At the National Regulatory Conference meeting in Williamsburg, Virginia on May 19, a panel of three natural gas pipeline attorneys – two representing interstate systems and one a major distributor – explored contentious questions regarding the replacement or abandonment of infrastructure dating from a least half a century ago. Some of these legacy systems have largely served their purpose; others are being repurposed to move gas from new resource basins and/or meet increasing demands as the nation’s electric grid becomes more dependent on natural gas as a critical fuel. Pipelines face the high bar FERC applies to abandonment proposals as well as arguments over who bears the costs of new facilities.
The panelists were:
- Georgia Carter – Vice president and general counsel, Millennium Pipeline
- Kevin Frank – Attorney, Atmos Energy Corp.
- Dennis Kelly – Senior Counsel, American Midstream Partners, LP
Terry Boss, senior VP of environment, safety, and operations with the Interstate Natural Gas Association of America (INGAA), served as moderator. He remarked early on that the gas industry appears to entering a period of significant change – so much so the chairman of INGAA (Don Santa) had remarked recently that it looked comparable to the era of Order 636 (when the interstate pipelines went through a sweeping, FERC-dictated restructuring). As to the focus of the subject panel – replacement and modernization of the aging system – Boss observed that the origins of this trend can be traced to the late 1990s, when the “integrity management” program was initiated at PHMSA and made applicable first to all interstate pipelines and later as a “corollary” to distribution systems.
Currently, continued Boss, a new rulemaking is in play that “raises the bar” by incorporating “significantly more” facilities than was encompassed in 2004-vintage regulations, responding in part to Congressional demands in a 2011 statute. Boss also undercut the common belief that these types of regulations are about “maintaining” the pipelines; they are actually about “making the pipelines better than they were when originally installed.”
Another wave of regulation is addressing climate change by limiting methane emissions, noted Boss, with the previous week’s publication of new regulations, and “everyone now is trying to figure out what it involves.” It applies “pretty much through the whole value chain” short of distribution utilities, and there will be a “major impact [from] that.” Boss also commented on the “countervening” effects of these major regulatory thrusts because, when “trying to remediate facilities” for public safety some methane is emitted just from executing that activity. There are also worker safety issues to consider, so it is getting “very complicated” and “hard to accomplish” these assorted new regulations, Boss observed. And there will be questions about the costs involved, as “some of these [projects] will be remediation and some replacement.”
Georgia Carter, Millennium Pipeline. Carter credited Columbia Transmission Co. with taking a “collaborative” approach to modernization, observing that one of its settlements paved the way for FERC’s policy statement on this subject. The Columbia system (for which Carter previously worked) is a “reticulated” system in the Middle Atlantic region – “one of the oldest systems in the country,” she added – and was sorely in need of modernization.
The Millennium Pipeline, partly owned by the Columbia group, is a 230-mile interstate line running from western to eastern New York State. The pipeline was conceived as a “transformation” of an aging part of the Columbia system – specifically, a 70-year old, 12-inch diameter line crossing New York which by the late 1990s was approaching the end of its useful life. Although the line traversed a growing market, the cost of merely replacing it was “prohibitive”: a new capital investment of $1 billion at a time when the total ratebase of the Columbia system was just $2 billion. The company figured that a rate case filing to recover the cost of replacing the facility faced an uncertain outcome at FERC; while the Commission generally allows companies to replace aging facilities, this would be an “extreme example.”
Dealing as well with “capital constraints,” Columbia took what Carter characterized as an “interesting approach.” It formed a partnership with other entities, “upsized” the diameter to 30 inches, and proceeded to design and construct a new pipeline, the Millennium, on which Columbia leased capacity to serve the old line’s preexisting customers. Meanwhile, new customers subscribed to the additional capacity created at the higher costs of a new facility. The end result was a “win-win,” according to Carter, both for existing customers (whose rates and service were protected) and for the New York region (which needed incremental pipeline capacity). Millennium went into service in 2008.
Carter next provided the backdrop for a Columbia-customer settlement that, according to the speaker, provided inspiration for FERC’s policy statement on modernization initiatives. In 2011, facing the safety and reliability challenges of an aging system and experiencing new shipper demand from emerging shale gas plays in the Marcellus and Utica regions, Columbia surmised that a “traditional rate case approach” was not “ideal,” given the size and scope of its modernization needs. It therefore began working with customers on a solution and reached a settlement in September 2012, which FERC approved the following January.
Had Columbia employed a traditional rate case approach, Carter indicated it would have had to bring a new rate case about every year. Instead, it adopted a model being utilized by LDCs at state commissions: a tariff-based “tracker” provision dedicated solely to recovering the costs of its modernization program. This was “totally contrary to FERC policy” at the time, she added.
But it was acceptable to the Commission largely because the customers bought into it. They had some inducements: refunds and rate reductions upfront; the right to review and agree on the list of specific upgrade projects; a condition that Columbia first spend $100 million on maintenance annually; and a revenue-sharing mechanism for any “over-earning.”
Columbia agreed to all this, Carter explained, because it got something “very significant” in return: authorization to spend about $300 million annually on the specified system upgrades over five years (subject to a $1.5 billion cap) and make an annual filing to recover the cost of service on its investment. The only way this could have been done, given the arrangement was contrary to FERC policy, was to present the Commission with a unanimously accepted settlement (which was in fact what happened).
Carter touted the modernization program as “pretty successful” in achieving a “system transformation.” A major part of it was replacing inefficient, unreliable compression equipment that was 50-60 years old. The improvements also entailed replacing “bare steel” to improve safety and reliability. And, as a side benefit, emissions have been “dramatically reduced.” Customers are further benefitting in that, with the load growth Columbia has experienced, the rate impacts have been less than originally projected.
Three years into the term of the program, Columbia negotiated a three-year program extension with its customers. It was a tough financial decision for the company, indicated Carter, whether to go that route again or to file a rate case; but it opted for the program extension route because of the history of customer support. And while getting to a new agreement required a good deal of compromise on both sides, ultimately the company and its customers were able once again to present a unanimous settlement for the Commission’s approval.
In the meantime, prior to the second modernization settlement filing in late 2015, FERC issued its generic policy statement for approving system modernization cost recovery trackers. However, Carter underscored that both of Columbia’s negotiated settlements went beyond the Commission’s policy statement, and thus needed the full buy-in from its customers. She added that the company was “fortunate to have customers willing to work with us.”
Challenges Posed by Modernization Programs. Carter emphasized that, while it has been “good” for the company overall, it’s “not without its challenges.” In this respect, she highlighted:
- The importance of selecting and prioritizing facility replacement needs and yet having the “flexibility” to make adjustments as the program proceeds;
- The slew of permitting requirements at the state and federal levels from such a large volume of projects going on in the same general timeframe; and
- The time pressure of hitting completion targets associated with the annual filings – i.e., getting facilities “in service by a certain date” pursuant to the procedures of the tariff.
Carter also marveled at the extent of public opposition aroused to projects whose principal objectives were enhancing the system’s reliability and safety.
Moreover, Columbia had to assume some financial risk. By agreeing to a long-term rate case moratorium as part of the deal, Carter noted, should costs increase to an unforeseen extent, the pipeline would be “stuck.” However, on balance, the comprehensive settlement approach has proven to be a good thing for the company and customers alike, she concluded.
Kevin Frank – Atmos Energy. The focus of Frank’s presentation as the lone LDC/shipper representative on the panel was the customers’ response when, in March 2013 the Gulf South interstate pipeline proposed to “abandon” roughly 25% of its system (amounting to 2000 miles of pipe) on the ground that these segments were aging and underutilized. Frank contrasted the situation confronting LDC shippers on Gulf South with that of Columbia’s customers discussed in the preceding presentation (where those customers could benefit not only from a “modernization” program’s improvements in safety and reliability but also from load growth and enhanced access to inexpensive Marcellus gas). Gulf South customers did not have load growth or cheaper gas as additional carrots, he noted.
The Gulf South pipeline flows its gas primarily through Texas, Louisiana, and Mississippi. The thrust of its restructuring proposal was not to literally abandon the 25% of its system at issue, but rather to withdraw these segments from FERC regulation by making them intrastate “Hinshaw” pipelines. This would switch regulation of their rates away from FERC to the three respective state commissions.
Alongside the rationale that age and decline in usage justified abandonment of the targeted segments was Gulf South’s concern that, if it simply rehabilitated these segments without the jurisdictional shift, many customers not directly benefiting from these upgrades would complain about higher rates “subsidizing” the subset of customers whose service would be preserved. The pipeline also feared that a conventional rate case filing to recover the aging infrastructure upgrade costs could, by broadly pushing rates upwards, trigger a “death spiral” scenario (where some customers would bypass the more expensive Gulf South system, raising rates further on remaining customers – and spurring even more bypass threats).
The “abandonment” contemplated by Gulf South would have been, in size and scope, the largest in FERC history, Frank stated, and the customer reaction was predictable: waves of protests from shippers and affected states alike. An especially unpopular consequence of the proposal would be “rate pancaking,” where “through shippers” would potentially face both a FERC-approved interstate rate and multiple state-regulated rates on the Hinshaw segments. These criticisms did not necessary misconstrue Gulf South’s game plan, Frank claimed; the company’s intent was to blunt “subsidization” and “cost shifting” attacks by carving out the segments needing reinvestment and then appealing to state commissions to obtain cost recovery through significantly higher rates.
The shippers felt they were in a strong position to resist Gulf South’s plan because the Commission applies a high bar to abandonment applications, Frank asserted. And indeed, the Commission denied the request for abandonment in the face of massive customer protests and advised the pipeline (in Frank’s paraphrase): “Maybe you should file a rate case.”
That is what Gulf South did next, filing its first rate case in nearly 20 years. This time around, it tried to ward off the “subsidy” argument from some customer groups by subdividing the interstate system into zones, with the aging, underutilized segments bearing higher costs and rates. This led to yet another surprising customer-driven twist: their response was to forego an inter-customer war by instead unanimously agreeing to support a postage-stamp interstate rate. That provided the template for the settlement approved by FERC late last year.
Thus, as Frank put it, “everyone is sort of subsidizing everybody else and sharing the pain of the upgrades.” But it’s the customers’ hope moving forward that, with the higher rates Gulf South will be able achieve, it will have the “comfort” to go ahead and repair, replace, or upgrade the older facilities. And while rates are stabilized under a seven-year moratorium built into the settlement agreement, Gulf South did not accept all the risk of unexpectedly higher costs; to the extent PHMSA or EPA imposes new rules, Gulf South may make a filing to recover the related expenditures in rates.
Dennis Kelly – American Midstream Partners. The other key panel member, Kelly, began with an account of the long and colorful history of an interstate pipeline constructed to bring gas out of the Monroe, Louisiana Gas Field – first discovered in 1916 and by 1924 the largest gas field in the world. Owned mostly by Standard Oil of New Jersey, the better part of its production was initially used to produce carbon black – an application the Louisiana Department of Conservation condemned as “inefficient, wasteful, and reckless.”
Two years later, beginning in 1926, the Midla interstate pipeline was constructed to transport the gas field’s output to more distant markets. Running south from the Monroe field for 355 miles to the Baton Rouge area, the system crossed the Mississippi River near Natchez and traversed the southwest corner of Mississippi before reentering Louisiana north of Baton Rouge.
Kelly termed the Midla project a “remarkable achievement” in its day; but by 2013, it was an antiquated, leaky relic that was a prime candidate for abandonment. The Baton Rouge refinery that was its principal industrial customer no longer relied on any Monroe Field gas, and the portions of Louisiana and Mississippi it traversed were thinly populated and generally lacking in industrial load. The largest metro area it served, Natchez, Mississippi, had a population of only 18,000.
With such small-scale markets, a reconstruction of the original Midla line would have required a “significant” rate increase. (Kelly later elaborated that this increase would have been on the order of 1400%, from $8/Dth/mo. to “well over $100/Dth/mo.”)
The owner of the Midla system, American Midstream, initiated discussions with customers, regulators, and other stakeholders in May 2013 that continued until November. At that time, the company proposed a line rebuild; but in an open season held that December, there were no takers. Negotiations with customers broke off in January 2014, leading to a 3/28/14 abandonment filing at FERC. That step provoked considerable customer opposition and a general public uproar, with politicians and the media jumping in.
Panelist Kevin Frank of Atmos at this point interjected that his company was one of the largest LDCs taking gas from the Midla pipeline, serving the Natchez area. He noted that the price tag for rebuilding the line was $200 million, and both the customers and the company agreed spending that much did not seem practical under the circumstances. On the other hand, he remarked, you can’t just cut off a town of Natchez’s size and tell folks to go out and buy propane tanks.
Frank then related that Atmos declined to participate at all in the open season (where one of the terms was that failure to participate would be deemed “consent” to abandonment) and proceeded to file a complaint at FERC over American Midstream’s business tactics. He added that this was when the LDC’s relationship with the pipeline was “at its most adversarial.”
Resuming his presentation, Kelly related that, with the company abandonment and customer complaint pleadings filed, the parties then entered a new phase of negotiations pursuant to FERC’s ADR service. The negotiations eventually bore fruit, culminating in the filing of an uncontested settlement in December 2014. FERC approved the settlement in April 2015, and in June 2015 the company filed an application for authority to construct the Midla-Natchez pipeline, a reconceived, reduced version of a complete rebuild of the old Midla line. FERC granted authorization in December 2015.
Frank weighed in at this point to underscore it was important for Atmos, as an LDC subject to state jurisdiction, to have the buy-in of both relevant state regulatory commissions. Hence, the LDC had insisted that the regulators participate in the ADR negotiations under FERC’s auspices. Kelly agreed it was “critical” to have the two state commissions involved, so that they understood the full basis for the settlement and that their participation, especially with regard to where service had to be abandoned, was in fact helpful to the overall effort.
In the end, said Kelly, the reconstruction of part of the old Midla pipeline provided for a continuation of service to two main distribution customers – Atmos and an association of municipal customers. The new rates for the rebuilt facility would be phased in over a number of years so that the significantly higher rates would not hit retail customers at once.
There were three other types of customer solutions composing the settlement:
- Customers for whom American Midstream would construct a new connection to another interstate system;
- Customers to whom portions of the old system would be transferred;
- Customers who would be converted to propane.
The company agreed to bear the costs of all three alternate solutions.
Kelly quipped that it must have been a good settlement because “nobody got what they wanted. There was a lot of give and take in the process.” He also credited the company’s field personnel as “invaluable” in helping to arrive at the more “creative,” customized solutions for customer groups that would not be served by the Midla rebuild.
It was also helpful that the two large LDCs that would be served – Atmos and the municipal group – would be able to spread some of the increased cost of service from the rebuilt Midla-Natchez line over a larger customer base than simply those customers who were facing abandonment – an outcome that Frank observed was good for the state in general. He added that having state regulators participate in the negotiations was especially important in accomplishing this cost-spreading feature.
 The acronym “PHMSA” stands for the Pipeline and Hazardous Materials Safety Administration.
 FR No. 3100, pp 1-5.
 The Columbia Pipeline Group website identifies “subsidiaries of National Grid and DTE Energy” as well as Columbia as co-sponsors.
 Carter noted $60 million in refunds and $50 million in cost of service decreases.
 Customers also got a benefit because increased access to new, lower-cost gas supplies in the Marcellus region offset out-of-pocket costs.
 Columbia has replaced 129 miles of “bare steel and wrought iron.”
 Although modernization does not involve building entirely new pipelines, it does involve some looping and other construction activities triggering environmental permitting requirements.
 The standard he cited is that abandonment of interstate service is not permitted if not consistent with “the present or future public convenience or necessity.”
 “ADR” stands for alternative dispute resolution.
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