13.

Supplementary Oil and Gas Information (unaudited)

Costs Incurred in Oil and Gas Producing Activities

Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion, depreciation, amortization and accretion (“DD&A”) per equivalent unit-of-production were as follows for the years ended December 31, 2013 and 2014:


	2013		2014
Acquisition costs:
Unproved properties	$	—	$	34,500
Proved properties		—		—
Exploration costs		—		—
Development costs		307,834		594,359
Revisions to asset retirement obligation		34,934		—

Total costs incurred	$	342,768	$	628,859

Depletion per BOE of production	$	19.01	$	22.24

Supplemental Oil and Gas Reserve Information

The reserve information presented below is based on estimates of net proved reserves as of December 31, 2012 and 2013 that were prepared by Ryder Scott Company, the Company’s independent petroleum engineering firm, in accordance with guidelines established by the SEC.

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Changes in Proved Reserves

The Company did not have any proved reserves prior to 2011. The following table sets forth information regarding the Company’s estimated total proved and oil and gas reserve quantities for the years ended December 31, 2013 and 2014:


	Oil (Bbl)			Gas (Mcf)			Equivalent (BOE)
Balance, December 31, 2012		331,672			529,239			419,879
Sale of oil and gas reserves in place		(4,080	)		—			(4,080	)
Revisions in previous estimates		(60,081	)		233,116			(18,229	)
Production		(20,517	)		(85,567	)		(37,778	)

Balance, December 31, 2013		246,994			676,788			359,792
Revisions in previous estimates		13,060			8,347			14,452
Production		(22,825	)		(70,195	)		(34,524	)

Balance, December 31, 2014		237,229			614,940			339,720

Proved reserves, December 31, 2013:
Proved developed		184,349			668,489			295,764

Proved undeveloped		62,645			8,299			64,028

Proved reserves, December 31, 2014:
Proved developed		230,530			614,940			333,020

Proved undeveloped		6,699						6,699

Standardized Measure

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

As of December 31, 2013, future cash inflows were computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December of 2013, which resulted in benchmark prices of $96.78 per barrel for crude oil and $3.67 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2013 of $87.49 per barrel of oil and $5.86 per Mcf for natural gas.

As of December 31, 2014, future cash inflows were computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December of 2014, which resulted in benchmark prices of $94.99 per barrel for crude oil and $4.35 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2014 of $84.09 per barrel of oil and $6.09 per Mcf for natural gas.

The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Net operating losses incurred in oil and gas producing activities are utilized to reduce taxable income. Permanent differences in oil and gas related tax credits and allowances are recognized, if reasonably estimable.

A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves. The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves as of December 31, 2013 and 2014:


	2013			2014
Future cash inflows	$	25,573,856		$	23,132,987
Future production costs		(10,493,071	)		(9,732,541	)
Future development costs		(880,486	)		(781,442	)
Future income taxes		(2,490,706	)		—

Future net cash flows		11,709,593			12,619,004
10% annual discount		(5,554,945	)		(5,476,544	)

Standardized measure of discounted future net cash flows	$	6,154,648		$	7,142,460

The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil and gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on average prices realized in the preceding year and on costs in effect at the end of the year. However, actual future net cash flows from the Company’s oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas and changes in governmental regulations or taxation.

The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.

A summary of changes in the standardized measure of discounted future net cash flows is as follows for the years ended December 31, 2013 and 2014:


	2013			2014
Standardized measure of discounted future net cash flows, beginning of year	$	7,033,189		$	6,154,647
Sales of oil and gas, net of production costs and taxes		(1,359,448	)		(1,190,850	)
Purchases of reserves in place		—			—
Sales of reserves in place		(160,748	)		—
Changes in development costs		(7,872	)		98,054
Revisions of previous estimates		(524,565	)		213,112
Changes in prices and production costs		492,325			(341,335	)
Net changes in income taxes		(21,553	)		440,034
Accretion of discount		703,319			615,465

Standardized measure of discounted future net cash flows, end of year	$	6,154,647		$	5,989,127