Pipelines Sail into Political Winds in Washington in 2021

Pipeline & Gas Journal - for the original article go HERE.

With the ascension of President Joe Biden and environmentally friendly Democratic agency heads taking over U.S. regulatory and independent agencies, interstate gas pipelines face a host of newly emboldened, top-level appointees – many of them gas pipeline skeptics – who will make their political weight felt across federal permitting and safety requirements. 

In that regard, the biggest impact is likely to be at the Federal Energy Regulatory Commission (FERC), which is apt to give greater consideration to prospective emissions of greenhouse gases when considering applications for construction of new gas transmission pipelines.  

Biden will appoint one of the two current Democratic FERC commissioners as chairman. For pipelines, neither is a particularly appetizing choice. Richard Glick has repeatedly opposed approval of new pipelines because of their impact on greenhouse gas emissions and for other reasons. 

Allison Clements, a Democrat confirmed by the Senate in November, was previously in charge of the Sustainable FERC Project at the Natural Resources Defense Fund (NRDC). Clements’ successor at the NRDC FERC Project is Gillian Giannetti, who wrote a blog in November 2019 headlined “Reform Is Long Overdue for FERC’s Gas Pipeline Reviews.” 

FERC will continue to have a 3-2 Republican-to-Democrat advantage until July 2021 when Biden will have a chance to appoint a Democrat to a Republican seat, allowing Glick, who is likely to be appointed the chairman soon after Biden ascends, to take FERC pipeline approval policy in a potentially radical new direction.  

But the winds of change will probably blow before the FERC majority shifts to 3-2 Democratic. Gillian Giannetti thinks Glick or Clements will immediately begin to develop a climate test that FERC can use when considering applications for new pipeline construction. 

In the past, FERC has been unsure of the extent to which greenhouse gas emissions can be considered, in part because federal court case rulings had left a lot to be interpreted clearly.  

But Giannetti believes the National Environmental Policy Act (NEPA) and the Natural Gas Act (NGA) make a clear case for FERC considering “direct” GHG emissions, those created by the construction of a project and emissions from operation of the pipeline.  

“Those are the lowest hanging fruits,” she said. Even though she admits those direct emissions are a small part – though not de minimus – of GHG emissions from a project, calculating those would be a good first step, she said.  

Giannetti thinks many in the pipeline industry would agree with factoring direct emissions into the FERC’s consideration of pipeline applications. “I would be shocked if Joan Dreskin disagreed with me,” she said, referring to the senior vice president, secretary and general counsel of the Interstate Natural Gas Association of America (INGAA).  

But Giannetti and other environmentalists believe that ultimately FERC needs to come up with an assessment tool that measures the lion’s share of GHG emissions created by new pipelines, those from upstream and downstream operations. 

Dreskin said FERC already considers direct emissions.  

“Pipeline project developers provide FERC with information regarding the direct GHG emissions from their proposed projects, which include emissions from pipeline construction and operation,” Dreskin responded. “FERC has historically analyzed and reported these emissions. Current NEPA regulations, however, no longer subdivide effects in this manner. We anticipate FERC will continue to consider what were previously referred to as ‘direct effects’ in its analysis.” 

The question is, however, how far does current law allow FERC to go to block new pipeline projects? 

“Were FERC to find that a project is not in the public interest because of GHG emissions, this in my view would be a seismic shift for the agency, and it would have difficulty surviving judicial review,” offered Emily Mallen, who closely follows FERC activities as a partner in Washington with the law firm Sidley Austin LLP. “That said, FERC could deny a pipeline project under the NGA if it found lack of public need, and Commissioner Glick’s dissents have also centered on whether a particular project is really needed.” 

Mallen believes FERC’s consideration of public necessity will become more onerous and affiliate agreements likely will be subject to greater scrutiny going forward. 

“That said, I can foresee no scenario in which FERC will stop allowing affiliate agreements to serve as a basis for project need,” she added. “But the project sponsors may need to put more data into the record to bolster that needs assessment.” 

Mallen points out one other presumably anti-pipeline factor that may rear its head under a Democratic-controlled FERC: environmental justice (EJ), which has the potential to affect a proposed project on communities of color.  

“When it comes to EJ concerns raised in pipeline and LNG certificate matters, FERC has applied its own methodology to the review that is based on the EPA’s Environmental Justice Mapping and Screening (EJSCREEN) tool,” Mallen explained. “If modifications are made to the EJSCREEN tool to strengthen it, this is certain to impact future FERC analyses. Moreover, we’ve seen dissents by Commissioner Glick on FERC’s approach to EJ review that suggests the agency’s approach could shift under a Democratic-led Commission.” 

Almost as certain as tougher reviews for pipelines at FERC is the likelihood that the Environmental Protection Agency (EPA) will withdraw the Trump final rule issued in September 2020, called Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review and referred to as the “Methane Repeal Rule.”  

It did two favorable things for interstate pipelines: 1) canceled the 2012 Obama rule that make transmission pipelines subject to Clean Air rules on volatile organic chemical emissions and 2) canceled a 2016 Obama rule that made transmission pipelines and all other sectors of the oil industry subject to methane restrictions on air emissions. 

Environmental groups such as NRDC, Environmental Defense Fund and Sierra Club are challenging that Trump final rule in federal court, said David Doniger, senior strategic director, climate and clean energy program at the NRDC who oversees the case. 

“In short, we are very confident the court will reject EPA’s methane rollbacks if the case is seen through to decision. The incoming Biden administration is near certain,” he said. “However, to reverse course administratively, reissue the rules and proceed to regulate existing equipment, the case may not actually proceed to decision.”  

What will also be affected by the incoming Biden administration are Trump administration proposed rules that were not finalized by the time Biden was inaugurated. If these were finalized prior to Biden taking office, the Senate with its Democratic majority could potentially cancel those rules via the Congressional Review Act, since they would have been finalized within 60 days of a new administration taking office.

This is being written prior to Biden’s inauguration, so it isn’t known whether two key proposed rules will be finalized or whether they won’t, leaving the Biden administration to make changes or simply cancel the rulemakings outright. 

The first one is the Army Corps of Engineers proposed revisions to nationwide permits that industries use when digging around wetlands with very little environmental damage. Gas pipelines use NWP12 to which the Corps proposed a number of changes, all of them opposed by the INGAA.  

Interestingly, environmental groups opposed the changes, too, though for different reasons. The Corps is likely to hold off issuing a final rule because of numerous controversies about many aspects of its proposal. However, the law says the Corps must reissue NWPs every five years, meaning in this case by 2022. Among changes environmental groups are seeking is one totally eliminating NWP12.  

Another “hanging chad” is the Pipeline and Hazardous Materials Safety Administration’s (PHMSA) proposed rule giving pipelines a new alternative to replacing old pipe when the population density around that pipe increases from a Category 1 to a Category 3 location.  

Instead of having to replace old pipe, which the pipelines prefer not to do because of cost, the Trump PHMSA wants to allow pipelines to use integrity management procedures to assure the safety of that pipe in the now higher density area. This proposed rule has a somewhat lower visibility but still faces opposition from state safety officials represented by National Association of Pipeline Safety Representatives (NAPSR).  

That proposed rule will probably be carried over to the Biden administration. The fiscal 2021 appropriations bill passed by Congress at the end of December included the Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2020.  

That bill has minimal impact on gas transmission pipelines, but, more importantly, establishes new safety programs for both distribution pipelines and liquefied natural gas (LNG) facilities. So those two gas sectors will likely see the PHMSA begin to roll out new regulatory programs for them in 2021.

Author bio:
Mr. Barlas, a freelance writer based in Washington, D.C., covers topics inside the Beltway.

FERC Begins a Likely Skein of Mandatory Rate Cases

Pipeline & Gas Journal - for the original article go HERE.

FERC’s initiation of what amounts to a wholesale review of interstate pipeline rates threatens to shake up the industry and maybe its customers. The commission is in the early stages of reviewing the rates of about 130 pipeline and storage companies to see if they should lower their rates because of the 2017 tax cut enacted by Congress and a couple of other subsequent agency actions.

On Jan. 16, FERC announced the results of the first tranche of 12 reviews and initiated three Section 5 rate cases against two interstate pipelines and one storage company contending their current rates are “unjust and unreasonable.”

Extrapolating those early results means perhaps 30 companies could be subject to Section 5 rate cases, an unprecedented step. One industry observer who works with pipeline companies on rates, and asks not to be identified, says, “This has never happened before.”
He points out that it is possible that while FERC can force companies to lower rates, some companies, rather than subject themselves to a FERC-ordered Section 5 process, might instead voluntarily and peremptorily decide to file a Section 4 rate case.

That is exactly what Northern Natural Gas has done. It was one of the two big pipelines slapped with Section 5 cases in January. Northern disputed the FERC’s calculation of its return on equity (DOE) as affected by the 2018 tax cut and filed a motion Jan. 28 asking FERC to terminate the order subjecting Northern to a rate review or, in the alternative, to hold the proceeding in abeyance pending Northern’s filing of its FERC Form No. 2 in April 2019.

This is not the first time that the commission has pursued a Section 5 action against Northern based on erroneous support. “In 2009, FERC initiated a Section 5 against Northern that concluded with a request from customers to terminate the proceeding with no rate change,” said Mark Hewett, president and CEO of BHE Pipeline Group, which includes Northern. The company said from a purely financial perspective, the issuance of a Section 5 action is expected to produce positive results for Northern because the action will accelerate Northern’s filing of a Section 4 rate increase to allow Northern to recover the significant investment required to modernize its pipeline system. BHE is Berkshire Hathaway’s pipeline subsidiary, which also includes Kern River, which agreed to a settlement, based on the tax cut, of a customer-approved plan for an 11% rate credit, according to BHE.

Besides Northern Natural, FERC announced Section 5 cases against Bear Creek Storage Company and Panhandle Eastern Pipe Line Company, LP. FERC is basing its rates review on an analysis of the Form 501-Gs all companies have filed. Carl Fink, an outside attorney for Panhandle, declines to comment on FERC’s action against his client. Panhandle is a 6,009-mile natural gas pipeline that extends from sources of supply in the states of Texas, Kansas and Oklahoma, running through Missouri, Illinois, Indiana and Ohio to its northern termini in Michigan and at the International Boundary between the United States and Canada. Bear Creek is 50-50 jointly owned by Southern Natural Gas Company and Tennessee Gas Pipeline Company, both subsidiaries of Kinder Morgan. Kinder Morgan did not respond to requests for comment.

In each of these initial Section 5 cases, pipeline customers, whether local distribution companies or industrials such as U.S. Steel, are clamoring for FERC to reduce the company’s rates.

Northern is an about 14,700-mile natural gas pipeline that provides natural gas services to markets from Texas to Michigan’s Upper Peninsula. Northern reports that it has over 200 shippers.

In moving forward with a Section 5 rate case, FERC said based on its 501-G, Northern has a 17.3% return on equity (ROE). The commission added that based on that number it is “concerned that Northern’s current rates may be unjust and unreasonable.” If it moves forward, the investigation will look at Northern’s costs and revenues for most of 2018 and for part of 2019.

Northern argues no investigation is necessary, because FERC made mistakes in its ROE calculation. In its Jan. 28 motion, Northern stated its ROE is really 13.7%. “This result is very consistent with Northern’s calculated ROE for 2018 of 13.5%, and considerably below the erroneously calculated ROE of 17.3%,” Northern wrote.

The 12 companies identified on Jan 19 by FERC – the three Section 5 cases plus nine given a pass – account for 12 of the pipelines in Group 1, which has 29 companies. Group 1 companies had the earliest deadline for filing 501-Gs. Group 2 has 30 companies and Group 3 has 66 companies. If three of the first 12 companies examined by FERC were found to have unreasonable rates, that means 30 or more companies out of the 130 total could find themselves in Section 5 territory before all is said and done.

Order No. 849 required all interstate natural gas companies, with cost-based stated rates, that filed a 2017 FERC Form No. 2, or 2-A, to file a FERC Form No. 501-G informational filing. Using the data in the pipelines’ 2017 FERC Form Nos. 2 and 2-A, the form estimates: (1) the percentage reduction in the pipeline’s cost of service resulting from the Tax Cuts and Jobs Act and the Revised Policy Statement, and (2) the pipeline’s current return on equity (ROE) before and after the reduction in corporate income taxes and the elimination of income tax allowances for MLP pipelines.

Author bio:
Mr. Barlas, a freelance writer based in Washington, D.C., covers topics inside the Beltway.

Natural Gas Players Oppose Perry Coal/Nuclear Subsidy Proposal

Pipeline & Gas Journal-December 2017 for the original article go HERE.

The natural gas industry is attempting to turn back an attempt by Energy Secretary Rick Perry to in effect subsidize coal and nuclear suppliers to electric utilities at the expense of natural gas suppliers. Perry instructed the Federal Energy Regulatory Commission (FERC) in September to propose a rule to provide rate incentives to electric utilities with a 90-day fuel supply onsite in the event of supply disruptions. That would allow regional transmission organizations (RTOs) and independent system operators (ISOs), which essentially regulate wholesale electric supply and demand in various regions, to adjust rates to benefit utilities dependent on coal or nuclear power.

FERC was taking public comment on its Grid Resiliency Pricing Rule until Nov. 30 and will ostensibly decide whether to adopt Perry’s proposal, modify it or extend consideration of it. Chairman Neil Chatterjee emphasized on a FERC podcast on Oct. 25 that his is an independent agency and indicated that it doesn’t take orders from the Department of Energy. “I remain committed to upholding the Commission’s independence when considering the DOE NOPR, and the many other issues that may come before us,” he said.

Perry’s charge to the FERC follows a report issued by the Department of Energy this summer which reported on the state of the electric grid and its reliability, and surmised future reliability problems based on projected retirements of older coal plants, particularly. The report alluded to the impact, for example, of the early 2014 Polar Vortex, an extreme cold weather event, during which PJM Interconnection (PJM), a major RTO, struggled to meet demand for electricity because a significant amount of generation was not available to run.

According to the DOE staff report, the loss of generation capacity could have been catastrophic, but several fuel-secure plants that were scheduled for retirement were called upon to meet the need for electricity: American Electric Power reported that it deployed 89% of its coal units scheduled for retirement in 2014 to meet demand during the Polar Vortex, and Southern Company reported using 75% of its coal units scheduled for closure.

Paul Bailey, president and CEO, American Coalition for Clean Coal Electricity, explained at a recent hearing of the House Energy & Commerce Committee that the nation’s coal fleet is comprised of 1,004 individual generating units located at 377 power plants that represent a total of 262,000 megawatts (MW) of electric generating capacity. About 60,000 MW of coal-fueled generating capacity (20% of the coal fleet) had retired by the end of last year. An additional 41,000 MW have announced plans to retire. Altogether, these retirements represent one-third of the nation’s coal fleet.

In comments to FERC, the Interstate Natural Gas Association of America (INGAA) said the DOE proposal “disparages the reliability of natural gas-fired generators, and implicitly the reliability and resilience of the natural gas supply and delivery system, in attempting to make the case for the proposed grid reliability and resiliency rule.”

In fact, INGAA pointed to a recent DOE report which concluded: “Hurricanes Irene and Sandy did not have a major impact on natural gas infrastructure and supplies in the Northeast.” The group suggested instead that FERC ask RTOs and ISOs to report on how they value reliability and that FERC use that information to move forward with any rulemaking, but on a fuel-neutral basis.

The Natural Gas Supply Association argued, “The facts are impressive with interstate pipelines delivering 99.79% of firm contractual commitments over the last decade – a number that includes fulfilling firm shippers’ requests during the Polar Vortex when natural gas demand was at a record high and 9% higher than the previous winter.”

NGSA noted many generators in ISO and RTO markets choose to rely upon interruptible or secondary firm transportation service instead of primary firm transportation service so they may be more vulnerable to supply interruptions. But it is their decision to choose those contracts.

Moreover, the DOE Grid Study recounts that “many coal plants could not operate due to conveyor belts and coal piles freezing” during the Polar Vortex and “three nuclear reactors totaling 2,845 MW of capacity were shut down, and five operated at reduced levels due to disruptions in transmission infrastructure, reduced demand from distribution outages, and precautionary measures to protect equipment” during Superstorm Sandy.

The House Energy & Commerce Committee held two hearings in September and October on electric grid reliability. At one on Oct. 13, Marty Durbin, executive vice president and chief strategy officer, American Petroleum Institute, argued that increasing use of natural gas in electric power generation has not only enhanced the reliability of the overall system, it’s also provided significant environmental and consumer benefits. “As an example, since 2008 average annual wholesale power prices in PJM have decreased by almost 50%,” he related.

Major consumers of natural gas weighed in against Perry’s proposal. The Process Gas Consumers Group, composed of manufacturers who rely on natural gas for electric plants, stated FERC has already taken a number of steps to ensure reliability. For example, the commission approved the New England ISO’s “pay for performance” program and winter reliability programs which provide financial incentives for generators to be prepared to perform in extreme weather events.

Also, to handle issues related to possible natural gas supply interruptions, FERC issued an order to allow increased communication between electric system operators and pipeline operators, increasing electric operators’ information about gas pipeline status in dispatching gas-fired generators.

Solar and wind energy providers and environmental groups such as the Natural Resources Defense Council oppose the Perry proposal.

BLM Suspends Implementation of Methane Flaring Rule

The Bureau of Land Management (BLM) suspended and extended the deadlines for some provisions in its November 2016 final rule on methane flaring from gas wells on public lands. The 2016 final rule became effective on Jan. 17, 2017. Many of the final rule’s provisions are to be phased in over time and were to become operative on Jan. 17, 2018.

A coalition of gas and oil groups have challenged the legitimacy of the rule, arguing the Environmental Protection Agency (EPA) has the authority under the Clean Air Act to regulate methane emissions, the major contaminant among greenhouse gases. That was the argument made in April 2016 by The Independent Petroleum Association of America (IPAA), the Western Energy Alliance (WEA), the American Exploration and Production Council, and the U.S. Oil and Gas Association.

They argued that instead of worrying about methane emissions, the BLM would be better served directing its resources toward processing applications for the pipeline rights-of-ways across federal and Native American lands that are essential for the building of gas-capture technology. “Timely processing of such applications would have a much greater and more immediate impact on reducing flaring levels than BLM’s proposed one-size-fits-all, command-and-control regulation,” the groups said.

The BLM’s rule on venting and flaring of methane was also the subject of legal action undertaken by the WEA, IPAA and some of the western states most prominently affected. This litigation has been consolidated and is pending in the U.S. District Court for the District of Wyoming. The groups filed a separate request in federal court for an injunction and a stay of the rule, but those motions were denied by the court on Jan. 16, 2017 and the rule went into effect the following day.

Although the court denied the motions for a preliminary injunction, it expressed concerns that the BLM may have “usurped” the authority of the EPA and the states under the Clean Air Act, and questioned whether it was appropriate for the 2016 final rule to be justified based on its environmental and societal benefits, rather than on its resource conservation benefits alone. The next stage in the litigation will be the court’s consideration of the merits of the petitioner’s claims.

The possibility that the BLM rule could be overturned led to the BLM’s decision on Oct. 16, 2017 to delay until Jan.1, 2019 implementation of parts of the rule that would have gone into effect on Jan.1, 2018. In the meantime, the BLM will review the Obama administration rule to determine where it falls out of compliance, if it does, with President Trump’s Executive Order 13783, entitled, “Promoting Energy Independence and Economic Growth.”

Section 7(b) of Executive Order 13783 directs the Secretary of the Interior to review four specific rules, including the 2016 final rule, to determine whether to revise, suspend or rescind those rules. The result of that examination may lead to the BLM proposing a revision of the methane rule.

Author bio: 

Mr. Barlas, a freelance writer based in Washington, D.C., covers topics inside the Beltway.

In Turnaround, FERC Proposes to Allow Surcharges to Fund Modernization

Pipeline & Gas Journal - February 2015 - for the original online version of this article go HERE.

In a departure from past policy, the Federal Energy Regulatory Commission (FERC) is considering allowing interstate pipelines to recoup the costs of complying with federal environmental and safety regulations.

FERC would allow pipelines to insert simplified mechanisms, such as trackers or surcharges, into contracts with shippers. FERC allowed trackers in an isolated case involving Columbia Gas Transmission when it issued a final order in January 2013. Prior to that, the Commission stated that recovering those costs in a tracking mechanism was contrary to the requirement to design rates based on estimated units of service.

Joan Dreskin, the general counsel for the Interstate Natural Gas Association of America (INGAA), called the proposal a "very positive" development. She said that once it becomes final, it won't open a  floodgate of requests for a number of reasons, for example, because some pipelines face more competitive marketplaces than others.

Also, the timing of new environmental and safety requirements may not parallel one another, raising a question about the best timing to negotiate a "tracker" into a contract with a shipper. And those contracts, as was the case with Columbia, will require pipelines to make extensive shipper rate concessions, and provide consumer protections.

It appears FERC's tentative decision to change policy and allow trackers stems in good part from passage of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. That law requires transmission companies to undertake new maintenance initiatives. Even prior to passage of that law, the federal Pipeline and Hazardous Materials Administration (PHMSA) had issued a first-step regulatory proposal, never finalized, which could lead to broadened integrity management requirements, including expanded high-consequence areas. Moreover, the Environmental Protection Agency is considering a regulatory proceeding meant to decrease methane emissions from compressors.

Giving certain and potential new federal requirements, the Commission says it is proposing the proposed Policy Statement "in an effort to ensure that existing Commission ratemaking policies do not unnecessarily inhibit interstate natural gas pipelines’ ability to expedite needed or required upgrades and improvements."

The FERC order approving the contested Columbia settlement (the state of Maryland was among the most vociferous opponents) came in January 2013. The Columbia system stands out because both its pipelines and compressors are, for the most part, of pre-1970 vintage, before pipeline safety rules went into effect.

The majority of its system cannot accommodate inline inspection and cleaning tools. Fifty-five percent of its more than 300 compressor units were installed before 1970. FERC approved a capital cost recovery mechanism (CCRM) allowing Columbia to raise up to $300 million annually for a modernization program. The $300 million is being collected via a rate base multiplier of 14%.

In 2013 and 2014, Columbia spent $626 million to place 73 modernization projects in service including 82,692 horsepower at eight compressor stations and retired 92 miles of bare steel and wrought-iron pipeline.

All Columbia shippers supported the tracker, which was cushioned by substantial rebates, including an annual $35 million rate reduction (retroactive to Jan. 1, 2012), and an additional base rate reduction of $25 million each year beginning Jan. 1, 2014, both reductions to end on the effective date of Columbia’s next section 4 general rate case, or a subsequent NGA section 5 rate adjustment.

Columbia also agreed to initial refunds to firm shippers of $50 million in two equal installments, a rate moratorium through Jan. 31, 2018 and an NGA section 4 general rate filing obligation no later than Feb. 1, 2019. Only the Maryland Public Service Commission (MPSC) opposed it, arguing the tracker would shift the burden of investment costs from Columbia to its customers, and its approval could start down a slippery slope toward such mechanisms replacing rate cases as the primary method  for recovering major investment costs.

But Regina Davis, spokeswoman for the MPSC, said those objections would not be voiced today. That is because the Maryland General Assembly enacted the Strategic Infrastructure Development and Enhancement (STRIDE) legislation in 2013 which authorizes tracker-based infrastructure investment rate proceedings.

That STRIDE statute and the policy underlying it were recently applied in a number of Maryland PSC cases. "Therefore, the Maryland PSC precedent relied upon in opposing the Columbia Gas would no longer be argued in the way that it was if a case similar to the Columbia case came up today," she explained.

Author bio: 

Mr. Barlas, a freelance writer based in Washington, D.C., covers topics inside the Beltway.

FERC's Moeller Presses Online Gas Trading Platform; Industry Unenthusiastic

Pipeline & Gas Journal - October 2014 - for the online version go HERE.

FERC "pipeline" Commissioner Phillip Moeller held a workshop Sept. 18 to explore the possibility of the commission, on its own or through a third party, establishing an online trading platform for the nomination and confirmation of pipeline deliveries of natural gas. The proposal was made at a technical conference in April by Don Sipe, a Maine attorney, on behalf of the American Forest and Paper Association.

That workshop examined operational and resource issues in the gas and electric industries arising from last winter’s polar vortex. Sipe served two terms as chair of the New England Power Pool and for over a decade was vice chair of NEPOOL for the end use sector.

The potential of an online scheduling tool is just one idea FERC is studying to address several somewhat related issues dealing with getting adequate natural gas to electric utilities during cold snaps. Some proposals deal with scheduling, others with delivery, some only on the natural gas side of the issue, others with better coordination between gas pipelines and electric wholesalers.

Moeller says about the online trading workshop and scheduling issues more broadly, "We have to at least try and move the concept forward before next winter. Pipelines have the incentive to keep their electric generator customer base happy, so they should be in favor of these efforts because generators are not happy now with the lack of transparency and liquidity after hours."

Sipe says the response to his proposal from the industry at large could best be characterized as "thunderous silence." The current system of commodity trading is "old school," where generators faced with short-notice supply needs essentially use, according to Sipe, their rolodexes to call various marketers in search of gas and available capacity.

Joan Dreskin, INGAA general counsel, responds that pipelines are aware of Sipe's proposal, but haven't piped up because Sipe has advanced a concept, not a detailed proposal. "We are eager to learn more, but do have some serious reservations, as to who will pay for the online trading platform, and whether it will add value for our customers." She notes, for example, that some customers could lose out if pipelines have to make their capacity fungible.

"Pipelines have worked to customize tariffs for customers and not all firm transportation recourse tariffs look the same," she explains. "It is unclear how a uniform trading platform would work if you are not comparing apples to apples."

An online trading platform would theoretically allow electric generators to find out much more quickly whether pipelines will be able to supply gas needed on short notice such as when an Independent System Operator (ISO) must quickly find a replacement generator due to an outage or an unexpected change in load. Typically, an ISO, such as the one operating in New England, needs to know, in real time within 15 minutes whether a given generator will be able to supply the necessary power to local electric utilities on any given day. This is particularly an issue during a cold weather snap or a heat wave or when unexpected generator outages require the ISO to dispatch previously offline units.

However, in the current system, it takes much longer for generators to nominate gas on a given pipeline's system, and even longer for the pipeline to confirm it can supply the gas at a given price. That can sometimes take three to four hours. This is particularly tough on merchant generators which frequently don't have firm capacity. At times, this uncertainty will lead the system operator to dispatch more generation than needed because it is unsure which, if any of the units will be able to get gas.

Generators, in turn, may nominate more gas than needed to fulfill ISO requests. Subsequently, the ISO may find itself with more generation that it needs and “dispatch down” a certain number of generators that had gone out and secured supply. Left with excess supply, generators may either have to resell at a loss or face imbalance penalties. If generators cannot recover these costs in some fashion they are harmed, and conversely, if they can recover these costs electricity consumers end up paying these added charges.

The pipeline industry generally believes the solution to the problem is to build more pipeline capacity. "I agree we need to build more pipelines, but that appears to be the sole focus of the industry," explains Sipe. He believes the apparent lack of enthusiasm for considering expanding an online trading platform such as the Intercontinental Exchange, to coordinate more closely with and perhaps automate the nomination and confirmation process in real time trading, has to do with some uncertainty as to whether FERC could mandate such a trading platform, who would pay for it and perhaps some hesitancy on the part of marketers to be more transparent in their pricing. But he believes pipelines and others industry participants could make more money from "being more efficient."

His proposal wouldn't be a panacea," concludes Dreskin, "but we are willing to talk about it."

Author bio: 

Mr. Barlas, a freelance writer based in Washington, D.C., covers topics inside the Beltway.

Federal Court Ruling On Mercury Revives Gas-Electric Worries

Pipeline & Gas Journal
June 2014 - for the online version go HERE.

A federal court decision allowing the Environmental Protection Agency (EPA) to move forward with a rule limiting mercury emissions from power plants has heightened concerns in some quarters about interstate pipeline infrastructure inadequacy.

In mid-April, the U.S. Court of Appeals for the District of Columbia said 1,400 coal- and oil-fired electric generating units (EGUs) at 600 power plants must meet air emissions standards finalized in 2011. The plants have up to four years to comply with necessary reductions in emissions of mercury and other air toxics, but the 2011 final rule had been held in abeyance because of a legal challenge.

In September 2013 the EPA issued a proposed rule, which, if finalized, will force newly built power plants to meet stricter standards on emissions of carbon dioxide, a leading greenhouse gas. Taken together, these two EPA actions have persuaded some electric utilities to close coal-and oil-fired power plants, leading some officials at agencies such as the Federal Energy Regulatory Commission (FERC) to worry that natural gas pipelines will have a hard time supplying replacement power plants using natural gas, especially in tough weather such as last winter.

American Electric Power has said it will retire almost a quarter of its coal-fueled generating units in the next 14 months. That is 25% of its capacity. In PJM, 13,000 MW of additional capacity will be retired by mid-2015. "Unless the market structure changes, the capacity replacements for these assets may not provide the same level of reliability we have experienced historically," says Nicholas Akins, chairman, president, and CEO, AEP. PJM is the Regional Transmission Organization (RTO) serving all or parts of the states of Illinois, Indiana, Michigan, Ohio, Kentucky, Tennessee, West Virginia, North Carolina, Virginia, Maryland, Delaware, Pennsylvania, New Jersey and the District of Columbia. AEP, Dominion and Exelon, among others, serve electricity customers within PJM, to name a few.

To the extent that EPA regulations drive some coal-fired generation plants out of business, pressure will be ramped up on pipelines to serve the gas-fired plants that take their place, if in fact gas-fired plants DO take their place. "Natural gas has proven to be the fuel of choice for new generation developing in our region," states Michael Kormos, executive vice president of Operations for PJM Interconnection. "Over 64% of new resources in our queue are proposed gas-fired generation."

A week before the federal court handed down its EPA/mercury ruling, the FERC’s unofficial "pipeline commissioner" told a Senate committee he preferred the EPA present better data before forcing electric utilities to close because of new environmental rules. Philip Moeller told the Senate Energy and Natural Resources Committee, which was meeting to consider issues related to grid reliability, "The sufficiency of our generating resources has been clouded by uncertainties arising from changing environmental regulation. I am not opposed to closing older and less environmentally-friendly power plants, but I am concerned that the compressed timeframe for compliance with the new environmental rules was not realistic given the amount of time it takes to construct new plants and energize transmission upgrades to mitigate plant closures.”

Author bio: 

Mr. Barlas, a freelance writer based in Washington, D.C., covers topics inside the Beltway.

FERC To Review Recent Rule Requiring Permitting Of Auxiliary Facilities

Pipeline & Gas Journal
March 2014 - for the online version go HERE.

The Federal Energy Regulatory Commission (FERC) will look again at a new rule requiring certificates to be filed for right-of-way auxiliary construction and for landowners to be given a five-day heads-up before construction and maintenance work starts. That rule was published in November and went into effect Feb. 3.

The Interstate Natural Gas Association of America (INGAA) and National Fuel Gas Supply Corp. both asked for a rehearing, and FERC granted that wish on Jan. 29. The rule was issued as the result of a petition submitted in 2012 by INGAA whose requests were essentially squashed by FERC when it issued a final rule in November.

Joan Dreskin, general counsel, INGAA, says, "FERC issued a standard ‘tolling order’ in this case which allows them to act when they wish on the rehearing/clarification."

In part, the debate revolves around the difference between replacement and auxiliary facilities. FERC wants them treated similarly as "jurisdictional," meaning they would have similar requirements with regard to pipeline companies filing certificates which the commission would have to approve before the companies could start construction. INGAA says auxiliary facilities shouldn't be permitted.

INGAA had started the ball rolling in 2012 because of Commission staff discussions with pipeline representatives where FERC staffers stated that companies undertaking section 2.55(a) auxiliary installations to augment existing facilities must stay within the right-of-way or facility site for the existing facilities and restrict construction activities to previously used work spaces. Industry officials thought this was a change in policy which would force them to obtain certificates when auxiliary facilities were installed outside rights-of-way. The kinds of auxiliary facilities at issue include: valves; drips; pig launchers/receivers; yard and station piping; cathodic protection equipment; gas cleaning, cooling and dehydration equipment; residual refining equipment; and water-pumping equipment.

Given that ostensible change in policy made outside any rulemaking, INGAA filed its petition in 2012. FERC issued a proposed rule in December 2012 which simply codified the position its staff had laid out. INGAA protested. FERC argued the proposed rule was only a "clarification" which "articulated existing, long-standing constraints and obligations with respect to auxiliary installations." It then took more comments before ignoring INGAA's protests again when issuing the final rule last November.

The final rule also codified for the first time the common industry practice of notifying landowners prior to coming onto their property to install, replace or maintain auxiliary or replacement facilities.
In its request for rehearing, INGAA says that in the Final Rule, the Commission "persists as well in a fiction that its new ruling does not change what had been the plain and universal understanding of that provision for approximately 60 years until the December 2012 NOPR."

In addition to unlawfully converting an entire class of exempt, non-jurisdictional auxiliary installations into jurisdictional NGA facilities, the Commission, without referencing a record of abuse, without identifying any material threat to its statutory obligations, and without providing any premise based on relevant facts, extends regulatory limitations to these installations that in the past have applied only to separate and distinct replacement activities. The Commission’s Final Rule is arbitrary and capricious. It is not the product of reasoned decision making.

Besides absolving auxiliary activities from permitting, INGAA also wants FERC to clarify that the five-day prior notification requirement would not apply to activities done for safety, DOT compliance, in response to “one-call obligations,” or environmental or unplanned maintenance reasons that are not foreseen and that require immediate attention by the company and for activities that result in ground disturbance where such disturbance would be located entirely within the fence line of an existing, aboveground facility site.

David W. Reitz, Deputy General Counsel, National Fuel Gas Supply Corp. and attorney for Empire Pipeline, points out that PHMSA’s regulations require a company discovering a pipeline anomaly requiring immediate remediation to excavate and inspect the pipeline within five days of discovery. "Because of the time required to verify or determine the names and addresses of the property owners and to deliver the notices, five-day advance landowner notification would be impractical in these circumstances," he explains. "In addition, a pipeline receiving a one-call notification often has a maximum of 48 hours to determine and mark the precise location of its facilities, which may require some excavation."

Senate to Consider Pipeline Permitting Reform, Too

Pipeline & Gas Journal
September 2013 - for the online version go HERE.

The Senate may consider some form of pipeline permitting reform but the bill may not look like the one the House was expected to pass. Sen. Ron Wyden (D-OR), chairman of the Energy and Natural Resources Committee, released a broad statement on natural gas issues July 25.

Fleshing out the details in a speech hosted by the Bipartisan Policy Center Wyden laid out four areas – infrastructure, transportation, exports and shale development – where he is working to find bipartisan agreement. With regard to infrastructure he said he wants to speed pipeline development while plugging methane leaks that threaten the climate advantage that natural gas provides. “I’m going to look for ways to not just build more pipelines, but to build better pipelines,” Wyden said.

Sen. Lisa Murkowski (R-AL), the top Republican on the committee, is also interested in moving forward with pipeline legislation, but apparently is less interested in some broader natural gas bill. "We are doing our due diligence and seeing whether legislation is needed or whether the Federal Energy Regulatory Commission (FERC) can improve the permitting process administratively," says Robert Dillon, spokesman for Murkowski. "Sometimes legislation leads to unintended consequences."

Keith Chu, a spokesman for the Senate Energy Committee, says there isn’t a hearing scheduled for H.R. 1900. He adds, "Chairman Wyden is interested in talking to colleagues about whether there is interest in speeding up permitting while also addressing methane emissions, but it’s too soon to say whether there would be legislation."

Any Senate bill may contain some of the provisions in the Natural Gas Pipeline Permitting Reform Act (H.R. 1900) passed by the House Energy & Commerce Committee 28-14 on July 17. But there wasn't much Democratic support for that bill in the House. That means Wyden is likely to either modify many of H.R. 1900's provisions and add new ones, especially given his interest in seeing pipelines reduce methane emissions.

Wyden may accept some elements of H.R. 1900 since its sponsor, Rep. Mike Pompeo (R-KS), agreed to changes in the bill to appease the FERC. Those changes clarified that the expedited approval process endorsed by the bill would only be available to pipeline sponsors who put projects through the pre-filing process. That 12-month limit on how long FERC could take to either approve or reject a project after completion of a final environmental impact statement would begin after the commission received a completed application from the sponsor. Even after those changes were made, 14 Democrats voted against the bill and only two voted for it, meaning the legislation has a GOP stamp on it, clouding prospects in the Democratic-controlled Senate.