Shale gas is not a revolution. It’s just another play with a somewhat higher cost structure but larger resource base than conventional gas.
The marginal cost of shale gas production is $4/mmBtu despite popular but incorrect narratives that it is lower. The average spot price of gas has been $3.77 since shale gas became the sustaining factor in U.S. supply (2009-2017). Medium-term prices should logically average about $4/mmBtu.
A crucial consideration going forward, however, will be the availability of capital. Credit markets have been willing to support unprofitable shale gas drilling since the 2008 Financial Collapse. If that support continues, medium-term prices for gas may be lower, perhaps in the $3.25/mmBtu range. The average spot price for the last 7 months has been $3.13.
Gas supply models over the last 50 years have been consistently wrong. Over that period, experts all agreed that existing conditions of abundance or scarcity would define the foreseeable future. That led to billions of dollars of wasted investment on LNG import facilities.
Today, most experts assume that gas abundance and low price will define the next several decades because of shale gas. This had led to massive investment in LNG export facilities. Both the assumption and its investment corollary should be carefully examined through the lens of history.
The Lens of History
The last 40 years have been characterized by two periods of normal gas supply, and two periods of gas-resource scarcity. Supply was tight from 1980 through 1986, and gas prices averaged $5.57/mmBtu (all values in this report are in April 2017 dollars) (Figure 1). Normal supply was restored from 1987 through 1999, and gas prices averaged $3.24/mmBtu.
Figure 1. Cost Structure of Shale Gas Plays Consistent With 40-Year Natural Gas Average. Source: EIA, U.S. Dept. of Labor Statistics and Labyrinth Consulting Services, Inc.
Scarcity returned from 2000 through 2008, and prices averaged $7.72/mmBtu. Shale gas production began with the Barnett Shale in the 1990s. Development of other shale gas plays culminating in the giant Marcellus completed the return to normal supply. Prices since 2009 have averaged $3.77/mmBtu.
Because prices fell about 50% with growth of shale gas production, many assume that shale gas is low-cost. That is only true compared with the preceding period of high prices that resulted from resource scarcity, but not compared with conventional gas prices during periods of normal supply.
The 40-year average gas price since 1976 has been $4.70/mmBtu. Excluding periods of resource scarcity, it has been $3.40. The average cost of conventional gas from 1987-2000 was $3.42/mmBtu. During the period of shale gas supply dominance (2009-2017), prices have averaged $3.77 (Figure 2).
Figure 2. Cost Structure of Shale Gas (2009-2017) Higher Than Conventional Gas 1987-2000. Source: EIA, U.S. Dept. of Labor Statistics and Labyrinth Consulting Services, Inc.
Gas Supply Models Consistently Wrong and LNG The Wrong Solution
The lesson from history is that U.S. gas supply is highly uncertain. Normal supply characterized 60% of the period since 1976, but scarcity characterized the remaining 40%. During each episode of either normal or tight supply, experts agreed that existing conditions would define the long-term. They were consistently wrong.
Cheap, regulated natural gas was abundant in the 1950s and 1960s, and most analysts believed that this would be the case for decades. Abundance and low price led to demand growth of 283% (45 bcf/d) between 1950 and 1972 (Figure 3).
Figure 3. U.S. Gas Models Have Been Consistently Wrong For 50 Years. Source: EIA, U.S. Dept. of Labor Statistics and Labyrinth Consulting Services, Inc.
Supply could not keep pace and there were acute shortages of gas during the winter of 1970. By 1977, shortages had grown to crisis proportions. Few saw this coming partly because of incorrect reserve estimates.
Experts agreed that scarcity would be the case for decades and that imported LNG was the only solution. Four LNG import terminals were built between 1971 and 1980. Limited gas supply led to a golden age of nuclear and coal-fired power plants that largely re-balanced the electricity market. Government subsidies and tax credits provided incentives to evaluate shale gas and coal-bed methane as alternative sources of natural gas.
The 1980s and 1990s were a period of great stability in natural gas prices. Increased pipeline imports from Canada gave the false impression that, once again, there was cheap and abundant natural gas for decades to come. All LNG plants were closed and some were used for gas storage.
Amendments to the Clean Air Act in 1990 caused many power plants to switch to natural gas to replace coal. Demand for natural gas increased 40% (15 bcf/d) but production did not keep pace with demand growth despite increased gas-directed drilling.
Canadian and U.S. gas production peaked in 2001 and by 2003, LNG import terminals were re-opened and capacity was expanded. More than 42 additional import facilities were proposed between 2001-2006. Seven were built. Experts agreed that LNG import was, once again, the only solution to the gas-supply problem.
The first long-lateral horizontal wells were drilled in the Barnett Shale in 2003. By late 2006, shale gas production in the Barnett, Fayetteville and other shale gas plays exceeded 4 bcf/d and confounded not only the U.S. LNG import market but also the global LNG industry that had planned on the U.S. being the market of last resort.
In every supply cycle, major investments in LNG were either undertaken or abandoned. Total installed LNG import capacity reached 18.7 bcf/d but imports averaged only 1.3 bcf/d from 2000-2008 and never exceeded 2.1 bcf/d. That’s an average utilization of 7% and a maximum of 11%. The original cost for the terminals was approximately $18 billion. How could industry analysts, company executives and investors get things so wrong?
Now, experts agree that, because of production from shale, gas will be abundant and cheap forever. LNG exports began in early 2016, and the U.S. became a net exporter of gas in April 2017. Seven previously failed import facilities are being converted for LNG export at an anticipated cost of approximately $48 billion. Three other export terminals have been approved by the Department of Energy (Figure 4) and applications for a total of 42 export terminals and capacity expansions have been approved.
The total of approved export applications amounts to more than 54 bcf/d—75% of U.S. dry gas production. Daily U.S. dry gas production in 2016 was 72 bcf/d. Are we repeating the mistakes of LNG import in reverse?
The Natural Gas Act (1938) states that the Department of Energy should approve an application unless “the proposed exportation or importation will not be consistent with the public interest.” It is, therefore, not a question of whether or not to regulate but rather, how to regulate in the public interest. Approving LNG export applications for 75% of U.S. production does not seem to be in the public interest from either a supply security or gas price standpoint.
Shale Gas Marginal Cost
Shale gas producers have been making exaggerated claims about low-cost supply for so long that markets now believe them. Sell-side analysts routinely gush about sub-$3 break-even prices despite corporate income statements and balance sheets that show otherwise. Marcellus leaders Cabot, Range and Antero spent an average of $1.43 for every dollar they earned in 2016; Chesapeake had negative earnings for the year—it couldn’t even pay for operating expenses out of revenues before capital expenditures and other costs.
Rig count is a direct indicator of how oil and gas producers choose to allocate capital. It is, therefore, a simple way to judge marginal costs by how companies “vote with their feet.” Horizontal shale gas rig counts remained fairly flat in 2014 when gas prices fell from more than $6/mmBtu to $4 (Figure 5). Rig counts collapsed, however, when prices fell below $4.
Figure 5. Shale Gas Plays Have $4 Marginal Cost. Source: EIA, Baker Hughes and Labyrinth Consulting Services, Inc.
Gas prices reached a weekly average low price of $1.57/mmBtu in February 2016 and then, rose consistently through the end of 2016. Shale gas rig counts doubled on expectation of $4 gas prices but flattened when prices failed to reach that threshold. The implication is that the marginal cost of shale gas is approximately $4/mmBtu.
The Bearish Scenario
Most gas-market observers anticipate a supply glut and gas-price collapse beginning late in 2017 because of new pipeline take-away capacity from the Marcellus-Utica plays. Associated gas from tight oil plays—the Permian basin in particular—is expected to extend this bearish view some years into the future.
Forward curves reflect this perspective. Their term structure is inverted meaning that near-term futures prices are higher than longer-term prices (Figure 6). Market traders are betting that winter gas prices will peak between $3.25 and $3.50/mmBtu and fall below $3 in early 2018. The volume of contracts beyond May 2018 approaches zero so the picture of worsening prices is speculative even a year into the future.
Figure 6. Henry Hub Forward Curves Are Currently in the $2.70 to $3.30/mmBtu Range. Source: CME and Labyrinth Consulting Services, Inc.
The bearish scenario will be disastrous for producers whose share prices have fallen nearly 30% already in 2017 (Figure 7). Although investors have been willing to fund the unprofitable efforts of these companies for many years, I suspect that their patience is wearing about as thin as it has lately for tight oil.
Figure 7. Natural Gas Equity Shares Have Fallen 29% Since January 2017. Source: Google Finance and Labyrinth Consulting Services, Inc.
Some analysts incorrectly believe that shale gas producers have already pushed costs so low through technology and efficiency innovation that sub-$3 gas prices will become the new normal. Although it is true that costs have fallen substantially, than because of deflationary pricing by the service industry and less because of technology and innovation.
In fact, the technology that enables unconventional oil and gas production resulted in a 4-fold increase in oil and gas drilling costs from 2003 to 2014 (Figure 8). Depressed demand since 2014 has resulted in a 45% reduction in drilling costs and this accounts for most savings.
Figure 8. The Cost of Drilling Oil and Gas Wells Fell 45% After The Oil-Price Collapse. Unconventional Plays Resulted in a 4-fold Increase in Drilling Costs. Source: U.S. Federal Reserve Bank, EIA and Labyrinth Consulting Services, Inc.
I have little doubt that there will be downward pressure on gas prices in the near term but do not see how sub-$3 prices can become the new normal. Producers have send-or-pay agreements with the pipelines that will carry new supply from the Marcellus and Utica plays. Some of these projects will probably deliver gas to Canada and LNG export markets having limited effect on domestic supply. Similarly, much future Permian basin gas will likely go to Mexico. New supply from the Marcellus and Utica plays will inevitably force gas from higher cost plays out of the market.
New volumes that enter the domestic market must first overcome the present supply deficit (Figure 9). Gas production fell more than 4 bcf/d from February 2016 to January 2017. EIA forecasts that production will increase 4.7 bcf/d in 2017 but only 1.9 bcf/d in 2018. EIA anticipates monthly average prices above $3.00 in 2018 ending the year at $3.66/mmBtu.
Figure 9. EIA Forecast: Supply Deficit & Prices Rising to $3.66 By December 2018. Source: EIA June 2017 STEO and Labyrinth Consulting Services, Inc.
This is only a forecast and certainly incorrect in its details but EIA’s domestic gas forecasts have been notionally reliable over the past several years. Increased consumption and exports should keep supplies relatively tight, and prices reasonably strong.