With oil prices higher than they’ve been in some time, it’s no surprise that the 44 major U.S. exploration and production companies we track reported — as a group — the highest quarterly profit and cash flow since 2014. Regaining a solid financial footing has been a long, painful struggle for crude oil and natural gas producers, who slipped into a river of red ink after the crude oil price collapse in late 2014 and 2015. After implementing a dramatic strategic and operational transformation, the industry returned to the black in 2017 despite a mid-year oil price dip, generally weak gas prices, and lingering write-downs from massive portfolio shifts. Now, strengthening oil prices and continued operational and financial discipline have lifted our E&Ps well above breakeven and suggest a higher trajectory for the remainder of the year. Today, we dive into first-quarter 2018 financial reporting by leading E&Ps to identify the drivers of a remarkable recovery.
Daily energy Posts
As Permian crude differentials continue to widen, trading at a $8.45/bbl discount to Magellan East Houston this week, a lot of people are pointing fingers at midstream companies for not completing new takeaway pipeline projects quickly enough. But even in the oil patch, it takes two to tango and producers can also share some of the blame. Historically, the focus in the Permian has been on larger producers, with their sprawling acreage positions and their focus on creating long-term competitive advantages through efficient drilling programs. Many of the smaller, private equity-backed producers adopted more short-term strategies. Their game has been to prove undervalued acreage and then flip those assets to more substantial players. But these strategies are beginning to change. Today, we continue our series on Permian differentials with a look at how the recent ramp-up in the development of second- and third-tier production areas is affecting the region’s crude oil output, pipeline takeaway constraints and price differentials.
Everyone in the North American gas industry knows that a big wave of U.S. LNG exports is coming. Although Cheniere Energy’s Sabine Pass terminal in southwestern Louisiana started shipping out LNG in 2016, exports really started having a major impact in 2017 — increasing demand for U.S.-produced gas, providing an outlet for Marcellus and Utica supplies, and affecting physical flows at the Henry Hub and in south Louisiana more generally. But with the first four liquefaction trains at Sabine Pass all but fully ramped up, attention in recent months has been turning to the next facility being commissioned: Dominion’s Cove Point terminal on Chesapeake Bay in Maryland, which exported its first cargo in early March. But tracking gas pipeline flows into the Cove Point plant has not been easy, and in today’s blog, we consider the various possibilities and discuss our view of how best to monitor the amount of LNG feedgas going into Cove Point.
The Permian is a beehive of activity on the burgeoning water midstream front — the pipelines, saltwater disposal wells and other assets being built to facilitate the delivery of water to new wells for hydraulic fracturing and the transport of “produced water” from the lease to disposal or treatment sites. But the Bakken — arguably the birthplace of the water midstream sector nearly a decade ago — is no slouch, and a model of sorts for the infrastructure build-out now under way in the Permian. The volume of water needed for Bakken well completions is up sharply in recent years; more important still, the region is generating more than 1 MMb/d of produced water, and producers and water midstreamers alike are building new takeaway pipelines and drilling new SWDs to more efficiently deal with it. Today, we discuss water- and produced-water-related infrastructure in one of the U.S.’s largest production regions.
Permian Basin natural gas production is growing at a torrid pace. After starting 2017 just below 6 Bcf/d, production is set to breach the 8-Bcf/d mark soon on its way to 10 Bcf/d by the end of 2019. Pipelines flowing out of the basin are coming under increasing strain, and just about every single gas pipeline leaving the Waha hub in West Texas is now being utilized at levels not witnessed in years — if ever. Even routes north from the Permian to the Midcontinent and Midwest markets, traditionally only attractive on the coldest winter days, are starting to look viable year-round. Today, we look at recent gas-price and flow trends in the Permian natural gas market.
Despite widespread predictions that the oil and gas exploration and production sector would drown in an ocean of red ink after the crude oil price crash that started a little over three years ago, E&P companies finally returned to profitability in 2017. Better yet, with oil prices exceeding $60/bbl, margins are expected to increase in 2018, giving the 44 major E&Ps we track $24.5 billion in incremental cash flow. It’s no surprise that the 17 companies in our Oil-Weighted Peer Group are the prime beneficiaries of the higher crude price, garnering $13.6 billion, or 55%, of the incremental cash flow. Today, we continue our review of how rebounding oil prices are affecting E&P cash flow, this time zeroing in on oil-focused producers.
Price differentials in the Permian Basin are widening at a rapid pace. The discount for Midland crude to West Texas Intermediate (WTI) at Cushing has widened by over $4/bbl since the beginning of March and the discount to Magellan East Houston (MEH) crude was over $7/bbl yesterday. Permian production is increasing at a breakneck pace as new players are entering the scene. Private equity-backed exploration and production companies (E&Ps) are no longer just acquiring and flipping acreage, as they are being forced to prove their assets are profitable and can generate a return on investment. The combination of large drilling plans from the majors and new production from these smaller operators — with no new pipeline takeaway capacity in sight — has sent Permian crude pricing into a tailspin. Today, we begin a new series on the recent slide in Permian prices, how new producer strategies are contributing to it, and what it means for pipeline space, trucking and midstream infrastructure.
Efforts to increase natural gas production in the Rockies are running into a brick wall — make that several brick walls. To the east, burgeoning gas production in the Marcellus/Utica region is surging into Midwest markets, pushing back on Rockies gas supplies. To the south, Permian gas production is ramping up toward 8 Bcf/d, most of it associated gas from crude-focused wells — volumes that will be produced even if gas prices plummet. To the west, Rockies gas faces an onslaught of renewables in power generation markets, where wind and solar are increasingly replacing gas fired and coal generation, especially during non-peak periods when the sun is shining and the wind is blowing. To the north, Western Canadian producers facing a where-do-we-send-our-gas problem of their own are only days away from having expanded pipeline access to U.S. West Coast markets — access likely to displace some of the Rockies gas which has been flowing west. Today, we discuss highlights from a new report by our friends at Energy GPS that assesses these developments and explores their implications.
Crude oil and natural gas production in Oklahoma have fully rebounded from the declines that followed the 2014-15 collapse in oil prices and stand at 21st-century highs. While the active rig count in the state — at about 120 in recent weeks — is off 10% from its post-crash peak in mid-2017, the productivity of new wells continues to rise, as does interest in the Merge play between the SCOOP and STACK production areas in central Oklahoma and in the Arkoma Woodford play to the southeast. All that has put additional pressure on the state’s existing pipeline and gas-processing infrastructure and spurred continuing activity among midstream companies. Today, we begin a review of ongoing efforts to add incremental processing and takeaway capacity in the hottest parts of the Sooner State.
The Louisiana natural gas market is in a state of major flux. The state’s supply mix has changed drastically, with Offshore Gulf of Mexico production declining over the past few years and the long-dormant Haynesville Shale making somewhat of a comeback in the past year. At the same time, four new liquefaction trains at Cheniere Energy’s Sabine Pass LNG terminal have added more than 3.0 Bcf/d of export demand that didn’t exist before 2016. These trends signal a shift in Louisiana’s supply-demand balance and are a prelude to big changes yet to come as producers and midstreamers look to provide solutions for balancing the market. Today, we continue our deep-dive into recent and upcoming changes in the Louisiana market, this time focusing on flow trends across the state’s North, Offshore Gulf and Central pipeline corridors.
With crude prices in the $60s, oil-producing basins other than the Permian are finally seeing signs of life, and that includes the Rockies. But volumes flowing through the most important Rockies crude oil hub — at Guernsey, WY — are down. Moreover, the price of oil at Guernsey is up, trading at least flat and sometimes at a premium to the downstream market at Cushing, OK, suggesting that committed shippers are having to bid up the price at Guernsey to secure barrels for their downstream pipeline commitments. What about production from the nearby Powder River Basin? Well, Powder River oil production is up, and the rig count there is double what it was this time last year, so you might think there would be more than enough barrels at Guernsey. But not so. Who’s to blame? We need to look no further than the Bakken and the Dakota Access Pipeline (DAPL) to discover our culprits. Today, we check in on the market at Guernsey and consider the impact of DAPL, the implications for Rockies crude oil outflows, and what it all means for Guernsey price differentials.
The U.S. natural gas storage inventory lagged behind year-ago and five-year average levels throughout this past winter. The market started the withdrawal season in November 2017 with about 200 Bcf less in storage than the prior year. That year-on-year deficit subsequently ballooned to more than 600 Bcf. Compared to the five-year average, the inventory went from about 100 Bcf lower in November to a more than 300-Bcf deficit now, at the beginning of spring. An expanding deficit in storage is typically a bullish indicator for price. Yet, the CME/NYMEX Henry Hub natural gas futures contract struggled to hold onto the $3.00/MMBtu level it started the season with in mid-November, and, in fact, has retreated back to an average near $2.70 in the past couple of months — about 25 cents under where it traded a year ago. Today, we look at the supply-demand factors keeping a lid on the futures price.
How a company or industry handles adversity is a valuable test of its mettle. But assessing long-term sustainability requires a second test: handling prosperity. Recently released 2017 results of U.S. exploration and production (E&P) companies confirm that the industry not only defied predictions of widespread bankruptcies and credit defaults after the oil price plunge in late 2014, but learned to generate profits in a $50/bbl crude oil price world. And the E&Ps’ 2018 guidance, issued as oil prices appear to have stabilized above $60/bbl, indicate that the industry is sticking with the new financial discipline that drove its recovery, a remarkable departure from the financial profligacy in the emergence from down cycles over the previous three decades. Today, we examine how 44 large U.S. E&Ps are responding to a rebounding oil sector.
With LNG export demand rising along the Gulf Coast, there are big changes coming to the Louisiana natural gas supply-demand balance, with significant implications for the national benchmark pricing location Henry Hub. The state’s growing demand center is attracting midstream investment and supply from two of the fastest growing producing regions — Appalachia’s Marcellus/Utica and West Texas’s Permian. An analysis of pipeline flow data is already providing clues as to how markets will evolve in the Bayou State. Today, we continue our flow analysis of the Louisiana pipeline corridors, this time with a focus on interstate flows across the state’s western border.
Crude oil production in the Permian Basin is coming on strong — faster than midstreamers can build pipeline takeaway capacity out of the basin. You can see the consequences in price differentials. On Friday, the spread between Midland, TX and the Magellan East Houston terminal (MEH) on the Gulf Coast hit almost $5.00/bbl, a clear sign of takeaway capacity constraints out of the Permian. We’ve seen different variations of this scenario play out in recent years, most recently last fall, just before the first oil started flowing through the new Midland-to-Sealy and Permian Express III pipelines, and it’s not good news for Permian producers. Now Permian output is again bouncing up against the capacity of takeaway pipelines and in-region refineries to deal with it. As we’ve seen in the past, that’s a warning sign for possible price-differential blowouts. Today, we discuss the fast-changing market dynamics that put Permian producers at risk for another round of depressed Midland prices.
ExxonMobil earlier this month told analysts in New York that the company expects to add a total of 400 Mb/d of capacity to its three giant Gulf Coast refineries by 2025. Exxon plans to upgrade existing refineries in Houston (Baytown) and Baton Rouge, LA, to increase production of higher-value products and to add a new crude distillation unit to its 362-Mb/d Beaumont, TX, plant after 2020. A final investment decision on the Beaumont expansion — which reportedly would double the refinery’s throughput capacity and make it the largest refinery in the U.S. — is expected later this year and follows a $6 billion investment by Exxon to triple crude output from its Permian Basin production assets in West Texas. Today, we discuss the existing Beaumont operation, its feedstock sources, and the refined-product demand that supports the plant’s expansion.