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
- 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
- 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)
Balance as of December 31,
2017 385.6 68.7 454.3
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
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) 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 $3.32 per Boe, based on
preliminary unaudited D&C capital expenditures in 2017,
including facilities and capital workovers. The reserve life of
WRD’s proved reserves, based on estimated 2017 production, is
approximately 41 years.
Year-End 2017 3P Reserves
CG&A audited 3P reserves at year-end 2017 were 1,892.2
MMboe, a 131% increase over 818.9 MMboe at December 31, 2016.
Year-end 3P reserves were 1,450.0 MMboe in the Eagle Ford and 442.2
MMboe in North Louisiana, an increase of 193% and 36% from year end
2016, respectively. The table below summarizes CG&A audited 3P
reserve volumes using SEC pricing:
Eagle
Ford North Louisiana Total WRD WRD PV-10
($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
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 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
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 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:
FY 2018
Guidance Pro-Forma FY 2018 Guidance North
Louisiana Divestiture(10) 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) 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)
-
($2.50)
Taxes Other than Income (% of oil & gas revenue)
5.0%
-
6.0%
5.0%
-
6.0%
Commodity Price Realizations (Unhedged)(9)
Crude Oil Realized Price (% of WTI NYMEX)
98%
-
102%
98%
-
102%
Natural Gas Realized Price (% of NYMEX to Henry Hub)
94%
-
98%
90%
-
94%
NGL Realized Price (% of WTI NYMEX)
33%
-
37%
33%
-
37%
Drilling Program Wells Spud (Gross)
100
-
110
100
-
110
Wells Completed (Gross)
100
-
110
100
-
110
D&C Capital Expenditure ($MM)
$700
-
$800
$700
-
$800
Sand Mine Capital Expenditure ($MM)
$65
-
$75
$65
-
$75
Note: Guidance as of February 12, 2018
(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.
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 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 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 $3.06 - - Expected crude production hedged
(12) 71% 33% - -
(11)
Utilizing the mid-point for collars.
(12)
Using WRD’s 2018 expected production based on the midpoint of
guidance.
Fourth Quarter and Full Year 2017 Earnings Conference
Call
WRD will report its fourth quarter and full year 2017 financial
and operating results after the market closes for trading on March
7, 2018. On the morning of March 8, 2018, management will host a
fourth quarter and full year 2017 earnings conference call at 8
a.m. Central (9 a.m. Eastern). Interested parties are invited to
participate on the call by dialing (877) 883-0383 (Conference ID:
7958045), or (412) 902-6506 for international calls, (Conference
ID: 7958045) at least 15 minutes prior to the start of the call or
via the internet at www.wildhorserd.com. A replay of the call will
be available on WRD’s website or by phone at (877) 344-7529
(Conference ID: 10115365) for a seven-day period following the
call.
About WildHorse Resource Development Corporation
WildHorse Resource Development Corporation is an independent oil
and natural gas company focused on the acquisition, exploration,
development and production of oil, natural gas and NGL properties
primarily in the Eagle Ford Shale in East Texas and the
Over-Pressured Cotton Valley in North Louisiana. For more
information, please visit our website at www.wildhorserd.com.
Appendix
The tables set forth below provide additional information
relating to WRD's reserves. See “Cautionary Statements and
Additional Disclosures” for more information regarding 3P
reserves.
Additional 3P(1) Reserve
and PV-10(2) Detail (as of December 31,
2017):
Oil Natural Gas NGLs Total %
Oil PV-10 (MBbl) (MMcf) (MBbl)
(MBoe) (%) ($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
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
2P
Reserves 554,289 1,117,052 111,805
852,270 65% Possible 554,586
2,384,281 87,954
1,039,920 53% $3,620,826
3P
Reserves 1,108,875 3,501,333 199,759
1,892,190 59%
Additional 3P(1) Reserve
and PV-10(2) Detail (as of December 31,
2016):
Oil Natural Gas NGLs Total %
Oil PV-10 (MBbl) (MMcf) (MBbl)
(MBoe) (%) ($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
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
2P
Reserves 192,934 528,654 21,664
302,707 64% Possible 237,364
1,540,204 22,149 516,213
46% $847,809
3P Reserves
430,298 2,068,858 43,812 818,920
53%
3P Reserve Detail (as of December 31,
2017)(1):
Oil Natural Gas NGLs Total %
Oil
Eagle
Ford
(MMBbls) (Bcf)
(MMBbls) (MMboe)
(%) Proved 281.6 281.2 57.1 385.6 73% Probable 270.9 263.4
54.3 369.0 73% Possible 547.1 362.1
88.0 695.4 79%
3P Reserves
1,099.6 906.7 199.4 1,450.0 76%
North
Louisiana
Proved 1.2 402.6 0.4 68.7 2% Probable 0.6 169.8 0.0 28.9 2%
Possible 7.5 2,022.2 0.0
344.6 2%
3P Reserves 9.3 2,594.6
0.4 442.2 2%
Proved Reserve – Developed and
Undeveloped
Eagle Ford
North Louisiana
As of December 31, As of December 31,
Eagle Ford
2016 2017 2016 2017
Proved developed reserves: Oil (MMBbls) 18.8 64.5 0.4
0.5 Gas (Bcf) 19.5 58.2 126.4 163.3 NGL (MMBbls) 3.3 12.1
0.5 0.4
Total (MMboe) 25.4 86.3
21.9 28.2 Proved undeveloped reserves:
Oil (MMBbls) 67.9 217.1 0.4 0.6 Gas (Bcf) 25.6 223.0 153.6 239.3
NGL (MMBbls) 7.1 45.0 0.0 0.0
Total (MMboe)
79.3 299.3 26.0 40.5 Total
proved reserves Oil (MMBbls) 86.7 281.6 0.7 1.2 Gas (Bcf) 45.1
281.2 280.0 402.6 NGL (MMBbls) 10.4 57.1 0.5 0.4
Total (MMboe) 104.7 385.6 47.8
68.7
Drill-Bit Finding and Development (“F&D”) Cost
Calculation:
Drill-bit F&D cost is an indicator used to assist in the
evaluation of the historical cost of adding proved reserves on a
per Boe basis. Consistent with industry practice, future capital
cost to develop proved undeveloped reserves are not included in
costs incurred. Drill-bit F&D costs are calculated as D&C
capital expenditures, including facilities and capital workovers,
divided by reserve additions from extensions, discoveries,
additions and performance revisions.
Cost incurred ($'s in
millions): Eagle Ford North Louisiana Total
WRD 2017 D&C capex including facilities
$701.7
$78.0 $779.7 and capital workovers
Reserve
additions (Mboe): Extensions, discoveries and additions 142.2
20.3 162.5 Performance revisions 72.0 0.2 72.2
Total additions 214.2 20.5 234.7
Total Drill-bit F&D costs ($/boe) $3.28
$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 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 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 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.
View source
version on businesswire.com: http://www.businesswire.com/news/home/20180212005542/en/
WildHorse Resource Development CorporationPearce Hammond, CFA,
713-255-7094Vice President, Investor
Relationsir@wildhorserd.com
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