HOUSTON--(BUSINESS WIRE)--WildHorse Resource Development Corporation (NYSE: WRD) announced today its operating and financial results for the fourth quarter and year ended December 31, 2016. Financial and operational highlights for the fourth quarter and full year 2016 and other highlights include(1):
- Delivered fourth quarter 2016 average daily production of 14.3 MBoe/d and pro-forma fourth quarter 2016 average daily production of 17.5 MBoe/d as well as full year 2016 average daily production of 14.5 MBoe/d and pro-forma full year 2016 average daily production of 18.4 MBoe/d
- Reported a fourth quarter 2016 Net Loss of $0.11 per share and a full year 2016 Net Loss of $0.11 per share
- Completed 18 gross (17.5 net) horizontal wells in 2016 including 16 gross (16 net) wells in the Eagle Ford and 2 gross (1.5 net) wells in North Louisiana
- Closed the Burleson North acquisition of approximately 158,000 net acres from Clayton Williams Energy, Inc. (“CWEI”) for $389.8 million (closed 12/19/2016)
- Closed WRD’s initial public offering raising gross proceeds of $447 million with the issuance of approximately 29.8 million shares (including the partial exercise of the over-allotment option)
- Issued $350 million in Senior Notes due 2025 at 6.875% in February 2017
- Reported year-end 2016 proved reserves of 152.5 MMBoe, an increase of 48% from 103.0 MMBoe at year-end 2015
- Replaced 464% of production in 2016 including performance revisions and excluding price revisions and acquisitions
- Achieved drill-bit finding and development (“F&D”)(2) costs excluding acquisitions and price revisions of $4.79 per Boe based on capital expenditure amounts for 2016
“Despite the challenges that faced the upstream oil and gas industry, 2016 was an exciting year for WildHorse Resource Development as we took the company public, completed a major acquisition in the Eagle Ford, and began adding to our rig count at year end. We have gone from running a single rig in the Eagle Ford for the majority of 2016 to currently operating five rigs in the Eagle Ford and one rig in North Louisiana. Furthermore, WRD finished the year with 16 Gen 3 wells online in the Eagle Ford which continue to outperform our type curve,” said Chairman and Chief Executive Officer, Jay Graham.
“We have announced our 2017 capex budget which estimates growth of approximately 36% over last year pro-forma for the Burleson North acquisition. Our capex guidance range of $450 to $600 million offers plenty of flexibility and optionality as well as the ability to spend on special projects such as delineating our acreage position, testing new completion designs, and exploring new targets. With the many opportunities in front of us, 2017 is shaping up to be an even more exciting year than the last. We look forward to delivering results for our shareholders,” added Jay Graham.
WRD discusses fourth quarter and full year 2016 results below. Please see the supplemental financial information in the Appendix section of this press release for fourth quarter and full year 2016 results pro-forma for the Burleson North acquisition including a reconciliation of the non-GAAP financial measures of Adjusted EBITDAX and Adjusted Net Income (Loss) to GAAP financial measures.
Fourth Quarter 2016 Results
Net production was 14.3 MBoe/d for the fourth quarter 2016 compared to 14.1 MBoe/d for the fourth quarter 2015. Fourth quarter 2016 net production consisted of approximately 40% oil, 50% natural gas, and 10% NGLs. Pro-forma fourth quarter 2016 average daily production was 17.5 MBoe/d.
WRD reported a Net Loss for the fourth quarter 2016 of $17.6 million compared to a Net Loss of $5.5 million for the fourth quarter 2015. Adjusted Net Loss(3) for the fourth quarter 2016 was $3.7 million compared to an Adjusted Net Loss(3) of $7.3 million for the fourth quarter 2015. Pro-forma Adjusted Net Loss(3) for the fourth quarter 2016 was less than $0.1 million.
WRD reported Adjusted EBITDAX(3) for the fourth quarter 2016 of $21.2 million compared to Adjusted EBITDAX(3) for fourth quarter 2015 of $19.9 million. Pro-forma Adjusted EBITDAX(3) for the fourth quarter 2016 was $28.6 million.
Total revenues for the fourth quarter 2016 were $39.3 million compared to $28.2 million for the fourth quarter 2015. Favorable pricing variance was primarily responsible for the difference between 2016 and 2015.
Average realized prices for the fourth quarter 2016 and 2015, before the effect of commodity derivatives, are presented below:
| Q4’16 | Q4’15 |
Percent Change |
||||||||||
| Oil (per Bbl) | $47.41 | $39.20 | 21% | |||||||||
| Natural gas (per Mcf) | $3.02 | $2.19 | 38% | |||||||||
| NGL (per Bbl) | $15.88 | $10.80 | 47% | |||||||||
| Total (per Boe) | $29.52 | $21.42 | 38% | |||||||||
Average realized prices for the fourth quarter 2016 and 2015, after the effect of commodity derivatives, are presented below:
| Q4’16 | Q4’15 |
Percent Change |
||||||||||
| Oil (per Bbl) | $46.23 | $40.72 | 14% | |||||||||
| Natural gas (per Mcf) | $2.89 | $3.07 | (6%) | |||||||||
| NGL (per Bbl) | $15.88 | $10.80 | 47% | |||||||||
| Total (per Boe) | $28.68 | $24.99 | 15% | |||||||||
Lease operating expense ("LOE") for the fourth quarter 2016 was $4.6 million, or $3.52 per Boe, compared to $4.5 million, or $3.43 per Boe, for the fourth quarter 2015. Our reported fourth quarter 2016 results included only 13 days of production from the Burleson North acquisition. On a standalone basis for the full fourth quarter 2016, the Burleson North asset had LOE of $9.51 per Boe for the fourth quarter 2016. Combined, the pro-forma fourth quarter 2016 LOE was $4.93 per Boe.
Gathering, processing and transportation expense for the fourth quarter 2016 was $1.5 million, or $1.16 per Boe, compared to $1.7 million, or $1.28 per Boe in the fourth quarter 2015.
Taxes other than income were $1.8 million for the fourth quarter 2016, or $1.34 per Boe, compared to $1.8 million, or $1.36 per Boe, for the fourth quarter 2015. As a result of WRD’s reorganization from a partnership to a public corporation, taxes other than income are expected to increase slightly in 2017 as Louisiana imposes a capital based franchise tax on corporate entities.
General and administrative ("G&A") expense for the fourth quarter 2016 was $9.9 million, or $7.53 per Boe, compared to $4.5 million, or $3.49 per Boe, for the fourth quarter 2015. Cash G&A expense for the fourth quarter 2016 was $9.8 million, or $7.48 per Boe. During the fourth quarter 2016, G&A expense included a $3.2 million increase in the year-end cash bonus from less than $0.3 million in 2015 and $0.4 million in acquisition related costs, or $2.83 per Boe. On a go forward basis as a public entity, the year-end cash bonus will be accrued over the full year rather than be recognized in a single quarterly period. In addition, fourth quarter 2016 included the effect of a greater headcount. At September 30, 2016, WRD had a total of 63 employees. At December 31, 2016 and March 27, 2017, WRD had a total of 85 and 107 employees, respectively.
Net interest expense during the fourth quarter 2016 was $2.2 million, including amortization of deferred financing fees of approximately $0.1 million. This compares to net interest expense during the fourth quarter 2015 of $1.9 million, including amortization of deferred financing fees of approximately $0.2 million.
Drilling and completion (“D&C”) capital expenditures, including facilities and capital workovers, were approximately $38.7 million in the fourth quarter 2016 in comparison to $59.3 million in fourth quarter 2015.
Full Year 2016 Results
Production increased 39% year-over-year to 14.5 MBoe/d for 2016 compared to 10.4 MBoe/d for 2015. Full year 2016 net production consisted of approximately 35% oil, 56% natural gas, and 9% NGLs. Pro-forma full year 2016 average daily production was 18.4 MBoe/d.
During 2016, WRD drilled 17 gross (16.8 net wells) and completed 18 gross (17.5 net) wells including 16 gross (16 net) Eagle Ford wells and 2 gross (1.5 net) horizontal wells in North Louisiana.
WRD reported a Net Loss for 2016 of $47.1 million compared to a Net Loss of $33.0 million for 2015. Adjusted Net Loss(3) for 2016 was $18.1 million compared to an Adjusted Net Loss(3) of $35.4 million for 2015. Pro-forma Adjusted Net Loss(3) for 2016 was $5.9 million.
WRD also reported Adjusted EBITDAX(3) for 2016 of $84.3 million compared to $55.9 million for 2015. Pro-forma Adjusted EBITDAX(3) for 2016 was $113.0 million.
WRD reported total revenues of $127.3 million during 2016 compared to $86.3 million for 2015. Total revenues do not include the impact of realized hedges. Greater total production and a higher percentage of oil in the production mix contributed to a $39.3 million increase in oil, natural gas and NGL revenues from 2015.
Average realized prices for the years ended December 31, 2016 and 2015, before the effect of commodity derivatives, are presented below:
| 2016 | 2015 |
Percent Change |
||||||||||
| Oil (per Bbl) | $41.09 | $44.41 | (7%) | |||||||||
| Natural gas (per Mcf) | $2.44 | $2.60 | (6%) | |||||||||
| NGL (per Bbl) | $12.28 | $12.22 | 0% | |||||||||
| Total (per Boe) | $23.67 | $22.65 | 5% | |||||||||
Average realized prices for the years ended December 31, 2016 and 2015, after the effect of commodity derivatives, are presented below:
| 2016 | 2015 |
Percent Change |
||||||||||
| Oil (per Bbl) | $41.83 | $45.46 | (8%) | |||||||||
| Natural gas (per Mcf) | $2.62 | $3.34 | (22%) | |||||||||
| NGL (per Bbl) | $12.28 | $12.22 | 0% | |||||||||
| Total (per Boe) | $24.53 | $25.81 | (5%) | |||||||||
LOE for 2016 was $12.3 million, or $2.33 per Boe, compared to $14.1 million, or $3.70 per Boe, in 2015. LOE decreased in 2016 primarily due to operational efficiencies, operational savings, and lower service costs. Pro-forma LOE was $4.13 per Boe for 2016.
Gathering, processing and transportation expense for 2016 was $6.6 million, or $1.24 per Boe, compared to $5.3 million, or $1.40 per Boe in 2015.
Taxes other than income were $6.8 million for 2016, or $1.29 per Boe, compared to $5.5 million, or $1.45 per Boe, for the previous year. On a Boe basis, taxes other than income decreased in 2016 due primarily to certain newly drilled wells which have a lower severance tax rate.
G&A expense for 2016 was $24.0 million, or $4.53 per Boe, compared to $15.9 million, or $4.19 per Boe, for 2015. During 2016, G&A expense included $0.1 million, or $0.01 per Boe, of stock-based compensation expense. Cash G&A expense for 2016 was $23.9 million, or $4.52 per Boe. The increase in G&A expenses was primarily due to greater staffing, an increase of $3.2 million in the year-end cash bonus from less than $0.3 million in 2015, costs related to our IPO of $1.6 million, and a reduction in G&A reimbursements of $1.9 million related to the termination of management services agreement in early 2015.
Net interest expense during 2016 was $7.8 million, including amortization of deferred financing fees of approximately $0.5 million. This compares to net interest expense during 2015 of $6.9 million, including amortization of deferred financing fees of approximately $0.7 million.
For the full year 2016, D&C capital expenditures, including facilities and capital workovers, were approximately $117.8 million. Leasehold and acquisitions totaled $470.5 million in 2016. In full year 2015, D&C capital expenditures, including facilities and capital workovers, were approximately $244.0 million. Leasehold and acquisitions totaled $176.6 million in 2015.
| (1) | In this press release, WRD discusses fourth quarter and full year 2016 results pro-forma for the Burleson North acquisition which closed on December 19, 2016. Our calculations for the pro-forma fourth quarter and full year 2016 were calculated with unaudited lease operating statements provided by CWEI during the acquisition process. As a result, the pro-forma calculations leave out expenses associated with corporate overhead items such as CWEI’s G&A expense as well as the impact of CWEI’s commodity hedges. Reported GAAP fourth quarter 2016 and full year 2016 results are also provided in this press release. Because entities contributed to us in connection with our initial public offering were under common control, our predecessor’s historical financial statements have been recast and accounted for as a combination of entities under common control. As such, the financial data presented herein (i) (a) as of, and for the year ended, December 31, 2016, and (b) as of December 31, 2015, and for the period from February 17, 2015 (the inception of common control) to December 31, 2015, have been derived from the consolidated and combined financial position and results attributable to our predecessor and previous owner contributed to us for periods prior to our initial public offering and (ii) for the period from January 1, 2015 to February 16, 2015, have been derived from the financial position and results attributable to our previous owner. | |
| (2) | 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. | |
| (3) | Adjusted EBITDAX, Adjusted Net Income (Loss), and Pro-Forma unaudited measures are non-GAAP financial measures. Please see the reconciliation to the most comparable measures calculated in accordance with GAAP in the "Use of Non-GAAP Financial Measures" section of this press release. | |
Operational Update
WRD turned online 7 gross (7 net) Eagle Ford wells to sales during the fourth quarter 2016 and has turned online 7 gross Eagle Ford wells during the first quarter 2017. Due to a slower drilling pace from newly added rigs which were previously cold-stacked and mechanical issues associated with such previously cold-stacked rigs, the 7 gross wells were brought online later than originally expected in the first quarter 2017. WRD is seeing marked improvements in drilling times from these rig crews. After several wells, the rig crews are back to our previous pace of approximately 14 days from spud to rig release. As of December 31, 2016, the average of the 16 Gen 3 wells online is tracking above the Burleson Main type curve of 91 MBoe per thousand feet of lateral.
| Eagle Ford Averages | Well Count |
Lateral Length (Feet) |
EUR (Mboe)(4) |
EUR Mboe/ 1000(4) |
Days Producing |
||||||||||||
| Generation 1 | 7 | 6,225 | 430 | 76 | 881 | ||||||||||||
| Generation 2 | 15 | 6,447 | 537 | 82 | 543 | ||||||||||||
| Generation 3 | 16 | 6,233 | 594 | 97 | 204 | ||||||||||||
| (4) | EUR represents the sum of total gross remaining proved reserves attributable to each location in our reserve report as of December 31, 2016 and cumulative sales from such location as of such date. EUR is shown on a combined basis for oil, natural gas, and natural gas liquids. | |
In North Louisiana, WRD drilled a 2-well pad in late first quarter 2017 and expects to begin drilling a 3-well pad in the second quarter 2017. WRD did not bring online any new wells in the fourth quarter 2016 or first quarter 2017, but expects to bring online the recently drilled 2-well pad in the second quarter 2017.
2017 Development Plan
As previously announced, WRD expects to spend $450 to $600 million on its 2017 D&C capital budget and to bring online between 80 and 100 gross wells in 2017.
WRD brought online approximately 7 gross Eagle Ford horizontal wells during the first quarter of 2017. 70% of Eagle Ford wells will come online in the second half of 2017, evenly split between the third quarter and fourth quarter 2017. While the majority of the activity in the Eagle Ford will be focused on the Burleson Main and Burleson North areas, WRD recently added a fifth Eagle Ford rig that will focus on a number of special projects such as delineating the aerial extent of the acreage position, drilling wells in the Burleson Core, and exploring new targets. WRD’s broad capex range of $450 to $600 million is based on the flexibility of the fifth Eagle Ford rig. Based on the mid-point of 2017 guidance of 23.0 – 27.0 MBoe/d, WRD expects to grow production by 36% pro-forma for the Burleson North acquisition.
In North Louisiana, WRD expects to bring online 2 gross wells in the second quarter 2017 and 7 gross wells in the fourth quarter 2017. In the second quarter 2017, WRD plans to add an additional drilling rig in North Louisiana.
Currently, WRD is operating 5 drilling rigs in the Eagle Ford and 1 drilling rig in North Louisiana. During 2017, WRD plans to operate an average of 6 drilling rigs with an average of 4.5 rigs in the Eagle Ford and 1.5 rigs in North Louisiana. See the full year 2017 guidance 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(5) | ($2.75) - ($3.25) | ||||||
| Commodity Price Realizations (Unhedged)(6) | |||||||
| Crude Oil Realized Price (% of WTI NYMEX) | 95% - 100% | ||||||
| Natural Gas Realized Price (% of NYMEX to Henry Hub) | 95% - 100% | ||||||
| NGL Realized Price (% of WTI NYMEX) | 22% - 27% | ||||||
| Drilling Program | |||||||
| Wells Spud (Gross) | 90 - 110 | ||||||
| Wells Completed (Gross) | 80 - 100 | ||||||
| D&C Capital Expenditure ($MM) | $450 - $600 | ||||||
| Note: Guidance as of February 28, 2017 | ||
| (5) | 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 section of this press release for additional disclosures because such compensation charges are based in part on the price of our common stock and are too speculative to predict. | |
| (6) | Based on strip pricing as of February 23, 2017. | |
Year-End 2016 Proved and 3P Reserves
On February 28, 2017, WRD announced Cawley Gillespie & Associates (“CG&A”) audited year-end 2016 proved reserves of 152.5 MMBoe, an increase of 48% from 103.0 MMBoe at year-end 2015. CG&A audited proved, probable and possible (“3P”)(7) 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)(8).
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, an increase of 566 net locations in comparison to 1,134 net locations, or 49%, within the 3P geographic area reported at WRD’s recent initial public offering.
In 2016, WRD replaced 464% of production including performance revisions and excluding price revisions and acquisitions. Drill-bit finding and development (“F&D”)(2) costs for proved reserve additions from costs incurred for D&C capital expenditures, including facilities and capital workovers, averaged $4.79 per Boe, based on capital expenditure amounts for 2016. See below our proved reserves by operating region:
| (7) | See “Cautionary Statements and Additional Disclosures” in the Appendix section of this press release for more information regarding 3P reserves. | |
| (8) | WRD's 3P reserves at June 30, 2016 were prepared by its internal reserve engineers and audited by CG&A. The December 31, 2015 audited CG&A reserve report did not include 3P reserves. | |
| As of December 31, | ||||||||
| Eagle Ford | 2016 | 2015(9) | ||||||
| Total proved reserves: | ||||||||
| Oil (MMBbls) | 86.7 | 35.7 | ||||||
| Gas (Bcf) | 45.1 | 33.8 | ||||||
| NGL (MMBbls) | 10.4 | 8.5 | ||||||
| Total (MMboe) | 104.7 | 49.9 | ||||||
| North Louisiana | ||||||||
| Total proved reserves: | ||||||||
| Oil (MMBbls) | 0.7 | 0.9 | ||||||
| Gas (Bcf) | 280.0 | 311.1 | ||||||
| NGL (MMBbls) | 0.5 | 0.4 | ||||||
| Total (MMboe) | 47.8 | 53.2 | ||||||
| WildHorse Resource | ||||||||
| Development (WRD) | ||||||||
| Total proved reserves: | ||||||||
| Oil (MMBbls) | 87.4 | 36.7 | ||||||
| Gas (Bcf) | 325.1 | 345.0 | ||||||
| NGL (MMBbls) | 10.9 | 8.9 | ||||||
| Total (MMboe) | 152.5 | 103.0 | ||||||
| (9) | Excludes proved reserves associated with the Burleson North acquisition that closed 12/19/16. | |
Financial Update
As of December 31, 2016, total outstanding debt was $242.8 million drawn on WRD’s revolving credit facility. Pro-forma for the 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 $495.8 million consisted of $133.3 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 adjusted 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 Update
WRD utilizes its hedging program to mitigate financial risks and commodity price volatility. As of March 29, 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 deferred puts to hedge its production. In 2017, 28% of expected oil volumes and 16% of expected natural gas volumes are hedged with deferred 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 March 29, 2017.
| 2017 | 2018 | 2019 | ||||||||||
| Natural Gas Hedge Contracts: | ||||||||||||
| Total natural gas volumes hedged (MMBtu) | 17,757,080 | 11,565,800 | 9,877,900 | |||||||||
| Total weighted-average price (10) | $3.21 | $3.03 | $2.81 | |||||||||
| Expected gas production hedged (11) | 89% | - | - | |||||||||
| Crude Oil Hedge Contracts: | ||||||||||||
| Total crude oil volumes hedged (Bbl) | 3,570,020 | 1,663,596 | 1,381,300 | |||||||||
| Total weighted-average price (10) | $53.75 | $53.72 | $54.92 | |||||||||
| Expected crude production hedged (11) | 72% | - | - | |||||||||
| Total Hedge Contracts: | ||||||||||||
| Total hedged production (boe) | 6,529,533 | 3,591,229 | 3,027,617 | |||||||||
| Total weighted-average price ($/boe) (10) | $38.11 | $34.64 | $34.24 | |||||||||
| Expected total production hedged (11) | 72% | - | - | |||||||||
| (10) | Utilizing the mid-point for collars. | |
| (11) | Using the mid-point of WRD’s 2017 guidance ranges. | |
Annual Report on Form 10-K
WRD’s financial statements and related footnotes will be available in its Annual Report on Form 10-K for the year ended December 31, 2016, which will be filed with the U.S. Securities and Exchange Commission (“SEC”) on or before March 31, 2017.
Conference Call and Webcast
WRD will host an investor conference call tomorrow morning, March 30, 2017 at 8 a.m. Central (9 a.m. Eastern) to discuss these operating and financial results. 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
Cautionary Statements and Additional Disclosures
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.
3P Reserves
WRD has provided summations of its 3P 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 the volumetric estimates for probable reserves, 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.
Management Locations
WRD has disclosed net horizontal drilling locations in this press release in the proved, probable, and possible categories as audited by CG&A, WRD’s third party engineers, as well as 650 drilling locations that have been identified by WRD’s management. WRD identified those additional locations using the same methodology as those locations to which probable and possible reserves are attributed—by using existing geologic and engineering data from vertical production and seismic data. Of those 2,350 net horizontal drilling locations, 1,700 lie within the geographic areas to which proved, probable and possible reserves are attributed. The remaining 650 management identified net horizontal drilling locations are within geographic areas to which proved, probable or possible reserves are not attributed, but nonetheless are locations that WRD has specifically identified based on its evaluation of applicable geologic and engineering data accrued over our multi-year historical drilling activities in the surrounding area. The locations have been identified by WRD’s management based on its evaluation of applicable geologic and engineering data from historical drilling activities in the surrounding area. The locations on which WRD actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors, and may differ from the locations currently identified.
Use of Non-GAAP Financial Measures
This press release and accompanying schedules include the non-GAAP financial measures of Adjusted EBITDAX, Adjusted Net Income (Loss), and Pro-Forma measures. The accompanying appendix and schedules provide a reconciliation of these non-GAAP financial measures to their most directly comparable financial measure calculated and presented in accordance with GAAP. WRD's non-GAAP financial measures should not be considered as alternatives to GAAP measures such as Net Income, operating income, net cash flows provided by operating activities or any other measure of financial performance calculated and presented in accordance with GAAP. WRD's non-GAAP financial measures may not be comparable to similarly-titled measures of other companies because they may not calculate such measures in the same manner as WRD does.
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 | $117.8 | |||
| Reserve additions (Mboe): | ||||
| Extensions, discoveries and additions | 26.9 | |||
| Performance revisions | (2.3) | |||
| Total additions | 24.6 | |||
| Total Drill-bit F&D costs ($/boe) | $4.79 | |||
|
WildHorse Resource Development Corporation Reported Operating Data |
|||||||||||||||||||
| For the Three Months | For the Year Ended | ||||||||||||||||||
| Ended December 31, | December 31, | ||||||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||||||
|
Production Volumes |
|||||||||||||||||||
| Oil Sales (MBbls) | 523 | 424 | 1,848 | 968 | |||||||||||||||
| Natural Gas Sales (MMcf) | 3,948 | 4,512 | 17,820 | 14,847 | |||||||||||||||
| NGL Sales (MBbls) | 135 | 122 | 471 | 351 | |||||||||||||||
| Total (Mboe) | 1,316 | 1,298 | 5,289 | 3,793 | |||||||||||||||
| Total (Mboe/d) | 14.3 | 14.1 | 14.5 | 10.4 | |||||||||||||||
|
Average unit costs per boe |
|||||||||||||||||||
| Lease operating expense | $3.52 | $3.43 | $2.33 | $3.70 | |||||||||||||||
| Gathering, processing and transportation | $1.16 | $1.28 | $1.24 | $1.40 | |||||||||||||||
| Taxes other than income | $1.34 | $1.36 | $1.29 | $1.45 | |||||||||||||||
| General and administrative expenses | $7.53 | $3.49 | $4.53 | $4.19 | |||||||||||||||
| Cash settlements received / | |||||||||||||||||||
| (paid) on commodity derivatives | ($0.84) | $3.57 | $0.86 | $3.15 | |||||||||||||||
|
Pro-forma - Operating Data |
|||||||||
| Three Months | Year Ended | ||||||||
| Ended December 31, | December 31, | ||||||||
| 2016 | 2016 | ||||||||
|
Production Volumes |
|||||||||
| Oil Sales (MBbls) | 753 | 2,997 | |||||||
| Natural Gas Sales (MMcf) | 4,198 | 18,959 | |||||||
| NGL Sales (MBbls) | 154 | 560 | |||||||
| Total (Mboe) | 1,607 | 6,717 | |||||||
| Total (Mboe/d) | 17.5 | 18.4 | |||||||
|
Average unit costs per boe |
|||||||||
| Lease operating expense | $4.93 | $4.13 | |||||||
| Gathering, processing and transportation | $1.10 | $1.16 | |||||||
| Taxes other than income | $1.59 | $1.52 | |||||||
| General and administrative expenses | $6.17 | $3.57 | |||||||
| Cash settlements received / | |||||||||
| (paid) on commodity derivatives | ($0.69) | $0.67 | |||||||
Calculation of Adjusted EBITDAX:
We evaluate performance based on Adjusted EBITDAX. Adjusted EBITDAX is defined as Net Income (loss), plus interest expense; debt extinguishment costs; income tax expense; depreciation, depletion and amortization; impairment of goodwill and long-lived properties; accretion of asset retirement obligations; losses on commodity derivative contracts and cash settlements received; losses on sale of properties; stock-based compensation; incentive-based compensation expenses; exploration costs; provision for environmental remediation; transaction related costs; IPO related expenses; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; gains on sale of assets and other non-routine items. The following table presents WRD’s information for the periods indicated:
|
Reported Adjusted EBITDAX |
|||||||||||||||||||||||
| For the Three Months | For the Year Ended | ||||||||||||||||||||||
| Ended December 31, | December 31, | ||||||||||||||||||||||
| (Amounts in $000s) | 2016 | 2015 | 2016 | 2015 | |||||||||||||||||||
| Net Income (loss) | $ | (17,636 | ) | $ | (5,462 | ) | $ | (47,076 | ) | $ | (33,040 | ) | |||||||||||
|
Add (Deduct): |
|||||||||||||||||||||||
| Interest expense, net | 2,225 | 1,946 | 7,834 | 6,943 | |||||||||||||||||||
| Income tax (benefit) expense | (6,025 | ) | 278 | (5,575 | ) | 604 | |||||||||||||||||
| Depreciation, depletion an amortization | 20,353 | 19,891 | 81,757 | 56,244 | |||||||||||||||||||
| Exploration expense | 3,050 | 3,885 | 12,026 | 18,299 | |||||||||||||||||||
| Impairment of proved oil and gas properties | - | 1,280 | - | 9,312 | |||||||||||||||||||
| (Gain) loss on derivative instruments | 18,077 | (6,677 | ) | 26,771 | (13,854 | ) | |||||||||||||||||
| Cash settlements received / | |||||||||||||||||||||||
| (paid) on commodity derivatives | (1,093 | ) | 4,872 | 4,975 | 11,517 | ||||||||||||||||||
| Stock-based compensation | 68 | - | 68 | - | |||||||||||||||||||
| Acquisition related costs | 430 | - | 553 | 593 | |||||||||||||||||||
| (Gain) loss on sale properties | 43 | - | 43 | - | |||||||||||||||||||
| Debt extinguishment costs | 1,309 | - | 1,667 | - | |||||||||||||||||||
| Initial public offering costs | 378 | - | 1,560 | - | |||||||||||||||||||
| Non-cash liability amortization | - | (145 | ) | (286 | ) | (760 | ) | ||||||||||||||||
| Adjusted EBITDAX | $ | 21,179 | $ | 19,868 | $ | 84,317 | $ | 55,858 | |||||||||||||||
|
Pro-forma Adjusted EBITDAX |
|||||||||||||
| Three Months | Year Ended | ||||||||||||
| Ended December 31, | December 31, | ||||||||||||
| (Amounts in $000s) | 2016 | 2016 | |||||||||||
| Net Income (loss) | $ | (13,951 | ) | $ | (34,894 | ) | |||||||
|
Add (Deduct): |
|||||||||||||
| Interest expense, net | 2,225 | 7,834 | |||||||||||
| Income tax (benefit) expense | (6,025 | ) | (5,575 | ) | |||||||||
| Depreciation, depletion an amortization | 24,109 | 98,298 | |||||||||||
| Exploration expense | 3,050 | 12,026 | |||||||||||
| Impairment of proved oil and gas properties | - | - | |||||||||||
| (Gain) loss on derivative instruments | 18,077 | 26,771 | |||||||||||
| Cash settlements received / | |||||||||||||
| (paid) on commodity derivatives | (1,093 | ) | 4,975 | ||||||||||
| Stock-based compensation | 68 | 68 | |||||||||||
| Acquisition related costs | 430 | 553 | |||||||||||
| (Gain) loss on sale properties | 43 | 43 | |||||||||||
| Debt extinguishment costs | 1,309 | 1,667 | |||||||||||
| Initial public offering costs | 378 | 1,560 | |||||||||||
| Non-cash liability amortization | - | (286 | ) | ||||||||||
| Adjusted EBITDAX | $ | 28,620 | $ | 113,040 | |||||||||
Calculation of Adjusted Net Income (Loss):
Adjusted Net Income (Loss) is a supplemental non-GAAP financial measure that is used by external users of WRD’s financial statements. We define Adjusted Net Income (Loss) as Net Income excluding the impact of certain items including gains or losses on commodity derivative instruments not yet settled, gains or losses on sales of properties, debt extinguishment costs, stock-based compensation, incentive-unit compensation expense, and the tax effects related to these adjustments. We believe Adjusted Net Income (Loss) is useful to investors because it provides readers with a more meaningful measure of our profitability before recording certain items for which the timing or amount cannot be reasonably determined. However, this measure is provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP. The following table provides a reconciliation of Net Income (Loss) as determined in accordance with GAAP to Adjusted Net Income (Loss) for the periods indicated:
|
Reported Adjusted Net Income (Loss) |
|||||||||||||||||||||||
| For the Three Months | For the Twelve Months | ||||||||||||||||||||||
| Ended December 31, | Ended December 31, | ||||||||||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||||||||||
| Net Income (loss) | $ | (17,636 | ) | $ | (5,462 | ) | $ | (47,076 | ) | $ | (33,040 | ) | |||||||||||
| Add (Deduct) | |||||||||||||||||||||||
| (Gain) loss on derivative instruments | 18,077 | (6,677 | ) | 26,771 | (13,854 | ) | |||||||||||||||||
| Cash settlements received / | |||||||||||||||||||||||
| (paid) on commodity derivatives | (1,093 | ) | 4,872 | 4,975 | 11,517 | ||||||||||||||||||
| Stock-based compensation | 68 | - | 68 | - | |||||||||||||||||||
| (Gain) loss on sale properties | 43 | - | 43 | - | |||||||||||||||||||
| Debt extinguishment costs | 1,309 | - | 1,667 | - | |||||||||||||||||||
| Adjusted net income (loss) before tax effect | 768 | (7,267 | ) | (13,552 | ) | (35,377 | ) | ||||||||||||||||
| Tax effect related to adjustments | (4,489 | ) | 9 | (4,565 | ) | 12 | |||||||||||||||||
| Adjusted net income (loss) | (3,721 | ) | (7,258 | ) | (18,117 | ) | (35,365 | ) | |||||||||||||||
|
Pro-forma Adjusted Net Income (Loss) |
||||||||||||||
| Three Months | Twelve Months | |||||||||||||
| Ended December 31, | Ended December 31, | |||||||||||||
| 2016 | 2016 | |||||||||||||
| Net Income (loss) | $ | (13,951 | ) | $ | (34,894 | ) | ||||||||
| Add (Deduct) | ||||||||||||||
| (Gain) loss on derivative instruments | 18,077 | 26,771 | ||||||||||||
| Cash settlements received / | ||||||||||||||
| (paid) on commodity derivatives | (1,093 | ) | 4,975 | |||||||||||
| Stock-based compensation | 68 | 68 | ||||||||||||
| (Gain) loss on sale properties | 43 | 43 | ||||||||||||
| Debt extinguishment costs | 1,309 | 1,667 | ||||||||||||
| Adjusted net income (loss) before tax effect | 4,453 | (1,370 | ) | |||||||||||
| Tax effect related to adjustments | (4,489 | ) | (4,565 | ) | ||||||||||
| Adjusted net income (loss) | (36 | ) | (5,935 | ) | ||||||||||
| WildHorse Resource Development Corporation | ||||||||||||
| Commodity Hedge Positions | ||||||||||||
| At December 31, 2016, WRD had the following open commodity positions: | ||||||||||||
| 2017 | 2018 | 2019 | ||||||||||
| Crude Oil Derivative Contracts: | ||||||||||||
| Swap contracts: | ||||||||||||
| Volume (Bbl) | 2,146,300 | 1,638,500 | 1,381,300 | |||||||||
| Weighted-average fixed price | $52.90 | $53.68 | $54.92 | |||||||||
| Collar contracts: | ||||||||||||
| Volume (Bbl) | 60,784 | 25,096 | - | |||||||||
| Weighted-average floor price | $50.00 | $50.00 | - | |||||||||
| Weighted-average ceiling price | $62.10 | $62.10 | - | |||||||||
| Deferred put options | ||||||||||||
| Volume (Bbl) | 636,400 | - | - | |||||||||
| Weighted-average floor price | $55.00 | - | - | |||||||||
| Weighted-average put premium | ($4.76) | - | - | |||||||||
| Natural Gas Derivative Contracts: | ||||||||||||
| Swap contracts: | ||||||||||||
| Volume (MMBtu) | 9,029,600 | 11,565,800 | 9,877,900 | |||||||||
| Weighted-average fixed price | $3.15 | $3.03 | $2.81 | |||||||||
| Collar contracts: | ||||||||||||
| Volume (MMBtu) | 5,520,000 | - | - | |||||||||
| Weighted-average floor price | $3.00 | - | - | |||||||||
| Weighted-average ceiling price | $3.36 | - | - | |||||||||
| Deferred put options | ||||||||||||
| Volume (MMBtu) | 1,068,350 | - | - | |||||||||
| Weighted-average floor price | $3.40 | - | - | |||||||||
| Weighted-average put premium | ($0.35) | - | - | |||||||||
|
WildHorse Resource Development Corporation Statements of Consolidated and Combined Operations |
|||||||||||||||||||||||
| For the Three Months | For the Year Ended | ||||||||||||||||||||||
| Ended December 31, | December 31, | ||||||||||||||||||||||
| (Amounts in 000s) | 2016 | 2015 | 2016 | 2015 | |||||||||||||||||||
|
Revenues: |
|||||||||||||||||||||||
| Oil sales | $ | 24,794 | $ | 16,628 | $ | 75,938 | $ | 42,971 | |||||||||||||||
| Natural gas sales | 11,913 | 9,860 | 43,487 | 38,665 | |||||||||||||||||||
| NGL sales | 2,150 | 1,317 | 5,786 | 4,295 | |||||||||||||||||||
| Other income | 404 | 404 | 2,131 | 404 | |||||||||||||||||||
| Total operating revenues | 39,261 | 28,209 | 127,342 | 86,335 | |||||||||||||||||||
|
Operating Expenses |
|||||||||||||||||||||||
| Lease operating expenses | 4,633 | 4,456 | 12,320 | 14,053 | |||||||||||||||||||
| Gathering, processing and transportation | 1,527 | 1,661 | 6,581 | 5,300 | |||||||||||||||||||
| Gathering system operating expense | - | 597 | 99 | 914 | |||||||||||||||||||
| Taxes other than income | 1,760 | 1,770 | 6,814 | 5,510 | |||||||||||||||||||
| Depreciation, depletion and amortization | 20,353 | 19,891 | 81,757 | 56,244 | |||||||||||||||||||
| Impairment of proved oil and gas properties | - | 1,280 | - | 9,312 | |||||||||||||||||||
| General and administrative expenses | 9,914 | 4,532 | 23,973 | 15,903 | |||||||||||||||||||
| Exploration expense | 3,050 | 3,885 | 12,026 | 18,299 | |||||||||||||||||||
| Total expenses | 41,237 | 38,072 | 143,570 | 125,535 | |||||||||||||||||||
| Income (loss) from operations | (1,976 | ) | (9,863 | ) | (16,228 | ) | (39,200 | ) | |||||||||||||||
|
Other Income (Expense): |
|||||||||||||||||||||||
| Interest expense | (2,225 | ) | (1,946 | ) | (7,834 | ) | (6,943 | ) | |||||||||||||||
| Debt extinguishment costs | (1,309 | ) | - | (1,667 | ) | - | |||||||||||||||||
| Gain (loss) on derivative instruments | (18,077 | ) | 6,677 | (26,771 | ) | 13,854 | |||||||||||||||||
| Other income (expense) | (74 | ) | (52 | ) | (151 | ) | (147 | ) | |||||||||||||||
| Total other income (expense) | (21,685 | ) | 4,679 | (36,423 | ) | 6,764 | |||||||||||||||||
| Income (loss) before income taxes | (23,661 | ) | (5,184 | ) | (52,651 | ) | (32,436 | ) | |||||||||||||||
| Income tax benefit (expense) | 6,025 | (278 | ) | 5,575 | (604 | ) | |||||||||||||||||
| Net Income (loss) | $ | (17,636 | ) | $ | (5,462 | ) | $ | (47,076 | ) | $ | (33,040 | ) | |||||||||||
| Net income (loss) allocated to previous owners | (60 | ) | (597 | ) | (2,681 | ) | (3,085 | ) | |||||||||||||||
| Net income (loss) allocated to predecessor | (7,179 | ) | (4,865 | ) | (33,998 | ) | (29,955 | ) | |||||||||||||||
| Net income (loss) available to WildHorse Resources | $ | (10,397 | ) | $ | - | $ | (10,397 | ) | $ | - | |||||||||||||
| Earnings per share | $ | (0.11 | ) | - | $ | (0.11 | ) | - | |||||||||||||||
| Weighted average shares outstanding | |||||||||||||||||||||||
| Basic and diluted | 91,327 | - | 91,327 | - | |||||||||||||||||||
|
WildHorse Resource Development Corporation Pro-forma Fourth Quarter 2016 Statements of Consolidated and Combined Operations |
|||||||||||||||||||||
| For the Three Months | |||||||||||||||||||||
| Ended December 31, 2016 | |||||||||||||||||||||
| WRD | Burleson North | Other | Pro | ||||||||||||||||||
| (Amounts in 000s) | Historical |
Acquisition |
Adjustments(12) | Forma | |||||||||||||||||
|
Revenues: |
|||||||||||||||||||||
| Oil sales | $ | 24,794 | $ | 12,549 | $ | (1,748 | ) | $ | 35,595 | ||||||||||||
| Natural gas sales | 11,913 | 757 | (108 | ) | 12,562 | ||||||||||||||||
| NGL sales | 2,150 | 349 | (43 | ) | 2,456 | ||||||||||||||||
| Other income | 404 | - | - | 404 | |||||||||||||||||
| Total operating revenues | 39,261 | 13,655 | (1,899 | ) | 51,017 | ||||||||||||||||
|
Operating Expenses |
|||||||||||||||||||||
| Lease operating expenses | 4,633 | 3,178 | 114 | 7,925 | |||||||||||||||||
| Gathering, processing and transportation | 1,527 | 253 | (20 | ) | 1,760 | ||||||||||||||||
| Taxes other than income | 1,760 | 632 | 158 | 2,550 | |||||||||||||||||
| Depreciation, depletion and amortization | 20,353 | - | 3,756 | 24,109 | |||||||||||||||||
| General and administrative expenses | 9,914 | - | - | 9,914 | |||||||||||||||||
| Exploration expense | 3,050 | - | - | 3,050 | |||||||||||||||||
| Total expenses | 41,237 | 4,063 | 4,008 | 49,308 | |||||||||||||||||
| Income (loss) from operations | (1,976 | ) | 9,592 | (5,907 | ) | 1,709 | |||||||||||||||
|
Other Income (Expense): |
|||||||||||||||||||||
| Interest expense | (2,225 | ) | - | - | (2,225 | ) | |||||||||||||||
| Debt extinguishment costs | (1,309 | ) | - | - | (1,309 | ) | |||||||||||||||
| Gain (loss) on derivative instruments | (18,077 | ) | - | - | (18,077 | ) | |||||||||||||||
| Other income (expense) | (74 | ) | - | - | (74 | ) | |||||||||||||||
| Total other income (expense) | (21,685 | ) | - | - | (21,685 | ) | |||||||||||||||
| Income (loss) before income taxes | (23,661 | ) | 9,592 | (5,907 | ) | (19,976 | ) | ||||||||||||||
| Income tax benefit (expense) | 6,025 | - | - | 6,025 | |||||||||||||||||
| Net Income (loss) | $ | (17,636 | ) | $ | 9,592 | $ | (5,907 | ) | $ | (13,951 | ) | ||||||||||
| Net income (loss) allocated to previous owners | (60 | ) | 9,592 | (5,907 | ) | 3,625 | |||||||||||||||
| Net income (loss) allocated to predecessor | (7,179 | ) | - | - | (7,179 | ) | |||||||||||||||
| Net income (loss) available to WildHorse Resources | $ | (10,397 | ) | $ | - | $ | - | $ | (10,397 | ) | |||||||||||
| Earnings per common share | $ | (0.11 | ) | $ | - | $ | - | $ | (0.11 | ) | |||||||||||
| Weighted average shares outstanding | |||||||||||||||||||||
| Basic and diluted | 91,327 | - | - | 91,327 | |||||||||||||||||
|
Production Volumes |
|||||||||||||||||||||
| Oil sales (MBbls) | 523 | 265 | (35 | ) | 753 | ||||||||||||||||
| Natural Gas Sales (MMcf) | 3,948 | 287 | (37 | ) | 4,198 | ||||||||||||||||
| NGL Sales (MBbls) | 135 | 21 | (2 | ) | 154 | ||||||||||||||||
| Total (Mboe) | 1,316 | 334 | (43 | ) | 1,607 | ||||||||||||||||
| Total (Mboe/d) | 14.3 | 3.6 | (0.4 | ) | 17.5 | ||||||||||||||||
|
Other (Amounts in $000s) |
|||||||||||||||||||||
| Stock-based compensation | $ | 68 | $ | - | $ | - | $ | 68 | |||||||||||||
| Acquisition related costs | 430 | - | - | 430 | |||||||||||||||||
| (Gain) loss on sale properties | 43 | - | - | 43 | |||||||||||||||||
| Non-cash liability amortization | - | - | - | - | |||||||||||||||||
| (12) | Other adjustments represent amounts not included on the same lease operating statements provided by CWEI during the acquisition process. These amounts include certain non-op revenues, lease operating expenses, and estimated 2016 ad valorem taxes. Depletion expense was estimated based on the adjusted cost basis of the properties acquired. | |
|
WildHorse Resource Development Corporation Pro-forma Full Year 2016 Statements of Consolidated and Combined Operations |
||||||||||||||||||||
| For the Twelve Months | ||||||||||||||||||||
| Ended December 31, 2016 | ||||||||||||||||||||
| WRD | Burleson North | Other | Pro | |||||||||||||||||
| (Amounts in 000s) | Historical |
Acquisition |
Adjustments(12) | Forma | ||||||||||||||||
|
Revenues: |
||||||||||||||||||||
| Oil sales | $ | 75,938 | $ | 46,902 | $ | (1,748 | ) | $ | 121,092 | |||||||||||
| Natural gas sales | 43,487 | 2,566 | (108 | ) | 45,945 | |||||||||||||||
| NGL sales | 5,786 | 1,171 | (43 | ) | 6,914 | |||||||||||||||
| Other income | 2,131 | - | - | 2,131 | ||||||||||||||||
| Total operating revenues | 127,342 | 50,639 | (1,899 | ) | 176,082 | |||||||||||||||
|
Operating Expenses |
||||||||||||||||||||
| Lease operating expenses | 12,320 | 15,295 | 114 | 27,729 | ||||||||||||||||
| Gathering, processing and transportation | 6,581 | 1,263 | (19 | ) | 7,825 | |||||||||||||||
| Gathering system operating expense | 99 | - | - | 99 | ||||||||||||||||
| Taxes other than income | 6,814 | 2,339 | 1,025 | 10,178 | ||||||||||||||||
| Depreciation, depletion and amortization | 81,757 | - | 16,541 | 98,298 | ||||||||||||||||
| General and administrative expenses | 23,973 | - | - | 23,973 | ||||||||||||||||
| Exploration expense | 12,026 | - | - | 12,026 | ||||||||||||||||
| Total expenses | 143,570 | 18,897 | 17,661 | 180,128 | ||||||||||||||||
| Income (loss) from operations | (16,228 | ) | 31,742 | (19,560 | ) | (4,046 | ) | |||||||||||||
|
Other Income (Expense): |
||||||||||||||||||||
| Interest expense | (7,834 | ) | - | - | (7,834 | ) | ||||||||||||||
| Debt extinguishment costs | (1,667 | ) | - | - | (1,667 | ) | ||||||||||||||
| Gain (loss) on derivative instruments | (26,771 | ) | - | - | (26,771 | ) | ||||||||||||||
| Other income (expense) | (151 | ) | - | - | (151 | ) | ||||||||||||||
| Total other income (expense) | (36,423 | ) | - | - | (36,423 | ) | ||||||||||||||
| Income (loss) before income taxes | (52,651 | ) | 31,742 | (19,560 | ) | (40,469 | ) | |||||||||||||
| Income tax benefit (expense) | 5,575 | - | - | 5,575 | ||||||||||||||||
| Net Income (loss) | $ | (47,076 | ) | $ | 31,742 | $ | (19,560 | ) | $ | (34,894 | ) | |||||||||
| Net income (loss) allocated to previous owners | (2,681 | ) | 31,742 | (19,560 | ) | 9,501 | ||||||||||||||
| Net income (loss) allocated to predecessor | (33,998 | ) | - | - | (33,998 | ) | ||||||||||||||
| Net income (loss) available to WildHorse Resources | $ | (10,397 | ) | $ | - | $ | - | $ | (10,397 | ) | ||||||||||
| Earnings per common share | $ | (0.11 | ) | $ | - | $ | - | $ | (0.11 | ) | ||||||||||
| Weighted average shares outstanding | ||||||||||||||||||||
|
Basic and diluted |
91,327 | - | - | 91,327 | ||||||||||||||||
|
|
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|
Production Volumes |
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| Oil sales (MBbls) | 1,848 | 1,184 | (35 | ) | 2,997 | |||||||||||||||
| Natural Gas Sales (MMcf) | 17,820 | 1,177 | (38 | ) | 18,959 | |||||||||||||||
| NGL Sales (MBbls) | 471 | 91 | (2 | ) | 560 | |||||||||||||||
| Total (Mboe) | 5,289 | 1,471 | (43 | ) | 6,717 | |||||||||||||||
| Total (Mboe/d) | 14.5 | 4.0 | (0.1 | ) | 18.4 | |||||||||||||||
|
Other (Amounts in $000s) |
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| Stock-based compensation | $ | 68 | $ | - | $ | - | $ | 68 | ||||||||||||
| Acquisition related costs | 553 | - | - | 553 | ||||||||||||||||
| (Gain) loss on sale properties | 43 | - | - | 43 | ||||||||||||||||
| Non-cash liability amortization | (286 | ) | - | - | (286 | ) | ||||||||||||||
| (12) | Other adjustments represent amounts not included on the same lease operating statements provided by CWEI during the acquisition process. These amounts include non-op revenues, lease operating expenses, and estimated 2016 ad valorem taxes. Depletion expense was estimated based on the adjusted cost basis of the properties acquired. |
|
WildHorse Resource Development Corporation Statement of Consolidated and Combined Cash Flows |
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|
|
For the Three Months Ended December 31, |
For the Year Ended December 31, |
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| (Amounts in $000s) | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||||
| Net Income (Loss) | $ | (17,636 | ) | $ | (5,462 | ) | $ | (47,076 | ) | $ | (33,040 | ) | ||||||||
| Adjustments to reconcile net income (loss) to cash flows | ||||||||||||||||||||
|
provided by operating activities |
||||||||||||||||||||
| Depreciation, depletion and amortization | 20,245 | 19,794 | 81,350 | 55,890 | ||||||||||||||||
|
Accretion of asset retirement obligations |
108 | 96 | 407 | 354 | ||||||||||||||||
| Impairment of proved oil and gas properties | - | 1,280 | - | 9,312 | ||||||||||||||||
| Dry hole expense and impairments of unproved properties | 2,989 | 3,254 | 3,051 | 11,780 | ||||||||||||||||
| Amortization of debt issuance costs | 137 | 235 | 479 | 711 | ||||||||||||||||
| (Gain) loss on derivative instruments | 18,079 | (6,677 | ) | 26,771 | (13,854 | ) | ||||||||||||||
|
Cash settlements on derivative instruments |
(1,093 | ) | 4,872 | 4,975 | 11,517 | |||||||||||||||
| Deferred income tax expense | (6,010 | ) | 213 | (5,575 | ) | 604 | ||||||||||||||
| Debt extinguishment expense | 1,309 | - | 1,667 | - | ||||||||||||||||
| Amortization of equity awards | 68 | - | 68 | - | ||||||||||||||||
| (Gain) loss on sale of properties | 43 | - | 43 | - | ||||||||||||||||
| Changes in operating assets and liabilities | (20,251 | ) | 6,404 | (43,898 | ) | 6,822 | ||||||||||||||
| Net cash provided by operating activities | (2,012 | ) | 24,009 | 22,262 | 50,096 | |||||||||||||||
| Cash flows from investing activities: | (468,709 | ) | (104,900 | ) | (567,545 | ) | (443,639 | ) | ||||||||||||
| Cash flows from financing activities: | 472,385 | 73,377 | 505,272 | 424,481 | ||||||||||||||||
| Net Change in Cash and Cash Equivalents | $ | 1,664 | $ | (7,514 | ) | $ | (40,011 | ) | $ | 30,938 | ||||||||||
| Cash and Cash Equivalents, Begin of Period | 1,451 | 50,640 | 43,126 | 12,188 | ||||||||||||||||
| Cash and Cash Equivalents, End of Period | 3,115 | 43,126 | 3,115 | 43,126 | ||||||||||||||||
|
WildHorse Resource Development Corporation Consolidated and Combined Balance Sheet |
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|
|
For the Year Ended December 31, |
|||||||||
| (Amounts in $000s) | 2016 | 2015 | ||||||||
| ASSETS | ||||||||||
| Current Assets: | ||||||||||
| Cash and cash equivalents | $ | 3,115 | $ | 43,126 | ||||||
| Accounts receivable, net | 26,428 | 13,737 | ||||||||
| Short-term derivative instruments | - | 7,076 | ||||||||
| Prepaid expenses and other current assets | 1,633 | 2,830 | ||||||||
| Total Current Assets | 31,176 | 66,769 | ||||||||
| Property & equipment: | ||||||||||
| Oil and natural gas properties | 1,573,848 | 983,972 | ||||||||
| Other property and equipment | 34,344 | 30,609 | ||||||||
| Accumulated depreciation, depletion and impairment | (200,293 | ) | (118,943 | ) | ||||||
| Total property and equipment, net | 1,407,899 | 895,638 | ||||||||
| Other noncurrent assets | ||||||||||
| Restricted cash | 886 | 551 | ||||||||
| Long-term derivative instruments | - | 2,440 | ||||||||
| Debt issuance costs | 2,320 | 967 | ||||||||
| Total Assets | $ | 1,442,281 | $ | 966,365 | ||||||
| LIABILITIES AND EQUITY | ||||||||||
| Current Liabilities: | ||||||||||
| Accounts payable | $ | 21,014 | $ | 34,843 | ||||||
| Accrued liabilities | 23,371 | 28,782 | ||||||||
| Short-term derivative instruments | 14,087 | - | ||||||||
| Asset retirement obligations | 90 | 90 | ||||||||
| Total Current Liabilities | 58,562 | 63,715 | ||||||||
| Noncurrent Liabilities: | ||||||||||
| Long-term debt | 242,750 | 237,857 | ||||||||
| Asset retirement obligations | 10,943 | 6,930 | ||||||||
| Notes payable to members | - | 6,438 | ||||||||
| Deferred tax liabilities | 112,552 | 852 | ||||||||
| Long-term derivative instruments | 8,091 | - | ||||||||
| Other long-term liabilities | 1,495 | 1,884 | ||||||||
| Total liabilities | 434,393 | 317,676 | ||||||||
| Stockholders' equity: | ||||||||||
| Common stock | 917 | - | ||||||||
| Additional paid-in capital | 1,017,368 | - | ||||||||
| Accumulated earnings (deficit) | (10,397 | ) | - | |||||||
|
Total stockholders' equity |
1,007,888 | - | ||||||||
| Predecessor | - | 274,133 | ||||||||
| Previous owners | - | 374,556 | ||||||||
| Total Equity | 1,007,888 | 648,689 | ||||||||
| Total Liabilities & Equity | $ | 1,442,281 | $ | 966,365 | ||||||
