Note 13 – Supplemental Information on Oil and Natural Gas Properties (Unaudited)

 

The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States.

 

 

 

 

Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The Company expects that the majority of these costs will be evaluated over the next three to five years. 

 

Subsequent to December 31, 2015 and through February 26, 2016, the Company drilled 5 gross horizontal wells and completed 2 gross horizontal wells and had 5 gross horizontal wells awaiting completion.

 

Depletion per unit-of-production, on a BOE basis, amounted to $19.74,  $27.51 and $31.12 for the years ended December 31, 2015,  2014, and 2013, respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to $7.71,  $10.85, and $14.00 for the years ended December 31, 2015,  2014, and 2013, respectively.

 

The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities.

 

 

Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At December 31, 2015, the prices used in determining the estimated future net cash flows from proved reserves were $47.25 per barrel of oil and $2.73 per Mcf of natural gas. For the year ended December 31, 2015, the Company recognized a write-down of oil and natural gas properties of $208,435 as a result of the ceiling test limitation.

 

Estimated Reserves

 

The Company’s proved oil and natural gas reserves at December 31, 2015 and 2014 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum engineers. The Company’s proved oil and natural gas reserves at December 31, 2013 were estimated by Huddleston & Co., Inc. The reserves were prepared in accordance with guidelines established by the SEC.  Accordingly, the following reserve estimates are based upon existing economic and operating conditions.

 

There are numerous uncertainties inherent in establishing quantities of proved reserves.  The following reserve data represents estimates only, and should not be deemed exact.  In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.

 

The following tables disclose changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States:

 

 

 

 

Total Proved Reserves: The Company ended 2015 with estimated net proved reserves of 54,271 MBOE, representing a 65% increase over 2014 year-end estimated net proved reserves of 32,824 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, on which it drilled a total of 36 gross (27.1 net) wells, and acquisitions made during 2015. This increase was primarily offset by 2015 production and revisions.

 

The Company ended 2014 with estimated net proved reserves of 32,824 MBOE, representing a 121% increase over 2013 year-end estimated net proved reserves of 14,857 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, on which it drilled a total of 34 gross (28.7 net) wells, and acquisitions made during 2014. This increase was primarily offset by 2014 production and revisions.

 

The Company ended 2013 with estimated net proved reserves of 14,857 MBOE, representing a 6% increase over 2012 year-end estimated net proved reserves of 14,072 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin offset by the sale of the Company’s interest in the Medusa field and due to the Company’s reclassification of certain vertical PUD locations to the horizontal probable and PUD categories.

 

Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories.

 

Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The Company’s PUDs increased 75% to 25,654 MBOE from 14,623 MBOE at December 31, 2015 and 2014, respectively. The Company added 13,774 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 2,742 MBOE, or 19%, included in the year-end 2014 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $55,933, net.

 

The Company’s PUDs increased 98% to 14,623 MBOE from 7,387 MBOE at December 31, 2014 and 2013, respectively. The Company added 10,125 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 1,757 MBOE, or 24%, included in the year-end 2013 PUD reserves, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $34,619, net. Also offsetting the increase was the removal of 1,132 MBOE of PUDs, including the impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal development.

 

The Company’s PUDs increased 1% to 7,387 MBOE from 7,337 MBOE at December 31, 2013 and 2012, respectively. The Company added 5,168 MBOE to its PUDs, primarily from the continued horizontal development of its Permian Basin properties. The increase in Permian Basin PUDs was partially offset by 3,724 MBOE, or 51%, included in the year-end 2012 PUD reserves related to vertical PUD locations that were reclassified to horizontal probable reserves, and to a small extent, horizontal PDP and PUD categories. The reclassified vertical PUDs include locations that included certain target zones that were expected to be more efficiently developed by the Company’s multi-level horizontal drilling programs initiated in 2012. Also offsetting the Permian Basin PUD growth were the sale of 1,297 MBOE, or 18%, included in the year-end 2012 PUD reserves related to our Medusa field and the conversion of a small portion of 2012 PUD reserves to PDPs during 2013 from the drilling of vertical wells.

 

Standardized Measure

 

The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2015. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding 12-months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods:

 

 

Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.

 

Natural gas production from our Permian Basin properties has a high Btu content of separator natural gas. The natural gas per Mcf prices of $2.73,  $6.38 and $5.45 used in the 2015,  2014 and 2013 reserve estimates, respectively, include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The oil prices per Bbl of $47.25,  $86.30 and $92.16 used in the 2015,  2014 and 2013 reserve estimates, respectively, have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.