DENVER, Oct. 28, 2015 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its third quarter 2015 financial results. The relevant financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, which has been filed with the Securities and Exchange Commission ("SEC").
Highlights for the Third Quarter of 2015:
Net income of $534 million, or $1.93 per share, a 162% increase compared to the prior year quarter
Adjusted net income of $14 million, or $0.05 per share, an 80% decrease compared to the prior year quarter
Adjusted EBITDAX of $291 million, flat compared to the prior year quarter
On a per unit basis, cash production expense declined 18%, or $0.28 per Mcfe, and G&A expense declined 10%, or $0.03 per Mcfe, compared to the prior year quarter
Net daily gas equivalent production averaged 1,506 MMcfe/d, a 39% increase compared to the prior year quarter and a 1% increase compared to the prior quarter
Net daily liquids production, included in the above, averaged 52,250 Bbl/d, a 109% increase compared to the prior year quarter and a 14% increase compared to the prior quarter
Realized natural gas equivalent price including NGLs, oil and settled derivatives averaged $3.83 per Mcfe
Increased credit facility borrowing base by 12.5% to $4.5 billion from $4.0 billion
Closed drop down of water business and received $794 million of cash proceeds and approximately 11.0 million common units of Antero Midstream Partners
Recent Developments
Antero Resources Borrowing Base Increase
On October 26, 2015, Antero's borrowing base under its upstream credit facility was increased by 12.5% to $4.5 billion, a $500 million increase over Antero's previous borrowing base of $4.0 billion. Lender commitments under the facility remain at $4.0 billion. As of September 30, 2015, the Company had $500 million drawn under the upstream credit facility and $535 million in letters of credit outstanding, resulting in $3.0 billion in Antero standalone liquidity and $3.5 billion of unused borrowing base capacity, on a pro forma basis giving effect to the borrowing base increase.
Closing of the Water Business Drop Down
As previously announced on September 24th, 2015, Antero successfully completed the water business drop down transaction to Antero Midstream Partners, LP ("Antero Midstream") for $1.05 billion. In connection with the transaction, Antero received cash consideration of $794 million and 10,988,421 Antero Midstream common units, plus a total of $250 million of potential earn-out payments due at the end of 2019 and 2020 contingent on meeting specific average fresh water delivery volume thresholds. Transaction proceeds were used by Antero to repay credit facility borrowings.
Third Quarter 2015 Financial Results
As of September 30, 2015, Antero owned a 66.5% limited partner interest in Antero Midstream. Antero Midstream's results are consolidated with Antero's results.
For the three months ended September 30, 2015, the Company reported net income attributable to common stockholders of $534 million, or $1.93 per basic and diluted share, compared to net income of $204 million, or $0.78 per basic and diluted share in the third quarter of 2014. GAAP net income for the third quarter of 2015 included the following items:
Non-cash gains on unsettled derivatives of $873 million ($543 million net of tax);
Non-cash equity-based stock compensation expense of $24 million ($18 million net of tax); and
Impairment of unproved properties of $9 million ($5 million net of tax)
Without the effect of these non-cash items, the Company's results for the third quarter of 2015 were as follows:
Adjusted net income attributable to common stockholders of $14 million, or $0.05 per basic and diluted share, an 80% decrease compared to the third quarter of 2014;
Adjusted EBITDAX of $291 million, in line with the third quarter of 2014; and
Cash flow from operations before changes in working capital of $237 million, a 3% decrease compared to the third quarter of 2014
Commenting on third quarter 2015 EBITDAX and Antero's business model, Paul Rady, Chairman of the Board and CEO, said, "Despite the challenging commodity price environment during the quarter, our results truly show the sustainability of Antero's business model. Antero's better than expected production, combined with the Company's firm transportation portfolio and industry leading hedge position, again allowed Antero to achieve Appalachian leading EBITDAX and cash flow margins during the quarter. Despite more than a 30% decrease in natural gas prices and 50% decrease in crude oil prices over the last year, Antero generated the same level of EBITDAX as compared to the prior year quarter."
For a description of adjusted net income attributable to common stockholders, Adjusted EBITDAX and cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Net daily production for the third quarter of 2015 averaged 1,506 MMcfe/d, a 39% increase as compared to the third quarter of 2014 and a 1% increase from the second quarter of 2015. Net daily production was comprised of 1,192 MMcf/d of natural gas (79%), 45,072 Bbl/d of natural gas liquids ("NGLs") (18%) and 7,178 Bbl/d of crude oil (3%). Third quarter 2015 net liquids (NGLs and oil) daily production of 52,250 Bbl/d increased 109% as compared to the third quarter of 2014 and 14% from the second quarter of 2015.
Average natural gas price before settled derivatives decreased 36% from the prior year quarter to $2.32 per Mcf, a $0.45 per Mcf negative differential to Nymex, as Nymex natural gas prices decreased 32% from the prior year quarter. Approximately 68% of Antero's third quarter 2015 natural gas production was realized at favorable price indices, including Columbia Gas Transmission (TCO), Chicago and Nymex. The remaining 32% of natural gas production was priced at various less favorable index pricing points, primarily Dominion South and Tetco M2. Antero's average realized natural gas price after settled derivatives for the third quarter of 2015 was $3.99 per Mcf, a $1.22 positive differential to the Nymex average price for the period, and a 7% decrease compared to the prior year quarter. During the quarter, Antero realized a cash settled natural gas derivative gain of $183 million, or $1.67 per Mcf.
Antero's average realized C3+ NGL price before settled derivatives for the third quarter of 2015 was $12.08 per barrel, or approximately 26% of the WTI oil price average for the period. This represents a 74% decrease for NGL prices compared to the prior year quarter as WTI oil prices decreased 53% from the prior year quarter. NGL differentials in the Appalachian Basin have widened significantly in the region due to the need to utilize rail transport to move the product to markets. Logistics and regional shipping costs are expected to improve once the Mariner East II pipeline goes in service, which is anticipated to occur by the end of 2016. The Company's average realized NGL price after settled derivatives was $16.47 per barrel, or 35% of the WTI oil price average for the period, which represents a 65% decrease from the prior year quarter. For the third quarter of 2015, Antero realized a cash settled NGL derivative gain of $18 million, or $4.39 per barrel. Antero's NGL barrels are comprised of propane, butane and heavier liquids, as ethane is rejected at the gas processing plant and sold in the natural gas stream.
Antero's average realized oil price before settled derivatives for the third quarter of 2015 was $30.49 per barrel, a $15.92 per barrel negative differential to the average WTI oil price for the period, and a 64% decrease compared to the prior year quarter. The third quarter 2015 negative differential for condensate was a result of an increase in production of high API gravity condensate in the Utica. The Company's average realized oil price after settled derivatives decreased 54% from the prior year quarter to $38.18 per barrel, an $8.24 per barrel negative differential to the WTI oil price. For the third quarter of 2015, Antero realized a cash settled oil derivative gain of $5 million, or $7.69 per barrel. Including $206 million of total cash settled derivative gains for all products, the average all-in natural gas equivalent price, including NGLs, oil and derivative settlements, was $3.83 per Mcfe for the third quarter of 2015.
Total revenues for the third quarter of 2015 were $1.4 billion as compared to $762 million for the third quarter of 2014. Revenue for the third quarter of 2015 included an $873 million non-cash gain on unsettled derivatives while the third quarter of 2014 included a $252 million non-cash gain on unsettled derivatives. Liquids production contributed 22% of combined natural gas, NGLs and oil revenue before derivatives in the third quarter of 2015. Adjusted net revenue increased 12% to $570 million compared to the third quarter of 2014 (including cash settled derivative gains and losses but excluding non-cash unsettled derivative gains and losses). For a reconciliation of adjusted net revenue to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Net marketing expense was $26 million, or $0.19 per Mcfe, for the third quarter of 2015. Marketing revenue for the third quarter of 2015 was $36 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 Rockies Express Pipeline as well as to capture the positive spread between Tetco M2 pricing and Chicago pricing. Marketing expense for the third quarter of 2015 was $62 million. The largest components of marketing expense were the fixed transportation costs related to excess natural gas takeaway capacity, the cost of purchasing third-party gas and the fixed transportation costs associated with the Company's underutilized ATEX ethane pipeline capacity. The decrease in net marketing expense versus the prior quarter was primarily the result of increased production volumes in the Utica Shale flowing on the Company's Chicago firm transportation portfolio, which includes capacity on Rex, MGT, NGPL and ANR North.
Per unit cash production expense (lease operating, gathering, compression, processing and transportation, and production tax) for the third quarter of 2015 was $1.32 per Mcfe which is an 18% decrease compared to $1.60 per Mcfe in the prior year quarter. The decrease in cash production expense was driven by lower production taxes due to lower commodity prices, a reduction in the estimated liability for property taxes accrued for in prior periods, as well as reduced fuel costs due to lower commodity prices. Per unit general and administrative expense for the third quarter of 2015, excluding non-cash equity-based compensation expense, was $0.26 per Mcfe, a 10% decrease from the third quarter of 2014. The decrease was primarily driven by the significant increase in net production which was somewhat offset by an increase in the Company's workforce. Per unit depreciation, depletion and amortization expense increased 9% from the prior year quarter to $1.37 per Mcfe due to proved developed reserves increasing at a slower rate than the corresponding cost additions for wells completed during the period.
Adjusted EBITDAX of $291 million for the third quarter of 2015 was in line with the prior year quarter. Adjusted EBITDAX margin for the quarter was $2.10 per Mcfe, representing a 28% decrease from the prior year quarter due to lower commodity prices and lower hedged prices. For the third quarter of 2015, cash flow from operations before changes in working capital decreased 3% from the prior year to $237 million.
For a description of Adjusted EBITDAX and Adjusted EBITDAX margin, cash flow from operations before changes in working capital and adjusted net income attributable to common stockholders and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Balance Sheet and Liquidity
As of September 30, 2015 the Company's consolidated net debt was $4.4 billion, of which $500 million were borrowings outstanding under the Company's senior secured revolving credit facility, and $525 million were borrowings under Antero Midstream's $1.5 billion senior secured credit facility. Pro forma for the increased $4.5 billion borrowing base and including the $535 million in letters of credit outstanding, the Company had approximately $4.0 billion in available liquidity and $4.5 billion in unused borrowing base capacity on a consolidated basis as of September 30, 2015. For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Third Quarter 2015 Capital Spending
Antero's drilling and completion costs for the three months ended September 30, 2015 were $341 million. In addition, the Company invested $39 million for land, $20 million for fresh water distribution projects in the Marcellus and Utica Shale plays and $2 million in other capital projects.
Antero Midstream Financial Results
The following reflects results for Antero Midstream for the three and nine months ended September 30, 2015, and predecessor results for the three and nine months ended September 30, 2014. In addition, Antero Midstream's recent acquisition of Antero's integrated water business was accounted for as a transfer of entities under common control. As a result, the Partnership recast its condensed combined consolidated financial statements to retrospectively reflect the integrated water business as if the assets and liabilities were owned for all past periods presented. Beginning in the third quarter of 2015, and as a result of the acquisition, Antero Midstream will report its results through two business segments, Gathering and Compression and Water Handling. To facilitate comparison and discussion for third quarter 2015, operating results below are only for the Gathering and Compression segment operations. For operating results associated with the Water Handling segment and its contribution to the recast condensed combined consolidated financial statements contained in Antero Midstream's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, please read "Non-GAAP Financial Measures."
Antero Midstream's low pressure gathering volumes for the third quarter of 2015 averaged 1,038 MMcf/d, a 95% increase from the third quarter of 2014 and an 8% increase from the second quarter of 2015. High pressure gathering volumes for the third quarter of 2015 averaged 1,216 MMcf/d, a 129% increase from the third quarter of 2014 and a 2% increase from the second quarter of 2015. Compression volumes for the third quarter of 2015 averaged 435 MMcf/d, a 275% increase from the third quarter of 2014 and a 4% decrease from the second quarter of 2015. Condensate gathering volumes averaged 2,856 Bbl/d during the quarter, a 145% increase compared to the prior year quarter. Volumetric growth was driven by production growth from Antero Resources.
Antero Midstream's revenue for the third quarter of 2015 was $59.3 million as compared to $26.3 million for the prior year quarter, driven primarily by increased throughput volumes across Antero Midstream's systems. Direct operating expenses were a $3.2 million credit, driven by an $8.4 million reduction in the estimated liability for property taxes accrued for in prior periods and a slight decrease in other operating expenses during the quarter. Allocated general and administrative expenses totaled $11.3 million, including $4.2 million of non-cash equity-based compensation. Total cash and non-cash operating expenses were $23.2 million including $15.1 million of depreciation.
Capital expenditures associated with gathering and compression totaled $83 million, including $55 million invested in the Marcellus and $28 million invested in the Utica. Gathering and compression capital expenditures were primarily related to the build-out of midstream infrastructure to support Antero Resources' development program. Additionally, Antero Midstream invested $29 million in water handling assets during the quarter.
On October 13, 2015, the Board of Directors of Antero Resources Midstream Management LLC, the general partner of Antero Midstream, declared a cash distribution of $0.205 per unit ($0.82 per unit annualized) for the third quarter of 2015. The distribution represents an 8% increase quarter over quarter and Antero Midstream's third consecutive quarterly distribution increase since its initial public offering in November 2014. The distribution will be payable on November 30, 2015 to unitholders of record as of November 11, 2015.
Antero Midstream results were released today and are available at www.anteromidstream.com.
Conference Call
A conference call is scheduled on Thursday, October 29, 2015 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 Friday, November 6, 2015 at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10072161.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until November 6, 2015 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the October 29, 2015 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
Adjusted net revenue as set forth in this release represents total operating revenue adjusted for certain non-cash items, including unsettled derivative gains and losses. 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 September 30,
Nine months ended
September 30,
2014
2015
2014
2015
Total operating revenue
$
762,490
$
1,443,335
$
1,242,035
$
3,049,736
Commodity derivative (gains) losses
(308,975)
(1,079,071)
63,720
(1,836,398)
Gains on settled derivatives
57,451
205,919
57,333
586,639
Adjusted net revenue
$
510,966
$
570,183
$
1,363,088
$
1,799,977
Adjusted net income attributable to common stockholders as set forth in this release represents net income from continuing operations attributable to common stockholders, adjusted for certain items. Antero believes that adjusted net income attributable to common stockholders 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 attributable to common stockholders is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income from continuing operations attributable to common stockholders as an indicator of financial performance. The following table reconciles net income from continuing operations attributable to common stockholders to adjusted net income attributable to common stockholders:
Three months ended
Nine months ended
September 30,
September 30,
2014
2015
2014
2015
Net income from continuing operations attributable to common stockholders
$
203,909
$
533,842
$
64,655
$
782,900
Non-cash commodity derivative (gains) losses on unsettled derivatives
(251,524)
(873,152)
121,053
(1,249,759)
Impairment of unproved properties
4,542
8,754
7,895
43,670
Equity-based compensation
24,285
23,915
85,896
79,280
Loss on early extinguishment of debt
—
—
20,386
—
Contract termination and rig stacking
—
—
—
10,902
Income tax effect of reconciling items
90,474
320,711
(63,348)
435,033
Adjusted net income attributable to common stockholders
$
71,686
$
14,070
$
236,537
$
102,026
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. 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 for 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:
Three months ended September 30,
Nine months ended
September 30,
2014
2015
2014
2015
Net cash provided by operating activities
$
300,717
$
246,005
$
798,746
$
836,600
Net change in working capital
(55,621)
(9,078)
(96,153)
(98,909)
Cash flow from operations before changes in working capital
$
245,096
$
236,927
$
702,593
$
737,691
The following table reconciles consolidated total debt to consolidated net debt as used in this release:
As of
September 30,
2015
Antero:
Bank credit facility
$
500,000
6.00% senior notes due 2020
525,000
5.375% senior notes due 2021
1,000,000
5.125% senior notes due 2022
1,100,000
5.625% senior notes due 2023
750,000
Net unamortized premium
6,777
Antero Midstream:
Bank credit facility
525,000
Consolidated total debt
4,406,777
Cash and cash equivalents
27,410
Consolidated net debt
$
4,379,367
Adjusted EBITDAX is a non-GAAP financial measure that Antero defines as net income 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 (loss), 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 and by its lenders pursuant to covenants under its bank 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 table represents a reconciliation of the Company's net income (loss) including noncontrolling interest to Adjusted EBITDAX, a reconciliation of total Adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled derivatives to Adjusted EBITDAX margin:
Three months ended September 30,
Nine months ended September 30,
(in thousands)
2014
2015
2014
2015
Net income from continuing operations including noncontrolling interest
$
203,909
544,734
64,655
804,422
Commodity derivative fair value (gains) losses
(308,975)
(1,079,071)
63,720
(1,836,398)
Gains on settled derivative instruments
57,451
205,919
57,333
586,639
Interest expense
42,455
60,921
111,057
173,929
Loss on early extinguishment of debt
—
—
20,386
—
Income tax expense
135,035
335,460
75,919
498,709
Depreciation, depletion, amortization, and accretion
124,944
189,086
321,915
549,240
Impairment of unproved properties
4,542
8,754
7,895
43,670
Exploration expense
7,476
1,087
21,176
3,086
Equity-based compensation expense
24,285
23,915
85,896
79,280
State franchise taxes
450
2
1,738
131
Contract termination and rig stacking
—
—
—
10,902
Consolidated Adjusted EBITDAX
291,572
290,807
831,690
913,610
Income from discontinued operations
—
—
2,210
—
Gain on sale of assets
—
—
(3,564)
—
Income tax expense
—
—
1,354
—
Adjusted EBITDAX from discontinued operations
—
—
—
—
Total adjusted EBITDAX
291,572
290,807
831,690
913,610
Interest expense
(42,455)
(60,921)
(111,057)
(173,929)
Exploration expense
(7,476)
(1,087)
(21,176)
(3,086)
Changes in current assets and liabilities
55,621
9,078
96,153
98,909
State franchise taxes
(450)
(2)
(1,738)
(131)
Other noncash items
3,905
8,130
4,874
1,227
Net cash provided by operating activities
$
300,717
246,005
798,746
836,600
Three months ended
Nine months ended
September 30,
September 30,
Adjusted EBITDAX margin ($ per Mcfe):
2014
2015
2014
2015
Realized price before cash receipts for settled derivatives
$
4.33
$
2.34
$
5.06
$
2.59
Gathering, compression, and water distribution revenues
0.05
0.03
0.05
0.03
Lease operating expense
(0.09)
(0.08)
(0.07)
(0.06)
Gathering, compression, processing and transportation costs
(1.29)
(1.16)
(1.26)
(1.20)
Marketing, net
(0.14)
(0.19)
(0.14)
(0.17)
Production taxes
(0.22)
(0.08)
(0.26)
(0.14)
General and administrative(1)
(0.29)
(0.25)
(0.30)
(0.25)
Gains on settled derivatives
0.58
1.49
0.23
1.44
Adjusted EBITDAX margin ($ per Mcfe):
$
2.93
$
2.10
$
3.31
$
2.24
(1) Excludes franchise taxes and equity-based stock compensation that is included in G&A
The following reconciles the financial results from the gathering and compression business and water handling business to the consolidated total statements of operations and capital expenditures in Antero Midstream's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015:
Gathering and
Water
Consolidated
Compression
Handling
Total
Three months ended September 30, 2014
Revenues:
Revenue - affiliate
$
26,282
$
42,631
$
68,913
Revenue - third-party
—
2,671
2,671
Total revenues
26,282
45,302
71,584
Operating expenses:
Direct operating
3,525
9,054
12,579
General and administrative (before equity-based compensation)
3,956
1,576
5,532
Equity-based compensation
1,562
549
2,111
Depreciation
10,227
4,390
14,617
Total
19,270
15,569
34,839
Operating income
$
7,012
$
29,733
$
36,745
Three months ended September 30, 2015
Revenues:
Revenue - affiliate
$
59,220
$
21,819
$
81,039
Revenue - third-party
38
627
665
Total revenues
59,258
22,446
81,704
Operating expenses:
Direct operating
(3,164)
4,773
1,609
General and administrative (before equity-based compensation)
7,060
1,498
8,558
Equity-based compensation
4,205
1,079
5,284
Depreciation
15,076
6,485
21,561
Total
23,177
13,835
37,012
Operating income
$
36,081
$
8,611
$
44,692
Gathering and
Water
Consolidated
Compression
Handling
Total
Nine months ended September 30, 2014
Revenues:
Revenue - affiliate
$
54,978
$
107,907
$
162,885
Revenue - third-party
—
2,671
2,671
Total revenues
54,978
110,578
165,556
Operating expenses:
Direct operating
6,661
25,871
32,532
General and administrative (before equity-based compensation)
9,710
4,085
13,795
Equity-based compensation
5,365
2,027
7,392
Depreciation
24,991
10,748
35,739
Total
46,727
42,731
89,458
Operating income
$
8,251
$
67,847
$
76,098
Nine months ended September 30, 2015
Revenues:
Revenue - affiliate
$
168,056
$
86,759
$
254,815
Revenue - third-party
38
778
816
Total revenues
168,094
87,537
255,631
Operating expenses:
Direct operating
19,817
19,013
38,830
General and administrative (before equity-based compensation)
16,467
3,793
20,260
Equity-based compensation
14,218
3,445
17,663
Depreciation
44,748
18,767
63,515
Total
95,250
45,018
140,268
Operating income
$
72,844
$
42,519
$
115,363
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, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
Cautionary Statements
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.
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, 2014.
ANTERO RESOURCES CORPORATION
Condensed Consolidated Balance Sheets
December 31, 2014 and September 30, 2015
(Unaudited)
(In thousands, except share amounts)
2014
2015
Assets
Current assets:
Cash and cash equivalents
$
245,979
27,410
Accounts receivable, net of allowance for doubtful accounts of $1,251 in 2014 and 2015
116,203
60,904
Accrued revenue
191,558
115,793
Derivative instruments
692,554
834,482
Other current assets
5,866
1,739
Total current assets
1,252,160
1,040,328
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties
2,060,936
2,072,475
Proved properties
6,515,221
7,805,203
Water handling systems
421,012
517,513
Gathering systems and facilities
1,197,239
1,448,404
Other property and equipment
37,687
45,494
10,232,095
11,889,089
Less accumulated depletion, depreciation, and amortization
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion
321,915
549,240
Impairment of unproved properties
7,895
43,670
Derivative fair value (gains) losses
63,720
(1,836,398)
Gains on settled derivatives
57,333
586,639
Deferred income tax expense
75,919
498,709
Equity-based compensation expense
85,896
79,280
Loss on early extinguishment of debt
20,386
—
Gain on sale of discontinued operations
(3,564)
—
Deferred income tax expense—discontinued operations
1,354
—
Other
4,874
12,129
Changes in current assets and liabilities:
Accounts receivable
(36,145)
15,299
Accrued revenue
(47,189)
75,765
Other current assets
975
4,127
Accounts payable
530
(1,302)
Accrued liabilities
105,278
29,537
Revenue distributions payable
72,857
(20,839)
Other current liabilities
(153)
(3,678)
Net cash provided by operating activities
798,746
836,600
Cash flows used in investing activities:
Additions to unproved properties
(518,247)
(170,291)
Drilling and completion costs
(1,723,657)
(1,350,498)
Additions to water handling systems
(156,467)
(79,227)
Additions to gathering systems and facilities
(406,666)
(282,813)
Additions to other property and equipment
(12,539)
(5,225)
Change in other assets
(6,896)
11,190
Proceeds from asset sales
—
40,000
Net cash used in investing activities
(2,824,472)
(1,836,864)
Cash flows from financing activities:
Issuance of common stock
—
537,832
Issuance of common units in Antero Midstream Partners LP
—
240,972
Issuance of senior notes
1,102,500
750,000
Repayment of senior notes
(260,000)
—
Borrowings (repayments) on bank credit facility, net
1,217,000
(705,000)
Make-whole premium on debt extinguished
(17,383)
—
Payments of deferred financing costs
(27,570)
(17,190)
Distributions to noncontrolling interest in consolidated subsidiary
—
(21,358)
Other
—
(3,561)
Net cash provided by financing activities
2,014,547
781,695
Net decrease in cash and cash equivalents
(11,179)
(218,569)
Cash and cash equivalents, beginning of period
17,487
245,979
Cash and cash equivalents, end of period
$
6,308
$
27,410
Supplemental disclosure of cash flow information:
Cash paid during the period for interest
$
67,299
$
116,579
Supplemental disclosure of noncash investing activities:
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment
$
227,368
$
(193,288)
The following tables set forth selected operating data for the three months ended September 30, 2014 compared to the three months ended September 30, 2015:
Three Months Ended September 30,
Amount of Increase
Percent
(in thousands)
2014
2015
(Decrease)
Change
Operating revenues:
Natural gas sales
$
310,390
$
253,975
$
(56,415)
(18)
%
NGLs sales
91,111
50,092
(41,019)
(45)
%
Oil sales
29,304
20,138
(9,166)
(31)
%
Gathering, compression, and water distribution
4,875
4,426
(449)
(9)
%
Marketing
17,835
35,633
17,798
100
%
Commodity derivative fair value gains
308,975
1,079,071
770,096
249
%
Total operating revenues
762,490
1,443,335
680,845
89
%
Operating expenses:
Lease operating
8,680
10,786
2,106
24
%
Gathering, compression, processing, and transportation
128,531
160,302
31,771
25
%
Production and ad valorem taxes
21,726
10,721
(11,005)
(51)
%
Marketing
32,192
61,799
29,607
92
%
Exploration
7,476
1,087
(6,389)
(85)
%
Impairment of unproved properties
4,542
8,754
4,212
93
%
Depletion, depreciation, and amortization
124,624
188,667
64,043
51
%
Accretion of asset retirement obligations
320
419
99
31
%
General and administrative (before equity-based compensation)
28,715
35,770
7,055
25
%
Equity-based compensation
24,285
23,915
(370)
(2)
%
Total operating expenses
381,091
502,220
121,129
32
%
Operating income
381,399
941,115
559,716
147
%
Other Expenses:
Interest expense
(42,455)
(60,921)
(18,466)
43
%
Income before income taxes
338,944
880,194
541,250
160
%
Income tax expense
(135,035)
(335,460)
(200,425)
148
%
Net income and comprehensive income including noncontrolling interest
203,909
544,734
340,825
167
%
Net income and comprehensive income attributable to noncontrolling interest
Average prices before effects of derivative settlements:
Natural gas (per Mcf)
$
3.63
$
2.32
$
(1.31)
(36)
%
NGLs (per Bbl)
$
46.66
$
12.08
$
(34.58)
(74)
%
Oil (per Bbl)
$
84.17
$
30.49
$
(53.68)
(64)
%
Combined (per Mcfe)
$
4.33
$
2.34
$
(1.99)
(46)
%
Average realized prices after effects of derivative settlements:
Natural gas (per Mcf)
$
4.31
$
3.99
$
(0.32)
(7)
%
NGLs (per Bbl)
$
46.66
$
16.47
$
(30.19)
(65)
%
Oil (per Bbl)
$
82.47
$
38.18
$
(44.29)
(54)
%
Combined (per Mcfe)
$
4.91
$
3.83
$
(1.08)
(22)
%
Average Costs (per Mcfe):
Lease operating
$
0.09
$
0.08
$
(0.01)
(11)
%
Gathering, compression, processing, and transportation
$
1.29
$
1.16
$
(0.13)
(10)
%
Production and ad valorem taxes
$
0.22
$
0.08
$
(0.14)
(64)
%
Marketing, net
$
0.14
$
0.19
$
0.05
36
%
Depletion, depreciation, amortization, and accretion
$
1.26
$
1.37
$
0.11
9
%
General and administrative (before equity-based compensation)
$
0.29
$
0.26
$
(0.03)
(10)
%
The following tables set forth selected operating data for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2015:
Nine Months Ended September 30,
Amount of Increase
Percent
(in thousands)
2014
2015
(Decrease)
Change
Operating revenues:
Natural gas sales
$
936,877
$
810,982
$
(125,895)
(13)
%
NGLs sales
244,807
188,403
(56,404)
(23)
%
Oil sales
89,059
55,627
(33,432)
(38)
%
Gathering, compression, and water handling
11,964
15,084
3,120
26
%
Marketing
23,048
143,242
120,194
521
%
Commodity derivative fair value gains (losses)
(63,720)
1,836,398
1,900,118
*
Total operating revenues
1,242,035
3,049,736
1,807,701
146
%
Operating expenses:
Lease operating
18,570
25,561
6,991
38
%
Gathering, compression, processing, and transportation
315,878
490,633
174,755
55
%
Production and ad valorem taxes
64,123
57,458
(6,665)
(10)
%
Marketing
58,119
214,201
156,082
269
%
Exploration
21,176
3,086
(18,090)
(85)
%
Impairment of unproved properties
7,895
43,670
35,775
453
%
Depletion, depreciation, and amortization
320,984
548,013
227,029
71
%
Accretion of asset retirement obligations
931
1,227
296
32
%
General and administrative (before equity-based compensation)
76,446
98,645
22,199
29
%
Equity-based compensation
85,896
79,280
(6,616)
(8)
%
Contract termination and rig stacking
—
10,902
10,902
*
Total operating expenses
970,018
1,572,676
602,658
62
%
Operating income
272,017
1,477,060
1,205,043
443
%
Other Expenses:
Interest expense
(111,057)
(173,929)
(62,872)
57
%
Loss on early extinguishment of debt
(20,386)
—
20,386
*
Total other expenses
(131,443)
(173,929)
(42,486)
32
%
Income from continuing operations before income taxes and discontinued operations
140,574
1,303,131
1,162,557
827
%
Income tax expense
(75,919)
(498,709)
(422,790)
557
%
Income from continuing operations
64,655
804,422
739,767
1,144
%
Income from discontinued operations
2,210
—
(2,210)
*
Net income and comprehensive income including noncontrolling interest
66,865
804,422
737,557
1,103
%
Net income and comprehensive income attributable to noncontrolling interest
Average prices before effects of derivative settlements:
Natural gas (per Mcf)
$
4.31
$
2.45
$
(1.86)
(43)
%
NGLs (per Bbl)
$
53.20
$
17.06
$
(36.14)
(68)
%
Oil (per Bbl)
$
88.15
$
35.91
$
(52.24)
(59)
%
Combined (per Mcfe)
$
5.06
$
2.59
$
(2.47)
(49)
%
Average realized prices after effects of derivative settlements:
Natural gas (per Mcf)
$
4.58
$
4.07
$
(0.51)
(11)
%
NGLs (per Bbl)
$
53.20
$
20.34
$
(32.86)
(62)
%
Oil (per Bbl)
$
86.57
$
42.90
$
(43.67)
(50)
%
Combined (per Mcfe)
$
5.29
$
4.03
$
(1.26)
(24)
%
Average Costs (per Mcfe):
Lease operating
$
0.07
$
0.06
$
(0.01)
(14)
%
Gathering, compression, processing, and transportation
$
1.26
$
1.20
$
(0.06)
(5)
%
Production and ad valorem taxes
$
0.26
$
0.14
$
(0.12)
(46)
%
Marketing, net
$
0.14
$
0.17
$
0.03
21
%
Depletion, depreciation, amortization, and accretion
$
1.28
$
1.35
$
0.07
5
%
General and administrative (before equity-based compensation)
$
0.30
$
0.24
$
(0.06)
(20)
%
*
Not meaningful or applicable
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