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.

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.