Investors shouldn't put much stock into the overhyped recovery in U.S. natural gas prices. Yes, front-month natural gas prices in April 2013 rallied to a high of $4.408 per million British thermal units from an all-time low of $1.907 per million British thermal units 12 months earlier. But if you exclude six anomalous months of ultra-depressed natural gas prices, the commodity has merely oscillated around its four-year average of about $3.85 per million British thermal units over the past two years.
U.S. natural gas prices reflect a combination of long-term secular and shorter-term cyclical trends. Cyclical weather patterns drove the gas price collapse in early 2012.
Heating degree days (HDD) measure wintertime energy demand by subtracting a day's average temperature from a base level of 65 degrees Fahrenheit. For example, if a day's mean temperature in New York City is 40 degrees Fahrenheit that would equate to 25 HDDs. To quantify U.S. natural gas heating demand, the National Oceanic and Atmospheric Association (NOAA) releases data that assigns a weight to regional HDDs by their reliance on gas for heating.
The 2011-12 winter brought the fewest HDDs since NOAA began publishing this data in the early 1970s and snapped a five-year cycle of cold winters and rising HDDs. The effect on gas demand was devastating. Residential consumption of natural gas fell by 1.5 billion cubic feet per day, compared to the 2010-11 winter. Commercial demand dropped by 0.7 billion cubic feet per day.
Weekly data on the volumes of natural gas in storage drives near-term price action in this commodity. Thanks to weak demand during the 2011-12 winter, U.S. natural gas in storage had swelled to about 60 percent above the five-year average in April 2012. Natural gas prices plummeted in response.
The market ultimately corrected this imbalance. U.S. electric utilities ramped up operations at their natural gas-fired power plants to take advantage of the commodity's ultra-depressed price, a trend that hit domestic coal producers hard. The industry's total consumption of natural gas surged to 24.96 billion cubic feet per day in 2012 to 20.75 billion cubic feet per day in 2011. Exploration and production companies also curtailed drilling activity or shut in unprofitable wells, helping to limit the magnitude of production growth last year.
More important, the weather cooperated. With temperatures returning to normal during the 2012-13 winter, robust demand sopped up the excess volumes of natural gas in storage; by early 2013, inventories were near their five-year average once again. Headlines casting the big rally in natural gas prices as a major structural shift are disingenuous. The front-month price of this commodity has declined 16 percent from 24 months ago and 21 percent from 36 months ago. In other words, aside from the unseasonably warm 2011-12 winter, supply-demand conditions in the U.S. market for natural gas remain relatively unchanged.
In the short to intermediate term, natural gas prices should hover around prevailing levels. With some notable exceptions, the price of this commodity tends to weaken over the summer and strengthen in the fall and winter; natural gas inventories build during the summer, a period of weak seasonal demand, and decline in the fall and winter, when heating demand picks up.
Assuming normal weather patterns, natural gas prices should range between $3.25 per million British thermal units and $4.50 per million British thermal units over the next 12 months. Expect the commodity to test the low end of this price range over the next three months and the high end between November 2013 and March 2014.
Although media coverage often ensures that short-term trends in commodity markets are at the forefront of investors' minds, a firm understanding of secular trends in natural gas supply and demand is critical to building wealth over the long term. At present, these structural trends point to rising supplies of natural gas and a prolonged period where the commodity fetches less than $5 per million British thermal units in the U.S.
The U.S. Energy Information Administration's (EIA) Annual Energy Outlook 2007 called for the U.S. to expand yearly imports of liquefied natural gas (LNG) to 4.5 trillion cubic feet in 2030 from 0.6 trillion cubic feet in 2006. At the time, the U.S. lacked the domestic resources to replace waning natural gas output from mature fields.
Of course, the shale-oil and -revolution has completely reversed the supply outlook: Surging natural gas production from unconventional plays such as Appalachia's Marcellus Shale and the Eagle Ford Shale in southern Texas have enabled the U.S. to overtake Russia as the world's leading producer of the commodity. Accordingly, U.S. LNG imports fell to 130 billion cubic feet last year-well off the peak of 771 billion cubic feet in 2008.
Even more impressive, the EIA's most recent Annual Energy Outlook calls for the U.S. to transition from a net importer of natural gas in 2010 to a net exporter of over 3.55 trillion cubic feet by 2040. If these predictions pan out, the U.S. would export more than 10 percent of its annual gas production.
Ongoing development of the nation's shale-oil and -gas reserves underpin these forecasts. In 2008 volumes from unconventional fields accounted for about 11 percent of domestic natural gas production. As of last year, this percentage had tripled, while the EIA's current estimate calls for shale basins to account for more than half U.S. natural gas production by 2035.
The boom in shale-gas production is real and enduring. Over the past few years, a number of pundits and major media outlets have advanced the notion that the upsurge in U.S. natural gas output is a temporary phenomenon. This argument, summarized in the New York Times' article "Insiders Sound an Alarm amid a Natural Gas Rush," is that shale-gas wells exhibit unusually steep decline rates and that their output falls precipitously a few months after first production. Accordingly, critics assert that producers have vastly overestimated the potential output from U.S. unconventional fields.
These articles may attract eyeballs, but the underlying arguments don't hold water. True, the production profile of a horizontal well in a shale basin differs from a vertical well in a conventional field.
This graph from Chesapeake Energy Corp.'s (NYSE:CHK) July 2013 Investor Presentation illustrates the production profile of the upstream operator's acreage in the liquids-rich windows of the Eagle Ford Shale. Output from the company's typical well in this region declines roughly 65 percent in its first year, another 35 percent in the second year and 25 percent in the third year. Only after seven to eight years does the annual decline rate on Chesapeake Energy's average well in the Eagle Ford Shale shrink to between 8 and 10 percent-the typical range for mature conventional wells.
But investors must keep in mind that these sharp decline rates come from high initial rates of production. Chesapeake Energy's typical well in the Eagle Ford Shale flows hydrocarbons at an average rate of 626 barrels of oil equivalent per day over the first month of its life. That is, even after three years of production, Chesapeake Energy's average well in the Eagle Ford still yields about 100 barrels of oil equivalent per day.
The same pattern applies to the company's acreage in the Marcellus Shale, where the firm's average well exhibits an initial production rate of 12 million cubic feet of natural gas equivalent per day and a 60 percent decline rate in its first year. The well's output usually shrinks by 43 percent in the second year and 32 percent in the third year, at which point production averages about 2 million cubic feet of natural gas-equivalent per day.
Let's put these numbers into context. In 2007, there were 440,516 gas-producing wells in the U.S., from which operators extracted about 19 trillion cubic feet of natural gas, or about 52 billion cubic feet per day. In other words, the average U.S. well produced 118,000 cubic feet of natural gas per day in the U.S. Investors should also bear in mind that this estimate excludes volumes of associated natural gas lifted from wells that primarily produce crude oil.
Fast forward to 2011, when the U.S. energy industry produced about 22.57 trillion cubic feet of natural gas from 514,637 wells. That is, the average well yielded roughly 120,000 cubic feet per day of natural gas. Despite shale plays accounting for an increasing percentage of U.S. natural gas production between 2007 and 2011, the average productivity of the nation's wells ticked up slightly over this period.
Source: Energy Information Administration and Energy & Income Advisor.
For the sake of argument, let's assume that the U.S. energy industry has overstated the productivity of major shale-oil and -gas plays to bolster asset valuations. If we follow this line of reasoning, sky-high decline rates would force producers to accelerate their drilling activity to offset diminishing output from older wells. An oil and gas company facing an average annual decline rate and looking to grow production would have to drill ever-more aggressively to accomplish this goal. However, the exact opposite has occurred.
Between August 2008 and mid-2009, the number of onshore drilling rigs targeting natural gas in the U.S. plummeted to less than 700 from about 1,600-a product of the collapse in energy prices brought about by the credit crunch and Great Recession. As natural gas prices recovered in late 2009, the gas-directed rig count climbed to a high of almost 1,000 units in August 2010. Thereafter, extended weakness in natural gas prices has precipitated a sharp decline in the rig count to a recent low of about 350 units.
Despite these moves in the U.S. gas-directed rig count, natural gas production has continued to climb, suggesting that upstream operators could quickly boost their output if rising consumption and commodity prices improved wellhead economics. Moreover, the energy industry could easily bring mothballed production onstream in Louisiana's Haynesville Shale and other out-of-favor plays where drilling activity has trailed off because of higher costs.
The U.S. shale-oil and -gas revolution isn't a temporary or fleeting phenomenon but a long-term secular trend. For natural gas prices to break out of their recent range, consumption would need to expand to levels that would absorb the structural oversupply in the U.S. market. Such a situation likely won't emerge until after 2015, when U.S. LNG export capacity comes online and pipeline shipments to Mexico pick up.
In terms of domestic demand, electric utilities' appetite for natural gas will continue to grow as older, coal-fired plants are retired. We also expect natural gas to make inroads as a transportation fuel, especially for fleet vehicles and commercial trucks. But these adjustments will occur incrementally and over a long time frame. The EIA forecasts that LNG and compressed natural gas (CNG), which currently account for about 0.19 percent of U.S. transportation fuel, will grow their share to almost 4 percent of the market by 2040.
Until exports or new sources of demand kick in, expect natural gas to fluctuate between $3.00 per million British thermal units and $5.00 per million British thermal units. Whenever the price of natural gas exceeds $5.00 per million British thermal units, an influx of new supply should exert downward pressure on prices. By the same token, coal-to-gas switching by electric utilities should establish a floor under prices.