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The U.S. gas-directed rig count has been on a steep decline, falling by 521 rigs from 934 rigs as of 10/28/2011 to 413 rigs as of 11/09/2012, based on Baker Hughes' (NYSE:BHI) survey. This represents a 56% reduction during the last twelve months. Yet, the Lower 48 dry gas production has remained virtually unchanged since last October, according to the EIA data. The seeming contradiction would appear less striking if one were to turn for explanation to a specific industry example: Chesapeake Energy (NYSE:CHK).

Chesapeake's "Rigless" Gas Production Growth

As Chesapeake has been shifting its operating focus towards oil and liquids and away from dry gas, the company's gas-directed rig count and capital allocation have markedly declined. While in February 2011 Chesapeake was operating approximately 87 rigs drilling for natural gas, currently it is running just nine, according to the company's latest presentation, and may keep its gas-directed rig count at around this low level throughout 2013. This represents almost a ten-fold contraction in the gas rig count over an eighteen month period.

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The number of active gas rigs has reflected the decline in CHK's capital allocation for gas drilling, which has shrunk from 54% of total capital in 2011 to 15% in 2012 and 12% projected for 2013, according to the company.

One would expect that such a radical curtailment by Chesapeake in gas-directed drilling should have translated by now into a noticeable decline in natural gas production volumes. Actually, Chesapeake's operating results show something drastically different. Last Friday, the company reported a record quarterly natural gas production of approximately 3.3 Bcf/d net. Gas volumes were up 10% from the second quarter and 19% from a year ago. While Chesapeake expects the third quarter to mark a peak in its gas output, this peak is being achieved full six quarters after the company's gas rig count started an accelerated decline. CHK strong production growth during the last eighteen months is particularly impressive given several asset sales and VPP monetizations that have reduced the reported production volumes.

Clearly, the production from liquids-rich gas and oil plays has contributed to the company's gas production growth. However, even excluding the associated gas volumes, production growth from shale gas plays has still been robust (as seen in the slide below) and exceeded the industry-wide dry gas production growth rate.

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(Source: Chesapeake Energy November 2012 Investor Presentation)

Chesapeake is guiding to a 7% year-on-year gas production decline in 2013 (based on the midpoints of the company-provided estimate ranges for 2012 and 2013). It is important to note that the projected decline in CHK's 2013 gas production is partially attributable to the $3.3 billion Permian assets sale which, in my estimate, will result in a negative pro forma impact of approximately 70 MMcf/d. Excluding the effect of the Permian and other divestitures in 2012, CHK's gas production in 2013 would fall by approximately 4% year-on-year. If Chesapeake achieves the higher end of its 2013 gas production guidance, on a pro forma basis the company's gas output in 2013 will be very close to its 2012 level (approximately 2.5% decline).

One more factor should be taken into account. Chesapeake has a track record of under-promising and over-delivering as it comes to gas production volumes. As recently as in February this year in their 2/21/2012 news release the company stated:

As a result of production curtailments and reduced drilling and completion activity, partially offset by growth in associated natural gas production in liquids-rich plays, Chesapeake projects that its 2012 net natural gas production will average approximately 2.65 bcf per day, a decrease of 100 mmcf per day, or 4%, compared to the company's 2011 average net natural gas production of 2.75 bcf per day.

It looks like CHK is on track for a massive beat this year relative to the February forecast, as the company's most recent 2012 guidance shows 13% year-on-year growth, and that includes the negative effect of asset sales during the year. Is it conceivable that 2013 will in fact be another year of gas production growth for Chesapeake? If history is any guide, one should not rush to rule out such a possibility.

While Chesapeake is just one specific example, the production forecast the company has provided allows us to draw some important conclusions with regard to the supply outlook for the gas industry as a whole.

How does Chesapeake's gas production profile and rig count compare to those of the U.S. gas sector?

During the last eighteen months, the decline in the number of Chesapeake's rigs drilling for natural gas has been noticeably steeper than the decline in the Baker Hughes U.S. gas-directed rig count during the same period of time. The difference is almost five-fold.

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In terms of production, Chesapeake is currently the largest U.S. producer on a gross operated basis, accounting for approximately 10% of national natural gas volumes. At the same time, Chesapeake's operated rig count classified as drilling "for gas" has declined to only about 2% of the industry's total. By comparison, in February 2011, the company was operating approximately 9% of national gas production and 10% of gas-directed rigs.

Chesapeake's natural gas production comes predominantly from recently discovered shales and, due to the super-charged growth, is dominated by wells from relatively recent vintages. As a result, the production decline rate for Chesapeake's portfolio is higher than the decline rate for the aggregate U.S. natural gas production base (which is characterized by a larger component of low-decline "legacy" production). With the above comparisons in mind, it should not be surprising that the U.S. natural gas production has shown no signs of decline throughout 2012, even though the industry gas-directed rig count has contracted more than two-fold.

Given that Chesapeake's gas production is projected to experience only a minor contraction in 2013, despite its current gas-directed drilling being five times lower than the average for the sector, the natural question springs to mind: should the industry brace itself for another challenging year of persistent oversupply and low natural gas prices? To answer this question, it is instructive to look into the factors that explain the relative stability of Chesapeake's gas production going into 2013.

Gas production growth from Chesapeake's liquids plays to accelerate in 2013

A closer play-by-play analysis highlights that the "gas by-product" from CHK's liquids plays is so abundant that it offsets a larger part of the steep decline in the company's massive shale gas portfolio. In fact, of the nine oil and liquids plays highlighted in Chesapeake's Q3 press release, five produce just as much natural gas as they produce oil and liquids on a Btu equivalent basis, and two additional plays produce 38% natural gas. Only two plays of the nine, the Eagle Ford and PRB Niobrara, have natural gas as a lesser part of the production stream (26% and 18%, respectively).

The following table summarizes CHK's current rig count and estimated production mix by play (a more detailed discussion of CHK's current drilling activity in each of the plays is presented at the end of this note).

I estimate that on a gas-equivalent basis, the 80 rigs that CHK is currently operating in its liquids-rich and oil plays would be equal to approximately 25-30 gas-directed rigs operating in a play like the Barnett or the Haynesville. In other words, dry gas contribution from CHK's ongoing drilling in its liquids plays may be as much as three times greater than from the ongoing drilling activity in its gas shale plays.

Well backlog = "rigless" production

Well backlog is another factor that needs to be taken in consideration. CHK's inventory of wells that have been drilled but are not yet producing is particularly high in the Marcellus, Eagle Ford and Utica plays. Across all CHK's plays, I estimate the company's "above-normal" inventory at approximately 400-500 wells. Assuming that 300 inventory wells are absorbed by the end of 2013, one could think of it as an additional 8-10 gas-directed "equivalent rigs" deployed throughout the year (I take into account play-specific natural gas yields).

More than 50% of Chesapeake's active rig fleet is effectively drilling for natural gas

As a result, Chesapeake's effective gas-equivalent rig count currently stands at approximately 42-49 rigs (more than half of the 89-rig total) and is drilling to offset natural declines on the estimated 0.7 Bcf/d (gross operated) of low-decline legacy conventional production and estimated 5.5 Bcf/d (gross operated) of high-decline shale production. Assuming a 15% annual decline on the legacy volumes and 35%-40% annual decline on the shale volumes, the ongoing drilling program will need to offset approximately 2.0-2.3 Bcf/d of total production declines.

In my estimate, the current level of CHK's drilling activity may fall slightly short of fully offsetting such a massive base decline in dry gas output (although drilling efficiency gains and pace of infrastructure development in some of CHK's new plays such as Utica or PRB Niobrara may surprise to the upside). While the above analysis suggests a moderate contraction in CHK's gas production in 2013, essentially matching the company's forecast, a flat production or even moderate growth are also possible assuming accelerated infrastructure ramp up in the Marcellus and Utica and taking into consideration the possibility that the company's gas shale production has somewhat lower annual declines than broadly believed.

Implications for U.S. Gas industry

The Chesapeake example highlights the magnitude of the associated gas production growth as a share of the national natural gas supply. While the importance of this source of natural gas has been mentioned ad nauseum in industry research reports, its full scale appears often under-estimated. For instance, in its latest presentation, Encana (NYSE:ECA) estimates that the growth in North American gas production from liquids-rich and oil plays will be 1.7 Bcf/d in 2013. As a result, "dry natural gas production is expected to continue to decline and will only partially be offset by increases in liquids rich gas and associated gas production." Based on my analysis, Chesapeake alone may be able to deliver over 40% of the gas growth volumes from oil and liquids plays that Encana is projecting for 2013 while CHK's liquids rig count is less than 10% of the industry's. Encana's estimate likely understates the contribution from liquids-rich and oil plays in 2013 by more than two times.

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(Source: Encana Corporation November 2012 Analyst Presentation)

The above analysis framework can be applied to the U.S. natural gas industry as a whole. I assume that approximately 50% of the existing U.S. Lower 48 production of 64 Bcf/d is characterized by relatively low (c. 15%) declines while the other half is declining at approximately 30%-35% p.a. rate. I also assume that current industry-wide oil-directed rig count of 1,389 rigs, per Baker Hughes, represents an equivalent of approximately 250-300 rigs drilling for natural gas. I further assume that the drawdown from the industry-wide well backlog in 2013 will represent an equivalent of approximately 50-60 gas-directed rigs. This brings the total "effective gas equivalent" rig count to approximately 700-750 rigs that will be working to offset the total annual decline of approximately 14.5-16 Bcf/d.

Even assuming that Chesapeake's well productivity is higher than the industry's average due to the company's "core of the core" asset quality, the math still suggests that Chesapeake's dry gas production should lag the industry by several percentage points in 2013. Taking Chesapeake's 2013 gas production growth forecast as a base, the U.S. gas volumes may show moderate growth in 2013 even at today's seemingly low gas-directed rig count. The "gas-rich" content of the fast-growing "liquids-rich" plays may in fact surprise to the upside in 2013 and successfully fill the void created by the decline in dry gas drilling.

CHK: Summary of current oil & liquids drilling activity

  • Eagle Ford Shale. Chesapeake is currently operating 23 rigs in the play, down from a peak of 34 rigs in April 2012 and plans to exit the year at 22 rigs. The company is currently on pace to have essentially all of its core and Tier 1 Eagle Ford acreage held by production by the 2013 fourth quarter. Approximately 68% of total Eagle Ford production during Q3 2012 was oil, 14% was NGL and 18% was natural gas. As of September 30, 2012, Chesapeake had approximately 233 Eagle Ford wells drilled, but not yet producing, that were in various stages of completion and/or waiting on pipeline connection.
  • Utica Shale. Chesapeake is currently operating 13 rigs in the Utica play focusing on the core wet gas window in eastern Ohio. As of September 30, 2012, Chesapeake has drilled a total of 134 wells in the Utica play, which include 32 producing wells and 102 additional wells that are in various stages of completion or waiting on pipeline connection. Production from the Utica play is growing only moderately at this time because of the time and capital needed to build out gas processing and pipeline takeaway infrastructure. The company expects a much larger contribution to production growth from the Utica in 2013 and beyond as midstream constraints are reduced. Based on IP test results for three recent wells presented in Chesapeake's 3Q press release, the production mix was 49% gas, 32% oil and 18% NGLs.
  • Marcellus Shale - South. Chesapeake is currently drilling with three operated rigs in the southern wet gas portion of the Marcellus and anticipates maintaining that level of activity for the remainder of 2012. During the 2012 third quarter, Chesapeake's average daily net production in the southern wet gas portion of the play was approximately 125 MMcfe/d (206 MMcfe/d gross operated). Based on IP test results for three recent wells presented in Chesapeake's 3Q press release, the production mix was 56% gas, 17% oil and 27% NGLs.
  • Mississippi Lime. Chesapeake is currently operating nine rigs in the Mississippi Lime play. Production for the 2012 third quarter averaged approximately 25,000 Boe/d (30,100 Boe/d gross operated), up 211% year over year and 25% sequentially. Approximately 41% of total Mississippi Lime production during the 2012 third quarter was oil, 10% was NGLs and 49% was natural gas. As of September 30, 2012, Chesapeake had 227 producing wells in the Mississippi Lime play and 55 wells drilled, but not yet producing.
  • Powder River Basin Niobrara. Chesapeake is currently operating nine rigs in the play and plans to exit 2012 with 10 operated rigs. The company has drilled 55 horizontal wells in the play to date, and is focusing on a recently identified liquids-rich high-pressured core area. Based on IP test results for three recent wells presented in Chesapeake's 3Q press release, the production mix was 26% gas, 54% oil and 20% NGLs. Production from the Powder River Basin Niobrara play is just beginning to ramp up because of the time and capital needed to build out gas processing and pipeline takeaway infrastructure. The company expects a much larger contribution to production growth from the Niobrara in 2013 and beyond as midstream constraints are reduced.
  • Cleveland and Tonkawa Tight Sands. The company is currently operating 12 rigs in the two plays. Production from both plays for the 2012 third quarter averaged 24,100 boe per day (31,700 gross operated boe per day), up 75% year over year and 13% sequentially. Approximately 45% of total Cleveland and Tonkawa production during the quarter was oil, 17% was NGL and 38% was natural gas.
  • Granite Wash and Hogshooter Tight Sands. The company is currently operating 10 rigs in the two plays. Production for the 2012 third quarter averaged 47,750 Boe/d (95,800 Boe/d gross operated), up 2% sequentially. Approximately 28% of total Granite Wash and Hogshooter production during the quarter was oil, 22% was NGL and 50% was natural gas.

CHK: Summary of current gas shale drilling activity

  • Marcellus Shale - North. Chesapeake has reduced its operated rig count to five rigs in the northern dry gas portion of the Marcellus and anticipates maintaining that level of activity for the remainder of 2012.During the 2012 third quarter, Chesapeake's average daily net production in the northern dry gas portion of the Marcellus play was 540 MMcfe/d (1,229 MMcfe/d gross operated), an increase of 159% year over year and 9% sequentially.
  • Haynesville Shale and Barnett Shale. Chesapeake is currently operating four rigs in the two plays, two rigs in each.

A more detailed discussion of various factors that impact the U.S. natural gas supply is provided in the earlier articles:

http://seekingalpha.com/article/980461-natural-gas-the-tricky-craft-of-counting-drilling-rigs-part-ii

http://seekingalpha.com/article/954971-natural-gas-the-tricky-craft-of-counting-drilling-rigs-part-i

http://seekingalpha.com/article/976831-natural-gas-supply-unchanged-in-august-according-to-latest-data

http://seekingalpha.com/article/914291-how-many-gas-directed-rigs-do-we-really-need-part-i

This discussion is fundamentally relevant for natural gas (NYSEARCA:UNG) and the natural gas producer stocks. My natural gas producer index includes:

  • Chesapeake Energy
  • EnCana Corporation
  • Devon Energy (NYSE:DVN)
  • Southwestern Energy (NYSE:SWN)
  • Ultra Petroleum (NYSE:UPL)
  • EXCO Resources (NYSE:XCO)
  • WPX Energy (NYSE:WPX)
  • Cabot Oil & Gas (NYSE:COG)
  • Range Resources (NYSE:RRC)
  • QEP Resources (NYSE:QEP)
  • Quicksilver Resources (NYSE:KWK)
  • Forest Oil (NYSE:FST)
  • Bill Barrett (NYSE:BBG)

Disclaimer: This article is not an investment recommendation and does not provide a view on the value or price direction of any security. Any analysis presented in this article is illustrative in nature, is based on an incomplete set of information and has limitations to its accuracy, and is not meant to be relied upon for investment decisions. Please consult a qualified investment advisor.

Source: Chesapeake Energy And The Rig Count Conundrum