Enthusiasts believe that shale gas is simultaneously cheap, abundant and profitable thus defying all rules of business and economics. That is magical thinking.
The recently released EIA Annual Energy Outlook 2016 sparkles with pixie dust as it forecasts almost unlimited gas supply at low prices out to 2040 and beyond. Exuberant press reports herald a new era of LNG exports that will change the geopolitical balance of the world and make America great again.
But U.S. shale gas production is declining because of low prices and shale gas companies are in deep financial trouble because in the real world, price and cost matter.
That is not magical.
First Quarter 2016 Financial Performance
The financial performance of shale gas-weighted E&P companies in the first quarter of 2016 was a disaster.
Chesapeake Energy, the biggest shale gas producer in the world, had negative cash from operations.
That means that oil and gas sales didn’t even cover operating costs much less capital expenditures like drilling and completion.
Other shale gas-weighted companies including Anadarko, Comstock and Petroquest also had negative cash from operations. Goodrich and Sandridge are in bankruptcy and Exco and Halcon will soon follow. Ultra, Forest, Quicksilver, Swift and Talisman were lost in action last year.
On average, surviving companies out-spent cash flow by two-to-one both in 2015 and 2016 but many normally strong companies greatly increased negative cash flow this year.
Devon Energy has been cash-flow neutral through much of the shale gas revolution but disturbingly increased capex-to-cash flow 5-fold in the first quarter of 2016. Similarly, Southwestern Energy has had an excellent record of near-cash flow neutrality but doubled its negative cash flow in 2016.
The debt side of first quarter earnings is far more disturbing. The average debt-to-cash flow ratio for shale gas companies increased almost 4-fold to more than 7, up from less than 2 in 2015.
Devon’s debt-to-cash flow was more than 21 and Southwestern’s, more than 17. Gas prices below $3 cannot be sustained without damaging the balance sheets and income statements of even well-managed companies.
Debt-to-cash flow is a critical determinant of risk from a bank’s perspective because it measures how many years it would take to pay off debt if 100% of cash from operations were used for this purpose.
This means that it would take these companies an average of 7 years to pay down their total debt using all cash from operating activities.
The energy industry average from 1992-2012 was 1.53 and 2.0 was a standard threshold for banks to call loans based on debt-covenant agreements. That threshold increased in recent years to about 4 but 7 years to pay off debt is clearly beyond reasonable bank exposure risk.
Low Gas Prices and Declining Production
Shale gas is the principal support for all U.S. gas production since conventional gas is in terminal decline. U.S. dry gas production has declined almost 1 Bcf per day since September 2015 largely because of low gas prices
Henry Hub gas prices have fallen for the last 2 years from more than $6/mmBtu in January 2014 to $2 today and prices have been below $3/mmBtu since early 2015. A similar gas-price decline occurred from June 2011 to April 2012 (Figure 3). Then, dry gas production fell when prices dropped below $3/mmBtu.
$3 is well below the break-even gas price for any operator in any play. Even in the Marcellus–the most commercially attractive shale gas play–break-even prices are more than $3.
Shale gas production has fallen 0.83 Bcf/d since February 2016 All plays have declined from their respective peaks except the Utica Shale. Marcellus production accounts for more than a third (-0.36 Bcf/d) of shale gas decline in 2016. There is certainly no shortage of supply in that play but low prices and related delays in pipeline commitments have taken their toll on production.
There are no longer any horizontal rigs drilling in the Barnett or Fayetteville, plays that were supposed to help provide the U.S. with 100 years of gas supply. That is the intersection of magical thinking and low gas prices.
Posted in The Petroleum Truth Report on May 24, 2016
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In its latest Short-Term Energy Outlook, the U.S. Energy Information Administration (EIA) forecasts that natural gas-fired electricity generation in the United States will increase by 6% in 2019 and by 2% in 2020. EIA also forecasts that generation from wind power will increase by 6% in 2019 and by 14% in 2020. These trends vary widely among the regions of the country; growth in natural gas generation is highest in the mid-Atlantic region and growth in wind generation is highest in Texas. EIA expects coal-fired electricity generation to decline nationwide, falling by 15% in 2019 and by 9% in 2020.
The trends in projected generation reflect changes in the mix of generating capacity. In the mid-Atlantic region, which is mostly in the PJM Interconnection transmission area, the electricity industry has added more than 12 gigawatts (GW) of new natural gas-fired generating capacity since the beginning of 2018, an increase of 17%.
This new natural gas capacity in PJM has replaced some coal-fired generating capacity—6 GW of coal-fired generation capacity has been retired in that region since the beginning of 2018. The Oyster Creek nuclear power plant in New Jersey was also retired in 2018, and the Three Mile Island plant in Pennsylvania plans to shut down its last remaining reactor this month.
These changes in capacity contribute to EIA’s forecast that natural gas will fuel 39% of electricity generation in the PJM region in 2020, up from a share of 31% in 2018. In contrast, coal is expected to generate 20% of PJM electricity next year, down from 28% in 2018. In 2010, coal fueled 54% of the region’s electricity generation, and natural gas generated 11%.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
Wind power has been the fastest-growing source of electricity in recent years in the Electric Reliability Council of Texas (ERCOT) region that serves most of Texas. Since the beginning of 2018, the industry has added 3 GW of wind generating capacity and plans to add another 7 GW before the end of 2020. These additions would result in an increase of nearly 50% from the 2017 wind capacity level in ERCOT. EIA expects wind to supply 20% of ERCOT total generation in 2019 and 24% in 2020. If realized, wind would match coal’s share of ERCOT's electricity generation this year and exceed it in 2020.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
Natural gas-fired generation in ERCOT has fluctuated in recent years in response to changes in the cost of the fuel. EIA forecasts the Henry Hub natural gas price will fall by 21% in 2019, which contributes to EIA’s expectation that ERCOT’s natural gas generation share will rise from 45% in 2018 to 47% this year. Although EIA forecasts next year’s natural gas prices to remain relatively flat in 2020, the large increase in renewable generating capacity is expected to reduce the region’s 2020 natural gas generation share to 41%.
Headline crude prices for the week beginning 9 September 2019 – Brent: US$61/b; WTI: US$56/b
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Detailed market research and continuous tracking of market developments—as well as deep, on-the-ground expertise across the globe—informs our outlook on global gas and liquefied natural gas (LNG). We forecast gas demand and then use our infrastructure and contract models to forecast supply-and-demand balances, corresponding gas flows, and pricing implications to 2035.Executive summary
The past year saw the natural-gas market grow at its fastest rate in almost a decade, supported by booming domestic markets in China and the United States and an expanding global gas trade to serve Asian markets. While the pace of growth is set to slow, gas remains the fastest-growing fossil fuel and the only fossil fuel expected to grow beyond 2035.Global gas: Demand expected to grow 0.9 percent per annum to 2035
While we expect coal demand to peak before 2025 and oil demand to peak around 2033, gas demand will continue to grow until 2035, albeit at a slower rate than seen previously. The power-generation and industrial sectors in Asia and North America and the residential and commercial sectors in Southeast Asia, including China, will drive the expected gas-demand growth. Strong growth from these regions will more than offset the demand declines from the mature gas markets of Europe and Northeast Asia.
Gas supply to meet this demand will come mainly from Africa, China, Russia, and the shale-gas-rich United States. China will double its conventional gas production from 2018 to 2035. Gas production in Europe will decline rapidly.LNG: Demand expected to grow 3.6 percent per annum to 2035, with market rebalancing expected in 2027–28
We expect LNG demand to outpace overall gas demand as Asian markets rely on more distant supplies, Europe increases its gas-import dependence, and US producers seek overseas markets for their gas (both pipe and LNG). China will be a major driver of LNG-demand growth, as its domestic supply and pipeline flows will be insufficient to meet rising demand. Similarly, Bangladesh, Pakistan, and South Asia will rely on LNG to meet the growing demand to replace declining domestic supplies. We also expect Europe to increase LNG imports to help offset declining domestic supply.
Demand growth by the middle of next decade should balance the excess LNG capacity in the current market and planned capacity additions. We expect that further capacity growth of around 250 billion cubic meters will be necessary to meet demand to 2035.
With growing shale-gas production in the United States, the country is in a position to join Australia and Qatar as a top global LNG exporter. A number of competing US projects represent the long-run marginal LNG-supply capacity.Key themes uncovered
Over the course of our analysis, we uncovered five key themes to watch for in the global gas market: