Natural gas drillers facing death-defying choices as futures prices hit 17-year low

by Wesley Brown ([email protected]) 144 views 

While declining crude oil prices have roiled international markets from Beijing to New York’s Mercantile Exchange, natural gas futures have quietly plummeted to levels not seen in this century and are pushing many companies in the energy sector closer to bankruptcy every day, industry experts say.

On Thursday, natural gas futures for April delivery closed down 6.4 cents or 3.7% at $1.678 per million British thermal units (MMBtu) on NYMEX. That is the lowest settlement price for natural gas contracts since Feb. 26, 1999, according to data from the U.S. Energy Information Administration (EIA).

The EIA, which serves as the research arm for the U.S. Department of Energy, will release its weekly natural gas update today (Thursday, March 3), and most analysts expect prices to remain under pressure due to the massive glut in U.S. stockpiles.

“Shale gas producers have done an amazing job growing production despite the continued low gas prices,” said Wall Street oil and gas analyst Fadel Gheit told Talk Business & Politics. However, even though most natural gas producers have sharply reduced capital spending and rig count, they have continued to add reserves and grow production.

“This is all driven by efficiency gains and this is expected to continue, unfortunately exacerbating the current glut, which continues to depress prices. Allowing more LNG [liquified natural gas] exports to Europe and Asia is the only way to improve natural gas prices without burdening U.S. natural gas consumers,” said Gheit, managing director and senior oil and gas analyst at New York City-based Oppenheimer & Co.

In its last report, the EIA noted that U.S. natural-gas inventories stood at 2.584 trillion cubic feet as of Feb. 19, a net decline of 117 billion cubic feet (BCf) from the previous week and 29% above the historical five-year average for this time of year.

Still, natural gas prices fell substantially at most market locations this week with the biggest declines in the Northeast, according to EIA data. The Henry Hub spot price fell from $1.91 MMBtu to $1.79 per MMBtu for the market week ending Feb. 24, and there is no expectation that today’s report will provide any good news changing that downward trend.

Even with prices touching a 17-year low, December dry natural gas production was the highest for the month since the EIA began reporting dry natural gas production data in 1973. Preliminary dry natural gas production for December 2015 was 2,289 Bcf, or 73.8 Bcf per day. This level was a 0.4 Bcf per day (0.6%) increase from December 2014 production of 73.4 Bcf per day.

On an annual basis, preliminary annual dry natural gas production for 2015 was 27,091 Bcf, or 74.2 Bcf/day, the highest annual total on record dating back to the Depression era in 1930. Preliminary annual total consumption for 2015 was 27,473 Bcf, or 75.3 Bcf per day, also the highest total on record dating back to 1949.

For natural gas drillers like Southwestern Energy Corp., whose portfolio is about 95% natural gas-fired production, the massive glut and plummeting prices have forced major cuts in capital spending, company layoffs, lower production targets in 2016, and a halt to all drilling operations.

Last week, Southwestern’s newly appoint CEO Bill Way announced that the Houston driller was cutting its 2016 capital spending by 80% to between $350-400 million, compared to $1.82 billion a year ago. That capital budget includes a plan to cut the number of wells drilled in 2015 from 380 to zero this year.

The 2016 capital budget will slash spending in the Fayetteville Shale to only $140 million, down 75% from $565 million a year ago and well off recent years when the Houston driller’s annual budget in the Arkansas shale play easily exceeded $1 billion.

“We will capitalize on our premier quality assets, significant hydrocarbon resource and strong liquidity position to proactively address the challenges presented by the current commodity price environment. Our strategic plan will enable us to optimize the business in today’s constrained environment while positioning us to outperform when commodity prices improve,” Way said.

RBC Capital analyst Scott Hanold said even with minimal well completions, Southwestern’s 2016 production is expected to sharply decline by 14-16% year-over-year and as much as 27% from “entry to exit.”

“We expect flexibility if commodity prices improve, but that may not occur until the second half of 2016,” Hanold wrote in a recent research note. However, Hanold, offered some hope if natural gas prices improved over the next year. “A 25 cent per thousand cubic feet (Mcf) improvement in natural gas prices increases cash flow by approximately $200 million,” he said.

Southwestern’s problems are not unique as commodity price pressures are spreading across the entire oil and gas sector. All companies – from marginal well drillers and midstream pipeline companies that ship oil and gas to key markets across the country to oilfield service companies that provide drilling crews and equipment to larger integrated oil giants like ExxonMobil, Chevron and Shell Oil – are facing tough decisions to either slash budgets, lay off workers or consider bankruptcy.

On Tuesday, Houston-based Anadarko Petroleum Corp., one of the largest pure oil and gas exploration and production companies in the world, cut its capital budget in half to between $2.6 billion and $2.8 billion, compared to spending that exceeded $5 billion in 2015.

Anadarko officials said the company is also reducing its U.S. onshore rig count by 80% to five operated rigs, from an average of 25 in 2015, while focusing on its base production and retaining the flexibility to leverage its inventory of approximately 230 drilled but intentionally uncompleted wells.

As many companies like Anadarko, Southwestern and Fayetteville Shale drillers like BHP Billiton and Exxon Mobil’s XTO Energy have essentially mothballed drilling operations until oil and gas prices rebound, the U.S. rig count has declined for the 10th straight week.

As of Feb. 29, the number of rigs operating in the U.S fell by 12 to 502, according to Baker Hughes’ weekly rig count. Of that total, oil rigs fell by 13 to 400 and gas rigs rose by one to 102. Overall, the U.S. rig count is down 60% to 765 rigs from 1,267 in operation a year ago.

On a positive note, the bloated natural gas inventories, low futures prices and warmer-than-expected winter has caused dozens of power companies across the U.S. to make fuel costs adjustments and lower customers’ utility bills.

Last month, Entergy Arkansas announced its annual “fuel and purchased power cost” adjustment for declining energy expenses will largely offset a projected increase from the utility giant’s rate case that is now before the Arkansas Public Service Commission.

Originally, Entergy Arkansas’s rate request filing in April 2015 would have raised a typical monthly bill for a residential customer using 1,000 kilowatts per hour (kWh) by nearly $13, or 45 cents a day.

Additionally, natural gas use in the electric power sector has averaged 25.0 billion cubic feet per day (Bcf/d) so far this winter, up 17% from last year’s average of 21.4 Bcf per day during the same period and significantly higher than the 18.8 Bc per day average of the past five years, EIA data shows.

More recently, the Department of Energy research group reported in February that natural gas-fired power plants generated more energy in the U.S. than coal in the last seven months of last year. Prior to 2015, natural gas-fired power generation had never exceeded coal.

That trend is expected to continue in 2016 and beyond, as a number of utilities are increasing investments in large-scale natural gas projects for electric generation. Natural gas-fired power plants accounted for just over 50% of new utility-scale generating capacity added to the U.S. energy grid in 2013, the EIA said.