1. All Value Chains Begin Upstream

Borrowing the title of the classic book on scenario thinking by Schwartz (1996).

See footnote 1.

See https://​www.​bp.​com/​en/​global/​corporate/​energy-economics/​statistical-review-of-world-energy.​html for downloads.

See https://​ourworldindata.​org/​energy for data set and sources.

It is important to note that the concept of renewability refers only to the energy source itself, such as wind, solar, tidal and wave (marine) and biofuels (crops). Most inputs to renewable energy sources are nonrenewable.

That classic view is, of course, from Porter’s (1980) influential work.

Oil Is First Found in the Mind: The Philosophy of Exploration, compiled by Norm Foster and Ed Beaumont and published by the American Association of Petroleum Geologists in 1992 as number 20 in a petroleum geology series, makes the point succinctly. The book title was drawn from phrasing by Wallace Pratt, “Where oil is first found, in the final analysis, is in the minds of men” in another classic, Pratt’s 1952 paper “Towards a Philosophy of Oil Finding” in the AAPG Bulletin, volume 36.

In this phrasing, I refer to the classic work by Joseph Schumpeter from his classic work (Schumpeter 1942).

As explained in the book Appendix, gas (piped methane) delivered to customers requires considerable capital investment to dehydrate and separate from other hydrocarbons (to satisfy pipeline quality specifications) and build the necessary pipeline infrastructure. The larger capital investment relative to oil implies a price discount inherent in methane. See section “The Lure of Private Lands and Minerals”.

Based on communications with Barbara Shook, Chap. 3 co-author, regarding discussions with GTL developers.

It is hard to put a finger on exactly when critiques surfaced regarding natural gas as a “bridge” fuel for energy transition. A rough timeline is available in this link, https://​grist.​org/​natural-gas/​natural-gas-a-bridge-to-nowhere/​

Estimate based on U.S. government data for federal production as compared to total output and accounting for production from state and tribal lands. For a view of the main federal oil and gas domain—the OCS—see https://​www.​api.​org/​oil-and-natural-gas/​energy-primers/​offshore.

The concept of “obsolescing bargains” for extractives industries, mining as well as oil and gas, is well-trod ground. From the original idea, widely attributed to Raymond Vernon (1971). The notion, focused on multinational enterprises and their negotiations with resource-owning host governments, is that sovereign resource owners “learn” and bargaining power shifts away from the enterprise and to the sovereign. The same is true in open, competitive, private land and minerals markets and leasing. Companies may have the initial advantage in terms of knowledge about the resource endowment and commercialization potential. Private land and minerals owners come up to speed very quickly.

Ailworth (2017) provided an excellent case study of the gamut of improvements, including those I mentioned, with emphasis on logistics and inferences for OFS companies.

Operators now are moving toward “e-fracking” or fracking using electricity fueled by field gas. This has the advantage of soaking up gas production that operators might otherwise flare and providing substantial cost savings. The downside is faced by OFS companies who must pay to retrofit diesel pumpers (Hampton 2019).

In a proprietary review of E&P innovation (2001), McKinsey & Company found that the timeframe from idea to prototype to commercialization (50 percent of market penetration) tended to be more than 30 years. This compared to about 15 for broadband, about 12 for medicine and about 7 for consumer products. The study identified a number of inefficiencies, including those mentioned in the text.

See the Alerian website for excellent information and background on midstream, energy infrastructure and MLPs. https://​www.​alerian.​com/​

Kinder Morgan was the notable exit from its MLP arrangement. Other large midstream partnerships have not followed. See Steffey (2014) for a good overview.

The quick turnabout of business conditions in the Permian is a case study in midstream business challenges. Having finally achieved new pipelines, producers in the Covid-19 world are using substantially less capacity than midstream developers planned for (Elliott 2020).

See Michot Foss (2020b) for an overview on U.S. domestic upstream organization.

A prominent upstream equities analyst once referred to the often mentioned “shale factory” as the equity research shop strategy of covering pure play companies explaining that it was easier for “generalists”. Analysts typically hired by equities research groups could build valuation models for unconventional players as opposed to conventional, exploration risk (personal communication, November 30, 2011).

In fact, during the 1990s, Canadian producers and pipeline operators struggled mightily with the problem of how to get more gas into the Lower 48 in order to gain some relief from large surpluses and low prices. Prior to the wave of LNG import projects—including projects proposed in Eastern Canada to serve northeast U.S. markets—Canadian gas export pipeline expansions were the most closely watched and discussed gas industry news topic (OGJ 1995a, b, 1997).

See the newly named Canada Energy Regulator for status, https://​www.​cer-rec.​gc.​ca/​pplctnflng/​mjrpp/​nrgyst/​index-eng.​html.

The author participated briefly in a Canadian Energy Research Institute report initiated in 1993 that argued Mexico could become a large gas supplier and exporter, sending output from its northern basins into the United States and competing with Canadian deliveries. That report is no longer publicly available. However, other coverage from that period provides snapshots (see OGJ 1993a, b; Norton 1993).

Based on a quote in historical treatment of the Texas oil and gas industry. From Hazardous Business, Industry Regulation and the Texas Railroad Commission, Texas State Library Archives Commission online exhibit, https://​www.​tsl.​texas.​gov/​exhibits/​railroad/​oil/​page6.​html. To wit: “Hell, I sell a barrel of oil at ten cents and a bowl of chili costs me fifteen!”

New lessons are emerging on this front as Big Tech punches its weight. See Foer 2020.

From a proprietary Bernstein Research report, July 24, 2015. Bernstein analysts have consistently questioned whether “sunk cost fallacy” permeates the unconventional play operators.

Summary based on a number of industry reviews and retrospectives and author analysis of company financials and proprietary analyst reports. See section “We (Were) in the Money”, for details on various phases of the emerging shale gas and oil businesses.

I derived the term “Frankelnomics” in Michot Foss (2020a).

In Hotelling’s time, oil wars in California paralleled events in Texas.

See also Verlager 2007 for his review of Frankel’s views and idea on oil markets and pricing going forward.

Kemp also updates theories about oil prices moving beyond Verlager’s 2007 treatment.

Priddle’s comments are part of his independent review of a natural gas market analysis submitted to support the proposed Bear Head LNG export project in Nova Scotia. The project was never developed and was put up for sale in July, 2020 (Beswick 2020).

The producer benchmarking effort entailed a number of researchers in addition to myself: Miranda Wainberg, Daniel Quijano, Deniese Palmer-Huggins and Rahul Verma. See Notes on Research Methodology for more detail. An initial paper (Michot Foss and Wainberg 2012) included methodology and reasoning. See also http://www.beg.utexas.edu/files/energyecon/think-corner/2015/CEE_Snapshot-Producer_Benchmarks_Part_Deux-Mar15.pdf, http://www.beg.utexas.edu/files/energyecon/think-corner/2016/CEE_Snapshot-Producer_Benchmarks_2016-Mar16.pdf; http://​www.​beg.​utexas.​edu/​files/​energyecon/​think-corner/​2018/​CEE%20​producer%20​benchmarks%20​2017.​pdf

For an overview of breakevens and the various considerations, including components of full and half cycle economics, associated with the emergence of unconventional plays, see Kleinberg et al. (2018). The many definitions of breakeven points cloud use of those measures when assessing industry activity and response to different current and expected commodity price signals. Assessing breakevens of wells, plays and projects without consideration of overall enterprise sustainability can be misleading.

I acknowledge Bob Brackett, who has led E&P coverage at Bernstein Research for many years. We used their quarterly State of the Business reports, 2011–2018, for comparison with our benchmarking, among other research.

After initial publication of our results, we provided input to Liam Denning for a review of producer performance at Bloomberg (see Denning and Molla 2016), who cited our work.

Denning (2018a) commented on the distortions created by sunk costs and depreciation. “Shale’s treadmill of spending every dollar earned (plus some more if capital markets obliged) has been fantastic for U.S. oil and gas production, but less so for returns … As companies have shifted from basin to basin, learning by doing and driving down costs per barrel, so the sunk capital in older positions has become a drag on returns…as the legacy of the earlier land-grab and drilling frenzy fades, so depreciation charges should moderate, bringing them closer to finding and development costs and making earnings multiples more meaningful”.

API gravity is a measure, in degrees, of how heavy or light the petroleum product is when compared to water—the specific gravity of petroleum relative to water. Oil with an API number less than 10 (which is the degrees API of water) has a high specific gravity; that is, it is heavier than water and will sink, while oil with a high-degree API is lighter than water and will float. Lighter crude oils are valued more in the market as they will refine more easily into “light ends” like gasoline, diesel, kerosene and naphtha. In a market surplus of very light oils, the value of heavier crudes can appreciate as larger, more complex refineries will demand those crudes in order to optimize refinery runs.

Long lags in securing new oil pipeline capacity meant a surge in demand to transport oil by rail. See RBN Energy for news and research coverage (https://​rbnenergy.​com/​, subscription required). The volatility of LTO led to specific challenges in tank car safety. Information on incidents, preparedness and response can be obtained from the Pipeline and Hazardous Materials Safety Administration (PHMSA), https://​www.​phmsa.​dot.​gov/​safe-transportation-energy-products/​safe-transportation-energy-products-overview

David Einhorn’s critique of shale oil producers received considerable attention. See presentation at Sohn Investment Conference, May 15, 2014, https://​www.​greenlightcapita​l.​com/​926698.​pdf

In notable deals, BP engaged in several acquisitions of interests and joint ventures with Chesapeake (Fayetteville, Haynesville, Marcellus), an early leader in deal making, 2008–2010; ExxonMobil acquired Crosstimbers (XTO) in 2009 (mainly Texas plays); BHP acquired Petrohawk in 2011 (Eagle Ford); after several transactions in the Marcellus in 2010, Statoil acquired Brigham (Bakken and Three Forks in Williston Basin); Chevron acquired Atlas in 2010 (Marcellus/Utica); Shell acquired East Resources in 2010 (Marcellus/Utica). Petrohawk and XTO were early inclusions in our producer benchmarking.

EOG was the early leader in exiting shale gas acreage. In Notes on Research Methodology: Producer Benchmarking, I source an EOG investor presentation from September 2010 that was widely reviewed. EOG’s announced exit from its shale gas acreage positions to focus more on oil-rich plays and its accumulation of $5.1 billion in debt to finance that strategy (Womack 2010) triggered strong reactions. See Moody’s, 2010, press release, https://​www.​moodys.​com/​research/​Moodys-changes-EOGs-outlook-to-negative%2D%2DPR_​209537 (registration required). As I clarify in the Notes section, the 2010 announcement of EOG’s strategy and coverage of that announcement spurred our benchmarking concept.

Notable deals in that phase included acquisition by Shell, Chevron and EnerVest, a private equity group, of Chesapeake’s Permian upstream and midstream assets.

Notable deals in that phase included Noble’s purchase of Rosetta in 2015 (Permian and Eagle Ford liquids window, all-stock transaction); EOG’s acquisition of Yates in 2016 (widely viewed as a shift in emphasis from Eagle Ford, added New Mexico Permian and included cash in the transaction); the acquisition of Memorial by Range Resources in 2016 (an all-stock transaction for Louisiana liquids rich production).

See Dezember (2019), Matthews (2019a, b). The blogosphere is replete with bad reviews on oil and gas shares at the close of 2019 and opening of 2020 (Brower 2020).

Producers considered shale bonds, securitizing individual assets such as oil and gas wells (Matthews 2019a). For other treatments of producer debt, see Matthews et al. (2019a, b; lackluster well performance triggers tighter requirements on credit lines provided by banks), Dezember (20; push by producers to use improvement in revenues from higher oil prices to pay down debt rather than re-invest), Ambra Verlaine and Goldfarb (2020; rally in riskier bonds enabling some producers to refinance). It is not clear the extent to which shale bonds could apply with continued deterioration of business conditions in 2020.

The most prominent transaction during 2019 was Occidental’s acquisition of Anadarko after a brief competition with Chevron, widely credited for its discipline in walking away from a bidding war (and earning a $1 billion break-up fee). Other transactions, mainly among smaller companies who most need consolidation but where all-stock deals have been prevalent, have been highly criticized for providing low or no premiums. These include Parsley’s acquisition of Jagged Peak and Callon’s acquisition of Carrizo, considered a prime example of Permian bottom fishing. All content in footnotes related to transactions from public domain financial news reports.

Producer behavior is evident to the markets now (see Matthews et al. 2019a, b; Denning and Molla 2016; Denning 2010a, b, 2017, 2018a, b, 2019a, b) just as it was evident then (Denning, April 8 and 20, 2010a, b).

See Haskett and Brown (2005) for typical off ramp decision points in conventional and unconventional play development.

^{Raymond James analysts acknowledged that: “The untold reality is that the industry still drills a small amount of “problem” wells that have officially started the drilling process but are failed wells that will never be completed. These failed wells could be due to tools lost in the hole, sidetrack problems, lost circulation issues, stuck pipe, or a myriad of other real world problems”.} Proprietary report, December 2, 2019. The Ray James report was focused on the inventory of uncompleted wells called “DUCs” (drilled, uncompleted) that observers have viewed to be most responsive to increased prices but which include wells that will never be completed. See following section “Growth or Profitability Revisited: Rigs, Drilling and the Future of U.S. Production” for views on future U.S. supply. See footnote 53 below for related comments on failed wells.

EURs factor into how companies report on hydrocarbons to the U.S. SEC or other financial regulators. The Petroleum Resources Management System (PRMS) was created to improve consistency in hydrocarbons reporting, using project-based guidelines. Information on PRMS is at https://​www.​spe.​org/​en/​industry/​reserves/​.

Bernstein Research estimated that publicly traded companies in their coverage report roughly 3 percent of the wells drilled and generally the best wells (proprietary report and personal communications). The presence of sub-par wells and ongoing discussions about “type well” and “type curve” definitions and how to properly evaluate unconventional plays are reflected in Freeborn (2016) and Freeborn et al. (2012). They caution that expected ultimate recovery (EUR) can be inflated when forecasts from older type wells are used for newer, less productive wells given that companies tend to drill their best wells first in order to optimize NPV. They note that the reverse can happen during times when operator knowledge is improving with experience. In an influential paper, Fulford (2016; see also Carpenter’s 2016 excellent summary) goes further to explore sampling error, point to false positives and widespread practice of excluding underperforming wells from sampling for type curves (see Freeborn 2016) and many other risks and uncertainties associated with unconventional plays that undermine success from pilot drilling through development.

Are sweet spots all they are cracked up to be? Emphasis on sweet spots is prevalent in oil and gas exploration and exploitation, but for unconventional plays in particular. In a rejoinder to widespread beliefs that reliance on sweet spots is the solution to variable well production, Haskett (2014) offered up an interesting critique of the approach. While defining sweet spots can improve efficient in development, the frequency of false negatives and positives causes producers to make decisions that later prove incorrect and thus to incur costs, including missed opportunities. Most of all, the sweet spot focus shortchanges well completion learning curves: “If by chance or skill, a company has been successful in defining or drilling a real sweet spot, the science may stop as the exploitation team revels in the high productivity and then falls behind on drilling and completion techniques for the vast majority of wells that are not ‘sweet’. While no team would likely admit to such a thing being possible, the reality is that once we believe an answer is found, it is sticky and we slow our drive for efficiency and solution” (p. 6).

In his review of the superlat and superfrac “horizontal shale completion” (HSC) model, McDaniel noted: “Economic success achieved in only the past 2 to 4 years in shale reservoirs in North America has fired a ‘shot heard round the world’ for the oil and gas industry. Although a few high profile shale plays have caught the limelight, in a more complete picture, we should really say that it has been the production…fueled mostly by multistage hydraulic fracturing of extended lateral completions” (p. 1).

Quoting from Jacobs (2018): “an executive with Range Resources was even more exacting when he told analysts that underperforming wells in the company’s Louisiana shale asset and ‘corresponding frac hits to offset production’ amounted to a financial loss of $75 million per day”. In a proprietary report, Raymond James analysts evaluated well interference and suggested that well productivity gains could slow but with uncertain timing (April 15, 2019).

For example, a 12-well cube cost $150 million based on information from proprietary projects in the Permian-Delaware Basin. Companies can vary starkly in costs for wells and pads that should otherwise seem comparable. For the cube in question, an adjacent operator was able to drill, complete and frac comparable well laterals for upward of $2 million less per well.

Jacobs (2018) noted that Encana credited cube development with increasing well productivity in a Permian field by 70 percent. Olson (2019a) reported that Encana’s largest cube would yield about half of the oil the company predicted in 2017. Financial reporters have tracked shale company results with an eye to financial implications. See Olson et al. (2019), Elliott and Matthews (2019).

Rassenfoss (2020) quoted from a Deloitte review: “Over the past 3 years (2016–2018), the industry’s productivity was flat despite a 25% increase in proppant and fluid loading”, the report said. Wells with big fracturing jobs can produce more, but the amount of increase may fail to justify the expense. The data Deloitte analyzed showed many such instances where the added production of a well was not economic. In those cases, Bonny said, “maybe that was not always the right decision”.

Rassenfoss (2020) also quotes from published results of attempts to map breakeven oil prices for well locations that demonstrate the difficulty of extrapolating from small samples to large areas, which many have been inclined to do in tight rock plays. It is useful to consider that certainty about recovered volumes is strongest at end of life of producing assets. A substantial constraint to improving predictability lies in the fact that wells must be drilled, completed and put on production before results are known which means considerable capital destruction in the process.

Many analysts use realized revenues against modeled revenues using expected market prices.

The acquisition of Burlington Resources by then ConocoPhillips was widely thought to have been hastened by shareholders unhappy with a large missed hedge in which Burlington was too conservative in selecting future Henry Hub contracts (based on communications with ConocoPhillips personnel at the time, 2004–2005).

The CME Group, which operates the largest energy exchange, holds the NYMEX futures contracts and other derivatives for oil and gas and other energy products. Each crude oil (CL) contract is in units of 1000 barrels; CL futures contracts are based at Cushing, Oklahoma. Each natural gas (NG) contract is in units of 10,000 MMBtu; NG contracts are based at Henry Hub in Erath, Louisiana. See https://​www.​cmegroup.​com/​ for information on energy derivatives and trading.

For both multipliers I use production from the BP Annual Statistical Review and trading volumes reported by CME, as aggregated by Quandl, www.​quandl.​com.

A great deal of concern about who participates in financial markets and for what purpose, including whether markets could be manipulated, arose out of the 2008 recession. We considered the implications of non-commercial interests participating in financial trading for commodities (Michot Foss et al. 2009). That paper was a precedent to the work by Gülen and Michot Foss (2012).

I adapted this terminology and the methodology from David Pursell, then at Tudor Pickering & Holt, now at Apache Corporation, and used in a presentation to the Independent Petroleum Association of America (IPAA) supply-demand committee meeting in Houston, Texas, November 7, 2008. A broader, more fundamental, topic is how well commodity markets perform when it comes to trust and motivation. We explored the shifts in financial markets following the 2008 recession and the onset of new regulation (Michot Foss et al. 2009), concluding that financial and physical markets had become intertwined and that demand for financial products (derivatives) as an asset class could be influencing prices of the underlying physical goods. We also raised concerns about non-commercial participants seeking exposure to financial derivatives, such as private investors (as individuals or through funds) whose behaviors and motivations are quite different than commercial participants. I surveyed the state of literature on commodity trading since 2000 and drew several observations. Researchers realize that behaviors and motivations of market participants are different. Attempts to model behavior are fraught with complexity and lack of knowledge (within the academic research community) about how commercial market participations, including producing companies, operate and function. An age-old question of whether futures and spot prices are co-integrated is unsolved, although they can react simultaneously to new information. I first used the market error approach adapted here in Michot Foss (2020a).

Hedging by Pioneer resulted in losses of almost $8 per barrel during the third quarter of 2018 as crude oil spot prices during that quarter were higher than the value of the company’s hedges. Pioneer’s quarterly reporting also provided a lens on how hedging has offset losses from differentials associated with oil pipeline bottlenecks. The company’s hedging program through 2017 added $1–2 per barrel in income while netback discounts resulted in losses of $2–3 per barrel—Pioneer’s realized oil prices were lower than market due to the bottlenecks (Denning 2018a, b). Periodically over the years, commodities markets and prices and their regulators and policy overseers have been enveloped in debates about speculation (market participation for profit) as opposed to hedging (market participation to reduce price risk and volatility and their impact on revenues and cash flows) and potential for manipulation. See Pirrong (2017) for a useful survey of manipulation, the role of hedgers and speculators, and legal and regulatory considerations.

Pre-pandemic, various analysts expected Permian gas production to grow from about 13 Bcfd in the first half of 2019 to 10–12 Bcfd with high cases of 24 and sometimes even 30 Bcfd. Appalachian production was about 31 Bcfd; the back room chatter was that opposition to pipe projects would cap Marcellus output. The total U.S. market at the time was about 83 Bcfd delivered to customers, including exports. Two Permian gas pipes had reached FID and appeared to be one to two years away from entering service—Gulf Express, backed by XTO/Exxon Mobile with Apache, Pioneer and others. Gulf Express would add 2 Bcfd of capacity at a total cost of about $2 billion. The second was Permian Highway—again backed by XTO/Exxon Mobil and Apache. PHP also would add 2 Bcfd of takeaway and also at a total cost of $2 billion. Both projects were undertaken by Kinder Morgan. The PHP has been under continuous, intense pressure from opponents. These projects would contribute 4 Bcfd of the high case 24–30 Bcfd of output requiring transportation. Even the more conservative outlook of 10–12 Bcfd of production growth would need substantial pipeline takeaway capacity. Six projects were under discussion, none near FID. All of these projects need financial backing; prevailing assumptions were that the major companies were most likely sponsors.

See footnote 29. The Raymond James analysts noted the widening gap between monthly well completions and the average number of rigs working, attributing this to greater productivity per rig for all of the reasons I outline.

See the EIA Drilling Productivity Report for public domain tracking of activity and developments in the major onshore unconventional basins, https://​www.​eia.​gov/​petroleum/​drilling/​#tabs-summary-3.

An SPE JPT news item, “Analytics Firm: Permian Fracturing Work Underreported by 21 percent in 2018”, July 24, 2019 covered remote tracking of frac spreads developed by Kayrros. Subscription or other access required.

Based on Westwood evaluation of frac crew efficiency in a public domain posting, February 11, 2020, https://​www.​westwoodenergy.​com/​reports/​us-unconventionals/​stages-per-frac-crews-increase-by-26-across-shale-plays?​utm_​source=​ActiveCampaign&​utm_​medium=​Email&​utm_​campaign=​Frac_​Efficiency&​utm_​content=​ReadMore.

See footnote 29. The Raymond James analysts argued that viable DUCs were substantially lower than EIA’s count, by about 15 percent. The analysts’ consensus is for a drop in oil production near term: “Investor fears that a falling rig count will not translate into reduced completions, on account of ample supplies of drilled but uncompleted wells is based on the incorrect assumption that DUC inventories can return to lows of 2016. They cannot, for one thing, U.S. onshore completion activity (shown by the red bars in the graph above) is at an all-time high. As a result, operators are going to naturally require more inventory to continue running efficiently at an expanded pace. Adding to this, the near ubiquitous adoption of pad drilling, increasing wells per pad, and frac crew optimization have raised the ‘months of inventory’ required for efficient operations to four months from the historical level closer to two months of inventories. Making the situation all the more perilous, the EIA DUC data overstates the true amount of DUCs due to the inclusion of hundreds of ‘lame DUC’ wells that were drilled years ago and are never likely to be completed in the future. We estimate that the EIA DUC data is overstated by almost 15% (or about 1200 wells). Even assuming the EIA count is correct, the current disconnect between completion activity and drilling is the biggest we’ve ever seen and cannot be sustained through next year. Using what we believe to be the correct count, DUCs reach critical levels by February. At that point, frac crews will need to be idled or dropped as their simply won’t be enough slack (DUCs) to operate at today’s rapid pace, supporting our below consensus oil growth forecast next year”. Balancing their enthusiasm is the question of producer discipline—whether companies will rein in spending in order to focus on profitability and improved cash flows, and the extent to which industry consolidation will re-shape the landscape.

The most prevalent experiments reported and cited are in gassier locations, with Eagle Ford most often mentioned and documented. A big question is whether enhanced recovery can be repeated across multiple locations so as to support economics and availability and cost of equipment for high-pressure “huff and puff” applications.

Readers can look to the EIA for views on basin production and drilling trends (Drilling Productivity Report, https://​www.​eia.​gov/​petroleum/​drilling/​) and future supply and demand (Annual Energy Outlook, https://​www.​eia.​gov/​outlooks/​aeo/​).

Olson (2019b) is a good example. See footnotes in section “We (Were) in the Money” for major company deal making. Chevron, in particular, and Exxon Mobil have advantages in legacy land holdings.

The Bureau of Economic Geology has made distinct contributions to the understanding of shale and tight oil plays. See http://​www.​beg.​utexas.​edu/​research/​programs/​shale and http://​www.​beg.​utexas.​edu/​tora; individual research consortia make additional contributions. The U.S. Geological Survey provides ongoing resource assessments for the United States, https://​www.​usgs.​gov/​centers/​cersc/​science/​united-states-assessments-undiscovered-oil-and-gas-resources?​qt-science_​center_​objects=​0#qt-science_​center_​objects, and rest of world, https://​www.​usgs.​gov/​centers/​cersc/​science/​world-oil-and-gas-resource-assessments?​qt-science_​center_​objects=​0#qt-science_​center_​objects. The EIA compiles and reports year end oil and gas reserves, https://​www.​eia.​gov/​naturalgas/​crudeoilreserves​/​.

Based on Bernstein Research proprietary reports. Bernstein covers mostly “pure play” companies. The sample is based on reporting as of second quarter 2019.

Phrasing most often associated with Tom Wolfe and bonfires of vanities.

See footnote 5. A few differences exist between time periods with respect to companies under coverage but the populations are substantially the same. Most of the differences can be attributed to bankruptcies and M&A.

A survey of alternative energy investments gaining attention through first half of 2020 indicates that many are held by corporate entities that also hold legacy utility businesses including power generation assets in states where cost of service ratemaking still is used.

To considerable fanfare, BP announced it would phase out its core oil and gas businesses. BP stock dipped to a historical low as investors reacted. See Hurst (2020) for typical treatment and Kennedy (2020) for a more nuanced view.

See previous footnote 14. Pyper (2019) observed: “For one thing, greater levels of electrification threaten to weaken their core business, and oil majors investing in cleantech could be cannibalizing their own profits. Whether shareholders see this as a risk or as a new opportunity amid an undeniable shift within the industry is another related issue”.

I used https://​us.​spindices.​com/​indices/​equity/​dow-jones-us-oil-gas-index and https://​us.​spindices.​com/​indices/​equity/​sp-global-clean-energy-index, access required.

Smith and Eckhouse (2019), in typical reporting, reference prevailing views that industry maturity will reduce volatility, in coverage of one of the most prominent exchange traded funds, Invesco Solar.

For instance, in his keynote remarks at the 2019 Oil & Money conference, Shell CEO Ben van Beurden stated that “Governments can provide regulation and consumer signals…as well as incentives, like grants to help buy electric cars”. https://​www.​shell.​com/​media/​speeches-and-articles/​2019/​embracing-evolution.​html. Pyper (2019) noted: “The power generation business in particular is known for having relatively low returns, [Shell’s Marten] Wetselaar said. But that could change too. Subsidized solar and wind have attracted a lot of cheap capital. But as subsidies start to phase out, cheap money will begin to disappear, and as risk levels in the generation business rise, the returns are expected to be higher. ‘So I do think we’ll find serious pockets of value,’ said Wetselaar. ‘But … it won’t be easy; because if it were easy, then everybody would be doing it’ ”.

Outgoing BP CEO Bob Dudley’s remarks at the 2019 Oil & Money event were telling. https://​www.​bp.​com/​en/​global/​corporate/​news-and-insights/​speeches/​gas-in-a-net-zero-energy-system.​html

Les Demand, Consultant, notes that “Canadian production and infrastructure development has been retarded due to the U.S. shale explosion. Their large resources base might act as a ceiling on medium term U.S. prices”. (February, 2020)

Costs excluded from the full cost amortization pool are discussed separately in our full report found in Michot Foss and Wainberg (2012).