Drillers: Productivity Boom Transcends Gas Prices

Exxon Mobil (XOM) and Chesapeake Energy (CHK), two of the largest U.S. producer of natural gas have admitted that unlocking gas trapped in shale-rock formation and selling it for $3.50 per million British thermal units (MMBtu) is proving more costly, on balance, than extracting $90 per barrel oil. Not surprisingly, the companies are shifting drilling toward resources with greater potential for oil and natural-gas liquids. Nonetheless, investors willing to stick with more junior, natural gas plays could be handsomely rewarded in coming years, as drilling efficiency improvements are dramatically lowering breakeven prices – leading to improvements in operating margins.

Henry Hub Natural Gas Spot Price Chart

Henry Hub Natural Gas Spot Price data by YCharts

Natural gas working inventories ended February 2013 at an estimated 2.08 trillion cubic feet (Tcf), about 0.36 Tcf below the level at the same time a year ago, but still 0.27 Tcf greater than the 5-year average (2008-12). The U.S. Energy Information Association expects the Henry Hub natural gas spot price, which averaged $2.75 MMBtu in 2012, will price, on average, at $3.41 per MMBtu in 2013 and $3.63 per MMBtu in 2014.

Lucas Pipes, an analyst at Brean Murray, Carret & Co. opines that rising demand from utilities switching from coal to natural gas to generate electricity helped lift natural gas prices off their 2012 lows. However, in line with EIA forecasts, too much supply combined with more competitive coal prices are expected to mute any meaningful rise in natural gas prices through 2014.

Is the price of natural gas too cheap to drill profitably?

There is no industry consensus regarding how best to measure and define what constitutes the “total cost” to produce natural gas: the “all-in-costs” of finding, developing, and producing hydrocarbons. For comparative purposes, this article defines the all-in-costs as the sum of finding and development costs (F&D), such as lease operating expenses (LOE) and gathering fees, plus lifting costs, production taxes, depreciation, and interest charges.

Additionally, because exploration companies – like Exxon Mobil – do not typically break down cost allocations between oil and gas drilling activities, only companies whose proven reserves are mostly natural gas were reviewed for inclusion in this article.

The cost of capital required to break-even on drilling varies from one project to another, depending on shale geology, subsurface pressures, and infrastructure status (access to pipeline and gathering services). For example, prices currently average about $215 per drilled foot in the San Juan Basin of New Mexico, compared with $287 per drilled foot in the nearby Permian Basin section of West Texas. Against this backdrop, even with natural gas prices mired in a multi-year slump, some North American land-based drillers are favorably positioned to outperform their peers and show improvements in return on invested capital due to prudent investments in promising onshore assets.

UPL Return on Invested Capital Chart

UPL Return on Invested Capital data by YCharts

Ultra Petroleum (UPL), with all-in-costs of $3.00 per Mcfe, is one of the industry’s lowest cost producers. The Canadian-based company has maintained this enviable cost structure by leveraging its development activities in the Rockies: UPL owns interests in approximately 49,000 (net) acres of the Pinedale Field in Wyoming. Though generally unknown to most investors, it is one of the most prolific and economic natural gas plays on the continent. According to Morgan Stanley (MS) the average well drilled at the Pinedale Field will earn a 10% pretax rate of return with prices as low as $2.22 per MMBtu.

In 2012, Pinedale contributed 74% of the company’s 249.3 Bcf in annual production. Technological innovations in mud motors, diamond-tipped bits and faster horsepower motors (rpms) have helped improve completion efficiency on its operating wells, as measured by spud to total depth: During 2012, the company averaged just 11.5 days to drill a well, as compared with 20 days back in 2009.

In addition, the company is saving on capital expenditures by increasing the use of innovative “walking drill” rigs. Succinctly, these are rigs capable of moving between well sites on hydraulic feet without having to be dissembled. During 2012, rig to rig-release (total days per well) averaged 14.7 days in the fourth quarter, compared with 24 days in 2009. On average, total well costs have declined 8% to $4.6 million in the last few years.

UPL’s horizontal drilling projects at its emerging Marcellus Shale development in Pennsylvania (20% of annual production) are showing similar cost savings: Year-on-year well costs in Clinton-Lycoming counties declined almost 20% last year to just under $6.0 million per well.

Improved rig mobility and extended lateral fracturing (up to 13 stages) has yielded significant efficiency gains at Range Resources (RRC) too: Proved reserves have more than doubled since 2008, growing from 2.7 Tcf to 6.5 Tcf at year-ending 2012 – with all-in-costs (including reserve replacement) declining 32.5% in the same time period to $3.00 per Mcfe.

The Fort Worth, Texas based E&P, on average, can drill and complete a 3,000-foot lateral (horizontal) well in southwestern Pennsylvania for under $4.5 million, with forecasted ultimate recovery of 7.5 Bcf. Even with $3.00 gas, the projected rate of return is 23%.

EQT Corporation (EQT) is a natural gas company with a major presence in the Appalachian Basin. Though the Pittsburgh-based integrated energy company owns 3.5 million gross acres, including approximately 540,000 gross acres in the Marcellus play, management readily acknowledges that conventional vertical drilling techniques are no longer able to recover shale gas reserves effectively or economically. Horizontal drilling technologies and hydraulic fracturing allows EQT to recover much more natural gas from fewer wells. EQT spud 135 horizontal wells in 2012, increasing total proved reserves by 12% to more than 6.0 Tcf.

Driven by horizontal drilling in the Marcellus shale – 127 wells with an average length of pay equaling 5,485 feet – production sales volumes last year increased 33% to a record of 258.5 Bcf. Approximately 58% of EQT's 2012 production sales volumes came from Marcellus wells, whose volumes increased by 85% over 2011.

EQT has readily embraced newer techniques ideally suited for Appalachian terrain, allowing the driller to fracture the horizontal well bore in multiple stages all along its 5,000 feet of length – as opposed to mono-stage fracturing used in a vertical well bore. Ergo, it takes fewer wells to drill, fracture and produce the area of the gas-bearing formation than vertical well spuds: estimates are that 6 to 8 horizontal wells drilled from one pad (“multi-pad”) can take the place of 20 to 24 vertical wells, each on their own well-pad.

Increases in production, gathering and transmission volumes more than offset lower commodity prices, giving EQT the distinction of being the lowest all-in-cost producer in 2012 (with per Mcfe costs totaling less than $3.00, according to Wells Fargo (WFC) data.

In 2012, the company also commissioned two Marcellus drilling rigs powered by clean burning, liquefied natural gas, and expects to retrofit four additional rigs to displace diesel in 2013. EQT estimates a fuel cost savings of approximately $400,000 annually per converted rig, as well as an expected 20% to 30% reduction in carbon dioxide emissions, which should help to minimize the company's overall environmental footprint.

An E&P strategy built on organic growth through the drill bit need not be dependent just on drilling efficiency gains to add significant reserves at lower costs. Yes, technological innovations have helped Southwestern Energy (SWN) drive drilling days to completion down from 17.5 days in 2007 to just 6.7 days, on average, in 2012. Additionally, annual production grew from 113 Bcf to 565 Bcf in 2012 – with F&D and lifting costs falling from $2.70 per Mcfe to $2.08 per Mcfe. However, the company has benefited from first-mover advantages too: Most of its 913,502 (net) acres in the prolific Fayetteville Shale were acquired before this natural gas play became highly competitive. These assets, which hold 75% of proved reserves, cost on average just $313 per acre!

Despite their proven abilities to lower total E&P costs, should natural gas prices drop below $3.00 again, even the better-managed natural gas companies mentioned in this article can only drill wells for so long before the economics of the market adversely impact their financial health. The following YChart can serve as a practical guide in helping investors gauge each company’s ability to weather a reversal in predicted natural gas prices:

UPL Financial Debt to EBITDA Chart

UPL Financial Debt to EBITDA data by YCharts

David J. Phillips, a contributing editor at YCharts, is a former equity analyst. His journalism has appeared in Bloomberg BusinessWeek, Forbes, and Kiplinger's Personal Finance. From 2008 to 2011, David was a reporter for CBS News Interactive. He can be reached at editor@ycharts.com.

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