Roan Resources, Inc. (NYSE: ROAN) (“Roan” or the “Company”)
today announced first quarter 2019 operating and financial
results.
First Quarter 2019 Highlights
- Production of approximately 49 thousand
barrels of oil equivalent per day (MBoe/d) (26% oil, 30% natural
gas liquids (NGLs), 44% gas), up 30% over 1Q 2018; of the 15 gross
operated wells turned online in 1Q 2019, 12 were turned online in
late March resulting in minimal new production in the quarter;
- Net loss was $58.1 million, or $0.38
per diluted share; Adjusted EBITDAX(1) (non-GAAP) was $72.8
million;
- Capital expenditures totaled $172.8
million, a $44 million reduction, or 20%, compared to 4Q 2018;
- Current production of over 53 MBoe/d(2)
(or 56 MBoe/d when adding 2.8 MBoe/d for shut in production due to
offset completion activity) with 28% being oil; 2019 development
plan continues to ramp with approximately 55 gross operated wells
to be turned to first sales in 2Q 2019 – 4Q 2019;
- Completion costs per foot reduced by
40% during the quarter as compared to 4Q 2018; record drill time of
13.7 days for a 2.5-mile Mayes well;
- Continued encouraging results from
pressure management on 16 optimally-spaced 4Q 2018 wells; average
120-day initial production (IP) rate was 1,006 Boe/d (48% oil, 21%
NGLs, 31% gas) normalized to 10,000-foot lateral; average 150-day
IP rate was 999 Boe/d (47% oil, 22% NGLs, 31% gas) normalized to
10,000-foot lateral;
- Recently completed 4-well Mad Play
unit, located in Canadian County, is the first 2019 optimized
density unit turned to first sales; average 15-day per well IP rate
of 1,818 Boe/d (45% oil, 21% NGLs, 34% gas) normalized to
10,000-foot lateral with an average projected well cost of less
than $7 million per well;
- Recently completed the 3-well Victory
Slide pad located in Grady County; average daily rate of 1,444
Boe/d (78% oil, 8% NGLs, 14% gas) normalized to 10,000-foot lateral
for the two Mayes wells with an average projected well cost of
approximately $7 million per well; and
- The company remains focused on the
evaluation of various strategic options, following recent
unsolicited indications of interest from third parties related to
the outright sale of the company or in-basin M&A and
consolidation and is in the final stages of engaging one or more
banks to assist the Company in these efforts.
“Roan is beginning to execute on its optimized strategic and
operational goals for 2019 and we remain confident in the potential
of the company and its premier asset base in the Merge play,” said
Joseph A. Mills, Roan’s Executive Chairman of the Board. “Our
acreage is located in the core of the Merge play and we expect
continued performance improvements as we optimize our full-field
development practices. We remain focused on improving our overall
drilling and completion performance and continuing to reduce
development costs. Finally, we are committed to maximizing value
for our shareholders as we evaluate our strategic options.”
1) Please see the supplemental financial information in the
table under “Non-GAAP Financial Measures” at the end of this
earnings release for a reconciliation of the non-GAAP financial
measure of Adjusted EBITDAX to its most directly comparable GAAP
financial measure 2) Current production is as of mid-May 2019 and
is adjusted to reflect additional volumes of 3.3MBoe/d that would
be realized under ethane recovery
Operational Update
Roan’s first quarter 2019 average daily production was
approximately 48.9 MBoe/d (26% oil, 30% NGLs, 44% gas), up 30% over
the first quarter of 2018. Production is currently over 53 MBoe/d
when normalized for ethane recovery.
As a reminder, production in the first quarter of 2019 exhibited
a sequential decline as a result of the halting of all completion
activity in December 2018, which limited the contribution of
production from new development wells in the first quarter.
Specifically, 12 of the 15 wells that were turned online in the
first quarter of 2019 came online in late March causing minimal new
production to be accounted for in the quarter. Additionally, NGL
and natural gas pricing dynamics in January led the company to
elect to reject ethane, which negatively impacted volumes by
approximately 3.3 MBoe/d for the month.
Three Months Ended
March 31,
2019 2018 Production Data Oil (MBbls)
1,139 1,038 Natural gas (MMcf) 11,620 8,912 Natural gas liquids
(MBbls) 1,329 874 Total volumes (MBoe) 4,405 3,397 Average daily
total volumes (MBoe/d) 48.9 37.7
The Company drilled 19 gross (13.1 net) operated wells (36 gross
lateral miles) and brought online 15 gross (12.0 net) operated
wells during the quarter. Several of these wells were drilled but
uncompleted wells (DUCs) from 2018 and not part of the 2019
optimized drilling program.
1Q 2019 Operated Well Data Drilled gross wells
19 Drilled net wells 13.1 Drilled gross lateral miles 36 First
sales gross wells 15 First sales net wells 12.0
Previously, the Company announced 16 fourth quarter 2018
optimally-spaced wells that had an average 90-day initial
production (IP) rate of 1,059 Boe/d (50% oil, 20% NGLs, 30% gas),
normalized to a 10,000-foot lateral, with an average lateral length
of approximately 7,500 feet. These wells are all being pressured
managed. At 120 days, the average IP rate on the same set of wells
was 1,006 Boe/d (48% oil, 21% NGLs, 31% gas) and at 150 days, the
average IP rate of the 15 wells with 150 days of production was 999
Boe/d (47% oil, 22% NGLs, 31% gas).
Recently, the Company completed and brought online two units,
the Mad Play and the Earl, both located in Canadian County. The Mad
Play unit is the first set of drilled and completed wells of the
optimized 2019 program and it is a 4-well unit, with two Mayes
wells and two Woodford wells, with 500 feet of horizontal
separation between wellbores located in west Merge. The Earl is a
6-well unit, with three Mayes wells and three Woodford wells, with
500 to 800 feet of horizontal separation between wellbores located
in the eastern Merge. The average per well 15-day IP rates are as
follows:
- The 4-well Mad Play unit flowed an
average 1,818 Boe/d (45% oil, 21% NGLs, 34% gas) per well from a
normalized 10,000-foot lateral (with an actual lateral length of
6,780 feet) with an average projected well cost to be under $7
million per well
- The 6-well Earl unit flowed an average
932 Boe/d (45% oil,23% NGLs, 32% gas) per well from a normalized
10,000-foot lateral (with an actual lateral length of 10,165 feet)
with an average projected well cost to be approximately $7 million
per well
- The 3 optimized Mayes wells in the Earl
unit flowed an average 1,688 Boe/d (42% oil, 25% NGLs, 33% gas)
from a normalized 10,000-foot lateral (with an actual lateral
length of 10,160 feet)
The Company also recently completed the 3-well Victory Slide pad
in Grady County with first sales on May 10th. The two Mayes wells
had an average daily rate of 1,444 Boe/d (78% oil, 8% NGLs, 14%
gas) per well from a normalized 10,000-foot lateral (with an actual
lateral length of 9,900 feet). The third well is a Woodford well
and is still cleaning up. The preliminary well costs are projected
to be approximately $7 million per well.
Drill times continue to improve, and the Company drilled its
fastest 2.5-mile well to date during the quarter. The Red Bullet
22-27-34-11-7 2MXH was drilled in 13.7 days, nearly 30% faster than
the average drill time for 2.5-mile Mayes wells.
During the quarter, there were major improvements on completion
costs. Completion costs per foot came down by over 40% as compared
to similar completion costs during the fourth quarter 2018, due to
both service cost reductions and frac design optimization.
Financial Update
First quarter 2019 net loss was $58.1 million, or $0.38 per
share, and adjusted net income (non-GAAP) was $14.3 million, or
$0.10 per share. First quarter 2019 Adjusted EBITDAX (non-GAAP) was
$72.8 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.
First quarter 2019 average realized prices were $53.18 per
barrel of oil (Bo), $12.18 per barrel of NGLs and $1.87 per Mcf of
natural gas, resulting in a total equivalent unhedged price of
$22.37 per Boe or a total equivalent hedged price of $23.59 per
Boe.
The Company’s adjusted cash operating costs for the first
quarter were $7.06 per Boe, including production expense of $3.37
per Boe, production tax of $1.14 per Boe and cash G&A expense
(non-GAAP) of $2.55 per Boe. Both production expense and cash
G&A expense were down quarter-over-quarter on a total dollar
basis. The Company expects production expenses to continue trending
down throughout the year as the benefit of the water disposal
agreement with Blue Mountain Midstream LLC is recognized, which
began early in the second quarter of 2019.
Capital expenditures for first quarter 2019 totaled
approximately $172.8 million, a $44 million reduction as compared
to the fourth quarter 2018. The Company anticipates capital
expenditures to trend sequentially lower for the remainder of the
year.
As of the end of the first quarter, Roan had $2.2 million of
cash on the balance sheet and $602.6 million drawn on its revolving
credit facility, resulting in a net debt balance of $600.4 million.
Roan currently has no other outstanding debt or letters of credit.
The Company had approximately $150 million of available liquidity
on the revolver as of March 31, 2019. The Company is in the process
of adding additional liquidity to its balance sheet.
A table of the Company’s derivative contracts as of May 10, 2019
is provided at the conclusion of this press release.
First Quarter 2019 Earnings Conference Call
Roan will host a conference call to discuss first quarter 2019
results on Wednesday, May 15, 2019 at 10:30 a.m. ET (9:30 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: 877-699-1024International dial-in:
647-689-5461Conference ID: 3767979
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: 800-585-8367 or 416-621-4642Conference ID:
3767979
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 Annual Report on Form 10-K for
the year ended December 31, 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, the
expectations of plans, strategies, objectives and growth and
anticipated financial and operational performance, the structure
and timing of any transaction or strategic alternative and whether
any transaction or strategic alternative will be completed,
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 Resources, Inc.
Roan Resources, Inc. Condensed Consolidated
Statements of Operations (Unaudited) Three
Months Ended
March 31,
2019 2018 (in thousands,
except per share amounts)
Revenues Oil sales $ 60,571 $
63,692 Natural gas sales 11,189 10,332 Natural gas sales -
Affiliates 10,592 6,558 Natural gas liquid sales 8,338 11,939
Natural gas liquid sales - Affiliates 7,849 8,449 Loss on
derivative contracts (83,642 ) (9,614 ) Total
revenues 14,897 91,356
Operating Expenses Production
expenses 14,846 8,355 Production taxes 5,039 2,386 Exploration
expenses 12,488 7,850 Depreciation, depletion, amortization and
accretion 41,572 21,865 General and administrative 15,825 14,020
Gain on sale of other assets (664 ) - Total
operating expenses 89,106 54,476
Total operating (loss)
income (74,209 ) 36,880
Other income (expense) Interest
expense, net (6,744 ) (1,799 )
Net (loss) income
before income taxes (80,953 ) 35,081 Income tax benefit
(22,897 ) -
Net (loss) income $ (58,056 ) $
35,081
Earnings (loss) per share Basic $ (0.38 ) $
0.23 Diluted $ (0.38 ) $ 0.23
Weighted average
number of shares outstanding Basic 152,540
151,294 Diluted 152,540 151,294
Roan Resources, Inc. Condensed Consolidated
Balance Sheets (Unaudited) March 31, 2019
December 31, 2018 (in thousands, except par value and share
data)
ASSETS Current assets Cash and cash equivalents
$ 2,189 $ 6,883 Accounts receivable Oil, natural gas and natural
gas liquid sales 52,506 55,564 Affiliates 5,175 9,669 Joint
interest owners and other, net 148,051 133,387 Prepaid drilling
advances 23,132 28,977 Derivative contracts 14,104 82,180 Other
current assets 10,179 6,655 Total
current assets 255,336 323,315
Noncurrent assets Oil and
natural gas properties, successful efforts method 2,801,145
2,628,333 Accumulated depreciation, depletion, amortization and
impairment (282,541 ) (230,836 ) Oil and natural gas
properties, net 2,518,604 2,397,497 Derivative contracts 4,529
20,638 Other 12,967 7,659
Total
assets $ 2,791,436 $ 2,749,109
LIABILITIES AND EQUITY Current liabilities Accounts
payable $ 121,110 $ 49,746 Accrued liabilities 131,403 176,494
Accounts payable and accrued liabilities - Affiliates - 8,577
Revenue payable 95,104 97,963 Drilling advances 36,149 31,058
Derivative contracts 5,583 845 Other current liabilities
2,552 790 Total current liabilities 391,901
365,473
Noncurrent liabilities Long-term debt 602,639
514,639 Deferred tax liabilities 333,966 356,862 Asset retirement
obligations 16,967 16,058 Derivative contracts 241 141 Other
5,679 902
Total liabilities 1,351,393
1,254,075
Commitments and contingencies Equity Class
A common stock, $0.001 par value; 800,000,000 shares authorized;
152,539,532 shares issued and outstanding at March 31, 2019 and
December 31, 2018 153 153 Preferred stock, $0.001 par value;
50,000,000 shares authorized; no shares issued and outstanding at
March 31, 2019 or December 31, 2018 - - Additional paid-in capital
1,649,466 1,646,401 Accumulated deficit (209,576 )
(151,520 )
Total equity 1,440,043
1,495,034
Total liabilities and equity $ 2,791,436 $
2,749,109
Roan Resources, Inc. Condensed
Consolidated Statements of Cash Flows (Unaudited)
Three Months Ended March 31, 2019
2018 (in thousands)
Cash flows from
operating activities Net (loss) income $ (58,056 ) $ 35,081
Adjustments to reconcile net (loss) income to net cash provided by
(used in) operating activities: Depreciation, depletion,
amortization and accretion 41,572 21,865 Unproved leasehold
amortization and impairment 11,331 7,350 Gain on sale of other
assets (664 ) - Amortization of deferred financing costs 537 145
Loss on derivative contracts 83,642 9,614 Net cash received (paid)
upon settlement of derivative contracts 2,549 (4,138 ) Equity-based
compensation 3,065 2,292 Deferred income taxes (22,897 ) - Other
1,514 - Changes in operating assets and liabilities increasing
(decreasing) cash: Accounts receivable and other assets (14,770 )
(56,369 ) Accounts payable and other liabilities 15,792
(24,614 ) Net cash provided by (used in) operating
activities 63,615 (8,774 )
Cash flows from investing
activities: Acquisition of oil and natural gas properties -
(22,935 ) Capital expenditures for oil and natural gas properties
(159,381 ) (87,549 ) Acquisition of other property and equipment
(83 ) (770 ) Proceeds from sale of other assets 1,264
- Net cash used in investing activities (158,200 )
(111,254 )
Cash flows from financing activities:
Proceeds from borrowings 88,000 121,300 Other 1,891
- Net cash provided by financing activities
89,891 121,300 Net (decrease) increase in cash
and cash equivalents (4,694 ) 1,272 Cash and cash equivalents,
beginning of period 6,883 1,471 Cash
and cash equivalents, end of period $ 2,189 $ 2,743
The following table represent the Company's open commodity
contracts at May 14, 2019:
2019 2020 Total Oil fixed price
swaps Volume (Bbl) 3,874,890 3,429,500 7,304,390
Weighted-average price $ 60.05 $ 60.57 $ 60.29
Natural
gas fixed price swaps Volume (MMBtu) 30,442,000 16,005,000
46,447,000 Weighted-average price $ 2.91 $ 2.64 $ 2.82
Natural gas basis swaps Volume (MMBtu) 22,000,000 7,320,000
29,320,000 Weighted-average price $ 0.60 $ 0.53 $ 0.58
Natural gas liquids fixed price swaps Volume (Bbl) 825,000 -
825,000 Weighted-average price $ 32.25 $ - $ 32.25
Results of Operations
The following tables represent the
Company's production and average realized prices:
Three Months EndedMarch
31,
2019 2018 Production Data Oil
(MBbls) 1,139 1,038 Natural gas (MMcf) 11,620 8,912 Natural gas
liquids (MBbls) 1,329 874 Total volumes (MBoe) 4,405 3,397 Average
daily total volumes (MBoe/d) 48.9 37.7
Average Prices -
as reported Oil (per Bbl) $ 53.18 $ 61.36 Natural gas (per Mcf)
$ 1.87 $ 1.90 Natural gas liquids (per Bbl) $ 12.18 $ 23.33 Total
(per Boe) $ 22.37 $ 29.72
Average Prices - including
impact of derivative contract settlements (1) Oil (per
Bbl) $ 59.46 $ 56.78 Natural gas (per Mcf) $ 1.53 $ 1.92 Natural
gas liquids (per Bbl) $ 13.86 $ 23.33 Total (per Boe) $ 23.59 $
28.39
Average Prices - excluding gathering,
transportation and processing (2) Oil (per Bbl) $ 53.27
$ 61.36 Natural gas (per Mcf) $ 2.50 $ 2.39 Natural gas liquids
(per Bbl) $ 16.31 $ 28.66 Total (per Boe) $ 25.30 $ 32.40
(1) Excludes settlement of derivative contracts prior to their
contractual maturity for the three months ended March 31, 2018. (2)
Excludes the effects of netting gathering, transportation, and
processing costs.
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 EndedMarch
31,
2019 2018 (in thousands, except costs per Boe)
Operating Expenses Production expenses $ 14,846 $ 8,355
Production taxes 5,039 2,386 Exploration expenses 12,488 7,850
Depreciation, depletion, amortization and accretion 41,572 21,865
General and administrative (1) 15,825 14,020 Gain on sale of other
assets (664 ) - Total $ 89,106 $ 54,476
Average Costs per Boe Production expenses $ 3.37 $ 2.46
Production taxes 1.14 0.70 Exploration expenses 2.84 2.31
Depreciation, depletion, amortization and accretion 9.44 6.44
General and administrative (1) 3.59 4.13 Gain on sale of other
assets (0.15 ) - Total $ 20.23 $ 16.04
(1)
General and administrative expenses for
the three months ended March 31, 2019 and 2018 include $3.1
million, or $0.70 per Boe, and $2.3 million, or $0.67 per Boe, of
equity-based compensation expense, respectively. General and
administrative expenses for the three months ended March 31, 2019
includes $1.5 million, or $0.34 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 other assets, and exploration expenses.
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
For the Three Months Ended March 31,
2019 March 31, 2018 (in thousands) (per diluted share)
(in thousands) (per diluted share) Net (loss) income $ (58,056 ) $
(0.38 ) $ 35,081 $ 0.23 Adjusted for Loss on derivative
contracts 83,642 0.55 9,614 0.06 Cash received (paid) upon
settlement of derivative contracts (1) 5,382 0.04 (4,515 ) (0.03 )
Exploration expense 12,488 0.08 7,850 0.05 Gain on sale of other
assets (664 ) (0.00 ) - - Total tax effect of adjustments (2)
(28,540 ) (0.19 ) - -
Adjusted net income $ 14,252 $ 0.10 $ 48,030 $
0.31 (1) Excludes cash received upon settlement of
derivative contracts prior to the original contractual maturity for
the three months ended March 31, 2018. (2) Computed by applying a
combined federal and state effective tax rate of 28.3% for the
period.
Adjusted EBITDAX
Adjusted EBITDAX is a non-GAAP financial measure. The Company
defines Adjusted EBITDAX as net income (loss) adjusted for interest
expense, income tax (benefit) 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, the
Company has not incurred historical income tax expenses.
The Company believes 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. The Company adds 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 revolving 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 March
31, 2019 2018 (in
thousands) Net (loss) income $ (58,056 ) $ 35,081 Adjusted
for Interest 6,744 1,799 Income tax benefit (22,897 ) -
Depreciation, depletion, amortization and accretion 41,572 21,865
Exploration expense 12,488 7,850 Non-cash equity-based compensation
3,065 2,292 Allowance for doubtful accounts 1,481 - Gain on sale of
other assets (664 ) - Loss on derivative contracts 83,642 9,614
Cash received (paid) upon settlement of derivative contracts (1)
5,382 (4,515 ) Adjusted EBITDAX $ 72,757
$ 73,986 (1) Excludes cash received upon
settlement of derivative contracts prior to the original
contractual maturity for the three months ended March 31, 2018
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 and bad
debt expense. 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.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20190514006054/en/
Alyson GilbertInvestor Relations
Manager405-896-3767IR@RoanResources.com
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