASTERN CLEAN LINE PROPOSED ROUTE

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prices continue to fall. “We’re already seeing examples of solar in Texas priced at 4 cents/kWh ... and we think we’ll see continued declines in solar costs in the Southeast for both utility-scale and rooftop.”

“The renewable energy market in the Southeast has room for both” wind and solar, said Keith Johnson, managing attorney at the Birmingham, Alabama, office of the Southern Environmental Law Center. “These energy sources can, in many instances, complement each other, and with the paucity of renewable energy in the Southeast, they can both occupy a place. We have seen this with utilities in Southern states. For example, Alabama Power has signed [power purchase agreements] for wind within the past several years, and they just recently had utility-scale solar projects approved [by state regulators] for several military installations.”

— Housley Carr

Rooftop solar creates benefits, brings new challenges to grid, regulators: nARuC panelIntegrating more solar power into US grids creates costs and benefits for system operators and regulators, and some costs may be hard to address, attendees of a National Association of Regulatory Utility Commissioners panel discussion were told last week.

During a panel discussion November 10 entitled “All Under One Roof,” Donna Nelson, Public Utility Commission of Texas chairwoman, said that during a recent visit to Australia, she learned that about 25% of Queensland’s homeowners have rooftop solar panels.

“It has made it really difficult for the grid operator to know what demand is going to be,” Nelson said.

Thomas Coleman, North American Electric Reliability Corporation director of reliability assessments, noted that the demand curve of California, which has a relatively high percentage of solar penetration, has a “duck” shape, with load falling at midday, when rooftop solar panels produce the most power, but then ramp up sharply near the end of the day, when solar panels are less productive.

“It’s exactly then that the grid is making up the deficit when the sun goes down,” Coleman said. “Who pays for all that?”

Nelson asked whether the panelists thought a larger charge for access to the grid might be appropriate for consumers with rooftop solar panels, as they are most dependent on the grid to meet peak load when their own systems are less productive, which implies that other non-solar-owning consumers are paying a disproportionately large share for grid maintenance.

nelson pointed out that rooftop solar owners tend to have higher incomes, which means lower-income consumers might be defraying some of the higher-income consumers’ grid reliability costs.

Charles Cichetti, founder of the Pacific Economics Group, a former Wisconsin Public Service Commission chairman and currently an economics professor at the University of Southern California, said such costs have not yet been proven and have not been sufficiently evaluated against the benefits rooftop solar can provide the grid.

“There are incredible benefits to renewable energy,” Cicchetti said. “There are environmental benefits, there are energy security benefits.”

Furthermore, the benefit of rooftop solar panels, near load, may reduce the need to build more transmission from utility-scale renewable resources, he said.

“To determine whether low-income customers are net losers, you have to compare it to the alternative, which is utility-owned renewable energy,” Cicchetti said.

Nicole Sitaraman, assistant people’s counsel for the District of Columbia’s Office of People’s Counsel, said that as the district ramped up its solar incentives, some staff expressed concern about cost-shifting, but found that solar penetration had not risen so much that its impact could be significant.

But she noted that low-income people tend to bear the brunt of pollution caused by fossil-fuel generators.

“If we are really concerned about the impacts on low-income people, then there needs to be concentrated efforts to enable them to participate in renewable energy,” Sitaraman said.

An audience member from North Carolina said her state’s solar incentives are growing the state’s rooftop solar capacity quickly, but she questioned whether society is benefiting as much as it should from such investments.

To maximize solar panel output for the individual, they should be oriented to the south, to catch light from morning to evening, she said.

“But it’s better for the overall grid if they’re facing west, rather than south, so they generate the most power during peak demand,” she said. “How do regulators or vendors convince a consumer to take less because then society gets more?”

Cicchetti said it would be best for the system to send a price signal that would encourage orienting solar panels in such a way that they maximize output during peak demand periods “and then let the consumer respond.”

On the subject of consumer protection, Nelson said she had heard radio commercials for solar power providers who claim their customers “never have to pay another utility bill.”

“How do commissioners address that issue, if they don’t have authority over rooftop solar?” Nelson asked.

Sitaraman suggested consumer education might be one way to approach the issue.

Jeremy Susac, director of government affairs for Lennar Corporation, a homebuilder with a rooftop solar program active in California, Colorado, Florida and Texas, said his organization adheres to Better Business Bureau standards to ensure consumers are protected, but said a state attorney general might also be the appropriate authority if an unscrupulous vendor engages in deceptive practices.

A representative of the Solar Energy Industries Association said her group recently established a code of ethics to which all members must adhere.

— Mark Watson

spot prices at the benchmark Henry Hub in Louisiana dipped below $2/MMBtu October 30 for the first time since April 2012.

Falling prices led EIA to lower its forecast for fourth-quarter Henry Hub spot prices to $2.34/MMBtu, 49 cents below its estimate in October. The agency also lowered its first-quarter 2016 estimate by 17

eIA posits gas storage could reach record 4 tcf, winter drawdrawn seen below average … from page 1



17



cents to $2.83/MMBtu.EIA said in its report that it expects the monthly average spot price

to remain below $3/MMBtu through June, and below $3.50/MMBtu through the end of 2016.

Henry Hub gas prices are projected to average $2.69/MMBtu for full-year 2015 and $3.00/MMBtu in 2016, it said.

“While natural gas prices are expected to rise next year, power plants are not expected to switch back to coal as a generating fuel

because gas prices will still be low compared to recent years,” Sieminski said.

The report asserted that gas spot prices below $3/MMBtu through mid-2016 would support “high consumption” of gas for electricity generation in both 2015 and 2016.

Gas demand from the power sector is expected to jump 16.8% in 2015 to 26.08 Bcf/d. Consumption of gas for electricity will then fall slightly in 2016 to 25.76 Bcf/d, although that level still is 15.4% higher than power sector demand seen in 2014, EIA projected.

While eIA sees power generation from both gas and coal declining in 2016, the agency said generation from hydropower and other renewables would be on the rise.

“Total utility-scale solar power generating capacity in the United States is expected to more than double between the end of 2014 and the end of next year,” Sieminski said, adding, “US wind power generating capacity is expected to increase by 14% next year.”

But the need for gas remains high. EIA raised its estimate for overall US gas demand in Q4 2015 by 660 MMcf/d to 78.65 Bcf/d. EIA’s Q1 2016 demand estimate also was raised by 660 MMcf/d to 94.08 Bcf/d in its report.

The agency said demand for US gas for 2015 is expected to average 76.29 Bcf/d — 90 MMcf/d above last month’s estimate — compared with 73.15 Bcf/d in 2014. It estimated full-year 2016 gas consumption at 76.79 Bcf/d, 410 MMcf/d above its estimate in October.

Demand will be outpaced by gas production in 2015 and 2016, EIA said. The agency predicted marketed gas production to average 79.61 Bcf/d in 2015, a 550 MMcf/d bump above its prior estimate. It put 2016 production at an average 81.2 Bcf/d, 620 MMcf/d above the previous estimate.

“Increases in drilling efficiency will continue to support growing natural gas production in the forecast despite low natural gas prices and declining rig activity,” the agency said.

“Most of the growth is expected to come from the Marcellus Shale, as the backlog of uncompleted wells is reduced and as new pipelines come online to deliver Marcellus natural gas to markets in the Northeast,” it added.

The report noted that marketed production for August was at a record 81.3 Bcf/d.

EIA raised its total marketed production estimate for the US in the Q4 2015 by 910 MMcf/d to 80.52 Bcf/d. The Q1 2016 production estimate also saw a 670 MMcf/d boost from the prior month’s projection to 80.86 Bcf/d.

— Jasmin Melvin

($/MMBtu)

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2016201520142013Kentucky said in a joint statement November 9 that “FERC’s evaluation of PURPA and its implementation will help identify potential administrative or legislative updates to ensure the appropriate role for PURPA in today’s electricity marketplace.”

Murkowski is chairman of the Senate Energy and Natural Resources Committee, while Upton heads the House Energy and

Lawmakers mull update of PuRPA, seek FeRC’s assistance in weighing need for reform … from page 1


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suPPLY & deMAnd

PJM resources significantly exceed winter load; forecast for mild weather hits peak load projectionThe PJM Interconnection’s total resources will exceed expected peak demand this winter by almost 46,000 MW, or about 35%, the independent system operator reported Thursday.

PJM expects to have more than 177,600 MW of electric capacity resources to handle forecast demand of more than 131,700 MW, which is about 8% less than last winter’s peak demand, which was almost 143,300 MW.

This coming winter’s expected mildness, in contrast with last winter’s extraordinarily frigid weather, accounts for most of the big drop in expected peak load, PJM spokeswoman Paula Dupont-Kidd said.

A winter weather procedure training document presented Thursday notes that the region can expect normal to above-normal temperatures this December through January, and precipitation may be above normal along PJM’s coastal regions and below normal in PJM’s western regions, especially in the Chicago area.

Another factor is a continuing trend among PJM’s electricity delivery companies in expecting decreased demand, Dupont-Kidd said.

Michael Kormos, PJM executive vice president and chief operations officer, in a prepared statement, said, “PJM has taken many steps to reinforce generator readiness and to continue to improve coordination with natural gas pipelines, a key source for a large portion of the generation fleet.”

In addition to training, PJM has been testing equipment and

Commerce Committee and Whitfield is at the helm of the House Energy and Commerce subcommittee on energy and power.

The three noted in the letter to FERC that they heard testimony earlier in the year while crafting comprehensive energy packages that brought the potential need for PURPA policy reform to their attention.

“One witness testified that his company is locked into a PURPA ‘must purchase’ contract at rates that are 43% higher than the market price — forcing customers to pay an incremental $1.1 billion over the next 10 years for electricity that is not even needed,” the letter said.

Further, they noted the substantial changes the electricity markets have experienced in the nearly 40 years since the law was enacted, including the emergence of competitive markets and open access policies that have broadened opportunities for new generation sources like renewable energy.

the lawmakers acknowledged that PuRPA was amended in 2005 to relieve utilities of the mandatory purchase requirement when generators have access to competitive wholesale markets.

But since then, “electricity markets have undergone an even more significant transformation,” they said, citing abundant and cheap natural gas supplies as well as environmental regulations that have reduced coal plants’ share of the generation mix along with lower renewable energy technology costs, federal tax credits and state renewable energy mandates that have opened more doors to renewable energy developers.

“In light of these developments, we encourage the commission to take a comprehensive look at PURPA and its regulations implementing section 210 through a discussion with … commission-regulated and non-regulated electric utilities, owners and operators of qualifying facilities …, competitive electricity suppliers, electricity consumers, trade associations, … state regulators” and other interested stakeholders, the letter said.

Among the issues the lawmakers suggested the technical conference should address were the methods states use to determine avoided cost rates; potential abuses of the one-mile rule aimed at weeding out large generators with dispersed facilities from qualifying as small power production facilities under PURPA; and whether voluntary energy imbalance markets should be viewed as comparable markets for purposes of exempting participants from mandatory purchase obligations.

The lawmakers also sought clarity on whether imposing mandatory purchase obligations was “appropriate” when a state regulatory agency finds that capacity from a qualifying facility is not needed for a utility to meet load, or when states mandate integrated resource planning with competitive procurement processes that allow qualifying facilities to compete for identified resource needs.

Reforms to PuRPA were contemplated by senators earlier in the year as part of a broad energy bill, but those provisions lacked support from Democrats and were left out of the measure that cleared the Senate energy committee to preserve the bipartisan nature of the legislation.

Democrats argued that the burden on utility customers from PURPA projects where there was no need for additional power was being overblown given the states’ abilities to tailor their own avoided cost rules, a legislative aide said.

Further, many Democrats on the committee thought it puzzling that anyone would try to equate EIMs, which are often limited in scope with a thin volume of trading, with the scale of a wholesale market that Congress said would allow a utility to get out of a mandatory purchase requirement, the aide said.

The ability of PURPA to ensure some measure of competition in regulated states with monopoly utilities and bring more renewable energy to the power grid were two priorities that many Democrats still saw a need for, the aide said.

— Jasmin Melvin

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procedures, working to ensure adequate fuel supplies and coordinating with the natural gas industry, a PJM press release states. From November through March, PJM has been having daily phone calls with various natural gas pipelines to discuss generation and transmission outages.

This winter, the locational marginal price cap is expected to rise from $1,000/MWh to $2,000/MWh, if FERC approves, as expected in mid-December, the training document states. Generators can recover costs over $2,000/MWh after review on a case-by-case basis.

Another change this winter allows PJM to recall generators on maintenance outage with 72-hour notice.

— Mark Watson

efficiency restrains new england demand growth; renewables gaining share of generation mixAggressive energy efficiency efforts and new distributed generation capacity — most of it solar — are putting a lid on growth in peak demand and electric use in New England, ISO New England said in its newly released 2015 Regional System Plan.

“The regional energy landscape is undergoing a dramatic change in terms of the composition of generation, transmission, demand resources, and wholesale markets,” the ISO said in RSP15, which provides the foundation for long-term power planning in New England.

“This evolution poses a series of challenges the ISO is addressing through a collaborative effort of the New England states and market participants, as well as neighboring regions,” the plan said.

According to the plan, the annual growth rate in peak summer demand in the six-state region will average 0.6%, and annual use of electricity will remain unchanged through the 10-year period. ISO New England’s winter peak will actually decline over the period, albeit only slightly: by an estimated 0.1% per year.

Without expanded energy efficiency and new solar capacity, annual energy consumption would grow by 1% per year, and peak demand would grow by 1.3%, ISO New England said.

Solar capacity in New England topped 900 MW at year-end 2014, RSP15 said, and is expected to exceed 2,000 MW by 2019 and approach 2,500 MW by 2024. Most of the existing and planned solar capacity is in Massachusetts, the region’s most populous state; 667 MW of solar capacity was operational in Massachusetts as of the end of last year, and by 2024 solar capacity in the state is expected to rise to 1,405 MW.

Many of the roughly 4,000 MW of proposed wind projects would be built “in remote areas of the region where wind conditions are good, but the electrical system is weak,” ISO New England said.

ISO New England has been working with utilities and other stakeholders to improve New England’s transmission network, and key elements of one of the region’s larger transmission efforts — the Maine Power Reliability Program — were completed earlier this year.

the new, variable-output renewable capacity being developed in New England will require the support of new gas-fired projects “to provide operating reserves as well as other ancillary services, such as regulation and ramping,” the ISO said. Studies have shown that the best places for adding gas-fired capacity — from both economic and system-reliability perspectives — are Rhode Island and eastern Massachusetts.

Generation developers already have been responding. Invenergy has said it plans to build a 900 MW gas-fired combined-cycle plant in Burrillville, Rhode Island; Johnston Clean Power is planning a 225 MW gas-fired combined-cycle plant in Johnston, Rhode Island; and Emera Energy has said it will increase the output of its 265 MW gas-fired combined-cycle plant in Tiverton, Rhode Island, by 22 MW and improve its heat rate, thereby boosting its competitiveness.

That new gas-fired capacity could exacerbate New England’s already significant wintertime gas-supply problems, but gas pipeline companies continue to work on projects that would increase pipeline capacity into and through the region.

Spectra Energy said November 9 that earlier this month its Algonquin Gas Transmission pipeline unit filed a request with FERC to initiate the prefiling review process for Algonquin’s proposed Access Northeast project.

Bill Yardley, president of US transmission and storage at Spectra, said in a statement, “Access Northeast will provide true ‘last-mile’ supply access for 5,000 MW of generation from the approximately 12,000 MW of gas-fired generation currently attached — or expected to be attached over the next five years — to Algonquin and [the] Maritimes & Northeast pipeline systems.”

— Housley Carr

As us production continues to displace exports, Canada looks to broaden gas customer baseFor years Canada has reigned as the largest exporter of natural gas to the US, but as those trade volumes continue to shrink in the wake of the US shale boom, the US’s northern neighbor is expanding its horizons.

In the wake of the new economic reality, Canada is developing plans to diversify its trading partners, especially with new Asian markets, according to an international energy study on Canada released last week by the Energy Information Administration.

Canada is the fourth-largest exporter of gas, trailing only Russia, Qatar and Norway, according to the EIA report. It’s also the fifth largest producer. Currently, all gas exports ship to the US via pipelines, but like the US, Canadian producers hope to begin exporting LNG to markets outside of North America.

Exports to the US have dropped dramatically in recent years. In

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2007, annual US imports of Canadian gas totaled 3.8 Tcf. By 2014, imports had plunged to 2.6 Tcf.

At the same time, US exports to Canada grew to 770 Bcf last year, according to the EIA. And as US gas production continues to grow, further lowering a need for imports, the import/export gap between the two nations should narrow even further.

Much of the decline has to do with rampant production in the Northeast US over the past few years, which has been quite noticeable at the Niagara interconnect with Tennessee Gas Pipeline and TransCanada Pipeline.

Historically, TransCanada pushed gas from eastern Canada into the Northeast US. In 2007, Canada exported more than 800 MMcf/d on this line, according to Platts Analytics. The roles reversed after 2012 when US gas started moving north at the Niagara interconnect. So far this year, US imports to Canada at the interconnect average 440 MMcf/d, representing a drastic switch.

And US exports to Canada at the Niagara interconnect are expected to continue growing. In facts, they are expected to more than double within a year. TransCanada announced plans to expand the interconnect to a full 1 Bcf/d of flow capacity from the US into East Canada by late 2016. On Wednesday, a representative from TransCanada said the company has contracts in place to flow this entire amount when it comes online.

“The most dramatic story is how US production has increased so much in the Lower 48,” Canadian Gas Association CEO Timothy Egan said in an interview Wednesday. “The most prolific production is coming in the Northeastern US from the Marcellus and increasingly from the Utica. It’s a very competitive pricing region for gas. People are

going to continue to buy gas as cheaply as possible, and transportation cost plays a big role.

“It’s cheaper for the Northeast to buy domestic gas rather than imports from East Canada. We don’t see this changing any time soon.”

This phenomenon is also demonstrated in the Midwest where Canadian imports are being displaced by cheaper Northeast US gas. Demand for western Canadian gas in the Midwest is expected to decline from about 3.4 Bcf/d to a total of 2.6 Bcf/d by 2020 as the price spread shrinks between AECO and Chicago, according to Platts Analytics.

the only market where Canadian exports to the US appear safe is on the West Coast, where there is little competition.

Consequently, 28 Canadian companies have applied for 35 LNG export licenses. As of September, 12 of those applications had received approval by Canada’s National Energy Board. Most of those are slated for development in British Columbia, to take advantage of Asian markets.

The proposed Kitimat LNG facility in British Columbia would be able to process 1.3 Bcf/d of LNG coming from British Columbia shale plays. Another major project, LNG Canada, a partnership between Shell, Mitsubishi, KoGas and PetroChina, would include a two-train, 1.6-Bcf/d export terminal. Located near Kitimat, it is slated for completion in 2020. However, a final investment decision has not been made on either of these projects.

“There are currently 68 Bcf/d of proposed LNG export projects in Canada,” Egan said. “I don’t think anyone believes they will all be completed. But even if just a couple of them are, it will help bring Canada back to its historic export levels.

“But that market is also very competitive as the spreads between the world’s three primary gas pricing regions – North America, Europe and Asia – come closer together.”

Still, Egan remains optimistic.“As energy prices remain cheap, it will help industry and the

economy grow, which should increase demand eventually.”— Brandon Evans, Richard Frey

hedges key to short-term merchant profitability as ties eroding between economy, demand: s&PCredit rating agency Standard and Poor’s believes merchant power generators will have to rely on their hedging strategies and higher capacity payments to ensure profitability until there is an increase in natural gas prices.

S&P, like Platts, is owned by McGraw Hill Financial. It said in a report released November 11 that it anticipates depressed natural gas prices to continue into next year. It said, as well, that while the US economy is showing signs of improving, energy efficiency and demand response efforts could weaken power demand.

Despite this naysaying, and the “several substantial risks that are looming,” S&P said its outlook for the merchant sector and its credit quality for the rest of 2015 and for 2016 is “stable in general” since it believes the merchant sector’s earnings potential to be “more or less stable.”

It noted that both investment-grade and speculative-grade

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merchant firms have been able to tap the debt and equity markets this year to finance acquisitions, growth projects and to refinance coming debt maturities.

S&P noted, however, that borrowing rates have increased over time for some smaller, new issuers, “leading them to be more selective regarding accessing the debt capital markets.”

The ratings agency said that when it looks at merchant power generation it focuses mainly on the economic indicators most correlated with higher electricity consumption.

“Power demand is driven by demand for services needed in homes and places of work,” S&P said. “In the long term, a region’s economic growth — the GDP or gross metropolitan product — is a key driver of overall [power] demand.”

The credit analysts said, however, that the relationship between a region’s economic growth and power demand “has weakened considerably” over the past several years, and they expect the ties to continue to erode as efficiency and demand reduction programs take hold.

With power prices already low due to low natural gas prices, any impacts on demand could upset “an already tenuous equilibrium.”

A protracted recession, which the credit rating agency said “is not out of the question,” would hurt merchant generators. “Power prices are roughly the product of fuel prices and market heat rates, which rise and decline with tightening or widening demand/supply dynamics. As demand declines, fuel prices and market heat rates both decline, amplifying the effect on merchant power generators’ gross margins.”

With weak demand and continued depressed gas prices, and thus low power prices, the only way to stabilize a company’s earnings is through hedging.

S&P acknowledges, though, that hedging at a time when forward prices are “comparatively weak” has disadvantages. It says in its report that attaining profitability via hedging strategies “is not likely to be indefinite without an increase in demand and gas prices.”

S&P concludes by saying that its current outlook on the merchant sector is relatively short-term, extending from the latter part of 2015 through much of 2016 when it would look at the sector’s prospects stretched out over the next two to three years.

— Jeffrey Ryser

PIPeLIne RAtes

Medallion seeks approval for rate structure on crude pipe expansions in West texasMedallion Pipeline recently asked FERC to approve the rate structure for the second major set of expansions to extend the geographic reach and boost capacity on its Wolfcamp Connector crude oil pipeline system in Texas.

The Wolfcamp Connector system includes 200 miles of pipeline in West Texas with a capacity of about 95,000 b/d.

The proposed Santa Rita Lateral would add 55 miles of pipeline capable of shipping 65,000 b/d into central and southern Reagan County, Texas. The proposed Reagan expansion would add 30,000 b/d of capacity to Medallion’s mainline between northern Reagan County and Garden City in Glasscock County.

Medallion on November 6 filed a petition for declaratory order for the two expansion projects (OR16-4). The company sought the commission’s OK for its open season procedures, a 90% capacity set-aside for firm committed shippers, and the rate structure for each class of service.

The pipeline also asked for approval for various other provisions, including its annual rate adjustments, contract extension rights, a “ramp-up” option for firm shippers, and an option for firm shippers to add a new destination point subject to a potential surcharge.

Medallion had discussions with many potential shippers during the open season for the expansions.

“Given the substantial downturn in crude oil commodity prices, however, the majority of these prospective shippers were not in a position to undertake the long-term financial commitment necessary to enter into a transportation service agreement,” the petition said.

At the close of the open season, Medallion received only one binding commitment, from an affiliate that signed up for 90% of the capacity on the two expansion projects.

Medallion plans to put the expansion projects into service in the fourth quarter of 2015.

— Kate Winston

LIQueFIed nAtuRAL GAs

Final eIs for Magnolia LnG finds impacts can be trimmed to less-than-significant levelsFERC’s final environmental review of the Magnolia LNG export facility and the associated pipeline in Louisiana has found the projects would result in adverse impacts to wetlands, vegetation and land use. Yet with the applicant’s proposed and FERC’s recommended mitigation measures, the commission staff found those harms would be cut to “less-than-significant” levels.

FERC staff Friday released the final environmental impact statement for the Magnolia Liquefied Natural Gas and the Kinder Morgan Lake Charles Expansion Project in Louisiana (CP14-347, CP14-511).

The project envisions a natural gas liquefaction and export facility

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in the Port of Lake Charles, Louisiana, to be built by Magnolia LNG, a unit of Australia’s Liquefied Natural Gas. The Lake Charles Expansion Project, proposed by Kinder Morgan Louisiana Pipeline, would reconfigure Kinder Morgan’s existing pipeline system to deliver gas to the LNG terminal site.

Construction of the projects would affect 204.8 acres during construction. Of that 144.6 acres would be needed for operation and 60.2 acres would be allowed to “revert to pre-construction land use,” the EIS said. The terminal would result in the permanent loss of about 15 acres of wetlands, the EIS found.

In deciding that the impacts could be sufficiently reduced, FERC said it based that decision on the fact that 99% of the terminal project would be on land previously disturbed by commercial or industrial facilities, and that the Kinder pipeline would occur within and near adjacent facilities.

It also cited Magnolia’s proposal for beneficial use of dredge material to recreate historic emergent wetlands, and ongoing efforts to comply with the Endangered Species Act during construction, among other measures.

To add to that, FERC staff recommended a host of environmental conditions: 27 mitigation measures to reduce impacts from construction and operation of the facility; 83 measures related to engineering, vulnerability and detailed design of the terminal; and four steps related to inspection and notifications throughout the life-cycle of the LNG terminal.

To minimize impacts on aquatic resources caused by increased turbidity and suspended solids, the EIS notes that Magnolia would implement a dredging water quality plan. When other mitigation measures are considered, the EIS suggests the project would result in a net increase in habitat available for aquatic resources and that construction-related impacts on those resources would be temporary and minor.

— Maya Weber

Cuomo vetoes Port Ambrose LnG import project, citing security, threats to wind projectNew York Governor Andrew Cuomo has vetoed Liberty Natural Gas’ proposal for an LNG import project offshore of New York City, saying the security and economic risks outweighed potential benefits and raised concerns about negative impacts to off-shore wind development.

The company had planned the project to meet growing demand for gas in capacity-constrained areas in New York City and Long Island.

While Liberty Natural Gas recently welcomed an environmental impact statement released by the US Maritime administration and Coast Guard, the project also required approval from Cuomo and New Jersey Governor Chris Christie under the Deepwater Port Act.

It faced substantial opposition from environmental and civic groups, more than 20 of which had delivered a letter to Cuomo in recent days pressing him for a veto.

“My administration carefully reviewed this project from all angles, and we have determined that the security and economic risks far outweigh any potential benefits,” Cuomo said in a statement Thursday.

“Superstorm Sandy taught us how quickly things can go from bad to worse when major infrastructure fails – and the potential for disaster with this project during extreme weather or amid other security risks is simply unacceptable. Port Ambrose would also hinder the local maritime economy in a way that negatively impacts businesses throughout Long Island, and that is simply unacceptable. This is a common-sense decision, because vetoing this project is in the best interests of New Yorkers.”

The Maritime Administration and Coast Guard recently released a 4,000-page final EIS as part of the National Environmental Policy Act review of the deepwater project.

Located 16 miles off of Jones Beach, New York, Port Ambrose would consist of two buoys submerged in deep water and connected to a subsea pipeline system feeding into the Transcontinental Gas Pipe Line Lower New York Bay Lateral serving Long Island and New York City. The subsea pipeline would be designed to receive regasified LNG mostly brought by carriers with regasification equipment on board.

Most deliveries would occur during peak demand in winter and summer, according to the company. Each delivery would be capable of transferring about 400,000 Mcf/d of gas into a new 18.8 nautical mile, 26-inch-diameter subsea pipeline system feeding into the Transcontinental Gas Pipe Line Lower New York Bay Lateral serving Long Island and New York City.

Company officials could not immediately be reached for comment on Cuomo’s decision.

Opponents of the project have raised concerns about environment and wildlife impacts, threats from terrorism and interference with a wind project planned for the same area.

Following the EIS, the company’s CEO expressed confidence that material concerns flagged by both governors had substantially been addressed in the document. In his summation, the EIS found “no significant” impact on the environment, addressed security in detail, and found a 1-4% overlap with a nearby wind project, making it unlikely to impede that development.

But in Cuomo’s November 12 letter to the Maritime Administration, the governor said “this project presents risks to New York’s security and economy while negatively impacting a critical renewable energy project. Taken together, these unmitigated concerns cumulatively outweigh the project’s intermittent impact on the natural gas supply.”

He said the state’s own assessment found that the project would make 20% of the wind project location unavailable, undermining New York’s commitment to reducing fossil fuel emissions to mitigate impacts of climate change.

Cuomo also wrote that the eIs downplays potential security concerns of the location between two main shipping channels in and out of New York by stating that safety requirements would minimize such risks.

“The potential hazads they present are unacceptable. Furthermore, the low risk assessment may be overstated given the Council on Foreign Reglations’ warnings that terrorists have considered targeting LNG terminals,” he wrote.

He also cited potential disruption of commercial navigation and maritime activities as reasons for his decision.

— Maya Weber



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Commission argues against ‘speculative’ environmental review in Corpus Christi LnG caseFERC Thursday defended its decision to certify construction of the Corpus Christi LNG terminal in a key court case in which the Sierra Club asserted the commission flouted National Environmental Policy Act requirements to consider indirect and cumulative environmental impacts.

In a brief filed before the DC Circuit Court of Appeals, the commission laid out its argument that the Sierra Club would have it consider ‘speculative’ impacts beyond what is required by NEPA (Sierra Club v. FERC, 15-1133).

The filing came a day before oral arguments were set in two other cases filed by environmentalists raising similar issues involving FERC decisions to approve siting of LNG export facilities — for the Freeport LNG and Sabine Pass Liquefaction projects in Texas and Louisiana, respectively.

The Corpus Christi case involves FERC’s decision to approve Cheniere’s import-export project in Texas, capable of liquefying about 700 MMcf/d of natural gas for export and vaporizing about 200 MMcf/d of LNG, along with an associated 23-mile bidirectional pipeline that connects with five existing interstate pipelines (CP12-507;CP12-508).

Sierra Club, in a brief filed September 28, said “uncontroverted evidence” showed the projects would boost natural gas production and make more polluting fuels, like coal, more likely to be used in power production. Studies on LNG exports, such as those by the Energy Information Administration and private consultants like ICF International, would enable FERC to forecast the amount, timing and location of induced production, Sierra Club said.

FERC also fell short of the NEPA requirement to rigorously explore alternatives, in this case to substitute electric motors for proposed natural gas turbines at the terminal, the environmentalists argued. And it failed to fully assess the projects’ impacts on greenhouse gas emissions, for instance, by examining their bearing on emission reduction targets or examining the “social costs” spelled out by EPA, Sierra Club said.

In its reply brief, FERC reminded the court that agency actions pursuant to NEPA are entitled to a high degree of deference, and it restated many conclusions in its order backing the project and declining rehearing.

the order backing the project found environmental impacts would be sufficiently minimized by mitigation measures, and imposed 104 environmental conditions. It also found that environmental effects associated with induced gas production are “neither causally related nor reasonably foreseeable.”

Given that the project amounts to less than 3% of US gas production and an even smaller share of the global market, FERC has “‘no way of predicting where or how’ the exported gas would be consumed ‘much less what alternative fuel sources it may replace,’” the commission argued in its brief Thursday.

A modeling system created by the EIA is not imeant for predicting or analyzing the environmental impacts of specific infrastructure projects, FERC said.

Addressing Sierra Club’s assertions that LNG exports would boost domestic coal use, the commission said the environmentalists would require the commission to engage in “speculation upon speculation.” Use of coal for power is likely to be more swayed by other factors such as EPA standards for power plants, fuel prices and steps to curb

greenhouse gas emissions, FERC argued.To make the case that there is legally no causal link between the

project approval and increased gas production, FERC said it has no jurisdiction over natural gas production, nor exports of the commodity. “For that reason, the commission’s decision also would not be the cause, for NEPA purposes, of any LNG exports,” FERC argued.

And because the pipelines interconnecting with the project span from Texas to Illinois to Pennsylvania, “the location and extent of potential subsequent production activity are unknown and too speculative” to inform the NEPA analysis, the commission said.

It also rejected Sierra Club’s assertion that FERC needed to analyze cumulative impacts of all other LNG export projects that have received conditional export authorization by the Department of Energy. FERC’s review was consistent with case law limiting the scope of an agency’s cumulative impact analysis to other projects in the same area impacted by the project at issue, the commission said.

On a separate point, the commission said it had reasonably rejected an alternative to use electric motors to drive compressors on the liquefaction train, citing environmental and design challenges supporting the view that the option was not “environmentally preferable.”

It also said it had adequately weighed the project’s greenhouse gas emissions, but found there was “no standard method”to gauge the impacts on the physical environment. Sierra Club had argued FERC could have looked at the social cost of carbon developed by EPA to monetize climate change impacts or measurements against greenhouse gas emission targets.

But FERC countered that the EPA social cost tool was developed for cost benefit analysis informing policy decisions and not fit for assessing impacts of a specific infrastructure project.

— Maya Weber

eneRGY PROJeCts

Pennsylvania task force floats plan to cope with gas pipeline boom, weighs new siting authorityA task force led by the Pennsylvania Department of Environmental Protection has released a draft report with 184 recommendations to ensure that the upcoming boom in natural gas pipeline construction in the state is efficient, safe and environmentally friendly.

Some of the recommendations would have far-reaching impacts if adopted by the state, for example, by giving state agencies authority to site intrastate pipelines and write safety rules that are more stringent than federal regulations.

“This is an important first milestone in developing the framework to help guide responsible pipeline development in Pennsylvania,” PDEP Secretary John Quigley said in a statement November 10.

Pennsylvania already has more than 12,000 miles of large-diameter oil and gas pipelines in the ground, and the miles gas gathering lines alone will at least quadruple by 2030, according to the draft report.

“The footprint of just that expansion is larger than the cumulative area impacted by all other Marcellus gas infrastructure combined, and could exceed 300,000 acres, or 1% of the state’s land area,” the draft report said.


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Pennsylvania Governor Tom Wolf in July appointed the members of the task force, which includes representatives from state agencies, federal and local governments, the pipeline and natural gas industries and environmental organizations. The group was tasked with developing policies and guidelines to assist in gas pipeline planning, permitting and construction.

Since no single federal or state agency is responsible for pipeline permitting, projects do not necessarily minimize impacts to the environment, landowners and communities along the way, the draft report noted. “This lack of smart planning can lead to individual decisions accumulating into a much broader and longer impact on the citizens and the lands of a community, county or watershed,” the report said.

While FERC permits interstate natural gas pipelines, Pennsylvania is one of two states that do not regulate the siting of intrastate transmission pipelines, according to the report. State and federal agencies also oversee environmental permits and safety rules for gas pipelines.

the draft report made recommendations on a wide range of issues, including environmental protection, siting and routing, pipeline safety and emergency preparedness, local and county government involvement, public participation, and workforce and economic development.

A number of the recommendations could create sweeping changes if they are adopted by the state. For example, the draft report recommended creating a stakeholder task force to study creating a new regulatory agency, or empowering an existing agency, to review and approve siting and routing of intrastate gas transmission lines. Such a change would require legislative authorization, the document noted.

The draft report also floated the idea of repealing the state’s prohibition on writing state pipeline safety rules that are more stringent than federal regulations. But “overturning this may be controversial from an industry perspective,” the task force noted.

One safety issue that the state may wish to act on is creating an integrity management program to assess the safety risks of all existing and new gathering lines, the draft report said.

State and local agencies should also use a landscape approach for planning and siting rights-of-way corridors, the draft report said. This approach would identify areas that are inappropriate for pipelines and maximize the use of existing corridors, including roadways.

But in some cases, FERC regulations for interstate pipes work against this type of landscape approach, the task force noted. FERC rules mandate companies build to subscribed capacities, versus anticipated capacities, which may lead to development of additional corridors, the draft report said.

FeRC also evaluates the merits of individual looping projects instead of the cumulative impact of the entire corridor, the task force said. “This allows companies to submit limited proposals and request additional segments as needed, which eliminates the opportunity to evaluate the entire corridor using a landscape approach.”

The environmental protection section was by far the most extensive, including 69 recommendations touching on erosion, water quality, air emissions, and wetland and forest protection. Recommendations include; locating pipelines outside of 100-year floodways, minimizing methane emissions, requiring shutoff valves for liquid product pipelines, and implementing wetland banking and mitigation measures.

The draft report also suggests that Pennsylvania support the use of natural gas for compliance with the EPA’s Clean Power Plan to cut

greenhouse gas emissions from existing power plants.“Given the economic position that Pennsylvania holds in its global

reserve of natural gas, and the opportunities to reduce carbon emissions in the power sector by shifting from coal to natural gas and reducing industrial demand through combined heat and power to comply with the CPP, we strongly recommend consideration of these specific opportunities in Pennsylvania’s solution to reduce carbon,” the draft report said.

PDEP is accepting comments on the draft report until December 14.— Kate Winston

Clark urges state regulators to defend independent regulatory model from attackAs a panel of regulators and industry officials discussed opportunities and challenges posed by convergence of utility sectors, FERC Commissioner Tony Clark had two pieces of advice.

He urged regulators to speak up for the independent commission model for reviewing infrastructure development, and suggested they quickly address subsidies that create inefficiencies in deregulated markets. Clark was speaking November 10 on a panel at the National Association of Regulatory Utility Commissioners annual meeting in Austin, Texas, last week.

He called out the long delays in the Keystone XL pipeline review for particular criticism, saying, “the idea of having linear infrastructure sit around as a matter of politics and not be decided for seven years … is not how the industries that we deal with can move forward,” he said.

All of the sectors being discussed by the panel — electric and gas, water and telecommunications — are infrastructure-dependent, involve large investments and usually have opposition groups that don’t like the projects, he said.

“Exactly how you do not want infrastructure development to happen is how the Keystone XL permitting process went through at the State Department,” Clark said.

“The value that … utility commissions bring, that the independent regulatory model brings, is being able to apply the rule of law through a known and knowable process and then make a decision based on the record. That benefits consumers, ultimately. That model is under attack,” he said.

The regulatory commissioners “have to be able to explain to consumers why that process at the end of the day is a preferable one,” he concluded.

speaking to reporters on the sidelines of the conference, Clark said he believed it was unlikely that the Obama administration’s decision November 6 to reject the Keystone pipeline application had implications for the FERC permitting process under the Natural Gas Act.

That process sets up FERC as an independent regulatory body that acts in a “much more judicial way,” — unlike the State Department process which he argued became enmeshed in presidential and interest group politics.

While groups opposing the natural gas pipelines would like to apply the success blocking Keystone to the interstate gas pipeline process, Clark said, there is a large body of case law and regulatory precedent, relying on the rule of law as opposed to a more political process, that “probably mitigate the chance that you’d have a Keystone-like debacle” affecting the Natural Gas Act.


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Clark also spoke to the conferees about how his experience in telecommunication regulation as a state regulator could apply to regulators overseeing shifts to markets in other sectors. “All sorts of implicit subsidies and cross subsidies,” that existed under monopolies no longer made economic sense, he said. “As soon as the outer wall cracked, we began to have all sorts of competition.”

The earlier state regulators can identify inefficiencies from subsidies, before vested interests can use them for arbitrage opportunities, the better off they will be, he said.

Susan Story, CEO of American Water, also on the panel, detailed multiple ways in which the various utility services faced overlapping challenges, such as replacing infrastructure and moving supplies, and she cited multiple examples of interdependencies.

she noted for instance that 25% of water treated is lost due to leaks, that thermoelectric plants, such as coal, nuclear or gas-fired plants, remove every day over 160 billion gallons of water for cooling, and that 13% of primary energy consumption is used for water.

The resources are “so interconnected you can’t separate the two,” she said.

In the case of cybersecurity, she said it is not only a matter of someone taking down the grid with the result of contaminated water but also protecting customer information.

In the event of a terrorist attack or electromagnetic pulse event that takes down the grid for more than a month, what would cause confusion and evacuation has been identified to be water and sanitation, she said. Her company has been coordinating with PJM Interconnection and the departments of Defense and Homeland Security on that issue.

Among convergence opportunities she cited was the possibility for taking credit under the Clean Power Plan for water efficiencies that translate into energy savings.

Panelists also described risks, in addition to benefits, associated with collocating rights of ways, and pointed to efficiencies possible by cooperating on smart metering, for instance.

Bob Nelson, president of the National Association of State Utility Consumer Advocates, sought to “flash a little bit of a yellow light” to caution regulators to protect consumers, even as the regulators are well-placed to spearhead efforts at convergence among the sectors.

The emphasis when talking about these goals is often on sustainability and resilience, he said, adding that those goals while important are “somewhat at odds with the broad consumer expectation of affordability.”

Commissions where necessary should play the role of skeptic, he said, and put proposals to the test before committing captive customers to pay for new programs.

— Maya Weber

Low commodity prices pause demicks Lake natural gas pipeline project in north dakotaWBI Energy Transmission on Thursday asked FERC to suspend the early environmental review for its Demicks Lake Pipeline Project in North Dakota because the natural gas plant associated with the project is now in limbo due to low commodity prices.

The 22-mile gas pipeline (PF15-24) was slated to run from ONEOK Rockies Midstream’s proposed Demicks Lake processing plant in

Keene, North Dakota, to Northern Border Pipeline’s mainline near Watford City, North Dakota. FERC had planned to conduct an environmental assessment for the project (IF, 3 Aug, 19).

ONEOK, however, recently told WBI Energy that it had suspended development of the Demicks Lake gas plant, leading WBI Energy to put its activities on hold for the pipeline. ONEOK has agreed to compensate WBI Energy for the cost of the suspension, according to the FERC filing.

“Keeping the prefiling docket open until September 30, 2016, will allow ONEOK to evaluate the change in the market regarding oil prices and drilling activity in the Bakken to determine whether to continue the suspension of the project or not,” the filing said.

— Kate Winston

Penneast overstating jobs potential of pipeline, environmentalist-backed study saysPennEast Pipeline overstated the amount of jobs that would be created through construction of the pipeline by two-thirds or more, according to an environmentalist-commissioned study submitted to federal regulators on November 6.

“Clearly the PennEast information can’t be trusted,” said Tom Gilbert, a campaign director at the New Jersey Conservation Foundation, the group that sponsored the study.

“The erroneous jobs claims made by PennEast hardly justify the construction of this massive pipeline that would damage more than 4,000 acres of preserved open space and farmland, impact numerous high-quality streams and wetlands, and take private property from homeowners,” Gilbert said in a statement.

The study is the latest salvo from advocates who have grown increasingly vocal about their opposition to the environmental, health and community impacts of pipeline projects.

The PennEast project is a 114-mile, 36-inch-diameter pipeline in Pennsylvania and New Jersey that will deliver up to 1.1 million Dt/d of gas from the Marcellus in eastern Pennsylvania to markets in New Jersey, New York, Pennsylvania and surrounding states.

In its September 24 application (CP15-558) with FERC, PennEast estimated that the project’s total economic impact would support 12,160 jobs and $740 million in wages during the design and construction phases.

PennEast’s economic impact analysis was prepared by Econsult Solutions and Drexel University School of Economics.

Meanwhile, the new environmentalist-commissioned study, conducted by The Goodman Group, said PennEast’s number overestimates the amount of offsite jobs the pipeline will create in supporting industries.

“Further, it should be noted that these jobs are very short-term in nature … with activity and jobs concentrated into only six months (early January-early July 2017).”

Other comparable gas pipelines in the Northeast assumed far fewer jobs would be created per project dollar, the study said. “TGG’s review of employment impact studies for other comparable gas pipelines in the Northeast US shows that the PennEast analysis multiplier (10.7 jobs per $1 million project cost for all workers) is an outlier.”

Even if PennEast’s job estimates were realistic, “the employment impacts from the project are tiny in the context of the New Jersey and Pennsylvania state economies (less than 0.1% of total New Jersey jobs).”



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But PennEast spokeswoman Patricia Kornick said the foundation’s study does not change the factual findings of PennEast’s study.

“The jobs benefit is important, though most significant are the cost savings and increased reliability New Jersey and eastern Pennsylvania consumers will receive through the PennEast Pipeline,” Kornick said.

“The fact that the PennEast Pipeline will support approximately 12,000 jobs simply is an additional benefit to a critical infrastructure project that will deliver a safe, environmentally preferred and locally produced energy option for area consumers,” she said.

— Kate Winston

to keep pace with in-service schedule, Rover seeks swifter FeRC approvalIn an attempt to speed up the construction process, Rover Pipeline last week asked FERC to expedite the approval process for its proposed 700-plus-mile project.

Energy Transfer Partners, the project’s developer, hopes to begin construction on Rover no later than June or July. Developers say this is necessary in order for the line to go in-service to Defiance County, Ohio, by January 2017 and extend to Vector Pipeline by the middle of that year.

According to Rover’s original filing with FERC in February, the pipeline will deliver 750 MMcf/d to Panhandle Eastern Pipeline where volumes can then be used for backhaul on Trunkline Gas to move south. Additionally, it will be capable of delivering up to 1.7 Bcf/d to ANR Pipeline and up to 1.3 Bcf/d to a proposed interconnect with Vector, which is currently contracted for 900 MMcf/d.

Eventually, Rover’s capacity will reach 3.25 Bcf/d, providing a huge bump in takeaway capacity from the prolific Marcellus and Utica shales. The pipeline, which will also include four mainline compressor stations, six supply lateral compressor stations and other

infrastructure, will allow Northeast gas to reach markets in the Midwest, Gulf Coast and Canada as well as the Northeast.

The interconnect with Vector in Michigan has the potential to displace a substantial amount of gas from West Canada traveling on Alliance Pipeline. Currently, Canadian gas flowing on Alliance makes up the bulk of Union Gas deliveries at St. Clair. As of the beginning of this month, Alliance made up 81% of the 1.08 Bcf/d of deliveries, according to Platts Analytics. Some of this gas goes to various facilities in Michigan before making its way to the Dawn Hub in Canada. In Ontario, gas can travel to storage facilities in the area, be sold into the Canadian market, make its way to markets in the Northeast US or can be sent back to Chicago and Michigan markets.

But Rover has a contract with Vector to ship 900 MMcf/d on the line for 20 years beginning November 1, 2017, potentially squeezing out West Canada gas traveling into the Midwest on Alliance Pipeline. And if prices stay the same, markets in East Canada will want Northeast gas rather than West Canada gas, which is more expensive and faces higher transportation costs.

Rover’s connection with Panhandle might also displace gas coming out of the Anadarko play headed to upper-Midwest markets.

In Rover’s original filing with FERC early this year, it requested a decision by this November in order to meet its deadlines and contracts. The $4.2 billion dollar project is already fully subscribed at 3.21 to 3.25 Bcf/d. Now, Energy Transfer is just hoping for approval by spring.

Energy Transfer said if FERC authorization is not provided by the second quarter of 2016 it would jeopardize the project’s ability “to complete the work necessary to place its facilities into service in the safest and most environmentally sensitive and timely manner.” This could delay project completion by up to a full year “similarly strand Marcellus and Utica production for the same period of time.”

Rover admits the timeline is ambitious, but the pipeline already has multiple 15 and 20-year long-term contracts with nine producers. It also sees the pipeline as necessary to avoid price volatility.

“Price hubs in the central and northeast portions of the Marcellus region, where natural gas production has been higher, and pipeline capacity to bring it to other markets has been more limited, have seen lower prices compared to hubs around southern and western portions of the Marcellus,” according to an Energy Information Administration report on Appalachian spot prices.

“The large amount of backed-up supply also makes Appalachian spot prices more volatile, and can cause them to drop by as much as $1/MMBtu on moderate temperature days when Northeast demand is low.”

— Brandon Evans, Tyler Jubert

Michigan

West Virginia

Ohio

CANADA

Lake Erie

Pennsylvania

Kentucky

Indiana

Source: Platts Analytics

ROUTE OF ET ROVER PIPELINE PROJECT

ET Rover PipelineVector PipelineColombia GasTexas EasternDominionANR

VECTOR RECEIPTS AND DELIVERIES


(Bcf/d)

0.0

0.5

1.0

1.5

2.0

NovOctSepAugJulJunMayAprMarFebJan

Alliance receipts Union gas deliveries (St. Clair)



Energy Imbalance Market Developments, Renewables vs. Grid Reliability, and Natural Gas Market Projections

California Power and Gas Conference

Learn from Leading Experts: CAISOCalifornia Energy Commission CAPUCCalpine CorporationDeutsche BankDuke EnergyEnerNOC, Inc.Eos Energy StorageMegawatt Storage Farms NRG EnergyNV EnergyPacifiCorp TransmissionStoel Rives LLPSunEdisonUBSAnd Many More!

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Industry Leaders Share Exclusive Insight into California’s Evolving Power and Gas Market

• Renewable Portfolio Standards — How California plans to meet the newlyproposed GHG emissions reductions of 2030 and 2050

• Demand response — Identifying its role amid the generation portfolio mix• Energy Imbalance Market — The pros, the cons, and the future impact it

can have on trading in the West• Energy storage — Making it a viable option via technological advancements

and improvements• Renewables — What might the price of new solar energy look like post

tax-credit expirations?• Natural gas supply/demand — Overviews on supply/demand, gas storage,

and pipeline flows between regions• California Resource Adequacy Market — As customer load shifts from

utilities to other load-serving entities, who may be responsible for long-termresource adequacy?

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Smart Energy — How Embracing New Technology is Empowering Utilities and Their UsersMichael Sachse, Senior Vice President, Marketing, Business Development, and Regulatory Affairs Opower

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InsIde FeRC - Platts as 26 states are seeking to block EPA’s Clean Power Plan to reduce carbon dioxide emissions, Environmental Protection Agency Administrator Gina McCarthy sought