Largest Ever U.S. Shale Oil Deposit Identified in Texas

By Aaron Sidder  21 November 2016

The Wolfcamp shale, which underlies a large swath of Texas roughly centered on the city of Midland, contains 20 billion barrels of oil that could be recovered with current technology.

A water pool attached to Robinson Drilling rig 4 in Midland County, Texas. Last week, the USGS estimated that the Wolfcamp shale that lies beneath the Midland region is the largest shale oil deposit ever identified in the United States. Credit: Associated Press/James Durbin, Reporter-Telegram

As global oil prices remain mired in their worst downturn in decades, news from western Texas suggests that petroleum fortunes continue to smile on the region.

In its first assessment in nearly a decade of the Permian Basin, a large sedimentary basin underlying parts of Texas and New Mexico, the U.S. Geological Survey (USGS) has determined that a vast deposit of shale there, known as the Wolfcamp shale, contains much more oil than previously estimated. In fact, according to a USGS announcement last Tuesday, the region contains what is estimated to be the largest amount of continuous oil—meaning oil accessible only by means of hydraulic fracturing, or fracking—ever assessed in the United States. The agency estimated the Wolfcamp shale contains 20 billion barrels (3.2 billion cubic meters) of oil that can be recovered using today’s technology. That’s nearly 3 times as much recoverable oil as estimated in the Bakken–Three Forks accumulation in North Dakota. A similar assessment had estimated, in 2013, that the Bakken–Three Forks oil field was the largest continuous oil accumulation in the United States.

Unlike “conventional” oil that accumulated underground in discrete, buoyant pools on a column of water and can be drawn to the surface using a traditional vertical drilling rig, unconventional continuous oil accumulations commonly occur in shale reservoirs or coal beds. In these accumulations, the oil has dispersed throughout the geologic formation.


The Wolfcamp shale lies in the Midland Basin portion of the Permian Basin. The map shows the basin’s “assessment units” (regions with similar geology, exploration strategy, and risk characteristics) in west Texas. Credit: U.S. Geological Survey, Energy Resources Program

The Wolfcamp shale makes up part of the Midland Basin, a major component of the Permian Basin, along with the Delaware Basin and the Central Basin Platform. The Permian’s basins were low-lying marine features that collected sediments rich in organic, deepwater material, which eventually became the petroleum source rocks in production today. According to Chris Schenk, project chief of the National and Global Petroleum Assessment and a coauthor of the USGS report, the Permian source rocks form strong stratigraphic traps that seal oil in the rocks, creating one of the best petroleum systems in the world.

The Wolfcamp shale also contains an estimated 16 trillion cubic feet (453 billion cubic meters) of associated natural gas and 1.6 billion barrels (245 million cubic meters) of natural gas liquids, according to USGS.

Welcome, but Not Surprising, for Petroleum Industry

The agency’s announcement hardly comes as a surprise to those who work in the Permian Basin. In a statement to Eos, the Permian Basin Petroleum Association commented that the USGS estimate was exciting but was more of a confirmation than a new story.

The Wolfcamp shale also contains an estimated 16 trillion cubic feet of associated natural gas and 1.6 billion barrels of natural gas liquids, according to USGS.

Troy Cook, a petroleum engineer with the U.S. Energy Information Administration, agreed and added that if anything, some companies may even find the estimate on the low end. For example, the oil company Pioneer Natural Resources has stated that continuous oil in the Wolfcamp shale and an overlying deposit known as the Spraberry Formation could eventually produce upward of 100 billion barrels (16 billion cubic meters) of oil.

For decades, oil and gas companies have used vertical wells to access conventional oil accumulations in the Permian Basin; however, the oil industry is now mostly using hydraulically fractured horizontal wells to retrieve the continuous oil found in the Wolfcamp shale.

Schenk said there are roughly 3000 horizontal wells currently operating in the Wolfcamp shale. Production data from these wells, along with research articles, industry subsurface data, and other background sources, were used to craft a geologic framework of the basin and derive the newly reported estimate.

Even Greater Potential?

Cook noted that although the USGS estimate is substantial, it is hard to determine if the assessment is big or small compared to other potential resources in the Permian Basin. The Permian Basin is one of the most prolific basins in the world, he said, and as engineering and technology evolve, they may open up other shale resources for exploration and development.

The Permian Basin is one of the most prolific basins in the world, and it may contain other unknown shales with large potential resources.

Walter Guidroz, program coordinator for the USGS Energy Resources Program, said in the USGS press release, “The fact that this is the largest assessment of continuous oil we have ever done just goes to show that, even in areas that have produced billions of barrels of oil, there is still the potential to find billions more.”

The USGS assessment, although large, may not capture the full extent of the Wolfcamp resource. Because well production data inform so much of the estimate, the estimated resource could grow even larger in time as new wells provide more data, Schenk said.

—Aaron Sidder (email:, Freelance Science Writer

Citation: Sidder, A. (2016), Largest ever U.S. shale oil deposit identified in Texas, Eos, 97, doi:10.1029/2016EO063225. Published on 21 November 2016.

© 2016. The authors. CC BY-NC-ND 3.0

U.S. Gas Production, Consumption Hits Record in 2015

The market for natural gas continues to grow as the U.S. currently produces and consumes more gas than ever before, according to EIA’s 2015 Natural Gas Annual.

Prices for consumers continue to decline, although residential pricing for heating remains highest in the Eastern United States. Net imports also continue to decline as the country starts to export more natural gas and as LNG export facilities begin to come on line.


Domestic dry natural gas production totaled 27.1 Tcf, or 74.1 billion Bcf/d in 2015, a 4.5% increase above 2014.

[U.S. Gas Production, Consumption Hits Record in 2015]

Source: EIA

Pennsylvanian production increased to 13.04 Bcf/d in 2015 over 11.56 Bcf/d in 2014. This is the third consecutive year that the state has recorded the largest total gain in annual production.

Ohio recorded the largest increase, percentage-wise, of any state, for the second consecutive year. Dry natural gas production in Ohio doubled from 1.31 Bcf/d in 2014 to 2.62 Bcf/d in 2015. With the exception of Louisiana and Texas, steady or continuing to increasing production is the norm across the U.S.


Total natural gas deliveries to residential, industrial, commercial, and power generation consumers increased 2.8% to 25.1 Tcf, or 68.6 Bcf/d, in 2015.

[U.S. Gas Production, Consumption Hits Record in 2015]

Source: EIA

The favorable economics of gas generation continue to drive gas demand as coal plant retirements continue. Power sector consumption of natural gas increased 18.7% to a record level of 26.5 Bcf/d while natural gas for vehicle fuel also increased 11.6%. Deliveries to the residential, commercial, and industrial sectors dropped by 9.4%, 7.7%, and 1.5%, respectively, from 2014 levels, offsetting the increase in power consumption.


Natural gas residential delivery prices have continued the long-term decline from their mid-2000s highs. 2014 featured a slight increase in prices, due to price spikes brought about by extreme winter weather and transportation issues in the Northeast.

[U.S. Gas Production, Consumption Hits Record in 2015]

Source: EIA

States with the highest prices for delivery to residential consumers were primarily located in the capacity-strained Northeast and warmer Southeast. West Coast pricing was also in the upper percentile, due to a lack of regional production and dependence on Canadian imports.

[U.S. Gas Production, Consumption Hits Record in 2015]

Source: EIA

NatGas Imports and Exports

Natural gas imports rose year-to-year for the first time since 2007, increasing 0.8% to 2,718 Bcf. Pipeline imports from Canada’s Western shale basins into the Upper Midwest and Pacific Northwest accounted for a large percentage of the total. LNG from Trinidad/Tobango, Norway, and Yemen to the East and Gulf Coasts provided a small share of the total.

Higher imports were offset by the first year-to-year rise in gas exports since 2012 and net imports continued their steady downward trend.

[U.S. Gas Production, Consumption Hits Record in 2015]

Source: EIA

Exports increased 17.8% from 1,514 to 1,783 Bcf, with 1,054 Bcf going by pipeline to Mexico, roughly 700 Bcf to Eastern Canada, and 28 Bcf by LNG tanker. Texas LNG shipments went to Brazil, Egypt, and Turkey while Alaskan loads were sent evenly to Taiwan and Japan.

There's a 'black gold rush' happening in America

The so-called hunt for yield is causing a "black gold rush" into one of America's richest oilfields, according to Citi analyst Scott Gruber.

Because interest rates and bond yields have been low, investors everywhere have been searching for the next best investing opportunity to increase their chances of a bumper return.

And in their search, "investors have plowed money into private equity funds who have turned to their old friend, oil and gas, for the prospect of outsized returns," Gruber and his team wrote in a note on Tuesday.

US exploration and production companies, or E&Ps, have raised $18 billion in equity this year, according to FactSet data cited by Gruber. Half of that amount was raised in the high-quality Permian Basin, which includes parts of Texas and New Mexico. Meanwhile, the E&Ps have found ways to drill oil more efficiently.

"The combination has spurred acreage values higher in the Permian which has incented some privates to sell or initiate the IPO process," Gruber wrote.

"In turn, this has spurred public E&Ps to issue equity to be earlier in the capital raise queue and/or raise funds to develop newly acquired acreage, ultimately taking advantage of the same thirst for yield."

The gains in acreage or land values have in turn improved the valuations of oil explorers in the Permian Basin.

Private E&Ps, particularly in the Permian Basin, have accounted for nearly 80% of the recent gains in the oil rig count. As of Friday, the US oil rig count had gained in 10 out of the past 11 weeks, the longest streak since before oil crashed two years ago, according to the drilling giant Baker Hughes.

However, the count of the more efficient horizontal oil rigs in the Permian Basin is still 53% below its peak, Citi estimated.

The Permian Basin Secret: How efficiency plays a role in today's energy marketplace

Source: U.S. Energy Information Administration

With the price of oil in the mid-$40 range this week and plummeting to a low of sub-$27 earlier this year, energy companies are tightening the purse strings on new exploration and extraction.

They’re focusing the most attention on the high-producing and low-cost rigs of the Permian Basin — where rock formations tend to be thinner and require less drilling and upkeep.

In looking at the latest rotary rig count data by Houston-based oilfield services company Baker Hughes, the Permian Basin had 142 rigs, by far the state and nation’s most-active basin. (There are 178 active rigs in Texas and 408 in the United States, according to the data.)

It’s no coincidence, then, that the average break-even cost per barrel of oil in Bone Spring, Spraberry and Wolfcamp formations — all in the Permian Basin — are lower than those of the nearby Eagle Ford.

Source: U.S. Energy Information Administration

When looking at average break-even numbers, it’s important to note that there will be rigs with higher and lower breakeven points and that even one highly efficient or inefficient well can easily skew the numbers.

Still, take a look at the latest map of active oil and gas wells by the U.S. Energy Information Administration that we could find. The largest cluster? You guessed it: The Permian Basin.

Good Regulation” Won’t Hurt Texas Oil And Gas

The price of oil will be higher next year than it is now and regulation won’t kill the industry. Those are two takeaways from one of the state’s top oil and gas officials.

Ryan Sitton is a Republican politician. But contrary to what some of his colleagues say about government regulators of the oil & gas industry, Sitton says they are not necessarily a “job-killing bureaucratic communist machine…”

Sitton was speaking to the NAPE convention underway in Houston, that’s an industry group for people who develop oil & gas fields.

”Too often these days when we talk about the world of regulation, it’s so often discussed in political jargon that we miss the true impacts of good regulation,” Sitton told a hundred or so conventioneers at the NAPE event in downtown Houston.

Sitton is one of the three elected officials on the Railroad Commission of Texaswhich regulates drilling.

One on one, he told News 88.7 that the commission needs to do a better job of working with communities. His comment was prompted by a question about a new state law that prevents local communities from banning the controversial drilling method called fracking and leaves it to the state commission to oversee.

“You asked me if this is something we can live with; absolutely. I live in a little town, Friendswood and we’re right next to the Friendswood Oil Field. There are pipelines and oil wells in our town,” Sitton told us.

Sitton said Friendswood officials have told him that they don’t know anything about fracking and want the experts at the state commission to regulate it.

But is the commission up the job? By its own admission, it’s having trouble hiring enough inspectors. Sitton told us they’re asking the state legislature to authorize the hiring of more inspectors. 

But the question Sitton says he gets asked most often: where’s the price of oil headed?

“I believe we will see $60 a barrel next year, “ Sitton told the NAPE audience, citing decreases in oil production that he said is closing the gap between output and demand.

Oil and Gas M&A Seen Accelerating as Fear of Bad Deals Fade

Energy acquisitions are poised to pick up as oil and gas prices stabilize and fears of bad deals wane, according to Ernst & Young LLP.

Acquisitions will accelerate in the fourth quarter with most of the announced deals coming through next year, Andy Brogan, global oil and gas transaction leader at the consultancy said. There are about 2,000 energy assets available globally and buyers and sellers are gaining confidence as industry price expectations “coalesce,” he said.

Oil has traded in a range between about $42 and $52 a barrel since early June after almost doubling from a 12-year low in February amid speculation a global glut is easing. Oil and gas deals in North America alone so far this year have outpaced mergers and acquisitions in the same period in 2015, according to data compiled by Bloomberg. Last year as a whole marked the lowest level since 2004.

“Everybody has now sort of reset to a new forward curve,” Brogan said by phone from London on Friday. “The way the market was moving destroyed peoples’ confidence that they understood how the market works. People can now have a conversation about what an asset is worth with both sides being comfortable that they’re not going to be made fools of by doing the deal.”

Marginal Costs

About 80 percent of the assets announced for sale are upstream projects, according to Brogan. Price expectations for as long as a 15-year period may help buyers assess the value of an asset that has a 20- to 30-year life span, he said.

Global oil prices are now set by the cost of marginal U.S. shale production, Brogan said. Insufficient investment in future output because of lower prices means that in two to three years the market may move back to where the Organization of the Petroleum Exporting Countries produces the marginal barrel, according to Brogan.

“At that point in time, you have OPEC back in a position where if they act coherently they could reintroduce price discipline,” Brogan said.

Exxon Mobil Corp. last week agreed to acquire natural gas explorer InterOil Corp. to add discoveries in Papua New Guinea to its portfolio. With the range of potential payouts valuing the agreement at as much $3.6 billion, it may represent Exxon’s biggest acquisition since the $35 billion purchase of U.S. shale explorer XTO Energy in 2010.

“We have seen a number of processes initiated in the last month or so that indicates that firstly, there is renewed confidence among sellers, they can actually start a process and actually get to a conclusion,” said Brogan. “Secondly, we are also seeing a renewed interest on the buyers front.”

Texas Oil And Gas Industry: Down, Not Out

THE OIL AND GAS INDUSTRY is big in Texas. So, despite the promise of the Permian and the shine of the Eagle Ford, it comes as no surprise that The Lone Star State is feeling the blow of the two-years-and-counting industry downturn. For those not following the happenings as closely as folks who live and breathe (and swelter in) Texas, I've rustled up some statistics that may help paint the picture.

This May, Texas bankruptcy courts passed Delaware in terms of cumulative debt administered, according to Haynes and Boone LLC. The firm's latest Oil Patch Bankruptcy Monitor, dated May 31, counted 41 E&P bankruptcies-representing nearly $24.3 billion in cumulative secured and unsecured debt-filed in Texas since 2015, putting the state in the unenviable top spots for volume and debt by Haynes and Boone calculations.

The largest of the Texas filings was that of LINN Energy. The company filed voluntary petitions for restructuring under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas in May. In fact, Texas Alliance of Energy Producers, the nation's largest state association of independent oil and gas producers, noted in its May newsletter that LINN's $10 billion debt made the company's bankruptcy "the biggest among energy companies so far in this downturn."

Tough times for companies mean tough times for employees. Job losses across the state have been dramatic. According to the Texas Petroleum Index (TPI), a service of the Texas Alliance of Energy Producers, the number of jobs trimmed from upstream oil and gas company payrolls in Texas surpassed 100,000 in May 2016, declining to 205,100 from a peak of about 306,020 in December 2014. "The last time industry employment was this low was in late 2010, as the last expansion of upstream oil and gas activity in Texas was just beginning to take off," said Karr Ingham, the economist who created the TPI, in a June 27 update.

And while it's likely cold comfort, the job losses actually pale in comparison to those of the late 1980s. A straight comparison of the current downturn to the industry bust of the 1980s is hard to formulate, but it's estimated that job losses in the industry reached somewhere near 240,000 in Texas alone during that time, John Graves of Graves & Co. told Bloomberg in a late fall 2015 interview.

Considering drilling activity in Texas has declined more than 80%, Ingham said it's a "minor miracle" that only about 32% of jobs have been cut since December 2014.

So about that drilling activity…the monthly average of active drilling rigs in April 2016 declined to less than 200 for the first time since June 1999. The rig count continued downward in May, despite higher crude oil prices. The Baker Hughes count of active drilling rigs in Texas averaged 182, 51.5% fewer units than in May 2015 when an average of 375 rigs were working. According to Baker Hughes calculations, the Texas rig count as of June 3 was 176, down almost 81% from the weekly count in November 2014-the count just before rigs began to drop.

The Railroad Commission of Texas (Commission) issued a total of 606 original drilling permits inMay 2016 compared to 916 in May 2015. The May total included 488 permits to drill new oil or gas wells, 13 to re-enter plugged well bores and 105 for re-completions of existing well bores. The breakdown of well types for those permits issued May 2016 included 179 oil, 28 gas, 354 oil or gas, 17 injection, zero service and 28 other permits.

In May 2016, Commission staff processed 760 oil, 199 gas, 60 injection and 11 other completions compared to 1,299 oil, 201 gas, 72 injection and seven other completions in May 2015. Total well completions for 2016 year to date are 5,529 down from 9,832 recorded during the same period in 2015.

Now all that said, the price of WTI has inched steadily upward, resting just above $46/bbl in late June.

"It appears increasingly likely that we have seen the bottom, and that is certainly cause for some celebration and cautious optimism about where we are headed at this point," Ingham said in May, noting that just as it took time for these indicators to trend downward following the fall of crude oil prices, positive changes will likely take several months to appear following the price uptick.

But if you're looking for positivity - and who isn't? - keep one eye on The Lone Star State. Remember those 176 rigs I mentioned? Those rigs represent roughly 43% of all active rigs in the US. Many producers looking to put rigs back to work are targeting the Permian. Exceeding all other districts in Texas, the Midland district saw 221 original drilling permits issued and 304 completions processed by the Commission in May. Texas may be down, but it is certainly not out.

Analysts: Permian Holds Seeds Of Production Growth

Permian Basin - Log Analysis Solutions

Brought to you by the Oil an Gas Investor 

As oil and gas production continues to decline in basins across Texas, the Permian Basin still holds the potential for impressive economic returns and substantial production growth, according to a recent report by Bernstein Research.

Catalyzed by the shale revolution, U.S. producers added nearly 4 million barrels per day (MMbbl/d) starting in 2011, with Texas contributing more than half of that growth, the analysts said.  Texas producers began pumping the brakes as oil prices collapsed, but production in the Permian Basin “has been growing in a time when others are struggling to stay flat,” according to the report.

“The shale revolution may have begun in gas and may have landed on other plays following that, but it has clearly ended in the Permian,” they said.

The basin makes up about one-fifth of U.S. oil production today. Legacy and “non-horizontal” or non-shale growth has been maintained at 1 MMbbl/d since 2011, with roughly 1 MMbbl/d of horizontal growth.

Currently, Permian production is composed of about 0.5 MMbbl/d of legacy, 0.5 MMbbl/d of non-horizontal growth and nearly 1 MMbbl/d of horizontal growth, which was increasing 0.25 MMbbl/d year-over-year since 2011, the analysts said.  Of the horizontal growth, 0.5 MMbbl/d is from the Delaware, 0.35 MMbbl/d is from the Midland and the negligible remainder is from other basins.

The Permian Basin has proven that it has significant inventory, that it can grow and that it can generate “powerful economic returns.” These factors, coupled with its low geopolitical risk, have garnered the attention of the more than 27 integrateds and publicly traded E&Ps with exposure in the basin, the report found.

Bernstein’s own coverage identifies seven public companies with exposure: Apache Corp. (NYSE: APA), Anadarko Petroleum Corp. (NYSE: APC), ConocoPhillips (NYSE: COP), Devon Energy Corp. (NYSE: DVN), Encana Corp. (NYSE: ECA), EOG Resources Inc. (NYSE: EOG) and Noble Energy Inc. (NYSE: NBL).

The Permian owes its steady production levels to its rig count, which has fallen slowly and minimally compared to other plays. Although non-Delaware and non-Midland counts “have hit record lows and in some cases even zeroed out,” key Midland counties to the west “have maintained their share.”

Well productivity isn’t why rigs haven’t fallen as fast in the Permian, as compared with the higher rates in individual wells in the Bakken and Eagle Ford, Bernstein reported. Instead, Permian rigs were kept in the field thanks to growth operators who were hedged, ensuring the cash flow needed to continue high levels of activity and the basin’s potential for growth. 

Lateral lengths, another component in Permian production, experienced “massive year-on-year growth” from 2007 to 2013. But according to recent data, growth is approaching single digits.

In 2009, both Delaware and Midland wells’ laterals were about 3,000 feet. Now, the “Midland Basin has grown to 7,500 feet while the Delaware only 5,500 feet.” The Delaware’s shorter wells result from “checkerboarding,” or railroad land grants’ effect on acreage ownership, and could be remedied by joint ventures and acreage swaps, the analysts said.

The Midland Basin to the east has experienced a plateau in lateral lengths for the last few years, while the Delaware Basin has recently stepped up its pace. The Delaware “has the most to gain in capital efficiency” and “looks like the long-term winner” in projected long-lateral development, according to Bernstein.

At the moment, the Midland appears more valuable, yielding $10,000 to $25,000 per acre, with an average of $13,480/acre last year. Prices in the Delaware are rising from their current average of $6,640/acre.

Meanwhile, “in practice, the equity market appears to place a value of $20,000 to $40,000/acre on the Permian acreage of most operators,” the analysts said.

A Permian E&P company is worth owning, they said, because of its ability “to generate future discounted cash flow significantly in excess of a) its costs, b) its valuation and c) its peers.”

The analysts attributed this notable cash flow to a Permian E&P’s capacity to drill more wells and have wells that both return cash flow quickly and generate greater cash flow than capex.

Top E&Ps operating in the Permian include EOG, which boasts some of the longest laterals and “is improving the fastest in the basin,” according to Bernstein.  On the other end of the spectrum, Anadarko “has the most room for improvement on well cost … well productivity needs to improve at the same time.”

Apache’s acreage position is significant, but the company may reap more benefits if it focuses on core holdings, whereas ConocoPhillips could profit from “upsizing exiting the basin or deploying capital elsewhere,” according to the report.

In all, the Permian Basin “is the last large arena for oil production growth in the U.S,” Bernstein concluded. 

What The Failed Halliburton-Baker Hughes Deal Means For The Oil Service Industry

One of the biggest proposed mergers in the oil industry in recent years, the $35 billion deal between the two oil service giants Halliburton and Baker-Hughes, has been abandoned in response to opposition from the U.S. Department of Justice. Halliburton will pay a $3.5 billion penalty for the deal’s cancellation, while Baker-Hughes has noted losses related to the deal of about $500 million. Yet the stock price of both companies rose on the announcement that the merger was being abandoned.

The straightforward explanation is that investors felt the deal was unlikely to go through, or would not yield favorable results if it did. Which raises the question of what they knew (or believed) that the two companies’ executives did not? Most likely, they expected the deal would not be approved, as the Justice Department looked askance at the potential combination of the second and third largest oil field services companies and its impact on competition. Since less competition and higher prices would undoubtedly be one of the benefits from the merger, the Justice Department’s concerns were a clear signal that even if allowed, the conditions, including spinning off large units, would be onerous enough to prevent those gains. The strong opposition from the oil industry obviously reinforced the government’s interpretation.

The other possibility is that investors did not believe the cost savings would meet projections. Halliburton expected to be able to save $2 billion annually, or about 4% of revenue, but given the two companies size, it seems unlikely that gains from economies of scale would be widespread. No doubt there are places were combining back-office services could result in some savings, but again, these are not small firms with underemployed HR people who could accept a doubled case load. Selling off redundant rigs would simply mean creating low-cost assets available for competitors, and reducing workforce (and equipment) does not require a merger to accomplish.

Given the history of megamergers, which are usually driven by optimism about “synergy” and cost savings, the market was naturally skeptical about the benefits in this case. Study after study has shown that most mergers do not generate the expected benefits, and there is not much reason to think this one would have been different.

The two companies were not suffering from being too small, but from the inflation that crept into their operations and costs during the boom years; a merger is hardly the best way to solve that. Indeed, the prospective merger put most cost-cutting on hold, a typical downside to mergers that is often overlooked or underestimated. Wall Street seems to feel that the combination of operational confusion before, during and after the merger, and lower than expected returns from economies of scale, would translate into a typical case of overreach and the resultant subpar financial outcome. Arguably, the merger effort represented executives desire to make a grand statement and/or hubris about their ability to sway the Justice Department to approve the deal, but that judgement awaits more analysis than can be done now.


The message to the service industry generally is that cost control is going to be their obsession for the near-term future. Higher oil prices would bail many out, but thinking that they will rise significantly above $50 in the next few years is naïve. Yes, war and revolution could send prices soaring, but a business strategy that relies on such is foolish.

With two of the three service industry giants now committed to layoffs and other cost reductions, the rest of the industry will be under pressure to respond accordingly (if they haven’t already done so). Laid off skilled workers will depress wages in the sector and the prices for equipment rentals (deepwater rigs, for example) should remain depressed. Offshore rig utilization is about 50%, down from 80% two years ago, while estimated capital expenditures for offshore are down about 25% in the same period. The value of many rigs will probably be written down and deep discounting will allow them to find work, but ultimately, the path forward will be long and painful.

Fracking And Survival In A West Texas Oil Field


A frack operation in the Permian Basin of Texas, the nation's highest-producing oilfield. The Basin was once the floor of an ancient seabed that today is laden with hydrocarbons.

The massive fall in the price of crude oil means hundreds of thousands of people are no longer working in the energy business and many small and mid-level energy companies are in a footrace against bankruptcy.

While many oil fields have a seen oil production fall, the Permian Basin of west Texas, the nation's highest-producing oilfield, is still increasing production.


Sam Sledge is a Technical Operations Manager at Pro Petro, an energy services company. He says the players that survive the downturn will inherit the business of those that don't when energy prices rebound.

Sam Sledge showed me through a field in Midland Texas that had been transformed into pipes, trucks, 2500 horse power pumps and dozens of scurrying workers.  “This is the heart of the operation right here," he said.  He is Technical Operations Manager atPro Petro, a drilling services company based in Midland.

During the oil boom, when the price of crude jumped to more than 100 dollars plus per barrel there were approximately 30 fracking companies working this oil field. Today that number is less than 20. Sledge says the market may be hurting that but the technology of what's called the "horizontal play" - drilling down deep into the earth and then sideways - is still working here. 

“It’s just been trial and error with this new horizontal play in west Texas over the last 5-10 years, to just dial it in to where we’re going to get the most out of the rock as possible," Sledge explained with respect to the increasing efficiency of the technology.

Sledge showed me a trailer arrayed with computers and real-time charts monitoring the flow in the pumps connected to the well.

"14 different pumps on location, shift gears, throttle up and down. All of that is where you can control the horse power from, right here," said Sledge.

A wellhead near Stanton, Texas. The rig count in the Permian Basin has fallen by 50 per cent since April 2014. But production is rising.

As an industry, drillers are improving their efficiency. One example is 3D seismic readings, physics and software that pin down exactly where oil is which means more fracks are successful.  So despite low prices and a plummeting number of rigs working the Permian Basin, as of April oil production was still rising. This time last year there were 255 rigs here.Today, just 120. Yet production is higher, from 1.8-million barrels per day in April 2015 to two million in April 2016.

The U.S. Energy Information Agency predicts that production in the Permian will begin to fall next month, in May, catching up with other oil fields such as the Niobrara in Colorado or the Bakken in North Dakota and Montana, which have already seen a dip in production.

Fewer companies are doing the work. But those that remain can benefit because ofthose that have left.

"Right now it's a pretty simple battle for market share," continued Sledge, who has an MBA from Baylor University.

"It's in our interest to survive because the companies that are going out of business are going to in turn give us their business when we turn back around."

Until then, survival means slashing costs, said Russell Gold, Senior Energy reporter at the Wall Street Journal and currently a Fellow at the Energy Institute at the University of Texas at Austin.

"The first thing you do is you get on the phone with everyone you do business with and you try to get a cut-rate," he said as he laid out possible defensive strategies companies deploy in a downturn.

Gold is also the author of "The Boom: How Fracking Ignited the American Energy Revolution and Changed the World."

“You make the case that, look this is a major recession for the oilfield and everyone's got to cut."

He said banks are also scrambling.

"There are a lot of regional banks right now that have a lot of oilfield loans out there. They don't want to see everyone go belly up. So they're going to be in the business of selectively cutting some deals. You're going to go to your banker and say,' Please, please give me more time, let's renegotiate, let's work this out.'"

I spoke with Dale Redman, Pro Petro's CEO in his office in Midland. He is charismatic and exudes enthusiasm for the energy business even as it is buffeted by headwinds.

"It is going to work itself out. It is a cycle," he said. "And just about the time everybody says it's over, it comes back."

Redman takes the long view.

"You have to look at this as a marathon, not a sprint," said Redman as he explained his take on the long term view of an always cyclical business.

He said that downturns mean companies like his need to forge an even deeper partnership with oil and gas customers who have financial woes of their own.

“You have to be in tandem with what they’re trying to accomplish and you better understand what their internal rates of returns are to get those costs down.”

Many people wonder why producers don't cut production in the US to restrict supply and thereby raise prices. Russell Gold explained many of these companies live under a mountain of debt and don't have the luxury of that option.

"They need to have cash coming in the door to pay offtheir loans. They can't just simply stop drilling. If you stop drilling, the cash stops coming in."

Critics have called the current energy predicament a "drilling treadmill." What that means is that even in the face of an oil glut and low prices, those who want to survive later must try to stay in the game now.

The Rigzone Interview: TPH Chief Tudor Says Oil Price Already Hit Floor

An ongoing downturn in oil prices has reshaped many businesses. At Tudor Pickering Holt & Co. (TPH), it’s meant less transactions work and more engagement to help companies shore up their balance sheets and plan for the future. And although the downturn has been painful for many in the field, Tudor maintains that the energy industry is still a good space for new college graduates.

Founder and CEO Bobby Tudor runs the premier oil and gas investment banks in Houston. With office throughout the U.S. and Canada, TPH has more than $1.5 billion in assets under management specifically in the energy space.

Days into a price rebound that showed oil selling at slightly more than $40 per barrel, Tudor talked with Rigzone about the business’ cycles and how the energy industry will likely emerge from the downturn. 

Rigzone: What’s your take on the production freeze discussions between the Organization of the Petroleum Exporting Countries (OPEC) and Russia? Is there a real intent to hold production at January levels, or is it just lip service?

Tudor: I think it’s mostly lip service. Primarily because production there (with the exception of) Iran, is mostly frozen now. It’s not going up. I think it’s really meant to signal to the broader market that they’re not going to do anything different from what they’re doing right now. The balancing factor continues to be what happens in North America.


The market is not going to get balanced based on what happens at OPEC at this point because they basically are flat, they’re just not decreasing. To balance the market, there actually has to be a decrease, and the decrease is going to have to come from the United States.

Rigzone: If prices do go up, wouldn’t the effect on prices be minimized when U.S. producers turned the spigot back on?

Tudor: There are a lot of drilled but uncompleted wells, (but) the spigot cannot be turned on immediately. I do think, though, given what’s happened to cost, producers can hedge their 2017 production at $45. For example, they would do that and do it aggressively and would produce more at those levels. It’s all driven ultimately by what price can you hedge, and I think at $45, there would be a lot of hedging and more production.

That being said, the ultimate question is what price is required for the United States to keep production flat. We don’t think the United States could keep production flat in the $40s. We think it’s going to have to be $50 or more for it to keep production flat.

Rigzone: Let’s talk a little about the businesses themselves. The spring borrowing base redetermination, in which banks re-evaluate corporate debt, is upon us. What do you expect to happen to that source of financing?

Tudor: We’re expecting average redeterminations to be down 25 to 30 percent, and if that’s an average number, then that means there are some that are down 50 percent. But there will be some that are basically flat. That’s a very different thing from what we saw in the fall, when redeterminations were down 8 to 10 percent on average. We are expecting pretty dramatically higher levels of downward redeterminations.

Rigzone: So this is the moment the finance executives have been dreading as the downturn has dragged on for more than a year?

Tudor: I think time is not your friend when you continue to have soft commodity prices. The banks have been, frankly, bending over backwards to work with people. But at some point, if you still have an oil price in the $30s and the banks have regulators breathing down their necks and reserves for so many of these companies are fundamentally uneconomic in the $30s … the banks have no choice but to take down the bases, and that’s what they’re doing.

Rigzone: What do you suppose this means for reserve-based lending going forward?

Tudor: I don’t think reserve-based lending goes away. Typically, it’s been the very best place to be in the whole capital structure if you’re a lender to the energy industry. But they have to be sensitive to price, and there’s just not that much in North America that is economic in the $30s. Costs are too high, and for you to book those reserves, you need higher commodity prices and that’s just not where we are at the moment. I don’t think reserve-based lending goes away at all. It’s just the amount that they can lend in a price environment like this has gone down. There’s nothing magic to that.

Rigzone: What will be the enduring impact of this downturn?

Tudor: I think people will definitely be a lot more cautious on the backend of this for a meaningful period of time – meaning I think CEOs and boards are going to be less inclined to lever back up. I think they’re going to be a little less inclined to outspend their cash flow. I think banks are going to be inclined to be less aggressive. I think it will be a while before the high yield market opens back up with these covenant-light deals we saw a lot of in 2013, 2014 and early 2015.

So on the whole, the industry is going to come out of this more cautious. That being said, capital markets have very short memory spans, and when people – people being investors – start making money again by participating in equity deals and high yield deals in the energy business, the markets will open back up. It always happens that way, and there’s no reason to believe it won’t happen that way again.

I do think that boards of directors for energy companies are going to be less comfortable in outspending their cash flow dramatically, assuming capital markets are going to be there for them. We had a period of time when the markets just weren’t there; there’s also basically been no (acquisitions and divestitures) market to help you fund things. When you have a near death experience, it tends to impact you. We think there will be more caution on the back end of this, and frankly, that’s good for the oil price, just because it means we’re not going to see this immediate hard-snap back to dramatic year-over-year growth in North America.

Rigzone: Do you expect oil prices to dip any further?

Tudor: We think we probably have seen the bottom. But inventories are still very heavy. I think a lot depends on what happens with inventories in the next month or two – do we see continued drawdowns and returns to more normalized levels? We think you will, but we could be wrong. It’s a little hard to predict.

Rigzone: At what point will transactions activity pick up in the market?

Tudor: We’ve been saying that to have a functioning asset market in the United States, we need propped oil prices at $40 and above. And prices five years out, in and around $50, and we’re just not there yet. The problem has been to date if you were selling assets at the current strip with the [prop month] being in and around $30, and a five year number in and around $40, it actually really didn’t help you all that much. And so, you just didn’t have buyers who were willing to look at that strip price and say well, even though the five year strip says $40, I’m willing to use a longer term price of $50. Buyers were just not in that mood. So we’ve just needed an uplift in that forward curve to have a functioning A&D market and we’re not there quite yet, but directionally, we’re going in the right way and it feels a bit better.

Rigzone: How has downturn impacted what you do at TPH?

Tudor: It has slowed the overall (mergers and acquisitions) market pretty dramatically. If you look at overall M&A volumes in the last year, and in particular in the last three to six months, they’ve been down very dramatically from … the five or seven year average, so we’ve spent more time on restructurings, and more time helping companies think through balance sheet issues and planning for the future. It has slowed transaction activity a lot in the upstream and in oilfield services. The healthiest market generally has been in the midstream space, where those assets have generally continued to trade at high valuations. There hasn’t been a ton of them on the market, but the ones that have been on the market have generally traded pretty well.

Rigzone: How would you advise a recent graduate interested in working in the oil and gas industry?

Tudor: I think it’s a great place to be. You just have to recognize that it’s a cyclical industry and there are periods when supply and demand get out of balance and when that happens, the industry tends to shrink. But you know what? It happens to manufacturing, it happens to autos, it happens to technology – it’s not the only business that has cycles. It’s just that this particular cycle seems really harsh and painful, and it is. I’ve had a lot of people who have been running energy companies for 30 years saying this is as painful as they can remember, including back to the mid-80s. But the world will continue to need energy, and the United States will continue to be a very important supplier of that. Our degree of confidence in the industry is very high and that’s what I would tell a college senior.

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Big Star’s first Wolfcamp horizontal well delivers record results

Brought to you by Shale Gas International

Big Star Oil & Gas announced yesterday that their first well in the Wolfcamp shale, in Howard County, has achieved the highest reported 30-day average rate of any Howard County Wolfcamp horizontal well to date .

The well has a productive lateral length of 7500′, and was completed using a 30-stage hybrid hydraulic fracture stimulation. The well achieved a peak 24-hour IP rate of 1725 boepd (2-phase) and had a 30 day IP rate of 1469 boepd, consisting of average rates of 1358 bopd and 670 mcfd (92% oil).

According to Railroad Commission data, Big Star’s Ryder Unit A2H well produced 23% more oil and gas in its first month than the previous top horizontal Wolfcamp well, Athlon Energy’s Tubb 39 #5H. The Ryder Unit A2H is also performing significantly above the company’s 752 MBOE Wolfcamp type curve.

The Wolfcamp Shale is located in the prolific Permian Basin and is tipped to be the next leading shale play in the U.S.

Scott Sheffield, chief executive officer of Pioneer Natural Resources, who is the largest acreage holder in the Spraberry/Wolfcamp field with about 900,000 gross acres (730,000 net acres), said back in 2013 that “The Wolfcamp could possibly become the largest oil and gas discovery in the world.”

The Wolfcamp’s variety of geological zones places it as a frontrunner among the world’s largest onshore plays. Based on recoverable reserves, the Wolfcamp is second only the Ghawar field in Saudi Arabia.

“We believe this field will reach 100 billion boe recoverable reserves at some point in time,” Sheffield said.

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Analysts have noticed that operators in the Wolfcamp Shale that have focused on the field tend to perform much better in the region than companies that have recently moved in or only spend a fraction of their drilling budgets in the play.

“It’s not based on location,” Benjamin Shattuck, an analyst with Houston energy research firm Wood Mackenzie, said last June. “It boiled down to attention to the Permian: How long have these operators been operating in the Permian and, if they hadn’t been operating in the Permian for long, how focused are they?”

On announcing the impressive results from the Ryder Unit A2H well, Bradley Cross, President and Partner at Big Star Oil & Gas, said: “We are pleased with the record results that we have been able to achieve to date. The successful drilling and completion of our Ryder Unit A2H horizontal shale well strategically positions Big Star among a small population of private, independent oil companies with the technological capabilities and resources to be a top-tier shale player in the Midland Basin.”

Big Star is currently completing two additional Howard County horizontal wells, one in the Wolfcamp A shale and one in the Lower Spraberry shale.

The company has identified 207 gross development locations within the Wolfcamp A, Wolfcamp B, and Lower Spraberry shale horizons across its approximately 11,000 net acres of Midland Basin leasehold, and is seeking additional horizontal well development opportunities in the Middle Spraberry and Cline formations.