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Roan Resources, Inc. Reports Preliminary(1) Fourth Quarter and Full-Year 2018 Results

OKLAHOMA CITY--(BUSINESS WIRE)--

Roan Resources, Inc. (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: 866-393-4306
International dial-in: 734-385-2616
Conference 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 404-537-3406
International replay dial-in: 800-585-8367
Conference 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

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