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This note continues the series of articles discussing emerging horizontal oil & gas plays and focuses on the shallow Marmaton formation in the Oklahoma and Texas panhandles. Other recent articles include:


In its Q2 2012 Operating update, Cabot Oil & Gas (COG) reported strong drilling results in its new Marmaton horizontal oil play in Beaver County of Oklahoma. Cabot's last five operated wells delivered IP rates from 650 Boepd to 2,000 Boepd. One well produced at a 30-day average rate of 1,570 Boepd (84% oil) and is the second Marmaton well reported by Cabot this year that has achieved full payout in less than two months. Cabot's well costs in the second quarter ranged from $2.9 to $3.4 million. Despite the wide variance, these IP rates measure up to initial flows in some of the most contested horizontal oil plays while the well cost ranks low by comparison.

The active leasing in Beaver County and continuously improving operating results reported by Cabot, Unit Corporation (UNT), and QEP Resources (QEP), the three operators focused on the Marmaton, warrant a fresh look at this "under the radar" play. This note provides a brief overview of the Marmaton, summarizes the drilling activity to date, and discusses the play's key challenges, including the dependency on natural fracturing systems and rapid production declines. The note also analyzes the play's economics and potential value impact to Cabot stock which can be meaningful.

The Shallow Marmaton - An Overview

The oil bearing Marmaton formation in Beaver County has been the target of vertical drilling for several decades with almost 400 vertical wells completed to date. The flow rates from vertical wells have been particularly strong in the areas characterized by extensive natural fracturing. The formation produces high quality (38 degree API) crude and moderate amounts of NGLs and natural gas. Well costs are relatively low as the producing zone has a typical depth of about 6,000 ft. While Marmaton's oil potential in this area has been well known, the approach using the horizontal frac technology is relatively new.

Map of Oklahoma and Texas Panhandles Marmaton Play
(high drilling activity area shown in circle)

Source: Unit Corporation June 2012 slide presentation.

The shallow Marmaton in Beaver County should not be confused with its more famous brother, the deep Marmaton (also known as the "Marmaton Wash"), a series of arkosic sandstones with depths of about 13,000 ft. The Marmaton Wash has been frequently mentioned as the target of the horizontal gas and condensate drilling mainly in Wheeler County, TX and Washita County, OK. The depth is not the only difference between the two plays. Geologically, the Marmaton Wash is a sandstone while the Beaver County Marmaton is a fractured limestone carbonate.

Carbonate deposits are characterized by finer grained rock than sandstones. As a result, the low porosity and permeability can make the hydrocarbons extraction from the body of the rock problematic. Most of the oil is found in the fracture porosity typical of the carbonates. Fracture porosity may have developed due to a variety of factors such as the wash out by water, erosion, changes in the rock structure, and tectonic shifts. Such fractures create storage space as well as conductivity paths for oil within the rock body which itself has very low porosity and permeability.

In the Marmaton, these fractures often occur in discrete "swarms" (or clusters) separated by domains that either lack fractures or have only rare fractures. These scarcely fractured domains may be as much as several hundred feet wide. Within swarms, fractures are likely to be well interconnected along the length of the swarm but poorly interconnected across the width of the swarm.

This geological structure makes the Marmaton a logical candidate for a horizontal frac development. Fracture stimulation is called upon to create additional conductivity paths around the wellbore to tap into the oil-filled natural fracture systems that otherwise would stay isolated from the well by the rock body. A multistage completion allows to reach a long section of the rock with one well.

The Marmaton Drilling Activity Is Accelerating

At least three operators have been actively pursuing this play over the past eighteen months, including Unit, Cabot and QEP Resources. Apache Corporation (APA) also has leaseholds in the area and has been rumored to be adding to its position.

Unit Corporation. Unit entered the play in June 2010 when it acquired 45,000 net leasehold acres and 10 producing oil wells in Beaver County for $74 million in cash. The transaction implied, in my estimate, a purchase price of approximately $1,000 per undeveloped acre (PDP reserves associated with the 10 wells was 762,000 Boe, 67% oil, 20% NGLs and 13% natural gas). Since then, Unit has been the most active operator in the play having drilled, as of April this year, over 60 horizontal wells and accumulated over 102,000 net acres with high working interest. The company has been running two rigs in the area and has budgeted $71 million for 30-35 gross Marmaton wells in 2012.

Unit's well results have varied widely. The initial 30-day production rate for the 34 wells drilled in 2011 ranged from 20 Boepd to 930 Boepd with an average rate of 308 Boepd. The competed well cost was $2.7 million (4,000 ft lateral and 16-stage frac). Unit estimates the average ultimate recovery (EUR) for a Marmaton horizontal to be 130 MBoe comprised of approximately 78% oil, 14% NGLs and 8% natural gas.

Cabot Oil & Gas. Cabot has been actively leasing in the play since it drilled its first operated Marmaton horizontal in early 2011 which flowed with a 24-hour IP rate of 646 Boepd (92% oil) from a 10-stage completion in a 4,000 ft lateral. At that time, Cabot commented: "Clearly a 10-stage completed well with initial production competitive with the Eagle Ford play and at a lower cost is an attractive place to allocate capital." To date, Cabot has accumulated over 61,000 net acres in the Marmaton, mostly in Beaver County and the adjacent Ochiltree County of Texas, and is continuing adding to its position. After participating in seven non-operated wells throughout 2011, Cabot committed one rig to the play late in the year. The company plans to bring in another rig in the third quarter 2012 and has guided that it is considering a three-rig program in 2013.

Similar to Unit's results, Cabot's wells have shown a wide variability of flow rates. In the first quarter 2012, Cabot reported average IP rates of 705 Boepd (24-hour) and 420 Boepd (30-day) for its operated wells and 532 Boepd (24-hour) and 330 Boepd (30-day) for non-operated wells. One well reached a production level of 1,470 Boepd (87% oil) and produced 50,000 Boe in 50 days. In the second quarter, Cabot's last five operated wells have delivered initial production rates from 650 Boepd to 2,000 Boepd. One well had a 30-day averaged rate of 1,570 Boepd (87% oil). The well cost ranged from $2.9 to $3.4 million during the latest quarter.

QEP Resources. QEP entered the play in 2011 and had over 31,000 net acres under lease as of November 2011 (last reported). Through the end of the first quarter 2012, QEP has drilled 5 operated Marmaton wells and participated as a non-operator in several others. The company reported the initial 30-day average rate for its 2011 wells, operated and non-operated, of approximately 360 Boepd, which is in line with Unit's and Cabot's results. QEP's notable well, Bobbitt Trust 3-13H, has reached a peak production rate of 1,063 Boepd from a 4,508 ft lateral.

Drilling Results Depend on the Presence of Natural Fracturing Systems

The extent of natural fracturing around the wellbore appears to be the biggest geological factor that drives the divergence between very strong wells and poor wells. This makes the outcome of a specific well hard to predict unless it is located in a close proximity of other wells and a good understanding of the local fracture systems exists. Therefore, high variability of results is likely to prevail at least through the play's delineation phase.

As the development of the play progresses, operators should get a better ability to map the fracturing systems and choose drilling locations and well design accordingly. On the technology side, operators are continuing to improve their completion methods. For example, Cabot mentioned a well logging program they have implemented which is focused on mapping local natural fracture "swarms" and choosing optimal positions for the packers during the completion to achieve better isolation of the frac stages.

Production Profile Is Characterized by Steep Declines

The other challenge is the steep initial production declines that have been observed in the Marmaton. Within a year, a typical well will produce at only 20% of its initial peak rate. Just like IP rates, the decline rates vary from well to well. In fact, the 24-hour IP rate is not the most reliable measure of well performance in the Marmaton. A longer production history is needed to draw better estimates of ultimate reserve recoveries.

QEP has been applying the following type curve for Marmaton horizontals:

  • IP: 760 Boepd
  • b factor: 1.0
  • Initial (effective annual) decline rate: 80%
  • Terminal decline: 10% exponential

This type curve results in an EUR of 135 Mboe per well with a production profile strongly skewed towards the front end. As much as 50% of total recoverable reserve is produced during the first nine months.

Costs and EURs

The low well costs, high IPs and strong crude yields result in very robust economics in the Marmaton in spite of the steep production decline curve. Unit and QEP estimate EURs for a typical Marmaton well at 130 Boe and 135 Boe, respectively (Cabot has not provided an estimate). Costs have ranged from $2.7 million to $3.5 million. This translates into a typical IRR in the 50% range at $85 per barrel WTI. The progression of drilling reports shows the general tendency of increasing IP rates and declining costs (as would be natural to expect). New IP records are being set every quarter, and some of the wells show less steep initial declines. This indicates that there is a substantial upside to the IRR as the play matures.

Extended laterals will be one of the tools driving the costs down. Unit drilled its first 9,000 ft extended lateral in this play during the first quarter of 2012 with a pre-drill estimated cost of $4.2 million. Cabot is planning their first extended lateral in the third quarter.

How Big Is the Marmaton Play?

Operators' reports suggest that an area of over 1,000 square miles is likely to be prospective for the Marmaton in Beaver County, OK and Ochiltree and Lipscomb Counties, TX. Assuming, for the purpose of illustration, that only 50% of the prospective area will ultimately prove to be economically compelling for development, this would yield as many as 2,000 drilling locations (assuming 160 acre spacing). Four operators with a three-rig program each can develop the entire play in less than eight years, including assessment drilling in the portions of the play that will end up less productive and will not be developed. This leads me to the estimated aggregate net present value for the play of approximately $4.0 billion after a full development. In my calculation, I assume a 25% improvement to the current 130 Boe EUR estimate partially offset by the negative impact of the infill drilling (10% decrease). I also assume a 20% well cost reduction due to extended laterals and pad drilling. The figure would be higher if additional well productivity gains can be realized over time (due to a better fracture mapping, optimized completions, ability to diagnose low productivity areas, etc.).

While this play is relatively small in magnitude, it certainly already beats many bigger ones in profitability. While an average well has estimated IRR in the 50% range, the best wells' IRR can exceed 300%.

Potential Implications for Cabot Stock

From the stock valuation perspective, the Marmaton play can be meaningful to both Cabot and Unit, the two operators who have shown the greatest commitment to the play so far. The important question, what is the upper end of the potential value range for this business to Cabot in the long term? Assuming COG continues to build operating momentum and ultimately takes, for the purpose of illustration, a 25% market share in the play, the NPV to be ultimately realized could be high as $1 billion, based on the discussion above. Given the accelerated development pace, Cabot may achieve a point where there is some preliminary visibility of this project's final outcome already in a year or two from now, the moment when the expected value will gradually begin being reflected in the stock price.

Developments to Watch

· Delineation results defining the boundaries and "sweet spots" of the play.

· Leasing/acquisition activity in the area and changes in the rig count.

· IP rate trends quarter to quarter.

· Decline profiles for the wells of older vintages to validate estimated EURs (upward revisions are likely).

· Reserve bookings at the end of the year.

Source: Cabot Oil & Gas: Marmaton Initiative Is Beginning To Pay Off