During a panel discussion in which I participated recently with three energy experts, the moderator asked us if we agreed with the recent projection by British oil giant BP that oil demand may have already peaked during 2019. Everyone on the panel answered with a firm “no.”
From my own perspective, I gave that answer in large part because all of the dozens of previous “peak oil” predictions – whether from the supply side or the more recent demand side reasoning – have turned out to be entirely wrong, often in hilarious fashion. From an historical perspective, it just seems like the safer position to take.
That’s not to downplay the position assumed by BP, whose internal expertise is undeniable. But it’s key to note that much of the media coverage the company’s findings have received portrays BP’s position as being far more absolute than it really is. The company’s position on “peak oil” is in fact highly-qualified.
As a part of its recently-released Global Energy Outlook study, the company ran three scenarios based on differing assumptions regarding how rapidly governments around the world would attempt to move to adopt emissions-reducing policies and subsidize renewables. The cases were labeled “Rapid” (the most aggressive assumptions), “Net-Zero” (assuming most governments would adopt ‘net-zero by 2050’ policies) and “Business as Usual”, in which progression would continue on the slower path seen to date.
In a COVID-19 hampered world in which governments across the globe are teetering on the brink of insolvency, the “Business as Usual” scenario certainly appears to be most likely to persist for the time being, given the multi-trillion dollar costs involved in the other two cases. Under that scenario, BP in fact projects that global demand will not only recover to pre-COVID levels seen late last year, but continue to grow through the year 2030.
Today’s news moves at a faster pace than ever. Whatfinger.com is the only real conservative alternative to Drudge, and deserves to become everyone’s go-to source for keeping up with all the latest events in real time.
One of the longest-running dramas in corporate oil and gas history finally came to a climax on Sunday when management for Chesapeake Energy announced it would seek Chapter 11 protection under the U.S. bankruptcy code. The company has traveled a long and winding road to reach this point.
Rumors about the company’s pending bankruptcy have run rampant over the past year as it teetered on the financial brink. But in reality, Chesapeake’s financial troubles go back much further, to the early years of this century, when founder and former CEO Aubrey McClendon famously made a bet on natural gas continuing to be a scarce resource in high demand whose price would remain strong for decades. Based on that market view, the company then went on a buying spree for the next several years, buying up natural gas assets and companies at very high prices. In one acquisition in which the company I worked for – Burlington Resources – was the second high bidder, Chesapeake’s winning bid was $3 per MMBTU equivalent higher. That’s a lot of excess capital deployment.
None of his assumptions about the future for natural gas turned out to be accurate, of course, but it must be pointed out that McClendon certainly was not alone in making them. For example, I personally played a leadership role in a 2003 National Petroleum Council study which attempted to project natural gas supply, demand and prices through the year 2025. The study was led by ExxonMobil and Anadarko Petroleum (acquired last year by Oxy), and included participants from many other industry companies, the Energy Department, the Department of Interior and environmental NGOs.
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The fundamental conclusions and projections of that study basically supported McClendon’s view of natural gas remaining a scarce resource with pretty high commodity prices as far as the statistical models we used could project. It was in fact the prevailing common wisdom in the industry at that time.
The NPC study projected that imports of Liquefied Natural Gas (LNG) would in fact have to make up an increasingly high percentage of U.S. natural gas supply. That incredibly wrong projection led to the building of a series of LNG import facilities in the U.S. and helped compel ExxonMobil to invest billions in its own fleet of new LNG tankers to help supply America’s coming needs.
Today, 17 years later, the advent of gigantic shale natural gas resources like the Marcellus shale, the Haynesville, the Eagle Ford and the Permian Basin mean that U.S. producers must export a prodigious amount of natural gas in an effort to keep the supply and demand curves somewhat in balance. But remember, that study – and McClendon’s assumptions – came at a time before those major shale plays had been discovered. The only natural gas shale being developed during that time frame was the Barnett Shale in North Texas, where Chesapeake was a pioneering operator.
While other operators held similar views about the future for U.S. natural gas, Chesapeake was without doubt the most aggressive in terms of pursuing new reserves. In addition to arguably over-paying for acquisitions of other companies or their assets, Chesapeake became infamous for radically driving up lease bonus prices in every new shale play, in the process running up a prodigious level of corporate debt. At one point, Chesapeake’s corporate debt exceeded that held by ExxonMobil, a company many times its size.
As natural gas prices collapsed in the late ‘00s, McClendon next turned to sales of his own company’s assets or portions of working interests in big play areas as a means of continuing to finance and pay down that debt. He sold shares of the company’s working interests in the Barnett, the Eagle Ford, the Marcellus and the Haynesville to various other players, like BP and CNOOC, but every sale also meant less and less cash flow coming into the company itself. Many in the business during that time joked about it being a sort of a pyramid scheme in which the debts would ultimately end up outstripping the company’s income and ability to pay.
One of the big concerns during the depths of the oil price bust of 2014-2016 was the fact that so many big, integrated and state-run oil companies were delaying or taking a full pass on investing in major and highly-costly international projects. During the financial retrenchment of this dark period, exploration for major new resources consistently took a back seat to finding ways to pay the bills and service the company’s debt.
This lack of investment in new exploration and infrastructure projects led to concerns among many energy analysts that we could be facing a shortage of global supply early in the next decade as decline rates caused existing reserves to play out without the needed new production coming on line to replace them. The surge in new supply from U.S. shale plays has served to alleviate those concerns for the near-term, and a new report issued by the Norwegian research firm Rystad Energy documents a similar surge in new international investments that should help avoid supply shortages further down the road.
“We expect global FID volumes in 2019 to triple over last year, and 2019’s megaproject awards could lead to billions of subcontracting dollars in coming years,” said Rystad Energy upstream research analyst Readul Islam, “The only supply segment likely to shrink this year is the oil sands, whereas deepwater, offshore shelf and other conventional onshore developments are all poised to show substantial growth. From a geographical perspective, all regions are headed for robust growth except Europe and North America, still bearing in mind that shale plays are not included in these numbers.”
That last point – that shale plays are not included in this report – is key. As I pointed out last week, the Permian Basin has become a focal point for major development not just for big independents like Pioneer Natural Resources, Noble Energy, Apache Corporation and others, but also for major, integrated companies like ExxonMobil, BP, Shell and Chevron. These U.S. shale plays are likely to sustain significant production growth for years to come, giving the big investments documented by Rystad in its report the running room they need to move from final investment decisions to first production, which can easily consume five-to-seven years.
So, if you’ve been wondering why all those stories about concerns of a looming supply crunch on the horizon have disappeared from your daily news clips, this is the reason.
Today’s Energy Update
(Because Energy Fuels Our Lives)
The energy media has recently featured headlines that seem at odds with one another and that, when taken together, portend the possibility of a coming train wreck somewhere down the road where crude oil supply and prices are concerned. Let’s look at some of the more recent headlines as examples:
That Investor’s Business Daily story begins by stating “The U.S. shale oil boom is about to get a whole lot bigger. The reason: Giant oil companies like Exxon Mobil (XOM) are leveraging their massive scale to unleash more production from the top-producing shale oil formation.”
Meanwhile, the theme of the Gulf Times story is that pretty much all of the big Permian Basin producers are exercising budgetary discipline, cutting back on their drilling budgets in response to pressure from Wall Street, and focusing instead on maximizing investor returns after the recent drop in prices. Yet, despite this exercise of “restraint,” despite a slightly lower regional rig count, despite the temporary constraints on pipeline takeaway capacity, the U.S. Energy Information Administration (EIA) tells us that the pace of increase in overall U.S. shale production is continuing to accelerate over the first quarter of this year.
“My story starts in 1956 when I was one year old, and M. King Hubbard made a prediction about ‘peak oil.’ He said somewhere around 1970 U.S. production would peak at about 10 million barrels per day and then it would fall off over the next 25-30 years to about 4 million bpd, and the U.S. would be completely dependent on foreign oil.”
Steve Keenan is, to put it mildly, a high-energy individual. Apache Corporation’s Senior Vice President for Worldwide Exploration, he is a 40-year veteran of the oil and gas industry, a geoscientist who has seen it all and done most of it. As we start our interview last November, he is seated at his desk at the company’s offices on the western edge of San Antonio, trying to describe to this writer the series of events that led to the discovery of the massive Alpine High resource in the Delaware Basin of far West Texas. As we will soon see, it was a discovery that required a “cradle to grave” kind of approach, and true to form, Keenan was starting his explanation at the cradle.
“That’s important because people really believed what Hubbard was saying,” he continues. “And the amazing thing to me is that he was practically correct — oil did peak at 10 million bpd around 1970, and it did fall and we were disproportionally dependent on imports for a long time. But it didn’t fall in the logistic distribution curve that he predicted.” To emphasize this point, Keenan pulls up a line graph of the last 45 years of U.S. oil production onto his computer display. “If you’ll notice, there are changes in the slope of the curve, and it is those changes in slope that are the story of my career.
“Up until about 2005 the industry was involved in what we used to just call ‘exploration’ but which we now refer to as ‘conventional exploration,’ since we now have exploration in ‘unconventional’ or ‘resource’ plays,” he says, describing the different terms used to differentiate the sand and limestone formations from which almost all oil and gas was extracted during the industry’s first 150 years and the tight sands, coal and shale formations that have produced most of it in the U.S. during the course of the 21st century.
“All these changes in slope are important because what they represent are the introduction of new ideas, really creative and adaptive thinking, so that we could slow or arrest that decline. Or some kind of new engineering capability or new technology that didn’t exist previously. But mainly it was creative thinking.”
He points to a specific spot on the graph. “This is where I come in. I actually first got hired in 1978, after the Arab oil embargo and the discovery at Prudhoe Bay. Like a lot of people my age with my credentials (he has an MS degree, undergrad in geology with a master’s thesis topic pertaining to spectral analysis of seismic signals – most of his contemporary MS colleagues studying Geophysics were writing about the evaluation of gravity or magnetic data) I began my career working in frontier areas where all the big hopes were. The main suspects at that time were in Alaska and California.”
Indeed, the progression of Keenan’s career, which, before coming to Apache Corp. in June 2014 included stops at Cities Service Oil Company, SOHIO Petroleum, BP, Marathon and EOG Resources, reads basically as compendium of some of the largest major oil discoveries of the last 40 years.
As Keenan notes, the early years of his career, spent at Cities Service, were spent exploring for oil on the North Slope of Alaska and in California, where he worked on the huge Milne Point field 35 miles west of Prudhoe Bay, and also on the Point Arguello field in the Pacific Ocean waters offshore California, just north of Santa Barbara.
While working as Regional Project Manager and as Chief Geophysicist at a domestic independent oil company from 1985 through 1997, Keenan gained a wealth of international experience, exploring for oil faraway places like Norway, Oman, Spain, Argentina and Egypt. Keenan moved over to Marathon Oil in 1997, and spent the next five years working on assets in the deep waters of the Gulf of Mexico and Angola.
Keenan next moved to become Division Exploration Manager of the South Texas operations for EOG Resources. There, he led the company’s highly-successful development of the Middle Wilcox tight sands assets in South Texas. Then, in 2008, his team made a major new discovery when it drilled, hydraulically fractured and completed the first successful horizontal well in the giant Eagle Ford Shale formation.
Wait, you’re thinking, didn’t Petrohawk drill that first successful Eagle Ford well? That is the common story, and, to be fair, Petrohawk was the first company to publicly announce a successful Eagle Ford completion, in October of 2008.
In 2008, EOG made a strategic decision to add more liquids to its portfolio of assets as the natural gas market in the U.S. began to become over-supplied. Keenan and his team were directed by then-EOG CEO Mark Papa at that time to go find more oil, even though it had been highly successful in drilling for the natural gas in the Wilcox formation for many years by then.
In the summer of that year, Keenan’s team which included current Apache employees Chester Pieprzica, Roberto Alaniz and Navneet Behl, drilled the Tully C. Gardner #94H, a 4,200’ lateral well in Webb County, Texas, which is in the wet gas window of the Eagle Ford Shale, and brought it online in August. So, why does the Petrohawk well continue to get the credit? Because EOG made the strategic decision to not make an announcement of its new discovery.
“At EOG, we decided that there was no value to us in telling people that,” Keenan says with a chuckle. “We convinced our management to move over to Karnes County (to the east) [to start up an expanded leasing program]. We then moved our rig over into Karnes County and drilled what was the first crude oil well in the Eagle Ford Shale.
“If you think about it, what business advantage would we [EOG] have to tell anybody about that first well?” Keenan says, noting that doing so would only serve to bring new competitors into the play area. “When we drilled that first well, we had about 15,000 acres under lease in the Eagle Ford,” he notes. In the coming months, EOG’s acreage position ultimately grew to more than 575,000 acres, and the company became one of the handful of biggest players in the Eagle Ford drilling boom that lasted through 2014, and is now seeing something of a revival today.
Energy Week, Episode 4: Why the majors aren’t worried about “Peak Oil” but the markets are worried about events in Saudi Arabia.
Show Notes: In this episode, David Blackmon and Ryan Ray discussed how the ongoing upheaval in Saudi Arabia is impacting oil markets, and the impacts it all could have on the planned IPO for Saudi Aramco. Next, they talked about the reasons why the various “Peak Oil” theories and narratives are wrong, and why the big oil companies aren’t really worried about them. Finally, David talked about the reasons why he thinks the U.S. industry just might not mess up the current positive oil price situation in 2018.