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Roan Resources, Inc. Reports First Quarter 2019 Results


OKLAHOMA CITY–(BUSINESS WIRE)–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: 877-699-1024
International dial-in: 647-689-5461
Conference 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 416-621-4642
Conference 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 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
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 Ended
March 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.

Contacts

Alyson Gilbert
Investor Relations Manager
405-896-3767
[email protected]

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