WildHorse Resource Development Corporation Announces Year-End 2016 Reserves, Operational Update, and 2017 Guidance

February 28, 2017

WildHorse Resource Development Corporation Announces Year-End 2016 Reserves, Operational Update, and 2017 Guidance

HOUSTON--(BUSINESS WIRE)-- WildHorse Resource Development Corporation (NYSE:WRD) announced today year-end 2016 reserves, an operational update, and 2017 guidance. Highlights include:

Year-End 2016 Reserves:

  • Reported year-end 2016 proved reserves of 152.5 MMboe, an increase of 48% from 103.0 MMboe at year-end 2015
  • Increased proved, probable and possible (“3P”)(1) reserves by 59% to 818.9 MMboe at year-end 2016 from 515.8 MMboe at June 30, 2016 (WRD’s last 3P reserve audit date)
    • At year-end 2016, 3P reserves were 494.2 MMboe in the Eagle Ford and 324.8 MMboe in North Louisiana, an increase of 90% and 27% from June 30, 2016, respectively
    • WRD increased its audited Burleson Main type curve used to evaluate PUD reserves by 9% to an EUR of 584 Mboe from 535 Mboe at year-end 2015
  • PV-10 of proved reserves increased by 66% to $750 million at year-end 2016 from $452 million at year-end 2015 despite lower SEC commodity pricing
  • Drill-bit finding and development (“F&D”) costs excluding acquisitions and price revisions averaged $4.73 per Boe, based on preliminary unaudited capital expenditure amounts for 2016(4)
  • Replaced 464% of estimated production in 2016 including performance revisions and excluding price revisions and acquisitions

Operational Update:

  • Estimated fourth quarter 2016 production of 17.5 Mboe/d pro-forma for the Burleson North acquisition (closed on 12/19/16)
  • Turned online 7.0 gross (7.0 net) Eagle Ford wells during the fourth quarter 2016
    • Drilled 16 gross (16.0 net) wells and completed 16 gross (16.0 net) wells in the Eagle Ford for full year 2016
    • Drilled 1 gross (0.8 net) wells and completed 2 gross (1.5 net) wells in North Louisiana for full year 2016
  • As of December 31, 2016, WRD had 16 Gen 3 wells on production in the Eagle Ford averaging above the Burleson Main EUR type curve of 91 Mboe per thousand feet of lateral

2017 Financial and Operational Guidance:

  • Project 2017 daily production to average 23.0 – 27.0 Mboe/d
    • Represents an approximate 36% increase over 2016's average daily production pro-forma for the Burleson North acquisition (using the mid-point of WRD's guidance range)
  • WRD currently operates 3 rigs in the Eagle Ford and 1 rig in North Louisiana and expects to operate an average of approximately 6 total drilling rigs in 2017
  • Estimated fiscal year 2017 D&C capex is approximately $450 - $600 million
    • D&C capex allocates 88% of the budget to the Eagle Ford and 12% of the budget to North Louisiana
    • Capital budget expected to be funded with cash on hand and WRD’s credit facility while targeting a Net Debt / EBITDAX ratio of approximately 2.0x or less

"With sixteen Gen 3 wells online at the end of 2016, our latest completion design now outnumbers the total of Gen 2 wells. We are tracking above our Burleson Main Eagle Ford type curve and are beginning to see the impact of our choke management strategy with shallower declines on the most recent wells. In addition, we will now control over 378,000 net acres in the Eagle Ford and North Louisiana after the closing of our most recent Burleson County acquisition. Furthermore, at year end 2016, we have expanded our proved reserves to 152.5 MMboe, an increase of 48% since the previous year. We look forward to delineating more of our acreage and expanding it as opportunities present themselves. Our top priorities for 2017 will include continuing to improve our completion design, while delivering industry-leading growth and maintaining a strong balance sheet,” said Jay Graham, Chairman and Chief Executive Officer of WRD.

Year-End 2016 Proved Reserves

WRD reported year-end 2016 proved reserves of 152.5 MMboe an increase of 48% from 103.0 MMboe at year-end 2015. At year-end 2016, WRD's proved reserves consisted of 57% oil, 36% natural gas and 7% NGLs.

Summary of Changes in Proved Reserves   Mboe
Balance as of December 31, 2015103.0
Extensions, Discoveries and Additions 26.9
Acquisitions 30.9
Performance Revisions (2.3)
Price Revisions (0.7)
Estimated Production (5.3)
Balance as of December 31, 2016152.5
 

Cawley, Gillespie & Associates (“CG&A”), an independent reserve engineering firm, audited WRD’s year-end reserves estimates as of December 31, 2016. WRD’s 2016 development program was primarily in the Eagle Ford with only two wells brought online in North Louisiana. Due to the Burleson North acquisition and greater activity in the Eagle Ford, the majority of added proved reserves were in the Eagle Ford. However, on a 3P basis, reserves increased in both areas with a 3P increase of 90% in the Eagle Ford and a 3P increase of 27% in North Louisiana since June 30, 2016. The table below provides additional information relating to WRD's reserves for the periods indicated:

  As of December 31,
Eagle Ford2015(2)   2016
 
Total proved reserves:
Oil (MMBbls) 35.7 86.7
Gas (Bcf) 33.8 45.1
NGL (MMBbls) 8.5   10.4
Total (MMboe)49.9104.7
 
North Louisiana
 
Total proved reserves:
Oil (MMBbls) 0.9 0.7
Gas (Bcf) 311.1 280.0
NGL (MMBbls) 0.4   0.5
Total (MMboe)53.247.8
 
WildHorse Resource
Development (WRD)
 
Total proved reserves:
Oil (MMBbls) 36.7 87.4
Gas (Bcf) 345.0 325.1
NGL (MMBbls) 8.9   10.9
Total (MMboe)103.0152.5
 

Using SEC prices, the present value discounted at 10% ("PV-10")(3) of WRD’s proved reserves at December 31, 2016 was $750 million (excluding WRD's hedges). The SEC rules require that proved reserve calculations be based on the average of the closing prices for the first day of each month in 2016. For the year-end 2016 reserve evaluation, the benchmark prices were $42.75 per barrel for crude oil and $2.48 per MMBtu for natural gas which compares to $50.28 per barrel for crude oil and $2.59 per MMBtu for natural gas at year-end 2015. This represents a 15% and 4% year-over-year decrease in benchmark crude oil and natural gas prices, respectively.

  Dec. 31
2015(2)
  Dec. 31
2016
 
PV-10 ($M)(3)
Eagle Ford 309,675 626,398
North Louisiana 142,255 123,590
Total ($M)451,930749,988
 
WTI Crude ($/bbl) $50.28$42.75
Henry Hub Gas ($/mmbtu) $2.59$2.48
 

WRD replaced 464% of estimated production in 2016 including performance revisions and excluding price revisions and acquisitions. Drill-bit finding and development (“F&D”)(4) costs for proved reserve additions from costs incurred for D&C capital expenditures, including facilities and capital workovers, averaged $4.73 per Boe, based on preliminary unaudited capital expenditure amounts for 2016. The reserve life of WRD’s proved reserves, based on the 2016 drilling program, is approximately 28.8 years. Additional detail regarding WRD’s calculation of its F&D costs can be found in the "Appendix" section of this press release.

Year-End 2016 3P Reserves

CG&A audited 3P reserves at year-end 2016 were 818.9 MMboe, a 59% increase over 515.8 MMboe at June 30, 2016 (WRD’s last 3P reserve audit date). Year-end 3P reserves were 494.2 MMboe in the Eagle Ford and 324.8 MMboe in North Louisiana, an increase of 90% and 27% from June 30, 2016, respectively. The table below summarizes CG&A audited 3P reserve volumes using SEC pricing:

3P Reserves - Eagle Ford (MMboe)(1)   Jun. 30
2016(2)(5)
  Dec. 31
2016
Proved 60.7   104.7
Probable 72.6 122.1
Possible 126.7   267.4
Total 3P Reserves259.9494.2
 
3P Reserves - North Louisiana (MMboe)(1)
Proved 46.7 47.8
Probable 28.1 28.1
Possible 181.1   248.8
Total 3P Reserves255.9324.8
 
Total 3P Reserves - WRD (MMboe)(1)
Proved 107.4 152.5
Probable 100.6 150.2
Possible 307.8   516.2
Total 3P Reserves515.8818.9
(1) See “Cautionary Statements and Additional Disclosures” in the Appendix section of this press release for more information regarding 3P reserves.
(2) Excludes proved reserves associated with the Burleson North acquisition that closed 12/19/16.
(3) PV-10 is a non-GAAP financial measure. See “Cautionary Statements and Additional Disclosures” in the Appendix section of this press release for more information.
(4) See “Drill-Bit Finding and Development (‘F&D”) Cost Calculation” in the Appendix section of this press release for more information regarding WRD’s calculation of its F&D costs.
(5) WRD's 3P reserves at June 30, 2016 were prepared by its internal reserve engineers and audited by CG&A. Note that the December 31, 2015 audited CG&A reserve report did not include 3P reserves.
 

Acreage and Horizontal Drilling Location Update

As of December 31, 2016, management estimates 2,350 net horizontal drilling locations in the Eagle Ford and North Louisiana. Specifically, this includes 1,702 net locations in the Eagle Ford and 648 net locations in North Louisiana.

Of WRD’s total 2,350 net horizontal locations, 1,700 or 72%, are included within CG&A’s 3P geographic area as of the year-end 2016 reserve report. This is 566 net locations greater than the 1,134 net locations, or 49%, within the 3P geographic area reported at WRD’s recent initial public offering. Of the additional 566 net locations in the 3P geographic area, 411 net locations are part of the Burleson North acquisition. The majority of the remaining new 3P locations are in other Eagle Ford operational areas with 3P locations added to North Louisiana as well.

In addition to the greater 3P location count, WRD has continued to increase its acreage position through organic leasing and acquisitions. Since the IPO, WRD has added another 12,843 net acres in the Eagle Ford including the recently announced acquisition of 10,535 net acres in Burleson County from multiple sellers for $15.6 million. The acquisition comes with 16 producing wells and 195 net barrels of oil equivalent per day of production, with an implied acquisition cost of approximately $812 per acre. One transaction has closed and the other transactions are expected to close in April 2017. Pro-forma for the acquisition, WRD’s total acreage position is now 378,024 net acres. WRD will continue to actively evaluate further acquisition opportunities as they arise.

Fourth Quarter and Full Year 2016 Operational Update

WRD expects to report estimated fourth quarter 2016 average daily production of 14.3 Mboe/d, which represents a 1% increase from the fourth quarter 2015. WRD’s estimated production mix during the fourth quarter 2016 consisted of approximately 40% oil, 50% natural gas, and 10% NGLs. WRD’s estimated full year 2016 production was 14.5 Mboe/d, a 39% increase from 10.4 MBoe/d for full year 2015. Fourth quarter 2016 production was impacted by downtime associated with workover activity and maintenance on several existing wells in North Louisiana. In addition, the timing of wells in the Eagle Ford also had a limited effect on fourth quarter 2016 production.

Full fourth quarter 2016 production pro-forma for the closed Burleson North acquisition was 17.5 Mboe/d consisting of approximately 47% oil, 44% natural gas, and 9% NGLs. Pro-forma full year 2016 production was 18.4 Mboe/d, a 14% increase from 16.2 MBoe/d for full year 2015. Pro-forma estimated production mix during the full year 2016 consisted of approximately 45% oil, 47% natural gas, and 8% NGLs.

As of December 31, 2016, WRD had 16 Gen 3 wells on production in the Eagle Ford averaging above the Burleson Main EUR type curve of 91 Mboe per thousand feet of lateral. WRD turned to sales 7.0 gross (7.0 net) Eagle Ford wells during the fourth quarter 2016. The preliminary estimate of D&C capital expenditures, including facilities and capital workovers, totaled $35.7 million in the fourth quarter 2016. For the full year 2016, WRD’s preliminary estimate of D&C capital expenditures, including facilities and capital workovers, was approximately $116.4 million. Land and leasehold acquisitions totaled $397.3 million in 2016 of which $294.2 million was attributable to the Burleson North acquisition.

2017 Operational and Financial Guidance

During 2017, WRD expects to operate an average of approximately 6.0 rigs with an average of 4.5 drilling rigs in the Eagle Ford and 1.5 rigs in North Louisiana. WRD currently projects 2017 daily production between 23.0 – 27.0 Mboe/d. At the mid-point, this represents an approximate 36% increase over 2016's average daily production pro-forma for the Burleson North acquisition. WRD anticipates 2017 average daily production to consist of approximately 52% - 56% oil, 35% - 38% natural gas and 8% - 10% NGLs.

WRD estimates a total fiscal year 2017 D&C capex of approximately $450 - $600 million with 88% of the budget to the Eagle Ford and 12% of the budget to North Louisiana. WRD expects this capital budget outspend to be funded by cash on hand and the currently undrawn credit facility.

For the full year 2017, WRD expects to spud 90 to 110 gross wells and to bring online 80 to 100 gross wells. WRD estimates an average working interest of approximately 89% for wells brought online in 2017. For the full year 2017, a summary of the guidance is presented below:

  2017 FY Guidance
Low   High
Net Average Daily Production (Mboe/d) 23.0 - 27.0
Oil (% of Production) 52% - 56%
Natural Gas (% of Production) 35% - 38%
NGLs (% of Production) 8% - 10%
 
Average Costs (per Boe)
Lease Operating Expense ($2.75) - ($3.25)
Gathering, Processing, and Transportation ($0.95) - ($1.15)
Taxes Other than Income ($2.00) - ($2.25)
Cash General and Administrative(2) ($2.75) - ($3.25)
 
Commodity Price Realizations (Unhedged)(1)
Crude Oil Realized Price (% of WTI NYMEX) 95% - 100%
Natural Gas Realized Price (% of NYMEX to Henry Hub) 95% - 100%
NGL Realized Price (% of WTI NYMEX) 22% - 27%
 
Drilling Program
Wells Spud (Gross) 90 - 110
Wells Completed (Gross) 80 - 100
D&C Capital Expenditure ($MM) $450 - $600
Note: Guidance as of February 28, 2017
(1) Based on strip pricing as of February 23, 2017
(2) Excludes non-cash compensation charges associated with grants under our LTIP and incentive units issued to certain of our officers and employees. WRD does not guide to anticipated average non-cash general and administrative costs. Please see cautionary language in the appendix for additional disclosures
 

The operational and financial guidance provided in this press release is subject to the cautionary statements and limitations described under “Cautionary Statements and Additional Disclosures – Forward-Looking Statements” in the Appendix of this press release. WRD’s guidance is based on, among other things, its current expectations regarding capital expenditure levels and the assumption that market demand and prices for oil, natural gas and NGLs will continue at a level that allows for economic production of these products.

Financial Update

As of December 31, 2016, total outstanding debt was $242.7 million drawn on WRD’s revolving credit facility. Pro-forma for the recent over-allotment exercise proceeds received of $32.6 million and the issuance of $350 million in senior unsecured notes, total debt is $350.0 million leaving the revolving credit facility fully undrawn with a borrowing base of $362.5 million. As of December 31, 2016, WRD’s pro-forma liquidity of $495.9 million consisted of $133.4 million of cash and cash equivalents and $362.5 million of availability under its revolving credit facility. WRD is projected to exit 2017 with a net debt to annualized EBITDAX ratio of less than 2.0 times. WRD's liquidity position is expected to be sufficient to finance anticipated working capital and capital expenditures.

Hedging Overview

WRD utilizes its hedging program to mitigate financial risks and commodity price volatility. As of February 23, 2017, WRD has hedged approximately 72% of its expected 2017 production (using the mid-point of WRD’s guidance range). In 2017, WRD has hedged approximately 72% of expected oil volumes and approximately 89% of expected natural gas volumes (using the mid-point of WRD’s guidance range). WRD’s weighted average hedge price in 2017 is $53.75 per Bbl of oil and $3.21 per MMBtu of natural gas.

WRD uses a combination of swaps, collars, and puts to hedge its production. In 2017, 28% of expected oil volumes and 16% of natural expected gas volumes are hedged with put option contracts which do not limit the potential upside from rising commodity prices (using the mid-point of WRD’s guidance range).

The following table reflects WRD’s hedged volumes and corresponding weighted-average price, as of February 23, 2017:

  Q4 2016 (3)   2017   2018   2019
     
Natural Gas Hedge Contracts:
Total natural gas volumes hedged (MMBtu) 3,600,000 17,757,080 11,565,800 9,877,900
Total weighted-average price (1)$2.84$3.21$3.03$2.81
Expected production hedged (2) 91% 89% - -
 
Crude Oil Hedge Contracts:
Total crude oil volumes hedged (Bbl) 244,072 3,570,020 1,663,596 1,381,300
Total weighted-average price (1)$47.15$53.75$53.72$54.92
Expected production hedged (2) 47% 72%
 
Total Hedge Contracts:
Total hedged production (boe) 844,072 6,529,533 3,591,229 3,027,617
Total weighted-average price ($/boe) (1)$25.77$38.11$34.64$34.24
Expected production hedged (2) 64% 72% - -
(1) Utilizing the mid-point for collars
(2) Using WRD’s 2016 expected production and 2017 guidance ranges
(3) 4Q 2016 hedge volumes represent the period October – December 2016. Volumes represent 4Q 2016 estimated results not pro-forma for the Burleson North acquisition
 

Fourth Quarter and Full Year 2016 Earnings Conference Call

WRD will report its fourth quarter and full year 2016 financial and operating results after the market closes for trading on March 29, 2017. On the morning of March 30, 2017, management will host a fourth quarter and full year 2016 earnings conference call at 8 a.m. Central (9 a.m. Eastern). Interested parties are invited to participate on the call by dialing (877) 883-0383 (Conference ID: 0311954), or (412) 902-6506 for international calls, (Conference ID: 0311954) at least 15 minutes prior to the start of the call or via the internet at www.wildhorserd.com. A replay of the call will be available on WRD’s website or by phone at (877) 344-7529 (Conference ID: 10102013) for a seven-day period following the call.

About WildHorse Resource Development Corporation

WildHorse Resource Development Corporation is an independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and NGL properties primarily in the Eagle Ford Shale in East Texas and the Over-Pressured Cotton Valley in North Louisiana. For more information, please visit our website at www.wildhorserd.com.

Appendix

The tables set forth below provide additional information relating to WRD's reserves. See “Cautionary Statements and Additional Disclosures” for more information regarding 3P reserves.

3P Reserve Detail (as of December 31, 2016)(2):

Eagle Ford

  Oil
(MMBbls)
  Natural Gas
(Bcf)
  NGLs
(MMBbls)
  Total
(MMboe)
  % Oil
(%)
Proved 86.7   45.1   10.4   104.7   83%
Probable 104.9 38.8 10.8 122.1 86%
Possible 231.9   79.7   22.1   267.4   87%
3P Reserves423.5163.743.4494.286%
 

North Louisiana

Proved 0.7 280.0 0.5 47.8 2%
Probable 0.6 164.7 0.0 28.1 2%
Possible 5.4   1,460.5   0.0   248.8   2%
3P Reserves6.81,905.20.5324.82%
 

WildHorse Resource Development

Proved 87.4 325.1 10.9 152.5 57%
Probable 105.5 203.6 10.8 150.2 70%
Possible 237.4   1,540.2   22.1   516.2   46%
3P Reserves430.32,068.943.8818.953%
 

Proved Reserve – Developed and Undeveloped

Eagle Ford

  Dec. 31
2015(1)
  Dec. 31
2016
 
Proved developed reserves:
Oil (MMBbls) 7.1 18.8
Gas (Bcf) 8.8 19.5
NGL (MMBbls) 1.9 3.3
Total (MMboe)10.425.4
 
Proved undeveloped reserves:
Oil (MMBbls) 28.7 67.9
Gas (Bcf) 25.0 25.6
NGL (MMBbls) 6.7 7.1
Total (MMboe)39.579.3
 
North Louisiana
 
Proved developed reserves:
Oil (MMBbls) 0.4 0.4
Gas (Bcf) 134.2 126.4
NGL (MMBbls) 0.4 0.5
Total (MMboe)23.221.9
 
Proved undeveloped reserves:
Oil (MMBbls) 0.5 0.4
Gas (Bcf) 177.0 153.6
NGL (MMBbls) 0.0 0.0
Total (MMboe)30.026.0
(1) Excludes proved reserves associated with the Burleson North acquisition
(2) See “Cautionary Statements and Additional Disclosures” in the Appendix section of this press release for more information regarding 3P reserves
 

Drill-Bit Finding and Development (“F&D”) Cost Calculation:

Drill-bit F&D cost is an indicator used to assist in the evaluation of the historical cost of adding proved reserves on a per Boe basis. Consistent with industry practice, future capital cost to develop proved undeveloped reserves are not included in costs incurred. Drill-bit F&D costs are calculated as D&C capital expenditures, including facilities and capital workovers, divided by reserve additions from extensions, discoveries, additions and performance revisions.

Cost incurred ($'s in millions):  
2016 D&C and other expenditures$116.4
 
Reserve additions (Mboe):
Extensions, discoveries and additions 26.9
Performance revisions   (2.3)
Total additions24.6
 
Total Drill-bit F&D costs ($/boe)$4.73
 

Cautionary Statements and Additional Disclosures

The description of WRD’s business, properties, strategies and other information in this press release relates solely to WRD and its consolidated subsidiaries following its initial public offering.

Cautionary Statement Concerning Forward-Looking Statements

This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by words such as “anticipates,” “intends,” “will,” “plans,” “seeks,” “believes,” “estimates,” “could,” “expects” and similar references to future periods. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond WRD’s control. All statements, other than historical facts included in this press release, that address activities, events or developments that WRD expects or anticipates will or may occur in the future, including such things as WRD’s future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, future drilling locations and inventory, competitive strengths, goals, expansion and growth of WRD’s business and operations, plans, successful consummation and integration of acquisitions and other transactions, market conditions, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. All forward-looking statements speak only as of the date of this press release. Although WRD believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

WRD cautions you that these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond WRD’s control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to: commodity price volatility; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory changes; the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital; and the timing of development expenditures. Information concerning these and other factors can be found in WRD’s filings with the SEC, including its Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in this press release are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by WRD will be realized, or even if realized, that they will have the expected consequences to or effects on WRD, its business or operations. WRD has no intention, and disclaims any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.

Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.

The preliminary results above are based on the most current information available to management. As a result, our final results may vary from these preliminary estimates. Such variances may be material; accordingly, you should not place undue reliance on these preliminary estimates.

PV-10 and 3P Reserves

PV-10 is a non-GAAP financial measure and represents the period-end present value of estimated future cash inflows from WRD’s natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using SEC pricing assumptions in effect at the end of the period. SEC pricing for oil and natural gas of $42.75 per Bbl and $2.48 per MMBtu; $43.12 per Bbl and $2.24 per MMBtu; and $50.28 per Bbl and $2.59 MMBtu was based on the unweighted average of the first-day-of-the-month prices for each of the twelve months preceding December 2016, June 2016, and December 2015, respectively. PV-10 differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes. Moreover, GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves. Because PV-10 estimates of probable and possible reserves are more uncertain than PV-10 and standardized estimates of proved reserves, but have not been adjusted for risk due to that uncertainty, they may not be comparable with each other. Nonetheless, WRD believes that PV-10 estimates for reserve categories other than proved present useful information for investors about the future net cash flows of its reserves in the absence of a comparable GAAP measure such as standardized measure. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from reserves on a more comparable basis. At this time, WRD is unable to provide a reconciliation of PV-10 to a standardized measure because WRD has not yet finalized its calculation of the effects of income taxes for the year ended December 31, 2016. WRD expects to include a full reconciliation of PV-10 as of December 31, 2016 to standardized measure in its Form 10-K for the year ended December 31, 2016. Neither PV-10 nor standardized measure represents an estimate of fair market value of WRD’s natural gas and oil properties. WRD and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.

WRD has provided summations of its proved, probable and possible reserves and summations of its PV-10 for its proved, probable and possible reserves in this press release. The SEC strictly prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Investors should be cautioned that estimates of PV-10 of probable reserves, as well as the underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. Further, because estimates of probable and possible reserve volumes have not been adjusted for risk due to this uncertainty of recovery, their summation may be of limited use.

Cash General and Administrative Expenses per Boe

Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.

WildHorse Resource Development Corporation
Luis Mier, 713-255-9327
Director, Investor Relations
ir@wildhorserd.com

Source: WildHorse Resource Development Corporation