Roan Resources, Inc. Reports Third Quarter 2018 Results
Roan Resources, Inc. (NYSE: ROAN) (“Roan” or the “Company”) today announced third quarter 2018 operating and financial results.
Third Quarter 2018 Highlights
- Reorganization process closed to form publicly traded Roan Resources, Inc.
- Roan uplisted to the New York Stock Exchange on November 9, 2018
- Total production increased 30% to 46.5 MBoe/d and liquids production increased 35%, quarter-over-quarter
- 27 gross operated wells were drilled with the addition of the eighth rig and 26 gross operated wells were brought to first sales during the quarter
- 23 gross operated wells selected, drilled and completed by Roan have at least 90 days of production, average 90-day peak production rate of 1,560 Boe/d (35% oil, 67% total liquids), normalized to 10,000-foot lateral; better targeting efforts yield tighter distribution and improvement in production rates
- Last quarter adjusted EBITDAX annualized (LQA) leverage ratio of 1.3x and net debt to total capitalization of 16%
- Year-to-date return on capital employed (ROCE) of 9.8% and return on equity (ROE) of 10.8%
“Third quarter 2018 was a very successful quarter for Roan,” said Tony Maranto, Roan’s Chairman and Chief Executive Officer. “We completed the last steps to becoming a standalone public Company, finalizing the reorganization process from our two predecessor companies and increasing headcount to 170 full-time employees. Additionally, operational performance from our Merge asset was impressive with 30% production growth over second quarter 2018 and over 100% production growth over third quarter 2017. This growth was achieved while maintaining our strong balance sheet with LQA leverage ratio of 1.3x and debt to capital ratio of 16%. I am tremendously proud of our team’s accomplishments.”
Operational Update
Roan’s third quarter 2018 average daily production was approximately 46.5 thousand barrels of oil equivalent per day (MBoe/d) (25% oil, 56% total liquids), up 30% over second quarter 2018 with liquids production up approximately 35% over second quarter 2018. September production was approximately 48.2 MBoe/d (26% oil, 55% total liquids).
| 3Q 2017(1) | 2Q 2018 | 3Q 2018 | |||||||||
| Production Data: | |||||||||||
| Oil (MBbls) | 453 | 878 | 1,089 | ||||||||
| Natural gas (MMcf) | 6,837 | 9,157 | 11,417 | ||||||||
| Natural gas liquids (MBbls) | 510 | 883 | 1,286 | ||||||||
| Total volumes (MBoe) | 2,103 | 3,287 | 4,278 | ||||||||
| Average daily total volumes (MBoe/d) | 22.9 | 36.1 | 46.5 | ||||||||
| (1) | Pro-forma to include both Linn and Citizen production for the full quarter | ||||||||||
The Company drilled 27 gross (19.2 net) operated wells during the third quarter, bringing the total drilled wells for the year to 66 gross (49.0 net) operated wells. The Company also brought online 26 gross (19.0 net) operated wells during the quarter, bringing the year-to-date (YTD) total of wells turned online to 58 gross (44.5 net) operated wells.
| 3Q 2018 | YTD 2018 | |||||
| Operated Well Data: | ||||||
| Drilled gross wells | 27 | 66 | ||||
| Drilled net wells | 19.2 | 49.0 | ||||
| Completed gross wells | 26 | 58 | ||||
| Completed net wells | 19.0 | 44.5 | ||||
| Total net miles completed | 33.1 | 69.3 | ||||
For wells turned online in the third quarter of 2018, the oil percentage for wells with 90 days of production increased to an average of 43%, compared to a 28% oil percentage for wells turned online in the second quarter of 2018.
Of the 58 gross wells turned online through third quarter of 2018, 29 wells targeted the Mayes formation and 29 wells targeted the Woodford formation. 40 of the 58 gross wells developed by Roan and its predecessors turned online in 2018 have had at least 90 days of production with an average 90-day peak production rate of 1,428 Boe/d (32% oil, 65% total liquids) normalized to a 10,000-foot lateral, with an average lateral length of 7,500-feet.
Included in the 58 gross wells are 23 gross operated wells that were selected, drilled and completed by Roan with at least 90 days of production. The average 90-day peak production rate for these 23 wells is 1,560 Boe/d (35% oil, 67% total liquids) normalized to a 10,000-foot lateral, with an average lateral length of 7,685-feet. These 23 wells are outperforming over 230 industry wells in the Merge on average by 27%, based on cumulative production at 90 days, which equates to approximately $1 million in additional gross revenue per well based on $60 WTI.
“The average outperformance Roan operated wells are seeing at 90 days is a direct correlation to our emphasis on targeting,” said Mr. Maranto. “We expect this trend to continue as more wells fully operated by Roan reach 90 days of production and the distribution of our operated well results continues to narrow and improve from historical averages.”
Drill times continue to trend lower as the Company has made numerous performance-driven adjustments since taking over the majority of drilling operations in January of 2018. Average drill times for two-mile Mayes wells during the third quarter were drilled in 13.8 days, an improvement of almost 50% compared to wells drilled in 2017. Average drill times for two-mile Woodford wells during the third quarter were drilled in 19.2 days, an improvement of over 35% compared to wells drilled in 2017.
Financial Update
Third quarter 2018 net loss was $301.2 million, or $1.97 per share, and third quarter 2018 adjusted net income (non-GAAP) was $32.2 million, or $0.21 per share. The third quarter net loss included the impact of income tax expense of $299.7 million attributable to the reorganization. Third quarter 2018 Adjusted EBITDAX (non-GAAP) was $75.4 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 are provided in the supporting tables or definitions at the conclusion of this press release.
Third quarter 2018 average realized prices were $68.86 per barrel of oil (Bo), $21.08 per barrel of natural gas liquids (NGLs) and $1.58 per Mcf of natural gas, resulting in a total equivalent unhedged price of $28.09 per Boe or a total equivalent hedged price of $24.83 per Boe.
The Company’s cash operating costs for the third quarter were $7.28 per Boe, including lease operating expense (LOE) of $3.44 per Boe, production tax of $1.45 per Boe and cash G&A expense (non-GAAP) of $2.39 per Boe. LOE per Boe was higher in the third quarter due to increased maintenance and surface repairs incurred on previously shut in wells once Blue Mountain’s Cryogenic plant came online. The Company expects LOE per Boe to be lower in the fourth quarter of 2018 and in 2019. Production tax also increased in the quarter due to new legislation on gross production tax in Oklahoma taking effect in July of 2018.
Non-acquisition capital expenditures for third quarter 2018 totaled approximately $244.2 million, including $226.5 million for drilling and completions and $17.7 million for other capital expenditures. Capital expenditures for the quarter were higher due to increased activity with adding an eighth rig and ramp in completion activity, as well as costs attributable to wells drilled and completed by Roan’s predecessors.
As of September 30, 2018, Roan had $3.9 million of cash on the balance sheet and $394.6 million drawn on its revolving credit facility. Roan currently has no other outstanding debt. The Company’s third quarter annualized leverage ratio remained low at 1.3x. The Company also reported strong return metrics for the quarter with ROCE at 9.8% and ROE at 10.8%.
During the third quarter of 2018, Roan entered into additional oil and natural gas derivative contracts. A table of the Company’s derivative contracts as of November 9, 2018 is provided at the conclusion of this press release.
The Company completed its fall 2018 borrowing base redetermination process for its credit facility in late September. All participating lenders consented to a borrowing base increase to $675 million, from $425 million.
2018 Guidance
The Company is projecting fourth quarter 2018 production to range between 52 and 56 MBoe/d, with total liquids at approximately 57% and the fourth quarter exit rate between 58 and 62 MBoe/d. Full-year 2018 production is expected to be between 43 and 44 MBoe/d, in-line with previous guidance.
Fourth quarter 2018 operating expenses are projected to be lower than the third quarter results. LOE is expected to be between $2.60 and $2.90 per Boe and cash G&A (non-GAAP) is expected to be between $2.10 and $2.40 per Boe.
Fourth quarter capital expenditures are expected to be between $200 million and $225 million. Therefore, total capital expenditures for 2018 are now expected to be between $760 million and $785 million, which includes $110 million to $115 million in other capital expenditures. This is an increase to previously provided guidance due to costs attributable to wells drilled and completed from the predecessor companies, adding an eighth rig earlier than originally planned and higher completion costs as the Company tests different completion designs.
| Guidance Metric |
1Q'18
Actual |
2Q'18
Actual |
3Q'18
Actual |
4Q'18
Est. |
FY'18
Est. |
||||||||||
| Total production (MBoe/d) | 37.7 | 36.1 | 46.5 | 52 - 56 | 43 - 44 | ||||||||||
| Total liquids production as % of total | 56% | 54% | 56% | ~57% | ~56% | ||||||||||
| LOE ($ per Boe) | $2.46 | $2.14 | $3.44 | $2.60 - $2.90 | $2.70 - $2.80 | ||||||||||
| Cash G&A ($ per Boe) | $3.45 | $3.12 | $2.39 | $2.10 - $2.40 | $2.67 - $2.75 | ||||||||||
| Production tax (% of revenue) | 2.2% | 2.5% | 5.2% | 5.2% - 5.3% | 3.9% - 4.1% | ||||||||||
| D&C Capex ($ in MM) | $103.9 | $144.3 | $226.5 | $175 - $195 | $650 - $670 | ||||||||||
| Other Capex ($ in MM) | $4.8 | $60.8 | $17.7 | $25 - $30 | $110 - $115 | ||||||||||
| Total Capex ($ in MM) | $108.7 | $205.1 | $244.2 | $200 - $225 | $760 - $785 | ||||||||||
The Company plans to provide formal 2019 guidance with or before year-end 2018 results early next year.
Third Quarter Earnings Conference Call
Roan will host a conference call to discuss third quarter 2018 results on Tuesday, November 13, 2018 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:
| Dial-in: 866-393-4306 |
| International dial-in: 734-385-2616 |
| Conference ID: 6791447 |
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: 6791447 |
Upcoming Confirmed Conference Participation
Members of the Roan Management team plan to attend the following investor conferences:
- December 4-5, 2018 Capital One 13th Annual Energy Conference
- January 8-9, 2019 Goldman Sachs 2019 Global Energy Conference
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 and after the Reorganization, 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 Condensed Consolidated Statements of Operations | |||||||||||||||||||||
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||||||||
| (in thousands, except per share amounts) | |||||||||||||||||||||
| Revenues | |||||||||||||||||||||
| Oil sales | $ | 74,987 | $ | 16,701 | $ | 197,356 | $ | 45,702 | |||||||||||||
| Natural gas sales | 10,442 | 11,818 | 31,900 | 29,857 | |||||||||||||||||
| Natural gas sales - Affiliates | 7,617 | 1,027 | 17,056 | 1,027 | |||||||||||||||||
| Natural gas liquid sales | 12,983 | 9,224 | 38,127 | 21,199 | |||||||||||||||||
| Natural gas liquid sales - Affiliates | 14,123 | 850 | 27,250 | 850 | |||||||||||||||||
| (Loss) gain on derivative contracts | (36,704 | ) | 131 | (100,920 | ) | 2,385 | |||||||||||||||
| Total revenues | 83,448 | 39,751 | 210,769 | 101,020 | |||||||||||||||||
| Operating Expenses | |||||||||||||||||||||
| Production expenses | 14,737 | 4,336 | 30,111 | 10,450 | |||||||||||||||||
| Gathering, transportation and processing | - | 4,890 | - | 11,360 | |||||||||||||||||
| Production taxes | 6,210 | 847 | 10,892 | 2,057 | |||||||||||||||||
| Exploration expenses | 11,646 | 4,229 | 30,129 | 4,475 | |||||||||||||||||
| Depreciation, depletion, amortization and accretion | 37,164 | 10,824 | 83,630 | 22,176 | |||||||||||||||||
| General and administrative | 13,177 | 4,489 | 40,283 | 22,062 | |||||||||||||||||
| Gain on sale of oil and natural gas properties | - | (838 | ) | - | (838 | ) | |||||||||||||||
| Total operating expenses | 82,934 | 28,777 | 195,045 | 71,742 | |||||||||||||||||
| Total operating income | 514 | 10,974 | 15,724 | 29,278 | |||||||||||||||||
| Other income (expense) | |||||||||||||||||||||
| Interest expense, net | (2,092 | ) | (264 | ) | (4,978 | ) | (441 | ) | |||||||||||||
| Net (loss) income before income taxes | (1,578 | ) | 10,710 | 10,746 | 28,837 | ||||||||||||||||
| Income tax expense | 299,662 | - | 299,662 | - | |||||||||||||||||
| Net (loss) income | $ | (301,240 | ) | $ | 10,710 | $ | (288,916 | ) | $ | 28,837 | |||||||||||
| Earnings (loss) per share | |||||||||||||||||||||
| Basic | $ | (1.97 | ) | $ | 0.11 | $ | (1.90 | ) | $ | 0.35 | |||||||||||
| Diluted | $ | (1.97 | ) | $ | 0.11 | $ | (1.90 | ) | $ | 0.35 | |||||||||||
| Weighted average number of shares outstanding | |||||||||||||||||||||
| Basic | 152,540 | 99,859 | 152,129 | 83,578 | |||||||||||||||||
| Diluted | 152,540 | 99,859 | 152,129 | 83,578 | |||||||||||||||||
| Roan Resources, Inc. | ||||||||||
| Unaudited Condensed Consolidated Balance Sheets | ||||||||||
| September 30, 2018 | December 31, 2017 | |||||||||
| (in thousands, except par value and share data) | ||||||||||
| ASSETS | ||||||||||
| Current assets | ||||||||||
| Cash and cash equivalents | $ | 3,900 | $ | 1,471 | ||||||
| Accounts receivable | ||||||||||
| Oil, natural gas and natural gas liquid sales | 47,365 | 74,527 | ||||||||
| Affiliates | 14,689 | 4,695 | ||||||||
| Joint interest owners and other | 110,991 | 320 | ||||||||
| Prepaid drilling advances | 49,279 | - | ||||||||
| Derivative contracts | 203 | 152 | ||||||||
| Other current assets | 6,412 | 930 | ||||||||
| Total current assets | 232,839 | 82,095 | ||||||||
| Noncurrent assets | ||||||||||
| Oil and natural gas properties, successful efforts method | 2,429,892 | 1,876,951 | ||||||||
| Accumulated depreciation, depletion, amortization and impairment | (183,557 | ) | (78,307 | ) | ||||||
| Oil and natural gas properties, net | 2,246,335 | 1,798,644 | ||||||||
| Other property and equipment, net | 2,935 | 1,147 | ||||||||
| Deferred financing costs | 4,417 | 2,710 | ||||||||
| Derivative contracts | - | 996 | ||||||||
| Total assets | $ | 2,486,526 | $ | 1,885,592 | ||||||
| LIABILITIES AND EQUITY | ||||||||||
| Current liabilities | ||||||||||
| Accounts payable and accrued liabilities | $ | 198,020 | $ | 10,245 | ||||||
| Accounts payable and accrued liabilities - Affiliates | 7,748 | 183,820 | ||||||||
| Revenue payable | 88,029 | - | ||||||||
| Drilling advances | 57,374 | - | ||||||||
| Derivative contracts | 64,261 | 9,279 | ||||||||
| Asset retirement obligations | 535 | - | ||||||||
| Total current liabilities | 415,967 | 203,344 | ||||||||
| Noncurrent liabilities | ||||||||||
| Long-term debt | 394,639 | 85,339 | ||||||||
| Deferred tax liabilities | 299,662 | - | ||||||||
| Asset retirement obligations | 12,876 | 10,769 | ||||||||
| Derivative contracts | 18,901 | 1,371 | ||||||||
| Other | 662 | - | ||||||||
| Total liabilities | 1,142,707 | 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 September 30, 2018 | 153 | - | ||||||||
| Preferred stock, $0.001 par value; 50,000,000 shares authorized; no shares issued and outstanding at September 30, 2018 | - | - | ||||||||
| Additional paid-in capital | 1,643,431 | - | ||||||||
| Accumulated deficit | (299,765 | ) | - | |||||||
| Members' equity | - | 1,584,769 | ||||||||
| Total equity | 1,343,819 | 1,584,769 | ||||||||
| Total liabilities and equity | $ | 2,486,526 | $ | 1,885,592 | ||||||
| Roan Resources, Inc. | ||||||||||
| Unaudited Condensed Consolidated Statements of Cash Flows | ||||||||||
|
Nine Months Ended
September 30, |
||||||||||
| 2018 | 2017 | |||||||||
| (in thousands) | ||||||||||
| Cash flows from operating activities | ||||||||||
| Net (loss) income | $ | (288,916 | ) | $ | 28,837 | |||||
| Adjustments to reconcile net (loss) income to net cash provided by operating activities: | ||||||||||
| Depreciation, depletion, amortization and accretion | 83,630 | 22,176 | ||||||||
| Unproved leasehold amortization and impairment and dry hole expense | 25,642 | 4,475 | ||||||||
| Gain on sale of oil and natural gas properties | - | (838 | ) | |||||||
| Amortization of deferred financing costs | 571 | 39 | ||||||||
| Amortization of deferred rent | 662 | - | ||||||||
| Loss (gain) on derivative contracts | 100,920 | (2,385 | ) | |||||||
| Net cash (paid) received upon settlement of derivative contracts | (27,462 | ) | 2,385 | |||||||
| Equity-based compensation | 8,060 | - | ||||||||
| Deferred income taxes | 299,662 | - | ||||||||
| Other | (111 | ) | (8 | ) | ||||||
| Changes in operating assets and liabilities increasing (decreasing) cash: | ||||||||||
| Accounts receivable - Oil, natural gas and natural gas liquid sales | 27,162 | (10,820 | ) | |||||||
| Accounts receivable - Affiliates | (9,994 | ) | (1,877 | ) | ||||||
| Accounts receivable - Joint interest owners and other | (110,671 | ) | (8,410 | ) | ||||||
| Prepaid drilling advances | (55,815 | ) | - | |||||||
| Other current assets | (5,398 | ) | (1,805 | ) | ||||||
| Accounts payable and accrued liabilities | 37,773 | 37,816 | ||||||||
| Accounts payable and accrued liabilities - Affiliates | (24,474 | ) | 1,913 | |||||||
| Drilling advances | 57,374 | (25,363 | ) | |||||||
| Revenue payable | 88,029 | 13,113 | ||||||||
| Net cash provided by operating activities | 206,644 | 59,248 | ||||||||
| Cash flows from investing activities: | ||||||||||
| Acquisition of oil and natural gas properties | (22,935 | ) | (42,701 | ) | ||||||
| Capital expenditures for oil and natural gas properties | (485,580 | ) | (138,152 | ) | ||||||
| Acquisition of other property and equipment | (2,353 | ) | (153 | ) | ||||||
| Proceeds from sale of oil and natural gas properties | - | 1,435 | ||||||||
| Purchase of investment | - | (3,000 | ) | |||||||
| Net cash used in investing activities | (510,868 | ) | (182,571 | ) | ||||||
| Cash flows from financing activities: | ||||||||||
| Proceeds from borrowings | 309,300 | 75,340 | ||||||||
| Repayment of borrowings | - | (40,000 | ) | |||||||
| Deferred financing costs | (2,279 | ) | (2,340 | ) | ||||||
| Deferred offering costs | (368 | ) | - | |||||||
| Contributions from Citizen members | - | 95,557 | ||||||||
| Distributions to Citizen members | - | (11,147 | ) | |||||||
| Net cash provided by financing activities | 306,653 | 117,410 | ||||||||
| Net increase (decrease) in cash and cash equivalents | 2,429 | (5,913 | ) | |||||||
| Cash and cash equivalents, beginning of period | 1,471 | 6,853 | ||||||||
| Cash and cash equivalents, end of period | $ | 3,900 | $ | 940 | ||||||
The following table represent the Company's open commodity contracts at November 9, 2018:
| 2018 | 2019 | 2020 | Total | |||||||||||||||||
| Oil fixed price swaps | ||||||||||||||||||||
| Volume (bbl) | 1,233,180 | 5,540,670 | 1,599,500 | 8,373,350 | ||||||||||||||||
| Weighted-average price per bbl | $ | 57.09 | $ | 59.86 | $ | 63.14 | $ | 60.08 | ||||||||||||
| Natural gas fixed price swaps | ||||||||||||||||||||
| Volume (mmbtu) | 8,004,000 | 36,500,000 | 12,325,000 | 56,829,000 | ||||||||||||||||
| Weighted-average price per mmbtu | $ | 2.94 | $ | 2.87 | $ | 2.63 | $ | 2.83 | ||||||||||||
| Natural gas basis swaps(1) | ||||||||||||||||||||
| Volume (mmbtu) | 4,600,000 | 21,900,000 | 3,640,000 | 30,140,000 | ||||||||||||||||
| Weighted-average price per mmbtu | $ | (0.54 | ) | $ | (0.58 | ) | $ | (0.62 | ) | $ | (0.58 | ) | ||||||||
| Natural gas liquids fixed price swaps | ||||||||||||||||||||
| Volume (bbl) | 230,000 | 912,500 | - | 1,142,500 | ||||||||||||||||
| Weighted-average price per bbl | $ | 34.03 | $ | 34.03 | - | $ | 34.03 | |||||||||||||
| 1) Includes PEPL contracts | ||||||||||||||||||||
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
September 30, 2018 |
Nine Months Ended
September 30, 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 | $ | 74,987 | $ | 68.86 | $ | 75,062 | $ | 68.93 | $ | 197,356 | $ | 65.70 | $ | 197,431 | $ | 65.72 | |||||||||||||||||
| Natural gas sales | $ | 18,059 | $ | 1.58 | $ | 21,739 | $ | 1.90 | $ | 48,956 | $ | 1.66 | $ | 60,919 | $ | 2.07 | |||||||||||||||||
| Natural gas liquids sales | $ | 27,106 | $ | 21.08 | $ | 35,195 | $ | 27.37 | $ | 65,377 | $ | 21.49 | $ | 83,735 | $ | 27.53 | |||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||
|
Gathering, transportation and processing |
$ | - | $ | - | $ | 11,844 | $ | 2.77 | $ | - | $ | - | $ | 30,396 | $ | 2.77 | |||||||||||||||||
Results of Operations
|
Three Months Ended
September 30, |
||||||||
| 2018 | 2017 | |||||||
| Production Data: | ||||||||
| Oil (MBbls) | 1,089 | 348 | ||||||
| Natural gas (MMcf) | 11,417 | 4,709 | ||||||
| Natural gas liquids (MBbls) | 1,286 | 405 | ||||||
| Total volumes (MBoe) | 4,278 | 1,538 | ||||||
| Average daily total volumes (MBoe/d) | 46.5 | 16.7 | ||||||
| Average Prices - as reported (1) | ||||||||
| Oil (per Bbl) | $ | 68.86 | $ | 47.99 | ||||
| Natural gas (per Mcf) | $ | 1.58 | $ | 2.73 | ||||
| Natural gas liquids (per Bbl) | $ | 21.08 | $ | 24.87 | ||||
| Total (per Boe) | $ | 28.09 | $ | 25.76 | ||||
| Average Prices - including impact of derivative contract settlements (1)(2) | ||||||||
| Oil (per Bbl) | $ | 55.71 | $ | 47.99 | ||||
| Natural gas (per Mcf) | $ | 1.62 | $ | 2.73 | ||||
| Natural gas liquids (per Bbl) | $ | 21.08 | $ | 24.87 | ||||
| Total (per Boe) | $ | 24.83 | $ | 25.76 | ||||
| Average Prices - excluding gathering, transportation and processing (3) | ||||||||
| Oil (per Bbl) | $ | 68.93 | $ | 47.99 | ||||
| Natural gas (per Mcf) | $ | 1.90 | $ | 2.73 | ||||
| Natural gas liquids (per Bbl) | $ | 27.37 | $ | 24.87 | ||||
| Total (per Boe) | $ | 30.86 | $ | 25.76 | ||||
| (1) | Average prices for the three months ended September 30, 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:
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Three Months Ended
September 30, |
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| 2018 | 2017 | ||||||||
| (in thousands, except costs per Boe) | |||||||||
| Operating Expenses | |||||||||
| Production expenses | $ | 14,737 | $ | 4,336 | |||||
| Gathering, transportation and processing (1) | - | 4,890 | |||||||
| Production taxes | 6,210 | 847 | |||||||
| Exploration expenses | 11,646 | 4,229 | |||||||
| Depreciation, depletion, amortization and accretion | 37,164 | 10,824 | |||||||
| General and administrative (2) | 13,177 | 4,489 | |||||||
| Gain on sale of oil and natural gas properties | - | (838 | ) | ||||||
| Total | $ | 82,934 | $ | 28,777 | |||||
| Average Costs per Boe | |||||||||
| Production expenses | $ | 3.44 | $ | 2.82 | |||||
| Gathering, transportation, and processing (1) | - | 3.18 | |||||||
| Production taxes | 1.45 | 0.55 | |||||||
| Exploration expenses | 2.72 | 2.75 | |||||||
| Depreciation, depletion, amortization and accretion | 8.69 | 7.04 | |||||||
| General and administrative (2) | 3.08 | 2.92 | |||||||
| Gain on sale of oil and natural gas properties | - | (0.54 | ) | ||||||
| Total | $ | 19.38 | $ | 18.72 | |||||
| (1) | Gathering, transportation and processing for the three months ended September 30, 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 September 30, 2018 include $2.9 million, or $0.69 per Boe, of equity-based compensation 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, certain exploration expenses and the income tax expense associated with our deferred tax liability as a result of the Reorganization. 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 (Loss) Income to Adjusted Net Income and Adjusted Net Income per Share
| For the Three Months Ended | |||||||||||||||||||||
| September 30, 2018 | September 30, 2017 | ||||||||||||||||||||
| (in thousands) | (per diluted share) | (in thousands) | (per diluted share) | ||||||||||||||||||
| Net (loss) income | $ | (301,240 | ) | $ | (1.97 | ) | $ | 10,710 | $ | 0.11 | |||||||||||
| Adjusted for | |||||||||||||||||||||
| Loss (gain) on derivative contracts | 36,704 | 0.24 | (131 | ) | (0.00 | ) | |||||||||||||||
| Cash (paid) received upon settlement of derivative contracts (1) | (13,551 | ) | (0.09 | ) | - | - | |||||||||||||||
| Exploration expense | 11,171 | 0.07 | 4,229 | 0.04 | |||||||||||||||||
| Gain on sale of oil and natural gas properties | - | - | (838 | ) | (0.01 | ) | |||||||||||||||
| Income tax expense resulting from Reorganization | 299,662 | 1.96 | - | - | |||||||||||||||||
| Total tax effect of adjustments (2) | (571 | ) | (0.00 | ) | - | - | |||||||||||||||
| Adjusted net income | $ | 32,175 | $ | 0.21 | $ | 13,970 | $ | 0.14 | |||||||||||||
| (1) | Excludes cash received upon settlement of derivative contracts prior to the original contractual maturity | |
| (2) |
Computed by applying a combined federal and state statutory tax rate of 25.5% for the period subsequent to the Reorganization. No tax effect is presented for periods prior to Reorganization. |
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| For the Nine Months Ended | |||||||||||||||||||||
| September 30, 2018 | September 30, 2017 | ||||||||||||||||||||
| (in thousands) | (per diluted share) | (in thousands) | (per diluted share) | ||||||||||||||||||
| Net (loss) income | $ | (288,916 | ) | $ | (1.90 | ) | $ | 28,837 | $ | 0.35 | |||||||||||
| Adjusted for | |||||||||||||||||||||
| Loss (gain) on derivative contracts | 100,920 | 0.66 | (2,385 | ) | (0.03 | ) | |||||||||||||||
| Cash (paid) received upon settlement of derivative contracts (1) | (27,839 | ) | (0.18 | ) | 130 | 0.00 | |||||||||||||||
| Exploration expense | 25,642 | 0.17 | 4,475 | 0.05 | |||||||||||||||||
| Gain on sale of oil and natural gas properties | - | - | (838 | ) | (0.01 | ) | |||||||||||||||
| Income tax expense resulting from Reorganization | 299,662 | 1.97 | - | - | |||||||||||||||||
| Total tax effect of adjustments (2) | (571 | ) | (0.00 | ) | - | - | |||||||||||||||
| Adjusted net income | $ | 108,898 | $ | 0.72 | $ | 30,219 | $ | 0.36 | |||||||||||||
| (1) | Excludes cash received upon settlement of derivative contracts prior to the original contractual maturity | |
| (2) |
Computed by applying a combined federal and state statutory tax rate of 25.5% for the period subsequent to the Reorganization. No tax effect is presented for periods prior to Reorganization. |
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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, gain (loss) on early termination of derivative contracts, and cash (paid) received upon settlement of derivative contracts. 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 (loss) income, our most directly comparable financial measures calculated and presented in accordance with GAAP for each of the periods indicated.
Reconciliation of Net (Loss) Income to Adjusted EBITDAX
| For the Three Months Ended September 30, | ||||||||||||
| 2018 | 2017 | |||||||||||
| (in thousands) | ||||||||||||
| Net (loss) income | $ | (301,240 | ) | $ | 10,710 | |||||||
| Adjusted for | ||||||||||||
| Interest | 2,092 | 264 | ||||||||||
| Income tax expense | 299,662 | - | ||||||||||
| Depreciation, depletion, amortization and accretion | 37,164 | 10,824 | ||||||||||
| Exploration expense | 11,646 | 4,229 | ||||||||||
| Non-cash equity-based compensation | 2,933 | - | ||||||||||
| Loss (gain) on derivative contracts | 36,704 | (131 | ) | |||||||||
| Cash (paid) received upon settlement of derivative contracts (1) | (13,551 | ) | - | |||||||||
| Adjusted EBITDAX | $ | 75,410 | $ | 25,896 | ||||||||
| (1) | Excludes cash received upon settlement of derivative contracts prior to the original contractual maturity | |||||||||||
| For the Nine Months Ended September 30, | ||||||||||||
| 2018 | 2017 | |||||||||||
| (in thousands) | ||||||||||||
| Net (loss) income | $ | (288,916 | ) | $ | 28,837 | |||||||
| Adjusted for | ||||||||||||
| Interest | 4,978 | 441 | ||||||||||
| Income tax expense | 299,662 | - | ||||||||||
| Depreciation, depletion, amortization and accretion | 83,630 | 22,176 | ||||||||||
| Exploration expense | 30,129 | 4,475 | ||||||||||
| Non-cash equity-based compensation | 8,060 | - | ||||||||||
| Loss (gain) on derivative contracts | 100,920 | (2,385 | ) | |||||||||
| Cash (paid) received upon settlement of derivative contracts (1) | (27,839 | ) | 130 | |||||||||
| Adjusted EBITDAX | $ | 210,624 | $ | 53,674 | ||||||||
| (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. 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.
The following table provides the YTD calculation of ROE and ROCE:
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For the |
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| ROE and ROCE | 2018 | ||||
|
(in millions) |
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| Adjusted Net Income | $ | 108.9 | |||
| Annualized Adjusted Net Income | $ | 145.2 | |||
| 3Q Equity | $ | 1,343.8 | |||
| ROE | 10.8 | % | |||
| Adjusted EBITDAX | $ | 210.6 | |||
| Less: DD&A | (83.6 | ) | |||
| Adjusted EBIT | $ | 127.0 | |||
| Annualized EBIT | $ | 169.3 | |||
| Net Debt | $ | 390.7 | |||
| 3Q Equity | $ | 1,343.8 | |||
| Total | $ | 1,734.6 | |||
| ROCE | 9.8 | % | |||
View source version on businesswire.com: https://www.businesswire.com/news/home/20181112005795/en/
