The commodity price downturn has had a widespread impact on the oil and gas industry, but it is unlikely to stop midstream development.

What a difference a year makes

In the last 12 months, the U.S. unconventional shale industry has experienced its first market downturn unrelated to an overall economic slump while also showing how much the U.S. energy market has changed. Since the 1970s OPEC oil embargo, the U.S. has been largely isolated from global energy markets, but as these markets have become oversupplied, the U.S. has not been immune to challenging prices.

It is a misconception that fluctuations in the marketplace have immediate changes on capital spending. In any marketplace, it would be foolhardy to make financial decisions on real-time changes in the market. This is why long-term forecasts are so important—the impact of capital on a project is often tied to its timing.

Business as usual

After a period of uncertainty following the collapse in hydrocarbon commodity prices, the oil and gas industry has seemingly stabi lized with the midstream still going about business as usual in its buildout across the U.S. According to Industrial Info Resources, there are a total of 18,620 active oil and gas projects with future completion dates that will cost a total of $2.41 trillion in North America. On a global basis, this is second only to Asia, which is spending $6.66 trillion on 37,744 projects.

Producers are certainly taking a step back, but unless there is a sustained down period, it is unlikely that the midstream will experience any real changes to its development schedule.

“I have not seen a change in the midstream at all,” Daniel Hagan, partner, White & Case, a Washington, D.C.- based international law firm, told Midstream Business.“The general consensus is that the midstream space is pretty insulated from commodity prices.”

If anything, there appears to be even more interest in the midstream— among those seeking to enter the sector or current players seeking to increase their foothold. Hagan, who heads the firm’s energy markets and regulatory practice, said there remains a great deal of activity, especially on the M&A side of the midstream.

“There’s been a lot of activity with companies looking to diversify into different geographic areas or services,” Hagan said. “There is no shortage of interest from investors in the space. The buyers have either been larger players looking to increase their size and breadth or a lot of new entrants into the market, such as funds and private equity,” he added.

Transportation focus

These deals have run the gamut from large to small with a particular focus on transportation assets, specifically pipelines because of their fee-based nature. According to Hagan, private equity firms have focused on mid- sized to large acquisitions.

Interestingly, while it would appear to be a safe assumption that producers would be the group leading the sale of midstream assets, Hagan said so far that hasn’t been the case.

“Those types of sales haven’t been what is driving the market. For sure, some producers have been involved, but they’re not the primary sellers,”

Hagan said. “It’s really been strategically focused with companies seeking to reallocate funds into different assets.”

It is likely that companies will take a more cautious approach to backlogged projects as they evaluate the market going forward. “There’s already been so much announced that there’s been a general evaluation and re-evaluation of projects. However, it’s a very competitive space so where there is a need, you’ll likely continue to see projects being announced,” Hagan added.

Fear of the unknown

Other industry observers see the same trend. “One of the reasons people are struggling with calling when a bounceback from this downturn will occur is because of the unknown. You have this issue with decline rates in shale oil that haven’t been observed the way they have in gas,” Anne Keller, manager, NGL research, at Wood Mackenzie, told Midstream Business. Typically, crude oil wells have longer recovery rates, but as more drilling rigs are directed toward unconventional production, these decline rates are shortening and may look more akin to shale gas production. This makes it more difficult to forecast supply, which is troublesome not only for producers but midstream operators.

“The Barnett Shale was the grandfather of unconventional gas production more than a decade ago. When things slowed down in the gas markets, we saw how that play peaked and has since come off,” Keller said.

She noted that it’s not entirely fair to make a direct comparison between unconventional oil and gas. “The Eagle Ford is the analog for the oil side of shale production, and we haven’t seen how it will play out. We know the decline rate is rapid compared to conventional wells, but beyond that it’s hard to calibrate the oil and gas models,” Keller said. This is especially true as these models are still being developed.

Keeping cash flow

Crude market analysis usually revolves around the breakeven value, but Keller said that marginal players aren’t focused so much on the breakeven value as much as maintaining cash flow in the current environment.

Another factor that makes forecasting the current market difficult is the availability of “cheap” money with an abundance of capital flowing into the sector over the last five to seven years, Keller said. During this time period, there have been a number of investments that ran counter to historical fundamentals.

“How much did people, investing past the point where it typically was thought to make sense, fundamentally exacerbate the current supply overhang? What troubles me is that when I look at the numbers for ethane I can see a lot of large ethylene plants coming online in the next 12 to 18 months. That tells me relief is at hand for a big chunk of the ethane out there now,” Keller said.

“What is there for crude that will handle this inventory?” she added. “Will we have such a falloff in drilling and completions that the decline rate will take care of it? Will it be increased demand? The world market is struggling and countries are competing to devalue their currency so they can export to each other. U.S. refineries are running at very high rates and crude tanks are still filling up. I’m not so sure we’ve hit the bottom yet because of the inventory builds.

Opportunities abound

Capital flow into the midstream is likely to fund a new round of projects as the sector continues its buildout. “We’ve built a lot of the assets to support the first wave of drilling. Now we’re starting to see companies looking at other opportunities such as adding throughput between regions,” Keller said. Indeed, the midstream has not slowed since the downturn.

“While NGL prices have fallen, our NGL and liquids business units continue to be critical parts of our company,” Mac Hummel, executive vice president and president of the liquids business unit at EnLink Midstream LLC, told Midstream Business. While the price downturn will lead to some infrastructure projects being delayed beyond previous expectations, Hummel said that there are opportunities for the company to expand its footprint in core areas.

“EnLink remains well positioned because our corporate structure and growth strategy allow us to take advantage of opportunities in any cycle. When commodity prices do recover from current levels, we will be in a good position to benefit from that recovery,” Hummel added. The company has been one of the most active players in the midstream space this year, having secured more than $1.1 billion of acquisitions in new growth areas since December. EnLink, which was formed in 2014, has an active strategy to double its size by the end of 2017. This strategy includes dropdowns from its strategic partner Devon Energy, organic growth and M&A. “We have made tremendous progress toward executing our plan, even in this volatile environment,” Hummel said.

Since so much of gas and NGL production is currently associated with crude production, decreased oil drilling will likely have notable impacts on gas and liquids markets in the months ahead. This could even result in NGL and crude prices decoupling once again.

“As Wood Mackenzie has been working on our short-term revision, we’ve noticed that supply trends may not be following our expectations, and we are beginning to wonder if NGL supply may not be keeping up with the flat pace of crude production,” Keller said.

Most likely, the first drilling rigs to return to the field will be focused on crude, but the impact of the decline in drilling will take time to have an impact on the market. In fact, it could even be sooner than some expected if liquids and gas rig counts continue to languish.

Marcellus-Utica impact

“Everyone is focused on associated gas and tight oil and prices,” she added. “That matters, but associated gas isn’t going to give us the boost in NGL supply that everyone is counting on. It will support the market by keeping supplies at current levels or potentially slightly above these levels, but in order to really achieve the big numbers that are being counted on to have additional barrels in the medium to long term, you’ll need gas markets sufficient to pull production out of the Marcellus-Utica.

“A lot of people are really focused on crude, but we are looking very hard at the ability to build gas infrastructure out of the Marcellus-Utica and then at which markets it can be moved to. That’s far and away our most prolific region in terms of future growth,” Keller said.

Wood Mackenzie was bearish on propane even before storage levels reached such a high mark heading into spring, a situation Keller described as being “pretty scary” since it’s so far outside the norm. Luckily, propane’s pricing relationship to crude oil is closer to the norm. According to the consulting firm, propane likely bottomed out against West Texas Intermediate crude at a 32% ratio in 2012. Since then, propane has not gone back to this ratio in relative terms.

However, there is room for a bullish sentiment in the propane market, especially if production slows or stagnates. “Production out of the Eagle Ford accelerted in our forecast, but conventional gas declines are steeper than what we had in our forecast, and they’re tending to offset the increase in shale production to the point where I’m not seeing the year-over-year growth in NGL production, at least for the Gulf Coast,” Keller said. “That’s a more bullish NGL story than what we’ve had the last couple of years.”

Should U.S. production remain flat for an extended period of time, it could cause an increase in demand from foreign markets, realizing the propane-to-crude ratio isn’t going to spike and it’s not a short-term phenomenon. In this case, they may seek to utilize propane on a permanent basis to displace diesel fuel in power plants and other markets, including the increased use of bottled LP gas.

Exports still drawing interest

Ethane rejection has been widespread throughout the U.S. for the past several years as supplies overwhelmed demand. While speaking at the recent Gas Processors Association conference in San Antonio, William Ordemann, group senior vice president, unregulated liquids, crude and natural gas services at Enterprise Products Partners, stated that about 500,000 barrels per day of ethane is being rejected. This rejection policy has been having a noticeable impact as prices have been improving this year and have established a floor.

Despite this policy, supplies are still high, which leaves opportunities for market expansion.

“There’s plenty of ethane available, there will be a huge overhang even with the additional cracking capacity that will be coming on in the next few years,” Ordemann said. As such, Enterprise and other operators are building terminals to export the product to Asia and Europe.

While it may reduce overhangs, export capacity may not help prices recover more quickly.

LPG vs. LNG

“The export market hopefully will give you a physical outlet, though we’ve seen several cargos turned back recently. The worst-case scenario that our analysis shows is LPG competing as fuel with LNG overseas,” Keller said. As LNG is rapidly falling down in value to parity with the U.S., once you net out freight and other costs, this isn’t an especially attractive price.

“The only thing that will really help exports is that over time these markets grow. Exports provide a way to physically move volumes and chase more markets than before, but they may not do a lot for prices in the next 12 to 18 months,” she said.

If ethane exports take off, there could be an increased need for ethane to be shipped to the Gulf Coast. This has the potential to help work off the ethane storage overhang and increase competition along the Gulf Coast between ethane crackers and exporters.

“There are only so many barrels available from the rest of the U.S. from existing infrastructure and then you hit the point where you’re looking at another round of midstream development—either new NGL lines or regional fractionation or some other infrastructure on the plant side,” Keller added.

The ability to transport Bakken and Marcellus production to the Gulf Coast will push against capacity in the next 12 to 18 months and require solutions, according to Keller. New flaring regulations will result in the need to process more Bakken volumes even if production remains flat. This will require the increased use of rail transportation due to pipeline constraints and the lack of West Coast export capacity. The Marcellus will also need more capacity as production is forecast to increase even with a slowdown in drilling.

“The summer of 2015—and possibly the summer of 2016—will be pretty tough on those regions with wide differentials between them and the rest of the world since a lot of this production will have to be moved by rail,” Keller said.
She added that on a short-term basis, there is a concern that the NGL distribution system will become overloaded, which would have the potential of causing shut-ins. On a longer-term basis there are projects underway to increase both export and pipeline capacity, which will help to pull these differentials back.
Rail alternative
Though rail will see increased use in different parts of the country, the industry could face a major headwind that could open up further pipeline development. Pipelines have had some very public skirmishes with regulatory agencies, most notably in the case of the construction of the Keystone XL and the Rockaway Lateral pipelines, but the industry could benefit from regulatory action against railway shipments of crude and liquids production.

“Rail is a real competitor and threat to pipelines, but right now that industry is being scrutinized by regulators to impose better safety standards,” Hagan, with White & Case, said. “The question is, how far are regulators going to go and what are the cost implications? The higher regulation of rail could benefit midstream because it’s going to potentially impact the economics of transport by rail. Where it’s marginally economic to build a pipeline, those economics may change if the cost of transport by rail increases.”

The current downturn in the hydrocarbon markets isn’t likely to cause widespread project cancellations, but it could result in projects being moved back so that infrastructure comes online at a time when production and demand are at more optimal levels.

The larger a project is, the more unlikely it is that the current downturn will have a tangible impact on its construction. There aren’t many larger projects than ethane crackers.

“Companies looking at new cracking capacity are looking at 2020 and beyond so they can’t look at what’s happening today,” Keller said. “They’re looking at where and what type of barrels are coming on post-2020 in order to meet demand.”

NGL price downturn inevitable

While it is true that the downturn in crude prices didn’t help the NGL market, Keller added that it was inevitable that NGL prices fall in 2015 regardless of crude price movement.“The absolute price would’ve been better if crude hadn’t dropped because it would have been tied to crude in some way, but if we are drilling at the rate we were going at in the fourth quarter, we were looking at the Armageddon scenario of declaring force majeure to shut the wells in because we didn’t have anywhere to go with the NGL production,” she said.

“It’s a good news/bad news story: If crude prices stay low and this actually puts the brakes on supply that might tighten up the market,” Keller continued.

As companies re-evaluate project development, they are likely to become more regionally focused to match producer activity. As such, the Eagle Ford, Permian, Marcellus and Utica shales will be of particular emphasis for midstream companies.

Permian perspective

The Permian remains the hottest play in the U.S. both for producers as well as midstream operators, though Keller said that processing growth has slowed recently in the play.

“It’s a little surprising to see this slowdown and you have to wonder if it’s a lost opportunity with gas not getting processed. It is possible that this dip in new processing is just breathing room, and next year we’ll see this big surge as wells are completed and plants come online,” Keller said.

The announcement of new LNG projects may slow in the coming months, but this isn’t so much related to a downturn in prices. “I don’t think there’s necessarily a loss of appetite on the LNG front, but there is a cap on what can be built and what the market can bear,” Hagan said.

In some ways, the LNG sector serves as a snapshot of the overall midstream industry. There is still plenty of interest from investors and operators to continue to build new infrastructure, but this desire is limited by market dynamics.

It would be easy to say that these dynamics are related to a crude price downturn, but this doesn’t appear to be the case; at least not entirely. Now that there has been time to reflect on how the market is moving, it seems as though midstream growth will continue.