Roan Resources, Inc. (NYSE: ROAN) (“Roan” or the “Company”)
today announced preliminary fourth quarter and full-year 2018
operating and financial results.
Fourth Quarter and Full-Year 2018 Highlights
- Fourth quarter production of 54.1
thousand barrels of oil equivalent per day (MBoe/d) (27% oil, 31%
NGLs, 42% gas), with a 25% increase in oil production as compared
to the third quarter 2018;
- Full-year production of 43.7 MBoe/d
(27% oil, 29% NGLs, 44% gas), a 170% increase in total production
and 200% increase in oil production as compared to the full-year
2017 period;
- Fourth quarter net income was $148.2
million, or $0.97 per diluted share; fourth quarter adjusted
EBITDAX (non-GAAP) was $87.8 million;
- Fourth quarter capital expenditures
totaled $217.2 million, an 11% decrease from third quarter 2018;
and
- 2018 proved reserves increased
approximately 32% to 306 MMBoe and $2.1 billion of PV-10 value at
year-end 2018 SEC prices.
“2018 was a transformative year for Roan,” said Tony Maranto,
Roan’s Chairman and Chief Executive Officer. “We achieved several
corporate and operational milestones throughout the year and are an
entirely different company from where we started last January. We
grew both oil and total production substantially over 2017 and are
now well positioned to implement our 2019 plan to increase
production by 30% over the 2018 period and generate free cash flow
by the fourth quarter of the year.”
1 Our audit relating to the financial information included in
this earnings release is not yet complete. Accordingly, the
information herein is subject to change as we complete our annual
audit process.
Operational Update
Roan’s fourth quarter 2018 average daily production was
approximately 54.1 MBoe/d (27% oil, 31% natural gas liquids (NGLs),
42% gas), up 16% over third quarter 2018 with oil production up
approximately 25% over third quarter 2018. Full-year 2018
production averaged 43.7 MBoe/d (27% oil, 29% NGLs, 44% gas).
4Q 2018
3Q 2018 4Q 2017
FY 2018 FY 2017 Production
Data:
Oil (MBbls) 1,360 1,089 570 4,364 1,454 Natural gas (MMcf) 12,404
11,417 7,059 41,890 17,582 Natural gas liquids (MBbls) 1,550 1,286
613 4,592 1,524 Total volumes (MBoe) 4,977 4,278 2,360 15,938 5,908
Average daily total volumes (MBoe/d) 54.1 46.5 25.6 43.7 16.2
The Company drilled 26 gross (19.1 net) operated wells (48.7
gross lateral miles) during the fourth quarter, bringing the total
drilled wells for 2018 to 92 gross (70.1 net) operated wells (143.7
gross lateral miles). The Company also brought online 20 gross
(15.3 net) operated wells during the quarter, resulting in the 2018
total of wells turned online to 78 gross (61.0 net) operated wells.
In December the Company began reducing completion activity and
ended the year with 33 drilled and uncompleted wells (DUCs).
4Q
2018 FY 2018 Operated Well Data:
Drilled gross wells 26 92 Drilled net wells 19.1 70.1
Drilled lateral miles 48.7 143.7 Completed gross wells 20 78
Completed net wells 15.3 61.0
Average 30-day initial production (IP) rates for the 20 wells
turned online during the fourth quarter was approximately 1,082
Boe/d (52% oil, 20% NGLs, 28% gas), normalized to a 10,000-foot
lateral, with an average lateral length of approximately
7,500-feet. At 90 days, the average IP for these wells was
approximately 906 Boe/d (50% oil, 21% NGLs, 29% gas), normalized to
a 10,000-foot lateral. After removing wells for improper
co-development of Mayes and Woodford completions, average 30-day IP
rates for the 16 wells turned online during the quarter was
approximately 1,265 Boe/d (51% oil, 21% NGLs, 28% gas), normalized
to a 10,000-foot lateral, with an average lateral length of
7,500-feet. At 90 days, the average IP for these 16 wells was
approximately 1,055 Boe/d (50% oil, 21% NGLs, 29% gas). Several of
these wells were brought online using specific pressure management
techniques to maximize oil production over the life of the
well.
“During the fourth quarter we began testing pressure management
techniques designed to maximize oil production by managing bottom
hole pressure drawdown rates. While this practice results in muted
initial production rates, the benefits are evident in increased oil
recoveries, stabilized GOR trends and ultimately improved well
economics. At 90 days, the cumulative oil production on the fourth
quarter completions was 15% higher compared to the average results
from the previous three quarters. This is very encouraging heading
into 2019 where we plan to utilize pressure management for the
entire year.”
Drill times trended lower throughout the year as the Company
made numerous performance-driven adjustments. Average drill times
for two-mile Mayes wells during 2018 were 15.5 days, an improvement
of over 43% compared to wells drilled in 2017. Average drill times
for two-mile Woodford wells during the year were 19 days, an
improvement of over 36% compared to wells drilled in 2017.
Completion techniques were also improved throughout the year as
the Company focused on optimizing well designs and increasing
operational efficiencies. The drilling and completion design
enhancements coupled with declining service costs equate to cost
savings of approximately $1 million per well. For 2019, the Company
anticipates two-mile well costs to average approximately $7.5
million.
Financial Update
Fourth quarter 2018 net income was $148.2 million, or $0.97 per
share, and full-year 2018 net loss was $140.7 million, or $0.92 per
share. Fourth quarter 2018 adjusted net income (non-GAAP) was $26.2
million, or $0.17 per share, and full-year 2018 adjusted net income
was $140.4 million, or $0.92 per share. Fourth quarter 2018
Adjusted EBITDAX (non-GAAP) was $87.8 million and full-year 2018
Adjusted EBITDAX was $299.3 million.
See the definitions and reconciliations of adjusted net income,
adjusted net income per share, Adjusted EBITDAX and cash general
and administrative (G&A) expense presented within this release
to the most directly comparable U.S. generally accepted accounting
principles (GAAP) financial measures provided in the supporting
tables or definitions at the conclusion of this press release.
Fourth quarter 2018 average realized prices were $57.27 per
barrel of oil (Bo), $14.90 per barrel of NGLs and $2.18 per Mcf of
natural gas, resulting in a total equivalent unhedged price of
$25.73 per Boe or a total equivalent hedged price of $24.64 per
Boe.
The Company’s cash operating costs for the fourth quarter were
$6.99 per Boe, including production expense of $3.51 per Boe,
production tax of $1.34 per Boe and cash G&A expense (non-GAAP)
of $2.14 per Boe. Production expense per Boe was higher in the
fourth quarter than previously guided to primarily due to increases
in water disposal costs. The Company expects water disposal costs
to decline in 2019 as a result of the Company’s recent agreement
with Blue Mountain Midstream LLC.
Capital expenditures for fourth quarter 2018 totaled
approximately $217.2 million. Full-year 2018 capital expenditures
totaled $773.1 million, in-line with recent guidance.
As of the end of the fourth quarter, Roan had $6.9 million of
cash on the balance sheet and $514.6 million drawn on its revolving
credit facility, resulting in a net debt balance of $507.7 million.
Roan currently has no other outstanding debt or letters of credit.
The Company upsized its borrowing base earlier this month by $75
million to $750 million, resulting in adjusted liquidity of over
$240MM at year-end 2018. The Company’s fourth quarter annualized
leverage ratio remained low at 1.4x.
During the fourth quarter of 2018 and first quarter of 2019,
Roan entered into additional oil and natural gas derivative
contracts. A table of the Company’s derivative contracts as of
March 14, 2018 is provided at the conclusion of this press
release.
2018 Reserves
Year-end 2018 proved reserves were 306 million barrels of oil
equivalent (MMBoe), a 32% increase compared with year-end 2017
proved reserves. At December 31, 2018, Roan had a Standardized
Measure of discounted future net cash flows of $1.7 billion
and proved reserves had a PV-10 of $2.1 billion. PV-10 is a
non-GAAP financial measure and generally differs from Standardized
Measure, the most directly comparable GAAP financial metric. A
supporting table and definition of PV-10 can be found at the
conclusion of this release. The Company’s forward F&D cost
based on year-end 2018 reserves is $6.71 per Boe. The 2018 SEC
average prices used by the Company’s third-party engineering
firm was $65.66 per barrel of oil, $20.35 per barrel of
natural gas liquids and $3.16 per MMBtu for natural gas.
2019 Guidance
There are no changes to the annual guidance provided on February
19, 2019. The Company has reduced its rig count to four in the
first quarter and anticipates being at approximately this level for
the remainder of the year. As previously noted, capital
expenditures will be heavily weighted to the first half of the year
with first quarter being higher than second quarter as a result of
the Company operating eight drilling rigs in January and the
majority of non-D&C capital being deployed in the quarter.
First quarter 2019 production is projected to be lower than fourth
quarter 2018 due to the temporary suspension of operated completion
activity in December and January, which allowed for the reset of
service costs and optimization of completion techniques deployed by
the Company, which is anticipated to save approximately $1 million
per well. The deferred completion activity resulted in minimal
wells coming online until mid-March.
2019 Guidance
Low
High
Annual Production (MBoe/d) 56.0
59.0 4Q 2019 Production (MBoe/d) 64.0
66.0 Oil Mix 26% 28%
Liquids Mix 58% 60% LOE ($/Boe)
$2.50 $2.80 Production Taxes (%
of Production Revenues) 5.2%
5.4% Cash G&A ($/Boe) $1.80
$2.00 Gross Operated Spuds 57 62
Gross Operated Completions 70 75
Capital Expenditures ($MM) $520
$570
Note: Assumes ethane recovery in the second quarter of 2019
through the fourth quarter of 2019.
Fourth Quarter and Full-Year 2018 Earnings Conference
Call
Roan will host a conference call to discuss fourth quarter and
full-year 2018 results on Tuesday, March 19, 2019 at 11:00 a.m. ET
(10:00 a.m. CT). Interested parties may listen to the conference
call via webcast on the Company’s website at www.RoanResources.com
under the “Investor Relations” section of the site or by phone. The
Company plans to post a presentation to the website prior to the
start of the call.
Dial-in: 866-393-4306International dial-in:
734-385-2616Conference ID: 4598253
A replay of the webcast will be available on the Company’s
website and a replay of the call will be available for two weeks by
phone:
Replay dial-in: 855-859-2056 or 404-537-3406International replay
dial-in: 800-585-8367Conference ID: 4598253
About Roan Resources
Roan is an independent oil and natural gas company headquartered
in Oklahoma City, OK focused on the development, exploration and
acquisition of unconventional oil and natural gas reserves in the
Merge, SCOOP and STACK plays of the Anadarko Basin in Oklahoma. For
more information, please visit www.RoanResources.com, where we
routinely post announcements, updates, events, investor
information, presentations and recent news releases.
Cautionary 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. All statements, other than statements of historical fact,
are forward-looking statements which contain our current
expectations about future results. These forward-looking statements
are based on certain assumptions and expectations made by the
Company, which reflect management’s experience, estimates and
perception of historical trends, current conditions and anticipated
future developments. Such statements are subject to a number of
assumptions, risks and uncertainties, many of which are beyond the
control of the Company, which may cause actual results to differ
materially from those implied or anticipated in the forward-looking
statements. When considering these forward-looking statements, you
should keep in mind the risk factors and other cautionary
statements found in the Company’s filings with the Securities and
Exchange Commission, including its Current Report on Form 8-K,
filed September 24, 2018 and any subsequently filed quarterly
reports on Form 10-Q or current reports on Form 8-K.
We caution you that these forward-looking statements are subject
to all of the risks and uncertainties, most of which are difficult
to predict and many of which are beyond our control, or incidental
to the development, production, gathering and sale of oil, natural
gas and NGLs. 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 reserves and in projecting
future rates of production, cash flow and access to capital, the
timing of development expenditures and the other risks.
Reserve engineering is a process of estimating underground
accumulations of oil, natural gas and NGLs that cannot be measured
in an exact way. The accuracy of any reserve estimate depends on
the quality of available data, the interpretation of such data and
price and cost assumptions made by reserve engineers. In addition,
the results of drilling, testing and production activities may
justify revisions of estimates that were made previously. If
significant, such revisions would change the schedule of any
further production and development drilling. Accordingly, reserve
estimates may differ significantly from the quantities of oil,
natural gas and NGLs that are ultimately recovered.
Should one or more of the risks or uncertainties described
occur, or should underlying assumptions prove incorrect, our actual
results and plans could differ materially from those expressed in
any forward-looking statements.
All forward-looking statements, expressed or implied, included
in this release are expressly qualified in their entirety by this
cautionary statement. This cautionary statement should also be
considered in connection with any subsequent written or oral
forward-looking statements that we or persons acting on our behalf
may issue.
Except as otherwise required by applicable law, we disclaim any
duty to update any forward-looking statements, all of which are
expressly qualified by the statements in this section, to reflect
events or circumstances after the date of this release.
Financial Statements
The information in the following financial statements and tables
reflect the results of Roan Resources LLC prior to September 24,
2018 and on and after September 24, 2018, the results of Roan Inc.
For periods prior to August 31, 2017, the date oil and natural gas
properties were contributed to us by Citizen Energy II, LLC and
subsidiaries of Linn Energy, Inc., the following financial
information reflects the results of Citizen, our accounting
predecessor.
Roan Resources, Inc. Unaudited Consolidated
Statements of Operations Three Months Ended
December 31,
Year Ended December 31,
2018 2017 2018 2017 (in thousands,
except per share amounts)
Revenues Oil sales $ 77,883 $
31,174 $ 275,239 $ 76,876 Natural gas sales 15,066 16,446 46,966
46,303 Natural gas sales - Affiliates 12,034 1,881 29,090 2,908
Natural gas liquid sales 13,340 14,018 51,467 35,217 Natural gas
liquid sales - Affiliates 9,755 4,231 37,005 5,081 Gain (loss) on
derivative contracts 178,974 (9,182 )
78,054 (6,797 )
Total revenues
307,052 58,568 517,821 159,588
Operating Expenses Production
expenses 17,489 6,422 47,600 16,872 Gathering, transportation and
processing - 7,242 - 18,602 Production taxes 6,687 1,628 17,579
3,685 Exploration expenses 13,174 28,154 43,303 32,629
Depreciation, depletion, amortization and accretion 40,292 15,200
123,922 37,376 General and administrative 20,591 9,295 60,874
31,357 Gain on sale of oil and natural gas properties -
- - (838 ) Total
operating expenses 98,233 67,941 293,278 139,683
Total operating
income (loss) 208,819 (9,373 ) 224,543 19,905
Other income
(expense) Interest expense, net (3,374 ) (1,020 ) (8,352 )
(1,461 ) Other income - 13 -
13
Net income (loss) before income
taxes 205,445 (10,380 ) 216,191 18,457 Income tax expense
57,200 - 356,862 -
Net income (loss) $ 148,245 $ (10,380 ) $
(140,671 ) $ 18,457
Earnings (loss) per share Basic $
0.97 $ (0.07 ) $ (0.92 ) $ 0.18 Diluted $ 0.97
$ (0.07 ) $ (0.92 ) $ 0.18
Weighted average number of
shares outstanding Basic 152,540 150,607
152,232 100,473 Diluted
152,540 150,607 152,232
100,473
Roan
Resources, Inc. Unaudited Consolidated Balance Sheets
December 31, 2018 December 31, 2017 (in thousands,
except par value and share data)
ASSETS Current
assets Cash and cash equivalents $ 6,883 $ 1,471 Accounts
receivable Oil, natural gas and natural gas liquid sales 55,564
74,527 Affiliates 9,669 4,695 Joint interest owners and other, net
133,387 320 Prepaid drilling advances 28,977 - Derivative contracts
82,180 152 Prepaid expenses 2,644 930 Other current assets
4,011 - Total current assets 323,315 82,095
Noncurrent assets Oil and natural gas properties, successful
efforts method 2,628,333 1,876,951 Accumulated depreciation,
depletion, amortization and impairment (230,836 )
(78,307 ) Oil and natural gas properties, net 2,397,497 1,798,644
Derivative contracts 20,638 996 Other 7,659
3,857
Total assets $ 2,749,109 $ 1,885,592
LIABILITIES AND EQUITY Current
liabilities Accounts payable $ 49,746 $ - Accrued liabilities
176,494 10,245 Accounts payable and accrued liabilities -
Affiliates 8,577 183,820 Revenue payable 97,963 - Drilling advances
31,058 - Derivative contracts 845 9,279 Asset retirement
obligations 790 - Total current
liabilities 365,473 203,344
Noncurrent liabilities Long-term
debt 514,639 85,339 Deferred tax liabilities 356,862 - Asset
retirement obligations 16,058 10,769 Derivative contracts 141 1,371
Other 902 -
Total liabilities
1,254,075 300,823
Commitments and contingencies
Equity Common stock, $0.001 par value; 800,000,000 shares
authorized; 152,539,532 shares issued and outstanding at December
31, 2018 153 - Preferred stock, $0.001 par value; 50,000,000 shares
authorized; no shares issued and outstanding at December 31, 2018 -
- Additional paid-in capital 1,646,401 - Accumulated deficit
(151,520 ) - Members' equity - 1,584,769
Total equity 1,495,034 1,584,769
Total liabilities and equity $ 2,749,109 $
1,885,592
Roan
Resources, Inc. Unaudited Consolidated Statements of Cash
Flows
Year Ended December 31, 2018 2017 (in
thousands)
Cash flows from operating activities Net (loss)
income $ (140,671 ) $ 18,457 Adjustments to reconcile net (loss)
income to net cash provided by operating activities: Depreciation,
depletion, amortization and accretion 123,922 37,376 Unproved
leasehold amortization and impairment 36,046 25,377 Gain on sale of
oil and natural gas properties - (838 ) Amortization of deferred
financing costs 853 175 Amortization of deferred rent 902 - (Gain)
loss on derivative contracts (78,054 ) 6,797 Net cash (paid)
received upon settlement of derivative contracts (33,279 ) 2,705
Equity-based compensation 11,030 379 Deferred income taxes 356,862
- Other 2,971 (11 ) Changes in operating assets and liabilities
increasing (decreasing) cash: Accounts receivable - Oil, natural
gas and natural gas liquid sales 18,963 (62,170 ) Accounts
receivable - Affiliates (4,974 ) (4,695 ) Accounts receivable -
Joint interest owners and other (136,367 ) (8,729 ) Prepaid
drilling advances (28,977 ) - Prepaid expenses (1,992 ) (2,312 )
Other current assets (2,584 ) (2 ) Accounts payable 16,733 -
Accrued liabilities 21,536 47,801 Accounts payable and accrued
liabilities - Affiliates (23,645 ) 31,121 Drilling advances 31,058
(25,363 ) Revenue payable 97,963 (5,793 ) Net
cash provided by operating activities 268,296 60,275
Cash
flows from investing activities: Acquisition of oil and natural
gas properties (22,935 ) (42,701 ) Capital expenditures for oil and
natural gas properties (673,465 ) (167,122 ) Acquisition of other
property and equipment (3,237 ) (1,332 ) Proceeds from sale of oil
and natural gas properties 10,545 1,435 Other -
(2,801 ) Net cash used in investing activities (689,092 )
(212,521 )
Cash flows from financing activities:
Proceeds from borrowings 429,300 105,339 Repayment of borrowings -
(40,000 ) Deferred financing costs (2,279 ) (2,885 ) Deferred
offering costs (813 ) - Contributions from Citizen members - 95,557
Distributions to Citizen members - (11,147 )
Net cash provided by financing activities 426,208
146,864 Net increase (decrease) in cash and cash
equivalents 5,412 (5,382 ) Cash and cash equivalents, beginning of
year 1,471 6,853 Cash and cash
equivalents, end of year $ 6,883 $ 1,471
The following table represents the Company's open commodity
contracts at March 14, 2019:
2019
2020 Total Oil fixed price swaps Volume (Bbl)
5,118,030 3,063,420 8,181,450 Weighted-average price $ 60.20 $
60.74 $ 60.40
Natural gas fixed price swaps Volume
(MMBtu) 41,242,080 16,005,180 57,247,260 Weighted-average price $
2.91 $ 2.64 $ 2.83
Natural gas basis swaps Volume
(MMBtu) 29,200,000 7,320,000 36,520,000 Weighted-average price $
0.60 $ 0.53 $ 0.59
Natural gas liquids fixed price
swaps Volume (Bbl) 1,095,000 - 1,095,000 Weighted-average price
$ 32.25 $ - $ 32.25
Revenue from Contracts with Customers
The Company adopted ASC 606 on January 1, 2018 using a modified
retrospective approach, which only applies to contracts that were
not completed as of the date of initial application. The adoption
did not require an adjustment to opening retained earnings for the
cumulative effect adjustment. The adoption does not have a material
impact on the timing of the Company’s revenue recognition or its
financial position, results of operations, net income, or cash
flows, but does impact the Company’s presentation of revenues and
expenses under the gross-versus-net presentation guidance in ASU
2016-08.
The following table shows the impact of the adoption of ASC 606
on the Company’s current period results as compared to the previous
revenue recognition standard, ASC Topic 605, Revenue recognition
(ASC 605):
Three Months Ended
December 31, 2018
Year Ended
December 31, 2018
Under ASC 606 Under ASC 605 Under
ASC 606 Under ASC 605 (in thousands)
(per Boe) (in thousands)
(per Boe) (in thousands) (per Boe) (in
thousands) (per Boe)
Revenues Oil sales $
77,883 $ 57.27 $ 77,968 $ 57.33 $ 275,239 $ 63.07 $ 275,399 $ 63.11
Natural gas sales $ 27,100 $ 2.18 $ 35,167 $ 2.84 $ 76,056 $ 1.82 $
96,086 $ 2.29 Natural gas liquids sales $ 23,095 $ 14.90 $ 30,286 $
19.54 $ 88,472 $ 19.27 $ 114,021 $ 24.83
Operating
expenses Gathering, transportation and
processing
$ - $ - $ 15,343 $ 3.08 $ - $ - $ 45,739 $ 2.87
Results of Operations
The following tables represent the Company's production and
average realized prices:
Three Months Ended
December 31,
2018 2017 Production Data Oil (MBbls) 1,360
570 Natural gas (MMcf) 12,404 7,059 Natural gas liquids (MBbls)
1,550 613 Total volumes (MBoe) 4,977 2,360 Average daily total
volumes (MBoe/d) 54.1 25.6
Average Prices - as
reported (1) Oil (per Bbl) $ 57.27 $ 54.69 Natural gas
(per Mcf) $ 2.18 $ 2.60 Natural gas liquids (per Bbl) $ 14.90 $
29.77 Total (per Boe) $ 25.73 $ 28.71
Average Prices -
including impact of derivative contract settlements
(1)(2) Oil (per Bbl) $ 56.23 $ 54.69 Natural gas (per Mcf) $
1.74 $ 2.64 Natural gas liquids (per Bbl) $ 15.89 $ 29.77 Total
(per Boe) $ 24.64 $ 28.85
Average Prices - excluding
gathering, transportation and processing (3) Oil (per
Bbl) $ 57.33 $ 54.69 Natural gas (per Mcf) $ 2.84 $ 2.60 Natural
gas liquids (per Bbl) $ 19.54 $ 29.77 Total (per Boe) $ 28.81 $
28.71 (1) Average prices for the three months ended December
31, 2018 reflects the adoption of ASC 606 on January 1, 2018. The
adoption of ASC 606 requires certain costs that were previously
recorded as gathering, processing and transportation expenses to be
accounted for as a deduction from revenue. We elected the modified
retrospective method of transition. Accordingly, comparative
information has not been adjusted and continues to be reported
under the previous revenue standard. (2) Excludes settlement of
derivative contracts prior to their contractual maturity. (3)
Excludes the effects of netting gathering, transportation, and
processing costs under ASC 606.
Year Ended
December 31,
2018 2017 Production Data Oil (MBbls) 4,364
1,454 Natural gas (MMcf) 41,890 17,582 Natural gas liquids (MBbls)
4,592 1,524 Total volumes (MBoe) 15,938 5,908 Average daily total
volumes (MBoe/d) 43.7 16.2
Average Prices - as
reported (1) Oil (per Bbl) $ 63.07 $ 52.87 Natural gas
(per Mcf) $ 1.82 $ 2.80 Natural gas liquids (per Bbl) $ 19.27 $
26.44 Total (per Boe) $ 27.59 $ 28.16
Average Prices -
including impact of derivative contract settlements
(1)(2) Oil (per Bbl) $ 55.87 $ 53.57 Natural gas (per Mcf) $
1.73 $ 2.89 Natural gas liquids (per Bbl) $ 19.60 $ 26.44 Total
(per Boe) $ 25.50 $ 28.60
Average Prices - excluding
gathering, transportation and processing (3) Oil (per
Bbl) $ 63.11 $ 52.87 Natural gas (per Mcf) $ 2.29 $ 2.80 Natural
gas liquids (per Bbl) $ 24.83 $ 26.44 Total (per Boe) $ 30.46 $
28.16 (1) Average prices for the year ended December 31,
2018 reflects the adoption of ASC 606 on January 1, 2018. The
adoption of ASC 606 requires certain costs that were previously
recorded as gathering, processing and transportation expenses to be
accounted for as a deduction from revenue. We elected the modified
retrospective method of transition. Accordingly, comparative
information has not been adjusted and continues to be reported
under the previous revenue standard. (2) Excludes settlement of
derivative contracts prior to their contractual maturity. (3)
Excludes the effects of netting gathering, transportation, and
processing costs under ASC 606.
Operating Expenses
Our operating expenses reflect costs incurred in the
development, production and sale of oil, natural gas and NGLs. The
following table provides information on our operating expenses:
Three Months Ended
December 31,
2018 2017 (in thousands, except costs per Boe)
Operating Expenses Production expenses $ 17,489 $ 6,422
Gathering, transportation and processing (1) - 7,242 Production
taxes 6,687 1,628 Exploration expenses 13,174 28,154 Depreciation,
depletion, amortization and accretion 40,292 15,200 General and
administrative (2) 20,591 9,295 Total $ 98,233 $
67,941
Average Costs per Boe Production expenses $
3.51 $ 2.72 Gathering, transportation, and processing (1) - 3.07
Production taxes 1.34 0.69 Exploration expenses 2.65 11.93
Depreciation, depletion, amortization and accretion 8.10 6.44
General and administrative (2) 4.14 3.94 Total $
19.74 $ 28.79 (1) Gathering, transportation and processing
for the three months ended December 31, 2018 reflects the adoption
of ASC 606 on January 1, 2018. The adoption of ASC 606 requires
certain costs that were previously recorded as gathering,
processing and transportation expenses to be accounted for as a
deduction from revenue. We elected the modified retrospective
method of transition. Accordingly, comparative information has not
been adjusted and continues to be reported under the previous
revenue standard. (2) General and administrative expenses for the
three months ended December 31, 2018 include $3.0 million, or $0.60
per Boe, of equity-based compensation expense, $3.7 million, or
$0.74 per Boe, of reorganization costs, and $3.3 million, or $0.66
per Boe, of bad debt expense.
Year Ended
December 31,
2018 2017 (in thousands, except costs per Boe)
Operating Expenses Production expenses $ 47,600 $ 16,872
Gathering, transportation and processing (1) - 18,602 Production
taxes 17,579 3,685 Exploration expenses 43,303 32,629 Depreciation,
depletion and amortization 123,922 37,376 General and
administrative (2) 60,874 31,357 Gain on sale of oil and natural
gas properties - (838 ) Total $ 293,278 $ 139,683
Average Costs per Boe Production expenses $
2.99 $ 2.86 Gathering, transportation, and processing (1) - 3.15
Production taxes 1.10 0.62 Exploration expenses 2.72 5.52
Depreciation, depletion and amortization 7.78 6.33 General and
administrative (2) 3.82 5.31 Gain on sale of oil and natural gas
properties - (0.14 ) Total $ 18.40 $ 23.64 (1)
Gathering, transportation and processing for the three
months ended December 31, 2018 reflects the adoption of ASC 606 on
January 1, 2018. The adoption of ASC 606 requires certain costs
that were previously recorded as gathering, processing and
transportation expenses to be accounted for as a deduction from
revenue. We elected the modified retrospective method of
transition. Accordingly, comparative information has not been
adjusted and continues to be reported under the previous revenue
standard. (2) General and administrative expenses for the year
ended December 31, 2018 include $11.1 million, or $0.70 per Boe, of
equity-based compensation expense, $4.6 million, or $0.29 per Boe,
of reorganization costs, and $3.3 million, or $0.21 per Boe, of bad
debt expense.
Non-GAAP Financial Measures
Adjusted Net Income and Adjusted Net Income per Share
Adjusted net income and adjusted net income per share are
non-GAAP performance measures. The Company defines adjusted net
income and adjusted net income per share as net (loss) income and
net (loss) income per share excluding non-cash gains or losses on
derivatives, gains on early terminations of derivative contracts,
gain on the sale of property, exploration expenses and the income
tax expense associated with our deferred tax liability as a result
of the reorganization of the Company completed in September 2018.
Management uses adjusted net income and adjusted net income per
share as an indicator of the Company's operational trends and
performance relative to other oil and natural gas companies.
Adjusted net income and adjusted net income per share should not be
considered an alternative to net income (loss), operating income,
or any other measure of financial performance presented in
accordance with GAAP or as an indicator of our operating
performance.
Reconciliation of Net Income (Loss) to Adjusted Net Income
and Adjusted Net Income per Share
For the Three Months Ended December 31, 2018
December 31, 2017 (in thousands) (per diluted share) (in
thousands) (per diluted share) Net income (loss) $ 148,245 $ 0.97 $
(10,380 ) $ (0.07 ) Adjusted for (Gain) loss on derivative
contracts (178,974 ) (1.17 ) 9,182 0.06 Cash (paid) received upon
settlement of derivative contracts (1) (5,440 ) (0.04 ) 320 0.00
Exploration expense 13,174 0.09 19,616 0.13 Reorganization
transaction costs 3,704 0.02 - - Income tax expense resulting from
Reorganization 4,793 0.03 - - Total tax effect of adjustments (2)
40,661 0.27 - -
Adjusted net income $ 26,163 $ 0.17 $ 18,738
$ 0.12 (1) Excludes cash received upon
settlement of derivative contracts prior to the original
contractual maturity (2)
Computed by applying a combined federal
and state effective tax rate of 24.3% for the period subsequent to
the Reorganization. No tax effect is presented for periods prior to
Reorganization.
For the Year Ended December 31, 2018 December 31,
2017 (in thousands) (per diluted share) (in thousands) (per
diluted share) Net (loss) income $ (140,671 ) $ (0.92 ) $ 18,457 $
0.18 Adjusted for (Gain) loss on derivative contracts
(78,054 ) (0.51 ) 6,797 0.07 Cash (paid) received upon settlement
of derivative contracts (1) (33,279 ) (0.22 ) 450 0.00 Exploration
expense 43,303 0.28 24,091 0.24 Gain on sale of oil and natural gas
properties - - (838 ) (0.01 ) Reorganization transaction costs
4,577 0.03 - - Income tax expense resulting from Reorganization
304,455 2.00 - - Total tax effect of adjustments (2) 40,090
0.26 - - Adjusted
net income $ 140,421 $ 0.92 $ 48,957 $ 0.49
(1) Excludes cash received upon settlement of
derivative contracts prior to the original contractual maturity (2)
Computed by applying a combined federal
and state effective tax rate of 24.3% for the period subsequent to
the Reorganization. No tax effect is presented for periods prior to
Reorganization.
Adjusted EBITDAX
Adjusted EBITDAX is a non-GAAP financial measure. We define
Adjusted EBITDAX as net income (loss) adjusted for interest
expense, income tax expense, depreciation, depletion, amortization
and accretion, exploration expense, non-cash equity-based
compensation expense, expense for allowance for doubtful accounts,
(gain) loss on derivative contracts, and cash (paid) received upon
settlement of derivative contracts, excluding amounts on contracts
settled prior to contract maturity. Adjusted EBITDAX is not a
measure of net income (loss) as determined by GAAP. Our accounting
predecessor, Roan LLC, passed through its taxable income to its
owners for income tax purposes and thus, we have not incurred
historical income tax expenses.
We believe Adjusted EBITDAX is useful because it allows our
management to more effectively evaluate the operating performance
and compare the results of our operations from period to period
without regard to our financing methods or capital structure. We
add the items listed above to net income (loss) in arriving at
Adjusted EBITDAX because these amounts can vary substantially from
company to company within our industry depending upon accounting
methods and book values of assets, capital structures and the
method by which the assets were acquired. Adjusted EBITDAX should
not be considered as an alternative to, or more meaningful than,
net income (loss) as determined in accordance with GAAP or as an
indicator of our operating performance or liquidity. Certain items
excluded from Adjusted EBITDAX are significant components in
understanding and assessing a company’s financial performance, such
as a company’s cost of capital and tax structure, as well as the
historic costs of depreciable assets, none of which are components
of Adjusted EBITDAX.
Roan’s computations of Adjusted EBITDAX may not be comparable to
other similarly titled measures of other companies or to such
measure in our credit facility or any of our other contracts.
The following tables present a reconciliation of Adjusted
EBITDAX to net income (loss), our most directly comparable
financial measure calculated and presented in accordance with GAAP
for each of the periods indicated.
Reconciliation of Net Income
(Loss) to Adjusted EBITDAX For the Three Months Ended
December 31, 2018 2017 (in thousands) Net income
(loss) $ 148,245 $ (10,380 ) Adjusted for Interest 3,374
1,020 Income tax expense 57,200 - Depreciation, depletion,
amortization and accretion 40,292 15,200 Exploration expense 13,174
28,154 Non-cash equity-based compensation 2,970 379 Reorganization
transaction costs 3,704 - Allowance for doubtful accounts 3,300 -
(Gain) loss on derivative contracts (178,974 ) 9,182 Cash (paid)
received upon settlement of derivative contracts (1) (5,440
) 320 Adjusted EBITDAX $ 87,845 $ 43,875
(1) Excludes cash received upon settlement of
derivative contracts prior to the original contractual maturity
For the Year Ended December 31, 2018
2017 (in thousands) Net (loss) income $ (140,671 ) $ 18,457
Adjusted for Interest 8,352 1,461 Income tax expense 356,862
- Depreciation, depletion, amortization and accretion 123,922
37,376 Exploration expense 43,303 32,629 Non-cash equity-based
compensation 11,030 379 Reorganization transaction costs 4,577 -
Allowance for doubtful accounts 3,300 - (Gain) loss on derivative
contracts (78,054 ) 6,797 Cash (paid) received upon settlement of
derivative contracts (1) (33,279 ) 450 Adjusted
EBITDAX $ 299,342 $ 97,549 (1) Excludes cash received
upon settlement of derivative contracts prior to the original
contractual maturity
Cash general and administrative expenses per Boe
Cash G&A expense is a non-GAAP measure, which is defined as
total general and administrative expense as determined in
accordance with GAAP less equity-based compensation expense, bad
debt expense and reorganization costs. Cash G&A expense should
not be considered as an alternative to, or more meaningful than,
total general and administrative expense as determined in
accordance with GAAP and may not be comparable to other companies’
similarly titled measures.
PV-10
PV-10 is not a financial measure calculated or presented in
accordance with GAAP and generally differs from standardized
measure, the most directly comparable GAAP financial measure,
because it does not include the effects of income taxes on future
net revenues. Neither PV-10 nor standardized measure
represents an estimate of the fair market value of our oil and
natural gas properties. We and others in the industry
use PV-10 as a measure to compare the relative size and
value of proved reserves held by companies without regard to the
specific tax characteristics of such entities. The following table
reconciles the GAAP standardized measure of discounted future net
cash flows to PV-10 at December 31, 2018 (in thousands):
Standardized
measure of discounted future net cash flows $ 1,699,701 Present
value of future income taxes discounted at 10% 391,808 PV-10
of proved reserves $ 2,091,509
View source
version on businesswire.com: https://www.businesswire.com/news/home/20190318005844/en/
Alyson GilbertInvestor Relations
Manager405-896-3767IR@RoanResources.com
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