July 2019, Vol. 246, No. 7


LNG: Supporting Midstream Infrastructure as Financial Lifeline

By Richard Nemec, Contributing Editor  

When examining the global liquefied natural gas (LNG) trade, including the role of U.S. midstream infrastructure, there are various exogenous factors that can be part of the matrix. 

They may seem unrelated, but there are possible impacts from such disparate issues as immigration reform in the European Union and United States, the U.S. Jones Act regarding shipping, U.S.-Russia relations, recent North American natural disasters such as Hurricane Maria, and the U.S.-China ongoing trade war. Officials at the Center for LNG, a branch of the Natural Gas Supply Association (NGSA) in Washington, D.C., were emphatic that they wouldn’t connect those dots or concede any relevance in the LNG arena.

The experts in the LNG space say forget about all that, except the Jones Act. “LNG is all about credit-worthy project developers and, especially these days, credit-worthy buyers,” said Michelle Michot Foss, a fellow in the prestigious Center for Energy Studies at Rice University in Houston. “The latter is necessary for the former, and the best buyers are saturated in Japan, Korea and Taiwan. Hopefully the Chinese buyers will pay their bills – we’ll see.” 

Some LNG advocates, such as Fred Hutchison, president of the U.S. trade association LNG Allies, have publicly challenged the Trump administration on its handling of relations with China, although the current White House is strongly supportive of U.S. gas exports. 

Hutchison said his concerns center on the fact that the United States and China are two of the world’s biggest LNG players. He reacts against “anything that disrupts the furtherance of long-term commercial relationships, which are needed for more LNG exports,” he noted in late May in response to growing trade tensions between the two economic giants. 

While President Donald Trump was on hand in the spring to help celebrate the opening of the Cameron, La., export facilities, industry leaders continue to second-guess some of the administration’s specific actions when asked about them privately.

Among the exogenous considerations, none of the experts contributing to this report cited the influence of anti-fossil fuel activist groups, one of which at the time of this compilation released a report (The Fracking Endgame: Plastics, Pollution and Climate Change) on hydraulic fracturing with recommendations for banning all fracking nationwide, along with eliminating all fossil fuel exports, and all infrastructure built to support those endeavors.

The leaders of the group, Food & Water Watch, are alleging that to combat climate change the United States must almost overnight close its infrastructure supporting oil, natural gas and coal. While obviously infeasible and extreme, the industry leaders cannot ignore these “Keep It in the Ground”-like efforts.

There is widespread appreciation, however, for the importance in having a flexible and resilient midstream sector throughout North America, and for getting adequate future investment for the U.S. producers to share in the growing global LNG trade. As summer dawned in North America this year, all indications were for another period of natural gas supply surplus along with robust LNG export and domestic U.S. industrial growth, but in any event, supply likely was going to outstrip demand.

“Depending on which parts of the midstream sector you look at, I would say parts of the U.S. pipeline system are quite new, especially when looking at the pipeline expansions in the Northeast over the past few years,” said Morningstar Research’s Matthew Hong. “An extensive system could be a competitive advantage because it allows for supply flexibility in meeting export obligations.”

Regardless, Hong isn’t ready to agree that the development of U.S. LNG exports has increased the value and need for midstream infrastructure. Midstream allure in 2019 is more directly related to abundant low-cost supplies, Hong thinks. “U.S. LNG as a story would probably not be viable without access to low-cost shale production, and now that the country is finding ways of expanding the gas sector generally, this need for greater infrastructure presented itself.”

Historically, Michot Foss puts in perspective the see-saw effect back and forth between oil and natural gas with the advent of the shale boom. Players have gone from emphasizing gassy acreage to the current obsession with black oil as in the Permian Basin and North Dakota’s Bakken. Gas prices in the late 1990s and early 2000s were shooting upward ($4-$6 MMcf) while global oil prices were not.

“All the natural gas producers [riding the shale boom] destroyed the strong gas prices by putting way too much gas into the markets,” said Michot Foss, a James Baker Energy Center colleague of well-known energy economist Kenneth Medlock. “Then, in about 2010, everyone got interested in oil again.”

She thinks that companies in the shale gas plays recognized that they were not going to be able to make a viable business on the gas side alone. So, the early leaders took a risk and migrated to the oilier plays like the Permian and the Bakken. In many places in the Permian they were able to produce what she calls “black oil” – not just light oil for condensate, butane or ethylene. The business today is that business – the black oil business, according to Michot Foss.

What she left out is that huge amounts of natural gas are being produced as a byproduct. “If you’re not in a black oil play, then hopefully you’re in the natural gas liquids (NGL) play, which means you’re mainly in the Utica, or other parts of the Appalachian or the right spot in Oklahoma where you can use the condensate,” she said.

The future of the global LNG business is dependent on high oil prices. “You have to have high oil prices to continue to put methane into the market,” said Michot Foss. “And that requires a strong enough U.S. [Henry Hub] price to encourage people to drill.” She maintains that a high Henry Hub price, however, does not encourage more LNG exports. 

“We have no relative advantages to the largest gas producers around the world (Australia, Russia, Qatar, Iran, et al.) who are closer to the market (Asia) than we are,” Michot Foss said. “Qatar can push out tons of gas without any new drilling. In the United States, you have to drill.”

And if you have to drill here, you have to develop the midstream infrastructure to make your drilling marketable. In various U.S. projects, such as Sempra Energy’s Energia Costa Azul in Baja California, Mexico, and Cheniere Energy Inc.’s Sabine Pass in Louisiana, they have pipelines used for LNG receiving terminals that can reverse flows. Cheniere did that with Sabine and then added some relatively small proportion to infrastructure.

Midstream infrastructure is a vitally important, but sometimes forgotten, part of the U.S. LNG export equation. Analysts such as Morningstar’s Hong spend little time analyzing it in relationship to gas exports; more in relationship to producers and their ability to get supplies to markets. 

However, it can help set the United States aside from other competing exporting nations such as Canada and Australia. Nevertheless, it can be under-appreciated by both would-be buyers and sellers of LNG, said Katie Ehly, senior policy advisor at the Center for LNG.

“Some people consider the LNG export terminal itself to be part of the midstream,” Ehly said. “From a pipelines standpoint, in the United States we are very fortunate to have an extensive pipeline network. It definitely aids in our ability to build the export terminals.”

Ehly struggles with trying to satisfy a questioner’s attempt to cite a proportional role for the midstream infrastructure as part of the overall LNG export projects’ economic, logistical and strategic importance. “Some of the terminals, especially ones in Texas and Louisiana, are using a lot of pipeline systems already in place, and then just building shorter laterals off of those pipelines,” Ehly said.

“Part of the determination of where to build a terminal goes into the question of midstream infrastructure needed. It is easier and less expensive if you’ve already got a lot of that in place versus Jordan Cove in Oregon which has a big part of its project involving a 232-mile large-diameter transmission pipeline. That is certainly a more expensive project because of that.”

Now sponsored by Calgary, Alberta-based midstream developer/operator Pembina Pipeline Corp., the Jordan Cove LNG project is a posture child for the peaks and valleys of U.S. LNG project development over the past 15 years, beginning with long-standing plans to develop a receiving terminal in Coos Bay, along the south-central Oregon coast. 

Late in 2018, Pembina ponied up US$75 million (C$100 million), betting that the long-struggling project will get approval from the Federal Energy Regulatory Commission (FERC) by year-end 2019, following a FERC environmental schedule release.

Pembina acquired Jordan Cove in its 2017 takeover of the project’s creator, Calgary-based Veresen Inc., for $7.3 billion (C$9.7 billion). The proposal had a long, checkered past that attracted Pembina as being the most advanced West Coast North American LNG export project, despite its added costs and risks as a greenfield project that required substantial midstream investment to assure adequate supplies. 

Begun with an import vision and context, the Oregon project dates back to 2004-05 before the unconventional shale gas revolution was fully unleashed. FERC approved the Oregon facilities for imports in 2009, but the shale boom precluded its development; it switched to an export project in 2013 and has a 25-year export license from Canada’s National Energy Board to eventually get most of its 1.6 Bcf/d in supplies from Canada, although now the project looks to rely on a blend of Canadian and U.S. Rockies supplies.

The current Jordan Cove LNG proposal also revised the original export facilities design as part of a second, re-application to FERC, and the project has been modified in response to local community and environmental opposition that contributed to FERC’s rejection in 2016. Last year, the U.S. Coast Guard approved the project for shipping at the export terminal. Sponsors still think it can compete in the coming decade with LNG from brownfield projects in the Gulf Coast on a delivered basis to Asia.

Permitting, building and operating a $10 billion project involving the logistics of 7.8 mtpa is difficult enough, but when you add in the 232-mile Pacific Connector pipeline from the Malin Hub at the Oregon-California border, the challenges and permitting risk escalate greatly, according to supports and analysts alike. This pushes the projects technical, environmental and logistical challenges into political and public policy vortex in a U.S. region, the Pacific Northwest that is moving toward a carbon-free environment that now disdains fossil fuels, even natural gas.

As a result, even before Pembina replaced Veresen as the sponsor, the latest project proposal at FERC dropped plans to include a 420 MW gas-fired generation plant at the terminal site and included more than 50 route adjustments in the connecting gas supply 36-inch transmission pipeline. Several water crossings had to be reconfigured to mitigate against environmental impacts using trenchless drilling techniques. Total engineering, procurement and construction costs for the terminal and pipeline had shot up beyond the $10 million level in 2017.

Wall Street analysts for the investment banks and private equity firms were put off more by local opponents to the project, particularly the pipeline, than by FERC’s initial rejection. They concede Jordan Cove is one of the most expensive LNG export projects, but it can reach Asian markets at a discount to Henry Hub prices, and that helps offset its higher costs relative to the Gulf projects. It also has half of its potential volumes contracted for at this point. The question is: can the connecting infrastructure be permitted and financed.

“Infrastructure serving LNG export facilities are very important because they play a role in ensuring supplies can make their way to the export terminal with primacy,” Morningstar’s Hong said. “It helps the export facility compete against others. In general, the name of the game is least-cost-of-operations, so the export projects that can put the gas into the ship the cheapest way will be best positioned to compete. Projects that have the needed associated pipeline connections seem to be more attractive.”

The domestic U.S. infrastructure needs to help secure an even bigger slice of the LNG pie globally, so it will continue to be viewed as an invaluable asset for producers and shippers. As an emerging global commodity that has relied on oil-indexed contract prices, LNG is going through growing pains and various levels of geopolitical and economic pain. One executive close to the Permian told P&GJ he understands that the availability of an export market and use of LNG terminals in the United States now “is incredibly important, but it isn’t something on which I spend much time or gather much information.”

“People generally are so focused on the terminals themselves that they forget about the pipelines and other back-end assets, especially when we talk to people in other countries about importing our LNG, the conversation stops at the import or export terminal,” said Ehly, from the Center for LNG. “We have to remind them that there is a whole other system that needs to be put in place to get the gas to market.” 

Nevertheless, the permitting processes usually blend together the terminals and the pipeline/processing infrastructure needed to make any given project go. The DOE export applications, for example, combine both, Ehly points out.

In its role as a fledgling worldwide commodity, LNG today faces price pressures tied to oil, cash shortages, and financing limits that raise the importance of byproducts such as natural gas liquids (NGL) that have the economists scrambling to sort out the speed bumps confronting the fast-unfolding sector. The global NGL markets are emerging regardless of LNG, according to Michot Foss, who sees them as a separate market play. “You don’t need LNG as an excuse to build midstream capacity for NGLs,” she said. “You need a market for the NGLs.”

Not many LNG customers can take cargoes with high NGL content, and for many of the Gulf Coast LNG projects, the NGLs get stripped out locally for diversion to local petrochemical plants, or separate export processing. In this case more NGL infrastructure is needed, and is being developed, completely separate from the LNG-related build-out. Energy Transfer Partners (ETP) and Satellite Petrochemical USA Corp. in 2018 launched plans for a Gulf Coast ethane export project of 6.3 million gallons a day by 2020. ETP plans to construct and wholly own the infrastructure that is required to both supply ethane to the pipeline and to load it on ocean-going carriers.

When the midstream role in LNG exports is fully deconstructed, it is a bit of a mystery needing the likes of Sherlock Holmes or Hercules Poirot to unravel it. The way academic/researchers like Michot Foss approach the conundrum is to describe some of the dynamics, such as a lingering midstream capacity in the midst of the continuing shale boom that makes methane cheap and alluring for exports.  

She is referring to negative gas prices at the Waha Hub in the Permian, and deep discounts for Utica/Marcellus dry gas production. What develops is a classic arbitrage opportunity for traders. Once the price differentials are closed, the processing, pipeline and connection capacity shortfalls also get filled.

“As long as we mainly have associated gas to sell – gas that is in the market entirely because producers are chasing oil as their highest priority and liquids as the second priority, methane will be a byproduct and cheap,” said Michot Foss, noting someday U.S. gas prices will need to reflect the cost of drilling, and at that point it is unclear whether the U.S. exports would continue to have a competitive advantage.

So far, producers in Appalachia and the Haynesville play have adjusted by concentrating on acreage that yields enough NGLs for commercial capture, and abandoning areas that don’t. “That has been a story across the Lower 48 and Canada with regional variations,” Michot Foss said.

When asked about how important the LNG export business has been to the U.S. midstream sector, Michot Foss does not mince words. NGLs have been more of a driver, from her perspective.

“So again, most LNG customers take cargoes that are 99.9% CH4 [methane],” she said. “Clearly, any LNG export strategy needs midstream support, but midstream is important for value capture of NGLs, and we were doing that before, and now coincident with, LNG export development. I would say that midstream came into its own as producers started the search for uplift from NGLs.” 

At the outset of summer 2019 positive supply and demand and financial news was lifting the spirits of U.S. LNG advocates as global oil prices were losing some momentum. A highlight was the early June decision of four prominent backers to move ahead with building the multibillion-dollar Whistler Pipeline project from the Waha Hub in West Texas to the Gulf Coast and all those export outlets.

MPLX LP, White Water Midstream, and a joint venture between Stonepeak Infrastructure Partners and West Texas Gas Inc. decided to move forward with the $2.5 billion, 2 Bcf/d transmission pipeline.  

It is supposed to open in the third quarter of 2021 and include 475 miles of 42-inch pipeline with supplies from multiple upstream sources in the Permian. It will have direct connections to plants in the Midland Basin through a 50-mile, 30-inch lateral as well as a link to the 1.4 Bcf/d Agua Blanca Pipeline, another joint venture of White Water, MPLX and Targa.

The final investment decision on this mega midstream project came little more than a week after the USGA released a bullish 2019 summer natural gas outlook, calling for record-setting summer U.S. demand (82.1 Bcf/d) driven by a combination of LNG exports and domestic industrial growth. After nearly doubling year-over-year last summer with an added 1.4 Bcf/d of added LNG export capacity, USGA’s outlook forecasts up to 2.5 Bcf/d of added capacity this year from four sites with added liquefaction trains (Corpus Christi, Freeport, Elba Island and Cameron).

“LNG exports provide stability for production, allow the U.S. to help its trading partners improve air quality, and create jobs and household buying power,” said USGA’s Senior Vice President Jenny Fordham. “We also expect industrial demand for gas to reach record levels this summer at almost 3% higher than last summer.”

To further put an exclamation point on the late spring boost to the U.S. LNG export space, international France-based energy giant Total purchased Toshiba Corp.’s interest in the Freeport export project for $815 million as a further indication the sector is alive and well and headed for more growth perhaps. And for the midstream operators, they can take comfort in the fact that they are in the middle of all this potential. P&GJ

Richard Nemec is a Los Angeles-based contributing writer to P&GJ. He can be reached at rnemec@ca.rr.com.

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