Supplemental Information on Oil and Natural Gas Properties (unaudited) | Note 13 – Supplemental Information on Oil and N atural 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. For the Year Ended December 31, 2016 2015 2014 Evaluated Properties (a) Beginning of period balance $ 2,335,223 $ 2,077,985 $ 1,701,577 Capitalized G&A expenses 12,222 10,529 10,071 Property acquisition costs (b) 216,561 26,726 94,541 Exploration costs 38,612 81,320 118,251 Development costs 151,735 138,663 153,545 End of period balance $ 2,754,353 $ 2,335,223 $ 2,077,985 Unevaluated Properties (a)( c) Beginning of period balance $ 132,181 $ 142,525 $ 43,222 Property acquisition costs (b) 548,673 5,520 128,342 Exploration costs 8,631 4,576 11,177 Capitalized interest expenses 19,857 10,459 4,295 Transfers to Evaluated Properties (40,621) (30,899) (44,511) End of period balance $ 668,721 $ 132,181 $ 142,525 Accumulated depreciation, depletion and amortization Beginning of period balance $ 1,756,018 $ 1,478,355 $ 1,420,612 Provision charged to expense 71,330 69,228 56,663 Write-down of oil and natural gas properties (a) 95,788 208,435 — Sale of mineral interests 24,537 — 1,080 End of period balance $ 1,947,673 $ 1,756,018 $ 1,478,355 (a) The Company uses the full cost method of accounting for its exploration and development activities. See the Company’s accounting policy about oil and natural gas properties in Note 2 for details on the full cost method of accounting. (b) See Note 3 in the Footnotes to the Financial Statements for additional information about the Company’s significant acquisitions . (c) Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest expenses 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 majority of these costs are primarily associated with the Company’s focus areas of its future development program and are expected to be evaluated over ten to fifteen years. T he Company’s unevaluated property balance of $668,721 as of December 31, 2016, consisted of $123,345 , $521,520 and $23,856 of costs attributable to our Monarch, Wild H orse and Ranger operating areas, respectively. Subsequent to December 31, 2016 , and through February 22, 2017 , the Company drill ed four gross ( 3.4 net) horizontal wells and completed five gross ( 3.4 net) horizontal wells and had five gross ( 4.1 net) horizontal wells a waiting completion. Depletion per unit-of-production, on a BOE basis, amounted to $12.81 , $19.74 and $27.51 for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to $6.88 , $7.71 , and $10.85 for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Estimated Reserves The Company’s proved oil and natural gas reserves at December 31, 2016 , 2015 and 2014 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum engineers. 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: For the Year Ended December 31, Proved developed and undeveloped reserves: 2016 2015 2014 Oil (MBbls): Beginning of period 43,348 25,733 11,898 Revisions to previous estimates (5,738) (1,632) (243) Purchase of reserves in place 25,054 2,932 3,223 Sale of reserves in place (1,718) (23) — Extensions and discoveries 14,479 19,127 12,547 Production (4,280) (2,789) (1,692) End of period 71,145 43,348 25,733 Natural Gas (MMcf): Beginning of period 65,537 42,548 17,751 Revisions to previous estimates 13,929 4,870 (215) Purchase of reserves in place 36,474 2,915 8,591 Sale of reserves in place (2,765) (105) — Extensions and discoveries 17,194 19,621 18,641 Production (7,758) (4,312) (2,220) End of period 122,611 65,537 42,548 For the Year Ended December 31, Proved developed reserves: 2016 2015 2014 Oil (MBbls): Beginning of period 22,257 14,006 5,960 End of period 32,920 22,257 14,006 Natural gas (MMcf): Beginning of period 38,157 25,171 9,059 End of period 61,871 38,157 25,171 MBOE: Beginning of period 28,617 18,201 7,470 End of period 43,232 28,617 18,201 Proved undeveloped reserves: Oil (MBbls): Beginning of period 21,091 11,727 5,938 End of period 38,225 21,091 11,727 Natural gas (MMcf): Beginning of period 27,380 17,377 8,692 End of period 60,740 27,380 17,377 MBOE: Beginning of period 25,654 14,623 7,387 End of period 48,348 25,654 14,623 Total Proved Reserves: The Company ended 2016 with estimated net proved reserves of 91,580 MBOE, representing a 69% increase over 2015 year-end estimated net proved reserves of 54,271 MBOE. The Company added 48,477 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 29 gross ( 20.9 net) wells. This increase was primarily offset by 11,168 M BOE related to divestitures, 2016 production and revisions primarily due to pricing. 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, where 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, where 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. 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 88% to 48,348 MBOE from 25,654 MBOE at December 31, 2016 and 2015 , respectively. The Company added 17,482 MBOE to its PUDs, primarily from acquisitions in the Permian Basin, net of divestitures, and added 12,035 MBOE from the continued horizontal development of its Permian Basin properties, net of revisions. The increase in Permian Basin PUDs was partially offset by the reclassification of 6,823 MBOE , or 27% , inclu ded in the year-end 2015 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $43,415 , net. 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. 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, 2016 . 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: 2016 2015 2014 Average 12-month price, net of differentials, per Mcf of natural gas (a) $ 2.71 $ 2.73 $ 6.38 Average 12-month price, net of differentials, per barrel of oil (b) $ 40.03 $ 47.25 $ 86.30 (a) Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. (b) Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 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. Standardized Measure For the Year Ended December 31, 2016 2015 2014 Future cash inflows $ 3,180,005 $ 2,227,463 $ 2,492,178 Future costs Production (974,667) (827,555) (873,469) Development and net abandonment (384,117) (239,100) (288,081) Future net inflows before income taxes 1,821,221 1,160,808 1,330,628 Future income taxes (1,602) — (164,490) Future net cash flows 1,819,619 1,160,808 1,166,138 10% discount factor (1,009,787) (589,918) (586,596) Standardized measure of discounted future net cash flows $ 809,832 $ 570,890 $ 579,542 Changes in Standardized Measure For the Year Ended December 31, 2016 2015 2014 Standardized measure at the beginning of the period $ 570,890 $ 579,542 $ 283,946 Sales and transfers, net of production costs (150,628) (110,476) (120,518) Net change in sales and transfer prices, net of production costs (103,136) (286,660) (156,066) Net change due to purchases and sales of in place reserves 260,859 37,616 111,331 Extensions, discoveries, and improved recovery, net of future production and development costs incurred 180,228 184,469 299,192 Changes in future development cost 82,320 108,216 186,605 Revisions of quantity estimates (35,938) (12,625) (7,673) Accretion of discount 57,091 62,968 30,114 Net change in income taxes 16 35,407 (32,940) Changes in production rates, timing and other (51,870) (27,567) (14,449) Aggregate change 238,942 (8,652) 295,596 Standardized measure at the end of period $ 809,832 $ 570,890 $ 579,542 |