For the majority of global oil & gas companies, 2016 was a tough year. Buffeted by depressed crude oil and natural gas prices, corporate profits were squeezed, sparking widespread restructurings, layoffs and, in certain cases, bankruptcies.In normal circumstances, such conditions would be a boon for merger & acquisition (M&A) activity. However, continued uncertainty over the length and severity of the commodity price downturn has created a value mismatch between buyers and sellers. The result was a moribund M&A market in the oil & gas sector. In fact, according to business advisory firm Deloitte, the first half of 2016 saw the lowest number of deals and deal value in five years. On reflection, it’s easy to see why deal activity in the oil & gas sector slowed. Firstly, there was a notable lack of terminally distressed sellers; hedging strategies have mostly worked and companies have been able to renegotiate debt and lower operating costs. On top of this, there have been fewer funding options available, in terms of both equity and debt, for buyers of oil & gas assets.For 2017, it is very much a buyers’ market in the oil & gas sector, albeit with some caveats. Purchasers are being asked to come up with more innovative ways of structuring deals and are increasingly required to negotiate with a wider group of stakeholders. Further complicating the M&A picture is the emergence of private equity and other financial buyers who, generally unaccustomed to normal industry practice, bring a vastly different approach to risk and costs.
Source: For oil and gas M&A, it’s a Buyers’ Market – Oil & Gas Financial Journal
Houston, 15 May (Argus) — US shale crude output is expected to rise by 122,000 b/d to 5.4mn b/d next month, according to new data from the US Energy Information Administration (EIA).The largest increases will be in the Permian basin in Texas and New Mexico, and the Eagle Ford in south Texas, the EIA said in its latest Drilling Productivity Report.Permian basin production should increase by 71,000 b/d from May to June to about 2.49mn b/d.Output in the top-producing Permian has been more resilient than in other regions during the downturn in commodity prices because of lower extraction costs. Midstream companies are investing heavily to add takeaway capacity out of the region because of the expected rise in output.Eagle Ford oil production is expected to rise by 36,000 b/d to about 1.28mn b/d in June.
Source: News – Argus Media
EOG posted a profit for the first quarter of the year, accomplishing a relatively rare feat in the shale patch. Given its reputation as a top operator it was expected.
Its Eagle ford acreage, which helped earn its reputation, is now showing signs of deterioration in terms of quality as the Eastern part is saturated, while Western part is inferior.
EOG is working to move away from over-dependence on Eagle Ford, increasing presence in currently popular areas like the Delaware basin. It remains to be seen whether it will help.
This was not unexpected, given that other companies involved in shale announced an operating profit for the first quarter of the year. One such company that I just covered was Chesapeake (NYSE:CHK), which is generally not thought of as one of the best in the shale patch. The fact that EOG (NYSE:EOG), which developed a reputation in the shale patch as one of the best, announced a profit did not surprise me. If there is anything to be surprised of here is the fact that the operating profit was only $108 million on revenue of $2.6 billion. Chesapeake by comparison had an operating profit that was double, on similar revenue, as I pointed out in a recent article.
Source: EOG’s Eagle Ford Golden Era May Be Close To Ending – EOG Resources, Inc. (NYSE:EOG) | Seeking Alpha
WildHorse Resource Development is acquiring Eagle Ford properties for US$625 million. The assets, comprising 111,000 net acres (449 square km), are being purchased from Anadarko Petroleum and affiliates of private equity firm Kohlberg Kravis Roberts & Co.In 2016, fourth-quarter net production on the acquired properties totalled 7,583 boepd, comprising 72% oil from 386 operated wells. The assets are located in Texas’ Burleson, Brazos, Lee, Milam, Robertson and Washington counties, adjacent to WildHorse’s existing acreage position. The transaction is expected to close on or around June 30, 2017 with an effective date of January 1, 2017.The Houston-based firm said that production on the purchased acreage came from 68 Eagle Ford, 299 Austin Chalk, and 19 Buda-Georgetown operated wells. The acreage is estimated to contain 949 net Eagle Ford locations and 22.9 million boe of proven developed producing reserves, consisting of 73% oil and 88% liquids.“This transformative acquisition presented us with a strategic opportunity to consolidate our acreage position. With a total of 385,000 net acres [1,558 square km], we have built a premier contiguous acreage base, making us the second largest operator in the entire Eagle Ford trend,” said WildHorse’s chairman and CEO, Jay Graham.
Source: Your Oil & Gas News | WildHorse buys Eagle Ford assets for US$625 million
Investors who took a hit last year when dozens of U.S. shale producers filed for bankruptcy are already making big new bets on the industry’s resurgence.In the first quarter, private equity funds raised $19.8 billion for energy ventures – nearly three times the total in the same period last year, according to financial data provider Preqin.The quickening pace of investments from private equity, along with hedge funds and investment banks, comes even as the recovery in oil prices from an 8-year low has stalled at just over $50 per barrel amid a stubborn global supply glut.The shale sector has become increasingly attractive to investors not because of rising oil prices, but rather because producers have achieved startling cost reductions – slashing up to half the cost of pumping a barrel in the past two years. Investors also believe the glut will dissipate as demand for oil steadily rises.That gives financiers confidence that they can squeeze increasing returns from shale fields – without price gains – as technology continues to cut costs. So they are backing shale-oil veterans and assembling companies that can quickly start pumping.”Shale funders look at the economics today and see a lot of projects that work in the $40 to $55 range” per barrel of oil, said Howard Newman, head of private equity fund Pine Brook Road Partners, which last month committed to invest $300 million in startup Admiral Permian Resources LLC to drill in West Texas.Data on investments by hedge funds and other nonpublic investment firms is scant, but the rush of new private equity money indicates broader enthusiasm in shale plays.”Demand for oil has been more robust than anyone imagined three years ago,” said Mark Papa, chief executive of Centennial Resource Development Inc (CDEV.O).Papa referred to the beginning of an international oil price crash in 2014, which took many firms in the shale sector to the brink of bankruptcy.
Source: Undaunted by oil bust, financiers pour billions into U.S. shale | Reuters
Increasing crude oil production in the Permian basin of western Texas and eastern New Mexico is filling available pipeline capacity, putting modest downward pressure on West Texas Intermediate (WTI) crude oil priced at Midland, Texas compared with WTI at Cushing, Oklahoma. However, the Midland versus Cushing discount, which recently widened to more than $1 per barrel (b), is unlikely to be either as large or as persistent in 2017 as it was following the rapid increase in Permian production over 2010-14. Pipeline capacity expansions and other market changes now underway appear poised to facilitate the efficient disposition of higher volumes of Permian crude oil.Compared with other oil producing regions, the Permian has a large number of productive geological formations stacked in the same area, including the Wolfcamp, Bonespring, Spraberry, and Yeso-Glorieta formations. The Permian’s other favorable characteristics are in-region refining capacity, close proximity to large refining centers on the Gulf Coast, and existing pipeline infrastructure.Crude oil production in the Permian grew by 593,000 barrels per day (b/d) between January 2010 and January 2014, more than could be accommodated by in-region refinery capacity and pipeline capacity. This situation resulted in large price discounts at the crude gathering and transportation hub in Midland, Texas compared with Cushing, Oklahoma, indicating that the marginal barrel of crude oil was moving out of the region via a mode of transport more expensive than by pipeline. In 2014, WTI-Midland averaged a $6.94/b discount to WTI-Cushing, compared with a $1.68/b average discount the prior year. However, as new and expanded pipeline capacity was added in 2014 and 2015, WTI-Midland’s discount to WTI-Cushing narrowed, falling to an average of only $0.07/b in 2016 (Figure 1).
Source: This Week In Petroleum Summary Printer-Friendly Version
Posted in oil, Permian
Tagged oil, Permian
The 2020s could be a “decade of disorder” for the oil markets as the lack of drilling today leads to a shortfall of supply. Demand will continue to grow, year after year, and shale will not be able to keep up.It may be hard to envision today, with an oil market suffering from low prices and a glut of supply. Falling breakeven prices have drillers still churning out huge volumes of shale oil, with production in the U.S. already rebounding and rising on a weekly basis.The tidal wave of shale, however, is the direct result of extreme market tightness a decade ago, which pushed oil prices up into triple-digit territory. The rapid rise of China and other developing Asian countries in the early 2000s put the squeeze on the market, as conventional production struggled to keep up with demand. High prices sparked new shale drilling in the 2010-2014 period, which, as we now know, brought a lot of supply online. That, subsequently, led to a price meltdown.“I think that what you might take away from this historical review, is that oil is volatile. We go through periods of stability, followed by huge increases, followed by the almost inevitable downturn coming off the big spike,” The former administrator of the EIA, Adam Sieminski, said on the Platts Capitol Crude podcast on April 10. But busts in the oil market tend to sow the seeds of the next upcycle.“And we’re in that downturn kind of age now. And everybody is kind of sitting around saying ‘well, maybe shale is going to make it different. Maybe we are going to be less volatile now because shale can feed into rising demand.’ I’m thinking that the decade of the ‘20s is going to be one of difficulties,” Sieminski said. “That’s why I call it the decade of disorder. We’re not getting enough capital investment now, I don’t know that shale is going to be able to do it all.”
Source: 2020s To Be A Decade of Disorder For Oil | OilPrice.com
Posted in oil, Shale
Tagged oil, shale
Two new crude pipeline projects from West Texas’ prolific Permian Basin to the Corpus Christi coastline have analysts crowing about refinery and export expansion in that city. The Houston-based pipeline company Buckeye Partners has proposed a 400,000 barrel-per-day line from Wink and Midland to existing facilities in Corpus.And a three-company consortium — TexStar Midstream Logistics, based in San Antonio, Castleton Commodities International, out of Connecticut, and Dallas-based Ironwood Midstream Energy — have proposed a new 590,000 barrel-per-day pipeline from Orla, Pecos, Crane, and Midland to Corpus, with a stop in Gardendale in the Eagle Ford oil field. Both projects aim to open for business in 2019.
Source: Pipelines planned from Permian to Gulf; Boom to come to Corpus Christi | Fuel Fix
Energy enterprises Repsol and Armstrong Energy say they made the largest U.S. onshore oil discovery in three decades in Alaska.The conventional hydrocarbon oil was found in the Horseshoe-1 and 1A wells initially drilled during the 2016 to 2017 winter campaign in the Nanushuk, an area located in Alaska’s North Slope.
Source: U.S. companies claim largest onshore oil discovery in 30 years – UPI.com
Posted in E&P, oil
Tagged E&P, oil
Storage makes renewable energy available when it’s needed the most. Peak electricity usage happens in the early morning and evening, whereas peak production of solar energy is midday and at night for wind. Given the U.S. electric grid’s lack of storage capacity, conventional power plants, including gas-fired ones, are utilities’ most reliable source of electricity.That could be about to change. In a new collaborative report, “An Underappreciated Disruptor,” Morgan Stanley’s Utility and Clean Tech analyst, Stephen Byrd and Shared Mobility & Auto analyst, Adam Jonas, argue that the price of both solar and wind energy, as well as new storage units, have reached a point where renewable energy can finally become a dependable rather than an unpredictable source of energy. “Demand for energy storage from the utility sector will grow more than the market anticipates by 2019-20,” the report posits. The demand for storage is expected to grow from a less than $300 million a year market to as much as $4 billion in the next two to three years, says the Morgan Stanley report. Ultimately there’s about a $30 billion market for storage units, with capacity for around 85 gigawatt-hours of power storage. That’s enough electricity to light up most of the New York City metro area for a year.
Source: Renewable Energy Storage: The Next Big Power Play | Morgan Stanley