Natural Gas

Lingering Clouds over Shale Assets

Shale gas and oil assets across the U.S., while certainly not in a bust, have been devalued over the past few years, and the trend has continued in 2014. Market forces have been compounded by problems with water availability, speculation and contractual stipulations, as well as future environmental and governmental limitations affecting hydrocarbons.

Tuesday, June 24, 2014

By Owen Reynolds, Angela Conroy and Julia Farber


Shale gas and oil assets across the U.S., while certainly not in a bust, have been devalued over the past few years, and the trend has continued in 2014. Market forces have been compounded by problems with water availability, speculation and contractual stipulations, as well as future environmental and governmental limitations affecting hydrocarbons.

While the shale boom has been touted as the beginning of energy independence, the market has played a nuanced version of that tune. Most energy majors have reassessed performance expectations of their hydrocarbon reserves, with shale gas and oil taking the brunt of the change.

As covered previously, shale write-downs removed a combined $5 billion from the balance sheets of BHP Billiton and Royal Dutch Shell last year. As shale is nearly always hydraulically fractured (fracked) to release gas and oil, write-downs are largely attributed to the specifics of the technique.

Additionally, the industry as a whole faces mounting concern over climate change and the threat of broadly impaired hydrocarbon assets, often known as stranded assets. Many of the assets that have experienced the most volatility and devaluation have, in fact, been associated with shale.

A recent report from Carbon Tracker Initiative specifically evaluates the financial risks to oil-related capital expenditures, including unconventional investments like shale. It aims to inform capex decision-makers via stress tests indicative of future market conditions. According to the study, supply costs, air quality standards, technological innovation and carbon regulation could lower the demand for oil resources, either through price-signaling or quantity limitations.

ExxonMobil and the IPCC

ExxonMobil has been America's largest natural gas producer since its $25 billion purchase of XTO Energy in 2010. The energy giant released two unprecedented reports in March at the behest of stockholders. The reports represent mirror images of several areas of the broader energy industry.

A group led by Arjuna Capital became increasingly concerned about the potential for impaired assets - concerns fueled in part by the mounting pressure on the hydrocarbon extraction and refinement industries. Climate-change denial has become ever less academically defensible in the face of documentation like that of the United Nations International Panel on Climate Change.

The IPCC report and supporting research papers by some 800 scientists detail higher global temperatures, migrating climate zones and other phenomena associated with increased atmospheric carbon. Their recommendations follow a "low-carbon scenario" that would limit emissions to 450 parts per million (ppm). The Grantham Institute has determined that maintaining this concentration of atmospheric carbon has an 80% chance of keeping the global temperature increase to only 2°C.

Grantham has also maintained that, to mitigate future global warming, up to two-thirds of current fossil-fuel reserves must be left untapped. Therein lies the concern. Such a scenario could leave trillions of dollars of current assets on balance sheets untouched and impaired. Arjuna Capital director Natasha Lamb has called fossil-fuel assets a "fundamental risk to [the energy] business."

The first of the ExxonMobil reports, " Energy and Carbon," directly asserts "that none of our hydrocarbon reserves are now or will become stranded." The report estimates that growth in global demand from economic development and population increases will outweigh the pressures on governments to mitigate carbon emissions in the face of climate change.

While including the rising cost of carbon in financial projections, ExxonMobil sees a "low-carbon scenario" as an exceedingly unlikely and harmful direction for governments. The specific low-cost scenario referenced is the IPCC's 450 ppm recommendation. The report's bottom line is that the demand for extracted and refined products will not likely be hindered, despite climate change, because of the potentially negative impacts on economic development and global standards of living.

The second report, " Energy and Climate," addresses many of the same issues of the first, though it tacitly accepts the validity of the IPCC report. ExxonMobil focuses on efficiency to push economic development and predicts the greenhouse gas emissions that cause global climate change will plateau and decrease after 2030. The two reports do address the broader concerns of impaired hydrocarbon assets, but not the more immediate concerns of shareholders about the lack of write-downs.

The Write-Downs

A dozen companies had to write down shale assets because of the risks specific to the oil and gas fracked from it.





Sasol Limited (SSL)

492 million

March, 2014

Canadian Shale

Itochu Corp. (Samson Investment House)

279 million

March, 2014

US Shale

BHP Billiton (BHP)

2.84 billion

October, 2013


Encana (ECA)

1.7 billion

July, 2012


Exco Resources Inc. (N:XCO)

276 million

May, 2012

US Shale

Noble Energy (NBL)

73 million


US Shale

Quicksilver (KWK)

63 million

May, 2012


BP plc (BP)

2.11 billion

July, 2012

US Shale

Devon Energy Corp. (DVN)

896 million

February, 2013

US Shale

Chesapeake (CHK)

5 - 6 billion

June, 2012

US Shale

Royal Dutch Shell (RDSA)

2.2 billion

September, 2013

US Shale, Eagle Ford

BG Group plc (BG.L)

1.3 billion

July, 2012

US Shale

Total SA (TOT)

911 million

October, 2012



Perhaps most dramatically, the BHP write-down represented more than 50% of its Fayetteville shale purchase from Chesapeake. This April, both companies accepted the potential for even further write-downs in the near future.

ExxonMobil remains notably absent from the list - a concern that led Arjuna Capital to ask the company to report on strategies relating to impaired assets. The Securities and Exchange Commission even questioned in a February letter how ExxonMobil has averted such write-downs. According to the Wall Street Journal, many of the write-downs occurred during leadership reorganizations. ExxonMobil CEO Rex Tillerson's defense has been that temporary price lows did not reflect the true value of shale assets and did not necessitate devaluation.

The Shale

Oil and gas from shale, once uneconomical to extract, has literally been broken open by polemic hydraulic fracturing and horizontal drilling technology. Proponents claim the technology can harness these reserves for a hundred years of domestic energy. However, to the mounting consternation of many shareholders and environmentalists, fracking introduces systemic risk factors that exacerbate issues that the broader industry faces.

Mapping natural gas production drop-off, the University of Texas' Tad Patzek, Frank Male and Michael Marder released a study last year in the Proceedings of the National Academy of Sciences. This study of over 8,000 wells in the Barnett Shale, America's most mature shale-drilling region, depicts ever-increasing scaling requirements. It notes an exponential decline in the gas production of mature wells and expects commensurate increases in drilling, especially as exploration moves away from the "sweet spots."

The Belfer Center for Science and International Affairs at Harvard University's Kennedy School has detailed the rapid decline of fracked-oil production in Bakken-Three Forks and other U.S. shale plays. Author Leonardo Maugeri, a former senior executive of Eni, concludes that American fracking is sustainable but forecasts the need for ever-increasing new rigs to maintain production, and a high turnover of rigs. The study also assumes relatively stable oil prices for an increase in oil production and points to the likelihood of environmental problems from fracking in more densely populated areas such as the Marcellus region.

Water and Waste

Another issue affecting both gas and oil assets tied up in shale is access to water. Fracking requires tens of thousands of gallons. Although fracking techniques increasingly allow for recycling of water by various means, investors are sensitive to the value of access to water resources as a necessity for the sustainability of extraction from shale.

The U.S. Geological Survey has explored the relationship between fracking-byproduct water and earthquakes in unlikely locales such as Oklahoma. The average number of earthquakes above 3.0 on the Richter scale in Oklahoma was 1.6 per year for decades. However, in 2010 there were more than 500, and in 2014 the state's rate exceeded that of California.

A third issue is simply the economics of hydraulic fracturing and horizontal well-drilling. Traditional, vertical on-shore wells hit the top of a gas or oil bulge under a sheet of impermeable rock, usually less than half a mile below the surface. For an initial investment of less than $1 million, it can be sucked out like a straw.

Fracking, by contrast, costs between $3.5 million and $5 million and requires upward of 18 horizontal wells along a thin sheet of shale a mile or two below the surface. The resulting risk profile is higher than that of traditional oil extraction and is exacerbated by the quick drop-off in production, making financing from the increasingly risk-averse banking community more complicated.

Gas Glut

The fourth issue - perhaps the biggest reason to write down natural gas assets, but one that has played out little in the oil market - is the glut in natural gas production. The Marcellus Shale play in Pennsylvania and surrounding states has replaced the Gulf region as the largest producer of domestic natural gas. As a result, energy minors such as Chesapeake and Devon have suddenly become huge players. Gas-pipeline flows have been reversed, and the price of gas dropped from over $10 per thousand cubic feet (mcf) in 2008 to under $2 by 2012.

Part of the glut is explained by the sheer magnitude of reserves that became economical to extract because of the combination of hydraulic fracturing and horizontal drilling of gas and oil-soaked shale rock.

However, the nature of contracts signed in the flurry of leasing across unproven shale plays has presented yet another problem. The land leases of speculative energy minors nearly uniformly require extraction within just a few years, or the contract is moot. This contractual quirk led minors - and the majors to whom they often liquidated themselves - to drill immediately, whether the market was saturated or not. The industry admits to drowning in gas and suffering from its own over-production, with Tillerson once saying ExxonMobil was "losing our shirts."

While natural gas prices have recovered to $4/mcf, the industry is lobbying for exports of liquid natural gas (LNG) as a release valve to the continued market glut, though the process of doing so and leveling the market will take years. It could also push prices back towards the $10/mcf or $15/mcf of Europe or Asia, respectively, precluding the marketing of cheap natural gas for manufacturing and transportation.

A final issue facing shale assets is the constant concern of economic feasibility, typified by recent adjustments to California's Monterey Shale expectations. The U.S. Energy Information Agency in May lowered estimates to 600 million barrels (bbl) of recoverable oil, down 96% from more than 14 billion. These figures, although unofficial at the time they were reported, were expected to cut Monterey Shale exploration short and dampen enthusiasm for other shale resources.

Cost Curve and ROI

The Carbon Tracker study points to risks inherent to oil assets, fundamentally challenging assumptions of long-term stable demand. The study stress-tests the assumption of demand with different price and emissions models along the cost curve. It ties risk directly to the "carbon supply cost curve," or the cost in terms of carbon emitted.

All scenarios, regulatory or otherwise, that limit or price carbon will attribute a cost to energy sources in terms of their emissions. Carbon Tracker uses a carbon cost curve against which companies can stress-test assets using their own demand assumptions. According to the study, those assets and projects that produce energy with the highest supply cost per ton of carbon will be the first to suffer when carbon costs are internalized.

The Carbon Tracker study predicts that in the case of such a regulatory scenario, the $75 to $95/bbl of oil market price range is even at risk. Although the likelihood of this scenario can be debated, it is indicative of potential asset impairment under even less restrictive regulatory scenarios. Notably, this particular scenario is the same low-carbon scenario the IPCC prescribed and the one ExxonMobil sidelined.

There is a more general concern about the hydrocarbon sector as the share of unconventional hydrocarbon reserves increases in proportion to conventional resources. Unconventional reserves, like shale, are more expensive to extract per British thermal unit, which author Richard Heinberg calls decreasing energy returns on energy invested (EROEI).

According to Heinberg, as conventional energy reserves are depleted, unconventional resources are farther down the "resource pyramid" and farther up the carbon cost curve. That would indicate increases in price and decreases in accessibility. He posits that as extraction heads further down the resource pyramid, into increasingly difficult-to-extract resources, those assets' returns on investment decline. Heinberg raises the point specifically for fracking, but it may also be applicable to other unconventional hydrocarbon reserves.

Meanwhile, the major players continue to write down assets, despite the recovery of natural gas prices and relative stability of oil prices. The future use of natural gas by any means necessary should not be the standard approach for long-term planning. Climate change is already impacting the energy industry, and every other industry. The climate and environmental issues are expected to contribute to the reassessment of shale asset values, which can be read largely as an adjustment to the market glut and present some magnitude of impaired assets. Accordingly, the hydrocarbon companies that are quicker to acknowledge the realities can provide a more accurate representation to their shareholders about the validity of their investments.

Owen Reynolds is a Washington, D.C.-based writer and federal energy economist. Angela Conroy is a senior energy policy analyst with ICF International and has been recognized by the Association of Energy Engineers as a 2013 Legend in Energy. Julia Farber works in government affairs and has a background in the environmental field, focusing on the carbon market, energy use and environmental certification. They previously co-authored for " Hurdles to Shale Assets" and " How Environmental Damage Translates into Financial Risk."?


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