Rumors about potential oil and gas mergers are always swirling, but the announcement of ExxonMobil’s record-breaking deal to acquire Pioneer Natural Resources a couple of weeks ago generated a fever pitch of speculation about potential matchups. In the past week, we’ve seen media reports of possible courtships between Devon Energy and Marathon Oil and then Chesapeake Energy and Southwestern Energy. However, it was Chevron that shocked the oil patch by swiping right on former integrated oil company Hess Corp., opting for a $60 billion acquisition of an E&P with no Permian Basin exposure. In today’s RBN blog, we analyze the drivers and implications of what is now the second-largest U.S. upstream transaction ever.
Posts from Tom Biracree
Sometimes, courtship is better the second time around. After some previous rumors and flirting with a deal in the spring of 2023, ExxonMobil, the largest international integrated oil company, reached an agreement to acquire Pioneer Natural Resources, the largest pure-play Permian producer, for $64.5 billion, the largest-ever U.S. upstream transaction. In today’s blog, we analyze the deal that would make ExxonMobil the top Permian producer, including shifts in the focus and depth of its upstream portfolio, the integration with its existing midstream and downstream infrastructure, and its energy transition goals.
U.S. natural gas producers had a rough start to 2023, with spot prices dipping to just above $2.15/MMBtu this past spring. But optimism was abundant in midyear earnings calls on expectations that demand will eventually soar, driven largely by a near-doubling of U.S. LNG export capacity by the end of the decade. A key question, however, is whether E&Ps have built the inventories of proved reserves to support future production increases to meet that demand. In today’s RBN blog, we analyze the crucial issue of reserve replacement by the major U.S. Gas-Weighted E&Ps.
While the weather-related headlines might still scream “summer” in some places — from stifling heat to powerful hurricanes to downpour-induced mud bogs at Burning Man in the Nevada desert — we’ve actually turned the corner into meteorological fall. Oil and gas prices have moved up from their Q2 2023 lows and supply issues, particularly for oil, are the chief concerns as the heating season approaches. Long-term production by the Diversified E&P peer group, whose production streams are weighted 40%-60% for gas and oil, respectively, are a major factor in U.S. supply. In today’s RBN blog, we analyze the crucial issue of reserve replacement by the major diversified U.S. producers.
As this brutally hot summer meanders towards Labor Day, we’re all facing rising gasoline prices as we head to the beach, to barbecues, or to the mall for back-to-school shopping. The main culprit is crude oil production cutbacks by the Russians and Saudis and the situation would likely be much more precarious were it not for strong U.S. shale output keeping gasoline prices from climbing to $5 a gallon or more — except in California, of course. Crucial to sustaining that production long-term is not just replenishing U.S. oil reserves but growing them. In today’s RBN blog, we continue our look at crude oil and natural gas reserves with an analysis of the critical issue of reserve replacement by major oil-focused U.S. producers.
On average, the landowners and other entities that own mineral and royalty interests in producing oil and gas wells receive about 20% of the gross revenues generated by those wells — and do so without any responsibility for the significant costs and complications associated with well development and production. Mineral and royalty interests have traditionally been a highly fragmented market, with most held and passed down through generations by landowners or purchased by individual investors. However, competition for these interests has become more heated in recent years with the creation of large publicly owned and private-equity-funded consolidators and a new emphasis by E&P companies on adding these higher-margin slices of revenue from leases they own and operate. In today’s RBN blog, we explain mineral and royalty interests and analyze the developments in this massive $700 billion market.
The wave of Permian corporate consolidations has continued unabated as spring transitioned into summer with the public company purchases of two EnCap-funded Delaware Basin private operators: Forge Energy, which was purchased by Vital Energy for $540 million, and Novo Oil & Gas, which was purchased by Earthstone Energy for $1.5 billion. Although the theme hasn’t changed, the funding of the transactions includes an intriguing new element — Northern Oil & Gas, which primarily invests in non-operated minority interests, partially funded the acquisitions by agreeing to take 30% and 33% interests in the assets from buyers Vital Energy and Earthstone Energy, respectively. In today’s RBN blog, we review the emergence of three public non-op-focused E&Ps — Northern Oil & Gas, Granite Ridge Energy and Vitesse Energy — and their recent evolution from consolidators of asset packages to trusted partners of acquisition-focused operators.
It’s true, the Permian is — and will likely remain — the center of attention in the U.S. oil and gas industry, not just for its massive and still-growing production volumes but also for the ongoing consolidation among producers in the West Texas/southeastern New Mexico play. But while the Permian has dominated production and M&A activity the past couple of years, Chevron’s recently announced $7.6 billion acquisition of Denver-Julesburg (DJ) Basin-focused PDC Energy highlights the potential for producers to generate significant production and profits from other major U.S. regions, including the Rocky Mountains. In today’s RBN blog, we analyze Chevron’s latest mega-deal and its impacts on the buyer, seller, and the broader oil and gas industry.
For a major oil and gas producer, organic growth over time is all well and good. But if you want next-level scale — and the economies that come with it — there’s nothing like cannon-balling into the deep end of the pool with a huge, game-changing acquisition. ExxonMobil has already done that twice — first in 2010 with the $41 billion purchase of XTO Energy, then in 2017 when it bought the Bass family’s oil and gas assets for $6.6 billion. Now it’s said to be poised for another big plunge, and to be eyeing the Permian’s largest E&P, Pioneer Natural Resources. In today’s RBN blog, we analyze a potential deal that would make Exxon the dominant producer in the premier U.S. shale play.
The pandemic-induced shackles on U.S. E&P capital spending were shattered by rising commodity prices in 2022, and total investment for the 42 producers we follow rose a dramatic 54% over 2021. But E&Ps haven’t abandoned the fiscal discipline or focus on cash-flow generation that allowed them to survive COVID-related demand destruction and resuscitate investor interest. Their 2023 capital budgets generally sustain the pace of Q4 2022 spending and reflect a modest 17% increase over full-year 2022. However, commodity price trends and changes in investment opportunities have resulted in significant shifts in the allocation of the total investment among the major U.S. unconventional plays. In today’s RBN blog, we’ll analyze 2023 capital spending, region by region.
In marking the third anniversary of COVID’s onset, the Washington Post detailed a study that showed most of us are already shedding the virus-impacted memories of that tedious and often traumatic time to concentrate on looking ahead — a trait scientists label “future-oriented positivity bias.” That transition was clearly evident in the 2022 investment decisions of U.S. E&Ps as the capex budgets of the 42 companies we monitor, pared to the bone during the pandemic, expanded through last year from initial guidance of a 24% increase over 2021 to a final 54% reported increase for the full year. They increased production by 9% year-over-year, but producers haven’t forgotten fiscal discipline or a focus on cash flow generation. In today’s RBN blog, we analyze 2023 capital budgets that generally sustain the pace of Q4 2022 spending and eschew additional increases in a lower commodity price environment.
Punxsutawney Phil presaged six more weeks of winter when he saw his shadow on February 2, the famous groundhog’s annual attempt to predict the arrival of spring that garners national headlines, despite his dismal 39% success rate over the last 150 years. Although we haven’t turned to rotund rodents, we spend a lot of time exploring ways to predict energy industry trends. A far more reliable way to gain early insights into E&P spending and production patterns is by analyzing the year-end results and forecasts issued by the major oilfield services firms, which release their year-end reports well before E&Ps typically do. In today’s RBN blog, we review the data and insights from the reports and conference calls of the major firms that are in constant communication with the major oil and gas producers.
Bragging rights are a big deal in Texas, and we’re not just talking pride about the Astros’ annual rampage through baseball’s post-season. Getting to the top is also a source of immense pride for oil and gas midstreamers, and right now Targa Resources claims the bragging rights as the largest gatherer and processor of associated natural gas in the Permian Basin. Targa’s bold decision to build an integrated gas and NGL business, its timely infrastructure expansions through and after the pandemic, and a recent, accretive acquisition have resulted in a massive footprint where a stunning 25% of forecast Permian gas production growth is expected to take place. But strong competitors such as Enterprise Product Partners, DCP Midstream and Energy Transfer are nipping at Targa’s heels. In today’s RBN blog, we discuss highlights from our Spotlight Report on the company.
As U.S. E&Ps deal with a slew of shorter-term challenges such as broken supply chains, labor shortages, and infrastructure constraints, they’re also paying increasing attention to a longer-term concern: “inventory exhaustion.” There is a growing chorus of analysts asserting that oil and gas producers’ inventory of top-tier drilling locations has been significantly depleted as the nation’s major unconventional resource plays mature. Many producers have continued to rein in their capital spending and husband their current resources and several have boosted inventories through bolt-on acquisitions. Premier E&P EOG Resources has taken a different approach, emphasizing organic exploration that has led to the discovery of two new significant plays over the past two years, including the recent announcement of a new Utica Shale combo play that it describes as being “almost reminiscent” of the early Delaware Basin. In today’s RBN blog, we discuss EOG’s dramatically different approach to building inventory and dive into the details of its new Utica discovery.
Bragging rights are a big deal in Texas, and we’re not just talking pride about the Astros’ annual rampage through baseball’s post-season. Getting to the top is also a source of immense pride for oil and gas midstreamers, and right now Targa Resources claims the bragging rights as the largest gatherer and processor of associated natural gas in the Permian Basin. Targa’s bold decision to build an integrated gas and NGL business, its timely infrastructure expansions through and after the pandemic, and a recent, accretive acquisition have resulted in a massive footprint where a stunning 25% of forecast Permian gas production growth is expected to take place. But strong competitors such as Enterprise Product Partners, DCP Midstream and Energy Transfer are nipping at Targa’s heels. In today’s RBN blog, we discuss highlights from our new Spotlight Report on the company.