Exhibit 99.1
Antero Resources Reports First Quarter 2017 Financial and Operational Results
Denver, Colorado, May 8, 2017—Antero Resources Corporation (NYSE: AR) (“Antero” or the “Company”) today released its first quarter 2017 financial and operational results. The relevant condensed consolidated financial statements are included in Antero’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, which has been filed with the Securities and Exchange Commission.
First Quarter Highlights Include:
· Net daily gas equivalent production averaged a record 2,144 MMcfe/d (28% liquids), a 22% increase over the prior year quarter
· This includes a record 99,119 Bbl/d of liquids production, a 45% increase over the prior year quarter
· Liquids production contributed 32% of total product revenues, before hedging, up from 25% the prior year
· Realized C3+ NGL price of $29.52 per barrel, 57% of average Nymex WTI price before hedging
· Realized natural gas price of $3.35 per Mcf before hedging, a $0.03 per Mcf premium to Nymex
· Realized natural gas equivalent price of $3.80 per Mcfe including NGLs, oil and hedges
· GAAP net income of $268 million, or $0.85 per share, compared to a net loss of $5 million, or $(0.02) per share, in the prior year quarter
· Adjusted net income of $56 million, or $0.18 per share, a 19% increase compared to the prior year quarter
· Adjusted EBITDAX of $365 million, a 3% increase compared to the prior year quarter
Recent Developments
Borrowing Base Reaffirmed at $4.75 Billion
As a result of the recent spring borrowing base redetermination, the borrowing base under Antero’s upstream credit facility was reaffirmed at $4.75 billion. Lender commitments under the facility remain at $4.0 billion. The bank syndicate, which is co-led by JPMorgan Chase Bank, N.A. and Wells Fargo, N.A., is currently comprised of 29 banks.
Natural Gas Firm Transportation Update
In February 2017, Energy Transfer Partners, L.P. (“Energy Transfer”) received FERC approval to proceed with the construction of the Rover Pipeline (“Rover”). Energy Transfer has confirmed its plans to place Rover into service in the third quarter of 2017, with Phases 1 and 2 expected to come on line in July 2017 and November 2017, respectively. Antero is an anchor shipper on Rover with an 800,000 MMBtu/d firm commitment. The pipeline will connect Antero’s Marcellus and Utica Shale assets to the Midwest and Gulf Coast via additional downstream firm transportation already in service. The project will also enable Antero to transport natural gas both from the Seneca (via Phase 1) and Sherwood (via Phase 2) Processing Facilities, allowing for maximum optionality on its firm transportation portfolio, and further strengthens the Company’s ability to deliver on its long-term production targets through 2020.
NGL Infrastructure Update
In February 2017, Sunoco Logistics Partners LP (“Sunoco”) began construction on the Mariner East 2 pipeline project after receiving the necessary permits from the Pennsylvania Department of Environmental Protection. The pipeline will transport NGLs from Southwestern Pennsylvania and Eastern Ohio to the Marcus Hook terminal and export facility near Philadelphia, Pennsylvania. Antero is an anchor shipper on Mariner East 2 with a 61,500 barrel per day commitment (11,500 barrels of ethane, 35,000 barrels of propane and 15,000 barrels of butane). The pipeline is expected to be placed into service in the fourth quarter of 2017. Antero is forecasting a C3+ NGL price realization improvement once Mariner East 2 is placed into service as the Company will have the ability to export ethane, propane and butane to international markets.
Firm Processing Update
Antero Resources recently committed to plants 8 through 11 at the Sherwood Facility and they are expected to be placed into service over the next 12 to 18 months. These four 200 MMcf/d plants at the Sherwood Processing Facility, in addition to Sherwood 7, will be owned by the recently formed joint venture between Antero Midstream Partners LP (NYSE: AM) (“Antero Midstream” or the “Partnership”) and MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, L.P. Plants 8 through 11 are expected to be placed into service in the third quarter of 2017, first quarter of 2018, third quarter of 2018 and fourth quarter of 2018, respectively. Plant 7 was placed into service in February of 2017.
First Quarter 2017 Financial and Operating Results
As of March 31, 2017, Antero owned a 59% limited partner interest in Antero Midstream. Antero Midstream’s results are consolidated with Antero’s results.
For the three months ended March 31, 2017, the Company reported net income of $268 million, or $0.85 per basic and diluted share, compared to a net loss of $5 million, or $(0.02) per basic and diluted share, in the first quarter of 2016. Net income for the first quarter of 2017 included the following items:
· Non-cash gain on unsettled hedges of $394 million
· Non-cash equity-based compensation expense of $26 million
· Impairment of unproved properties of $27 million
· Income tax effect of these reconciling items of $129 million
Excluding the items detailed above, the Company’s results for the first quarter of 2017 were as follows:
· Adjusted net income of $56 million, or $0.18 per basic and diluted share, a 19% increase compared to the first quarter of 2016
· Adjusted EBITDAX of $365 million, a 3% increase compared to the first quarter of 2016
For a description of adjusted net income and adjusted EBITDAX and reconciliations to their nearest comparable GAAP measures, please read “Non-GAAP Financial Measures.”
Antero’s net daily production for the first quarter of 2017 averaged 2,144 MMcfe/d, including 99,119 Bbl/d of liquids (28% liquids). First quarter 2017 production represents an organic production growth rate of 22% from the first quarter of 2016 and an 8% increase compared to the fourth quarter of 2016. First quarter 2017 C3+ natural gas liquids (“NGLs”) and oil production averaged 66,313 Bbl/d and 7,140 Bbl/d, respectively. Ethane (C2) production averaged 25,666 Bbl/d while leaving approximately 68,000 Bbl/d of ethane in the natural gas stream. Total liquids production for the first quarter of 2017 represents an organic production growth rate of 45% and 14% as compared to the first quarter of 2016 and fourth quarter of 2016, respectively.
Antero’s average natural gas price before hedging increased 61% from the prior year quarter to $3.35 per Mcf, a $0.03 per Mcf premium to the average Nymex natural gas price for the period. Virtually all of Antero’s first quarter 2017 natural gas revenue was realized at currently favorable price indices, including Columbia Gas Transmission (TCO), Chicago, MichCon, Gulf Coast and Nymex. Antero’s average realized natural gas price after hedging for the first quarter of 2017 was $3.89 per Mcf, a $0.57 premium to the Nymex average natural gas price for the period, and a 14% decrease compared to the prior year quarter. During the quarter, Antero realized a cash settled natural gas hedge gain of $75 million, or $0.54 per Mcf compared to $302 million, or $2.46 per Mcf in the prior year quarter.
The Company’s average realized C3+ NGL price before hedging for the first quarter of 2017 was $29.52 per barrel, or 57% of the average Nymex WTI oil price, which represents a 110% increase as compared to the prior year quarter. The improvement in C3+ NGL pricing is primarily due to an increase in Mont Belvieu pricing combined with an improvement in local differentials. Antero’s average realized C3+ NGL price including hedges was $24.01 per barrel, a 27% increase compared to the first quarter of 2016. The Company’s average realized ethane price before hedging for the first quarter of 2017 was $0.19 per gallon, or $8.00 per barrel. Antero’s average realized ethane price including hedges for the first quarter of 2017 was $0.21 per gallon, or $8.73 per barrel. The average realized oil price before hedging was $41.96 per barrel, a $9.81 differential to Nymex WTI and a 95% increase as compared to the first quarter of 2016. Antero’s average realized oil price including hedges was $43.17 per barrel, an $8.60 differential to Nymex WTI for the period.
Antero’s average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased from the prior year quarter by 69% to $3.57 per Mcfe. The Company’s average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, decreased by 8% to $3.80 per Mcfe compared to the prior year quarter. For the first quarter of 2017, Antero realized a total cash settled hedge gain on all products of $45 million, or $0.23 per Mcfe.
Commenting on NGL price improvements and the outlook on liquids production, Glen Warren, President and CFO, said, “NGL price realizations for the quarter were strong, as we were able to achieve a pre-hedge C3+ NGL price of 57% of the average Nymex WTI oil price, which is above the high end of our recently increased 2017 NGL price guidance range of 50% to 55%. The uptick in liquids pricing compliments our market leading liquids-rich inventory in Appalachia and further highlights the momentum we have established through increased liquids production and forward-looking approach to capitalize on the NGL infrastructure buildout in the Northeast. Looking ahead, we expect this momentum to continue as Antero Midstream’s recently announced joint venture with MarkWest combined with the expected startup of Mariner East 2 pipeline later this year provides tremendous visibility around getting our NGLs to market at favorable pricing.”
Total operating revenue for the first quarter of 2017 was $1.2 billion as compared to $721 million for the first quarter of 2016. Operating revenue for the first quarter of 2017 included a $394 million non-cash gain on unsettled hedges, while the first quarter of 2016 included a $44 million non-cash loss on unsettled hedges. During the first quarter of 2017, the non-cash gain on unsettled hedges was driven by a decrease in natural gas futures pricing. Revenue excluding the unrealized hedge gain was $802 million, a 5% increase compared to the first quarter of 2016. Liquids production contributed 32% of total product revenues before hedges in the first quarter of 2017, as compared to a 25% contribution for the prior year quarter. For a reconciliation of revenue excluding unrealized hedge gains to operating revenue, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”
Marketing revenue for the first quarter of 2017 was $66 million. Antero’s marketing revenue was primarily associated with the sale of third party gas purchased to utilize the Company’s excess firm transportation capacity on the Tennessee, Columbia Gas and Rockies Express Pipelines. Marketing expense for the first quarter of 2017 was $90 million, including costs related to excess capacity and the cost of purchasing third party gas. Net marketing expense was $24 million, or $0.12 per Mcfe, for the first quarter of 2017, representing a 50%, or $0.12 per Mcfe decrease from the first quarter of 2016.
Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) for the first quarter of 2017 was $1.59 per Mcfe, a 7% increase compared to $1.49 per Mcfe in the prior year quarter. The increase is primarily due to increased utilization of a long haul pipeline which has higher per unit transportation costs as compared to our transportation portfolio average. The per unit cash production expense for the quarter included $0.08 per Mcfe for lease operating costs, $1.38 per Mcfe for gathering, compression, processing and transportation costs and $0.13 per Mcfe for production and ad valorem taxes. Per unit general and administrative expense for the first quarter of 2017, excluding non-cash equity-based compensation expense was $0.20 per Mcfe, a 5% decrease from the first quarter of 2016, driven by the increase in production. Per unit depreciation, depletion and amortization expense decreased 13% from the prior year quarter to $1.05 per Mcfe, primarily driven by increases in Antero’s estimated recoverable reserves as well as decreases in its per unit development costs.
Adjusted EBITDAX of $365 million for the first quarter of 2017 represents a 3% increase compared to the prior year quarter. Adjusted EBITDAX margin for the quarter was $1.89 per Mcfe, representing a 15% decrease from the prior year quarter, driven primarily by a reduction in gains on settled derivatives. For the first quarter of 2017, cash flow from operations was $394 million, a 16% increase from the prior year quarter. Cash flow from operations before changes in working capital was $297 million, a 2% increase from the first quarter of 2016.
For a description of adjusted EBITDAX, adjusted EBITDAX margin, as well as cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read “Non-GAAP Financial Measures.”
The following table details the components of average net production and average realized prices for the three months ended March 31, 2017:
|
| Three Months Ended |
| ||||||||
|
| Gas |
| Oil |
| C3+ NGLs |
| Ethane |
| Combined |
|
Average Net Production |
| 1,550 |
| 7,140 |
| 66,313 |
| 25,666 |
| 2,144 |
|
|
| Gas |
| Oil |
| C3+ NGLs |
| Ethane |
| Combined |
| |||||
Average Realized Prices |
|
|
|
|
|
|
|
|
|
|
| |||||
Average realized price before settled derivatives |
| $ | 3.35 |
| $ | 41.96 |
| $ | 29.52 |
| $ | 8.00 |
| $ | 3.57 |
|
Settled derivatives |
| 0.54 |
| 1.21 |
| (5.51 | ) | 0.73 |
| 0.23 |
| |||||
Average realized price after settled derivatives |
| $ | 3.89 |
| $ | 43.17 |
| $ | 24.01 |
| $ | 8.73 |
| $ | 3.80 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Nymex average price |
| $ | 3.32 |
| $ | 51.77 |
|
|
|
|
| $ | 3.32 |
| ||
Premium / (Differential) to Nymex |
| $ | 0.57 |
| $ | (8.60 | ) |
|
|
|
| $ | 0.48 |
| ||
Marcellus Shale — Antero completed and placed on line 25 horizontal Marcellus wells during the first quarter of 2017 with an average lateral length of 8,850 feet. All 25 wells completed in the first quarter of 2017 have been on line for more than 30 days and had an average 30-day rate on choke of 18.6 MMcfe/d while rejecting ethane (21% liquids).
Current average well costs are $0.87 million per 1,000 feet of lateral in the Marcellus, which represents a 29% reduction from 2015 and in line with the fourth quarter of 2016. In the Marcellus, average drilling days from spud to final rig release declined to 12 days in the first quarter of 2017, a 49% reduction from 2015 and an 18% reduction from 2016. Antero is currently operating four drilling rigs and five completion crews in the Marcellus Shale.
One notable Marcellus pad that was completed late in the fourth quarter of 2016 had 4 wells with an average lateral length of 10,017 feet, an average BTU content of 1227 and an average of 1,700 pounds of proppant per foot. The average EUR for this pad is 2.4 Bcf/1,000 at the wellhead and 2.9 Bcfe/1,000’ processed (ethane rejection). This pad had an all-in development cost of $0.39 per Mcfe, driving attractive rates of return.
Ohio Utica Shale — Antero did not complete and place on line any wells during the quarter while managing Utica development ahead of the anticipated Rover in service date. However, the Company drilled an average of 2,757 feet per day in its laterals while drilling and casing 13 wells during the quarter. Antero is currently operating three drilling rigs and one completion crew in the Utica Shale. The Company has plans to move one of these rigs to the Marcellus Shale in the second quarter of 2017.
Current average well costs are $1.01 million per 1,000 feet of lateral in the Utica, which represents a 26% reduction from 2015 and in line with the fourth quarter of 2016. Drilling days from spud to final rig release averaged 18 days in the Utica in the first quarter of 2017.
Commenting on the continued operational momentum and Antero’s integrated business strategy, Paul Rady, Chairman and CEO said, “We continue to see increases in well productivity through the utilization of our advanced completion techniques while keeping drilling and completion costs down. We have seen encouraging early results in the Marcellus with completions yielding wellhead EURs in the 2.0 to 2.4 Bcf/1,000’ range. Importantly, some of the early results are outside of our current high graded core areas and could lead to an extension of those areas. The continued operational momentum compliments Antero’s integrated business strategy which includes best quality rock, firm transport to favorable price indices, an industry leading hedge book, significant exposure to liquids pricing upside and value created by infrastructure buildout through our 59% ownership in Antero Midstream. This high level of operational performance and integration gives us confidence in our ability to achieve our 2017 production growth guidance as well as our production growth targets through 2020.”
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com.
Low pressure gathering volumes for the first quarter of 2017 averaged 1,659 MMcf/d, a 26% increase from the first quarter of 2016 and a 9% increase sequentially. Compression volumes for the first quarter of 2017 averaged 1,028 MMcf/d, a 68% increase from the first quarter of 2016 and a 12% increase sequentially. High pressure gathering volumes for the first quarter of 2017 averaged 1,581 MMcf/d, a 28% increase from the first quarter of 2016 and a 12% increase sequentially. The increase in gathering and compression volumes was driven by production growth from Antero Resources in Antero Midstream’s area of dedication. Fresh water delivery volumes averaged 148 MBbl/d during the quarter, a 51% increase compared to the prior year quarter and a 1% decrease sequentially.
For the three months ended March 31, 2017, the Partnership reported revenues of $175 million, comprised of $92 million from the Gathering and Processing segment and $83 million from the Water Handling and Treatment segment. Revenues increased 28% compared to the prior year quarter, primarily driven by growth in throughput volumes and fresh water delivery volumes. Water Handling and Treatment segment revenues include $33 million from produced water handling and high rate water transfer services provided to Antero Resources, which is billed at cost plus 3%.
Direct operating expenses for the Gathering and Processing and Water Handling and Treatment segments were $8 million and $40 million, respectively, for a total of $48 million compared to $49 million in direct operating expenses in the prior year quarter. Water Handling and Treatment direct operating expenses include $32 million from produced water handling and high rate water transfer services. General and administrative expenses including equity-based compensation were $14 million, a $1 million increase compared to the first quarter of 2016. General and administrative expenses excluding equity-based compensation were $8 million during the first quarter of 2017, a 15% increase compared to the first quarter of 2016. The increase in general and administrative expenses was primarily driven by non-recurring expenses incurred from the processing and fractionation joint venture with MarkWest. Total operating expenses were $93 million, including $28 million of depreciation and $4 million of accretion of contingent acquisition consideration.
The Board of Directors of the general partner of the Partnership declared a cash distribution of $0.30 per unit ($1.20 per unit annualized) for the first quarter of 2017. The distribution represents a 28% increase compared to the prior year quarter and a 7% increase sequentially. The distribution is the Partnership’s ninth consecutive quarterly distribution increase since its initial public offering in November 2014 and will be paid on May 10, 2017 to unitholders of record as of May 3, 2017.
Balance Sheet and Liquidity
As of March 31, 2017, Antero’s consolidated net debt was $4.8 billion, of which $720 million were borrowings outstanding under the Company’s and Antero Midstream’s revolving credit facilities. Total borrowing capacity under these two facilities is currently $5.5 billion. Reduced for $710 million in letters of credit outstanding, the company had $4.1 billion in available consolidated liquidity as of March 31, 2017. For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”
First Quarter 2017 Capital Spending
Antero’s drilling and completion costs for the three months ended March 31, 2017 were $307 million. In addition, the Company invested $56 million for land and $50 million for proved property acquisitions. Antero Midstream invested $67 million for gathering and compression systems, $37 million for water infrastructure projects, including $19 million on the Antero Clearwater Treatment Facility and $160 million in the recently announced processing and fractionation joint venture with MarkWest.
Hedge Position
Antero currently has hedged 3.3 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from April 1, 2017 through December 31, 2023 at an average index price of $3.61 per MMBtu. At March 31, 2017, the Company’s estimated fair value of commodity derivative instruments was $2.0 billion.
The following table summarizes Antero’s hedge position as of March 31, 2017:
Period |
| Natural Gas |
| Average |
| Liquids |
| Average |
| ||
2Q 2017: |
|
|
|
|
|
|
|
|
| ||
Nymex Henry Hub |
| 1,370,000 |
| $ | 3.26 |
| — |
| — |
| |
CGTLA |
| 420,000 |
| $ | 4.13 |
| — |
| — |
| |
Chicago |
| 70,000 |
| $ | 4.38 |
| — |
| — |
| |
Propane MB ($/Gal) |
| — |
| — |
| 27,500 |
| $ | 0.38 |
| |
Ethane MB ($/Gall) |
| — |
| — |
| 20,000 |
| $ | 0.25 |
| |
Nymex WTI ($/Bbl) |
| — |
| — |
| 3,000 |
| $ | 54.75 |
| |
3Q 2017: |
|
|
|
|
|
|
|
|
| ||
Nymex Henry Hub |
| 1,370,000 |
| $ | 3.33 |
| — |
| — |
| |
CGTLA |
| 420,000 |
| $ | 4.20 |
| — |
| — |
| |
Chicago |
| 70,000 |
| $ | 4.45 |
| — |
| — |
| |
Propane MB ($/Gal) |
| — |
| — |
| 27,500 |
| $ | 0.39 |
| |
Ethane MB ($/Gal) |
| — |
| — |
| 20,000 |
| $ | 0.25 |
| |
Nymex WTI ($/Bbl) |
| — |
| — |
| 3,000 |
| $ | 54.75 |
| |
4Q 2017: |
|
|
|
|
|
|
|
|
| ||
Nymex Henry Hub |
| 1,370,000 |
| $ | 3.46 |
| — |
| — |
| |
CGTLA |
| 420,000 |
| $ | 4.37 |
| — |
| — |
| |
Chicago |
| 70,000 |
| $ | 4.68 |
| — |
| — |
| |
Propane MB ($/Gal) |
| — |
| — |
| 27,500 |
| $ | 0.40 |
| |
Ethane MB ($/Gal) |
| — |
| — |
| 20,000 |
| $ | 0.25 |
| |
Nymex WTI ($/Bbl) |
| — |
| — |
| 3,000 |
| $ | 54.75 |
| |
2017 Total |
| 1,860,000 |
| $ | 3.59 |
| 50,500 |
| N/A | (1) | |
2018: |
|
|
|
|
|
|
|
|
| ||
Nymex Henry Hub |
| 2,002,500 |
| $ | 3.91 |
| — |
| — |
| |
Propane MB ($/Gal) |
| — |
| — |
| 2,000 |
| $ | 0.65 |
| |
2019 Nymex Henry Hub |
| 2,330,000 |
| $ | 3.70 |
| — |
| — |
| |
2020 Nymex Henry Hub |
| 1,417,500 |
| $ | 3.63 |
| — |
| — |
| |
2021 Nymex Henry Hub |
| 710,000 |
| $ | 3.31 |
| — |
| — |
| |
2022 Nymex Henry Hub |
| 810,000 |
| $ | 3.18 |
| — |
| — |
| |
2023 Nymex Henry Hub |
| 50,000 |
| $ | 2.83 |
| — |
| — |
| |
(1) Average index price is not applicable as 2017 liquids hedges include propane, ethane and oil hedges.
Conference Call
A conference call is scheduled on Tuesday, May 9, 2017 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference “Antero Resources”. A telephone replay of the call will be available until Wednesday, May 17, 2017 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10103993.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company’s website until Wednesday, May 17, 2017 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company’s website before the May 9, 2017 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company’s website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Revenue excluding unrealized hedge gains as set forth in this release represents total operating revenue adjusted for non-cash gains on unsettled hedges. Antero believes that revenue excluding unrealized hedge gains is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue excluding unrealized hedge gains is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to revenue excluding unrealized hedge gains (in thousands):
|
| Three months ended |
| ||||
|
| 2016 |
| 2017 |
| ||
|
|
|
|
|
| ||
Total operating revenue |
| $ | 721,004 |
| $ | 1,195,579 |
|
Commodity derivative fair value gains |
| (279,924 | ) | (438,775 | ) | ||
Cash receipts for settled hedges |
| 324,347 |
| 44,849 |
| ||
Revenue excluding unrealized hedge gains |
| $ | 765,427 |
| $ | 801,653 |
|
Adjusted net income as set forth in this release represents net income (loss), adjusted for certain items. Antero believes that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance. The following table reconciles net income (loss) to adjusted net income (in thousands):
|
| Three months ended |
| ||||
|
| March 31, |
| ||||
|
| 2016 |
| 2017 |
| ||
|
|
|
|
|
| ||
Net income (loss) |
| $ | (5,055 | ) | $ | 268,396 |
|
Non-cash commodity derivative (gains) losses on unsettled derivatives |
| 44,423 |
| (393,926 | ) | ||
Impairment of unproved properties |
| 15,526 |
| 26,899 |
| ||
Equity-based compensation |
| 23,470 |
| 25,503 |
| ||
Income tax effect of reconciling items |
| (31,273 | ) | 129,225 |
| ||
Adjusted net income |
| $ | 47,091 |
| $ | 56,097 |
|
Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release (in thousands):
|
| Three months ended |
| ||||
|
| 2016 |
| 2017 |
| ||
|
|
|
|
|
| ||
Net cash provided by operating activities |
| $ | 340,168 |
| $ | 393,939 |
|
Net change in working capital |
| (48,830 | ) | (97,337 | ) | ||
Cash flow from operations before changes in working capital |
| $ | 291,338 |
| $ | 296,602 |
|
The following table reconciles consolidated total debt to consolidated net debt as used in this release (in thousands):
|
| December 31, |
| March 31, |
| ||
|
| 2016 |
| 2017 |
| ||
|
|
|
|
|
| ||
Bank credit facilities |
| $ | 650,000 |
| $ | 720,000 |
|
5.375% AR senior notes due 2021 |
| 1,000,000 |
| 1,000,000 |
| ||
5.125% AR senior notes due 2022 |
| 1,100,000 |
| 1,100,000 |
| ||
5.625% AR senior notes due 2023 |
| 750,000 |
| 750,000 |
| ||
5.375% AM senior notes due 2024 |
| 650,000 |
| 650,000 |
| ||
5.000% AR senior notes due 2025 |
| 600,000 |
| 600,000 |
| ||
Net unamortized premium |
| 1,749 |
| 1,721 |
| ||
Net unamortized debt issuance costs |
| (47,776 | ) | (46,419 | ) | ||
Consolidated total debt |
| $ | 4,703,973 |
| $ | 4,775,302 |
|
Less: Cash and cash equivalents |
| 31,610 |
| — |
| ||
Consolidated net debt |
| $ | 4,672,363 |
| $ | 4,775,302 |
|
Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income from continuing operations including noncontrolling interest after adjusting for those items shown in the table below. Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero’s management team believes adjusted EBITDAX is useful to an investor in evaluating the Company’s financial performance because this measure:
· is widely used by investors in the oil and gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;
· helps investors to more meaningfully evaluate and compare the results of Antero’s operations from period to period by removing the effect of its capital structure from its operating structure; and
· is used by the Company’s management team for various purposes, including as a measure of operating performance, in presentations to its board of directors, as a basis for strategic planning and forecasting. Adjusted EBITDAX is also used by our Board of Directors as a performance measure in determining executive compensation. Adjusted EBITDAX, as defined by our credit facility, is used by our lenders pursuant to covenants under our revolving credit facility and the indentures governing the Company’s senior notes.
There are significant limitations to using adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero’s net income, the lack of comparability of results of operations of different companies and the different methods of calculating adjusted EBITDAX reported by different companies. The following tables represent a reconciliation of the Company’s net income from continuing operations including noncontrolling interest to adjusted EBITDAX, a reconciliation of adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled hedges to adjusted EBITDAX margin (in thousands except adjusted EBITDAX margin).
|
| Three months ended |
| ||||
|
| March 31, |
| ||||
|
| 2016 |
| 2017 |
| ||
Net income from continuing operations including noncontrolling interest |
| $ | 10,650 |
| $ | 305,558 |
|
Commodity derivative fair value gains |
| (279,924 | ) | (438,775 | ) | ||
Gains on settled derivative instruments |
| 324,347 |
| 44,849 |
| ||
Interest expense |
| 63,284 |
| 66,670 |
| ||
Income tax expense |
| 4,815 |
| 131,346 |
| ||
Depreciation, depletion, amortization, and accretion |
| 192,180 |
| 203,366 |
| ||
Impairment of unproved properties |
| 15,526 |
| 26,899 |
| ||
Exploration expense |
| 1,014 |
| 2,107 |
| ||
Equity-based compensation expense |
| 23,470 |
| 25,503 |
| ||
Equity in earnings of unconsolidated affiliate |
| — |
| (2,231 | ) | ||
State franchise taxes . |
| 39 |
| — |
| ||
Total adjusted EBITDAX |
| 355,401 |
| 365,292 |
| ||
Interest expense |
| (63,284 | ) | (66,670 | ) | ||
Exploration expense |
| (1,014 | ) | (2,107 | ) | ||
Changes in current assets and liabilities |
| 48,830 |
| 97,337 |
| ||
State franchise taxes |
| (39 | ) | — |
| ||
Other non-cash items |
| 274 |
| 87 |
| ||
Net cash provided by operating activities |
| $ | 340,168 |
| $ | 393,939 |
|
|
| Three months ended |
| ||||
|
| March 31, |
| ||||
Adjusted EBITDAX margin ($ per Mcfe): |
| 2016 |
| 2017 |
| ||
Realized price before cash receipts for settled hedges |
| $ | 2.11 |
| $ | 3.57 |
|
Gathering, compression, and water handling and treatment revenues |
| 0.02 |
| — |
| ||
Lease operating expense |
| (0.07 | ) | (0.08 | ) | ||
Gathering, compression, processing and transportation costs |
| (1.30 | ) | (1.38 | ) | ||
Marketing, net |
| (0.24 | ) | (0.12 | ) | ||
Production and ad valorem taxes |
| (0.12 | ) | (0.13 | ) | ||
General and administrative(1) |
| (0.21 | ) | (0.20 | ) | ||
Adjusted EBITDAX margin before settled hedges |
| 0.19 |
| 1.66 |
| ||
Cash receipts for settled hedges |
| 2.03 |
| 0.23 |
| ||
Adjusted EBITDAX margin ($ per Mcfe): |
| $ | 2.22 |
| $ | 1.89 |
|
(1) Excludes equity-based stock compensation that is included in G&A.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company’s website is located at www.anteroresources.com.
This release includes “forward-looking statements”. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero’s control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions 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 the Company’s control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. 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 natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A. Risk Factors” in Antero’s Annual Report on Form 10-K for the year ended December 31, 2016.
For more information, contact Michael Kennedy — SVP — Finance, at (303) 357-6782 or mkennedy@anteroresources.com.
ANTERO RESOURCES CORPORATION
Condensed Consolidated Balance Sheets
December 31, 2016 and March 31, 2017
(unaudited)
(In thousands, except per share amounts)
|
| December 31, 2016 |
| March 31, 2017 |
| |
Assets |
|
|
|
|
| |
Current assets: |
|
|
|
|
| |
Cash and cash equivalents |
| $ | 31,610 |
| — |
|
Accounts receivable, net of allowance for doubtful accounts of $1,195 in 2016 and 2017 |
| 29,682 |
| 36,874 |
| |
Accrued revenue |
| 261,960 |
| 220,059 |
| |
Derivative instruments |
| 73,022 |
| 237,086 |
| |
Other current assets |
| 6,313 |
| 9,679 |
| |
Total current assets |
| 402,587 |
| 503,698 |
| |
Property and equipment: |
|
|
|
|
| |
Natural gas properties, at cost (successful efforts method): |
|
|
|
|
| |
Unproved properties |
| 2,331,173 |
| 2,330,010 |
| |
Proved properties |
| 9,549,671 |
| 9,942,450 |
| |
Water handling and treatment systems |
| 744,682 |
| 771,239 |
| |
Gathering systems and facilities |
| 1,723,768 |
| 1,785,669 |
| |
Other property and equipment |
| 41,231 |
| 42,290 |
| |
|
| 14,390,525 |
| 14,871,658 |
| |
Less accumulated depletion, depreciation, and amortization |
| (2,363,778 | ) | (2,566,359 | ) | |
Property and equipment, net |
| 12,026,747 |
| 12,305,299 |
| |
Derivative instruments |
| 1,731,063 |
| 1,811,435 |
| |
Investments in unconsolidated affiliates |
| 68,299 |
| 230,418 |
| |
Other assets |
| 26,854 |
| 37,804 |
| |
Total assets |
| $ | 14,255,550 |
| 14,888,654 |
|
|
|
|
|
|
| |
Liabilities and Equity |
|
|
|
|
| |
Current liabilities: |
|
|
|
|
| |
Accounts payable |
| $ | 38,627 |
| 37,706 |
|
Accrued liabilities |
| 393,803 |
| 416,588 |
| |
Revenue distributions payable |
| 163,989 |
| 198,775 |
| |
Derivative instruments |
| 203,635 |
| 54,277 |
| |
Other current liabilities |
| 17,334 |
| 16,090 |
| |
Total current liabilities |
| 817,388 |
| 723,436 |
| |
Long-term liabilities: |
|
|
|
|
| |
Long-term debt |
| 4,703,973 |
| 4,775,302 |
| |
Deferred income tax liability |
| 950,217 |
| 1,081,563 |
| |
Derivative instruments |
| 234 |
| 102 |
| |
Other liabilities |
| 55,160 |
| 54,299 |
| |
Total liabilities |
| 6,526,972 |
| 6,634,702 |
| |
Commitments and contingencies |
|
|
|
|
| |
Equity: |
|
|
|
|
| |
Stockholders’ equity: |
|
|
|
|
| |
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued |
| — |
| — |
| |
Common stock, $0.01 par value; authorized - 1,000,000 shares; issued and outstanding 314,877 shares and 315,006 shares, respectively |
| 3,149 |
| 3,150 |
| |
Additional paid-in capital |
| 5,299,481 |
| 6,407,158 |
| |
Accumulated earnings |
| 959,995 |
| 1,228,391 |
| |
Total stockholders’ equity |
| 6,262,625 |
| 7,638,699 |
| |
Noncontrolling interest in consolidated subsidiary |
| 1,465,953 |
| 615,253 |
| |
Total equity |
| 7,728,578 |
| 8,253,952 |
| |
Total liabilities and equity |
| $ | 14,255,550 |
| 14,888,654 |
|
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Operations and Comprehensive Income
Three Months Ended March 31, 2016 and 2017
(unaudited)
(In thousands, except per share amounts)
|
| Three Months Ended March 31, |
| |||
|
| 2016 |
| 2017 |
| |
Revenue: |
|
|
|
|
| |
Natural gas sales |
| $ | 254,776 |
| 466,664 |
|
Natural gas liquids sales |
| 73,065 |
| 194,652 |
| |
Oil sales |
| 10,179 |
| 26,960 |
| |
Gathering, compression, and water handling and treatment |
| 3,844 |
| 2,604 |
| |
Marketing |
| 99,216 |
| 65,924 |
| |
Commodity derivative fair value gains |
| 279,924 |
| 438,775 |
| |
Total revenue |
| 721,004 |
| 1,195,579 |
| |
Operating expenses: |
|
|
|
|
| |
Lease operating |
| 11,293 |
| 15,551 |
| |
Gathering, compression, processing, and transportation |
| 208,738 |
| 266,829 |
| |
Production and ad valorem taxes |
| 19,284 |
| 24,793 |
| |
Marketing |
| 137,933 |
| 89,993 |
| |
Exploration |
| 1,014 |
| 2,107 |
| |
Impairment of unproved properties |
| 15,526 |
| 26,899 |
| |
Depletion, depreciation, and amortization |
| 191,582 |
| 202,729 |
| |
Accretion of asset retirement obligations |
| 598 |
| 637 |
| |
General and administrative (including equity-based compensation expense of $23,470 and $25,503 in 2016 and 2017, respectively) |
| 56,287 |
| 64,698 |
| |
Total operating expenses |
| 642,255 |
| 694,236 |
| |
Operating income |
| 78,749 |
| 501,343 |
| |
Other income (expenses): |
|
|
|
|
| |
Equity in earnings of unconsolidated affiliates |
| — |
| 2,231 |
| |
Interest |
| (63,284 | ) | (66,670 | ) | |
Total other expenses |
| (63,284 | ) | (64,439 | ) | |
Income before income taxes |
| 15,465 |
| 436,904 |
| |
Provision for income tax expense |
| (4,815 | ) | (131,346 | ) | |
Net income and comprehensive income including noncontrolling interest |
| 10,650 |
| 305,558 |
| |
Net income and comprehensive income attributable to noncontrolling interest |
| 15,705 |
| 37,162 |
| |
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
| $ | (5,055 | ) | 268,396 |
|
|
|
|
|
|
| |
Earnings (loss) per common share—basic |
| $ | (0.02 | ) | 0.85 |
|
|
|
|
|
|
| |
Earnings (loss) per common share—assuming dilution |
| $ | (0.02 | ) | 0.85 |
|
|
|
|
|
|
| |
Weighted average number of shares outstanding: |
|
|
|
|
| |
Basic |
| 277,050 |
| 314,954 |
| |
Diluted |
| 277,050 |
| 315,769 |
| |
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Cash Flows
Three Months Ended March 31, 2016 and 2017
(unaudited)
(In thousands)
|
| Three Months Ended March 31, |
| |||
|
| 2016 |
| 2017 |
| |
Cash flows from operating activities: |
|
|
|
|
| |
Net income including noncontrolling interest |
| $ | 10,650 |
| 305,558 |
|
Adjustment to reconcile net income to net cash provided by operating activities: |
|
|
|
|
| |
Depletion, depreciation, amortization, and accretion |
| 192,180 |
| 203,366 |
| |
Impairment of unproved properties |
| 15,526 |
| 26,899 |
| |
Derivative fair value gains |
| (279,924 | ) | (438,775 | ) | |
Gains on settled derivatives |
| 324,347 |
| 44,849 |
| |
Deferred income tax expense |
| 4,815 |
| 131,346 |
| |
Equity-based compensation expense |
| 23,470 |
| 25,503 |
| |
Equity in earnings of unconsolidated affiliates |
| — |
| (2,231 | ) | |
Other |
| 274 |
| 87 |
| |
Changes in current assets and liabilities: |
|
|
|
|
| |
Accounts receivable |
| 651 |
| (7,192 | ) | |
Accrued revenue |
| (8,204 | ) | 41,901 |
| |
Other current assets |
| 15 |
| (3,366 | ) | |
Accounts payable |
| 4,387 |
| 12,545 |
| |
Accrued liabilities |
| 49,041 |
| 19,339 |
| |
Revenue distributions payable |
| 2,969 |
| 34,786 |
| |
Other current liabilities |
| (29 | ) | (676 | ) | |
Net cash provided by operating activities |
| 340,168 |
| 393,939 |
| |
Cash flows used in investing activities: |
|
|
|
|
| |
Additions to proved properties |
| — |
| (49,664 | ) | |
Additions to unproved properties |
| (28,675 | ) | (55,542 | ) | |
Drilling and completion costs |
| (395,185 | ) | (306,925 | ) | |
Additions to water handling and treatment systems |
| (37,036 | ) | (36,954 | ) | |
Additions to gathering systems and facilities |
| (48,686 | ) | (66,559 | ) | |
Additions to other property and equipment |
| (541 | ) | (590 | ) | |
Investment in unconsolidated affiliate |
| — |
| (159,889 | ) | |
Change in other assets |
| (9,172 | ) | (12,350 | ) | |
Net cash used in investing activities |
| (519,295 | ) | (688,473 | ) | |
Cash flows from financing activities: |
|
|
|
|
| |
Issuance of common units by Antero Midstream Partners LP |
| — |
| 223,119 |
| |
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation |
| 178,000 |
| — |
| |
Borrowings on bank credit facilities, net |
| 33,000 |
| 70,000 |
| |
Payments of deferred financing costs |
| (64 | ) | — |
| |
Distributions to noncontrolling interest in consolidated subsidiary |
| (14,013 | ) | (27,149 | ) | |
Employee tax withholding for settlement of equity compensation awards |
| (117 | ) | (1,657 | ) | |
Other |
| (1,282 | ) | (1,389 | ) | |
Net cash provided by financing activities |
| 195,524 |
| 262,924 |
| |
Net increase (decrease) in cash and cash equivalents |
| 16,397 |
| (31,610 | ) | |
Cash and cash equivalents, beginning of period |
| 23,473 |
| 31,610 |
| |
Cash and cash equivalents, end of period |
| $ | 39,870 |
| — |
|
|
|
|
|
|
| |
Supplemental disclosure of cash flow information: |
|
|
|
|
| |
Cash paid during the period for interest |
| $ | 14,350 |
| 35,770 |
|
Supplemental disclosure of noncash investing activities: |
|
|
|
|
| |
Decrease in accounts payable and accrued liabilities for additions to property and equipment |
| $ | (119,191 | ) | (10,020 | ) |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended March 31, 2016 compared to the three months ended March 31, 2017:
|
| Three Months Ended March 31, |
| Amount of |
| Percent |
| |||||
(in thousands) |
| 2016 |
| 2017 |
| (Decrease) |
| Change |
| |||
Operating revenues and other: |
|
|
|
|
|
|
|
|
| |||
Natural gas sales |
| $ | 254,776 |
| $ | 466,664 |
| $ | 211,888 |
| 83 | % |
NGLs sales |
| 73,065 |
| 194,652 |
| 121,587 |
| 166 | % | |||
Oil sales |
| 10,179 |
| 26,960 |
| 16,781 |
| 165 | % | |||
Gathering, compression, and water handling and treatment |
| 3,844 |
| 2,604 |
| (1,240 | ) | (32 | )% | |||
Marketing |
| 99,216 |
| 65,924 |
| (33,292 | ) | (34 | )% | |||
Commodity derivative fair value gains |
| 279,924 |
| 438,775 |
| 158,851 |
| 57 | % | |||
Total operating revenues and other |
| 721,004 |
| 1,195,579 |
| 474,575 |
| 66 | % | |||
Operating expenses: |
|
|
|
|
|
|
|
|
| |||
Lease operating |
| 11,293 |
| 15,551 |
| 4,258 |
| 38 | % | |||
Gathering, compression, processing, and transportation |
| 208,738 |
| 266,829 |
| 58,091 |
| 28 | % | |||
Production and ad valorem taxes |
| 19,284 |
| 24,793 |
| 5,509 |
| 29 | % | |||
Marketing |
| 137,933 |
| 89,993 |
| (47,940 | ) | (35 | )% | |||
Exploration |
| 1,014 |
| 2,107 |
| 1,093 |
| 108 | % | |||
Impairment of unproved properties |
| 15,526 |
| 26,899 |
| 11,373 |
| 73 | % | |||
Depletion, depreciation, and amortization |
| 191,582 |
| 202,729 |
| 11,147 |
| 6 | % | |||
Accretion of asset retirement obligations |
| 598 |
| 637 |
| 39 |
| 7 | % | |||
General and administrative (before equity-based compensation) |
| 32,817 |
| 39,195 |
| 6,378 |
| 19 | % | |||
Equity-based compensation |
| 23,470 |
| 25,503 |
| 2,033 |
| 9 | % | |||
Total operating expenses |
| 642,255 |
| 694,236 |
| 51,981 |
| 8 | % | |||
Operating income |
| 78,749 |
| 501,343 |
| 422,594 |
| 537 | % | |||
|
|
|
|
|
|
|
|
|
| |||
Other earnings (expenses): |
|
|
|
|
|
|
|
|
| |||
Equity in earnings of unconsolidated affiliates |
| — |
| 2,231 |
| 2,231 |
| * |
| |||
Interest expense |
| (63,284 | ) | (66,670 | ) | (3,386 | ) | 5 | % | |||
Total other expenses |
| (63,284 | ) | (64,439 | ) | (1,155 | ) | 2 | % | |||
Income before income taxes |
| 15,465 |
| 436,904 |
| 421,439 |
| 2,725 | % | |||
Income tax expense |
| (4,815 | ) | (131,346 | ) | (126,531 | ) | 2,628 | % | |||
Net income and comprehensive income including noncontrolling interest |
| 10,650 |
| 305,558 |
| 294,908 |
| 2,769 | % | |||
Net income and comprehensive income attributable to noncontrolling interest |
| 15,705 |
| 37,162 |
| 21,457 |
| 137 | % | |||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
| $ | (5,055 | ) | $ | 268,396 |
| $ | 273,451 |
| * |
|
|
|
|
|
|
|
|
|
|
| |||
Adjusted EBITDAX (1) |
| $ | 355,401 |
| $ | 365,292 |
| $ | 9,891 |
| 3 | % |
|
| Three Months Ended March 31, |
| Amount of |
| Percent |
| |||||
|
| 2016 |
| 2017 |
| (Decrease) |
| Change |
| |||
Production data: |
|
|
|
|
|
|
|
|
| |||
Natural gas (Bcf) |
| 123 |
| 139 |
| 16 |
| 14 | % | |||
C2 Ethane (MBbl) |
| 1,081 |
| 2,310 |
| 1,229 |
| 114 | % | |||
C3+ NGLs (MBbl) |
| 4,681 |
| 5,968 |
| 1,287 |
| 27 | % | |||
Oil (MBbl) |
| 472 |
| 643 |
| 171 |
| 36 | % | |||
Combined (Bcfe) |
| 160 |
| 193 |
| 33 |
| 21 | % | |||
Daily combined production (MMcfe/d) |
| 1,758 |
| 2,144 |
| 386 |
| 22 | % | |||
Average prices before effects of derivative settlements: |
|
|
|
|
|
|
|
|
| |||
Natural gas (per Mcf) |
| $ | 2.08 |
| $ | 3.35 |
| $ | 1.27 |
| 61 | % |
C2 Ethane (per Bbl) |
| $ | 6.68 |
| $ | 8.00 |
| $ | 1.32 |
| 20 | % |
C3+ NGLs (per Bbl) |
| $ | 14.07 |
| $ | 29.52 |
| $ | 15.45 |
| 110 | % |
Oil (per Bbl) |
| $ | 21.56 |
| $ | 41.96 |
| $ | 20.40 |
| 95 | % |
Combined (per Mcfe) |
| $ | 2.11 |
| $ | 3.57 |
| $ | 1.46 |
| 69 | % |
Average realized prices after effects of derivative settlements: |
|
|
|
|
|
|
|
|
| |||
Natural gas (per Mcf) |
| $ | 4.54 |
| $ | 3.89 |
| $ | (0.65 | ) | (14 | )% |
C2 Ethane (per Bbl) |
| $ | 6.68 |
| $ | 8.73 |
| $ | 2.05 |
| 31 | % |
C3+ NGLs (per Bbl) |
| $ | 18.88 |
| $ | 24.01 |
| $ | 5.13 |
| 27 | % |
Oil (per Bbl) |
| $ | 21.56 |
| $ | 43.17 |
| $ | 21.61 |
| 100 | % |
Combined (per Mcfe) |
| $ | 4.14 |
| $ | 3.80 |
| $ | (0.34 | ) | (8 | )% |
Average Costs (per Mcfe): |
|
|
|
|
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Lease operating |
| $ | 0.07 |
| $ | 0.08 |
| $ | 0.01 |
| 14 | % |
Gathering, compression, processing, and transportation |
| $ | 1.30 |
| $ | 1.38 |
| $ | 0.08 |
| 6 | % |
Production and ad valorem taxes |
| $ | 0.12 |
| $ | 0.13 |
| $ | 0.01 |
| 8 | % |
Marketing, net |
| $ | 0.24 |
| $ | 0.12 |
| $ | (0.12 | ) | (50 | )% |
Depletion, depreciation, amortization, and accretion |
| $ | 1.20 |
| $ | 1.05 |
| $ | (0.15 | ) | (13 | )% |
General and administrative (before equity-based compensation) |
| $ | 0.21 |
| $ | 0.20 |
| $ | (0.01 | ) | (5 | )% |
(1) Please see “Non-GAAP Financial Measures” for a description of Adjusted EBITDAX
*Not meaningful or applicable