The 2018 Marcellus-Utica Midstream conference (MUM) opened with keynote speaker Robert Phillips, chairman, president and CEO of Crestwood Equity Partners LP, declaring “2017 was a good year, 2018 is going to be a great year” for his company, which operates diversified midstream assets in active basins across the U.S., including a significant gathering operation in the Marcellus.

He also told an audience of about 1,000 in Pittsburgh late January that the Marcellus-Utica’s unparalled natural gas resources have long-term growth potential not only for Crestwood, but also the entire industry. “In our view, it has an endless supply of gas for both the Northeast gas markets and the rest of the U.S.”

Already, the Marcellus-Utica accounts for 35% of natural gas production in the U.S. at about 22 billion cubic feet per day (Bcf/d) to 25 Bcf/d. “It is the largest single source and a vital source to all the markets now,” Phillips said.

But he cautioned that such long-term outlooks for the Marcellus-Utica—particularly beyond 2020—are dependent on several factors, not the least of which is the need for additional infrastructure.

“Today there are approximately 17.5 Bcf/d of pipeline projects underway. Most of those were underwritten by producers,” he said. “We believe most of those projects will largely fill up in the next three years. Therefore, we may be right back here needing more projects to drive more supply development.”

Phillips said Northeast Pennsylvania growth forecasts are entirely contingent on takeaway capacity. “We think it’s dependent on how many projects we can get out,” he said. “We think Northeast Pennsylvania needs another 3 to 5 Bcf/d to realize its full potential.”

Of course, building more takeaway capacity faces regulatory challenges. Phillips said Crestwood operates in several basins across the U.S. so he couldn’t say that the regulatory environment was any more challenging in the Northeast U.S. than anywhere else, but admitted that regulatory difficulties in the Marcellus-Utica are significant and threaten future natural gas growth in the region.

“This is hand-to-hand combat in this region. Not only do we have to deal with the federal regulatory environment, but also numerous state-level regulatory agencies that have to clear to get projects built to evacuate that gas and get it exported,” he said.

For that reason, Phillips said southwestern Marcellus has an advantage that will continue to lead to a “fairly large basin [price] differential” that will work against the producers in Northeast Pennsylvania from an economics standpoint.

Phillips also cited the need to manage the region’s volatility. Crestwood owns 50% of the Stagecoach storage facility in Northeast Pennsylvania. “We live on volatility. We predict more volatility. We’ve seen it this winter,” he said. He said it’s another reason the region needs even more connectivity to manage demand and growth as well as price swings.

He said this winter’s cold spell produced a spike in prices. “It’s a real demand event that we haven’t had in about four years. We’ll continue to see that spike when we have that kind of demand and limited supply,” he warned.

Phillips also believes the region has a need for more NGL services.

“We view the Marcellus-Utica as a significant NGL supply basin,” he said. “We expect to go from supply of about 225,000 barrels per day [bbl/d] in 2016 to 300,000 in 2020. In the entire Marcellus region we are currently running about 500,000 to 600,000 bbl/d. Our forecasts have that going to 800,000 to 900,000bbl/d. We need more takeaway and we need more service to the local markets.”

Demand-driven projects

As major pipeline projects, including Rover, Mountain Valley and Atlantic Coast, move forward in their quest to unlock new markets for Appalachian gas, participants at MUM discussed prospects for the next round of projects likely to emerge based on abundant Appalachian gas.

Eureka Midstream president Chris Akers said the impact of the Rover Pipeline, starting up early in 2018, was “going to be positive,” but noted it “was just one piece of getting gas out of the basin. With the Atlantic Coast and Mountain Valley pipelines taking gas to the southeast, and other projects going to the west and northeast, I think the basin is now getting well-shaped to be able to get gas and/or NGL out of the basin.”

Steve Woodward, senior vice president of business development for Antero Resources Corp., cited a “change going toward demand-driven projects,” with the Atlantic Coast Pipeline as an example. “It was a much needed project to come in, and we’re excited to see that project move forward,” he said.

“As far as the future for additional projects out the basin,” Woodward continued, “the thing that I’ve been promoting is the concept of meeting halfway with demand. We’ve been talking to a number of utilities; we’ve been talking to various co-gen projects and combined cycle projects, trying to figure out ways to meet halfway on reservation.”

As additional infrastructure is built in the basin, “we’re seeing that the cost is exceeding $1, and at current Nymex gas prices, it’s pretty tough for a producer to stomach the takeaway. I used to use the rule many years ago that you don’t want to spend more than 10% of the commodity price on firm transportation. Needless to say, this basin has been a very costly basin, and we’ve all exceeded that parameter,” Woodward said.

As a result, the industry is “trying to look forward, as utilities need more gas, and do some form of sharing mechanism,” he said. “What we’re seeing is that a lot of the people that are in the middle of these long-haul pipelines between the Gulf Coast and Appalachia are stepping up. Because the long-haul transport keeps the gas from one end of the pipe to the other, the guy in the middle sometimes gets left out, and so he really has to create his own destiny and step up and say, ‘I want to be part of this. Let me help sponsor some takeaway.’ We’re excited that we’re having those sorts of discussions with people midway between the Gulf and Appalachia.”

Speakers at MUM also discussed changing views on acreage dedications and volume commitments. Dana Bryant, senior vice president, midstream and marketing with Eclipse Resources Corp., noted that as development drilling has expanded in the basin, volume commitments have followed.

“There’s more certainty,” noted Bryant. “You’re more willing to make a volume commitment.”

Akers concurred with Bryant’s assessment. “An acreage dedication is nice, but if it’s not being produced, and if it’s not being backed by MVCs [minimum volume commitments] or a reservation charge, it really doesn’t pay the bills,” he observed. “There’s enough production in the area now that you can feel some level of security as to what’s going to happen. We’d love to have acreage dedication, but we’d much rather have MVCs.”

Woodward noted a more “hybrid structure” evolving in some areas.

“What we’ve seen, particularly in the development of the Appalachian region—the most capital-intensive gas basin in the United States—is a kind of a hybrid structure, where you’ll have a dedication, but you’ll also have some form of reservation charge,” he said. “There’s typically a modified fixed and variable component of the reservation fee coupled with some form of acreage dedication. That seems to have worked well for a lot of the relationships between producers and their midstream counterparts.”

Akers pointed to a move to more risk-sharing between the midstream and the upstream sectors.

“One of the things I think is growing more and more important is having the midstream company start sharing some of the risk and the upside with producers—so more of a joint relationship than we’ve seen in the past, with the midstream provider sharing in the risk and the upside,” he said.

In addition to higher commodity prices—as well as rapid well connections and reliable flow of wells—what else makes for a more effective midstream operation?

“We try to work out relationships that work for both parties,” stated Akers. “We believe in shared success. And once that contract is in place, you still have to be a little bit flexible outside the contract.”

As an example of the above, Bryant pointed to Eclipse’s ability to work with Eureka on natural gas usage.

“Eclipse is using natural gas to fuel drilling and completions, so we work with Eureka in getting access to natural gas off the system to fuel our operations,” she said. “We have to work together potentially out of the four corners of the contract to make that work for everyone.”

Given the integrated relationship between upstream and midstream, ways to create value are easier to identify in the Antero family of companies.

“We’ve found a good way to get the value is not just to get good netbacks on our upstream company, but also to share in the value of the midstream through getting dividends [from the midstream MLP, Antero Midstream Partners LP and its Antero Midstream GP].”

“Our midstream company enjoys a very reliable company on the upstream side,” he winked. “And the company has a very well-planned drilling plan.”

Len Vermillion can be reached at lvermillion@hartenergy.com or @LenVermillion.

FERC Back In Business

Commissioner Robert Powelson of the Federal Energy Regulatory Commission (FERC) had a vote in determining whether projects moved forward—that anyone had a vote on a panel which lacked a quorum for six months last year.

“We are back in business at the FERC,” Powelson told an approving crowd at MUM.

Powelson, nominated by President Donald Trump last May and confirmed as a FERC commissioner in August 2017, came to the federal agency after almost nine years on the Pennsylvania Public Utility Commission (PUC). Since seats were filled last summer, the commission has moved quickly.

“Within the last seven months, this current makeup of Federal Energy Regulatory Commissioners have approved $25.6 billion in pipeline infrastructure in this country,” Powelson said. “As I like to remind people, when you’re a five-member independent agency, you can come up with a lot of solutions to the problems but you can’t buy No. 2 pencils unless you have three votes; it’s that simple.”

Among the recent approvals, Powelson listed:

  • Atlantic Coast Pipeline, a $5.1 billion, 600-mile project between West Virginia and eastern North Carolina, scheduled for completion in 2019;
  • Mountain Valley Pipeline, EQT Corp.’s $3.5 billion, 303-mile line between northwestern West Virginia and southern Virginia; and
  • PennEast Pipeline, a 115-mile line connecting the Marcellus Shale in northeast Pennsylvania to New Jersey.

Powelson also gave an extended shout-out to Dominion’s Cove Point LNG terminal, set to begin operations in March, and noted the geopolitical importance of developing U.S. gas exports.

“The exploration of natural gas and the ability to move it to market is the greatest peace dividend we have,” he said.

He recalled how, during his years on the Pennsylvania PUC, a delegation from Kosovo described how Russian gas pipelines were shut off in the middle of a cold winter snap, shutting down power plants and leaving citizens without heat.

“Can you imagine that in this country?” he asked. “In this construct, with rule-of-law markets, that any operator could do that to an American citizen, an American ratepayer? But that’s the reality of how the Russians are playing with these markets. I think it’s disruptive and I think if we get our act together around LNG exports, I think we have a tremendous opportunity in front of us.”

But Powelson expressed his own concerns about the U.S., especially regarding the radical price spikes experienced by the New England market during the recent bomb cyclone storm that struck the region. Some spot prices for natural gas soared as high as $141 per million British thermal unit during the storm.

Less than 500 miles from the New England market and its massive price blowout sits the Transco Leidy hub, he noted. Yet the 15 million customers in the market, despite living within driving distance of the cheapest natural gas in the country, pay the highest prices, not only during severe weather events like the bomb cyclone but on average going back to 2014.

“It is alarming,” Powelson said. “It’s alarming for FERC. It’s alarming for governors in the New England market who objectively have been committed to solving their lack of pipeline capacity into the market. It really speaks to where we need to look ahead in terms of solving this energy calculus equation.”

Ironically, a region that is pushing for clean energy sources was forced to burn 2 million barrels of oil during the bitter four-day cold snap in January when natural gas supplies were insufficient. Powelson noted that Repsol’s Canaport facility in St. John, New Brunswick, with 10 billion cubic feet (Bcf) of storage, went through almost 1.8 Bcf during the bomb cyclone.

“The New England ISO [utility] has alerted us that if that facility ever went down, it could create a cascading event in the power sector in New England where between 5,000 and 7,500 megawatts of combined-cycle generation would come offline,” he said. “That’s very alarming. Again, it’s something that is critically important to the FERC and you as industry partners as we work together to solve that problem.”

Joseph Markman can be reached at jmarkman@hartenergy.com and @JHMarkman.