SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES

(UNAUDITED)

Costs Incurred Related to Oil and Gas Activities

Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion.

The Company’s oil and gas activities for 2016, 2015 and 2014 were entirely within the United States of America. Costs incurred in oil and gas producing activities were as follows (in thousands):

	Years Ended December 31,
	2016 ⁽¹⁾		2015		2014
Acquisition cost:
Proved	$	48,116	$	4,508	$	74,728
Unproved		26,600		10,646		36,236

Exploration costs:
Exploratory drilling		—		—		—
Geological and geophysical		5		142		111

Development costs		28,577		56,862		75,105
Total additions	$	103,298	$	72,158	$	186,180

⁽¹⁾

Acquisition costs incurred during 2016 consisted entirely of the assets acquired in the Lynden Arrangement described in Note 3. Acquisitions and Divestitures of the Notes to Consolidated Financial Statements.

During each of the three years ended December 31, 2016, 2015 and 2014, additions to oil and gas properties of $0.2 million were recorded for estimated costs of future abandonment related to new wells drilled or acquired.

For the years ended December 31, 2016, 2015 and 2014, the Company had no capitalized exploratory well costs.

Capitalized Costs

Capitalized costs, impairment, and depreciation, depletion and amortization relating to our oil and natural gas properties producing activities, all of which are conducted within the continental United States as of December 31, 2016 and 2015 are summarized below (in thousands):

	December 31,
	2016			2015
Oil and gas properties, successful efforts method:
Proved properties	$	476,832		$	394,532
Accumulated impairment to proved properties		(113,760	)		(110,888	)
Proved properties, net of accumulated impairments		363,072			283,644

Unproved properties		100,612			79,619
Accumulated impairment to Unproved properties		(48,889	)		(45,010	)
Unproved properties, net of accumulated impairments		51,723			34,609

Total oil and gas properties, net of accumulated impairments		414,795			318,253

Accumulated depreciation, depletion and amortization		(145,393	)		(119,920	)
Net oil and gas properties	$	269,402		$	198,333

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time 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. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves represent estimated quantities expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

The proved reserves estimates shown herein for the years ended December 31, 2016, 2015 and 2014 have been independently prepared by Cawley, Gillespie & Associates, Inc.

The reserve information in these consolidated financial statements represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. As a result, estimates by different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.

The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated. The oil prices as of December 31, 2016, 2015, and 2014 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate spot prices which equates to $42.75 per barrel, $50.28 per barrel, and $94.99 per barrel, respectively. The natural gas prices as of December 31, 2016, 2015 and 2014 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $2.48 per MMBtu, $2.59 per MMBtu and $4.30 per MMBtu, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials. All prices are held constant in accordance with SEC guidelines.

A summary of the Company’s changes in quantities of proved oil and natural gas reserves for the years ended December 31, 2016, 2015 and 2014 are as follows:

	Oil			Natural Gas			NGLs			Total
	(MBbl)			(MMcf)			(MBbl)			(MBOE)
Balance - December 31, 2013		6,078			24,213			1,318			11,431
Extensions and discoveries		1,909			1,403			221			2,364
Purchases of minerals in place		7,025			6,064			437			8,473
Production		(403	)		(2,132	)		(124	)		(882	)
Revision to previous estimates		(806	)		9,031			107			806

Balance - December 31, 2014		13,803			38,579			1,959			22,192
Extensions and discoveries		526			828			21			685
Sales of minerals in place		(4	)		(8,040	)		—			(1,344	)
Purchases of minerals in place		1,641			679			208			1,962
Production		(904	)		(2,143	)		(176	)		(1,437	)
Revision to previous estimates		(5,701	)		(16,565	)		(1,022	)		(9,484	)

Balance - December 31, 2015		9,361			13,338			990			12,574
Extensions and discoveries		345			285			30			423
Purchases of minerals in place		5,548			14,770			2,637			10,647
Production		(878	)		(2,171	)		(225	)		(1,465	)
Revision to previous estimates		(7,265	)		(5,821	)		(1,892	)		(10,128	)
Balance - December 31, 2016		7,111			20,401			1,540			12,051

Proved developed reserves:
December 31, 2013		1,307			11,053			557			3,706
December 31, 2014		6,093			16,214			1,005			9,800
December 31, 2015		6,114			10,954			673			8,613
December 31, 2016		6,052			13,545			1,051			9,361

Proved undeveloped reserves:
December 31, 2013		4,771			13,160			761			7,725
December 31, 2014		7,710			22,365			954			12,392
December 31, 2015		3,247			2,384			317			3,961
December 31, 2016		1,059			6,856			489			2,690

Total proved reserves decreased by 0.5 MMBoe during 2016 which primarily resulted from a 10.1 MMBoe downward reserve revision caused by decreases in the prices used to calculated those reserves (prices used to estimate reserves are included in Oil and Natural Gas Reserves above), including the related decrease in volume estimates, along with production of 1.5 MMBoe, which was offset by a 10.6 MMBoe increase in reserves resulting from the purchase of minerals in place through the aforementioned Lynden Arrangement, as well as 0.4 MMBoe resulting from extensions and discoveries.

At December 31, 2016 the Company’s estimated proved undeveloped reserves (PUDs) were 2.7 MMBoe, a 1.3 MMBoe net decrease over the previous year’s estimate of 4.0 MMBoe. The following details the changes in PUD reserves for 2016 (in MBoe):

Proved undeveloped reserves at December 31, 2015	3,961
Conversions to developed	(169	)
Extensions and discoveries	293
Purchases	873
Revisions	(2,268	)
Proved undeveloped reserves at December 31, 2016	2,690

The change to the PUD reserves was a result of the significant decline in oil and natural gas prices. Prices used to estimate reserves are included in Oil and Natural Gas Reserves above.

Extensions and Discoveries during the year ended December 31, 2016 were from the Company’s operated Eagle Ford and non-operated Bakken properties.

All of the Company’s purchases of minerals in place reserves during the year ended December 31, 2015, occurred in the Eagle Ford property in Gonzales County, Texas.

Based on the Company’s year-end 2015 reserve report, the Company expects to drill all of its PUD locations within five years.

The total proved reserves increase of 10.8 MMBoe during 2014 is comprised of 6.1 MMBoe in proved developed and 4.7 MMBoe in proved undeveloped reserves.

During 2014, the Company added 2.4 MMBoe in proved reserves due to extension and discoveries, the majority of which is due to successful drilling in its operated Eagle Ford property in Fayette and Gonzales counties, Texas. Both new wells drilled and completed during 2014 along with the PUD locations that were added because of this successful drilling contributed to the increase in proved reserves. Purchase of minerals in place of 8.5 MMBoe were as a result of the Exchanges Agreement whereby Oak Valley acquired the legacy Earthstone assets through a reverse acquisition and the Flatonia Contribution Agreement where the Company acquired additional interests in its operated Eagle Ford property.

All of the Company’s increases through extensions and discoveries occurred in its operated Eagle Ford property in Fayette and Gonzales counties, Texas as a result of successful drilling during 2014 which added additional PUD locations as well.

PUDs that were converted during the year occurred in both the Company’s operated Eagle Ford and non-operated Bakken properties and 62% of the conversions occurred in the Eagle Ford property.

Extensions and Discoveries were from the Company’s operated Eagle Ford and non-operated Bakken properties.

All of the Company’s purchases of PUD reserves occurred in the Eagle Ford property in Gonzales County, Texas.

Based on the Company’s year-end 2016 reserve report, the Company expects to drill all of its PUD locations within five years.

For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lack sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. PUD locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing ASC 932, Extractives Activities – Oil and Gas (ASC 932) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s third party engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

•

Future costs and commodity prices will probably differ from those required to be used in these calculations;

•

Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

•

A 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

•

Future net revenues may be subject to different rates of income taxation

At December 31, 2016, 2015 and 2014, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. Prices used to estimate reserves are included in Oil and Natural Gas Reserves above. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying 10% discount factor.

The Standardized Measure is as follows (in thousands):	December 31,
	2016			2015			2014
Future cash inflows	$	346,948		$	481,131		$	1,464,138
Future production costs		(172,062	)		(192,349	)		(427,113	)
Future development costs		(29,814	)		(91,725	)		(312,010	)
Future income tax expense		—			—			(180,248	)
Future net cash flows		145,072			197,057			544,767
10% annual discount for estimated timing of cash flows		(59,189	)		(92,661	)		(288,911	)
Standardized measure of discounted future cash flows	$	85,883		$	104,396		$	255,856

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2016 (in thousands):

	December 31,
	2016			2015			2014
Beginning of year	$	104,396		$	255,856		$	125,357
Sales of oil and gas produced, net of production costs		(24,998	)		(29,152	)		(35,794	)
Sales of minerals in place		—			(2,470	)		—
Net changes in prices and production costs		(102,143	)		(288,064	)		(34,681	)
Extensions, discoveries, and improved recoveries		241			6,514			54,157
Changes in income taxes, net ⁽¹⁾		—			88,944			(88,944	)
Previously estimated development costs incurred during the period		27,770			26,977			18,252
Net changes in future development costs		102,267			6,697			7,028
Purchases of minerals in place		16,921			7,695			163,309
Revisions of previous quantity estimates		(45,239	)		(16,671	)		16,283
Accretion of discount		11,506			25,586			12,536
Changes in timing of estimated cash flows and other		(4,838	)		22,484			18,353
End of year	$	85,883		$	104,396		$	255,856

⁽¹⁾

As a result of the December 19, 2014 Exchange, all historical financial information contained in this report is that of OVR and its subsidiaries. OVR, is a partnership for federal tax purposes and is not subject to federal income taxes or state or local income taxes that follow the federal treatment, and therefore OVR did not pay or accrue for such taxes. Pursuant to the Exchange OVR’s subsidiaries have become subsidiaries of Earthstone Energy, Inc., which is a taxable entity; as such estimated tax expense was included in the Standardized Measure for December 31, 2014.