NOTE 17 – UNAUDITED CRUDE OIL AND NATURAL GAS RESERVES INFORMATION

The reserves at December 31, 2017, presented below, were prepared by the independent engineering firm Cawley, Gillespie & Associates Inc. All reserves are located within the DJ Basin. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine the proved reserve estimates. The principal methodologies employed are decline curve analysis, advance production type curve matching, petro physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of the Company’s fields. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Analysis of Changes in Proved Reserves. Estimated quantities of proved developed reserves (all of which are located within the United States), as well as the changes in proved developed reserves during the periods indicated, are presented in the following tables:


		Natural
	Oil	Gas	NGL’s	Total
	(Bbls)	(Mcf)	(Bbls)	(BOE)
Proved Reserves:
Balance as of December 31, 2014	159	—	—	159
Revisions of previous estimates	(122)	—	—	(122)
Extensions and discoveries	—	—	—	—
Sales of reserves in place	—	—	—	—
Improved recovery	—	—	—	—
Purchase of reserves	—	—	—	—
Production	(37)	—	—	(37)
Balance as of December 31, 2015	—	—	—	—
Revisions of previous estimates	—	—	—	—
Extensions and discoveries	2,710,437	10,498,397	1,570,454	6,030,624
Sales of reserves in place	—	—	—	—
Improved recovery	—	—	—	—
Purchase of reserves	55,669	1,020,516	62,244	287,999
Production	(4,902)	(26,058)	(1,510)	(10,755)

Balance as of December 31, 2016	2,761,204	11,492,855	1,631,188	6,307,868
Revisions of previous estimates	(388,211)	292,477	38,668	(300,797)
Extensions and discoveries	839,738	4,183,757	631,149	2,168,180
Sales of reserves in place	—	—	—	—
Improved recovery	—	—	—	—
Purchase of reserves	—	—	—	—
Production	(188,529)	(549,846)	(50,111)	(330,281)
Balance as of December 31, 2017	3,024,202	15,419,243	2,250,894	7,844,970

Proved Developed Reserves, included above
Balance as of December 31, 2015	—	—	—	—
Balance as of December 31, 2016	260,284	1,788,895	181,655	740,088
Balance as of December 31, 2017	521,354	3,752,330	387,430	1,534,172

Proved Undeveloped Reserves, included above
Balance as of December 31, 2015	—	—	—	—
Balance as of December 31, 2016	2,500,920	9,703,960	1,449,533	5,567,780
Balance as of December 31, 2017	2,502,847	11,666,911	1,863,465	6,310,797

The values for the 2017 oil, natural gas and NGL reserves are based on the twelve-month arithmetic average of the first day of the month prices for the period from January through December 31, 2017. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months was $51.34 per barrel (West Texas Intermediate price) for crude oil and NGLs and $2.98 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2017 was $45.03 per barrel for oil, $1.71 per Mcf for natural gas and $20.42 per barrel for NGLs.

The values for the 2016 oil, natural gas and NGL reserves are based on the twelve-month arithmetic average of the first day of the month prices for the period from January through December 31, 2016. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months was $42.75 per barrel (West Texas Intermediate price) for crude oil and NGLs and $2.48 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2016 was $34.09 per barrel for oil, $2.69 per Mcf for natural gas and $14.44 per barrel for NGLs.

The Company did not assign a value to its proved reserves as of December 31, 2015 due to immaterial quantity estimates and a volatile price environment.

For the year ended December 31, 2017, the Company reported extensions and discoveries of 2,168,180 BOE primarily as result of the conversion of 18 PUD locations in the Todd Creek Farms prospect area during 2017 coupled with the addition of new PUD locations due to economic field extensions adjacent to Company leases. The Company reported downward revisions of previous estimates of 300,797 BOE primarily related to the removal of uneconomic PUD locations.

For the year ended December 31, 2016, the Company reported extensions and discoveries of 6,030,624 BOE as a result of drilling and completion activities during 2016. Additionally, during 2016 the Company purchased reserves of 287,999 BOE.

Standardized Measure of Estimated Discounted Future Net Cash Flows to Proved Oil and Natural Gas Reserves (in thousands):

The Company follows the guidelines prescribed in ASC 932, Extractive Activities-Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.

The information is based on estimates of proved reserves attributable to the Company’s interest in oil and gas properties as of December 31 of the years presented. These estimates were prepared by Cawley Gillespie & Associates, Inc., independent petroleum engineers.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (2) the estimated future cash flows are compiled by applying the twelve-month average of the first-day-of-the-month prices of crude oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves; (3) the future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred; and (4) future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The following are the principal sources of change in the standardized measure (in thousands):


	For the years ended December 31,
	2017		2016		2015

Future cash inflows	$	208,459	$	148,596	$	5
Future cash outflows:
Production cost		(48,929)		(35,038)		(3)
Development cost		(58,784)		(37,667)		—
Future income tax		(16,006)		(5,802)		—
Future net cash flows		84,740		70,089		2

Adjustment to discount future annual net cash flows at 10%		(35,054)		(29,925)		(2)

Standardized measure of discounted future net cash flows	$	49,686	$	40,164	$	—

The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC 932, Extractive Activities-Oil and Gas (in thousands):

Changes in Standardized Measure of Estimated Discounted Future Net Cash Flows


	For the years ended December 31,
	2017		2016		2015
Standardized measure, beginning of year	$	40,164	$	—	$	5
Sales of oil and gas, net of production cost		(9,392)		(126)		(3)
Net change in sales prices, net of production cost		10,263		489		—
Discoveries, extensions and improved recoveries		11,979		76,445		—
Change in future development costs		(4,050)		(37,667)		—
Development costs incurred during the period that reduced future development cost		1,144		—		—
Sales of reserves in place		—		—		—
Revisions of quantity estimates		(559)		—		(2)
Accretion of discount		4,275		130		—
Net change in income tax		(6,810)		(2,587)		—
Purchase of reserves		—		6,021		—
Changes in timing of rates of production		2,672		(2,541)		—

Standardized measure, end of year	$	49,686	$	40,164	$	—