Exhibit 99.1
Antero Resources Reports Fourth Quarter and Year-End 2013 Financial and Operating Results
Highlights:
· Average net production of 678 MMcfe/d in the fourth quarter of 2013, a 115% increase over the prior year quarter
· Adjusted net income of $73 million ($0.28 per share) for the fourth quarter of 2013, a 111% increase over the prior year quarter
· EBITDAX from continuing operations of $215 million in the fourth quarter of 2013, a 149% increase over the prior year quarter
· EBITDAX margin of $3.43 per Mcfe for the fourth quarter of 2013, a 17% increase over the prior year quarter
· Average net production of 522 MMcfe/d in 2013, a 119% increase over 2012 production from continuing operations
· Adjusted net income of $171 million ($0.65 per share) in 2013, a 215% increase over 2012
· EBITDAX from continuing operations of $649 million in 2013, a 128% increase over the prior year
· Proved reserves of 7.6 Tcfe at year-end 2013, a 78% increase from 2012 at an all-in finding and development cost of $0.58 per Mcfe
· Fully engineered and audited 3P reserves of 35.0 Tcfe at year-end 2013, a 62% increase from 2012
· Production guidance of 925 to 975 MMcfe/d for 2014 including 24,000 to 26,000 Bbl/d of liquids (16% liquids), driven by a $1.8 billion drilling and completion capital budget
Denver, Colorado, February 26, 2014—Antero Resources Corporation (NYSE: AR) (“Antero” or the “Company”) today released its fourth quarter and year-end 2013 financial and operating results. The relevant financial statements are included in Antero’s Annual Report on Form 10-K for the year ended December 31, 2013, which has been filed with the Securities and Exchange Commission (“SEC”).
Recent Developments
2014 Outlook Update
During the first two months of 2014 Antero’s three operating areas in West Virginia, Ohio and Pennsylvania have experienced severe winter weather. While presenting a challenging environment for our personnel and operations, the weather has not had an impact on our production outlook for 2014. Further, due to our diversified portfolio of firm transportation and firm sales, through the first two months of 2014, Antero’s estimated average gas price realizations, before the impact of hedges, have been at the high end of our 2014 guidance of $0.00 to $0.10 per Mcf premium to NYMEX. Our firm transportation and sales commitments will increase to over 1.6 Bcf/d by year-end 2014.
Additionally, Antero has changed the classification of ethane firm transportation in its guidance to include this fee as a component of cash production expense. Previously this fee was treated as a reduction of realized NGL sales price which resulted in a lower assumed Y-grade C3+ price as a percentage of WTI oil price. This change results in increased cash production expense and increased assumed NGL price as a percentage of WTI oil price. There is no impact to expected earnings or cash flow due to this change in classification. Accordingly, Antero is revising its 2014 guidance as follows:
|
|
|
Previous |
|
Current |
|
|
Natural gas liquids realized price |
|
50% to 52% of WTI |
|
53% to 57% of WTI |
|
|
Cash production expense(1) |
|
$1.40 — $1.50/Mcfe |
|
$1.50 — $1.60/Mcfe |
|
(1) Includes lease operating expenses, gathering, compression and transportation expenses and production taxes.
Antero confirms previously revised guidance for all other categories as summarized below:
1
|
2014 Guidance |
|
|
|
|
Total Net Production |
|
925 — 975 MMcfe/d |
|
|
Net Natural Gas Production |
|
780 — 820 MMcf/d |
|
|
Net Liquids Production |
|
24,000 — 26,000 Bbl/d |
|
|
G&A |
|
$0.25 — $0.30/Mcfe |
|
|
Natural gas realized price premium to NYMEX(1) |
|
$0.00 — $0.10/Mcf |
|
|
Oil realized price differential to NYMEX |
|
$(10.00) — $(12.00)/Bbl |
|
(1) Antero’s processed tailgate and unprocessed gas production is greater than 1000 Btu on average.
Year-End 2013 Proved and 3P Reserves
On February 4, 2014, Antero announced that proved reserves at December 31, 2013 were 7.6 Tcfe, a 78% increase compared to proved reserves at December 31, 2012, in each case assuming ethane rejection. Finding and development costs for proved reserve additions from all sources including costs incurred for drilling capital, acquisitions, leasehold additions and all price and performance revisions averaged $0.58 per Mcfe. Drill bit only finding and development costs averaged $0.45 per Mcfe for 2013. Proved developed reserves at year-end 2013 totaled 2.0 Tcfe, a 117% increase over 2012. Additionally, the percentage of proved reserves classified as proved developed increased from 22% at year-end 2012 to 27% as of December 31, 2013. The Company’s fully engineered and audited proved, probable and possible (“3P”) reserves at year-end 2013 totaled 35.0 Tcfe, which represents a 62% increase compared to last year, also assuming ethane rejection.
2014 Capital Budget
On January 29, 2014, Antero announced that it expects to invest approximately $2.6 billion in 2014 for drilling and completion, midstream and leasehold activities. Antero’s capital budget for 2014 includes $1.8 billion for drilling and completion, $600 million for the expansion of midstream facilities, including $200 million for fresh water distribution infrastructure, and $200 million for core leasehold acreage acquisitions. The midstream budget assumes the completion of the IPO of the Company’s midstream business as an MLP.
Operating Update
On January 27, 2014, Antero provided a fourth quarter 2013 operating update. The update included detail on the continued encouraging results from the Company’s SSL program in the Marcellus Shale, strong initial production rates on five additional Utica Shale wells and 30-day production rates on the first 11 core area Utica wells. Additionally, it was announced that the first compressor station in the Utica serving Antero’s production was placed into service in late January 2014.
Chairman and CEO Paul M. Rady, commented, “2013 was a historic year for Antero as we took the Company public in the largest U.S. independent E&P IPO in history. We also grew our fully engineered and audited 3P reserves by 62% to 35.0 Tcfe and average net daily production by 115% to 678 MMcfe/d. All of this was accomplished with peer group leading 3-year development costs per Mcfe, 2013 average price realizations and EBITDAX margin. Since our IPO in October 2013, we have continued to set the stage for our high growth business model by committing to additional firm transportation and processing, hedging prices on additional natural gas volumes and expanding our liquids-rich acreage position in the Marcellus and Utica Shales.”
Fourth Quarter 2013 Financial Results
For the three months ended December 31, 2013, Antero reported a net loss from continuing operations of $225 million, or $(0.86) per basic and diluted share, compared to net income of $85 million in the fourth quarter for 2012. The GAAP net loss for the fourth quarter of 2013 included the following items:
· Non-cash gains on unsettled hedges of $152 million ($94 million net of tax)
· Non-cash stock compensation expense of $365 million ($365 million net of tax)
· Loss on early extinguishment of debt of $43 million ($26 million net of tax)
Without the effect of these items, the Company’s results for the fourth quarter of 2013 were as follows:
· Adjusted net income from continuing operations of $73 million, or $0.28 per basic diluted share, compared to $35 million in the fourth quarter of 2012
· EBITDAX of $215 million compared to $86 million in the fourth quarter of 2012
2
· Cash flow from continuing operations before changes in working capital of $174 million compared to $67 million in the fourth quarter of 2012
Net production for the fourth quarter of 2013 averaged 678 MMcfe/d, an increase of 20% from the third quarter of 2013 and 115% from continuing operations in the fourth quarter of 2012. Net production was comprised of 611 MMcf/d of natural gas (90%), 10,064 Bbl/d of natural gas liquids (“NGL”s) (9%) and 1,126 Bbl/d of crude oil (1%). Fourth quarter 2013 net liquids production of 11,190 Bbl/d increased 42% from the third quarter of 2013. The net production increase was primarily driven by production from 18 new Marcellus wells and one new Utica well brought on line in the fourth quarter of 2013.
Fourth quarter 2013 net liquids production was negatively impacted by a start-up delay of two compressor stations originally expected to be completed and placed in service in Ohio during the fourth quarter of 2013. The first of the two stations was placed into service in late January, providing 120 MMcf/d of compression, with the second station expected to be placed on line late in the first quarter of 2014.
Average natural gas price before hedging increased 5% from the prior year quarter to $3.79 per Mcf, a $0.19 per Mcf premium to NYMEX, due to an increase in Antero’s average residue gas heating value or Btu partially offset by wider Appalachian index basis. Approximately 53% of Antero’s fourth quarter 2013 natural gas revenue was realized at the Columbia Gas Transmission (TCO) index price at a $0.04 per Mcf negative differential to NYMEX but at a net $0.35 per Mcf positive differential to NYMEX after Btu upgrade due to ethane remaining in the natural gas stream. The Company’s remaining natural gas revenue was realized at various other index pricing points at a $0.36 per Mcf negative differential to NYMEX but at only a net $0.01 per Mcf negative differential to NYMEX after Btu upgrade.
Average realized Y-grade C3+ NGL price for the fourth quarter of 2013 was $56.04 per barrel, or 58% of NYMEX WTI oil price, and average realized oil price was $88.33 per barrel. Average natural gas-equivalent price including NGLs and oil, but excluding hedge settlements, increased 18% to $4.39 per Mcfe from the prior year quarter.
Average realized natural gas price including hedges was $4.71 per Mcf for the fourth quarter of 2013, a 4% decrease as compared to the fourth quarter of 2012. Average natural gas-equivalent price including NGLs, oil and hedge settlements increased by 6% to $5.26 per Mcfe for the fourth quarter of 2013 as compared to the fourth quarter of 2012. For the fourth quarter of 2013, Antero realized hedging gains of $54 million, or $0.87 per Mcfe.
Revenue for the fourth quarter of 2013 was $480 million as compared to $235 million for the fourth quarter of 2012. Revenue for the fourth quarter of 2013 included a $152 million non-cash gain on unsettled hedges while the fourth quarter of 2012 included a $90 million non-cash gain on unsettled hedges. Liquids production contributed 22% of natural gas, NGLs and oil revenue before hedges in the fourth quarter of 2013 compared to 4% during the fourth quarter of 2012. Non-GAAP adjusted net revenue increased 127% to $328 million compared to the fourth quarter of 2012 (including cash-settled hedge gains and losses but excluding unsettled hedge gains and losses). For a reconciliation of adjusted net revenue to operating revenue, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”
Per unit cash production expense (lease operating, gathering, compression, processing and transportation, and production tax) for the fourth quarter of 2013 was $1.52 per Mcfe which is a 4% decrease compared to $1.58 per Mcfe in the prior year quarter. The decrease was primarily driven by first production in Ohio, which has a lower production tax rate than West Virginia. Per unit general and administrative expense for the fourth quarter of 2013, excluding non-cash stock compensation expense, was $0.31 per Mcfe, a 34% decrease from the fourth quarter of 2012. The decrease was primarily driven by the increase in net production. Per unit depreciation, depletion and amortization expense decreased 5% from the prior year quarter to $1.21 per Mcfe, primarily driven by an increase in proved reserves.
EBITDAX from continuing operations of $215 million for the fourth quarter of 2013 was 149% higher than the prior year quarter due to increased production and revenue. EBITDAX margin for the quarter was $3.43 per Mcfe representing a 17% increase over the prior year quarter. For the fourth quarter of 2013, cash flow from continuing operations before changes in working capital increased 159% from the prior year to $174 million.
The Company had a net loss from continuing operations of $225 million ($(0.86) per basic and diluted share) on a GAAP basis for the fourth quarter of 2013, including $152 million of non-cash gains on unsettled hedges, $365 million of non-cash stock compensation expense and $43 million of losses on early extinguishment of debt. Excluding these non-cash items and $2 million of other non-cash items, net of tax, adjusted net income was $73 million ($0.28 per basic and diluted share) for 2013 representing a 111% increase over the prior year.
3
For a description of EBITDAX and EBITDAX margin from continuing operations, cash flow from continuing operations before changes in working capital and adjusted net income and reconciliations to their nearest comparable GAAP measures, please read “Non-GAAP Financial Measures.”
2013 Financial Results
Net production for 2013 averaged 522 MMcfe/d, an increase of 119% from 2012 net production from continuing operations. Net production was comprised of 484 MMcf/d of natural gas (92%), 5,815 Bbl/d of NGLs (7%) and 618 Bbl/d of crude oil (1%). 2013 net liquids production of 6,433 Bbl/d increased 2,494% over 2012 liquids production from continuing operations. The net production increase was primarily driven by production from 103 new Marcellus wells and 11 new Utica wells brought on line in 2013.
Average natural gas price before hedges increased 30% from the prior year to $3.90 per Mcf, a $0.25 per Mcf premium to NYMEX, due to an increase in Antero’s average residue gas heating value or Btu. Approximately 67% of Antero’s 2013 natural gas revenue was realized at the Columbia Gas Transmission (TCO) index price at a $0.06 per Mcf negative differential to NYMEX but at a net $0.37 per Mcf premium to NYMEX after Btu upgrade due to ethane remaining in the natural gas stream. The Company’s remaining natural gas revenue was realized at various other index pricing points at a $0.38 per Mcf negative differential to NYMEX but at a net $0.01 per Mcf premium to NYMEX after Btu upgrade.
Average realized Y-grade C3+ NGL price for 2013 was $52.61 per barrel, or 54% of the NYMEX WTI oil price, and average realized oil price was $91.27 per barrel. Average natural gas-equivalent price including NGLs and oil, but excluding hedge settlements, increased 42% to $4.31 per Mcfe from the prior year.
Average realized natural gas price including hedges was $4.82 per Mcf for 2013, a 5% decrease as compared to 2012. Average natural gas-equivalent price including NGLs, oil and hedge settlements, increased by 2% to $5.17 per Mcfe for 2013 as compared to 2012. For 2013, Antero realized hedging gains of $164 million or $0.86 per Mcfe.
Revenue for 2013 was $1.3 billion as compared to $736 million for the prior year. Revenue for 2013 included a $328 million non-cash gain on unsettled hedges while 2012 included a $1 million non-cash gain on unsettled hedges. Liquids production contributed 16% of natural gas, NGLs and oil revenue before hedges in 2013 compared to 2% during 2012. Non-GAAP adjusted net revenue increased 122% to $985 million compared to 2012 (including cash-settled hedge gains and losses but excluding unsettled hedge gains and losses). For a reconciliation of adjusted net revenue to operating revenue, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”
Per unit cash production expense (lease operating, gathering, compression, processing and transportation, and production tax) for 2013 was $1.46 per Mcfe which is a 9% increase compared to $1.34 per Mcfe in the prior year. The increase was primarily driven by processing costs associated with liquids production for the entire year in 2013 compared to 2012 when processing only commenced in the fourth quarter. Per unit general and administrative expense for 2013, excluding non-cash stock compensation expense, was $0.32 per Mcfe, a 38% decrease from 2012. The decrease was primarily driven by the increase in net production. Per unit depreciation, depletion and amortization expense increased 5% from the prior year to $1.23 per Mcfe, primarily driven by higher depreciation on gathering and fresh water distribution assets as the Company continued to build out these systems in the rich gas areas of the Marcellus Shale and Utica Shale.
EBITDAX from continuing operations of $649 million for 2013 was 128% higher than the prior year due to increased production and revenue. EBITDAX margin for 2013 was $3.39 per Mcfe representing a 5% increase from the prior year. For 2013, cash flow from continuing operations before changes in working capital increased 211% from the prior year to $493 million.
The Company had a net loss from continuing operations of $24 million ($(0.09) per basic and diluted share) on a GAAP basis for 2013, including $328 million of non-cash gains on unsettled hedges, $365 million of non-cash stock compensation expense and $43 million of losses on early extinguishment of debt. Excluding these non-cash items and $12 million of other non-cash items, net of tax, adjusted net income was $171 million ($0.65 per basic and diluted share) for 2013 representing a 215% increase over the prior year.
For a description of EBITDAX and EBITDAX margin from continuing operations, cash flow from continuing operations before changes in working capital and adjusted net income and reconciliations to their nearest comparable GAAP measures, please read “Non-GAAP Financial Measures.”
Capital Spending
Antero’s drilling and completion costs for the twelve months ended December 31, 2013 were $1.62 billion. In addition, during 2013, $390 million was expended on Appalachian gathering systems and compression, $204 million on Antero’s fresh water distribution
4
projects in the Marcellus and Utica Shale, and $456 million on leasehold acquisitions including $15 million for proved property acquisitions.
Antero Operations
All operational figures are as of the date of this release unless otherwise noted.
Current E&P Operations — Antero currently has 85 gross (79 net) operated wells in various stages of drilling, completion, or waiting on completion in the Marcellus and Utica Shale projects.
Antero is currently operating 15 drilling rigs in the Marcellus Shale play, including four intermediate rigs that drill the vertical section of planned horizontal wells to the kick-off point at approximately 6,000 feet. Antero has 65 gross (64 net) horizontal wells either in the process of drilling, completing or waiting on completion in the Marcellus. The Company currently has six frac crews working in West Virginia and plans to add a seventh crew in the next month.
Additionally, Antero is currently operating five drilling rigs, including one intermediate rig, in the highly-rich gas and highly-rich gas/condensate windows of the core of the Utica Shale play in southeastern Ohio. In addition to its 18 wells on line, Antero has 20 gross (15 net) wells either in the process of drilling, completing, or waiting on completion in the Utica. Antero has two frac crews currently working in Ohio.
Antero holds approximately 350,000 net acres in the southwestern core of the Marcellus Shale play and approximately 70% of Antero’s Marcellus leasehold is prospective for processable rich gas assuming an 1100 Btu cutoff. Additionally, Antero holds approximately 106,000 net acres of leasehold in the core of the Utica Shale play and approximately 75% of Antero’s Utica leasehold is prospective for processable rich gas also assuming an 1100 Btu cutoff.
Processing Update — In the Marcellus Shale, Antero has access to a total of 600 MMcf/d of cryogenic processing capacity at the MarkWest Sherwood processing facility located in Doddridge County, West Virginia. Antero has committed to two additional 200 MMcf/d cryogenic processing plants, Sherwood IV and V. Sherwood IV is expected to go on line in the third quarter of 2014 and Sherwood V is expected to go on line in the fourth quarter of 2014. These commitments provide Antero access to a total of 1 Bcf/d of Marcellus cryogenic processing capacity by year-end 2014. Ethane is currently being rejected at the processing facility and left in the gas stream.
In the Utica Shale, the Company’s rich gas production continues to flow into the Seneca processing complex. MarkWest is currently operating two 200 MMcf/d cryogenic plants, Seneca I and II. Antero has fully committed to Seneca I, and has committed to two additional 200 MMcf/d cryogenic processing plants, Seneca III and IV. Seneca III is expected to go on line in the second quarter of 2014 and Seneca IV is expected to go on line in the first quarter of 2015. Additionally, Antero has 50 MMcf/d of interim capacity at the Seneca II plant until Seneca IV is placed into service. These commitments provide Antero access to a total of 600 MMcf/d of Utica cryogenic processing capacity by the first quarter of 2015. Ethane is currently being rejected at the processing facility and left in the gas stream.
Financial Position and Liquidity
As of December 31, 2013, the Company’s total debt was $2.1 billion of which $288 million were borrowings outstanding under the Company’s credit facility. Total lender commitments under the credit facility are $1.5 billion and can be increased to the borrowing base amount of $2.0 billion upon bank approval. As of December 31, 2013, Antero also had $32 million in letters of credit outstanding, resulting in approximately $1.2 billion of available liquidity and $1.7 billion of unused borrowing base capacity.
Hedge Update
As of today, Antero has hedged 1,333 Bcfe of future production using fixed price swaps covering the period from January 1, 2014 through December 2019 at an average index price of $4.62/MMBtu and $96.54/Bbl. Over 75% of Antero’s estimated 2014 production is hedged at an average index price of $4.64/MMBtu and $96.54/Bbl. Approximately 50% of Antero’s financial hedge portfolio is made up of NYMEX hedges and 50% is tied to the Appalachian Basin or Gulf Coast pricing. Antero physically delivers a substantial portion of its gas production through direct firm transportation to Henry, Louisiana, the index for NYMEX pricing, which eliminates basis risk on the Company’s NYMEX hedges. Antero has 10 different counterparties to its hedge contracts, all of which are lenders in Antero’s bank credit facility.
5
The following table summarizes Antero’s hedge positions held as of February 26, 2014:
|
|
|
Natural gas
equivalent |
|
Equivalent |
|
|
Calendar Year |
|
MMBtu/day |
|
index price |
|
|
2014 |
|
728,833 |
|
$ |
4.92 |
|
|
2015 |
|
550,000 |
|
$ |
4.91 |
|
|
2016 |
|
642,500 |
|
$ |
4.71 |
|
|
2017 |
|
740,000 |
|
$ |
4.34 |
|
|
2018 |
|
630,000 |
|
$ |
4.65 |
|
|
2019 |
|
357,500 |
|
$ |
4.46 |
|
Conference Call
A conference call is scheduled on Thursday, February 27 at 11:00 a.m. ET. Topics of the teleconference will include financial results, operational results, and other matters with respect to the year and fourth quarter of 2013. A brief Q&A session for security analysts will immediately follow the results discussion. To participate in the call, dial in at 877-418-5260 (U.S.), 866-605-3852 (Canada), or 412-717-9589 (International) and reference passcode 10040960. 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 March 10.
Presentation
An updated presentation will be posted to the Company’s website before the February 27 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.
6
Non-GAAP Financial Measures
Adjusted net revenue as set forth in this release represents operating revenue adjusted for certain non-cash items, including unsettled hedge gains and losses and gains and losses on asset sales. Antero believes that adjusted net revenue is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net revenue 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 adjusted net revenue:
|
|
|
Three months ended
December 31, |
|
Twelve months ended
December 31, |
|
|
|
|
2012 |
|
2013 |
|
2012 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenue |
|
$ |
235,090 |
|
$ |
480,014 |
|
$ |
735,718 |
|
$ |
1,313,134 |
|
|
Hedge gains |
|
(127,336 |
) |
(206,179 |
) |
(179,546 |
) |
(491,689 |
) |
|
Cash receipts for settled hedges |
|
36,985 |
|
54,259 |
|
178,491 |
|
163,570 |
|
|
Gain on sale of assets |
|
— |
|
— |
|
(291,190 |
) |
— |
|
|
Adjusted net revenue |
|
$ |
144,739 |
|
$ |
328,094 |
|
$ |
443,473 |
|
$ |
985,015 |
|
Adjusted net income as set forth in this release represents income from continuing operations, adjusted for certain non-cash 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) from continuing operations as an indicator of financial performance. The following table reconciles net income (loss) from continuing operations to adjusted net income from continuing operations:
|
|
|
Three months ended |
|
Twelve months ended |
|
|
|
|
December 31, |
|
December 31, |
|
|
|
|
2012 |
|
2013 |
|
2012 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations |
|
$ |
84,845 |
|
$ |
(225,177 |
) |
$ |
225,276 |
|
$ |
(24,187 |
) |
|
Non-cash gains |
|
|
|
|
|
|
|
|
|
|
on unsettled hedges, net of tax |
|
(55,114 |
) |
(94,190 |
) |
(644 |
) |
(203,434 |
) |
|
Impairment of unproved properties, net of tax |
|
4,911 |
|
846 |
|
7,363 |
|
6,775 |
|
|
Stock compensation, net of tax |
|
— |
|
365,157 |
|
— |
|
365,157 |
|
|
Loss on early extinguishment of debt, net of tax |
|
— |
|
26,392 |
|
— |
|
26,392 |
|
|
Gain on sale of assets, net of tax |
|
— |
|
— |
|
(177,626 |
) |
— |
|
|
Other, net of tax |
|
18 |
|
166 |
|
62 |
|
660 |
|
|
Adjusted net income from continuing operations |
|
$ |
34,660 |
|
$ |
73,194 |
|
$ |
54,431 |
|
$ |
171,363 |
|
Cash flow from continuing operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital. Cash flow from continuing 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 continuing 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 continuing 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 continuing operations before changes in working capital as used in this release:
7
|
|
|
Three months ended
December 31, |
|
Twelve months ended
December 31, |
|
|
|
|
2012 |
|
2013 |
|
2012 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
106,855 |
|
$ |
202,770 |
|
$ |
332,255 |
|
$ |
534,707 |
|
|
Net change in working capital |
|
(15,377 |
) |
(28,385 |
) |
(24,887 |
) |
(41,914 |
) |
|
Cash flow from operations before changes in working capital |
|
91,478 |
|
174,385 |
|
307,368 |
|
492,793 |
|
|
Cash flow from discontinued operations before changes in working capital |
|
(24,105 |
) |
— |
|
(148,951 |
) |
— |
|
|
Cash flow from continuing operations before changes in working capital |
|
$ |
67,373 |
|
$ |
174,385 |
|
$ |
158,417 |
|
$ |
492,793 |
|
EBITDAX is a non-GAAP financial measure that Antero defines as net income (loss) from continuing operations after adjusting for those items shown in the table below. 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. EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. 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 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 and by its lenders pursuant to covenants under its credit facility and the indentures governing the Company’s senior notes.
There are significant limitations to using 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 or loss, the lack of comparability of results of operations of different companies and the different methods of calculating EBITDAX reported by different companies. The following table represents a reconciliation of the Company’s net income (loss) from continuing operations to EBITDAX from continuing operations, a reconciliation of income (loss) from discontinued operations to EBITDAX from discontinued operations, a reconciliation of total EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled hedges to EBITDAX Margin:
8
|
|
|
Three months ended |
|
Twelve months ended |
|
|
|
|
December 31, |
|
December 31, |
|
|
|
|
2012 |
|
2013 |
|
2012 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations |
|
$ |
84,845 |
|
$ |
(225,177 |
) |
$ |
225,276 |
|
$ |
(24,187 |
) |
|
Hedge fair value gains |
|
(127,336 |
) |
(206,179 |
) |
(179,546 |
) |
(491,689 |
) |
|
Net cash receipts on settled hedges |
|
36,985 |
|
54,259 |
|
178,491 |
|
163,570 |
|
|
Gain on sale of assets |
|
— |
|
— |
|
(291,190 |
) |
— |
|
|
Interest expense |
|
26,464 |
|
35,777 |
|
97,510 |
|
136,617 |
|
|
Loss on early extinguishment of debt |
|
— |
|
42,567 |
|
— |
|
42,567 |
|
|
Provision for income taxes |
|
12,704 |
|
65,515 |
|
121,229 |
|
186,210 |
|
|
Depreciation, depletion, amortization and accretion |
|
36,767 |
|
75,494 |
|
102,127 |
|
234,941 |
|
|
Impairment of unproved properties |
|
8,051 |
|
1,364 |
|
12,070 |
|
10,928 |
|
|
Exploration expense |
|
6,763 |
|
5,238 |
|
14,675 |
|
22,272 |
|
|
Stock compensation expense |
|
— |
|
365,280 |
|
— |
|
365,280 |
|
|
Other |
|
1,076 |
|
1,029 |
|
4,068 |
|
2,849 |
|
|
EBITDAX from continuing operations |
|
86,319 |
|
215,167 |
|
284,710 |
|
649,358 |
|
|
Income (loss) from discontinued operations |
|
(91,880 |
) |
2,157 |
|
(510,345 |
) |
5,257 |
|
|
Hedge fair value gains |
|
— |
|
— |
|
(46,358 |
) |
— |
|
|
Net cash receipts on settled hedges |
|
12,430 |
|
— |
|
92,166 |
|
— |
|
|
Loss (gain) on sale of assets |
|
368,713 |
|
(3,506 |
) |
795,945 |
|
(8,506 |
) |
|
Provision (benefit) for income taxes |
|
(276,638 |
) |
1,349 |
|
(272,553 |
) |
3,249 |
|
|
Depreciation, depletion, amortization and accretion |
|
11,470 |
|
— |
|
89,124 |
|
— |
|
|
Impairment of unproved properties |
|
— |
|
— |
|
962 |
|
— |
|
|
Exploration expense |
|
157 |
|
— |
|
664 |
|
— |
|
|
EBITDAX from discontinued operations |
|
24,252 |
|
— |
|
149,605 |
|
— |
|
|
Total EBITDAX |
|
110,571 |
|
215,167 |
|
434,315 |
|
649,358 |
|
|
Interest expense and other |
|
(26,464 |
) |
(43,582 |
) |
(97,510 |
) |
(144,422 |
) |
|
Exploration expense |
|
(7,427 |
) |
(5,238 |
) |
(15,339 |
) |
(22,272 |
) |
|
Changes in current assets and liabilities |
|
15,377 |
|
28,385 |
|
24,887 |
|
41,914 |
|
|
Other |
|
14,798 |
|
8,038 |
|
(14,098 |
) |
10,129 |
|
|
Net cash provided by operating activities |
|
$ |
106,855 |
|
$ |
202,770 |
|
$ |
332,255 |
|
$ |
534,707 |
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX margin from continuing operations: |
|
|
|
|
|
|
|
|
|
|
Realized price before cash receipts for settled hedges |
|
$ |
3.71 |
|
$ |
4.39 |
|
$ |
3.03 |
|
$ |
4.31 |
|
|
Lease operating expense |
|
0.07 |
|
0.07 |
|
0.07 |
|
0.05 |
|
|
Transportation costs |
|
1.18 |
|
1.13 |
|
1.04 |
|
1.15 |
|
|
Production taxes |
|
0.33 |
|
0.32 |
|
0.23 |
|
0.26 |
|
|
General and administrative |
|
0.47 |
|
0.31 |
|
0.52 |
|
0.32 |
|
|
EBITDAX margin, before cash receipts for settled derivatives |
|
1.66 |
|
2.56 |
|
1.17 |
|
2.53 |
|
|
Cash receipts for settled hedges |
|
1.27 |
|
0.87 |
|
2.05 |
|
0.86 |
|
|
EBITDAX margin |
|
$ |
2.93 |
|
$ |
3.43 |
|
$ |
3.22 |
|
$ |
3.39 |
|
Antero Resources is an independent oil and natural gas company engaged in the acquisition, development and production of unconventional oil and liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. 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, other than historical facts included in this release, are forward-looking statements. 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.
The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC. Antero has provided internally generated estimates that have been audited by its third party reserve engineer in this release. Antero’s estimate of proved, probable and possible reserves is provided in this release because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
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, 2013.
For more information, contact Michael Kennedy — VP Finance, at (303) 357-6782 or mkennedy@anteroresources.com.
9
ANTERO RESOURCES CORPORATION
Consolidated Balance Sheets
December 31, 2012 and 2013
(In thousands)
|
|
|
2012 |
|
2013 |
|
|
Assets |
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
18,989 |
|
$ |
17,487 |
|
|
Accounts receivable—trade, net of allowance for doubtful accounts of $174 and $1,251 in 2012 and 2013, respectively |
|
21,296 |
|
30,610 |
|
|
Notes receivable—short-term portion |
|
4,555 |
|
2,667 |
|
|
Accrued revenue |
|
46,669 |
|
96,825 |
|
|
Derivative instruments |
|
160,579 |
|
183,000 |
|
|
Other |
|
22,518 |
|
2,975 |
|
|
Total current assets |
|
274,606 |
|
333,564 |
|
|
Property and equipment: |
|
|
|
|
|
|
Natural gas properties, at cost (successful efforts method): |
|
|
|
|
|
|
Unproved properties |
|
1,243,237 |
|
1,513,136 |
|
|
Proved properties |
|
1,682,297 |
|
3,621,672 |
|
|
Fresh water distribution systems |
|
6,835 |
|
231,684 |
|
|
Gathering systems and facilities |
|
168,930 |
|
584,626 |
|
|
Other property and equipment |
|
9,517 |
|
15,757 |
|
|
|
|
3,110,816 |
|
5,966,875 |
|
|
Less accumulated depletion, depreciation, and amortization |
|
(173,343 |
) |
(407,219 |
) |
|
Property and equipment, net |
|
2,937,473 |
|
5,559,656 |
|
|
Derivative instruments |
|
371,436 |
|
677,780 |
|
|
Notes receivable—long-term portion |
|
2,667 |
|
— |
|
|
Other assets, net |
|
32,611 |
|
42,581 |
|
|
Total assets |
|
$ |
3,618,793 |
|
$ |
6,613,581 |
|
|
Liabilities and Equity |
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
Accounts payable |
|
$ |
181,478 |
|
$ |
370,640 |
|
|
Accrued liabilities |
|
58,829 |
|
77,126 |
|
|
Revenue distributions payable |
|
46,037 |
|
96,589 |
|
|
Current debt |
|
25,000 |
|
— |
|
|
Deferred income tax liability |
|
62,620 |
|
69,191 |
|
|
Derivative instruments |
|
— |
|
646 |
|
|
Other |
|
2,332 |
|
8,037 |
|
|
Total current liabilities |
|
376,296 |
|
622,229 |
|
|
Long-term liabilities: |
|
|
|
|
|
|
Long-term debt |
|
1,444,058 |
|
2,078,999 |
|
|
Deferred income tax liability |
|
91,692 |
|
278,580 |
|
|
Other long-term liabilities |
|
33,010 |
|
35,113 |
|
|
Total liabilities |
|
1,945,056 |
|
3,014,921 |
|
|
Stockholders’/Members’ Equity: |
|
|
|
|
|
|
Members’ equity of Antero Resources LLC |
|
1,460,947 |
|
— |
|
|
Common stock of Antero Resources Corporation, $0.01 par value; authorized—1,000,000,000 shares; issued and outstanding 262,049,659 shares |
|
— |
|
2,620 |
|
|
Preferred stock of Antero Resources Corporation, $0.01 par value; authorized—50,000,000 shares; none issued |
|
— |
|
— |
|
|
Additional paid-in capital |
|
— |
|
3,402,180 |
|
|
Accumulated earnings |
|
212,790 |
|
193,860 |
|
|
Total equity |
|
1,673,737 |
|
3,598,660 |
|
|
Total liabilities and equity |
|
$ |
3,618,793 |
|
$ |
6,613,581 |
|
10
ANTERO RESOURCES CORPORATION
Consolidated Statements of Operations and Comprehensive Income (Loss)
Years Ended December 31, 2011, 2012 and 2013
(In thousands)
|
|
|
2011 |
|
2012 |
|
2013 |
|
|
Revenue: |
|
|
|
|
|
|
|
|
Natural gas sales |
|
$ |
195,116 |
|
$ |
259,743 |
|
$ |
689,198 |
|
|
Natural gas liquids sales |
|
— |
|
3,719 |
|
111,663 |
|
|
Oil sales |
|
173 |
|
1,520 |
|
20,584 |
|
|
Commodity derivative fair value gains |
|
496,064 |
|
179,546 |
|
491,689 |
|
|
Gain on sale of gathering system |
|
— |
|
291,190 |
|
— |
|
|
Total revenue |
|
691,353 |
|
735,718 |
|
1,313,134 |
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
Lease operating |
|
4,608 |
|
6,243 |
|
9,439 |
|
|
Gathering, compression, processing, and transportation |
|
37,315 |
|
91,094 |
|
218,428 |
|
|
Production and ad valorem taxes |
|
11,915 |
|
20,210 |
|
50,481 |
|
|
Exploration |
|
4,034 |
|
14,675 |
|
22,272 |
|
|
Impairment of unproved properties |
|
4,664 |
|
12,070 |
|
10,928 |
|
|
Depletion, depreciation, and amortization |
|
55,716 |
|
102,026 |
|
233,876 |
|
|
Accretion of asset retirement obligations |
|
76 |
|
101 |
|
1,065 |
|
|
General and administrative (including $365,280 of stock compensation in 2013) |
|
33,342 |
|
45,284 |
|
425,438 |
|
|
Loss on sale of assets |
|
8,700 |
|
— |
|
— |
|
|
Total operating expenses |
|
160,370 |
|
291,703 |
|
971,927 |
|
|
Operating income |
|
530,983 |
|
444,015 |
|
341,207 |
|
|
Other expenses: |
|
|
|
|
|
|
|
|
Interest |
|
(74,404 |
) |
(97,510 |
) |
(136,617 |
) |
|
Loss on early extinguishment of debt |
|
— |
|
— |
|
(42,567 |
) |
|
Interest rate derivative fair value loss |
|
(94 |
) |
— |
|
— |
|
|
Total other expenses |
|
(74,498 |
) |
(97,510 |
) |
(179,184 |
) |
|
Income from continuing operations before income taxes and discontinued operations |
|
456,485 |
|
346,505 |
|
162,023 |
|
|
Provision for income taxes |
|
(185,297 |
) |
(121,229 |
) |
(186,210 |
) |
|
Income from continuing operations |
|
271,188 |
|
225,276 |
|
(24,187 |
) |
|
Discontinued operations: |
|
|
|
|
|
|
|
|
Income (loss) from results of operations and sale of discontinued operations, net of income tax (expense) benefit of $(45,155), $272,533, and $(3,249) in 2011, 2012, and 2013, respectively |
|
121,490 |
|
(510,345 |
) |
5,257 |
|
|
Net income (loss) and comprehensive income (loss) |
|
$ |
392,678 |
|
$ |
(285,069 |
) |
$ |
(18,930 |
) |
|
Earnings (loss) per share: |
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
1.04 |
|
$ |
0.86 |
|
$ |
(0.09 |
) |
|
Discontinued operations |
|
$ |
0.46 |
|
$ |
(1.95 |
) |
$ |
0.02 |
|
|
Total |
|
$ |
1.50 |
|
$ |
(1.09 |
) |
$ |
(0.07 |
) |
|
Earnings (loss) per share—assuming dilution: |
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
1.04 |
|
$ |
0.86 |
|
$ |
(0.09 |
) |
|
Discontinued operations |
|
$ |
0.46 |
|
$ |
(1.95 |
) |
$ |
0.02 |
|
|
Total |
|
$ |
1.50 |
|
$ |
(1.09 |
) |
$ |
(0.07 |
) |
11
ANTERO RESOURCES CORPORATION
Consolidated Statements of Cash Flows
Years ended December 31, 2011, 2012, and 2013
(In thousands)
|
|
|
2011 |
|
2012 |
|
2013 |
|
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
392,678 |
|
$ |
(285,069 |
) |
$ |
(18,930 |
) |
|
Adjustment to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depletion, depreciation, amortization, and depletion |
|
55,792 |
|
102,127 |
|
234,941 |
|
|
Impairment of unproved properties |
|
4,664 |
|
12,070 |
|
10,928 |
|
|
Derivative fair value gains |
|
(495,970 |
) |
(179,546 |
) |
(491,689 |
) |
|
Cash receipts for settled derivatives |
|
45,638 |
|
178,491 |
|
163,570 |
|
|
Deferred income taxes |
|
185,297 |
|
106,229 |
|
190,210 |
|
|
Loss (gain) on sale of assets |
|
8,700 |
|
(291,190 |
) |
— |
|
|
Stock compensation |
|
— |
|
— |
|
365,280 |
|
|
Loss on early extinguishment of debt |
|
— |
|
— |
|
42,567 |
|
|
Loss (gain) on sale of discontinued operations |
|
— |
|
795,945 |
|
(8,506 |
) |
|
Depletion, depreciation, amortization, and impairment of unproved properties—discontinued operations |
|
126,041 |
|
90,096 |
|
— |
|
|
Derivative fair value gains—discontinued operations |
|
(180,130 |
) |
(46,358 |
) |
— |
|
|
Cash receipts for settled derivatives—discontinued operations |
|
66,654 |
|
92,166 |
|
— |
|
|
Deferred income taxes—discontinued operations |
|
45,155 |
|
(272,553 |
) |
3,249 |
|
|
Other |
|
3,479 |
|
4,960 |
|
1,173 |
|
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
3,854 |
|
5,511 |
|
(9,314 |
) |
|
Accrued revenue |
|
(11,118 |
) |
(10,683 |
) |
(50,156 |
) |
|
Other current assets |
|
(4,528 |
) |
(8,882 |
) |
19,543 |
|
|
Accounts payable |
|
(1,875 |
) |
(2,117 |
) |
1,039 |
|
|
Accrued liabilities |
|
17,124 |
|
14,790 |
|
26,803 |
|
|
Revenue distributions payable |
|
4,852 |
|
11,268 |
|
50,552 |
|
|
Other |
|
— |
|
15,000 |
|
3,447 |
|
|
Net cash provided by operating activities |
|
266,307 |
|
332,255 |
|
534,707 |
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Additions to proved properties |
|
(105,405 |
) |
(10,254 |
) |
(15,300 |
) |
|
Additions to unproved properties |
|
(195,131 |
) |
(687,403 |
) |
(440,825 |
) |
|
Drilling and completion costs |
|
(527,710 |
) |
(836,350 |
) |
(1,615,965 |
) |
|
Additions to fresh water distribution systems |
|
— |
|
(2,801 |
) |
(203,790 |
) |
|
Additions to gathering systems and facilities |
|
(72,837 |
) |
(142,294 |
) |
(389,453 |
) |
|
Additions to other property and equipment |
|
(2,339 |
) |
(3,447 |
) |
(6,240 |
) |
|
(Increase) decrease in notes receivable |
|
(10,111 |
) |
4,889 |
|
4,555 |
|
|
Increase in other assets |
|
(3,095 |
) |
(3,707 |
) |
(6,574 |
) |
|
Proceeds from asset sales |
|
15,379 |
|
1,217,876 |
|
— |
|
|
Net cash used in investing activities |
|
(901,249 |
) |
(463,491 |
) |
(2,673,592 |
) |
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Issuance of common stock |
|
— |
|
— |
|
1,578,573 |
|
|
Issuance of senior notes |
|
400,000 |
|
300,000 |
|
1,231,750 |
|
|
Repayment of senior notes |
|
— |
|
— |
|
(690,000 |
) |
|
Borrowings (repayments) on bank credit facility, net |
|
265,000 |
|
(148,000 |
) |
71,000 |
|
|
Payments of deferred financing costs and loss on extinguishment of debt |
|
(6,691 |
) |
(5,926 |
) |
(53,940 |
) |
|
Distribution to members |
|
(28,859 |
) |
— |
|
— |
|
|
Other |
|
(153 |
) |
808 |
|
— |
|
|
Net cash provided by financing activities |
|
629,297 |
|
146,882 |
|
2,137,383 |
|
|
Net increase (decrease) in cash and cash equivalents |
|
(5,645 |
) |
15,646 |
|
(1,502 |
) |
|
Cash and cash equivalents, beginning of period |
|
8,988 |
|
3,343 |
|
18,989 |
|
|
Cash and cash equivalents, end of period |
|
$ |
3,343 |
|
$ |
18,989 |
|
$ |
17,487 |
|
|
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
|
|
Cash paid during the period for interest |
|
$ |
59,107 |
|
$ |
90,122 |
|
$ |
117,832 |
|
|
Supplemental disclosure of noncash investing activities: |
|
|
|
|
|
|
|
|
Changes in accounts payable for additions to property and equipment |
|
$ |
26,465 |
|
$ |
72,881 |
|
$ |
188,123 |
|
12
ANTERO RESOURCES CORPORATION
The following table sets forth selected operating data (as recast for discontinued operations) for the year ended December 31, 2012 compared to the year ended December 31, 2013:
|
(in thousands, except per unit |
|
Year Ended
December 31, |
|
Amount
of
Increase |
|
Percent |
|
|
data) |
|
2012 |
|
2013 |
|
(Decrease) |
|
Change |
|
|
Operating revenues: |
|
|
|
|
|
|
|
|
|
|
Natural gas sales |
|
$ |
259,743 |
|
$ |
689,198 |
|
$ |
429,455 |
|
165 |
% |
|
NGL sales |
|
3,719 |
|
111,663 |
|
107,944 |
|
2,903 |
% |
|
Oil sales |
|
1,520 |
|
20,584 |
|
19,064 |
|
1,254 |
% |
|
Commodity derivative fair value gains |
|
179,546 |
|
491,689 |
|
312,143 |
|
174 |
% |
|
Gain on sale of assets |
|
291,190 |
|
— |
|
(291,190 |
) |
* |
|
|
Total operating revenues |
|
735,718 |
|
1,313,134 |
|
577,416 |
|
78 |
% |
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
6,243 |
|
9,439 |
|
3,196 |
|
51 |
% |
|
Gathering, compression, processing and transportation |
|
91,094 |
|
218,428 |
|
127,334 |
|
140 |
% |
|
Production and ad valorem taxes |
|
20,210 |
|
50,481 |
|
30,271 |
|
150 |
% |
|
Exploration |
|
14,675 |
|
22,272 |
|
7,597 |
|
52 |
% |
|
Impairment of unproved properties |
|
12,070 |
|
10,928 |
|
(1,142 |
) |
(9 |
)% |
|
Depletion, depreciation, and amortization |
|
102,026 |
|
233,876 |
|
131,850 |
|
129 |
% |
|
Accretion of asset retirement obligations |
|
101 |
|
1,065 |
|
964 |
|
954 |
% |
|
General and administrative (before stock compensation) |
|
45,284 |
|
60,158 |
|
14,874 |
|
33 |
% |
|
Stock compensation |
|
— |
|
365,280 |
|
365,280 |
|
* |
|
|
Total operating expenses |
|
291,703 |
|
971,927 |
|
680,224 |
|
* |
|
|
Operating income |
|
444,015 |
|
341,207 |
|
(102,808 |
) |
* |
|
|
Other expenses: |
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
(97,510 |
) |
$ |
(136,617 |
) |
$ |
39,107 |
|
40 |
% |
|
Loss on early extinguishment of debt |
|
— |
|
(42,567 |
) |
42,567 |
|
* |
|
|
Total other expenses |
|
(97,510 |
) |
(179,184 |
) |
81,674 |
|
84 |
% |
|
Income before income taxes and discontinued operations |
|
346,505 |
|
162,023 |
|
(184,482 |
) |
* |
|
|
Income taxes expense |
|
(121,229 |
) |
(186,210 |
) |
(64,981 |
) |
54 |
% |
|
Income from continuing operations |
|
225,276 |
|
(24,187 |
) |
(249,463 |
) |
* |
|
|
Income (loss) from discontinued operations |
|
(510,345 |
) |
5,257 |
|
515,602 |
|
* |
|
|
Net income (loss) |
|
$ |
(285,069 |
) |
$ |
(18,930 |
) |
$ |
266,139 |
|
* |
|
|
EBITDAX from continuing operations |
|
$ |
284,710 |
|
$ |
649,358 |
|
$ |
364,648 |
|
128 |
% |
|
EBITDAX from discontinued operations |
|
149,605 |
|
— |
|
(149,605 |
) |
* |
|
|
Total EBITDAX |
|
$ |
434,315 |
|
$ |
649,358 |
|
$ |
215,043 |
|
50 |
% |
|
Production data: |
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf) |
|
87 |
|
177 |
|
90 |
|
103 |
% |
|
NGLs (MBbl) |
|
71 |
|
2,123 |
|
2,052 |
|
2,872 |
% |
|
Oil (MBbl) |
|
19 |
|
226 |
|
207 |
|
1,094 |
% |
|
Combined (Bcfe) |
|
87 |
|
191 |
|
104 |
|
119 |
% |
|
Daily combined production (MMcfe/d) |
|
239 |
|
522 |
|
283 |
|
119 |
% |
|
Average sales prices before effects of cash settled derivatives: |
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) |
|
$ |
2.99 |
|
$ |
3.90 |
|
$ |
0.91 |
|
30 |
% |
|
NGLs (per Bbl) |
|
$ |
52.07 |
|
$ |
52.61 |
|
$ |
0.54 |
|
1 |
% |
|
Oil (per Bbl) |
|
$ |
80.34 |
|
$ |
91.27 |
|
$ |
10.93 |
|
14 |
% |
|
Combined (per Mcfe) |
|
$ |
3.03 |
|
$ |
4.31 |
|
$ |
1.28 |
|
42 |
% |
|
Average realized sales prices after effects of cash settled derivatives: |
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) |
|
$ |
5.05 |
|
$ |
4.82 |
|
$ |
(0.23 |
) |
(5 |
)% |
|
NGLs (per Bbl) |
|
$ |
52.07 |
|
$ |
52.61 |
|
$ |
0.54 |
|
1 |
% |
|
Oil (per Bbl) |
|
$ |
80.34 |
|
$ |
99.06 |
|
$ |
18.72 |
|
23 |
% |
|
Combined (per Mcfe) |
|
$ |
5.08 |
|
$ |
5.17 |
|
$ |
0.09 |
|
2 |
% |
|
Average costs (per Mcfe): |
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
$ |
0.07 |
|
$ |
0.05 |
|
$ |
(0.02 |
) |
(29 |
)% |
|
Gathering compression, processing, and transportation |
|
$ |
1.04 |
|
$ |
1.15 |
|
$ |
0.11 |
|
11 |
% |
|
Production taxes |
|
$ |
0.23 |
|
$ |
0.26 |
|
$ |
0.03 |
|
13 |
% |
|
Depletion, depreciation, amortization, and accretion |
|
$ |
1.17 |
|
$ |
1.23 |
|
$ |
0.06 |
|
5 |
% |
|
General and administrative |
|
$ |
0.52 |
|
$ |
0.32 |
|
$ |
(0.20 |
) |
(38 |
)% |
13