Oil and Gas Reserves (Unaudited): |
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Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Oil and Gas Reserves (Unaudited) | OIL AND GAS RESERVES (Unaudited) BHEP has operating and non-operating interests in 1,006 gross developed oil and gas wells in 10 states and holds leases on approximately 236,545 net acres. Costs Incurred Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands):
Reserves The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2015, 2014 and 2013 and a reconciliation of the changes between these dates. These estimates are based on reserve reports by CG&A. Such reserve estimates are inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.
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Reserve additions for 2015 totaled 27.0 Bcfe, replacing 209% of annual production. Reserve additions resulted from drilling in the Piceance and Powder River Basins. Drilling in the Piceance for Mancos Shale accounted for 25.9 Bcfe and Powder River Basin drilling accounted for 1.2 Bcfe. Capital spending in 2015 was primarily for drilling and completion activities in the Piceance Basin. Future capital spending rates will be dependent on product prices, processing availability and support of our Cost of Service Gas program. In 2015, we had negative revisions of (10.1 Bcfe) to previous reserve estimates. Most of the negative revision was the result of lower equivalent prices of oil, liquids and gas received at the wellhead of (20.1 Bcfe), partially offset by improved wellhead performance of 3.6 Bcfe and non-consent interests we assumed related to new wells drilled in the southern Piceance Basin of 6.9 Bcfe. We changed our process for reporting natural gas in 2014 to separate NGL from wet gas steam. This change was from increased NGL recovery from the Powder River Finn Field and the Piceance wells. 2013 NGL was reported wet. The industry standard multiplication of liquid production by 6 to arrive at the equivalent gas volume results in higher overall equivalent volumes. This is offset by negative revisions of dry natural gas resulting from higher shrink factors during processing of the wet gas to dry gas and NGLs. We will continue to report oil, natural gas and NGL volumes in the future. SEC regulations require that proved undeveloped (PUD) locations meet the test of being developed within five years of being categorized as proved. In 2015, we had no PUD locations that were required to be dropped because of the five year rule. Companies are required to include a narrative disclosure of the total quantity of PUD locations at year end, any material changes in PUD locations during the year and investment and progress made in converting the PUD locations to proved developed during the year.
Capitalized Costs Following is information concerning capitalized costs for the years ended December 31 (in thousands):
Results of Operations Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands):
Unproved Properties Unproved properties not subject to amortization at December 31, 2015, relate primarily to the four wells drilled in the Mancos formation of the Piceance Basin, for which completions were deferred. Unproved properties not subject to amortization at December 31, 2014 and 2013 consisted mainly of exploration costs on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $1.0 million, $1.0 million and $1.1 million of interest during 2015, 2014 and 2013, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2015 and notes the year in which the associated costs were incurred (in thousands):
Standardized Measure of Discounted Future Net Cash Flows Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended December 31 (in thousands):
The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands):
Changes in the standardized measure from “revisions of previous quantity estimates” are driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications are generally made at the well level each year through the reserve review process. These production profile modifications are based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments are reviewed each year and are often modified in response to current market conditions for items such as permitting and service availability. |