Form 8-K WildHorse Resource Devel For: Feb 12
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 OR 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): February 12, 2018
WildHorse Resource Development Corporation
(Exact name of registrant as specified in its charter)
| Delaware | 001-37964 | 81-3470246 | ||
| (State or other jurisdiction of incorporation) |
(Commission File Number) | (IRS Employer Identification No.) |
9805 Katy Freeway, Suite 400
Houston, TX 77024
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (713) 568-4910
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company ☒
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☒
| Item 2.02. | Results of Operations and Financial Condition. |
On February 12, 2018, WildHorse Resource Development Corporation (the “Company”) issued a press release announcing an operational update, its 2017 year-end reserves, and 2018 financial and operational guidance. The press release is furnished as Exhibit 99.1 to this Current Report on Form 8-K and is incorporated by reference herein.
| Item 7.01. | Regulation FD Disclosure. |
On February 12, 2018, the Company issued a press release announcing, among other things, its 2018 financial and operational guidance. The press release is furnished as Exhibit 99.1 to this Current Report on Form 8-K and is incorporated by reference into this Item 7.01.
The information in this Current Report on Form 8-K, including the attached Exhibit 99.1, is being “furnished” pursuant to General Instruction B.2 of Form 8-K and shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any Company filing, whether made before or after the date hereof, regardless of any general incorporation language in such filing.
| Item 9.01. | Financial Statements and Exhibits. |
(d) Exhibits.
| Exhibit | ||
| Number |
Description | |
| 99.1 | Press release dated February 12, 2018 |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| WILDHORSE RESOURCE DEVELOPMENT CORPORATION
| ||
| By: | /s/ Kyle N. Roane | |
| Name: | Kyle N. Roane | |
| Title: | Executive Vice President, General Counsel and | |
| Corporate Secretary | ||
Dated: February 12, 2018
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Exhibit 99.1
|
News For Immediate Release |
WildHorse Resource Development Corporation Announces Year-End 2017 Reserves,
Operational Update, and 2018 Guidance
HOUSTON, February 12, 2018 – WildHorse Resource Development Corporation (NYSE: WRD) announced today year-end 2017 reserves, an operational update, 2018 guidance, and the construction of an in-field sand mine in Burleson County, TX. In a separate press release, WRD also announced today that it has executed a definitive purchase and sale agreement to divest its North Louisiana assets to a third party. Unless otherwise disclosed, all information in this press release does not give effect to the North Louisiana divestiture. Highlights include:
Year-End 2017 Reserves:
| • | 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”)(1) reserves by 131% to 1,892.2 MMboe at year-end 2017 from 818.9 MMboe at year-end 2016 |
| • | Increased PV-10(2) 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”)(3) costs, excluding acquisitions and price revisions, averaged $3.32 per Boe, based on preliminary unaudited capital expenditures for 2017 |
| • | Replaced 2,134% of estimated production in 2017 including performance revisions and excluding price revisions and acquisitions |
| • | Updated reserve life of WRD’s proved reserves is approximately 41 years based on estimated full year 2017 production |
Type Curve and Location Count Update
| • | WRD raised its Eagle Ford type curve to an EUR of 95 Boe per foot from 91 Boe per foot at year-end 2016. The current type curve reflects oil growth to 78 Bo per foot from 76 Bo per foot at year-end 2016. Current well costs are estimated at $6.5 million per well with an IRR of 57% at consensus pricing(4). Well costs with sand mine savings are estimated at $5.9 to $6.1 million per well with an IRR of 70% and 66% at consensus pricing(4), respectively |
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| • | Total number of net Eagle Ford locations(5) at the 95 Boe type curve increased to 3,154 locations from 1,996 locations following the Anadarko/KKR acquisition on June 30, 2017 |
| • | Washington County Austin Chalk type curve released for 71 gross (53 net) locations. Current well costs are estimated at $7.8 million per well with an IRR of 34% at consensus pricing(4). Well costs with sand mine savings are estimated at $7.2 to $7.4 million per well with an IRR of 39% and 37% at consensus pricing(4), respectively |
2018 Financial and Operational Guidance:
| • | Projects 2018 total daily production of 53.0 – 56.0 Mboe/d representing total production growth of 80% at the midpoint of guidance over 2017’s estimated average daily production |
| • | Plans to operate an average of approximately 4.8 drilling rigs in the Eagle Ford and Austin Chalk in 2018 |
| • | Estimated fiscal year 2018 D&C capex is between $700 - $800 million |
| • | Announced plans to build an in-field sand mine with estimated D&C cost savings of $400,000 to $600,000 per well upon project completion by the first quarter of 2019 |
| • | Estimated non-D&C capex of $65 - $75 million for sand mine construction |
Fourth Quarter and Full Year 2017 Operational Update(6):
| • | Estimated fourth quarter 2017 production of 43.8 Mboe/d (64% oil) |
| • | Estimated full year 2017 production of 30.2 Mboe/d (60% oil) |
| • | Exceeded the midpoint of full year 2017 production guidance by over 1,200 Boe/d |
| • | Estimated oil price realizations were 105% of WTI in the fourth quarter of 2017 |
| • | Drilled 109 gross (105.0 net) wells and completed 93 gross (90.5 net) wells in full year 2017 with 37 gross (35.7 net) wells online in the fourth quarter |
| • | Drilled 95 gross (93.0 net) wells and completed 82 gross (81.0 net) Eagle Ford wells for full year 2017 with 30 gross (29.4 net) wells online in the fourth quarter |
| • | Drilled 5 gross (4.7 net) and completed 3 gross (3.0 net) Austin Chalk wells for full year 2017 including 1 gross (1.0 net) well in the fourth quarter |
| • | Drilled 9 gross (7.3 net) wells and completed 8 gross (6.5 net) wells in North Louisiana for full year 2017 with 6 gross (5.3 net) wells online in the fourth quarter |
| • | Exited 2017 with 21 gross (19.3 net) wells in the process of drilling, completion, or awaiting completion |
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| • | Brought online 2 additional Eagle Ford step out wells in the fourth quarter of 2017 |
| • | Brought online two Austin Chalk wells in Washington County during the fourth quarter 2017 and early first quarter 2018 |
| • | The Lillie Hohlt #1H came online at an IP-30(7) of 2,604 Boe/d or 15.6 MMcfe/d (66% natural gas, 31% NGLs, and 3% oil) on a 4,815’ lateral |
| • | The Brollier AC #1H, which is in very early production, has reached a peak daily rate of 2,580 Boe/d or 15.5 MMcfe/d (60% natural gas, 30% NGLs, and 10% oil) on a 5,684’ lateral, and may continue to rise with additional days online |
“With nearly 100 Gen 3 wells online at year end 2017, we continue to prove that high intensity completions are the key to unlocking value in this part of the Eagle Ford. Furthermore, we have tripled our proved reserves to 454.3 MMboe and increased the PV-10 of our proved reserves by 372% to $3.539 billion at year-end 2017,” said Jay Graham, Chairman and Chief Executive Officer of WRD. “In 2018, WRD will become a significant oil producer with economies of scale. As part of this goal, we are constructing an in-field sand mine which we expect will have a payback period of less than two years upon completion and will save $400,000 to $600,000 per well. Our 2018 budget allows for drilling 100 to 110 gross wells and developing significant infrastructure while also maintaining a net debt to annualized EBITDAX ratio below 2.0x. Our investments in the current year will put WRD in a strong position for years to come.”
Year-End 2017 Proved Reserves
WRD reported year-end 2017 proved reserves of 454.3 MMboe, an increase of 198% from 152.5 MMboe at year-end 2016. WRD’s proved reserves consist of 62% oil, 25% natural gas and 13% NGLs. Proved developed and producing reserves were 114.4 MMboe or 25% of total proved reserves, and proved undeveloped reserves were 339.9 MMboe or 75% of total proved reserves at year-end 2017.
| Summary of Changes in Proved Reserves (Mboe) |
Eagle Ford | North Louisiana | Total WRD | |||||||||
| Balance as of December 31, 2016 |
104.7 | 47.8 | 152.5 | |||||||||
| Extensions, Discoveries and Additions |
142.2 | 20.3 | 162.5 | |||||||||
| Acquisitions |
70.6 | 0.0 | 70.6 | |||||||||
| Performance Revisions |
72.0 | 0.2 | 72.2 | |||||||||
| Price Revisions |
4.7 | 2.8 | 7.5 | |||||||||
| Estimated Production |
(8.6 | ) | (2.4 | ) | (11.0 | ) | ||||||
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| Balance as of December 31, 2017 |
385.6 | 68.7 | 454.3 | |||||||||
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Cawley, Gillespie & Associates (“CG&A”), an independent reserve engineering firm, audited WRD’s year-end reserves estimates as of December 31, 2017. Due to acquisitions and greater activity in the Eagle Ford, the majority of added proved reserves were in the Eagle Ford. In 2017, WRD brought online 82 gross wells in the Eagle Ford, 3 gross wells in the Austin Chalk and 8 gross wells in North Louisiana. The table below provides additional information relating to WRD’s reserves for the periods indicated:
| 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 | ||||||||||||||||||
Using SEC prices, the present value discounted at 10% (“PV-10”)(2) of WRD’s proved reserves at December 31, 2017 was $3.539 billion (excluding WRD’s hedges), an increase of 372% from $750 million at year-end 2016. The SEC rules require that proved reserve calculations be based on the average of the closing prices for the first day of each month in 2017. For the year-end 2017 reserve evaluation, the benchmark prices were $51.34 per barrel for crude oil and $2.98 per MMBtu for natural gas which compares to $42.75 per barrel for crude oil and $2.48 per MMBtu for natural gas at year-end 2016. The table below provides additional information relating to WRD’s PV-10(2) of proved reserves for the periods indicated:
| As of December 31, | ||||||||
| Proved Reserves PV-10 |
2016 | 2017 | ||||||
| PV-10 ($M)(2) |
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| Eagle Ford |
626,398 | 3,208,792 | ||||||
| North Louisiana |
123,590 | 330,545 | ||||||
| Total ($M) |
749,988 | 3,539,337 | ||||||
| WTI Crude ($/bbl) |
$ | 42.75 | $ | 51.34 | ||||
| Henry Hub Gas ($/mmbtu) |
$ | 2.48 | $ | 2.98 | ||||
WRD replaced 2,134% of estimated production in 2017 including performance revisions and excluding price revisions and acquisitions. Drill-bit finding and development (“F&D”)(3) costs for proved reserve additions averaged $3.32 per Boe, based on preliminary unaudited D&C capital
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expenditures in 2017, including facilities and capital workovers. The reserve life of WRD’s proved reserves, based on estimated 2017 production, is approximately 41 years.
Year-End 2017 3P Reserves
CG&A audited 3P reserves at year-end 2017 were 1,892.2 MMboe, a 131% increase over 818.9 MMboe at December 31, 2016. Year-end 3P reserves were 1,450.0 MMboe in the Eagle Ford and 442.2 MMboe in North Louisiana, an increase of 193% and 36% from year end 2016, respectively. The table below summarizes CG&A audited 3P reserve volumes using SEC pricing:
| Eagle Ford | North Louisiana | Total WRD | WRD PV-10 ($MM) | |||||||||||||||||||||||||||||
| As of December 31, | As of December 31, | As of December 31, | As of December 31, | |||||||||||||||||||||||||||||
| 3P Reserves (MMboe)(1) |
2016 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | ||||||||||||||||||||||||
| Proved |
104.7 | 385.6 | 47.8 | 68.7 | 152.5 | 454.3 | $ | 750.0 | $ | 3,539.3 | ||||||||||||||||||||||
| Probable |
122.1 | 369.0 | 28.1 | 28.9 | 150.2 | 398.0 | $ | 366.7 | $ | 1,767.1 | ||||||||||||||||||||||
| Possible |
267.4 | 695.4 | 248.8 | 344.6 | 516.2 | 1039.9 | $ | 847.8 | $ | 3,620.8 | ||||||||||||||||||||||
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| Total 3P Reserves |
494.2 | 1,450.0 | 324.8 | 442.2 | 818.9 | 1,892.2 | ||||||||||||||||||||||||||
| (1) | See “Cautionary Statements and Additional Disclosures” in the Appendix section of this press release for more information regarding 3P reserves. |
| (2) | 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. |
| (3) | 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. |
| (4) | Consensus Pricing as of 2/5/18: $60.00 / $3.07 for 2018, $60.00 / $3.09 for 2019, $62.00 / $3.13 for 2020, $61.01 / $3.19 for 2021, $57.00 / $3.22 for 2022 and thereafter for WTI and Henry Hub, respectively. |
| (5) | See “Management Locations” in the Appendix section of this press release for more information regarding CG&A and management locations. |
| (6) | Based on preliminary unaudited data as of February 12, 2018. |
| (7) | The initial production rates represent the peak average of the initial production rates for the applicable consecutive days of production. |
Type Curve and Horizontal Drilling Location Update
As a result of continued outperformance, WRD has increased its Eagle Ford type curve EUR to 95 Boe per foot from 91 Boe per foot. The oil
content of the type curve has also increased to 78 Bo per foot from 76 Bo per foot. The number of Eagle Ford locations at the 95 Boe per foot has also increased to 3,154 net locations from 1,996 net locations on June 30, 2017, primarily as a
result of drilling
activity(5).
As of December 31, 2017, management estimates a total of 3,849 net horizontal drilling locations in the Eagle Ford, Austin Chalk, and North Louisiana, an increase from 3,299 net
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locations following the Anadarko/KKR acquisition on June 30, 2017. Of WRD’s total 3,849 net horizontal locations, 3,099, or 81%, are included within CG&A’s 3P geographic area as of the year-end 2017 reserve report, an increase from 1,700 net locations, or 52%, within the 3P geographic area after the close of the Anadarko/KKR acquisition on June 30, 2017. The table below summarizes WRD’s location count across CG&A and management locations:
| Net Locations | CG&A | Management | Total | |||||||||||||||||||||
| Locations | Locations | WRD Locations | ||||||||||||||||||||||
| June 30, | Dec. 31, | June 30, | Dec. 31, | June 30, | Dec. 31, | |||||||||||||||||||
| 2017 | 2017 | 2017 | 2017 | 2017 | 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 | ||||||||||||||||||
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| Total Locations |
1,700 | 3,099 | 1,599 | 750 | 3,299 | 3,849 | ||||||||||||||||||
In addition, in the updated company presentation available on WRD’s website, WRD has released a budget type curve for the Washington County Austin Chalk with an EUR of 341 Boe per foot (64% natural gas, 29% NGLs, and 7% oil) and an IP-30 of 1,755 Boe/d (64% natural gas, 29% NGLs, and 7% oil). WRD currently estimates 71 gross (53 net) locations based on only 14,937 net acres in Washington County at spacing of 1,500’. WRD believes that another 85,000 net acres of its position are prospective for Austin Chalk development but currently has not assigned locations to such acreage.
2018 Operational and Financial Guidance (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 80% over 2017’s estimated 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 go from 4.0 completion crews in the first half of the year to 3.0 completion crews in the second half of 2018.
In 2018, WRD is taking proactive steps to secure pricing on key service costs to further reduce well costs. WRD expects to drill approximately 60% of its wells on 4-well pads versus 2-well
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pads which made up the majority of the 2017 program. Also, currently, two of WRD’s four completion crews are on contract in 2018. A spot rate completion crew will be released at mid-year. In addition, WRD has negotiated sand contracts in late December 2017 and early January 2018 to bridge the gap between current operations and the start date of WRD’s in-field sand mine by the first quarter of 2019. The budget allocates between $65 - $75 million of non-D&C capital expenditure for the acquisition, evaluation, and construction of the sand mine. WRD expects its capital budget to be funded by cash on hand, the 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.
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 East Texas Eagle Ford and Austin Chalk in either scenario. A summary of the full year 2018 guidance is presented below:
| Pro-Forma FY 2018 Guidance | ||||||||||||
| FY 2018 Guidance | North Louisiana Divestiture(10) |
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| 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(8) |
($1.65) - ($2.15) | ($2.00) - ($2.50) | ||||||||||
| Taxes Other than Income (% of oil & gas revenue) |
5.0% - 6.0% | 5.0% - 6.0% | ||||||||||
| Commodity Price Realizations (Unhedged)(9) |
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| Crude Oil Realized Price (% of WTI NYMEX) |
98% - 102% | 98% - 102% | ||||||||||
| Natural Gas Realized Price (% of NYMEX to Henry Hub) |
94% - 98% | 90% - 94% | ||||||||||
| NGL Realized Price (% of WTI NYMEX) |
33% - 37% | 33% - 37% | ||||||||||
| Drilling Program |
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| Wells Spud (Gross) |
100 - 110 | 100 - 110 | ||||||||||
| Wells Completed (Gross) |
100 - 110 | 100 - 110 | ||||||||||
| D&C Capital Expenditure ($MM) |
$700 - $800 | $700 - $800 | ||||||||||
| Sand Mine Capital Expenditure ($MM) |
$65 - $75 | $65 - $75 | ||||||||||
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Note: Guidance as of February 12, 2018
| (8) | 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. |
| (9) | Based on strip pricing as of February 9, 2018. |
| (10) | Pro-Forma North Louisiana asset sale guidance assumes the pending divestiture announced on February 12, 2018 closes on or about March 30, 2018. |
The operational and financial guidance provided in this press release is subject to the cautionary statements and limitations described under “Cautionary Statements and Additional Disclosures – Forward-Looking Statements” in the Appendix of this press release. WRD’s guidance is based on, among other things, its current expectations regarding capital expenditure levels and the assumption that market demand and prices for oil, natural gas and NGLs will continue at a level that allows for economic production of these products.
Sand Mine Development Plan
On January 4, 2018, WRD acquired surface and sand rights on 727 acres in Burleson County, TX. Prior to the acquisition, WRD retained a third party engineering advisor to evaluate and assess the proposed sand mine location. Based on such analysis, total resource potential of the sand mine is estimated at 85 million tons of sand. The reserves contain fine grade 100 mesh and 40/70 sand which is comparable to the product WRD currently sources from other mines.
Capital expenditure for the full development of the sand mine, a wholly-owned subsidiary of WRD, will total $65 - $75 million in 2018 which includes property acquisition, reserve evaluation, and construction. WRD expects that the sand mine will complement operations by lowering both the cost of sand and transportation. As a result of WRD’s contiguous 404,000 net acre Eagle Ford position, the sand mine will reduce the distance traveled to well sites from 70 to 180 miles per truckload compared to alternative mine options. Savings are expected to reduce well costs by $400,000 to $600,000 per well when the mine becomes fully operational by the first quarter of 2019. WRD expects that these savings could reduce Eagle Ford and Austin Chalk well costs to $5.9 - $6.1 million and $7.2 - $7.4 million per well, respectively. Based on the estimated resource potential and the 2018 development plan, the sand mine will provide WRD with over 40 years of sand supply in East Texas which effectively hedges the price of sand for the foreseeable future and covers WRD’s total development inventory.
The estimated payback period for the sand mine is less than two years upon completion based on the current pace of 100 to 110 gross Eagle Ford and Austin Chalk completions in 2018.
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Fourth Quarter and Full Year 2017 Operational Update
WRD expects to report estimated fourth quarter 2017 average daily production of 43.8 Mboe/d, which represents a 206% increase from the fourth quarter 2016. WRD’s estimated production mix during the fourth quarter 2017 consisted of approximately 64% oil, 25% natural gas, and 11% NGLs. East Texas represented 36.0 Mboe/d of production 78% oil, and North Louisiana represented 46.9 MMcfe/d of production (96% natural gas).
WRD’s estimated full year 2017 production was 30.2 Mboe/d, a 108% increase from 14.5 Mboe/d in 2016. Despite timing delays from six wells on two North Louisiana pads during the fourth quarter of 2017, WRD exceeded consensus production estimates in the fourth quarter and exceeded the mid-point of full year 2017 guidance by over 1,200 Boe/d. This outperformance is in addition to the 1,000 Boe/d upward revision in production guidance in May 2017. WRD intends to highlight and discuss in greater detail key well results with its fourth quarter earnings release after the market close on March 7, 2018.
Also in the fourth quarter of 2017, WRD brought online an Austin Chalk well in Washington County, the Lillie Hohlt #1H, 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, which is in very early production and has reached a peak daily rate of 2,580 Boe/d or 15.5 MMcfe/d (60% natural gas, 30% NGLs, and 10% oil) on a 5,684’ lateral. Since the Brollier is early in production, the production rate may continue to rise with additional days online and could potentially peak at a higher rate than currently reported in this press release.
The two wells are located 5 and 6 miles northeast of the Winkelmann, 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, 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(7) 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
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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.
During the fourth quarter, oil and NGL price realizations were 105% and 42% of WTI, respectively; natural gas price realizations were 93% of Henry Hub. The preliminary estimate of D&C capital expenditure totaled $258.1 million in the fourth quarter 2017 and $736.1 million for the full year 2017. Fourth quarter D&C capex was greater than anticipated as a result of temporarily higher sand costs prior to contract negotiation, 4-well pad preparation for the 2018 program, and higher working interests. Average working interest for all wells in 2017 was 97% versus guidance of 89% in February 2017. 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.
Financial Update
As of December 31, 2017, total net debt was $786.2 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 is $875 million. The next redetermination using year-end 2017 reserves is scheduled on or about March 30, 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. Under the 2018 budget, WRD is projected to maintain a net debt to annualized EBITDAX ratio of less than 2.0 times throughout the year. WRD’s liquidity position is expected to be sufficient to finance anticipated working capital and capital expenditures.
Hedging Overview
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 range). As a result, 43% of WRD’s expected oil volumes are unhedged to the upside and benefit from rising oil prices.
WRD has hedged approximately 57% of its expected 2018 production with a combination of swaps, collars, and puts including 79% of expected oil volumes and 34% of expected natural gas volumes (using the mid-point of the guidance range). WRD’s weighted average hedge price in 2018 is $52.16 per Bbl of oil and $3.03 per MMBtu of natural gas. WRD also hedged the
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spread between WTI and Louisiana Light Sweet (“LLS”) at a positive spread of $3.06 per barrel for 33% of its expected oil volumes in 2018.
The following table reflects WRD’s hedged volumes and corresponding weighted-average price, as of February 12, 2018:
| Q4 2017 | 2018 | 2019 | 2020 | |||||||||||||
| Crude Oil Hedge Contracts: |
||||||||||||||||
| Total crude oil volumes hedged (Bbl) |
2,089,724 | 9,526,420 | 8,402,126 | 1,101,762 | ||||||||||||
| Volumes hedged (Bbl/d) |
22,714 | 26,100 | 23,020 | 3,010 | ||||||||||||
| Total weighted-average price (11) |
$ | 52.54 | $ | 52.16 | $ | 53.93 | $ | 50.19 | ||||||||
| Expected crude production hedged (12) |
81 | % | 79 | % | — | — | ||||||||||
| Natural Gas Hedge Contracts: |
||||||||||||||||
| Total natural gas volumes hedged (MMBtu) |
5,692,660 | 11,825,800 | 9,877,900 | — | ||||||||||||
| Volumes hedged (MMbtu/d) |
61,877 | 32,399 | 27,063 | — | ||||||||||||
| Total weighted-average price (11) |
$ | 3.25 | $ | 3.03 | $ | 2.81 | — | |||||||||
| Expected gas production hedged (12) |
94 | % | 34 | % | — | — | ||||||||||
| Total Hedge Contracts: |
||||||||||||||||
| Total hedged production (boe) |
3,038,501 | 11,497,387 | 10,048,443 | 1,101,762 | ||||||||||||
| Volumes hedged (Boe/d) |
33,027 | 31,500 | 27,530 | 3,010 | ||||||||||||
| Total weighted-average price ($/boe) (11) |
$ | 42.21 | $ | 46.33 | $ | 47.86 | $ | 50.19 | ||||||||
| Expected total production hedged (12) |
75 | % | 57 | % | — | — | ||||||||||
| LLS Basis Swaps |
||||||||||||||||
| Total crude oil volumes hedged (Bbl) |
1,843,600 | 3,988,800 | — | — | ||||||||||||
| Volumes hedged (Bbl/d) |
20,039 | 10,928 | — | — | ||||||||||||
| Total weighted-average price - WTI (11) |
$ | 3.98 | $ | 3.06 | — | — | ||||||||||
| Expected crude production hedged (12) |
71 | % | 33 | % | — | — | ||||||||||
| (11) | Utilizing the mid-point for collars. |
| (12) | Using WRD’s 2018 expected production based on the midpoint of guidance. |
Fourth Quarter and Full Year 2017 Earnings Conference Call
WRD will report its fourth quarter and full year 2017 financial and operating results after the market closes for trading on March 7, 2018. On the morning of March 8, 2018, management will host a fourth quarter and full year 2017 earnings conference call at 8 a.m. Central (9 a.m. Eastern). Interested parties are invited to participate on the call by dialing (877) 883-0383 (Conference ID: 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.
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About WildHorse Resource Development Corporation
WildHorse Resource Development Corporation is an independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and NGL properties primarily in the Eagle Ford Shale in East Texas and the Over-Pressured Cotton Valley in North Louisiana. For more information, please visit our website at www.wildhorserd.com.
Appendix
The tables set forth below provide additional information relating to WRD’s reserves. See “Cautionary Statements and Additional Disclosures” for more information regarding 3P reserves.
Additional 3P(1) Reserve and PV-10(2) Detail (as of December 31, 2017):
| Oil | Natural Gas | NGLs | Total | % Oil | PV-10 | |||||||||||||||||||
| (MBbl) | (MMcf) | (MBbl) | (MBoe) | (%) | ($M) | |||||||||||||||||||
| PDP |
61,914 | 210,465 | 12,506 | 109,498 | 57 | % | $ | 1,392,178 | ||||||||||||||||
| PDNP |
3,109 | 11,052 | 46 | 4,997 | 62 | % | $ | 39,015 | ||||||||||||||||
| PUD |
217,775 | 462,291 | 44,997 | 339,820 | 64 | % | $ | 2,108,144 | ||||||||||||||||
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| Total Proved |
282,798 | 683,808 | 57,549 | 454,315 | 62 | % | $ | 3,539,337 | ||||||||||||||||
| Probable |
271,491 | 433,244 | 54,256 | 397,955 | 68 | % | $ | 1,767,148 | ||||||||||||||||
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| 2P Reserves |
554,289 | 1,117,052 | 111,805 | 852,270 | 65 | % | ||||||||||||||||||
| Possible |
554,586 | 2,384,281 | 87,954 | 1,039,920 | 53 | % | $ | 3,620,826 | ||||||||||||||||
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| 3P Reserves |
1,108,875 | 3,501,333 | 199,759 | 1,892,190 | 59 | % | ||||||||||||||||||
Additional 3P(1) Reserve and PV-10(2) Detail (as of December 31, 2016):
| Oil | Natural Gas | NGLs | Total | % Oil | PV-10 | |||||||||||||||||||
| (MBbl) | (MMcf) | (MBbl) | (MBoe) | (%) | ($M) | |||||||||||||||||||
| PDP |
18,449 | 136,530 | 3,674 | 44,878 | 41 | % | $ | 361,189 | ||||||||||||||||
| PDNP |
743 | 9,351 | 90 | 2,392 | 31 | % | $ | 18,565 | ||||||||||||||||
| PUD |
68,255 | 179,222 | 7,109 | 105,235 | 65 | % | $ | 370,233 | ||||||||||||||||
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| Total Proved |
87,448 | 325,103 | 10,874 | 152,505 | 57 | % | $ | 749,988 | ||||||||||||||||
| Probable |
105,487 | 203,551 | 10,790 | 150,202 | 70 | % | $ | 366,727 | ||||||||||||||||
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| 2P Reserves |
192,934 | 528,654 | 21,664 | 302,707 | 64 | % | ||||||||||||||||||
| Possible |
237,364 | 1,540,204 | 22,149 | 516,213 | 46 | % | $ | 847,809 | ||||||||||||||||
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| 3P Reserves |
430,298 | 2,068,858 | 43,812 | 818,920 | 53 | % | ||||||||||||||||||
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3P Reserve Detail (as of December 31, 2017)(1):
| Oil | Natural Gas | NGLs | Total | % Oil | ||||||||||||||||
| (MMBbls) | (Bcf) | (MMBbls) | (MMboe) | (%) | ||||||||||||||||
| Eagle Ford |
||||||||||||||||||||
| Proved |
281.6 | 281.2 | 57.1 | 385.6 | 73 | % | ||||||||||||||
| Probable |
270.9 | 263.4 | 54.3 | 369.0 | 73 | % | ||||||||||||||
| Possible |
547.1 | 362.1 | 88.0 | 695.4 | 79 | % | ||||||||||||||
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| 3P Reserves |
1,099.6 | 906.7 | 199.4 | 1,450.0 | 76 | % | ||||||||||||||
| North Louisiana |
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| Proved |
1.2 | 402.6 | 0.4 | 68.7 | 2 | % | ||||||||||||||
| Probable |
0.6 | 169.8 | 0.0 | 28.9 | 2 | % | ||||||||||||||
| Possible |
7.5 | 2,022.2 | 0.0 | 344.6 | 2 | % | ||||||||||||||
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| 3P Reserves |
9.3 | 2,594.6 | 0.4 | 442.2 | 2 | % | ||||||||||||||
Proved Reserve – Developed and Undeveloped
| Eagle Ford | North Lousisana | |||||||||||||||
| As of December 31, | As of December 31, | |||||||||||||||
| Eagle Ford |
2016 | 2017 | 2016 | 2017 | ||||||||||||
| Proved developed reserves: |
||||||||||||||||
| Oil (MMBbls) |
18.8 | 64.5 | 0.4 | 0.5 | ||||||||||||
| Gas (Bcf) |
19.5 | 58.2 | 126.4 | 163.3 | ||||||||||||
| NGL (MMBbls) |
3.3 | 12.1 | 0.5 | 0.4 | ||||||||||||
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| Total (MMboe) |
25.4 | 86.3 | 21.9 | 28.2 | ||||||||||||
| Proved undeveloped reserves: |
|
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| Oil (MMBbls) |
67.9 | 217.1 | 0.4 | 0.6 | ||||||||||||
| Gas (Bcf) |
25.6 | 223.0 | 153.6 | 239.3 | ||||||||||||
| NGL (MMBbls) |
7.1 | 45.0 | 0.0 | 0.0 | ||||||||||||
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| Total (MMboe) |
79.3 | 299.3 | 26.0 | 40.5 | ||||||||||||
| Total proved reserves |
||||||||||||||||
| Oil (MMBbls) |
86.7 | 281.6 | 0.7 | 1.2 | ||||||||||||
| Gas (Bcf) |
45.1 | 281.2 | 280.0 | 402.6 | ||||||||||||
| NGL (MMBbls) |
10.4 | 57.1 | 0.5 | 0.4 | ||||||||||||
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| Total (MMboe) |
104.7 | 385.6 | 47.8 | 68.7 | ||||||||||||
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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.
| Eagle Ford | North Louisiana | Total WRD | ||||||||||
| Cost incurred ($’s in millions): |
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| 2017 D&C capex including facilities and capital workovers |
$ | 701.7 | $ | 78.0 | $ | 779.7 | ||||||
| Reserve additions (Mboe): |
||||||||||||
| Extensions, discoveries and additions |
142.2 | 20.3 | 162.5 | |||||||||
| Performance revisions |
72.0 | 0.2 | 72.2 | |||||||||
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| Total additions |
214.2 | 20.5 | 234.7 | |||||||||
| Total Drill-bit F&D costs ($/boe) |
$ | 3.28 | $ | 3.80 | $ | 3.32 | ||||||
Cautionary Statement Concerning Forward-Looking Statements
This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by words such as “anticipates,” “intends,” “will,” “plans,” “seeks,” “believes,” “estimates,” “could,” “expects” and similar references to future periods. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond WRD’s control. All statements, other than historical facts included in this press release, that address activities, events or developments that WRD expects or anticipates will or may occur in the future, including such things as WRD’s future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, future drilling locations and inventory, competitive strengths, goals, expansion and growth of WRD’s business and operations, plans, successful consummation and integration of acquisitions and other transactions, market conditions, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. All forward-looking statements speak only as of the date of this press release. Although WRD believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual
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outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
WRD cautions you that these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond WRD’s control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to: commodity price volatility; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory changes; the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital; and the timing of development expenditures. Information concerning these and other factors can be found in WRD’s filings with the SEC, including its Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in this press release are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by WRD will be realized, or even if realized, that they will have the expected consequences to or effects on WRD, its business or operations. WRD has no intention, and disclaims any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.
Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.
The preliminary results above are based on the most current information available to management. As a result, our final results may vary from these preliminary estimates. Such variances may be material; accordingly, you should not place undue reliance on these preliminary estimates.
PV-10 and 3P Reserves
PV-10 is a non-GAAP financial measure and represents the period-end present value of estimated future cash inflows from WRD’s natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using SEC pricing assumptions in effect at the end of the period. SEC pricing for oil and natural gas of $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
15
from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes. Moreover, GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves. Because PV-10 estimates of probable and possible reserves are more uncertain than PV-10 and standardized estimates of proved reserves, but have not been adjusted for risk due to that uncertainty, they may not be comparable with each other. Nonetheless, WRD believes that PV-10 estimates for reserve categories other than proved present useful information for investors about the future net cash flows of its reserves in the absence of a comparable GAAP measure such as standardized measure. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from reserves on a more comparable basis. At this time, WRD is unable to provide a reconciliation of PV-10 to a standardized measure because WRD has not yet finalized its calculation of the effects of income taxes for the year ended December 31, 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.
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
16
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 pending Lee County, TX acquisition with an expected close date of 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.
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 spending 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.
17
Contact:
WildHorse Resource Development Corporation
Pearce Hammond, CFA (713) 255-7094
Vice President, Investor Relations
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