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Only Higher Prices Can Prevent The Imminent Natural Gas Bust

Natural Gas

One hundred years of natural gas? Not at these prices.

U.S. gas production is declining and shale gas output is down almost 2.5 Bcf per day. Production is decreasing while consumption and exports are both increasing. EIA data indicates a supply deficit by the end of 2016.

Henry Hub spot prices have doubled since early March. Will companies show discipline to preserve higher prices?

Not a chance. They will drill more wells if investors continue to provide capital. This, however, will probably be too little too late to stop the decline in gas production that is already underway.

Real Gas Prices Have Never Been Lower

In February 2016, I wrote that an increase in natural gas prices was inevitable and in April, I wrote that prices would double. Now, spot prices have doubled from $1.49 on March 4 to $2.97 per mmBtu on August 29 (Figure 1).

Still, real natural gas prices (in July 2016 dollars) have never been lower. Average prices so far this year are just $2.20 per mmBtu. That’s the lowest annual price in since 2000 and it is lower than any monthly price except April 2012.

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Figure 1. Real natural gas prices have never been lower than in 2016. Henry Hub natural gas prices are in CPI-Adjusted July 2016 dollars. Source: EIA, U.S. Bureau of Labor Statistics and Labyrinth Consulting Services.

Prices have increased because total dry gas production has declined 1.6 Bcf per day (Bcfd) from its peak of 75.29 Bcfd in February. Shale gas production has declined 2.4 Bcfd from its peak of 44.17 Bcfd (Figure 2).

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Figure 2. Total natural gas and shale gas production have declined since February 2016. Source: EIA August 2016 STEO, EIA Natural Gas Weekly Update and Labyrinth Consulting Services, Inc.

Conventional gas has been in terminal decline since 2008 and shale gas production growth has maintained and increased U.S. supply. Now, that shale gas production is also in decline (Figure 3), it is unlikely that production will increase much without higher prices.

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Figure 3. Shale gas production has declined 2.4 billion cubic feet per day since February 2016. Source: EIA Natural Gas Weekly Update and Labyrinth Consulting Services, inc.

All shale gas plays have declined including the Marcellus which is down -0.64 Bcfd (Table 1). Even the relatively new Utica play has declined -0.12 Bcfd. The legacy plays have declined the most: Haynesville, -3.77 Bcfd; Barnett, -1.91 Bcfd; and Fayetteville, -0.92 Bcfd. No new horizontal wells have been drilled in either the Barnett or Fayetteville since early 2016.

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Table 1. Shale gas play declines from maximum production. Source: EIA Natural Gas Weekly Update and Labyrinth Consulting Services, Inc.

Shale gas plays were supposed to provide 100 years of supply but there never was 100 years of gas.

It was a story told to promote the erroneous idea that the U.S. had so much gas that it could afford to squander and export this valuable natural resource. It is true that some of the production decline from shale gas plays is because the plays are not commercial at current prices.

But whose fault is that? Conscious over-production reduced the price below the marginal cost so promoting increased consumption and export became the only ways to increase price.

The U.S. government has been a great ally of the shale gas companies.

The SEC changed reserve reporting rules in 2010 making it easier for companies to book reserves and borrow against them. EPA air pollution regulations since 2011 have led to the closing of dozens of coal-fired power plants in favor of increased dependency on natural gas for electric power thus increasing demand. The U.S. Department of Energy has granted almost blanket approval to applications for LNG (liquefied natural gas) and pipeline export in recent years also increasing demand. And in 2011, the U.S. Department of State under Hillary Clinton created the Bureau of Energy Resources, a 63-person group to promote shale gas export and the spread of fracking technology around the world.

Meanwhile, E&P companies destroyed billions of dollars in shareholder value. They did this by knowingly producing gas into a non-commercial market and then, diluting shareholders by issuing more stock to fund more drilling and production.

Comparative Inventories Tell The Story

Natural gas storage is at near-record levels for this time of year. This surplus distracts from the likelihood of a supply deficit by the end of 2016 suggested by EIA STEO data (Figure 4).

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Figure 4. Natural gas supply should go into deficit by January 2017. Source: EIA September 2016 STEO and Labyrinth Consulting Services, Inc.

Periods of production growth led to lower prices and lower gas-directed rig counts. Flat production led to supply deficits that resulted in higher prices and more drilling. During the last deficit in 2013 and 2014, spot prices averaged $4.06 per mmBtu. The ensuing low prices have resulted in less drilling and flat production.

It is, therefore, reasonable that the increase in gas prices since March 2016 will result in more supply but how high might gas prices go before that happens?

Comparative inventories are the best indicators of price trends. Comparative inventory is the difference between current storage volumes and the 5-year average of storage levels for the same week. Figure 5 shows that there is an excellent negative correlation between comparative inventory and spot gas prices.

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Figure 5. Comparative inventories are the best indicators of price trends. Source: EIA and Labyrinth Consulting Services, Inc.

That is because the U.S. gas market is a disequilibrium system in which production and consumption are never in balance. During the months of winter heating, consumption greatly exceeds production. Withdrawals from storage provide the portion of supply that remains unmet by production. Once winter is over, production exceeds consumption. Additions to storage restore that portion of supply needed for the next winter heating season. Related: An OPEC Production Freeze Could See Oil Prices Rise To $60

Gas traders compare the current year’s evolving inventory level with that of previous years to determine if storage will be adequate to meet winter demand. If the rate of inventory buildup is judged to be ahead of expected winter demand, the price of futures contracts decreases. If that rate is deemed questionable to meet winter demand, the price of those contracts increases. Producer response to price signals is typically delayed until a price trend emerges to justify increased or decreased drilling. The potential for over-shoot and under-shoot is great.

Comparative inventory is, therefore, the best measure of the disequilibrium in the seasonal supply chain. It effectively removes the seasonal effects of energy use and plant maintenance that sometimes confuse the interpretation of absolute inventory levels.

Figure 6 shows that the fall in comparative inventories since May 2016 has been significant compared to both the 5-year average and to 2015 inventory levels.

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Figure 6. Comparative Inventories (CI) have fallen sharply since May 2016. Source: EIA and Labyrinth Consulting Services, Inc.

Despite falling comparative inventory, prices commonly decrease in the late summer based on probable inventory levels needed to meet winter consumption. Although that may be happening now, I believe that higher prices will prevail by the end of 2016.

A simplified cross-plot of comparative inventory and spot prices suggests a range of likely year-end prices between $3.00 to $3.75 with a most-likely case of of approximately $3.35 per mmBtu (Figure 7).

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Figure 7. Simplified 2014-present comparative inventory vs. spot price cross-plot suggests a $3.00 – $3.75 price range for year-end 2016. Source: EIA and Labyrinth Consulting Services, Inc.

Shale Gas Company Performance Is Weak

What will happen if gas prices increase to approximately $3.35 per mmBtu in the next several months? Operators with access to capital will probably add rigs and increase production. That is the correct response to market price signals in a market that believes company claims that they are making money at current gas prices.

Approximately 150 new wells are being completed each month in the currently active shale gas plays namely, the Marcellus, Utica, Haynesville and Woodford plays (Figure 8).

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Figure 8. Number of new producing wells per month and gas production from the Pennsylvania Marcellus Shale, Utica Shale, Haynesville Shale and Woodford Shale plays. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Unfortunately, most companies cannot make a profit at current gas prices despite their public statements. Today’s wellhead prices in the Marcellus Shale play have increased to $1.34 per mmBtu and Utica prices averaged $1.44 in the second quarter of 2016. A few well-hedged companies may break even on costs in the best parts of the Marcellus and Utica core areas but most do not.

Even so, breaking even does not meet the standards of serious investors who need at least a 10-15% discounted return once the cost of capital, and project and commodity risk are considered. Most Haynesville and Woodford wells need at least $6.00 per mcfe to break even.

All leading companies in the Marcellus and Utica plays reported net losses for the second quarter of 2016 summarized in Table 2. Antero, Cabot, Gulfport and Rice apparently had better access to equity capital than the rest based on share offerings in the first half of 2016.

Table 2. Marcellus-Utica key operator second quarter (Q2) 2016 gains and losses and first half (1H) 2016 equity offerings. Source: Company documents and Labyrinth Consulting Services, Inc.

The debt loads and debt-to-cash flow ratios of these companies is alarming. The average for the companies shown in Figure 9 was 9.4 in the first half of 2016. The current bank-risk threshold for debt-to-cash flow is about 4:1.

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Figure 9. All leading Marcellus-Utica operators exceeded debt-to-cash for bank-risk threshold of 4:1 in the first half of 2016. Source: Google Finance and Labyrinth Consulting Services, Inc.

Nor do the stock prices of most of these companies provide a good proxy for the substantial increase in Henry Hub spot prices of 75% since March 2016. Although the increase in stock prices for all companies exceeded 10%, only Rice and Consol out-performed commodity price and UNG (Exchange-traded natural gas fund) gains (Figure 10).

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Figure 10. Most leading Marcellus-Utica Companies’ stock prices under-performed spot and ETF gains since March 2016. Source: Google Finance and Labyrinth Consulting Services, Inc.

Despite their financial weakness, I expect that a small number of producers will continue to find favor among yield-hungry investors. I doubt, however, that increased drilling by those companies and a few like them in the Woodford play will be able to reverse declining shale gas production and, therefore, U.S. gas production.

In the early 2000s, the U.S. was running out of natural gas. Canadian imports supplied 17% of U.S. consumption by late 2005. The shale gas revolution was a singular phenomenon that occurred initially because gas prices from 2000 through mid-2008 averaged more than $7 per mmBtu in real 2016 dollars.

In late 2002 and early 2003, a few wells were horizontally drilled and hydraulically fracturing in the Barnett Shale. Initial production rates were more than three times higher than Mitchell Energy’s vertical wells that had been drilled as an experiment in the previous decade. Devon Energy and other operators applied for permits to drill more than 180 additional horizontal wells by mid-2003 and the shale gas rush was on.

A few years later in 2005, Southwestern Energy began the exploration and development of the Fayetteville Shale in nearby Arkansas. The apparent early success of the Barnett and Fayetteville plays heightened the frenzy of mineral leasing as prices soared to over $10,000 per acre. By 2007, Chesapeake Energy Corporation emerged as the dominant player in shale gas with a position second only to Devon in the Barnett and the leading position in the emerging Haynesville Shale play in Louisiana and East Texas.

Initial production rates of more than 10 million cubic feet (mmcf) per day from Chesapeake’s first Haynesville wells lead to an unprecedented land grab reminiscent of gold rushes in the 19th and early 20th centuries. Plains Exploration and Production Company paid more than $30,000 per acre to form a joint venture with Chesapeake. Foreign oil and gas companies eagerly entered similar partnerships with the company in the Haynesville, Barnett and Marcellus plays while major oil companies like ExxonMobil and BP also entered the shale gas arena.

Range Resources tested the first horizontally drilled wells in the Marcellus Shale in Pennsylvania in 2005. Development in the Marcellus was somewhat slower than the other plays but it has now proven to be the most prolific among them.

The explosion of production resulted from the mass participation in the plays by thousands of companies. Gas prices collapsed beginning in July 2008 with the onset of The Financial Collapse. After that, easy-money policies kept the party going for a few more years.

Over-production pushed gas prices well below the marginal cost of the wells. Liquids-rich and later, tight oil plays then stole the spotlight from shale gas. Gas could not compete with oil for profit or investor capital and it was really gas associated with the newer tight oil plays that kept gas production strong.

Despite the flagging fortunes of the shale gas plays, the natural gas lobby concocted a story that said the United States had 100 years of natural gas supply. This was based largely on technically recoverable resource estimates by the Potential Gas Committee that had nothing to do with reserves or economics. By 2012, the idea of 100 years of gas found its way into President Obama’s State of the Union address.

The collapse of oil prices in 2014 was the turning point for U.S. gas supply. It does not seem likely that oil prices will break out of their current range boundaries of about $40 to $50 any time soon and so associated gas will continue to decline. Even adding 150 new wells per month in the 4 active shale gas plays has not arrested or even slowed the inexorable decline of shale gas production.

North American natural gas supply is largely a closed system. Even a weak economy cannot suppress the price of gas as supply becomes less secure. That is because gas use has been implicitly mandated by EPA regulations and its low price over the last 7 years has greatly limited the growth of renewable alternatives.

Those regulations and the foolish decision to allow increased exports were founded on the preposterous belief that U.S. gas supply was almost unlimited, that we had at least 100 years of gas. It was a classic case of thinking that the future would be just like the present and immediate past, and that gas production would continue to increase forever. A similar irrational belief underlaid the real estate bubble that ultimately led to the 2008 Financial Collapse.

People in the eastern U.S. are not really all that into gas drilling, fracking and pipelines. Environmental groups have learned that they can slow the permitting and construction of pipelines. This has kept wellhead prices low and development in check. Related: Why Is Big Oil Backing Clinton Over Trump?

There never was 100 years of natural gas. The Barnett and Fayetteville plays that began a little more than a decade ago are dead at today’s prices. No horizontal wells have been drilled in either play since January of this year.

The Haynesville Shale was a great disappointment but has considerable volumes that can be developed commercially at $6 gas prices or higher. There are 35 rigs working in the Woodford play where liquids contribute to the value stream but unhedged producers need about $6 prices there also.

The Marcellus is the jewel in the shale gas crown and is currently providing almost 25% of U.S. total supply. Even the Marcellus, however, needs $4 gas prices for unhedged operators to break even. Although production has peaked, it will continue to provide meaningful supply into the next decade but not forever.

The Utica Shale is still in a relatively early stage of development but has the potential for commercial production at $4 to $5 gas prices in its core. That area is poorly defined at present but is smaller than the Marcellus core areas. Utica counties outside the core need $6 gas prices to break even.

The U.S. is not running out of gas yet. It will, however, take much higher prices to develop the remaining decade or so of supply. We have squandered the best production into a losing market and committed additional volumes to long-term foreign contracts that never made sense in the first place.

Declining production, greater consumption and increased exports have combined to make natural gas one of the best commodity values around. If somewhat higher prices cannot rescue supply then, even higher prices will be needed.

By Art Berman For Oilprice.com

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Leave a comment
  • Joe on September 08 2016 said:
    Well written article with a lot of research. If anyone doubts the story, take a look at today's natural gas storage numbers. The bubble is almost gone.
  • Coffeeguyzz on September 08 2016 said:
    Mr. Berman

    The US does not have 100 years' supply of natgas ... it has 200.

    The most recent Deep Utica well by EQT, the Shipman, has produced almost 1 1/2 Bcf it's first 37 days online, producing just under 40 MMcfd in June.
    JKLM's Sweden Valley well in Potter county not only greatly expanded the Utica's footprint in North central PA, it produced over 2 Bcf it's first six months online.

    The Upper Devonian is once again a target and, with the past few months' production numbers, looks to exceed Wrightstone Energy's report projecting 100 Tcf recoverable.

    The recent West Virginia University study on the Utica claims near 800 Tcf recoverable ... comparable to the Marcellus.

    Way, WAY down the road, the Trenton Black River may once again produce from its depths ... long after we are no longer around to discuss it.
  • JR on September 09 2016 said:
    Excellent analysis.
  • Bill Simpson on September 09 2016 said:
    Go on Google Earth and check out the size of the shallow Arctic Russian continental shelf. Imagine how much oil and gas might be under that vast area. Those big Siberian rivers have been depositing organic material there for a long time. Are those Russian deltas as prolific as some others have been? Once the ice melts, a vast amount of gas might become available from up there. By then, cold warrior Putin will be long gone. Russia might become a safe place for the world to invest. If not, Russia will still need the cash.
    Better detection through salt layers could locate a lot more oil and gas.
    I'm doing my part in my all electric home. Electricity can be made from nukes, wind, hydro, solar, and geothermal sources. I like the nukes myself. Even if it's more expensive, gas is finite, and too useful to waste as a fuel. Like oil, it should be conserved as much as possible for use in chemical and fertilizer manufacturing. Once they are gone, we will be screwed. The hydrocarbons WILL be missed. Baring some unanticipated development, life will be harder and shorter after they are gone.

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