Consolidation, commodities to drive energy M&A
Global M&A in 2016 will likely surpass the hyperactive deal making that totaled $4.7 trillion in 2015, but whether the energy industry will see a surge in activity is yet unclear, according to two recent reports.
A Mergermarket report showed a 27.2% reduction in total number of deals in the energy sector in 2015 compared to 2014. The value of those deals was down by 6.8% to $547.7 billion. Low commodity prices are leading to increased scrutiny of MLPs, the report said, and will contribute to a shakeout.
“While midstream MLPs are expected to weather the storm, upstream MLPs will pursue a variety of survival strategies in a prolonged low oil and gas price environment, but not all will make it,” said Mergermarket.
KPMG LLP’s survey of global executives found a bullish outlook generally for M&A. Among energy leaders, 47% identified consolidation of core businesses and competition as the leading driver for deals this year. The second key trend, picked by 43% of respondents, is the persistence of lower oil prices.
The top two challenges that energy executives perceive are valuation disparity between buyers and sellers (47%), and the general economic environment (42%). However, executives in all industries pointed to large cash reserves (51%) as the leading driver of M&A followed by the availability of credit on favorable terms (36%).
“Strong balance sheets tend to determine the method of ﬁnancing deals,” the KPMG report said.
Michael Underhill, founder and chief investment officer of Wisconsin-based Capital Innovations and author of “Handbook of Infrastructure Investing,” echoed that sentiment.
“The market’s focus has shifted from companies’ slowing growth prospects, which have characterized much of 2015, to the need for efﬁcient capital allocation given pockets of balance sheet stress in 2016,” he told Midstream Business recently. “Companies are not being paid to grow dividends in this environment.
Instead, we believe those with strong balance sheets and the best access to capital should continue to outperform their peers.”
KPMG’s survey showed an expectation that megadeals—those valued at $50 billion or more—are on the rise. Among factors that could inhibit M&A, executives included concerns such as:
• Slowing economic growth (42%);
• Rising interest rates (27%); and
• Lack of suitable targets (26%).
Bankruptcy case could challenge acreage dedications
A bankruptcy proceeding involving an upstream company may result in a ruling that challenges acreage dedications for midstream operators.
Judge Shelley Chapman of the Southern District of New York said that she was “inclined” to permit the rejection of gathering and processing agreements between Houston-based Sabine Oil & Gas Corp. and two counterparties. The decision could save the independent E&P a signiﬁcant amount in ongoing payments.
“Many midstream companies have long taken comfort in acreage dedications in midstream contracts being characterized as ‘covenants running with the land,’” Akin Gump Strauss Hauer & Feld LLP stated in a report. “This has historically served as a protection against asset sales being made without the new owners being subject to the contracts.”
With ongoing weakness in commodity prices squeezing the ﬁnances of many in the upstream, the meaning of the dedications is now being tested in bankruptcy court, Akin Gump wrote. In the ﬁrm’s opinion, such a rejection would be supportable under Texas law.
Immediate cost savings aside, asking for a ruling like this would not necessarily beneﬁt an E&P in terms of dealings with midstream partners.
“Given the unique nature of many of these gathering and processing systems, it is likely the counterparties will still want to work together due to the critical need for cash ﬂow on both sides,” Akin Gump wrote. “Contract renegotiations will turn on the leverage of the parties involved, particularly whether the E&P company can survive a shut-in (harming cash ﬂow and potentially putting its oil and gas leases at risk) or has another way to move or process its hydrocarbons.”
As a defensive measure, Akin Gump suggested that midstream companies and ﬁnancing partners consider options for mitigating risk in the future. This could take the form of a security requirement or contract structuring.
With oil prices likely to remain low, the law ﬁrm said it expects ongoing questions to emerge in oil and gas bankruptcy proceedings, with each case turning on speciﬁc background facts, contract language, applicable state law and how a particular court interprets applicable precedent.
Giving executives a game plan for 2016
The energy industry is pondering strategies in the wake of low oil prices: should executives be defensive-minded or go on the attack?
Five top energy analysts from Stratas Advisors described the ﬁeld of play for the oil and gas industry’s year at Hart Energy’s ﬁrst Viewpoint Executive Energy Club in Houston. The Stratas Advisors directors touched on all aspects of the industry, from pricing and geopolitical concerns to storage capacity and bankruptcies.
In 2014, Stratas expected oil prices to top $60 per barrel (bbl) throughout 2016. With its revised outlook in fourth-quarter 2015, Stratas predicts $50 well into 2017.
“In simple terms, supply did not adjust as fast as we thought. Actually, supply grew over this time,” said John Paisie, Stratas executive vice president. “Through June 2015, OPEC supply continued to grow. Saudi Arabia ramped up production, and Russia was able to maintain its production even though price dropped.”
Despite about half as many active rigs in the U.S., shale production has continued to grow, even though it has declined from its peak. “At the end of the year, the U.S. still maintained higher production over the previous year,” Paisie said.
In fact, U.S. shale production as a key driver of the world’s pricing dynamics was a recurring theme throughout the event.
“Shale not only changed where supply was coming from, but also changed the very structure of how that supply started to affect price,” said Paul Morgan, executive director for upstream at Stratas.
With supply still coming in, Paisie added that there are concerns about demand growth around the globe. “Demand was strong throughout  but started to waiver at the end of the year,” Paisie said. He cited concerns about China and the U.S. economy as factors.
John Kneiss, director of macroeconomics, geopolitics and policy for Stratas, said 2.3 million barrels per day (bbl/d) is currently at risk due to geopolitical concerns around the world. The Middle East has the most potential for disruption, with Iran and Iraq being most vulnerable.
One of the more interesting worldwide growth indicators was the split growth fortunes of the BRIC (Brazil, Russia, India, China) countries. “Russia and Brazil are in severe recessions right now, and we expect those to continue,” Kneiss said. “India and China still have substantial growth. Overall, Asia is going to continue to carry the global economy.
“The main takeaways are that global growth is still very weak, deleveraging has occurred in central banks, but for now we don’t really forecast a global recession,” he said.
Kneiss doesn’t see OPEC countries agreeing on production cuts anytime soon so he expects prices to remain low.
In the midstream sector, Greg Haas, director of integrated oil and gas for Stratas, pointed to the stock levels as an indication of the first integration of supply and demand.
“In 2015 we completely moved away from historical supply and demand curves,” Haas said. “We’ve gained some much more storage in 2015 as a result of continued production and [low] demand growth.”
He said that the lifting of the export ban provided some measure of export relief, but in the end the U.S. still has a signiﬁcant inventory of crude.
“That certainly has driven prices down,” he said. “We import roughly 650,000 bbl/d of light crude. That light crude is the kind we have sitting in our storage tanks. That’s a pretty strong overhang.”
He said export won’t be enough to eliminate the overhang so the U.S. will remain a net importer.
But there are good signs for midstream operators when it comes to exports. “Anytime you can ﬁnd new markets, that’s a good thing,” Haas said.
He also said that companies with long-lead time projects should be able to ride though the next couple of years of low prices.
But he does expect to see a number of bankruptcies this year.
Midstream M&A shackled by falling prices in 2015
Midstream M&A is primed for a resurgence this year if commodity prices stabilize and public markets again embrace oil- and gas-related assets, Ernst & Young (EY) said in its annual review of global energy transactions.
Of course, the analysts added, if volatility and uncertainty continue to shadow the pricing environment, the downward trend could continue.
Midstream M&A dipped 8% to $149.4 billion last year from 2014’s record, with 84% of all deals and 97% of the total value related to activity in the U.S. and Canada. Transactions started strong in the ﬁrst half of the year but stumbled as the impact of low commodity prices was more keenly felt.
EY noted that midstream companies reacted by:
• Focusing on capex rationalization;
• Employing “just-in-time” investments; and
• Delaying capex until a ﬁrm outlook on commodity prices emerges.
EY’s analysts were intrigued by Mexico’s new FIBRA E public structure that is designed to hold the country’s midstream and infrastructure assets. The structure is in many ways modeled after U.S. MLPs and may allow Mexican markets to raise funds for that country’s needed midstream buildout.
Stress experienced by companies with over-leveraged capital structures will translate into opportunities for larger companies with strong balance sheets, the review said. Continued low oil prices this year “could potentially signal an uptick in M&A as sellers with lofty price expectations realign and buyers become less opportunistic and more strategic in their view,” the analysts wrote.
The report also noted that a wide range of ﬁnancial players have renewed their interest in energy. EY expects numerous bolt-on opportunities for funds already invested in the sector and ﬂush with cash.
What happened to ‘golden age’ of gas?
In 2011, the International Energy Agency published a special report about the bright future of natural gas, declaring that the commodity was on the brink of entering into a “golden age” where it would enjoy a more prominent role in the global energy mix. Fast forward to 2016 and the landscape is ﬁlled with more gray hues than those of gold. What happened these so-called golden years? Did we blink and miss them, or are they ahead of us?
Michael Bradshaw, professor of global energy at Warwick Business School, said not to lose hope during a recent webinar hosted by Vostock Capital. The industry has not missed its best years; they are still on the horizon. In a world motivated by a desire to halt human-created climate change, gas is positioned to be the bridge fuel of choice going forward.
At COP21, held in Paris at the end of last year, more than 140 countries convened and presented action plans for speciﬁc and practical steps to lower their carbon footprints, thereby preventing the planet from warming more than 2 degrees compared to pre-industrial levels. This will necessitate moving away from “dirty” hydrocarbons for cleaner alternatives, creating a window of opportunity for natural gas, which is the cleanest fossil fuel, producing half as much CO2 when burned compared to coal.
To meet COP21’s ambitious climate objective means making the switch to natural gas as soon as possible in order for its environmental advantage to be felt. While a window is open, it is not one that will not stay open forever; time is of the essence. By the 2030s, gas stops being a solution to climate change and starts adding to the problem, at which point even half the carbon emissions of coal becomes higher than permissible. Eventually, it too must be completely phased out.
Bradshaw suggests that is possible to extend the number of years we can rely on natural gas if coal is eliminated sooner rather than later. If Earth’s atmosphere can only handle a certain amount of CO2 before global temperature increase beyond the two-degree mark, the less added each day buys a little more time. It all depends on how quickly countries begin shifting to greener forms of energy, and some are much further along than others. The U.K., for example, plans to eliminate its use of coal by 2025.
Carbon capture and storage (CCS), a technology that can prevent up to 90% of the CO2 produced by power generation and industrial processes from entering the atmosphere, can also keep gas in the mix for longer, Bradshaw said. However, even CCS is not a perfect solution, as a power plant utilizing CCS will have to use more gas to produce the same amount of energy.
No matter the circumstances, if the world is serious about climate change, no hydrocarbon can be used indeﬁnitely, but natural gas is certainly the lesser of many evils. However, despite its attractive carbon proﬁle, its utilization is contingent on how quickly it is embraced. “If there is to be a ‘golden age of gas,’ it’s likely to be short-lived,” said Bradshaw.
Proposed oil tax called industry ‘death sentence’
Despite tough times for the nation’s oil and gas producers, President Barack Obama is proposing a $10.25 per bbl oil fee to pay for clean energy and transportation initiatives.
George Rogers, chairman of the Texas Alliance of Energy Producers, said the tax on the sale of crude oil produced in the U.S. is a needless attempt to strangle an industry critical to the nation’s economy and security.
“A $10-per-barrel tax on an industry already in a deep decline would be a death sentence,” he said. Obama ﬁrst mentioned a $10 per bbl fee, later raised to $10.25 per bbl in his $300 billion “21st Century Clean Transportation System” initiative.
The U.S. Energy Information Administration has forecast Brent crude oil prices to average $40 per bbl in 2016 and $50 in 2017 and if prices linger in the $60s going forward the tax could be crippling.
The proposal was met with scorn by conservative politicians and industry veterans. House Speaker Paul Ryan (R-Wis.) said in a statement “President Obama’s oil tax is dead on arrival in Congress.”
The fee would be phased in over a 10-year period.
Obama’s initiative looks to alter the U.S. transportation system, which accounts for “30% of U.S. greenhouse gas emissions.”
The plan says that travelers choose among walking, biking, driving, ﬂying and taking the train while companies choose between trucks, barges, airplanes and rail lines.
“Our transportation system is heavily dependent on oil,” the plan says. “That is why we are proposing to fund these investments through a new… fee on oil paid by oil companies, which would be gradually phased in…”
By placing a fee on oil, the plan creates a “clear incentive for private sector innovation to reduce our reliance on oil and at the same time invests in clean energy technologies that will power our future.”
The Independent Petroleum Association of America (IPAA) said it makes little sense to tax an industry going through its largest crisis in 25 years. The plan puts a “hidden tax on American consumers currently beneﬁting from low energy costs,” IPAA said. Noted oil man T. Boone Pickens called the tax “the dumbest idea ever.”
Jeff Zients, director of the White House National Economic Council, pushed back against assertions the oil tax would place U.S. crude producers at a disadvantage, Reuters reported. On a press call he said that the fee would be applied to domestically produced and imported barrels of oil but not to crude exported from the U.S.
Saudi petchem proﬁts dwindle amid gloom
Saudi Arabia’s listed petrochemical companies have seen their annual proﬁts for the ﬁscal-year (FY) 2015 nosedive by almost 50%, while others have turned unexpectedly into losses for the ﬁrst time in ages, due to low sales prices and volumes among many other reasons. Oil prices, which have more than halved since June 2014, have also put pressure on petrochemical producers in the kingdom.
The announced results have missed analysts’ forecasts by almost 62% as industry analysts expected an aggregate net proﬁt of $1.3 billion, while the announced aggregate proﬁts—except for Alujain Corp. and Nama Chemicals Co.—were at $480 million.
Saudi Basic Industries Corp., the largest petrochemical producer in the Middle East and North Africa region and the largest listed ﬁrm in the region, saw its FY 2015 net proﬁt fall 20% year-on-year to $5.01 billion on lower sales prices. Fourth-quarter proﬁt dipped 29.4%, its sixth straight quarterly decline. Yousef Al-Benyan, the company’s acting CEO, said during a press conference held following the company’s announcement of its annual results that his company has been implementing a cost-cutting strategy and introducing new products to combat negative market conditions.
Al-Benyan also expressed his optimism about his prospects in the U.S. market, as well as Africa and South East Asia, including Vietnam, Indonesia and Malaysia.
UPS to fuel trucks with LNG
UPS Inc. will be expanding its existing agreement to purchase CNG from Clean Energy Fuels Corp. by adding renewable LNG (RLNG) to the mix, according to a statement by UPS.
Under the current arrangement, Clean Energy will provide UPS with about 1.5 million diesel-gallon equivalents (DGE) of CNG annually in California, where UPS operates almost 400 CNG-fueled vehicles.
Expanding its use of natural gas to power its ﬂeet, UPS has agreed to purchase 500,000 DGE of RLNG to fuel 140 of its trucks in Texas. UPS facilities in both Houston and Mesquite, located just east of Dallas, will dispense RLNG provided by Clean Energy from its “Redeem” biomethane obtained entirely from organic waste streams derived from many abundant and renewable sources, including decomposing organic waste in landﬁlls, wastewater treatment and agriculture.
“Renewable natural gas is helping us meet growing customer demand while reducing our environmental impact,” said Mark Wallace, UPS senior vice president, global engineering and sustainability, in a prepared statement. “Today’s agreement demonstrates UPS’s commitment to develop alternative fuels and advanced technologies. By the end of 2017 we will have driven one billion miles with our alternative fuel and advanced technology ﬂeet.”
Dealmaking starts in ﬁeld services sector
The wheels are slowly turning for deal making in the oilﬁeld services industry.
For months, analysts have predicted a surge in A&D activity for oilﬁeld services companies once the misery from low commodity prices made them hit bottom. For the most part, only giants like Schlumberger Ltd. and Halliburton have had the where-withal to execute deals, but that might soon be changing.
Houston-based service company MRC Global Inc. entered into an agreement recently to sell its U.S. oil country tubular goods (OCTG) business for $48 million. The company said it foresees no changes to its midstream services.
The deal follows Trican Well Service Ltd., Canada’s largest pressure pumper, agreeing in late January to sell its U.S. assets to Keane Group. MRC Global said it will sell to Sooner Pipe LLC, a subsidiary of Marubeni-Itochu Tubulars America Inc., in hopes to reduce its exposure to upstream drilling volatility.
MRC Global is the largest global distributor, based on sales, of pipe, valves and ﬁttings and related products and services to the energy industry, according to the release. Its U.S. OCTG sales were about $305 million in 2015.
“We remain committed to our line pipe business as it has applications across each of the upstream, midstream and downstream end markets,” said Andrew R. Lane, MRC Global’s chairman, president and CEO. “This transaction beneﬁts our U.S. OCTG customers, suppliers and employees by placing the business with the leading OCTG distributor and service provider.”
As a result of the expected sale, MRC Global expects a pretax charge of about $5 million to be recorded in the fourth quarter of 2015.
The transaction is expected to close in this quarter, subject to customary closing conditions. Lane said the company will work with Sooner to ensure a smooth transition of the business.
Houston’s Keane Group, a private well completion services company, agreed at the end of January to acquire Trican’s U.S. assets in a deal worth $247 million. The agreement pays Trican $200 million cash and gives Trican a 10% stake and two seats on Keane’s board.
Keane Group will be the eighth largest pressure pumper in the U.S. after the deal closes. Additionally, Trican’s stock has recently been grabbed by Wilks Brothers LLC, a private Cisco, Texas-based company. Wilks Brother said it acquired an additional stake of about 3 million common shares in the capital of Trican. Earlier in January, the company had acquired about 2.7 million shares of the Canadian company. The values of the transactions weren’t disclosed.
With its most recent purchase, Wilks Brothers owns 20.7 million common shares, or about 14%, of Trican. Wilks Brothers was formed by Farris Wilks and his brother Dan Wilks in 2011. One of the brothers, Farris Wilks, is on Forbes’ list of the world’s billionaires. According to Forbes, Farris and Dan Wilks also founded a fracking and oil-ﬁeld services company named Frac Tech. The brothers sold their stakes in the fracking company in 2011 for $3.5 billion.
Components of Tall Oak deal considered rock solid
On the surface, EnLink Midstream LLC paid $1.55 billion for subsidiaries of Tall Oak Midstream LLC in January and, one month later, the company’s market capitalization had slumped to only $1.3 billion.
But it’s the subsurface that drives this purchase and, as Citigroup Inc.’s Jeff Sieler explained at the recent NAPE business conference in Houston, the qualities involved in this transaction, well, rock.
“There’s a line item in there that says 1,000 drill locations,” said Sieler, who is managing director and co-head, U.S. energy A&D. “The reality is, it’s double or triple that, just on the acreage.”
In the greater area of Oklahoma’s Sooner Trend Anadarko Basin Canadian and Kingﬁsher Counties (STACK) and Central North Oklahoma Woodford (CNOW) plays, ﬁgures will approach 11,000 unrisked drill locations and around 5,000 risked locations, he said.
“Those are really stellar numbers,” Sieler said. “I think the thing that stood out to our subsurface team as we worked this particular set of assets was the economic robustness that we saw associated with it.”
The best-known formations involved are the Woodford and Meramec, with Tall Oak’s midstream assets on acreage located over the core of the play. The acreage is operated by Felix Energy, a Denver-based E&P that was acquired by Devon Energy Corp., EnLink’s general partner, as part of a $2.5 billion deal announced in December.
The midstream assets are strong and include:
• Pipeline systems of more than 200 miles in the STACK and 75 miles in the CNOW with capacity of 175 million cubic feet per day (MMcf/d) and the ﬂexibility to expand to over 1 billion cubic feet (Bcf/d);
• Fee-based contracts that average terms of 15 years; and
• New, state-of-the-art cryogenic processing plants with 175 MMcf/d of capacity and the ability to expand to 700 MMcf/d.
Sieler, who was trained as a petroleum engineer and worked for Shell, Kinder Morgan Inc. and Marathon Corp. before moving into the A&D side of the business, acknowledged that “sweet spots” in plays tend to change over time, but being positioned to handle growth in the play is a plus.
And the play is growing. Not all rigs pulled from unconventional operations around the country are stacked up—some are being relocated into the STACK.
From May to August of last year, the number of rigs moving into Kingfisher and Canada counties rose 50% from 22 to 33. Houston-based Newﬁeld Exploration Co. has indicated that it can position as many as 24 wells in the STACK area, what Sieler called “a remarkable number” in the Meramec and Woodford.
The boomlet is propelled by economics: the breakeven price for a barrel of oil in the stacked Meramec is less than $20, creating unusually happy margins during a time when WTI struggles to stay in the $30s. That’s possible because of the unique subsurface characteristics at play in the region, characteristics that caught the attention of the Citi team last year as it analyzed the transaction for its client.
The internal rates of return that Citi identiﬁed in the STACK were the best to be found in the Lower 48, Sieler said. The area had been studied by E&Ps, and there was plenty of data to conﬁrm the analysis that the 500-foot thicknesses associated with Mississippian rock in the Meramec and Osage plays made for ideal landings for horizontal laterals. Underlying that was the world-class Woodford, with porosities in excess of 10% total organic content.
The more the Citi subsurface team scrutinized the area involved in the deal, the more it found elements to warm the cockles of an energy investment banker’s heart: growing rig count, shallow decline rates of 61% to 63%, access to liquids-rich gas, close proximity to downstream markets.
Finally, a burst of efﬁciency by applying lessons learned in earlier plays.
“What I saw going into the Eagle Ford was literally hundreds of millions of dollars of development, millions and millions of dollars of research, not only by the operators there but by the service companies,” Sieler said. “I looked at the STACK and one thing stands out to me: many of these industry-leading unconventional operators are taking their best practices and applying them faster.”
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