Supplementary Oil and Gas Information (unaudited)

12 Months Ended

Dec. 31, 2016

Supplementary Oil And Gas Information

Supplementary Oil and Gas Information (unaudited)

12. 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, 2016 and 2015:

	2016		2015
Acquisition costs:
Unproved properties	$	-	$	-
Proved properties		-		1,404,493
Exploration costs		-		-
Development costs		-		115,992
Revisions to asset retirement obligation		-		-
Total costs incurred	$	-	$	1,520,485
Depletion per BOE of production	$	17.56	$	27.78

The reserve information presented below is based on estimates of net proved reserves as of December 31, 2016 and 2015 that were prepared by Pinnacle Energy Services, L.L.C. 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 following table sets forth information regarding the Company's estimated total proved oil and gas reserve quantities for the years ended December 31:

	Oil (Bbl)			Gas (Mcf)			Equivalent (BOE)
Balance, January 1, 2015		237,229			614,940			339,720
Sale of oil and gas reserves in place					-			-
Acquisition of reserves in place		71,870			-			71,870
Revisions in previous estimates		(14,924	)		(194,070	)		(47,269	)
Production		(18,955	)		(62,630	)		(29,393	)
Balance, December 31, 2015		275,220			358,240			334,928
Sale of oil and gas reserves in place		-			-			-
Acquisition of reserves in place		-			-			-
Revisions in previous estimates (1)		(105,804	)		(196,533	)		(138,562	)
Production		(23,386	)		(41,937	)		(30,376	)
Balance, December 31, 2016		146,030			119,770			165,990
Proved reserves, December 31, 2015:
Proved developed		275,220			358,240			334,928
Proved undeveloped		-			-			-
Proved reserves, December 31, 2016:
Proved developed		146,030			119,770			165,990
Proved undeveloped		-			-			-

(1) The primary reason for the revision in previous estimates is due to the higher lease operating expenses incurred, which made several of the wells uneconomic sooner than the prior year.

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, 2016, 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 2016, which resulted in benchmark prices of $42.75 per barrel for crude oil, West Texas Intermediate ("WTI") and $2.49 per MMbtu for natural gas, Henry Hub. Prices were further adjusted for transportation, quality and basis differentials, which resulted in a difference from the benchmark prices ranging from -$2.97 per barrel to -$10.77 per barrel, depending on the location of the wells. One well that produces from the Minnelusa formation has an oil differential of -$26.67 per barrel. The calculated natural gas differentials ranged from -74% to +59% as a percentage of the benchmark prices depending on where the well was located.

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, 2016 and 2015:

	2016			2015
Future cash inflows	$	5,751,250		$	13,002,030
Future production costs		(4,322,870	)		(7,976,560	)
Future development costs		-
Future income taxes		-
Future net cash flows		1,428,380			5,025,470
10% annual discount		(545,640	)		(2,472,800	)
Standardized measure of discounted future net cash flows	$	882,740		$	2,552,670

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, 2016 and 2015:

	2016			2015
Standardized measure of discounted future net cash flows, beginning of year	$	2,552,670		$	5,989,127
Sales of oil and gas, net of production costs and taxes		(224,105	)		23,891
Purchases of reserves in place		-			589,190
Sales of reserves in place		-			—
Changes in development costs		-			(699,000	)
Revisions of previous estimates		(802,699	)		(440,871	)
Changes in prices and production costs		(898,393	)		(4,661,912	)
Net changes in income taxes		-			1,153,332
Accretion of discount		255,267			598,913
Standardized measure of discounted future net cash flows, end of year	$	882,740		$	2,552,670