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In January 2014, Encana’s corporate guidance restated its commitment to developing its liquids-rich assets, allocating a record $1.875 billion toward developing five core growth areas (the Denver-Julesburg and San Juan basins, and the Duvernay, Montney and Tuscaloosa Marine [TMS] shales). Of the capital directed at these areas, a combined $450 million (24%) was earmarked for two of North America’s most promising emerging liquids plays. Encana anticipates investing $300 million in the Duvernay, which is slated to contribute liquids production this year, and $150 million in the TMS, which is undergoing delineation.
Despite differences in location and geologic age, the Duvernay and TMS share geological characteristics that have been demonstrated to be favorable for unconventional oil and gas production. The Upper Cretaceous TMS and the Upper Devonian Duvernay were both deposited in a marine environment and exhibit high overpressuring in the reservoir. The TMS is found at depths ranging from 9,000 to 14,000 feet, while the Duvernay sits between 7,500 and 16,400 feet. The average thickness of the TMS is between 150 and 325 feet with a total organic carbon (TOC) content range of 2% to 4%. The Duvernay mirrors these characteristics with an average thickness between 30 and 200 feet and a TOC of approximately 3.4%.
Encana holds vast acreage positions in both the Duvernay (253,000 net acres) and the TMS (302,000 net acres) that are expected to provide it with more than 1,300 potential well locations per play, based on moderate spacing assumptions. The challenge Encana faces in both regions results from another similarity: high drilling and completion costs. Recently, the operator reported capital expenditure costs in the Duvernay of between $12 and $18 million per well, not dissimilar to the relative range seen in the TMS at $12- to $14 million per well. These high costs are a result of the respective depths of each play and a lack of realized efficiencies due to each play’s emerging status.
We constructed composite type curves based on limited reported activity from Encana’s wells to demonstrate the effect of these high drilling and completion costs on the economic viability of each play. For the Duvernay, we ascribed the average peak production rate from existing Encana wells to an Eagle Ford condensate window type curve that we believe exhibits similar characteristics.
Generally speaking, natural gas wells enjoy higher productivity and estimated ultimate recoveries (EURs) than most oil wells because of the presence of gas and its higher-API-gravity liquids. Indeed, when compared with the TMS type curve, the Duvernay composite curve demonstrates a significantly higher initial production rate and EUR. A more subtle difference between each type curve—characteristic of shale gas vs. shale oil wells—is the steeper profile of the Duvernay type curve vs. the TMS’ more gradual decline.
When each composite curve is paired with Encana’s target well cost ($12 million) and a benchmark price deck ($80 oil, $37.80 natural gas liquids, $4 natural gas) the Duvernay type curve generates a net present value of $3.6 million, while the TMS type curve generates a net present value of -$2.3 million. At the target well cost (which is significantly lower than currently reported), further improvements in productivity and additional cost reductions will be necessary for the TMS to become profitable. However, the yield from the Duvernay curve suggests that further cost reductions alone (which the operator aims to achieve from pad drilling) could allow the play to contribute to Encana’s bottom line.
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