Nobel laureate Neils Bohr summed up the problem with forecasting when he once observed, “Prediction is very difficult, especially if it’s about the future.” He made the comment in reference to modeling built on past data that may—or may not—be replicated in the future.

Maybe, or maybe not: That’s an apt description of the energy sector’s midstream segment in the new year.

What past data should executives and investors turn to as they build their business models? Should they look back at the abysmal years of 2015 and 2016? How about the boom year of 2014? Or, there’s the just pretty-good or so-so year of 2017 when some things went well but challenges, particularly from Wall Street, lingered.

It’s pretty certain all that past data will be replicated at some point, but in what way and for how long? And it’s important to remember that “change doesn’t come by the calendar year,” Ben Davis, partner at Energy Spectrum Partners, told Midstream Business. Major change involves multiple issues that occur as the days, weeks and months roll by.

He’s not alone in that view. “We think 2018 will see a continuation and exacerbation of issues we've faced this year, including environmental and NIMBY [not in my backyard] opposition to pipeline construction, along with a metamorphosis of midstream players into more self-sufficient financing models,” Ethan Bellamy, senior research analyst for Baird Equity Research, said of the new year. He told Midstream Business, “The overall backdrop should be better, though, as U.S. production rises on a more normalized oil price and most of the pain of trough midstream economics is increasingly in the rearview mirror.”

But even with the questions, industry observers seem optimistic.

Meaningful growth

Simmons & Co. observed in a late-2107 report that “Cyclical tailwinds in the form of synchronized global economic growth and a meaningfully tightened Lower 48 upstream value chain, resulting in extended cycle times, have collectively contributed to an improved, near-to-intermediate term outlook.”

In an end-of-the-year report, Wells Fargo bulleted its expectations for 2018:

Crude, natural gas and NGL volume increases should drive free cash flow growth for

midstream. The report also predicted:

  • Northeast pipeline capacity will expand, debottlenecking the basin and driving accelerated natural gas supply growth;
  • Organic infrastructure investments should diminish, reducing financing needs;
  • Restructuring of the sector—including incentive distribution right elimination, a move to a self-funding model, a focus on return on invested capital, and a slowdown in distribution growth—should attract institutional capital over time;
  • A slowdown in growth should drive sector consolidation; and
  • There will be discounted valuations relative to other yield securities and relative to other energy subsectors.

And, understandably, the report warned of potential risks. A “lack of capital discipline could result in continued supply/demand imbalance for equity, higher interest rates, access to equity markets (less retail participation), difficult environment to build new pipelines (regulatory, environmental), [and] tax reform,” it said.

Whither prices?

The drivers of the entire oil and gas business are, of course, commodity prices. Crude oil prices finished 2017 on the upswing—although still far below 2014 peaks. Some industry observers project even better prices in the months ahead.

“We believe that an improving commodity environment, coupled with strong demand for U.S. exports, new demand from new ethylene plants and several of our major projects coming online should help increase our DCF [distributable cash flow] in the future,” Jim Teague, CEO of Enterprise Products Partners LP, told investors and analysts in the firm’s third-quarter 2017 conference call.

And then there is OPEC. What will it do? OPEC may not be the power player it once was but it still has an outsized influence on world crude prices, Michael Roomberg, portfolio manager and research analyst at Miller/Howard Investments, told Midstream Business.

“In my view, the two most critical factors in a sustained oil price recovery would be adherence to the OPEC production cut agreement that began in November 2016 and was recently extended through December 2018, and the absence of a global recession. On both counts, things appear to me to be trending fairly well going into 2018,” Roomberg said. “OPEC has exhibited a historically high degree of compliance, and the group has extended their agreement as necessary to eliminate the 500 million barrels [MMbbl] of stored crude oil in excess of normal.

“Unlike the agreements of past, current technology, including satellite tracking data, make it harder for OPEC members to cheat. A recent Reuters survey found that OPEC compliance rose to 92% in October 2017 vs. 86% in September 2017, with Saudi Arabia continuing to produce below its agreed-upon target. Production restraints in Kuwait, the United Arab Emirates, Saudi Arabia and Russia have more than offset strong growth in Nigeria and Libya,” countries that are not full parties to the agreement, he added.

Hedging their bets

It’s no surprise that producers and traders increased hedging activity to try and lock in the best oil prices seen in more than two years as 2017 ended. A Wood Mackenzie report said most of the new derivatives were added at strike prices between $50 per barrel (bbl) and$60/bbl.

Andy McConn, research analyst at Wood Mackenzie, explained: “Many producers have been basing long-term growth targets on $50/bbl price scenarios. When futures prices rose above that level, producers may have viewed it as an opportunity to lock in prices that will enable them to hit—or maybe outperform—targets,” said McConn. “Recent pressure from investors for producers to live within cash flow is likely compelling producers to limit exposure to price risk.”

OPEC’s own late-2017 forecast sees total global oil demand increasing by 1.51 million barrels per day (MMbbl/d) in 2018, with total projected demand edging up to 98.45 MMbbl/d.

Supply seems to be down and demand up—at least slightly. Overall, “2017 is shaping up to be the first year of the expansion in which growth surprises to the upside,” Goldman Sachs analyst Charles Himmelberg said in a late-2017 interview on CNBC. “We expect 2018 to deliver more of the same.”

Producers likely will take advantage of that trend, according to a fourth-quarter 2017 Westwood Global Energy Group report that projected an 18% increase in active rigs this year.

But not every driller will contract for more rigs.

Investor pressure

“North American E&P companies are under pressure from investors to focus on cash generation over pure growth,” Westwood said. “Many companies, particularly independents, have scaled back the pace and streamlined their future developments plans. Anadarko Petroleum recently announced that it would pursue a noteworthy share buyback program rather than directing cash into drilling or acquiring assets, as well as reducing its 2018 capital program compared to 2017.”

Roomberg added, “So far, we think about 50% of this excess inventory has been worked down, meaning that over the past year the world has consumed about 600 Mbbl/d more oil than it has produced, on average.”

He continued, “On the second count—demand—the International Energy Agency (IEA) recently confirmed what has become increasingly clear: global oil demand is growing at its fastest pace in several years. This includes a record end to the U.S. summer driving season, with gasoline demand hitting highs in August and seasonal highs since then. This is critical, given that higher demand is taking place against the backdrop of higher year-on-year prices. Further, a weaker U.S. dollar is aiding international demand, as oil is priced in dollars. Ultimately, we believe the growth of U.S. oil volumes is manageable in a growing demand environment.

“We continue to believe that the rejuvenation of U.S. shale volumes will not upset the overall oil market rebalancing,” Roomberg added. By late fourth-quarter 2017, “U.S. production had grown 650 Mbbl/d—below shale’s potential incremental 1 MMbbl/d deluge that some had feared. Shale is displacing non-OPEC, non-U.S. production declines.”

It’s a message other energy executives, such as Continental Resources CEO Harold Hamm have voiced. U.S. production slowed its growth in 2017.

That has impacted prices, Bellamy said.

The swing producer

“I think that oil should trade at the marginal cost of production. As the new swing producer globally, the U.S. needs on the whole $45 to $50–$55 [per barrel] oil, and so any period of time where we see oil trending above $55, I think that's going to incentivize more production, ultimately bringing the price down again,” he added. “So I would expect oil to trade in a high 40s to high 50s band, unless and until something big with OPEC changes. But if we have $60 or better for a few quarters, that wouldn’t be a shocker. Price elasticity always exceeds supply elasticity.”

Revisions to U.S. tax law could create an important boost to demand, according to the American Petroleum Institute (API).

“Pro-growth tax reform can support forward-looking energy policies to ensure our nation continues its global energy leadership,” Jack Gerard, API president and CEO, said as Congress closed in a rewrite of the nation’s tax code as 2017 ended. “Proposals to lower the corporate tax rate and strengthen cost-recovery provisions can allow the oil and natural gas industry to continue investing billions of dollars in the U.S. economy and add to the 10 million U.S. jobs our industry currently supports. These reforms can also drive innovations in new technologies to protect the environment and keep energy costs low for consumers.”

Some analysts project the oil market could see a complete turnaround this year.

“An abundance of oil, thanks largely to U.S. shale, has pushed down oil prices and sector sentiment. But since that means less investment in new production sources, the bearish market may soon rebalance from fears of oversupply to concerns over shortages—which would push prices higher,” Neil Dwane, global strategist at Allianz, told MarketWatch in a fourth-quarter interview.

“Global demand remains resilient at 97 MMbbl/d but oil fields are being steadily depleted. Oil producers collectively need to add about 7-8 million barrels a day in new production to keep up with demand growth and production declines, but that is difficult to do with prices so low,” Dwane said.

Cousin gas

Crude’s future may mirror that of its natural gas cousin, Dwane added. “I think the oil space is going to look a lot like what natural gas has done since that market became efficient and saturated with product.”

Crude exports will continue to be a major plus for the U.S. In a sign of the changing times, the U.S. Energy Information Administration (EIA) reported as December began that net oil imports stood at 1.77 MMbbl/d—the lowest number since the agency started tracking the statistic in 1990. In comparison, the peak was on the high side of 14 MMbbl/d in November 2005, just before the shale revolution began.

“The lifting of the crude export ban nearly two years ago helps to safeguard against the extreme price discounts seen earlier this decade by debottlenecking the U.S.,” RBC Capital Markets said in a year-end research report. “While geographically the U.S. remains distanced from the largest demand regions such as China and India, the U.S. Gulf stands to benefit from the wide-ranging cocktail of crudes available on offer to customers, from light, sweet shales to offshore sours like Mars and Southern Green Canyon to the ability to re-export Canadian heavy barrels.”

In another report, RBC took a you-ain’t-seen-nothin’-yet view of U.S. crude exports, which topped an astounding 2 MMbbl/d in 2017’s fourth quarter.

“… Our math suggests that physical bottlenecks are unlikely to kick in until waterborne exports approach 3.2 MMbbl/d. Additionally, we highlight the functionality and logistical capabilities of key U.S. Gulf export terminals ranging from smooth operators like the Port of Corpus Christi and Houston to the potential game-changing impact of exports from the Louisiana Offshore Oil Port (LOOP).”

Purposed ports

The challenge to midstream will continue to be repurposing the nation’s terminals and docks to handle tanker loading as well as unloading. Not a single U.S. port can load the giant very large crude carriers (VLCCs) favored for long-distance oil trading—although that’s changing.

Jarl Pedersen, chief commercial officer for the Port of Corpus Christi Authority, outlined steps the Texas port is taking to handle VLCCs, including deepening and widening its ship channel, in a presentation at Hart Energy’s DUG Eagle Ford conference in November. Also, the LOOP is expected to finish re-fits that will allow it to also load tankers in the first half of 2018.

And don’t forget petroleum product exports. EIA numbers for November 2017 pegged gasoline exports, alone, at a record 1.21 MMbbl/d and market watchers project gasoline, diesel, jet fuel and NGL sales abroad to continue to climb further this year.

Capex conundrum

Commodity price stability will make it easier to plot capex—but where that capital comes from may change, according to Bellamy. Debt loads likely will go down. A lot of capex will continue to flow into midstream infrastructure, both for new greenfield projects and repurposing of existing brownfield assets.

“The E&Ps got the message earlier this cycle that they should strive to live within the cash flow that they generate,” the Baird analyst said. “The midstream has been, by virtue of its generally more stable business model, later to accept that. But we have seen even firms that are in a good position, like Enterprise Products Partners, acknowledge that the market wants them to take even more internally-generated cash flow and reinvest that for capex than asking Wall Street for more.”

Simmons & Co. noted in a recent report that “cash flow neutrality is the new E&P call

to arms.”

“A major driver of slower-than-expected shale production appears to be the long-elusive capital discipline among upstream producers that may finally be taking place,” Roomberg said. “One piece of evidence for this is the significant increase in the number of drilled but uncompleted wells (DUCs) in the U.S. Upstream companies have been unwilling to lock in or pay up for fracking services to the degree necessary to give the frack service companies the confidence needed to add the substantial fixed capacity that is required to accelerate the industry’s overall pace of development. This has led to a situation where there are many wells that have been drilled but not completed and turned to production. It’s a clear stalemate that’s inhibiting U.S. volume growth.”

Midstream operators seem to be taking a positive outlook on the future and their capex budgets.

MDU Resources Group Inc., for example, released a five-year capital plan in late 2017 that projected a substantial capital spending increase for its midstream operations through 2020. It projected capex for its pipeline and midstream operations of $109 million in 2020, compared to $31 million in 2017. Capital investments in the pipeline and midstream business include the previously announced Valley Expansion project, a 38-mile pipeline that will deliver gas to eastern North Dakota and western Minnesota. This program also includes an expansion of MDU’s Line Section 27 in the Bakken, an expansion of about 13 miles of new pipe and associated facilities. As designed, the project will bring total capacity to more than 600 MMcf/d.

Watch for gathering and processing rates to increase—particularly if interest rates tick upward, Energy Spectrum’s Davis said.

“I don’t see how the current economic deals between producers and the midstream can continue if interest rates increase,” he added. “The question is not what is the absolute return, but what does a midstream operator earn above the cost of capital? And that cost of capital will increase if interest rates increase.”

What’s hot/what’s not

The status of the most active plays will remain unchanged in 2018.. The unconventional plays have had a profound impact on the energy business but it’s unlikely that a new one will pop up soon—and that will have implications for midstream firms’ investments.

“From a fundamental standpoint, I think you are going to see a real saturation in the number of players in the Permian Basin,” Bellamy said. “So the people that are there and who have committed to be there are going to keep putting capital in. But if you are not in the Permian game already, second- and third-tier basins are a lot more attractive for development activity, particularly the Scoop/Stack and Denver-Julesburg basins.”

But Bellamy expects a “resurrection” of shale plays that were active when commodity prices were higher. He mentioned the Haynesville specifically as a potential beneficiary of best practices in completion design coming out of other regions.

Overall, “The biggest shift fundamentally is going to be when we start seeing more Northeast greenfield infrastructure come online. The Marcellus and Utica are going to take an increasing portion of U.S. gas and NGL market share” as new pipeline capacity goes onstream, he added.

Davis agreed. Will some new unconventional play emerge in the near future? It’s possible but not likely, he said.

“I think we will see a revival in some of the less active plays. We’re already seeing that in the Haynesville and Cotton Valley. What about the Barnett? Will we see two-mile laterals and 40-stage fracks there? The Barnett has a lot of infrastructure in place, but it might not be able to handle 20-million-a-day wells.”

Gas to the Gulf
Overall U.S. gas production could reach 92 billion cubic feet per day (Bcf/d) by 2022, according to RBN Energy Inc. “Demand is expected to grow too—primarily from exports—but no more (and potentially less) than supply in the same time frame, leaving the market in a precarious equilibrium over the next five years. Thus, it will be all the more critical that incremental supply can access what new demand there will be. At the same time, demand growth will be concentrated in one geographic region—in the Gulf Coast states,” RBN noted in a late-2017 research report.

Midstream’s buildout likely will continue apace. A regional infrastructure analysis, performed quarterly as part of Stratas Advisors’ North American Oil Service, shows a significant number of new pipeline and terminal projects will have dirt moving in coming months.

Gas pipeline capacity out of the Appalachian plays has been particularly critical and new capacity will be entering service in the first six months of this year. Rover Pipeline, connecting the Utica and Marcellus to the Midwest and Canada, entered limited service in late 2017 with Phase 1B expected to go onstream in the first quarter. Phase 2 is expected to start up by late in the second quarter.

Mariner East 2 also is expected to be completed in the second quarter. The Williams Cos. Inc. recently restarted work on its Atlantic Sunrise Pipeline after an appeals court rejected a stay request by pipeline opponents. It has been scheduled for a midyear in-service date.

New pipeline capacity out of the booming Permian also is important—particularly as gas production increases in an oil-focused basin. Increasing gas production and limited capacity caused the price spread between the Permian’s Waha Hub and the benchmark Henry Hub to yawn as wide as near 60 cents/MMBtu in 2017.

Producers have been counting on new southbound capacity to Mexico to sop up the excess gas supply and, indeed, there’s significant new capacity going under the Rio Grande. Problem is, Mexico’s domestic gas grid remains limited and it may be years before it builds out sufficiently to handle U.S.-produced gas, observers say.

Noting the strong Gulf Coast market mentioned in the RBN report, an alternative appeared in 2017 when Kinder Morgan Inc., DCP Midstream LP and Targa Resources Corp. signed a letter of intent for the proposed Gulf Coast Express Pipeline, which would provide an outlet for increased Permian gas production to the Texas Gulf Coast. Proposed capacity will be 1.92 Bcf/d. Construction could begin this year if all goes well with an in-service date in second-half 2019.

LNG exports continue to grow in importance for the gas business. Dominion Resources’ Cove Point liquefaction plant on Chesapeake Bay received first gas in December. On the Gulf Coast, Cheniere added new liquefaction trains to its Sabine Pass plant.

There has been speculation that the Permian may be overbuilt in a year or two, but Davis doesn’t see that happening. Midstream firms will continue to add infrastructure as long as production continues to rise. The danger the sector faces is that midstream projects move in response to—but at a different pace—than drilling, he explained. “It’s like towing a boat on water. You can stop but the boat behind you doesn’t, and then you get bumped,” Davis said.

Keep it in the ground

But perhaps the biggest long-term concern for midstream executives is the continuing strong, well-financed environmentalist opposition to the infrastructure necessary to connect producers and customers.

Violent protests delayed Energy Transfer’s Dakota Access Pipeline (DAPL) that links the Williston Basin’s Bakken shale play to the Patoka, Ill., pipeline hub. Oil finally began to flow at midyear 2017. But emboldened pipeline opponents vow to continue the fight and there is the possibility—although remote—that a court injunction could shut DAPL down in early 2018.

TransCanada Corp. received final regulatory approval for its long-delayed Keystone XL (KXL) Pipeline in late 2017 from Nebraska’s Public Service Commission. Opponents immediately turned to the courts—and to lenders—in an effort to stop the project. A major November 2017 spill along the existing Keystone Pipeline gave opponents spare powder for that fight.

Project delay “gives Sierra Club and our allies the perfect opportunity to fight back by urging banks to stop funding Keystone XL,” the organization told its supporters immediately following the decision—as it started naming names.

“Wells Fargo currently supports two loans to TransCanada totaling $1.5 billion ... Wells Fargo can stop this funding right away and move to end all of its investments in KXL and tar sands. When we stand together, we are stronger than Big Oil’s money, and in this moment we can still fight back by showing Wells Fargo that they will be held publicly accountable for betting against our climate by investing in dirty fuels,” Sierra Club said in a statement.

Tracking protests

The trade group Energy Builders started a new online Energy Infrastructure Incident Reporting Center in 2017 to help the industry in “tracking and exposing attacks on critical energy infrastructure. Incidents of eco-terrorism, sabotage, arson, vandalism and violence are on the rise as severe actions have become a regular feature of pipeline protests, endangering public safety, the environment, jobs, and leaving taxpayers on the hook for millions of dollars.”

Bellamy ranked environmental opposition as the top midstream issue for 2018.

“There is an increased polarization of opposition and support of fossil fuels. The mainstreaming of climate alarmism continues, and I think that's only going to put further pressure on new projects,” he said. “We have seen a bit of a shift in the pendulum at the federal level but the state level remains tough to build infrastructure on either coast, where energy is needed. Local protests have swayed many local elections. Midstreamers need to step up their public relations game.”

Perhaps the bitterest fight as the year began was across the border in Canada. Kinder Morgan Inc. continues to face intense opposition from local and provincial officials to expansion of its Trans Mountain Pipeline linking Alberta producers with tidewater at Vancouver, British Columbia—even though the project has federal approval by Canada’s National Energy Board.

Ralph Cantafio, with the Colorado law firm of Cantafio Hammond, told attendees at the recent Pipeline Leadership Conference in Plano, Texas, not to discount the impact these protests will have on the midstream because the opponents—like the industry—view what they do as a business.

“Each project protested is a business opportunity to raise awareness and the ability to raise funds for environmental groups,” Cantafio told conference attendees. “It creates a call for action. Each protest provides environmental groups a forum to raise exposure and provide a new venue to raise funds.”

He noted that environmental groups saw donations skyrocket during the well-publicized DAPL protests.

“Projects with good economics will still be built—however, they will cost more and not be as profitable,” Cantafio added. “Projects with modest economics will on the margin not be built because the increased cost will make the rate of return unacceptable or the cost benefit analysis a loss.”

Hack attack

Be aware that pipeline opponents won’t appear only in court or at construction sites, Bellamy cautioned.

“Computers and algorithms keep getting smarter and hackers continue to be more dubious, and I think that cybersecurity is going to take an increasing amount of CEOs’ time,” he said. “On the one hand you’ve got efficiencies, lower G&A and lower operating costs with the use of SCADA systems and automation. But on the other hand you have an increased risk of being hacked with a bad actor that brings a risk of somebody hacking in and controlling or disrupting your system.

“When you’re handling hazardous materials, I think cybersecurity is doubly important. Infrastructure firms must get smarter and stay on top of these issues,” he added.

EY Global echoed his view in a fourth-quarter 2017 oil and gas study, finding the industry has been comparatively slow to adopt advanced—and more secure—technology.

“As oil and gas companies think about a path forward in a rapidly changing landscape, the majority of oil and gas executives are seeking to take proactive measures to deal with digital

transformation,” the study said. “In the past, oil and gas companies have been slow to adopt above-ground digital technologies. However, prolonged low commodity prices are driving companies to increase their investment in digital technologies to transform their business models, address the threat from competitors outside the sector and manage changing customer behaviors.

“Although 40% of oil and gas companies are looking to develop digital capabilities in-house to support their digital transformation agenda, many are considering a mix of internal and

external capabilities,” EY continued.

The big picture

So what will the energy business look like in the long term?

It could be good news for oil and gas producers and the midstream. The U.S. economy grew comparatively well in 2017—GDP was up 3.3% in the third quarter—as did most world economies.

A recent DNV report, “Energy Transition Outlook 2017,” speculated that any supply/demand balance may be short lived as economies become more energy efficient, renewables take on a bigger role and as shale plays grow in importance. The study projected energy production and usage trends through 2050.

“Combined with shale oil and gas, and abundant new oil and natural gas, this points towards a world about to experience an energy surplus, albeit one that is not accessible everywhere. Energy security will be of particular concern in fast-growing economies such as India, due to the sheer pace of growth in demand,” said.

DNV projected that by 2026, just eight years away, China—a rapidly growing market for U.S. crude oil—will replace North America as the world’s largest energy consumer.

As for gas, “The world’s gas demand has more than doubled over the last 30 years,” DNV added. “This increase will slow, but persist for another two decades, with gas demand

peaking in 2035 … As the direct use of gas loses out to electricity and as renewables take an ever-increasing share of the electricity market, the 2050 gas supply will have fallen back down to resemble today’s levels.”

The IEA had a lot to say about the U.S. and North America in its “World Energy Outlook 2017” analysis published in November 2017.

“A remarkable ability to unlock new resources cost-effectively pushes combined U.S. oil and gas output to a level 50% higher than any other country has ever managed; already a net exporter of gas, the U.S. becomes a net exporter of oil in the late 2020s,” the report said. “In our projections, [an] 8 MMbbl/d rise in U.S. tight oil output from 2010 to 2025 would match the highest sustained period of oil output growth by a single country in the history of oil markets. A 630 billion cubic meter increase in U.S. shale gas production over the 15 years from 2008 would comfortably exceed the previous record for gas.

“Expansion on this scale is having wide-ranging impacts within North America, fueling major investments in petrochemicals and other energy-intensive industries. It is also reordering international trade flows and challenging incumbent suppliers and business models.

“By the mid-2020s, the U.S. become the world’s largest LNG exporter and a few years later, a net exporter of oil—still a major importer of heavier crudes that suit the configuration of its refineries, but a larger exporter of light crude and refined products.”

So what will happen?

That depends. After all, predictions about the future are very difficult.

Sidebar story

Waiting On Wall Street

The stock market’s impressive run-up in 2017 to some extent bypassed the energy sector—and that may be changing, according to Baird’s Ethan Bellamy.

“I think energy is underinvested, so I think we could see a rotation back into energy now that we’re coming out of an oilfield recession and things normalize,” he said. “But the group is still confronted with some challenges to its business model; namely that the Street cannot provide a never-ending amount of capital to an increasingly large number of firms. This has been more in focus on E&P firms, with the idea of living within cash flow. It really it comes down to, for both E&Ps and midstreams, wise investment of capital.

“I think there’s probably been too much focus on how returns are provided to investors, be it buybacks or dividends or distributions or stock performance—when what investors really want are returns on invested capital. How capital is returned to investors is really a secondary, cosmetic consideration to generating good returns in the first place,” Bellamy added.

“There’s still a lot of money in private equity,” Davis said. “The question is what’s going to happen to that money?” Many investors moved into the midstream, “and oil and gas investing may not be an inflation hedge anymore.”

Wells Fargo provided an analysis of midstream firms in a recent research report that might draw the interest of investors who are not focused on energy.

“We looked at … 19 midstream companies [excluding Energy Transfer and Williams], and analyzed whether there was a strong correlation between price performance and returns on invested capital,” the study said.

“Indeed, there does seem to be a pretty strong relationship between the two with an R2 of 0.55 ... We also looked at the relationship between value spread [the difference between returns and cost of capital] and the same relationship holds with an R2 of 0.55 ... Clearly, the market is rewarding those companies that delivered better returns on capital over time.

“However, we must admit the relationship is not as strong as we would have thought. Perhaps this is because the market hasn’t been as focused on midstream returns over the past five years, with more of the focus on ‘thematic’ investing and distribution/dividend growth,” the report said.

East Daley Capital analyzed the midstream’s prospects for 2018 as 2017 ended and determined “overall adjusted-EBITDA forecasts skew positive vs. current market consensus, indicating midstream sentiment may be too pessimistic.”

“The midstream sector is at an inflection point as market sentiment has deviated from market fundamentals,” said Justin Carlson, vice president and managing director for research, said in a report. “Even though many midstream companies have taken a beating in 2017, East Daley’s data and models show 2018 could be very positive for many well-positioned companies.”

Carlson added, “It’s a really great time to assess opportunities in the U.S. midstream sector. It only makes sense that more investors will take a hard look at this distressed space. We are already seeing increased interest in this sector and we only expect that to continue into 2018. Not all midstream companies are equal, however; our analysis indicates there are many midstream companies with healthy assets that will generate cash-flow growth in 2018.”

East Daley’s guidance outlook made three points:

  • Analysis indicates that impending 2018 midstream financial guidance announcements could deviate significantly from market expectations;
  • The overall adjusted-EBITDA forecasts for the new year skew positive vs. current market consensus, indicating midstream sentiment may be too pessimistic; and
  • Pessimistic midstream sentiment, higher production growth and gas contract risk are three major themes that will drive the midstream sector in 2018.

—Paul Hart

Paul Hart can be reached at pdhart@hartenergy.com or 713-260-6427.

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