For natural gas in the Permian Basin, there seems no way out. For gas in the Northeast, there seems no way in.
The outlook for demand growth in power generation and petrochemicals is still positive, but the easy gains are over. Export markets look strong but increasingly crowded. Operators and investors are clearly still keen on the gas midstream, even as they ask critical questions about issues ranging from final end-use markets to the continuing embarrassment of massive flaring.
Gas? It’s complicated. But multiple projects and markets could ease the situation.
In June, The Williams Cos. formed a $3.8 billion joint venture with the Canada Pension Plan Investment Board (CPPIB) in the Marcellus/Utica shales that includes two systems owned and operated by Williams: the Ohio Valley Midstream (OVM) in the western Marcellus and the Utica East Ohio Midstream (UEO). The finalization of the agreement, originally announced in March, includes CPPIB investment of about $1.33 billion for a 35% stake in the partnership. Williams retains the rest and operates the combined business.
Williams expects that combining UEO and OVM will create a more efficient platform for capital spending in the region, resulting in reduced operating and maintenance expenses, and develop enhanced capabilities and benefits for producers in the area.
Williams will use the cash proceeds to offset the purchase price of its acquisition of the 38% of UEO it did not previously own from Momentum Midstream. The balance will pay down debt and fund Williams’s long list of growth projects. The Tulsa, Okla.-based firm ranks No. 6 on the current Midstream Business Midstream 50 list of the sector’s largest publicly held firms.
“The funding from CPPIB paid for UEO as well as provided funding for our current growth projects so we did not have to take on debt in 2019,” Micheal Dunn, Williams’ executive vice president and COO told Midstream Business, “and it’s a large list [of growth projects].”
In May, the Federal Energy Regulatory Commission (FERC) issued a certificate of public convenience and necessity authorizing the Northeast Supply Enhancement (NESE) project, an expansion of the existing Transco gas pipeline that is designed to serve New York markets in time for the 2020/2021 winter heating season. The NESE project will provide 400,000 dekatherms per day of additional gas supply to National Grid Inc.—the largest distributor of natural gas in the northeastern U.S.
National Grid is converting about 8,000 customers per year from heating oil to gas in New York City and Long Island. According to Williams, “the NESE is critical to make those conversions possible, as well as keep up with new development in the area.”
Transco is the nation’s largest-volume interstate gas pipeline system, a 10,000-mile network with a mainline running nearly 1,800 miles from South Texas through 12 Southeast and Atlantic Seaboard states. NESE will expand existing infrastructure in Pennsylvania, New Jersey and New York primarily by looping—placing new pipe alongside of existing pipe parallel to the existing right of way.
The project plans about 10 miles of 42-inch line looping facilities, three miles of onshore 26-inch looping facilities, 23 miles of offshore 26-inch looping facilities, the addition of 21,902 horsepower at an existing compressor station, a new 32,000 horsepower compressor station and related appurtenant facilities. According to researchers at the Edward J. Bloustein School of Planning and Public Policy, the design and construction of NESE will generate more than $325 million in economic activity in the three states.
With FERC approval in hand for NESE, the last hurdles are state permits.
Williams has resubmitted its permits from New York and New Jersey after having the initial submission rejected “for minor issues,” said Dunn. That resubmission restarts an up to yearlong window that regulators have to evaluate the application. Stressing that regulators will take as much time as they need, Dunn said the company “contemplates starting preliminary onshore work this fall, with offshore work beginning next year. We hope to have the project completed in time for the 2020-21 heating season.”
“Pipeline bottlenecks because of states’ obstruction to expansion projects make steel in the ground all the more valuable,” Ethan H. Bellamy, senior research analyst at Baird Equity Research, told Midstream Business. “That is especially the case in the Northeast. There are similar risks in Colorado that have made assets in Wyoming more valuable. It still looks like clear sailing for expansion along the major routes from the Permian to the Gulf Coast, with the possible exception of some activism in New Mexico.”
Returning to the global macroeconomic level, Bellamy stated emphatically that “switching power generation from coal to gas remains the best way to produce baseload electricity. A negative price for gas in West Texas will bring down global gas prices. That will reinforce the economic proposition for gas over coal—even without considering the particulate and other environmental concerns.”
Bellamy also offered some perspective on localized and even regional negative pricing for the resource.
“Oil and gas is still a mining business, and the mining company that wins is the one that can produce the resource at the lowest cost. Given the volumes being flared in the Permian, any beneficial use is literally trash to cash,” he said.
The NESE “is incredibly important to the region,” Dunn explained. “There are great benefits for National Grid [the regional utility] to convert fuel-oil users in Brooklyn and Long Island to natural gas. That conversion can mean as much as a 50% reduction in annual energy costs for residential customers. It also benefits the airshed in comparison to emissions from fuel oil. The environmental benefits are things that opponents of the project are not talking about, but we are.”
The minimal changes required in the permit applications can be taken as a positive sign, Dunn added.
“Regulators were coming up on the one-year deadline for responding to the initial permit applications. If they did not act before the one-year deadline, they would have waived their rights to issue a [Clean Water Act Section] 401 water quality certification, so they had to act. We responded quickly to their requests and are hopeful they will process the current applications timely in order to allow construction to begin this fall.”
Chink in the armor
Interests opposed to hydrocarbon fuels in general—and gas produced by hydraulic fracturing in particular—have found pipeline permits to be an effective point of resistance. As noted by industry leaders and analysts, it is easier and less expensive to get Marcellus ethane 3,000 miles by tanker to Europe than it is to get Marcellus methane 300 miles by pipeline to New England.
“It is less expensive to build pipelines underwater in the Gulf of Mexico than it is to build on land in Pennsylvania, New Jersey or New York,” Dunn lamented.
“We are doing what we can to balance the debate,” he said. “Our industry has mostly been out-of-sight, out-of-mind. It used to be that a certification from FERC was sufficient to proceed. Now we are doing more outreach. The Atlantic Sunrise project was a great example of that. We got all stakeholders involved.”
In September 2018, Williams was recognized by the International Association for Public Participation (IAPP) for collaborating with the public and other stakeholders during the planning phase of the Atlantic Sunrise pipeline project. The IAPP is an international federation of professionals in 26 countries working to advance the practice of public participation.
During the planning phase of the nearly 200-mile Atlantic Sunrise Pipeline, Williams collaborated with landowners and other stakeholders to adopt approximately 400 changes affecting more than half of the originally designed, greenfield route. The company used public meetings, contact with local officials, community leaders and affected landowners to identify and attempt to resolve issues or concerns prior to submitting its federal certificate permit application.
The project’s public engagement efforts also included the development and implementation of a voluntary $2.5-million environmental stewardship program designed to benefit resources and support communities within the Atlantic Sunrise project area.
IAP2 judges said Williams’ work on Atlantic Sunrise helped raise the bar in the field of public engagement, “setting a new standard” for the pipeline industry.
“Investing one-on-one time for effective stakeholder relationships is an integral component of successful public outreach,” said Mike Atchie, public outreach manager for Williams.
The Atlantic Sunrise project was designed to expand Williams’ existing Transco pipeline to connect abundant Marcellus gas supplies with markets in the Mid-Atlantic and southeastern U.S. It went into service in the fourth quarter of 2018.
Still, “all politics is local,” as former Speaker of the House Thomas Tip O’Neill (D-Mass.) once observed. Greg Haas, director of integrated energy at Stratas Advisors, a Hart Energy company, cited a recent situation where local politics cut in favor of gas. “A Northeast utility declared that because it could not get additional incoming gas pipelines built, no new residential connections would be made and all commercial customers would be locked into their existing volumes, or less. That was a serious threat to the growth of local businesses.”
Suddenly, people clamored for more gas. “It became a pocketbook issue to residents—taxpayers and voters—as well as to businesses,” Haas told Midstream Business. “The opposition to the pipeline blockaders became very vocal. When you threaten local development, even home renovations, people get upset.”
While certainly not advocating brinksmanship on the part of utilities, Haas anticipated that “We are going to see more limits on gas at the burner tip if politicians do not allow more gas to get to consumers. In most cases, the blockaded development is not limited to greenfield pipe, but also to simple looping or other expansion projects on existing lines in their rights of way.”
At the opposite end of the country, the opposite problem prevails. Haas likens questions about getting gas out of the Permian to the family road trip where one or another of the kids keeps asking, ‘Are we there yet?’
“I don’t think we are ever going to get there,” said Haas. “We need 1.5 to 2 billion cubic feet per day (Bcf/d) of new transportation out of the Permian every year through the middle of the decade. There is some capacity coming on later this year and into next. So instead of asking ‘are we there yet,’ the better question is, ‘how much more do we need to add each year?’ We are on a treadmill.”
Control has become a little more evident in one important aspect of Permian production: the profligate flaring that has plagued the play for years. States are now doing the control that has been missing.
In contrast, there does not seem to be much constructive regulatory movement in the Northeast. “There is a lot of activism in all the statehouses,” said Haas. “A lot of politicians believe that blocking fossil fuel is a winning ticket, especially in New York and New Jersey.”
One extreme example was a few years ago when Vermont banned hydraulic fracturing. There are about 35 states with commercial hydrocarbon reserves, but the Green Mountain State is one of the few that does not. So Vermont banning fracking is very much like Saudi Arabia banning snowball fights.
It bears mentioning that the first flaring permit challenge has come from a midstream company, with Williams challenging a permit application by Exco. The producer claims it is cheaper to flare than to pay for gathering and processing.
“The business and regulatory question is what to waste, money or molecules?” said Bellamy.
That is just one challenge, but Bellamy suggested it is only a matter of time until those opposed to flaring start challenging every permit. If every producer had to defend every flaring permit, there would have to be changes in the way industry makes its economic assumptions.
“We just had a call with a major industry executive,” Bellamy added. “He agreed that large-scale flaring is a black eye for the industry and called for more regulation of the practice. It is reasonable that a producer ought to have a plan for getting associated gas to a pipeline as part of any development project.”
Calls for regulation on the issue also make sense in the interest of keeping the playing field level. Companies that take stewardship should not be at a disadvantage to their more profligate competitors.
Because of midstream constraints, the price of gas in West Texas has recently dipped into negative territory.
“If producers can flare it, the value is zero, so I guess that is an upgrade,” David Foley, senior managing director and CEO at Blackstone Energy Partners, told Midstream Business. “That is the current reality, but it isn’t good for the environment, and I think it is a temporary anomaly. All that it says is that we need more pipelines. Nature abhors a vacuum, and the market abhors a wide differential.
“The crude differential is likely to be alleviated later this year. We need another dry-gas pipe, and also NGL takeaway, perhaps to a different destination than [NGL hub] Mont Belvieu. That could be anywhere on the Gulf Coast where there is petrochemical manufacturing,” he added.
Global NGL demand
Even as midstream operators labor to get molecules to market, the looming strategic question beyond domestic pipeline bottlenecks is continued demand. “Gluts flow downstream,” said Haas. The bonanza in gas, especially rich associated gas, has already created a surfeit of NGLs too.
“The glut in ethane and propane is already rolling downhill to the North American polymer market. The place of last consumption is the end user,” he added. For NGLs into polymers and gas into LNG alike, the final frontier seems more and more to be exports.
Haas made a presentation at Hart Energy’s recent DUG East Conference in Pittsburgh on exactly that topic.
“I came away from that event noticing that attendees were rightly wondering where the demand would be coming from,” he cautioned. “Producers have stopped drilling so hard, but they are still converting their DUCs [drilled but uncompleted wells], so production continues to rise. Upstream and midstream operators have to think through where all that gas is going to go.”
The ready answer seems to be LNG exports (see “To Market, To Market”).
Backing out coal
Gas replacement of coal-fired electrical generation is taken as a given, especially in North America and Europe, with vast potential in the rest of the world. That is true, but not unalloyed. There is some purely political pushback for coal under the current U.S. administration, but the bigger concern is that the low-hanging fruit has already been claimed.
There are still many retirements of coal-fired power, but with wind and solar now well established and even setting the incremental cost of generation in some wholesale regions, gas cannot assume every coal kilowatt lost is a gas kilowatt gained.
Overseas, the problem is the opposite. Both India and China have extensive plans for new coal-fired power. That plays to their own nationalistic interests, in the use of domestic fuel sources and minimized dependence on imported fuels.
“Even with coal disfavored in North America and Europe, we don’t anticipate $3 gas until the middle of the decade,” said Haas. “Prices had been $2.60- to $2.70 per thousand cubic feet, but that has sunk dramatically to about $2.30. That is below average relative to sub-average storage levels for early summer that presently exist. And, we have seen above-average storage injections this year, because of growth in production already noted, as well as delays in LNG exports.”
Those delays do not reflect serious problems, only normal slippage in schedules for construction and startup. Still, the situation has led to billions of cubic feet being put into storage,” said Haas.
He reiterated that the strategic, even macroeconomic, question for all North American hydrocarbon producers is, “‘Where is the ultimate demand going to be?’ We see potential gas demand for fuel worldwide, also as a raw material for fertilizers and petrochemicals. There is industrial demand for the renewed glass and steel industries. Low gas costs should make this a profitable year for those companies.”
Upping the ante
Blackstone’s Eagle Claw Midstream LLC, active in the Permian’s Delaware Basin, is a prime example.
“Since our original investment in Eagle Claw, that operator has tripled the acres of production dedicated to it to now well more than 600,000,” said Foley. “It has also tripled its pipeline miles to 1,100 and quadrupled its processing capacity to 1.3 Bcf/d. It is significantly larger than the second-largest private operator. The customer count has now increased significantly, including some very large acreage dedications from supermajors. We are at the scale where we can be of service to the largest producers.”
Most of that has been done through organic growth that has been augmented by acquisitions. Those, notably of CapRock and Pinnacle, have allowed Eagle Claw to expand into water and even a bit of crude. Water is extremely important because, as Foley noted dryly, “you can’t flare water.”
Growth in the Permian midstream is not just about expanding operations and one’s customer base, Foley explained.
“It is not just playing the hand that you are dealt. It requires active management, increasing your bet and drawing more cards—really working it.”
The genesis of several of Blackstone’s recent midstream investments came from Foley’s frustration over lack of producer discipline contributing to continued declines in natural gas prices.
A ‘rocket ship’
“We believed that incremental production of natural gas associated with oil wells in the Permian basin was going to grow at a rapid rate, a rocket ship really, representing more of the growth in U.S. gas production than from any gas-focused basin. It’s very hard to make money producing gas if the most active drillers are the ones who don’t care about the gas price because it is a byproduct of their oil production.
“We saw that existing midstream infrastructure was going to be inadequate and that basis differentials for natural gas and natural gas liquids in the Permian were going to blow out and create attractive opportunities to invest in the construction of new pipelines, processing and export facilities,” he added.
Foley sees continued growth in petrochemicals capacity, led by supermajors such as Exxon. “We have about 30 million metric tons per year [elsewhere referred to as million metric tons per annum or mpta] of ethylene cracker capacity now,” he said, “There is another 4.5 MMt/y coming into service this year and a further 4.8 MMt/y in 2020 and beyond. That is a 30% increase in a little more than two years.”
Foley also noted with satisfaction that, “We were the first and largest investor in Cheniere’s LNG export complex at Sabine Pass [La.], investing $1.5 billion back in 2012 that was critically needed to start construction of the facility.”
That initial investment has since converted into equity ownership of Cheniere Energy Partners that is worth approximately 5x Blackstone’s cost basis. In addition to the massive and still-growing liquefaction capacity, Cheniere has 20-year take-or-pay contracts with global major customers and pays a healthy cash dividend.
Foley anticipates the gas sector, both domestically and internationally, will undergo the same disintermediation as the oil sector did in the later decades of the 20th century. “It will be in fits and starts, but gas will be more actively traded.”
Electrons and molecules
One of the great frustrations of potential in the gas market has been Mexico. For years now, players have lamented that gas, which is much needed in Mexico, has adequate capacity to get to the border, but the pipeline network within Mexico necessary to deliver the gas has experienced significant development delays.
There is equal vexation in Mexico, which finds itself importing LNG at higher, global prices. One innovative approach is moving downstream all the way to generation.
“Sometimes it is easier to export electricity than natural gas molecules,” said Foley. “We have a power plant on the border. We are buying gas at U.S. domestic discounts, and selling electricity at Mexican premiums.”
One wrinkle in the grand plan to turn light liquids into olefins and then into polymers to ship to Asia is that there are companies in China and elsewhere in the region that want to produce plastics locally, and there are companies in the U.S. keen to sell them both alkanes and olefins.
“China has projects to take U.S. ethane to produce olefins and polymers,” Andrew Reed, principal and head of NLGs at ESAI Energy, told Midstream Business. The demand is growing, but, Reed added, “There is not room for all of this. There is an over-exuberance about the export market. The early movers among the exporters along the Gulf Coast are probably safe. Naphtha exports will probably be the first to feel the pressure.”
According to ESAI research, China has 35 mtpa of new ethylene capacity announced for this year through 2024. Some of that will be delayed, and some will be cancelled, but a significant amount will be completed.
In the same timeframe, the U.S. is adding about 10 mtpa of steam cracker capacity, onto a base capacity of about 34 mtpa. Global demand increases about 6 mtpa, which would total 30 mtpa through 2024. The announced plans for the U.S. and China alone—never mind any further announcements or incremental increases of existing facilities—is already 45 mtpa.
“Clearly, the world is not ready for this much,” said Reed. More broadly, he added, “From an NGLs perspective, we are coming from a bottleneck situation in terms of takeaway, fractionation, and LPG export terminals and quickly moving to build out capacity that will move ahead of export markets. That is especially true in LPG. Demand will adjust to the new supply, but that demand cannot grow fast enough to support the amount of exports already planned. I often perceive that some of the production and export plans fail to take into account the export market realities.”
There are some incremental increases possible from domestic demand, but the only viable volume markets are international: notably household use in Southeast Asia and petrochemical demand worldwide. Tanker utilization is likely to increase, but it is not yet clear if additional bottoms will be needed.
“No one demand sector will be able to lift LPG,” said Reed. “It will take all downstream developments from PDH to household use.”
Electric power has indeed offered the lion’s share of gas demand for the better part of the past decade at the expense of coal-fired installed capacity, noted Christopher Sighinolfi, managing director for gas, utilities, midstream and refining at Jefferies.
“But the low-hanging fruit has been gathered. Renewables have lowered their cost structure and increased their rates of growth, albeit from a low base. They have now reached double digits in terms of capacity composition, so from now on growth [for renewables] will have a more measured pace,” he told Midstream Business.
Most analysts also expect that there will be further retirements of coal-fired power, but the pace of their replacement will be slower than in recent years. If at the same time renewables have established themselves as a major source of baseline power, the only other likely segment would be nuclear.
“I recently spoke with Neil Chatterjee, chairman of the FERC, about the nuclear fleet,” said Sighinolfi. “Nuclear power is carbon-free and provides stable, high-paying jobs. But for many other reasons it does not totally jibe with the outlook of the environmental community, most notably because of the persistent question of what to do with spent fuel. There is also the shadow of Fukushima.”
Given the unknowns, the simplest outlook is back to gas replacement of coal. “Gas versus coal is straight economics,” said Sighinolfi. “From now on it is likely to be choppy, very episodic,” driven by the relative prices of the fuels and other regional factors.
This puts even more emphasis on exports—of LNG, or NGLs, or polyolefins, or even crude.
Which makes Sighinolfi uneasy.
“A lot of people have pivoted to exports as the answer. We hear it in every company presentation. Now a case can be made about the relative imbalance in energy consumption in Asia as compared to Europe or North America. But I am a little uncomfortable about so many companies relying so much on exports to Asia. Not the least because we don’t have good data on the region. People are used to the data we get from the Energy Information Administration in the U.S. That level of insight does not exist in other parts of the world. As soon as you export, the data get much less clear. At the same time you are in competition every day with other fuels or feedstocks and other producers.”
Of course, there is also the question of how many companies can be profitable all exporting the same stuff to the same region. “A lot of companies are banking on Asian GDP to clear the U.S. market,” he said ruefully. At least for gas, Sighinolfi is sanguine. “Even with coal growth in India and China, there are opportunities for gas growth as well. There is a benefit for the midstream in providing throughput for export.
“That said, the elements that have exposure to price are not in as strong of a position.”
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