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| 8-K - 8-K - WildHorse Resource Development Corp | d537114d8k.htm |
Exhibit 99.1
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WildHorse Resource Development Corporation Announces Fourth Quarter
and Full Year 2017 Results
HOUSTON, March 7, 2018 – WildHorse Resource Development Corporation (NYSE: WRD) announced today its operating and financial results for the fourth quarter and year ended December 31, 2017. Financial and operational highlights for the fourth quarter and full year 2017 include:
| • | Delivered fourth quarter 2017 average daily production of 45.9 Mboe/d and full year 2017 average daily production of 30.7 Mboe/d, exceeding the mid-point of annual guidance by over 1.7 Mboe/d |
| • | Reported Net Income of $14.1 million for the fourth quarter 2017 and $49.9 million for the full year 2017 |
| • | Reported Net Income available to common stockholders of $5.6 million or $0.06 per share for the fourth quarter 2017 and $31.1 million or $0.32 per share for the full year 2017 |
| • | Reported Adjusted Net Income available to common stockholders(1) of $22.5 million or $0.23 per share for the fourth quarter 2017 and $41.8 million or $0.43 per share for the full year 2017 |
| • | Reported Adjusted EBITDAX(1) of $138.0 million for the fourth quarter 2017 and $323.3 million for the full year 2017 |
| • | Brought online 37 gross (35.7 net) horizontal wells in the fourth quarter of 2017 including 30 gross (29.4 net) wells in the Eagle Ford, 1 gross (1.0 net) Austin Chalk well, and 6 gross (5.3 net) wells in North Louisiana |
| • | Brought online 10 gross wells on the Anadarko/KKR acquired acreage |
| • | Brought online 2 additional Eagle Ford step out wells |
| • | Brought online an Austin Chalk well in Washington County, the Lillie Hohlt #1H, which came online at an IP-30(2) of 2,604 Boe/d or 15.6 MMcfe/d (66% natural gas, 31% NGLs, and 3% oil) on a 4,815’ lateral |
| • | Brought online six wells in North Louisiana with IP-30 rates averaging 14% above the Upper Red type curve |
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| • | Achieved an average drilling time of 13.8 days from spud to rig release on all Eagle Ford rigs in the fourth quarter |
| • | Exited 2017 with 21 gross (19.3 net) wells in the process of drilling, completion, or awaiting completion |
First Quarter 2018 Highlights:
| • | Brought online an Austin Chalk well, the Brollier AC #1H, at a peak 24hr rate of 3,016 Boe/d and an IP-30 of 2,704 Boe/d or 16.2 MMcfe/d (61% natural gas, 30% NGLs and 9% oil) on a 5,684’ lateral |
| • | Brought online the Fritsche 109 #1 refrac, located 10.5 miles southwest of the Lee and Burleson County line, at a peak 30-day uplift(3) of 481 Boe/d (88% oil) on a 5,387’ lateral. |
| • | Closed the acquisition of 17,453 net acres and 110 net locations in Lee County, TX for approximately $18.6 million |
| • | Agreed to divest WRD’s North Louisiana assets to a third party for consideration of $217 million in cash and up to $35 million based on the number of wells spud on the North Louisiana assets over the next four years. The sale is expected to close on or about March 30, 2018 with an effective date of January 1, 2018 |
Key milestones achieved in 2017 (as previously announced on February 12, 2018):
| • | Brought online 93 gross (90.7 net) horizontal wells in 2017 including 82 gross (81.0 net) Eagle Ford wells, 3 gross (3.0 net) Austin Chalk wells, and 8 gross (6.7 net) wells in North Louisiana. A total of 98 Gen 3 Eagle Ford wells are online as of year-end 2017 |
| • | Increased proved reserves by 198% to 454.3 MMboe at year-end 2017 from 152.5 MMboe at year-end 2016 |
| • | Increased proved, probable and possible (“3P”)(4) reserves by 131% to 1,892.2 MMboe at year-end 2017 from 818.9 MMboe at year-end 2016 |
| • | Increased PV-10(5) of proved reserves by 372% to $3.539 billion at year-end 2017 from $750 million at year-end 2016 |
| • | Drill-bit finding and development (“F&D”)(6) costs, excluding acquisitions and price revisions, averaged $3.36 per Boe |
| • | Replaced 2,096% of production in 2017 including performance revisions and excluding price revisions and acquisitions |
| • | Raised the Eagle Ford type curve to an EUR of 95 Boe per foot from 91 Boe per foot |
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| • | Increased the number of Eagle Ford locations at the 95 Boe per foot type curve to 3,154 net locations from 1,996 net locations post the close of the Anadarko/KKR acquisition on June 30, 2017 |
| • | Released a Washington County Austin Chalk budget type curve and location count |
| • | Increased the borrowing base on WRD’s revolving credit facility to $875 million from $450 million at year-end 2016 |
| • | Closed $594 million Anadarko/KKR acquisition of approximately 111,000 net acres in the Eagle Ford |
| • | Closed financing of $435 million Series A Perpetual Convertible Preferred Stock |
| • | Issued $500 million of senior unsecured notes due 2025 at 6.875% |
“We are very proud of our achievements in 2017. In the matter of a year, we have more than doubled our production, reserves, and PV-10(5) valuation. This has all been accomplished while ending 2017 with a Net Debt(1) to annualized fourth quarter adjusted EBITDAX(1) ratio of 1.4x and almost doubling our borrowing base. In addition, our location count has grown significantly, our Austin Chalk wells continue to outperform expectations, and our Eagle Ford type curve has been raised for the fourth time since our Eagle Ford drilling program began in 2014,” said Chairman and Chief Executive Officer, Jay Graham.
“In addition, 2018 holds the potential to be even more exciting. Our planned in-field sand mine will set WRD on a course which takes advantage of our size and scale in the basin and could reduce well costs from $400,000 to $600,000 per well. We look forward to executing our 2018 plan and delineating even more of our acreage position,” added Jay Graham.
WRD discusses fourth quarter and full year 2017 results below. Please see the supplemental financial information in the Appendix section of this press release for a reconciliation of the non-GAAP financial measures of Adjusted EBITDAX and Adjusted Net Income (Loss) available to common stockholders(1) to GAAP financial measures and pro-forma measures mentioned in the press release.
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Fourth Quarter 2017 Results
Net production was 45.9 Mboe/d for the fourth quarter 2017 compared to 14.3 Mboe/d for the fourth quarter 2016. Fourth quarter 2017 net production consisted of approximately 62% oil, 28% natural gas, and 10% NGLs. The Eagle Ford represented 36.0 Mboe/d of total production (78% oil), and North Louisiana represented 59.3 MMcfe/d of total production (96% natural gas).
Separate from the North Louisiana divestiture, WRD reached a settlement with a third party regarding previously unrecognized acreage and associated production in North Louisiana. As a result of the settlement, WRD’s reported fourth quarter 2017 production was 2.1 Mboe/d higher than the preliminary fourth quarter production estimate of 43.8 Mboe/d released on February 12, 2018. The settlement provided WRD with higher working interests and accompanying production from certain wells which had previously been held in suspense. In addition, the settlement resulted in an increase to capital expenditures of $8.1 million.
WRD reported Net Income of $14.1 million for the fourth quarter 2017 compared to a Net Loss for the fourth quarter 2016 of $17.6 million. Net Income available to common stockholders was $5.6 million or $0.06 per share for the fourth quarter 2017. The North Louisiana settlement resulted in a non-cash loss before taxes of $7.0 million recognized in the fourth quarter of 2017.
Adjusted Net Income available to common stockholders(1) for the fourth quarter 2017 was $22.5 million or $0.23 per share. One of the adjusting items in the fourth quarter and full year 2017 was a non-cash income tax benefit of $43.4 million related to the revaluation of WRD’s deferred tax liability and certain other items resulting from the Tax Cuts and Jobs Act. WRD’s effective income tax rate is expected at approximately 23% in 2018, reflecting the enactment of the Tax Cuts and Jobs Act that lowered the corporate federal income tax rate. WRD reported Adjusted EBITDAX(1) for the fourth quarter 2017 of $138.0 million compared to Adjusted EBITDAX(1) for the fourth quarter 2016 of $21.2 million.
Total revenues for the fourth quarter 2017 were $180.2 million compared to $39.3 million for the fourth quarter 2016. Increased production as a result of operations and acquisitions along with favorable pricing variances were primarily responsible for the difference between fourth quarter 2017 and fourth quarter 2016 revenues.
Average realized prices for the fourth quarter 2017 and 2016, before the effect of commodity derivatives, are presented below:
| Q4’17 | Q4’16 | Percent Change |
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| Oil (per Bbl) |
$ | 57.99 | $ | 47.41 | 22 | % | ||||||
| Natural Gas (per Mcf) |
$ | 2.73 | $ | 3.02 | -10 | % | ||||||
| NGL (per BbL) |
$ | 23.43 | $ | 15.88 | 48 | % | ||||||
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| Total (per Boe) |
$ | 42.68 | $ | 29.52 | 45 | % | ||||||
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Average realized prices for the fourth quarter 2017 and 2016, after the effect of commodity derivatives, are presented below:
| Q4’17 | Q4’16 | Percent Change |
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| Oil (per Bbl) |
$ | 53.54 | $ | 46.23 | 16 | % | ||||||
| Natural Gas (per Mcf) |
$ | 2.83 | $ | 2.89 | -2 | % | ||||||
| NGL (per BbL) |
$ | 23.43 | $ | 15.88 | 48 | % | ||||||
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| Total (per Boe) |
$ | 40.12 | $ | 28.68 | 40 | % | ||||||
Lease operating expense (“LOE”) for the fourth quarter 2017 was $13.6 million, or $3.22 per Boe, compared to $4.6 million, or $3.52 per Boe, for the fourth quarter 2016.
Gathering, processing and transportation expense for the fourth quarter 2017 was $4.5 million, or $1.07 per Boe, compared to $1.5 million, or $1.16 per Boe in the fourth quarter 2016.
Taxes other than income were $9.7 million for the fourth quarter 2017, or $2.30 per Boe, compared to $1.8 million, or $1.34 per Boe, for the fourth quarter 2016. In the fourth quarter 2017, taxes other than income increased primarily due to higher price realizations, changes in commodity mix, higher ad valorem taxes associated with increased property valuations, and Louisiana franchise taxes incurred as a result of corporate reorganization at WRD’s initial public offering during fourth quarter of 2016.
General and administrative (“G&A”) expense for the fourth quarter 2017 was $12.1 million, or $2.87 per Boe, compared to $9.9 million, or $7.53 per Boe, for the fourth quarter 2016. During the fourth quarter of 2017, G&A expense included $2.4 million, or $0.58 per Boe, of stock-based compensation expense and $0.6 million, or $0.13 per Boe, of acquisition related costs. Cash G&A expense excluding acquisition related costs for the fourth quarter 2017 was $9.1 million, or $2.16 per Boe. In 2017, the employee head count grew from 85 employees at year-end 2016 to 137 employees.
Net interest expense during the fourth quarter 2017 was $11.0 million, including amortization of deferred financing fees of approximately $0.6 million. This compares to net interest expense during the fourth quarter 2016 of $2.2 million, including amortization of deferred financing fees of approximately $0.1 million.
Drilling and completion (“D&C”) capital expenditures were approximately $266.3 million in the fourth quarter 2017 in comparison to $33.7 million in fourth quarter 2016. Fourth quarter capital expenditures include $8.1 million due to the North Louisiana settlement.
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Full Year 2017 Results
Production increased 112% year-over-year to 30.7 Mboe/d in 2017 compared to 14.5 Mboe/d in 2016. Full year 2017 net production consisted of approximately 59% oil, 30% natural gas, and 11% NGLs. WRD exceeded the mid-point of full year 2017 guidance by over 1,700 Boe/d. This production is in addition to the 1,000 Boe/d upward guidance revision due to outperformance announced in May 2017. The Eagle Ford represented 23.5 Mboe/d of total production (76% oil), and North Louisiana represented 43.5 MMcfe/d of total production (96% natural gas).
WRD reported Net Income of $49.9 million for the full year 2017 compared to a Net Loss for the full year 2016 of $47.1 million. Net Income available to common stockholders for 2017 was $31.1 million or $0.32 per share.
Adjusted Net Income available to common stockholders(1) for 2017 was $41.8 million or $0.43 per share. WRD also reported Adjusted EBITDAX(1) for 2017 of $323.3 million compared to $84.3 million for 2016.
In 2017, total revenues were $427.2 million compared to $127.3 million for 2016. Total revenues do not include the impact of realized hedges. Greater total production, higher commodity prices, and a higher percentage of oil in the production mix contributed to an increase in oil, natural gas and NGL revenues in 2017. Average realized prices for the years ended December 31, 2017 and 2016, before the effect of commodity derivatives, are presented below:
| 2017 | 2016 | Percent Change |
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| Oil (per Bbl) |
$ | 51.90 | $ | 41.09 | 26 | % | ||||||
| Natural Gas (per Mcf) |
$ | 2.93 | $ | 2.44 | 20 | % | ||||||
| NGL (per BbL) |
$ | 19.04 | $ | 12.28 | 55 | % | ||||||
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| Total (per Boe) |
$ | 37.94 | $ | 23.67 | 60 | % | ||||||
Average realized prices for the years ended December 31, 2017 and 2016, after the effect of commodity derivatives, are presented below:
| 2017 | 2016 | Percent Change |
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| Oil (per Bbl) |
$ | 51.31 | $ | 41.83 | 23 | % | ||||||
| Natural Gas (per Mcf) |
$ | 2.96 | $ | 2.62 | 13 | % | ||||||
| NGL (per BbL) |
$ | 19.04 | $ | 12.28 | 55 | % | ||||||
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| Total (per Boe) |
$ | 37.64 | $ | 24.53 | 53 | % | ||||||
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LOE for 2017 was $39.8 million, or $3.54 per Boe, compared to $12.3 million, or $2.33 per Boe, in 2016. In 2017, WRD recorded $7.7 million of workover expenses used to increase efficiency on legacy wells. In addition, full year 2017 LOE was greater as a result of higher cost LOE production acquired with the Clayton Williams acquisition in late fourth quarter 2016 and the Anadarko/KKR acquisition at the end of the second quarter 2017.
Gathering, processing and transportation expense for 2017 was $11.9 million, or $1.06 per Boe, compared to $6.6 million, or $1.24 per Boe in 2016.
Taxes other than income were $24.2 million for 2017, or $2.15 per Boe, compared to $6.8 million, or $1.29 per Boe, for the previous year. On a Boe basis, taxes other than income increased in 2017 due primarily to higher realized commodity prices.
G&A expense for 2017 was $40.7 million, or $3.62 per Boe, compared to $24.0 million, or $4.53 per Boe, for 2016. During 2017, G&A expense included $6.6 million, or $0.59 per Boe, of stock-based compensation expense and $4.5 million, or $0.40 per Boe, of acquisition and IPO related costs. Cash G&A expense excluding acquisition and IPO related costs for 2017 was $29.5 million, or $2.63 per Boe. The increase in G&A expense was primarily due to greater staffing and expenses associated with operating as a public company.
Net interest expense during 2017 was $31.9 million, including amortization of deferred financing fees of approximately $2.6 million. This compares to net interest expense during 2016 of $7.8 million, including amortization of deferred financing fees of approximately $0.5 million.
For full year 2017, D&C capital expenditures totaled $744.2 million. Leasehold and acquisitions totaled $651.8 million in 2017. In full year 2016, D&C capital expenditures totaled $100.6 million. Leasehold and acquisitions totaled $470.5 million in 2016. Average working interest for all wells in 2017 was 97%, which surpassed WRD’s 2017 guidance of 89%. In addition, WRD exited 2017 with 21 gross (19.3 net) wells in the process of drilling, completion, or awaiting completion, which results in some capex benefitting the 2018 program.
| (1) | Adjusted EBITDAX, Adjusted Net Income (Loss) available to common stockholders, Cash G&A, and Net Debt are financial measures not calculated in accordance with accounting principles generally accepted in the United States of America (“GAAP”). 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. |
| (2) | The initial production rates represent the peak average of the initial production rates for the applicable consecutive days of production. |
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| (3) | The initial production rates represent the peak average of the initial production rates for the applicable consecutive days of production. The refrac uplift is an estimate of the additional production incurred as a result of the refrac over what the legacy well would have otherwise produced without a refrac completion. |
| (4) | See “Cautionary Statements and Additional Disclosures” in the Appendix section of this press release for more information regarding 3P reserves. |
| (5) | 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 |
| (6) | 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. |
Operational Update
WRD brought online 37 gross (35.7 net) horizontal wells in the fourth quarter of 2017 including 30 gross (29.4 net) Eagle Ford, 1 gross (1.0 net) Austin Chalk, and 6 gross (5.3 net) North Louisiana wells during the fourth quarter 2017. Of the Eagle Ford wells, 10 gross wells were located on the recently acquired Anadarko/KKR acreage. During the quarter, Eagle Ford wells were drilled at an average of 13.8 days under the target of 14 days from spud to rig release.
Also in the fourth quarter of 2017 as previously announced, WRD brought online an Austin Chalk well in Washington County, the Lillie Hohlt #1H, which came online at an IP-30(2) of 2,604 Boe/d or 15.6 MMcfe/d (66% natural gas, 31% NGLs, and 3% oil) on a 4,815’ lateral.
In addition, during the first quarter of 2018, WRD brought on another Austin Chalk well in Washington County, the Brollier AC #1H. Since the 2018 guidance release on February 12th, the Brollier’s production has continued to increase reaching a peak 24-hour rate of 3,016 Boe/d and an IP-30(2) of 2,704 Boe/d or 16.2 MMcfe/d (61% natural gas, 30% NGLs, and 9% oil) on a 5,684’ lateral. The Brollier’s production may continue to peak with additional days online.
These two Austin Chalk wells are located 5 and 6 miles northeast of the Winkelmann #1H, respectively. The wells were drilled at an average of 25 days per well from spud to rig release which is below the budgeted drilling time of 30 days per well.
In addition, as previously announced, WRD also brought online a two-well step out pad during the fourth quarter, the Wilde EF 1H and Teal EF 1H, representing the northernmost Gen 3 Eagle Ford wells brought online at year-end 2017. The pad averaged an IP-30(2) of 602 Boe/d (93% oil) on a 6,513’ lateral and is currently tracking an average EUR of 84 Bo per foot which is above the Eagle Ford type curve. These wells were considered outside of CG&A’s 3P reserve area at year-end 2016 and are located close to the northern tip of Burleson County near the Brazos County line. The Wilde and Teal bring the total number of step-outs to 7 wells in 2017 outside of CG&A’s 3P reserve area based on the year-end 2016 reserve report.
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In North Louisiana, WRD brought online the 3-well Henderson pad on a restricted choke at a combined 30-day rate of 38.7 MMcfe/d or an average of 12.9 MMcfe/d on a 7,296’ lateral and the 3-well Shriners pad on a restricted choke at a combined 30-day rate of 38.2 MMcfe/d or an average of 12.7 MMcfe/d on a 7,381’ lateral during the fourth quarter of 2017. The average IP-30 of the six wells, adjusted for lateral length, exceeded the North Louisiana Upper Red type curve by 14%. Average working interest on the six wells was 89%, above the budgeted working interest of 58% on February 2017.
2018 Development Plan (including North Louisiana)
WRD projects 2018 average daily production between 53—56 Mboe/d consisting of 31 – 35 Mbbls/d of oil, 90 – 100 MMcf/d of natural gas, and 5 – 7 Mbbls/d of NGLs. At the mid-point of guidance, this represents a total production growth rate of 78% over 2017’s average daily production.
WRD estimates a fiscal year 2018 D&C capex budget of approximately $700—$800 million. Drilling and completion activity will be weighted toward the first half of 2018 as WRD transitions from 7.0 rigs at the beginning of the year to 4.0 rigs at mid-year for an average of 4.8 rigs in the Eagle Ford and Austin Chalk during 2018. WRD has no commitments on its drilling rig fleet. In addition, WRD expects to transition from 4.0 completion crews in the first half of the year to 3.0 completion crews in the second half of 2018.
The budget also allocates between $65—$75 million of non-D&C capital expenditure for the acquisition, evaluation, and construction of WRD’s recently announced sand mine which is expected to produce savings of $400,000 to $600,000 per well upon completion by the first quarter of 2019. WRD expects its capital budget to be funded by cash on hand, the anticipated proceeds of the North Louisiana divestiture, and borrowings under its revolving credit facility.
For the full year 2018, WRD expects to spud 100 to 110 gross wells and to bring online 100 to 110 gross wells which include 90 – 100 Eagle Ford wells and 8 Austin Chalk wells. For wells brought online in 2018, WRD estimates an average working interest of approximately 93% in the Eagle Ford and 96% in the Austin Chalk.
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The table below shows WRD’s fiscal year 2018 guidance and the effect of the announced North Louisiana divestiture on the guidance plan. The difference between the guidance scenarios reflects only the impact of the North Louisiana divestiture and does not include any material changes in drilling or completion activity as almost 100% of capital spending is allocated to the Eagle Ford and Austin Chalk in either scenario. Both scenarios include production for the first quarter of 2018 from North Louisiana because the divestiture is expected to close on or about March 30, 2018.
| FY 2018 Guidance | Pro-Forma FY 2018 Guidance North Louisiana Divestiture(9) | |||||||||||||||
| Low | High | Low | High | |||||||||||||
| Net Average Daily Production (Mboe/d) |
53 | - | 56 | 46 | - | 49 | ||||||||||
| Oil (Mbbls/d) |
31 | - | 35 | 31 | - | 35 | ||||||||||
| Natural Gas (MMcf/d) |
90 | - | 100 | 45 | - | 55 | ||||||||||
| NGLs (Mbbls/d) |
5 | - | 7 | 5 | - | 7 | ||||||||||
| Average Costs (per Boe) |
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| Lease Operating Expense |
($2.80) | - | ($3.30) | ($2.90) | - | ($3.40) | ||||||||||
| Gathering, Processing, and Transportation |
($1.10) | - | ($1.40) | ($1.10) | - | ($1.40) | ||||||||||
| Cash General and Administrative(7) |
($1.65) | - | ($2.15) | ($2.00) | - | ($2.50) | ||||||||||
| Taxes Other than Income (% of oil & gas revenue) |
5.0% | - | 6.0% | 5.0% | - | 6.0% | ||||||||||
| Commodity Price Realizations (Unhedged)(8) |
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| Crude Oil Realized Price (% of WTI NYMEX) |
98% | - | 102% | 98% | - | 102% | ||||||||||
| Natural Gas Realized Price (% of NYMEX to Henry Hub) |
94% | - | 98% | 90% | - | 94% | ||||||||||
| NGL Realized Price (% of WTI NYMEX) |
33% | - | 37% | 33% | - | 37% | ||||||||||
| Drilling Program |
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| Wells Spud (Gross) |
100 | - | 110 | 100 | - | 110 | ||||||||||
| Wells Completed (Gross) |
100 | - | 110 | 100 | - | 110 | ||||||||||
| D&C Capital Expenditure ($MM) |
$700 | - | $800 | $700 | - | $800 | ||||||||||
| Sand Mine Capital Expenditure ($MM) |
$65 | - | $75 | $65 | - | $75 | ||||||||||
Note: Guidance as of February 12, 2018
| (7) | 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. See “Cautionary Statements and Additional Disclosures” in the Appendix section of this press release for more information. |
| (8) | Based on strip pricing as of February 9, 2018. |
| (9) | Pro-Forma 2018 North Louisiana divestiture guidance assumes the pending divestiture announced on February 12, 2018 closes on or about March 30, 2018. |
Year-End 2017 Proved and 3P Reserves
On February 12, 2018, WRD announced Cawley Gillespie & Associates (“CG&A”) audited year-end 2017 proved reserves of 454.3 MMboe, an increase of 198% from 152.5 MMboe at year-end 2016. The PV-10(5) of proved reserves increased by 372% to $3.539 billion at year-end 2017 from $750 million at year-end 2016. CG&A audited proved, probable and possible (“3P”)(4) reserves at year-end 2017 were 1,892.2 MMboe, a 131% increase over 818.9 MMboe at year-end 2016. In addition, WRD increased its type curve to 95 Boe per foot from 91 Boe per foot.
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As of December 31, 2017, management estimates 3,154 net locations at the 95 Boe type curve, a 58% increase from 1,996 locations at year-end 2016. Total net horizontal locations were 3,849 net locations including 3,154 net locations in the Eagle Ford, 53 net locations in the Austin Chalk, and 642 net locations in North Louisiana. Of WRD’s total 3,849 net horizontal locations, 3,099, or 81%, are included within CG&A’s 3P(4) geographic area as of the year-end 2017 reserve report, from 1,700 net locations, or 52%, within the 3P geographic area after the close of the Anadarko/KKR acquisition on June 30, 2017.
WRD replaced 2,096% of production in 2017 including performance revisions and excluding price revisions and acquisitions. Drill-bit F&D(6) costs for proved reserve additions averaged $3.36 per Boe based on D&C capital expenditures in 2017, including facilities and capital workovers. The reserve life of WRD’s proved reserves, based on 2017 production, is approximately 41 years. See below WRD’s proved reserves by operating region:
| Total Proved Reserves | Eagle Ford | North Louisiana | Total WRD | |||||||||||||||||||||
| As of December 31, | As of December 31, | As of December 31, | ||||||||||||||||||||||
| 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | |||||||||||||||||||
| Oil (MMBbls) |
86.7 | 281.6 | 0.7 | 1.2 | 87.4 | 282.8 | ||||||||||||||||||
| Gas (Bcf) |
45.1 | 281.2 | 280.0 | 402.6 | 325.1 | 683.8 | ||||||||||||||||||
| NGL (MMBbls) |
10.4 | 57.1 | 0.5 | 0.4 | 10.9 | 57.5 | ||||||||||||||||||
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| Total (MMboe) |
104.7 | 385.6 | 47.8 | 68.7 | 152.5 | 454.3 | ||||||||||||||||||
| SEC PV-10 ($MM)(5) |
$ | 626.4 | $ | 3,208.8 | $ | 123.6 | $ | 330.5 | $ | 750.0 | $ | 3,539.3 | ||||||||||||
Financial Update
As of December 31, 2017, total net debt was $786.2 million including $500 million of senior unsecured notes, $286.4 million of borrowings under WRD’s revolving credit facility, and $0.2 million in cash. WRD’s current borrowing base under its revolving credit facility is $875 million. The next borrowing base redetermination using year-end 2017 reserves is on or about March 31, 2018. As of December 31, 2017, WRD’s liquidity of $588.8 million consisted of $0.2 million of cash and cash equivalents and $588.6 million of availability under its revolving credit facility. Year-end 2017 Net Debt to annualized fourth quarter adjusted EBITDAX was 1.4x. Under the 2018 budget plan, WRD is projected to maintain a Net Debt to annualized adjusted EBITDAX ratio of less than 2.0x throughout the year. WRD’s liquidity position is expected to be sufficient to finance anticipated working capital and capital expenditures.
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Hedging Update
As of February 12, 2018, 22% of expected oil volumes in 2018 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 including North Louisiana). As a result, 43% of WRD’s expected oil volumes are unhedged to the upside and benefit from rising oil prices.
Total hedged production in the fourth quarter of 2017 was approximately 3.0 MMboe, or 71% of fourth quarter production of 4.2 MMboe. As of February 12, 2018, WRD has hedged approximately 57% of its expected 2018 production (using the mid-point of WRD’s guidance range). In 2018, WRD has hedged approximately 79% of expected oil volumes and approximately 34% of expected natural gas volumes (using the mid-point of WRD’s guidance range). WRD’s weighted average hedge price in 2018 is $52.24 per Bbl of oil and $3.03 per MMBtu of natural gas.
The following table reflects WRD’s hedged volumes and corresponding weighted-average price, as of February 12, 2018:
12
| 2018 | 2019 | 2020 | ||||||||||
| Crude Oil Hedge Contracts: |
||||||||||||
| Total crude oil volumes hedged (Bbl) |
9,526,420 | 8,402,126 | 1,101,762 | |||||||||
| Volumes hedged (Bbl/d) |
26,100 | 23,020 | 3,010 | |||||||||
| Total weighted-average price (10) |
$ | 52.24 | $ | 53.93 | $ | 50.19 | ||||||
| Expected crude production hedged (11) |
79 | % | — | — | ||||||||
| Natural Gas Hedge Contracts: |
||||||||||||
| Total natural gas volumes hedged (MMbtu) |
11,825,800 | 9,877,900 | — | |||||||||
| Volumes hedged (MMbtu/d) |
32,399 | 27,063 | — | |||||||||
| Total weighted-average price (10) |
$ | 3.03 | $ | 2.81 | — | |||||||
| Expected gas production hedged (11) |
34 | % | — | — | ||||||||
| Total Hedge Contracts: |
||||||||||||
| Total hedged production (boe) |
11,497,387 | 10,048,443 | 1,101,762 | |||||||||
| Volumes hedged (Boe/d) |
31,500 | 27,530 | 3,010 | |||||||||
| Total weighted-average price ($/boe) (10) |
$ | 46.40 | $ | 47.86 | $ | 50.19 | ||||||
| Expected total production hedged (11) |
57 | % | — | — | ||||||||
| LLS Basis Swaps |
||||||||||||
| Total crude oil volumes hedged (Bbl) |
3,988,800 | — | — | |||||||||
| Volumes hedged (Bbl/d) |
10,928 | — | — | |||||||||
| Total weighted-average price - WTI to LLS (10) |
$ | 3.06 | — | — | ||||||||
| Expected crude production hedged (11) |
33 | % | — | — | ||||||||
| (10) | Utilizing the mid-point for collars. |
| (11) | Using the mid-point of WRD’s 2018 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, 2017, which will be filed with the U.S. Securities and Exchange Commission (“SEC”) on or before March 16, 2018.
Conference Call and Webcast
WRD will host an investor conference call to discuss its fourth quarter and full year 2017 results tomorrow morning, March 8, 2018 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: 7958045), or (412) 902-6506 for international calls, (Conference ID: 7958045) 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: 10115365) for a seven-day period following the call.
13
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.
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
14
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.
Some of the above results are preliminary. Such preliminary results are based on the most current information available to management. As a result, WRD’s 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 $51.34 per Bbl and $2.98 per MMBtu; and $42.75 per Bbl and $2.48 per MMBtu was based on the unweighted average of the first-day-of-the-month prices for each of the twelve months preceding December 2017, and December 2016, 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
15
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, 2017. WRD expects to include a full reconciliation of PV-10 as of December 31, 2017 to standardized measure in its Form 10-K for the year ended December 31, 2017. 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 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 G&A expenses is a non-GAAP measure. We define cash G&A as total G&A determined in accordance with GAAP less non-cash equity compensation expenses, and we may express it on a per Boe basis. We report and provide guidance on cash G&A 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 is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and natural 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 should not be considered as an alternative to, or more meaningful than, total G&A as determined in accordance with GAAP and may not be comparable to other similarly titled measures of other companies.
16
Management Locations
WRD has disclosed a total of 3,099 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 750 net 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 WRD’s total 3,849 net horizontal drilling locations, 3,099 lie within the geographic areas to which proved, probable and possible reserves are attributed by CG&A. The remaining 750 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 management location count includes 110 net locations from the Lee County, TX acquisition which closed on March 1, 2018. 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. In addition, the total location count includes 642 net locations in North Louisiana with 338 net locations considered in CG&A’s 3P area and an additional 304 management locations outside of CG&A’s 3P area. On February 12, 2018, WRD announced the divestiture of the North Louisiana asset with an expected close date of March 30, 2018.
| Net Locations | CG&A Locations | Management Locations |
Total WRD Locations |
|||||||||||||||||||||
| June 30, 2017 |
Dec. 31, 2017 |
June 30, 2017 |
Dec. 31, 2017 |
June 30, 2017 |
Dec. 31, 2017 |
|||||||||||||||||||
| Eagle Ford |
1,343 | 2,708 | 1,296 | 445 | 2,639 | 3,154 | ||||||||||||||||||
| North Louisiana |
345 | 338 | 303 | 304 | 648 | 642 | ||||||||||||||||||
| Austin Chalk |
12 | 53 | 0 | 0 | 12 | 53 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total Locations |
1,700 | 3,099 | 1,599 | 750 | 3,299 | 3,849 | ||||||||||||||||||
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) available to common stockholders, and Net Debt. The accompanying appendix and schedules provide a reconciliation of these non-GAAP
17
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): | Eagle Ford | North Louisiana | Total WRD | |||||||||
| 2017 D&C capex including facilities and capital workovers |
$ | 701.7 | $ | 86.1 | $ | 787.8 | ||||||
| Reserve additions (Mboe): |
||||||||||||
| Extensions, discoveries and additions |
142.2 | 20.3 | 162.5 | |||||||||
| Performance revisions |
72.0 | 0.2 | 72.2 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total additions |
214.2 | 20.5 | 234.7 | |||||||||
| Total Drill-bit F&D costs ($/boe) |
$ | 3.28 | $ | 4.20 | $ | 3.36 | ||||||
18
WildHorse Resource Development Corporation
Statements of Consolidated and Combined Operations
| For the Three Months Ended December 31, |
For the Year Ended December 31, |
|||||||||||||||
| (Amounts in $000s except per share data) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Revenues: |
||||||||||||||||
| Oil sales |
$ | 150,437 | $ | 24,794 | $ | 342,868 | $ | 75,938 | ||||||||
| Natural gas sales |
19,596 | 11,913 | 59,924 | 43,487 | ||||||||||||
| NGL sales |
10,016 | 2,150 | 22,964 | 5,786 | ||||||||||||
| Other income |
187 | 404 | 1,431 | 2,131 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total operating revenues |
180,236 | 39,261 | 427,187 | 127,342 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating Expenses: |
||||||||||||||||
| Lease operating expenses |
13,570 | 4,633 | 39,770 | 12,320 | ||||||||||||
| Gathering, processing and transportation |
4,494 | 1,527 | 11,897 | 6,581 | ||||||||||||
| Taxes other than income |
9,703 | 1,760 | 24,158 | 6,814 | ||||||||||||
| Depreciation, depletion and amortization |
56,735 | 20,353 | 168,250 | 81,757 | ||||||||||||
| General and administrative expenses |
12,089 | 9,914 | 40,663 | 23,973 | ||||||||||||
| Exploration expense |
19,043 | 3,050 | 36,911 | 12,026 | ||||||||||||
| Other operating (income) expense |
20 | — | 73 | 99 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total expenses |
115,654 | 41,237 | 321,722 | 143,570 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income (loss) from operations |
64,582 | (1,976 | ) | 105,465 | (16,228 | ) | ||||||||||
| Other Income (Expense): |
||||||||||||||||
| Interest expense |
(10,981 | ) | (2,225 | ) | (31,934 | ) | (7,834 | ) | ||||||||
| Debt extinguishment costs |
— | (1,309 | ) | 11 | (1,667 | ) | ||||||||||
| Gain (loss) on derivative instruments |
(92,602 | ) | (18,077 | ) | (55,483 | ) | (26,771 | ) | ||||||||
| North Louisiana settlement |
(7,000 | ) | — | (7,000 | ) | — | ||||||||||
| Other income (expense) |
(4 | ) | (74 | ) | (3 | ) | (151 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total other income (expense) |
(110,587 | ) | (21,685 | ) | (94,409 | ) | (36,423 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income (loss) before income taxes |
(46,005 | ) | (23,661 | ) | 11,056 | (52,651 | ) | |||||||||
| Income tax benefit (expense) |
60,071 | 6,025 | 38,824 | 5,575 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net Income (loss) |
14,066 | (17,636 | ) | 49,880 | (47,076 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income (loss) attributable to previous owners |
— | (7,179 | ) | — | (2,681 | ) | ||||||||||
| Net income (loss) attributable to predecessor |
— | (60 | ) | — | (33,998 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income (loss) available to WRD |
14,066 | (10,397 | ) | 49,880 | (10,397 | ) | ||||||||||
| Preferred stock dividends |
6,623 | — | 13,146 | — | ||||||||||||
| Undistributed earnings allocated to participating securities |
1,892 | — | 5,612 | — | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income (loss) available to common stockholders |
$ | 5,551 | $ | (10,397 | ) | $ | 31,122 | $ | (10,397 | ) | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Earnings per share |
||||||||||||||||
| Basic |
$ | 0.06 | (0.11 | ) | $ | 0.32 | (0.11 | ) | ||||||||
| Diluted |
$ | 0.06 | (0.11 | ) | $ | 0.32 | (0.11 | ) | ||||||||
| Weighted average shares outstanding |
||||||||||||||||
| Basic |
99,156 | 91,327 | 96,324 | 91,327 | ||||||||||||
| Diluted |
99,156 | 91,327 | 96,324 | 91,327 | ||||||||||||
19
WildHorse Resource Development Corporation
Statement of Consolidated and Combined Cash Flows
| For the Three Months Ended December 31, |
For the Year Ended December 31, |
|||||||||||||||
| (Amounts in $000s) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Cash flows from operating activities: |
||||||||||||||||
| Net Income (Loss) |
$ | 14,066 | $ | (17,636 | ) | $ | 49,880 | $ | (47,076 | ) | ||||||
| Adjustments to reconcile net income (loss) to cash flows provided by operating activities |
||||||||||||||||
| Depreciation, depletion and amortization |
56,528 | 20,245 | 167,537 | 81,350 | ||||||||||||
| Accretion of asset retirement obligations |
207 | 108 | 713 | 407 | ||||||||||||
| Dry hole expense and impairments of unproved properties |
6,924 | 2,989 | 20,834 | 3,051 | ||||||||||||
| Amortization of debt issuance costs |
613 | 137 | 2,575 | 479 | ||||||||||||
| Accretion of senior note discount |
145 | — | 342 | — | ||||||||||||
| (Gain) loss on derivative instruments |
92,602 | 18,079 | 55,483 | 26,771 | ||||||||||||
| Cash settlements on derivative instruments |
(5,378 | ) | (1,093 | ) | 1,517 | 4,975 | ||||||||||
| Deferred income tax expense |
(60,094 | ) | (6,010 | ) | (39,831 | ) | (5,575 | ) | ||||||||
| Debt extinguishment expense |
— | 1,309 | (11 | ) | 1,667 | |||||||||||
| Amortization of equity awards |
2,427 | 68 | 6,644 | 68 | ||||||||||||
| Gain (loss) on sale of properties |
— | 43 | — | 43 | ||||||||||||
| Changes in operating assets and liabilities |
26,140 | (20,251 | ) | 11,689 | (43,898 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net cash provided by (used in) operating activities |
134,180 | (2,012 | ) | 277,372 | 22,262 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Cash flows from investing activities: |
||||||||||||||||
| Net cash used in investing activities |
(264,932 | ) | (468,709 | ) | (1,266,861 | ) | (567,545 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Cash flows from financing activities: |
||||||||||||||||
| Net cash provided by financing activities |
125,569 | 472,385 | 986,600 | 505,272 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net Change in Cash and Cash Equivalents |
$ | (5,183 | ) | $ | 1,664 | $ | (2,889 | ) | $ | (40,011 | ) | |||||
| Cash and Cash Equivalents, Beginning of Period |
5,409 | 1,451 | 3,115 | 43,126 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Cash and Cash Equivalents, End of Period |
$ | 226 | $ | 3,115 | $ | 226 | $ | 3,115 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
WildHorse Resource Development Corporation
Operating Data
| For the Three Months Ended December 31, |
For the Year Ended Ended December 31, |
|||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| Production volumes |
||||||||||||||||
| Oil Sales (MBbls) |
2,594 | 523 | 6,606 | 1,848 | ||||||||||||
| Natural Gas Sales (MMcf) |
7,182 | 3,948 | 20,463 | 17,820 | ||||||||||||
| NGL Sales (MBbls) |
427 | 135 | 1,206 | 471 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total (Mboe) |
4,218 | 1,316 | 11,222 | 5,289 | ||||||||||||
| Total (Mboe/d) |
45.9 | 14.3 | 30.7 | 14.5 | ||||||||||||
| Average unit costs per boe |
||||||||||||||||
| Lease operating expense |
$ | 3.22 | $ | 3.52 | $ | 3.54 | $ | 2.33 | ||||||||
| Gathering, processing and transportation |
$ | 1.07 | $ | 1.16 | $ | 1.06 | $ | 1.24 | ||||||||
| Taxes other than income |
$ | 2.30 | $ | 1.34 | $ | 2.15 | $ | 1.29 | ||||||||
| General and administrative expenses |
$ | 2.87 | $ | 7.53 | $ | 3.62 | $ | 4.53 | ||||||||
| Cash General and administrative expenses |
$ | 2.29 | $ | 7.48 | $ | 3.03 | $ | 4.52 | ||||||||
| Acquisition-related expenses |
$ | 0.13 | $ | 0.33 | $ | 0.39 | $ | 0.10 | ||||||||
20
WildHorse Resource Development Corporation
Consolidated Balance Sheet
| December 31, | December 31, | |||||||
| (Amounts in $000s) | 2017 | 2016 | ||||||
| ASSETS |
||||||||
| Current Assets: |
||||||||
| Cash and cash equivalents |
$ | 226 | $ | 3,115 | ||||
| Accounts receivable, net |
84,103 | 26,428 | ||||||
| Short-term derivative instruments |
2,336 | — | ||||||
| Prepaid expenses and other current assets |
3,290 | 1,633 | ||||||
|
|
|
|
|
|||||
| Total Current Assets |
89,955 | 31,176 | ||||||
| Property & equipment: |
||||||||
| Oil and natural gas properties |
2,999,728 | 1,573,848 | ||||||
| Other property and equipment |
53,003 | 34,344 | ||||||
| Accumulated depreciation, depletion and impairment |
(368,245 | ) | (200,293 | ) | ||||
|
|
|
|
|
|||||
| Total property and equipment, net |
2,684,486 | 1,407,899 | ||||||
| Other noncurrent assets |
||||||||
| Restricted cash |
— | 886 | ||||||
| Long-term derivative instruments |
86 | — | ||||||
| Debt issuance costs |
3,573 | 2,320 | ||||||
|
|
|
|
|
|||||
| Total Assets |
$ | 2,778,100 | $ | 1,442,281 | ||||
|
|
|
|
|
|||||
| LIABILITIES AND EQUITY |
||||||||
| Current Liabilities: |
||||||||
| Accounts payable |
$ | 53,005 | $ | 21,014 | ||||
| Accrued liabilities |
199,952 | 23,461 | ||||||
| Short-term derivative instruments |
58,074 | 14,087 | ||||||
|
|
|
|
|
|||||
| Total Current Liabilities |
311,031 | 58,562 | ||||||
| Noncurrent Liabilities: |
||||||||
| Long-term debt |
770,596 | 242,750 | ||||||
| Asset retirement obligations |
14,467 | 10,943 | ||||||
| Deferred tax liabilities |
71,470 | 112,552 | ||||||
| Long-term derivative instruments |
18,676 | 8,091 | ||||||
| Other long-term liabilities |
1,085 | 1,495 | ||||||
|
|
|
|
|
|||||
| Total liabilities |
1,187,325 | 434,393 | ||||||
| Series A Perpetual Convertible Preferred Stock |
445,483 | — | ||||||
| Stockholders’ equity: |
||||||||
| Common stock |
1,012 | 917 | ||||||
| Additional paid-in capital |
1,118,507 | 1,017,368 | ||||||
| Accumulated earnings (deficit) |
25,773 | (10,397 | ) | |||||
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| Total stockholders’ equity |
1,145,292 | 1,007,888 | ||||||
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| Total Liabilities & Equity |
$ | 2,778,100 | $ | 1,442,281 | ||||
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WildHorse Resource Development Corporation
Commodity Hedge Positions
The following table reflects WRD’s hedged volumes and corresponding weighted-average price, as of February 12, 2018:
| 2018 | 2019 | 2020 | ||||||||||
| Crude Oil Derivative Contracts: |
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| Swap contracts: |
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| Volume (Bbl) |
6,834,488 | 6,652,369 | 1,101,762 | |||||||||
| Weighted-average fixed price |
$ | 52.42 | $ | 54.27 | $ | 50.19 | ||||||
| Collar contracts: |
||||||||||||
| Volume (Bbl) |
25,096 | — | — | |||||||||
| Weighted-average floor price |
$ | 50.00 | — | — | ||||||||
| Weighted-average ceiling price |
$ | 62.10 | — | — | ||||||||
| Deferred put options |
||||||||||||
| Volume (Bbl) |
2,666,836 | 1,749,757 | — | |||||||||
| Weighted-average floor price |
$ | 51.74 | $ | 52.66 | — | |||||||
| Weighted-average put premium |
($ | 3.47 | ) | ($ | 5.43 | ) | — | |||||
| LLS basis swaps |
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| Volume (Bbl) |
3,988,800 | — | — | |||||||||
| Weighted-average fixed price—WTI |
$ | 3.06 | — | — | ||||||||
| Natural Gas Derivative Contracts: |
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| Swap contracts: |
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| Volume (MMBtu) |
11,825,800 | 9,877,900 | — | |||||||||
| Weighted-average fixed price |
$ | 3.03 | $ | 2.81 | — | |||||||
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; the North Louisiana settlement, 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:
22
Adjusted EBITDAX
| For the Three Months Ended December 31, |
For the Year Ended December 31, |
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| (Amounts in $000s) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Net Income (Loss) |
$ | 14,066 | $ | (17,636 | ) | $ | 49,880 | $ | (47,076 | ) | ||||||
| Add (Deduct): |
||||||||||||||||
| Interest expense, net |
10,981 | 2,225 | 31,934 | 7,834 | ||||||||||||
| Income tax (benefit) expense |
(60,071 | ) | (6,025 | ) | (38,824 | ) | (5,575 | ) | ||||||||
| Depreciation, depletion and amortization |
56,735 | 20,353 | 168,250 | 81,757 | ||||||||||||
| Exploration expense |
19,043 | 3,050 | 36,911 | 12,026 | ||||||||||||
| (Gain) loss on derivative instruments |
92,602 | 18,077 | 55,483 | 26,771 | ||||||||||||
| Cash settlements received / (paid) on commodity derivatives |
(5,378 | ) | (1,093 | ) | 1,517 | 4,975 | ||||||||||
| Stock-based compensation |
2,427 | 68 | 6,644 | 68 | ||||||||||||
| Acquisition related costs |
552 | 430 | 4,348 | 553 | ||||||||||||
| Debt Extinguishment costs |
1,309 | (11 | ) | 1,667 | ||||||||||||
| Initial public offering costs |
— | 378 | 182 | 1,560 | ||||||||||||
| Gain (loss) on sale of properties |
— | 43 | — | 43 | ||||||||||||
| Non-cash liability amortization |
— | — | — | (286 | ) | |||||||||||
| North Louisiana settlement |
7,000 | — | 7,000 | — | ||||||||||||
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| Adjusted EBITDAX |
$ | 137,957 | $ | 21,179 | $ | 323,314 | $ | 84,317 | ||||||||
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Calculation of Adjusted Net Income (Loss) Available to Common Stockholders:
Adjusted Net Income (Loss) available to common stockholders is a supplemental non-GAAP financial measure that is used by external users of WRD’s financial statements. We define Adjusted Net Income (Loss) available to common stockholders as Net Income (Loss) available to common stockholders 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, impairment-related expenses, the tax benefit related to the Tax Cuts and Jobs Act, the North Louisiana settlement and the tax effects related to these adjustments. We believe Adjusted Net Income (Loss) available to common stockholders 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) available to common stockholders as determined in accordance with GAAP to Adjusted Net Income (Loss) available to common stockholders for the periods indicated:
23
Adjusted Net Income (Loss) available to common stockholders
| For the Three Months Ended December 31, 2017 |
For the Year Ended Ended December 31, 2017 |
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| (Amounts in $000s) | (Basic /Diluted EPS) | (Amounts in $000s) | (Basic /Diluted EPS) | |||||||||||||
| Net Income (Loss) available to common stockholders |
$ | 5,551 | $ | 0.06 | $ | 31,122 | $ | 0.32 | ||||||||
| Add (Deduct) |
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| (Gain) loss on derivative instruments |
92,602 | 0.93 | 55,483 | 0.58 | ||||||||||||
| Cash settlements received / (paid) on commodity derivatives |
(5,378 | ) | (0.05 | ) | 1,517 | 0.02 | ||||||||||
| Stock-based compensation |
2,427 | 0.02 | 6,644 | 0.07 | ||||||||||||
| Impairment of oil and gas properties |
6,924 | 0.07 | 20,834 | 0.22 | ||||||||||||
| North Louisiana Settlement |
7,000 | 0.07 | 7,000 | 0.07 | ||||||||||||
| Debt extinguishment costs |
— | — | (11 | ) | (0.00 | ) | ||||||||||
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| Adjusted income (loss) before tax effect |
109,126 | 1.10 | 122,589 | 1.27 | ||||||||||||
| Tax effect related to adjustments |
(37,411 | ) | (0.38 | ) | (35,434 | ) | (0.37 | ) | ||||||||
| One time tax benefit related to Tax Cuts and Jobs Act |
(43,431 | ) | (0.44 | ) | (43,431 | ) | (0.45 | ) | ||||||||
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| Adjusted income (loss) after tax effect |
28,284 | 0.29 | 43,724 | 0.45 | ||||||||||||
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| Preferred stock dividend |
6,623 | 0.07 | 13,146 | 0.14 | ||||||||||||
| Undistributed earnings allocated to participating securities |
1,892 | 0.02 | 5,612 | 0.06 | ||||||||||||
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| Adjusted net income (loss) |
36,799 | 0.37 | 62,482 | 0.65 | ||||||||||||
| Preferred stock dividend |
(6,623 | ) | (0.07 | ) | (13,146 | ) | (0.14 | ) | ||||||||
| Undistributed adjusted earnings allocated to participating securities |
(7,668 | ) | (0.08 | ) | (7,537 | ) | (0.08 | ) | ||||||||
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| Adjusted net income (loss) available to common shareholders |
$ | 22,508 | $ | 0.23 | $ | 41,799 | $ | 0.43 | ||||||||
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| Weighted average basic and diluted shares outstanding |
99,156 | 96,324 | ||||||||||||||
Calculation of Net Debt:
Net Debt is a supplemental non-GAAP financial measure that is used by external users of WRD’s financial statements. We define Net Debt as total debt minus cash and cash equivalents. We believe Net Debt is useful to investors because it provides readers with a more meaningful measure of our outstanding indebtedness. 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.
Contact:
WildHorse Resource Development Corporation
Pearce Hammond, CFA (713) 255-7094
Vice President, Investor Relations
ir@wildhorserd.com
24