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At the World MoneyShow Toronto last week, several attendees asked for my updated take on North American natural-gas prices—a common question since gas prices peaked in 2008.
Despite persistent weakness, pundits continue to call false bottoms in natural-gas prices and recommend shares of companies that produce primarily natural gas.
Far too many investors and talking heads were head-faked by the weather-driven spike in natural gas that occurred in early 2014, buying shares of Cabot Oil & Gas Corp (NYSE: COG) and other names with sizable acreage positions in the Marcellus Shale.
Here’s why North American natural-gas prices should remain low over the next two to three years.
The investment media made a big deal about last winter’s upsurge in natural-gas prices, a phenomenon that stemmed from severely cold weather, not a lasting change in the underlying supply and demand conditions.
Many investors and media outlets focus on the spot market, where volumes are available for immediate delivery. This price benchmark is much more vulnerable to seasonal weather conditions.
In contrast, oil and gas producers focus on the 12-month strip, or the average cost of natural-gas for delivery over the next year. This forward-looking benchmark smoothes out weather-related fluctuations and other temporary blips, providing better insight into the producer’s full-year price realizations.
On this basis, North American natural-gas prices have fluctuated around $4 per million British thermal units over the past four years, with the high and low end of this range marked by the no-show 2011-12 winter and the polar vortex earlier this year.
Plummeting natural-gas prices from mid-2008 to late 2009 prompted many upstream operators to scale back drilling activity in the Haynesville Shale and other plays that primarily produce this out-of-favor commodity.
However, the decline in gas-directed drilling activity hasn’t resulted in a commensurate decline in US production.
Prior the shale revolution, a decline in the number of active rigs targeting natural gas would translate into lower production—exactly what happened when drilling activity slumped from mid-2001 to mid-2002.
But the traditional relationship between the gas-directed rig count and production completely broke down in 2008.
Although the number of rigs targeting natural gas collapsed from more than 1,600 in mid-2008 to 310 units in April 2014, US production has soared from 57 billion cubic feet per day to 70 billion cubic feet per day in July 2014.
This divergence reflects two factors:
You can read more about these trends in Breaking Down the US Onshore Rig Count and Salute Your Drillmasters: Efficiency Gains Lower Production Costs.
As the energy industry has transitioned to pad drilling and optimized well designs and completion techniques, operators have produced more natural gas from fewer active rigs.
Over the past two years, output per rig has increased by more than 50 percent in the Marcellus Shale, effectively lowering producers’ break-even costs to about $2 per million British thermal units in the play’s liquids-rich fairway.
Source: Crestwood Midstream Partners LP
These efficiency gains, coupled with readily available credit and independent producers’ imperative to grow their hydrocarbon output, mean that natural-gas prices near $4 per million British thermal units are no longer a disincentive to production.
But back in 2008, many producers needed natural gas to fetch $7 to $8 per million British thermal units to support drilling activity in higher-cost resource plays.
In addition, 15 percent to 20 percent of US natural-gas production comes from oil wells, a figure that could increase in coming years aw more gas-gathering and processing infrastructure comes onstream in the Bakken Shale.
Bottom Line: As long as crude oil remains above $70 per barrel, volumes of associated natural gas should continue to climb.
We also expect North American crude-oil output to remain more resilient than some expect because of hedging programs that lock in prices on future output and independent producers allocating more capital to core acreage that generates the best internal rates of return.
Over the past few years, energy companies have proposed the construction of more than 30 terminals to export liquefied natural gas (LNG). Thus far, the Federal Energy Regulatory Commission (FERC) has approved only four projects—about 6 billion cubic feet per day—to move forward.
But the market itself will dictate how much LNG export capacity the US adds; given the capital intensity of these projects, only terminals that have secure volume commitments from customers will be able to obtain the necessary financing. (See Understanding the Appeal of US LNG Exports.)
The case for LNG exports is deceptively simple: Whereas the 12-month strip for US natural-gas prices hovers around $3.60 per million British thermal units, this commodity fetches $9 per million British thermal units in Europe and $16 per million British thermal units in Asia.
When you factor in the $6 to $7 per million British thermal units that it would cost to liquefy and ship LNG from the Gulf Coast to Asia, these price advantages appear slightly less compelling. Liquefaction and shipping costs for cargos headed to Europe are expected to range from $3 to $4 per million British thermal units.
Cheniere Energy Partners LP’s (NYSE: CQP) Sabine Pass facility is slated to start exporting LNG from the US Gulf Coast in late 2015 or early 2016. More capacity will come onstream by 2020. By 2021, the US will also export more natural gas to Mexico and Canada via pipeline than it imports.
All told, the Energy Information Administration (EIA) forecasts that the US will export about 2 trillion cubic feet of natural gas annually by 2020—about 7 percent of projected supplies.
The EIA’s longer-term outlook contemplates the US exporting 5.8 trillion cubic feet of natural gas per year and 37.5 trillion cubic feet in annual production. Although long-range projections in the energy patch should be taken with a grain of salt, US exports would account for only 15 percent of domestic output in this scenario.
And if US natural-gas prices were to rally temporarily, the price advantage for customers in Asia and Europe would diminish, eroding demand in the international spot market.
Commentators who predict a surge in natural-gas demand from electric utilities likewise overlook the scope that power producers have to switch between coal and natural gas at their plants, depending on which thermal fuel offers the best economics.
Natural-gas consumption in the power sector spiked in 2012 after the no-show winter depressed the price of this commodity.
But electric utilities have reduced their natural-gas consumption over the past two years. In July 2014, the power sector burned about 7.8 billion cubic feet per day of natural gas less than in 2012.
The catalysts for this trend: Depressed coal prices and natural-gas prices that remained elevated after the severely cold 2013-14 winter, a situation that incentivized electric utilities to switch fuels.
In July 2014, US electricity demand fell 2.3 percent year over year because of a more than 12 percent drop in total cooling degree day. Natural-gas consumption in the power sector tumbled 7.3 percent, while coal demand dropped 1.9 percent.
Stricter regulation of carbon dioxide emissions will lead to the shutdown of as much as 50 to 60 gigawatts of coal-fired generation capacity in the US—roughly 15 percent to 20 percent of the current fleet. About 30 gigawatts could be shuttered by the end of next year.
Although the anticipated reduction in coal-fired capacity will be offset by an increased reliance on natural gas, the 1 trillion cubic feet per annum in incremental demand that’s expected to materialize by 2020 won’t offset a 4.5 trillion cubic feet jump in annual production.
In the global crude-oil market, analysts pay close attention to OPEC’s spare production capacity, or oil fields that could ramp up output quickly to offset a supply outage and rebalance the market.
Saudi Arabia controls much of this spare capacity and stepped up its output in 2011 to dampen the Libyan civil war’s effect on global oil prices.
Similarly, North America boasts a number of prolific natural-gas plays in which producers could accelerate drilling activity if prices were to climb to between $4.50 and $5 per million British thermal units.
Based on total reserves, Louisiana’s Haynesville Shale is one of the largest gas plays in the US. However, this play has fallen out of favor because it produces negligible volumes of crude oil and natural gas liquids, higher-priced hydrocarbons that help to boost economics.
This unfavorable production mix explains why drilling activity in the Haynesville Shale slumped sharply after 2008 and gas production from this field had plummeted by almost one-third from its peak.
However, the Haynesville Shale’s rig count and production levels appear to have bottomed last winter, suggesting that natural gas prices over $4.50 per million British thermal units would incentivize producers to accelerate drilling activity in the play’s core region.
Most analysts estimate that natural-gas prices of $5 per million British thermal units would enable producers to make money in the marginal portions of the Haynesville Shale.
The region already boasts sufficient pipeline and processing capacity to handle an increase in production, while its proximity to proposed export capacity on the Gulf Coast is another plus.
In short, any sustained upsurge in North American natural-gas prices would be stymied by an influx of output from the Haynesville Shale and other plays.
The current natural-gas futures curve projects that prices generally will remain below $5 per million British thermal through at least the middle of the coming decade.
Futures market expectations for gas prices are lower today than they were a year ago; the rapid build in inventories has convinced the market that significant structural changes will need to take place to tighten the supply-demand balance for more than a month or two.
Elliott and Roger on Aug. 31, 2021
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