Economic appraisal of shale gas resources, an example from the Horn River shale gas play, Canada

Abstract

Development of unconventional shale gas resources involves intensive capital investment accompanying large commercial production uncertainties. Economic appraisal, bringing together multidisciplinary project data and information and providing likely economic outcomes for various development scenarios, forms the core of business decision-making. This paper uses a discounted cash flow (DCF) model to evaluate the economic outcome of shale gas development in the Horn River Basin, northeastern British Columbia, Canada. Through numerical examples, this study demonstrates that the use of a single average decline curve for the whole shale gas play is the equivalent of the results from a random drilling process. Business decision based on a DCF model using a single decline curve could be vulnerable to drastic changes of shale gas productivity across the play region. A random drilling model takes those drastic changes in well estimated ultimate recovery (EUR) and decline rates into account in the economic appraisal, providing more information useful for business decisions. Assuming a natural gas well-head price of $4/MCF and using a 10 % discount rate, the results from this study suggest that a random drilling strategy (e.g., one that does not regard well EURs), could lead to a negative net present value (NPV); whereas a drilling sequence that gives priority to developing those wells with larger EURs earlier in the drilling history could result in a positive NPV with various payback time and internal rate of return (IRR). Under a random drilling assumption, the breakeven price is $4.2/MCF with more than 10 years of payout time. In contrast, if the drilling order is strictly proportional to well EURs, the result is a much better economic outcome with a breakeven price below the assumed well-head price accompanied by a higher IRR.

Optimization of shale gas reservoir evaluation and assessment of shale gas resources in the Oriente Basin in Ecuador

“…Various exploration stages, precision requirements, and available data determine the appropriate evaluation methods. Different techniques require varying parameters, and the methods for obtaining these parameters vary; the final estimation results also differ (Chen et al 2012(Chen et al , 2015. To select a method, researchers should refer to the exploration stage, geological features, and data conditions of the evaluation area.…”

The fiscal regime for UK shale gas: Analysing the impacts of pad allowance on shale gas investments

“…As shown in Table 7, at a flow rate of 3 mmcfd per well (case two), equivalent to an average yearly production of 7.4 bcf per well, the results are unfavourable with a pre-tax NPV of negative $1,189 million, an IRR of 4% and a break-even price of $6.2 per mmbtu at 10% cost of capital; this is $4.2/ Mcf for Canada (Chen et. al 2015).…”

Economic Feasibility Analysis of Shale Gas Extraction from UK’s Carboniferous Bowland-Hodder Shale Unit

“…For example, Agarwal [12] carried economic analysis on five major US shale gas plays using a discounted cash flow (DCF) method to compare their economic outcomes. Similarly, Ikonnikova et al [13] assessed the profitability of Fayetteville shale play while Kaiser [14] examined the economic viability of Haynesville shale play and economic modeling for shale gas development in Horn River Basin, Canada is conducted by Chen et al [15] where each of mentioned study uses DCF model to economically analyze the play. A recent study [16] estimates the breakeven prices for shale gas extraction in continental Europe, however, omits UK from analysis.…”