It’s no surprise that the onset of the COVID-19 pandemic early this year shut down upstream mergers & acquisition (M&A) activity, just as it did America’s corporate offices, restaurants, entertainment venues, and schools. U.S. M&A deal flow slowed to a trickle in the first half of 2020 as companies’ valuations dropped along with bid prices and E&P executives struggled to realign expenditures with dwindling cash flows. But, as we’ve seen in the past, energy-commodity price crashes eventually spur a resurgence in M&A activity. The dam finally broke in late July, when Chevron announced a $13 billion takeover of Noble Energy, followed in short order by other, major corporate consolidations that brought the deal value total for the last five months to nearly $50 billion. This time was different in one important way, though: Instead of the strong preying on the weak, the strong merged with the strong in low-premium, all-stock transactions. Today, we analyze this new paradigm and delve into the details of the high-value deals.
Posts from Tom Biracree
The energy industry in North America is in crisis. COVID-19 remains a remarkably potent force, stifling a genuine rebound in demand for crude oil and refined products — and the broader U.S. economy. Oil prices have sagged south of $40/bbl, slowing drilling-and-completion activity to a crawl and imperiling the viability of many producers. The outlook for natural gas isn’t much better: anemic global demand for LNG is dragging down U.S. natural gas prices — and gas producers. The midstream sector isn’t immune to all this negativity. Lower production volumes mean lower flows on pipelines, less gas processing, less fractionation, and fewer export opportunities. But one major midstreamer, Enbridge Inc., made a prescient decision almost three years ago to significantly reduce its exposure to the vagaries of energy markets, and stands to emerge from the current hard times in good shape — assuming, that is, that it can clear the major regulatory challenges it still faces. Today, we preview our new Spotlight report on the Calgary, AB-based midstream giant, Enbridge, which plans to de-risk its business model.
In observance of today’s holiday, we’ve given our writers a break and are revisiting a recently published blog on our last Spotlight Report on Enbridge, Inc. If you didn’t read it then, this is your opportunity to see what you missed! Happy Thanksgiving!
The energy industry in North America is in crisis. COVID-19 remains a remarkably potent force, stifling a genuine rebound in demand for crude oil and refined products — and the broader U.S. economy. Oil prices have sagged south of $40/bbl, slowing drilling-and-completion activity to a crawl and imperiling the viability of many producers. The outlook for natural gas isn’t much better: anemic global demand for LNG is dragging down U.S. natural gas prices — and gas producers. The midstream sector isn’t immune to all this negativity. Lower production volumes mean lower flows on pipelines, less gas processing, less fractionation, and fewer export opportunities. But one major midstreamer, Enbridge Inc., made a prescient decision almost three years ago to significantly reduce its exposure to the vagaries of energy markets, and stands to emerge from the current hard times in good shape –– assuming, that is, that it can clear the major regulatory challenges it still faces. Today, we preview our new Spotlight report on the Calgary, AB-based midstream giant, Enbridge, which plans to de-risk its business model.
On July 20, 2020, Chevron struck the first major energy sector deal since the onset of the pandemic, announcing a $13 billion agreement to acquire U.S. E&P Noble Energy. The transaction comes 15 months after the oil major bowed out of a bidding war with Occidental Petroleum to acquire Anadarko Petroleum, a landmark, $56 billion deal in which the winner may eventually end up as the loser after taking on massive debt. Oxy is just one example of how the sharp decline in oil demand and prices has ravaged producer cash flows and earnings, virtually freezing the M&A market. Despite widespread speculation that a resumption in deal activity would target the most distressed E&Ps, Chevron has broken the market wide open with a blockbuster deal for a premier E&P. The target this time, Noble Energy, has a portfolio very similar to that of Anadarko, and is being acquired at a small fraction of the cost. Today, we examine the strategies that drove this transaction, the impacts on buyer and seller, and the implications for the upstream M&A market going forward.
With Broadway theaters shuttered and Hollywood studios on lockdown, one of the most compelling long-term American dramas is the ongoing saga of U.S. E&P Occidental Petroleum (Oxy). Act One was a compelling David-vs.-Goliath story as Oxy battled oil major Chevron in early 2019 to acquire Anadarko Petroleum and its prime Permian acreage. Among the most fascinating elements was the supporting cast, which featured business legend Warren Buffett, who contributed a critical $10 billion to push Oxy’s deal over the top, versus billionaire investor and corporate raider Carl Icahn, who led an unsuccessful struggle to stop what he called “the worst deal I’ve ever seen.” Oxy snagged Anadarko with a winning bid of $57 billion, the fourth-highest total for an oil and gas transaction and a 20% premium to Chevron’s offer, and predicted strong future production, dividend, and cash flow growth. But those optimistic projections have been upended in the ongoing Act Two, as plunging oil demand and prices from the COVID-19 pandemic have stymied planned asset sales and ravaged cash flows. Oxy has responded by reining in spending, revamping operations, refocusing divestment plans, and restructuring debt. But is it enough? Today, we analyze the company’s current strategies and financial maneuvering, as well as the near-term outlook, under a range of oil price scenarios.
The fortunes of U.S. midstream companies in 2020 and beyond will be largely determined by how shrewdly they invested during the frenzied infrastructure build-out of the past few years. One of the most interesting case studies is San Antonio-based NuStar Energy, a master limited partnership born in 2001 to hold refiner Valero Energy’s midstream assets and spun off as a separate entity in 2007. In May 2017, as the industry was still recovering from the late 2014 plunge in crude oil prices, the MLP made a major play to capture growing Permian production through the ~$1.5 billion acquisition of Navigator Energy, which owned a crude oil gathering, transportation, and terminaling system in the Midland Basin. The purchase was widely panned as overpriced by analysts and investors, and NuStar’s unit price plummeted by 60%. But by 2019, the company’s Permian acquisition — and soaring exports from its Corpus Christi terminal — drove big year-on-year gains in NuStar’s fourth-quarter 2019 operating income and EBITDA. Today, we preview our new Spotlight report on NuStar.
After a decade in which unprecedented upstream production growth triggered massive investment in infrastructure to get crude oil, natural gas and NGLs to market, 2020 is a major inflection point for the U.S. midstream industry. The good news is that after peaking at a whopping $37 billion in 2019, midstream capital expenditures are forecast to steeply decline over the next few years as the lion’s share of the infrastructure needed to gather, transport, process, and store current and expected hydrocarbon volumes has already been built or is nearing completion. And, despite continued cutbacks in capex by exploration and production companies, output is still forecast to rise in 2020, which should boost earnings growth for the midstream sector. But all midstream companies aren’t alike, and the prospects for individual entities vary widely because of the specific basins and hubs where they’ve decided to build, acquire, expand or divest. Today, we analyze the headwinds and tailwinds these companies will experience, and how their decisions over the past few years will help determine their prospects.
After six years of output declines, Haynesville Shale natural gas production surged 25% in 2017, with the lion’s share of the increase coming in a remarkable second-half growth spurt. Preliminary 2018 guidance indicates that producers intend to keep the pedal to the metal, either sustaining or boosting the investment that has brought the play’s output to nearly 8 Bcf/d. Such increased activity indicates that producers have found new advantages in the region. But even though new drilling and completion techniques and producer strategies have significantly enhanced the economic viability of the dry gas Haynesville, it is much more highly dependent on natural gas prices than liquids-rich plays. Today, we continue our series on the rebounding Haynesville play with a look at RBN’s production forecast for the region.
After being left for dead for more than five years, natural gas production in the greater Haynesville region has been surging upward — from about 5.7 Bcf/d this time last year to more than 7 Bcf/d today, an increase of 25% during 2017. Much of this growth has been coming from a new cast of characters, employing different technologies and different strategies than the first wave of Haynesville pioneers that established the play back in 2008, then abandoned it in 2012. But a couple of big challenges face the Haynesville. Today, we begin an examination of the Haynesville that will take us from production trends through producer strategies and finally into detailed calculations of production economics for the play.
Despite a decline in natural gas prices, the nine gas-focused U.S. E&Ps we’ve been tracking fared better from a financial perspective in the second quarter of 2017 than E&Ps that concentrate on crude oil or have a diversified mix of oil and gas production. All nine companies in the Gas-Weighted Peer Group stayed in the black — no small feat — but with lower commodity prices the peer group’s profits fell 28% from the first quarter to just under $1.4 billion. Will 2017 be the gas group’s first profitable year since 2014? Today, we analyze the results for our gas-focused peer group as a whole and for individual companies within the group.
After posting a whopping $160 billion in losses in 2015-16, the 43 exploration and production companies (E&Ps) whose financial performance we’ve been closely tracking roared back to profitability in the first quarter of 2017 on higher commodity prices and cost savings from drilling efficiencies on high-graded portfolios. However, lower oil prices slowed the earnings train in the second quarter, as total adjusted pre-tax operating profit dropped 11.6% to $8.0 billion. Understandably, the 21 oil-focused producers in our universe suffered the biggest impact from depressed crude realizations, reporting a 29% decline in operating profits to just $1.9 billion. The good news is that oil peer group earnings remained solidly in the black, increasing the odds that 2017 will be their first profitable year since 2014. Today, we analyze the results for the individual companies in our Oil-Weighted Peer Group.
An analysis of mid-year 2017 guidance shows that the nine natural gas-focused exploration and production companies we’ve been tracking are still fully committed to the very aggressive exploration and development spending they outlined at the beginning of the year. These Gas-Weighted E&Ps slightly upped their total 2017 capital budgets to $8.87 billion, a whopping 59% boost from their 2016 investment — well above the 44% and 29% increases announced by the Oil-Weighted and Diversified E&P peer groups, respectively. The gas-focused producers also increased their 2017 production guidance by 1% to 1.046 billion barrels of oil equivalent (Bboe), in contrast to the mid-year reductions in 2017 output announced by the other two peer groups. Today, we continue our review of updated capital spending plans by 43 U.S.-based E&Ps, this time with a look at companies that focus on natural gas.
Over the last year or so, Plains All American Pipeline — a large, crude oil-focused master limited partnership (MLP) — has twice made significant changes to its corporate structure and distribution process to free capital to fund organic growth, reduce debt, and strengthen distribution coverage. The changes are efforts to fix a problem: As oil prices plunged, PAA’s distribution coverage fell below 100% in 2015 and 2016, forcing the company to add debt and issue equity to raise cash. An initial restructuring that Plains undertook in mid-2016 included eliminating the incentive distribution rights (IDRs) payable to its general partner — the IDRs had been draining $620 million per year. (For more on IDRs, see Changing Horses in Midstream.) The change resulted in a 21% reduction in the distribution to limited partners as PAA set a minimum annual distribution coverage target of 115%. But plunging profits from the company’s Supply & Logistics segment eroded its coverage to 99% in 2017, triggering another comprehensive review of how it calculates its distribution. In late August, Plains announced a 45% reduction in the annual distribution, from $2.20 per unit to $1.20 per unit, and said it would base future distributions only on the results from its fee-based Transportation and Facilities segments. Today we preview our new Spotlight Report on Plains, which provides a detailed analysis of the likely future performance of all three segments of this major midstream MLP.
Hurricane Harvey and major flooding in Houston and other areas may affect energy markets and lead the 21 exploration and production companies in our Oil-Weighted Peer Group to readjust their 2017 investment programs. But in the weeks leading up to the Lone Star State’s most catastrophic weather event in decades, these E&Ps remained committed to their sharply accelerated 2017 capex plans. Their updated guidance issued with first-half 2017 earnings releases reveal a 44% increase in 2017 capital spending over 2016’s level to $26.5 billion, only a 2% reduction from the $27 billion initially budgeted for this year. The peer group also stayed confident in the long-term profitability of the major U.S. resource plays, which are receiving 80% of their 2017 capex, despite investor concern about lower prices that have triggered a 23% decline in the median enterprise value per barrel of oil equivalent for the Oil-Weighted peers since December 2016. Today we continue our review of updated capital spending plans by 43 U.S.-based E&Ps, this time with a look at companies that focus on oil.
Midstream giant Enterprise Products Partners (EPD) has attracted significant investor interest because of its simplified structure, 51 consecutive quarters of dividend growth and strong coverage — $2.7 billion in retained cash in the past three years. The company, with a market capitalization of $58 billion, has also quietly continued to build out its large integrated midstream network despite the plunge in commodity prices, investing almost $18 billion in organic growth projects and acquisitions in 2014-16. The end result is impressive: Enterprise is now connected to every major U.S. shale basin, every U.S. ethylene cracker and 90% of the refineries east of the Rocky Mountains. As a result, the company is well positioned to benefit from the recovery in oil and gas production, especially in the Permian Basin and Eagle Ford Shale; the surge in hydrocarbon exports; and the rapid growth of the U.S. petrochemical industry. Today we discuss highlights from the second part of our new Spotlight analysis of EPD, which focuses on the company’s Crude Oil Pipelines & Services, Natural Gas Pipelines & Services and Petrochemical & Refined Products Services segments.
