Antero Resources Reports Second Quarter 2011 Results, Net Resources and Delivers Operating Update
Highlights:
-- Net production averaged 221 MMcfed, up 78% over the prior-year quarter
-- Consolidated EBITDAX was $77 million, up 79% over the prior-year quarter
-- Reported GAAP earnings of $75 million, adjusted net income $19 million
-- Current net production 250 MMcfed combined — 133 MMcfd net from the Marcellus alone
-- 7 Antero operated drilling rigs currently running in core areas
-- Issued $400 million of 7.25% senior notes due 2019
-- Natural gas hedges increased by 8% to 499 Bcfe through 2016 at $5.93 NYMEX-equivalent
DENVER, Aug. 15, 2011 /PRNewswire/ -- Antero Resources today released its second quarter 2011 results. Those financial statements are included in Antero Resources Finance Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, which has been filed with the Securities and Exchange Commission.
Recent Developments
On August 1, 2011, Antero Resources issued $400 million of 7.25% senior notes due 2019 in a private placement. The notes were sold at par to yield 7.25% to maturity. The net proceeds were initially used to repay all outstanding borrowings under Antero's credit facility. As of June 30, 2011, pro forma for the repayment of bank borrowings with the net proceeds of the note offering, Antero's $750 million of bank commitments on its $800 million borrowing base was completely undrawn, except for $19 million of letter of credit commitments, and the company had $72 million of cash resulting in over $800 million of liquidity.
Financial Results
Production for the second quarter 2011 increased by 78% to 20.1 Bcfe relative to the second quarter of 2010, resulting in net revenue growth of 73% to $117 million (including cash-settled derivatives but excluding unrealized derivative gains and losses). The increase in production was primarily driven by production from new wells in the Marcellus Shale. Liquids production (NGLs and oil) contributed 11% of revenues before commodity hedges. Average natural gas prices before hedges increased 15% from the prior-year quarter to $4.56 per Mcf and average natural gas-equivalent prices before hedges also increased 15% to $4.85 per Mcfe. Additionally, average realized gas prices including hedges increased by 1% to $5.59 per Mcf. Average realized NGL prices increased by 16% to $53.01 per barrel, while average realized oil prices including hedges increased by 19% to $75.59 per barrel. Average gas-equivalent prices, including NGLs, oil and hedges, increased 1% to $5.81 per Mcfe. For the quarter, Antero realized natural gas hedging gains of $19 million, or $0.96 per Mcfe.
Reported GAAP earnings resulted in net income of $75 million, including a $98 million unrealized gain on commodity derivatives as natural gas prices declined from the prior quarter, a $9 million non-cash loss on asset sale and $34 million in deferred income tax expense. Excluding the unrealized gain on commodity derivatives, the loss on asset sale, and deferred income tax expense, adjusted net income, a non-GAAP measure, was $19 million for the quarter.
Driven by a 73% increase in revenues, cash flow from operations before changes in working capital, a non-GAAP measure, increased 123% from the prior-year quarter to $59 million. EBITDAX of $77 million for the second quarter of 2011 was 79% higher than the prior-year quarter, also due primarily to a 78% increase in natural gas production.
Net production of 20.1 Bcfe for the quarter was comprised of 19.0 Bcf of natural gas, 150,000 barrels of NGLs and 34,000 barrels of oil, representing a 29% sequential increase over the first quarter of 2011. Net daily production averaged 221 MMcfed for the second quarter, a record high for Antero, and was comprised of 209 MMcfd of natural gas (95%), 1,654 Bbl/d of NGLs (4%) and 369 Bbl/d of crude oil (1%). Net NGL production increased 1% over the second quarter of 2010, which included NGLs generated by processing third party gas in the Arkoma Woodford. As a result of the execution of a gas processing agreement effective January 1, 2011 in the Piceance Basin, Antero has replaced all of the third party NGL production lost in the sale of the Arkoma midstream processing assets which took place in the fourth quarter of 2010.
Per unit cash production costs (lease operating, gathering, compression and transportation, and production tax) for the second quarter 2011 were $1.56 per Mcfe, a 12% improvement from the prior year quarter and a 12% improvement over the previous quarter. This improvement was primarily driven by increased production volumes from new Marcellus Shale wells that generally have low per unit production costs compared to the Company's existing production base. Per unit depreciation, depletion and amortization expense decreased 36% from the prior year quarter to $1.94 per Mcfe, driven by low cost reserve increases. On a per unit basis, general and administrative expense for the second quarter 2011 was $0.41 per Mcfe, a 7% decline from the second quarter of 2010, primarily driven by the increase in gas-equivalent production.
Antero Operations
Antero's current gross operated production is 280 MMcfd, and estimated net production is 250 MMcfed, including non-operated production, NGLs and oil. Antero estimates that an additional 25 MMcfd of gross operated production is constrained, primarily waiting on infrastructure completion in West Virginia. During the first six months of 2011, Antero completed 37 gross operated wells (28 net wells) and currently has 38 gross operated wells (29 net wells) in various stages of drilling, completion, waiting on completion or pipeline.
Marcellus Shale—Antero is operating five drilling rigs in the Marcellus Shale play, all of which are drilling in northern West Virginia. The Company plans to add a sixth drilling rig in October and a seventh rig before year-end 2011. Antero has 180 MMcfd of gross operated production of which 98% is coming from 47 horizontal wells, resulting in 133 MMcfd of net production. An additional estimated 25 MMcfd of gross operated deliverability is constrained, waiting on the completion of pipeline and compression facilities. Antero has 10 horizontal wells either completing or waiting on completion or pipeline and has two frac crews currently working in West Virginia. The 48 horizontal Marcellus wells that Antero has completed to date have an average lateral length of 6,000' and the Company is currently completing its longest horizontal lateral drilled to date, a 9,600' lateral.
Antero expects to alleviate the gas takeaway constraints by the end of September when a number of West Virginia infrastructure projects are completed. Those projects include additional compression at the existing Jarvisville compressor station, completion of the Jarvisville low pressure gathering system, completion of the Tichenal low pressure gathering system and high pressure pipeline as well as the new Tichenal compressor station. The addition of several more compressor units and another new compressor station planned for November 2011 will raise Antero's West Virginia compression capacity to 400 MMcfd. Based on drilling and completion schedules, Antero believes that it will have adequate gathering and compression capacity to accommodate anticipated production growth into the second quarter of 2012. Planning is underway for additional compression and pipeline projects to be completed in 2012 in order to continue to raise lean gas compression and pipeline capacity as well as to deliver rich gas production to a processing plant to be completed by a third party midstream company in the third quarter of 2012.
Antero has 194,000 net acres in the Appalachian Basin Marcellus Shale play of which only 9% was classified as proved at mid-year 2011.
Woodford Shale—Antero is operating one drilling rig in the Arkoma Woodford Shale play. The Company has 58 MMcfd of gross operated production from 135 operated horizontal wells online and 67 MMcfed of net production including net non-operated production, NGLs and oil. Antero has three operated horizontal Woodford wells waiting on completion and one horizontal well waiting on pipeline connection. In addition, Antero has three non-operated wells drilling with a combined 36% working interest on its Arkoma acreage.
Antero has 68,000 net acres in the Arkoma Woodford Shale play.
Piceance Basin—Antero has one operated drilling rig running in the Piceance Basin. The Company's gross operated production in the Piceance is currently 42 MMcfd and 43 MMcfed net including 3 MMcfed of non-operated production from 231 wells online. A third party midstream provider recently completed the start up of a new compressor station for Antero, the Hunter Mesa compressor station located in Antero's Gravel Trend area. The Antero-dedicated facility has four compressors and will add a fifth unit in late August giving the station an estimated 55 MMcfd of compression capacity. This facility should enable Antero to improve the reliability of its takeaway capacity and rapidly grow Mesaverde rich gas production volumes in the Piceance Basin. Antero has three Mesaverde wells currently in the process of completing and 14 Mesaverde wells waiting on completion in its Gravel Trend rich gas area. The company has one frac crew currently working in the basin.
Antero has 63,000 net acres in the Piceance.
Fayetteville Shale—Antero has 7 MMcfd of net production and 5,000 net acres in the Fayetteville Shale play. The Company has one non-operated Fayetteville Shale well drilling with a 6% working interest.
Net Risked Resources
Antero has an estimated 17.0 Tcfe of undeveloped net risked resources in its three core areas. This estimate excludes proved developed producing reserves but includes proved undeveloped reserves. In the Marcellus Shale, 12.0 Tcfe of net risked resource is attributable to 2,160 future gross horizontal wells with estimated net capital spending of $10.5 billion yielding a net development cost of $0.87 per Mcfe. The Marcellus Shale net risked resource estimate assumes that ethane is recovered from rich gas production beginning in 2013 and that a viable ethane market develops in the Marcellus. Recovering ethane in the Marcellus adds an estimated 2.4 Tcfe of net risked resource to Antero's proved, probable and possible (3P) Marcellus reserves as of June 30, 2011. In the Piceance, 3.5 Tcfe is attributable to 2,166 future gross wells with estimated net capital spending of $5.4 billion yielding a net development cost of $1.55 per Mcfe. The Piceance resource includes both Mesaverde rich gas vertical wells and deeper Mancos/Niobrara Shale horizontal wells. In the Arkoma, which includes both the Woodford Shale and the Fayetteville Shale, 1.5 Tcfe is attributable to 2,753 future gross horizontal wells with estimated net capital spending of $2.8 billion yielding a net development cost of $1.88 per Mcfe. Combining the resources from all three core areas, Antero has an inventory of 17.0 Tcfe of undeveloped net resources with over 7,000 future gross wells to drill with an estimated average net development cost of $1.10 per Mcfe.
Below is a table representing the Company's net risked resources by area and the associated net development costs:
|
Marcellus |
Piceance |
Arkoma |
TOTAL |
|||||||
|
Undeveloped net risked resources (Tcfe) |
12.0 |
3.5 |
1.5 |
17.0 |
||||||
|
Gross undeveloped locations |
2,160 |
2,166 |
2,753 |
7,079 |
||||||
|
Future net capital ($MMs) |
$10,453 |
$5,431 |
$2,832 |
$18,715 |
||||||
|
Future net development cost ($/Mcfe) |
$0.87 |
$1.55 |
$1.88 |
$1.10 |
||||||
Undeveloped net risked resource is an estimate prepared by Antero's internal reserve engineers including proved, probable and possible reserves using the June 30, 2011 5-year futures strip prices averaging $4.99 per MMBtu for natural gas, $98.37 per barrel for WTI oil and current NGL price correlations to WTI.
Commodity Hedges
From the beginning of the third quarter of 2011 through the end of 2016, Antero has hedged 499 Bcfe using simple fixed price swaps at an average NYMEX-equivalent price of $5.93 per MMBtu. Over 80% of estimated production for the last six months of 2011 is hedged at a NYMEX-equivalent price of $5.84 per MMBtu and over 60% of 2012 estimated production is hedged at a NYMEX-equivalent price of $5.84 per MMBtu. Virtually all of Antero's financial hedges are tied to the local basin. In the following table, these basin prices are converted to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market. Antero has nine different counterparties to its hedge contracts, all but one of which are lenders in the Company's bank credit facility.
|
Natural gas |
NYMEX- |
||||||
|
Calendar Year |
MMBtu/day |
index price |
|||||
|
2011 |
201,097 |
$ |
5.84 |
||||
|
2012 |
243,385 |
$ |
5.84 |
||||
|
2013 |
247,444 |
$ |
5.95 |
||||
|
2014 |
290,000 |
$ |
6.04 |
||||
|
2015 |
330,000 |
$ |
5.99 |
||||
|
2016 |
105,000 |
$ |
5.84 |
||||
Non-GAAP Financial Measures
Adjusted net income as set forth in this release represents income from operations before deferred income taxes, adjusted for certain non-cash items. We believe 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. The following table reconciles income from operations to adjusted net income:
|
Three months ended |
Six months ended |
||||||||||||||
|
2011 |
2010 |
2011 |
2010 |
||||||||||||
|
Net income (loss) |
$ |
74,623 |
$ |
(16,407) |
$ |
15,688 |
$ |
71,199 |
|||||||
|
Unrealized commodity derivative (gains) losses |
(97,814) |
(10,148) |
(20,549) |
(108,960) |
|||||||||||
|
Loss on sale of compressor station |
8,700 |
- |
8,700 |
- |
|||||||||||
|
Provision for income taxes |
33,785 |
2,862 |
25,363 |
14,180 |
|||||||||||
|
Adjusted net income |
$ |
19,294 |
$ |
(23,693) |
$ |
29,202 |
$ |
(23,581) |
|||||||
Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operations before changes in working capital and exploration expense. 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 as an alternative to cash flows from operations, 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:
|
Three months ended |
Six months ended |
|||||||||||||
|
2011 |
2010 |
2011 |
2010 |
|||||||||||
|
Net cash provided by operating activities |
$ |
41,736 |
$ |
8,915 |
$ |
111,903 |
$ |
60,904 |
||||||
|
Net change in working capital |
(17,101) |
(17,524) |
6,451 |
(1,991) |
||||||||||
|
Cash flow from operations before changes in working capital |
$ |
58,837 |
$ |
26,439 |
$ |
105,452 |
$ |
62,895 |
||||||
EBITDAX is a non-GAAP financial measure that we define as net income before interest expense and other income or expense, taxes, impairments, depletion, depreciation, amortization, exploration expense, unrealized hedge gains or losses, gain or loss on sale of assets, franchise taxes and expenses related to business acquisitions. EBITDAX, as used and defined by us, 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 provided by 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 are required for debt service, capital expenditures, working capital, and other commitments and obligations. However, our management team believes EBITDAX is useful to an investor in evaluating our operating performance because this measure is widely used by investors in the natural gas and oil 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 our operations from period to period by removing the effect of our capital structure from our operating structure; and is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to a covenant under our senior secured revolving credit facility. EBITDAX is also used as a measure of operating performance pursuant to a covenant under the indenture governing our 9.375% and 7.25% 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 our 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 our net income to EBITDAX for the three and six months ended June 30, 2010 and 2011:
|
Three months ended |
Six months ended |
|||||||||||||
|
2011 |
2010 |
2011 |
2010 |
|||||||||||
|
Net income (loss) |
$ |
74,623 |
$ |
(16,407) |
$ |
15,688 |
$ |
71,199 |
||||||
|
Unrealized loss (gain) on commodity derivative contracts |
(97,814) |
(10,148) |
(20,549) |
(108,960) |
||||||||||
|
Interest expense and other |
15,606 |
14,188 |
30,754 |
29,082 |
||||||||||
|
Provision (benefit) for income taxes |
33,785 |
2,862 |
25,363 |
14,180 |
||||||||||
|
Depreciation, depletion, amortization and accretion |
39,088 |
32,340 |
72,853 |
65,409 |
||||||||||
|
Impairment of unproved properties |
782 |
18,285 |
3,100 |
20,547 |
||||||||||
|
Exploration expense |
2,304 |
2,047 |
5,433 |
3,399 |
||||||||||
|
Loss on sale of compressor station |
8,700 |
— |
8,700 |
— |
||||||||||
|
Other |
156 |
37 |
523 |
73 |
||||||||||
|
EBITDAX |
$ |
77,230 |
$ |
43,204 |
$ |
141,865 |
$ |
94,929 |
||||||
The cash prices realized for oil, NGLs and natural gas production including the amounts realized on cash settled derivatives are a critical component in the Company's performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various hedging and derivative transactions, such information is now reported in various lines of the income statement.
Antero Resources is an independent oil and natural gas company engaged in the acquisition, development and production of unconventional natural gas properties primarily located in the Appalachian Basin in West Virginia and Pennsylvania, the Arkoma Basin in Oklahoma and the Piceance Basin in Colorado. Our website is www.anteroresources.com.
This release includes "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. 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.
|
ANTERO RESOURCES LLC Consolidated Balance Sheets December 31, 2010 and June 30, 2011 (Unaudited) (In thousands) |
|||||||
|
2010 |
2011 |
||||||
|
Assets |
|||||||
|
Current assets: |
|||||||
|
Cash and cash equivalents |
$ |
8,988 |
3,943 |
||||
|
Accounts receivable — trade, net of allowance for doubtful accounts of $272 and $181 in 2010 and 2011, respectively |
30,971 |
30,260 |
|||||
|
Accrued revenue |
24,868 |
36,762 |
|||||
|
Prepaid expenses |
7,087 |
8,644 |
|||||
|
Derivative instruments |
82,960 |
91,295 |
|||||
|
Inventories |
2,031 |
3,219 |
|||||
|
Total current assets |
156,905 |
174,123 |
|||||
|
Property and equipment: |
|||||||
|
Natural gas properties, at cost (successful efforts method): |
|||||||
|
Unproved properties |
737,358 |
757,832 |
|||||
|
Producing properties |
1,762,206 |
2,006,506 |
|||||
|
Gathering systems and facilities |
85,404 |
119,357 |
|||||
|
Other property and equipment |
5,975 |
6,775 |
|||||
|
2,590,943 |
2,890,470 |
||||||
|
Less accumulated depletion, depreciation, and amortization |
(431,181) |
(503,829) |
|||||
|
Property and equipment, net |
2,159,762 |
2,386,641 |
|||||
|
Derivative instruments |
147,417 |
159,632 |
|||||
|
Other assets, net |
22,203 |
23,221 |
|||||
|
Total assets |
$ |
2,486,287 |
2,743,617 |
||||
|
ANTERO RESOURCES LLC Consolidated Balance Sheets December 31, 2010 and June 30, 2011 (Unaudited) (In thousands) |
|||||||
|
2010 |
2011 |
||||||
|
Liabilities and Equity |
|||||||
|
Current liabilities: |
|||||||
|
Accounts payable |
$ |
82,436 |
85,838 |
||||
|
Accrued expenses |
21,746 |
26,126 |
|||||
|
Revenue distributions payable |
29,917 |
41,359 |
|||||
|
Advances from joint interest owners |
1,478 |
3,965 |
|||||
|
Derivative instruments |
4,212 |
— |
|||||
|
Deferred income tax liability |
12,694 |
15,498 |
|||||
|
Total current liabilities |
152,483 |
172,786 |
|||||
|
Long-term liabilities: |
|||||||
|
Bank credit facility |
100,000 |
325,000 |
|||||
|
Senior notes |
527,632 |
527,481 |
|||||
|
Long-term note |
25,000 |
25,000 |
|||||
|
Asset retirement obligations |
5,374 |
5,842 |
|||||
|
Deferred income tax liability |
77,489 |
100,048 |
|||||
|
Other long-term liabilities |
3,322 |
5,643 |
|||||
|
Total liabilities |
891,300 |
1,161,800 |
|||||
|
Equity: |
|||||||
|
Members' equity |
1,489,806 |
1,460,948 |
|||||
|
Accumulated earnings |
105,181 |
120,869 |
|||||
|
Total equity |
1,594,987 |
1,581,817 |
|||||
|
Total liabilities and equity |
$ |
2,486,287 |
2,743,617 |
||||
|
ANTERO RESOURCES LLC Consolidated Statements of Operations Six Months Ended June 30, 2010 and 2011 (Unaudited) (In thousands) |
|||||||
|
2010 |
2011 |
||||||
|
Revenue: |
|||||||
|
Natural gas sales |
$ |
40,268 |
86,695 |
||||
|
Natural gas liquids sales |
2,619 |
7,976 |
|||||
|
Oil sales |
2,303 |
2,888 |
|||||
|
Realized and unrealized gain on commodity derivative instruments (including unrealized gains of $10,148 and $97,814 in 2010 and 2011, respectively) |
26,324 |
117,135 |
|||||
|
Gas gathering and processing revenue |
6,076 |
— |
|||||
|
Total revenue |
77,590 |
214,694 |
|||||
|
Operating expenses: |
|||||||
|
Lease operating expenses |
6,277 |
7,683 |
|||||
|
Gathering, compression and transportation |
10,757 |
19,807 |
|||||
|
Production taxes |
1,932 |
4,109 |
|||||
|
Exploration expenses |
2,047 |
2,304 |
|||||
|
Impairment of unproved properties |
18,285 |
782 |
|||||
|
Depletion, depreciation and amortization |
32,265 |
38,979 |
|||||
|
Accretion of asset retirement obligations |
75 |
109 |
|||||
|
General and administrative |
4,757 |
8,207 |
|||||
|
Loss on sale of assets |
— |
8,700 |
|||||
|
Total operating expenses |
76,395 |
90,680 |
|||||
|
Operating income |
1,195 |
124,014 |
|||||
|
Other expense: |
|||||||
|
Interest expense |
(13,965) |
(15,606) |
|||||
|
Realized and unrealized gains on interest derivative instruments, net (including unrealized gains of $1,949 and $2,165 in 2010 and 2011, respectively |
(223) |
— |
|||||
|
Total other expense |
(14,188) |
(15,606) |
|||||
|
Income (loss) before income taxes |
(12,993) |
108,408 |
|||||
|
Income tax expense |
(2,862) |
(33,785) |
|||||
|
Net income (loss) |
(15,855) |
74,623 |
|||||
|
Noncontrolling interest in net income of consolidated subsidiary |
(552) |
— |
|||||
|
Net income (loss) attributable to Antero equity owners |
$ |
(16,407) |
74,623 |
||||
|
ANTERO RESOURCES LLC Consolidated Statements of Operations Three Months Ended June 30, 2010 and 2011 (Unaudited) (In thousands) |
|||||||
|
2010 |
2011 |
||||||
|
Revenue: |
|||||||
|
Natural gas sales |
$ |
92,508 |
147,553 |
||||
|
Natural gas liquids sales |
4,331 |
13,561 |
|||||
|
Oil sales |
4,417 |
5,416 |
|||||
|
Realized and unrealized gain on commodity derivative instruments (including unrealized gains of $108,960 and $20,549 in 2010 and 2011, respectively) |
137,407 |
69,107 |
|||||
|
Gas gathering and processing revenue |
12,489 |
— |
|||||
|
Total revenue |
251,152 |
235,637 |
|||||
|
Operating expenses: |
|||||||
|
Lease operating expenses |
10,875 |
14,984 |
|||||
|
Gathering, compression and transportation |
20,898 |
36,957 |
|||||
|
Production taxes |
4,602 |
7,237 |
|||||
|
Exploration expenses |
3,399 |
5,433 |
|||||
|
Impairment of unproved properties |
20,547 |
3,100 |
|||||
|
Depletion, depreciation and amortization |
65,261 |
72,648 |
|||||
|
Accretion of asset retirement obligations |
148 |
205 |
|||||
|
General and administrative |
9,168 |
14,568 |
|||||
|
Loss on sale of compressor station |
— |
8,700 |
|||||
|
Total operating expenses |
134,898 |
163,832 |
|||||
|
Operating income |
116,254 |
71,805 |
|||||
|
Other income expense: |
|||||||
|
Interest expense |
(27,257) |
(30,660) |
|||||
|
Realized and unrealized gains on interest derivative instruments, net (including unrealized gains of $3,474 and $4,212 in 2010 and 2011, respectively) |
(1,825) |
(94) |
|||||
|
Total other expense |
(29,082) |
(30,754) |
|||||
|
Income before income taxes |
87,172 |
41,051 |
|||||
|
Income tax expense |
(14,180) |
(25,363) |
|||||
|
Net income |
72,992 |
15,688 |
|||||
|
Noncontrolling interest in net income of consolidated subsidiary |
(1,793) |
— |
|||||
|
Net income attributable to Antero equity owners |
$ |
71,199 |
15,688 |
||||
|
ANTERO RESOURCES LLC Consolidated Statements of Cash Flows Six Months Ended June 30, 2010 and 2011 (Unaudited) (In thousands) |
|||||||
|
2010 |
2011 |
||||||
|
Cash flows from operating activities: |
|||||||
|
Net income |
$ |
72,992 |
15,688 |
||||
|
Adjustment to reconcile net income to net cash provided by operating activities: |
|||||||
|
Depletion, depreciation, and amortization |
65,261 |
72,648 |
|||||
|
Dry hole costs |
360 |
3,044 |
|||||
|
Impairment of unproved properties |
20,547 |
3,100 |
|||||
|
Accretion of asset retirement obligations |
148 |
205 |
|||||
|
Accretion of bond discount (premium), net |
(207) |
(151) |
|||||
|
Amortization and write-off of deferred financing costs |
2,048 |
1,617 |
|||||
|
Unrealized gains on derivative instruments, net |
(112,434) |
(24,762) |
|||||
|
Deferred taxes |
14,180 |
25,363 |
|||||
|
Loss on sale of assets |
— |
8,700 |
|||||
|
Changes in current assets and liabilities: |
|||||||
|
Accounts receivable |
6,228 |
712 |
|||||
|
Accrued revenue |
(4,724) |
(11,894) |
|||||
|
Other current assets |
(10,792) |
(2,745) |
|||||
|
Accounts payable |
3,804 |
(252) |
|||||
|
Other liabilities |
(2,498) |
6,701 |
|||||
|
Revenue distributions payable |
5,485 |
11,442 |
|||||
|
Advances from joint interest owners |
506 |
2,487 |
|||||
|
Net cash provided by operating activities |
60,904 |
111,903 |
|||||
|
Cash flows from investing activities: |
|||||||
|
Additions to unproved properties |
(15,723) |
(45,960) |
|||||
|
Drilling costs |
(139,136) |
(229,122) |
|||||
|
Additions to gathering systems and facilities |
(6,536) |
(49,953) |
|||||
|
Additions to other property and equipment |
(413) |
(799) |
|||||
|
Proceeds from asset sales |
— |
15,379 |
|||||
|
Increase in other assets |
(576) |
(2,635) |
|||||
|
Net cash used in investing activities |
(162,384) |
(313,090) |
|||||
|
Cash flows from financing activities: |
|||||||
|
Issuance of senior notes |
156,000 |
— |
|||||
|
Borrowings on bank credit facility |
85,994 |
255,000 |
|||||
|
Payments on bank credit facility |
(142,080) |
(30,000) |
|||||
|
Payments of deferred financing costs |
(3,788) |
||||||
|
Distribution to members |
— |
(28,858) |
|||||
|
Other |
(1,258) |
— |
|||||
|
Net cash provided by financing activities |
94,868 |
196,142 |
|||||
|
Net decrease in cash and cash equivalents |
(6,612) |
(5,045) |
|||||
|
Cash and cash equivalents, beginning of period |
10,669 |
8,988 |
|||||
|
Cash and cash equivalents, end of period |
$ |
4,057 |
3,943 |
||||
|
Supplemental disclosure of cash flow information: |
|||||||
|
Cash paid during the period for interest |
$ |
(31,918) |
(29,150) |
||||
|
Supplemental disclosure of noncash investing activities: |
|||||||
|
Changes in accounts payable for additions to properties, gathering systems and facilities |
$ |
28,560 |
3,654 |
||||
|
Results of Operations Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2011 The following table sets forth selected operating data for the three months ended June 30, 2010 compared to the three months ended June 30, 2011: |
||||||||||||||
|
Three Months |
Amount of |
Percent |
||||||||||||
|
2010 |
2011 |
(Decrease) |
Change |
|||||||||||
|
(in thousands, except per unit and production data) |
||||||||||||||
|
Operating revenues: |
||||||||||||||
|
Natural gas sales |
$ |
40,268 |
$ |
86,695 |
$ |
46,427 |
115% |
|||||||
|
Natural gas liquids sales |
2,619 |
7,976 |
5,357 |
205% |
||||||||||
|
Oil sales |
2,303 |
2,888 |
585 |
25% |
||||||||||
|
Realized commodity derivative gains |
16,176 |
19,320 |
3,144 |
19% |
||||||||||
|
Unrealized commodity derivative gains |
10,148 |
97,815 |
87,667 |
864% |
||||||||||
|
Gathering and processing |
6,076 |
— |
(6,076) |
* |
||||||||||
|
Total operating revenues |
77,590 |
214,694 |
137,104 |
177% |
||||||||||
|
Operating expenses: |
||||||||||||||
|
Lease operating expense |
6,277 |
7,683 |
1,406 |
22% |
||||||||||
|
Gathering, compression and transportation |
10,757 |
19,807 |
9,050 |
84% |
||||||||||
|
Production taxes |
1,932 |
4,109 |
2,177 |
113% |
||||||||||
|
Exploration expense |
2,047 |
2,304 |
257 |
13% |
||||||||||
|
Impairment of unproved properties |
18,285 |
782 |
(17,503) |
(96)% |
||||||||||
|
Depletion depreciation and amortization |
32,265 |
38,979 |
6,714 |
21% |
||||||||||
|
Accretion of asset retirement obligations |
75 |
109 |
34 |
45% |
||||||||||
|
General and administrative |
4,757 |
8,207 |
3,450 |
73% |
||||||||||
|
Loss on sale of compressor station |
— |
8,700 |
8,700 |
* |
||||||||||
|
Total operating expenses |
76,395 |
90,680 |
14,285 |
19% |
||||||||||
|
Operating income |
1,195 |
124,014 |
122,819 |
* |
||||||||||
|
Other income (expense): |
||||||||||||||
|
Interest expense |
(13,965) |
(15,606) |
(1,641) |
12% |
||||||||||
|
Realized interest rate derivative losses |
(2,172) |
(2,165) |
7 |
* |
||||||||||
|
Unrealized interest rate derivative gains |
1,949 |
2,165 |
216 |
11% |
||||||||||
|
Total other expense |
(14,188) |
(15,606) |
(1,418) |
10% |
||||||||||
|
Income (loss) before income taxes |
(12,993) |
108,408 |
121,401 |
* |
||||||||||
|
Deferred income tax expense |
(2,862) |
(33,785) |
(30,923) |
* |
||||||||||
|
Net income (loss) |
(15,855) |
74,623 |
90,478 |
* |
||||||||||
|
Non-controlling interest in net income of consolidated subsidiary |
(552) |
— |
552 |
* |
||||||||||
|
Net income (loss) attributable to Antero members |
$ |
(16,407) |
$ |
74,623 |
$ |
91,030 |
* |
|||||||
|
EBITDAX |
$ |
43,204 |
$ |
77,230 |
$ |
34,026 |
79% |
|||||||
|
Production data: |
||||||||||||||
|
Natural gas (Bcf) |
10 |
19 |
9 |
90% |
||||||||||
|
Oil (MBbl) |
36 |
34 |
(2) |
(6)% |
||||||||||
|
NGLs (MBbl) |
148 |
150 |
2 |
1% |
||||||||||
|
Combined (Bcfe) |
11 |
20 |
9 |
82% |
||||||||||
|
Daily combined production (MMcfe/d) |
124 |
221 |
97 |
78% |
||||||||||
|
Average prices before effects of hedges: |
||||||||||||||
|
Natural gas (per Mcf) |
$ |
3.95 |
$ |
4.56 |
$ |
0.61 |
15% |
|||||||
|
Natural gas liquids (per Bbl) |
$ |
45.58 |
$ |
53.01 |
$ |
7.43 |
16% |
|||||||
|
Oil (per Bbl) |
$ |
63.27 |
$ |
85.98 |
$ |
22.71 |
36% |
|||||||
|
Combined (per Mcfe) |
$ |
4.23 |
$ |
4.85 |
$ |
0.62 |
15% |
|||||||
|
Average realized prices after effects of hedges: |
||||||||||||||
|
Natural gas (per Mcf) |
$ |
5.53 |
$ |
5.59 |
$ |
0.06 |
1% |
|||||||
|
Natural gas liquids (per Bbl) |
$ |
45.58 |
$ |
53.01 |
$ |
7.43 |
16% |
|||||||
|
Oil (per Bbl) |
$ |
63.27 |
$ |
75.59 |
$ |
12.32 |
19% |
|||||||
|
Combined (per Mcfe) |
$ |
5.74 |
$ |
5.81 |
$ |
0.07 |
1% |
|||||||
|
Average Costs (per Mcfe): |
||||||||||||||
|
Lease operating costs |
$ |
0.59 |
$ |
0.38 |
$ |
(0.21) |
(36)% |
|||||||
|
Gathering, compression and transportation |
$ |
1.01 |
$ |
0.98 |
$ |
(0.03) |
(3)% |
|||||||
|
Production taxes |
$ |
0.18 |
$ |
0.20 |
$ |
0.02 |
11% |
|||||||
|
Depletion, depreciation amortization and accretion |
$ |
3.02 |
$ |
1.94 |
$ |
(1.08) |
(36)% |
|||||||
|
General and administrative |
$ |
0.44 |
$ |
0.41 |
$ |
(0.03) |
(7)% |
|||||||
|
Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2011 The following table sets forth selected operating data for the six months ended June 30, 2010 compared to the six months ended June 30, 2011: |
|||||||||||||
|
Six Months |
Amount of |
Percent |
|||||||||||
|
2010 |
2011 |
(Decrease) |
Change |
||||||||||
|
(in thousands, except per unit and production data) |
|||||||||||||
|
Operating revenues: |
|||||||||||||
|
Natural gas sales |
$ |
92,508 |
$ |
147,553 |
$ |
55,045 |
60% |
||||||
|
Natural gas liquids sales |
4,331 |
13,561 |
9,230 |
213% |
|||||||||
|
Oil sales |
4,417 |
5,416 |
999 |
23% |
|||||||||
|
Realized commodity derivative gains |
28,447 |
48,558 |
20,111 |
71% |
|||||||||
|
Unrealized commodity derivative gains (losses) |
108,960 |
20,549 |
(88,411) |
(81)% |
|||||||||
|
Gathering and processing |
12,489 |
— |
(12,489) |
* |
|||||||||
|
Total operating revenues |
251,152 |
235,637 |
(15,515) |
(6)% |
|||||||||
|
Operating expenses: |
|||||||||||||
|
Lease operating expense |
10,875 |
14,984 |
4,109 |
38% |
|||||||||
|
Gathering, compression and transportation |
20,898 |
36,957 |
16,059 |
77% |
|||||||||
|
Production taxes |
4,602 |
7,237 |
2,635 |
57% |
|||||||||
|
Exploration expense |
3,399 |
5,433 |
2,034 |
60% |
|||||||||
|
Impairment of unproved properties |
20,547 |
3,100 |
(17,447) |
(85)% |
|||||||||
|
Depletion depreciation and amortization |
65,261 |
72,648 |
7,387 |
11% |
|||||||||
|
Accretion of asset retirement obligations |
148 |
205 |
57 |
39% |
|||||||||
|
General and administrative |
9,168 |
14,568 |
5,400 |
59% |
|||||||||
|
Loss on sale of compressor station |
— |
8,700 |
8,700 |
* |
|||||||||
|
Total operating expenses |
134,898 |
163,832 |
28,934 |
21% |
|||||||||
|
Operating income (loss) |
116,254 |
71,805 |
(44,449) |
* |
|||||||||
|
Other income (expense): |
|||||||||||||
|
Interest expense |
(27,257) |
(30,660) |
(3,403) |
(12)% |
|||||||||
|
Realized interest rate derivative losses |
(5,299) |
(4,306) |
993 |
(19)% |
|||||||||
|
Unrealized interest rate derivative gains |
3,474 |
4,212 |
738 |
21% |
|||||||||
|
Total other expense |
(29,082) |
(30,754) |
(1,672) |
6% |
|||||||||
|
Income (loss) before income taxes |
87,172 |
41,051 |
(46,121) |
* |
|||||||||
|
Deferred income tax (expense) benefit |
(14,180) |
(25,363) |
(11,183) |
* |
|||||||||
|
Net income (loss) |
72,992 |
15,688 |
(57,304) |
* |
|||||||||
|
Non-controlling interest in net income of consolidated subsidiary |
(1,793) |
— |
1,793 |
* |
|||||||||
|
Net income (loss) attributable to Antero members |
$ |
71,199 |
$ |
15,688 |
$ |
(55,511) |
* |
||||||
|
EBITDAX |
$ |
94,929 |
$ |
141,865 |
$ |
46,936 |
49% |
||||||
|
Production data: |
|||||||||||||
|
Natural gas (Bcf) |
20 |
34 |
14 |
70% |
|||||||||
|
Oil (MBbl) |
68 |
65 |
(3) |
(4)% |
|||||||||
|
NGLs (MBbl) |
282 |
276 |
(6) |
(2)% |
|||||||||
|
Combined (Bcfe) |
22 |
36 |
14 |
64% |
|||||||||
|
Daily combined production (MMcfe/d) |
121 |
197 |
76 |
63% |
|||||||||
|
Average prices before effects of hedges: |
|||||||||||||
|
Natural gas (per Mcf) |
$ |
4.67 |
$ |
4.39 |
$ |
(0.28) |
(6)% |
||||||
|
Natural gas liquids (per Bbl) |
$ |
47.70 |
$ |
49.08 |
1.38 |
3% |
|||||||
|
Oil (per Bbl) |
$ |
64.67 |
$ |
82.88 |
$ |
18.21 |
28% |
||||||
|
Combined (per Mcfe) |
$ |
4.88 |
$ |
4.67 |
$ |
(0.21) |
(4)% |
||||||
|
Average realized prices after effects of hedges: |
|||||||||||||
|
Natural gas (per Mcf) |
$ |
6.11 |
$ |
5.84 |
$ |
(0.27) |
(4)% |
||||||
|
Natural gas liquids (per Bbl) |
$ |
47.70 |
$ |
49.08 |
1.38 |
3% |
|||||||
|
Oil (per Bbl) |
$ |
64.67 |
$ |
75.27 |
$ |
10.60 |
16% |
||||||
|
Combined (per Mcfe) |
$ |
6.25 |
$ |
6.03 |
$ |
(0.22) |
(4)% |
||||||
|
Average Costs (per Mcfe): |
|||||||||||||
|
Lease operating costs |
$ |
0.52 |
$ |
0.42 |
$ |
(0.10) |
(19)% |
||||||
|
Gathering, compression and transportation |
$ |
1.01 |
$ |
1.04 |
$ |
0.03 |
3% |
||||||
|
Production taxes |
$ |
0.22 |
$ |
0.20 |
$ |
(0.02) |
(9)% |
||||||
|
Depletion, depreciation amortization and accretion |
$ |
3.14 |
$ |
2.04 |
$ |
(1.10) |
(35)% |
||||||
|
General and administrative |
$ |
0.44 |
$ |
0.41 |
$ |
(0.03) |
(7)% |
||||||
SOURCE Antero Resources
Released August 15, 2011