DENVER, Feb. 14, 2024 /PRNewswire/ — Antero Resources Corporation (NYSE: AR) (“Antero Resources,” “Antero,” or the “Company”) today announced its fourth quarter 2023 financial and operating results, year end 2023 estimated proved reserves and 2024 guidance. The relevant consolidated financial statements are included in Antero Resources’ Annual Report on Form 10-K for the year ended December 31, 2023.
Fourth Quarter 2023 Highlights:
Net production averaged 3.4 Bcfe/d, an increase of 6% from the year ago period
Realized a pre-hedge natural gas equivalent price of $3.52 per Mcfe, a $0.64 per Mcfe premium to NYMEX pricing
Net income was $95 million, Adjusted Net Income was $71 million (Non-GAAP)
Adjusted EBITDAX was $322 million (Non-GAAP); net cash provided by operating activities was $312 million
Free Cash Flow was $90 million (Non-GAAP), before Changes in Working Capital
Lateral lengths drilled averaged a quarterly Company record of more than 17,000 feet per well
Full Year 2023 Highlights:
Net Production averaged 3.4 Bcfe/d, an increase of 6% from the prior year
Liquids production averaged 193 MBbl/d, an increase of 14% from the prior year
Natural gas production averaged 2.2 Bcf/d, up 2% from the prior year
Completion stages per day averaged 11 stages per day, a 39% increase from the prior year
Estimated proved reserves increased to 18.1 Tcfe at year end 2023 and proved developed reserves were 13.8 Tcfe (76% proved developed), a 2% increase from the prior year
Estimated future development cost for 4.3 Tcfe of proved undeveloped reserves is $0.42 per Mcfe
2024 Guidance Highlights:
Net production is expected to average 3.3 to 3.4 Bcfe/d, including 192 to 204 MBbl/d of liquids
Natural gas production is expected to decline 3% from the prior year
Liquids production is expected to increase 2% from the prior year
Drilling and Completion capital budget is $650 to $700 million, a decrease of 26% from 2023
Land capital budget is $75 to $100 million, a decrease of 41% from 2023
Currently operating two drilling rigs and one completion crew
Released one drilling rig in December 2023
Released one completion crew in February 2024
Completed lateral lengths are expected to average 15,500 feet, or 2,000 feet longer than in 2023
Paul Rady, Chairman, CEO and President of Antero Resources commented, “2023 was highlighted by significant capital efficiency improvements throughout the year. Our drilling and completions teams maintained a remarkable pace, setting numerous Company records in 2023. This impressive performance led to faster cycle times across our development program and allowed us to release one drilling rig at the end of 2023 and release one completion crew earlier this month. In addition, as we enter year four of targeted maintenance capital, our corporate decline rate is substantially lower. A reduced decline rate and faster cycle times directly leads to a significant reduction in our maintenance capital in 2024.”
Mr. Rady continued, “2024 is expected to be a transformational year for our sector as we enter the second wave of LNG export facility buildouts. By the end of 2025, total exports, including LNG and Mexico pipeline flows, are expected to increase by nearly 8 Bcf/d, far outpacing supply growth during that time. Antero is uniquely positioned to benefit from this demand surge through our extensive firm transportation portfolio, which delivers 100% of our natural gas out of basin, including 75% that is delivered to the LNG Fairway. With more than 20 years of premium core locations remaining, we are ready, willing and able to supply this substantial natural gas demand growth.”
Michael Kennedy, CFO of Antero Resources said, “Due to our capital efficiency gains and a lower base decline rate, our total maintenance capital budget is down nearly 30% in 2024 compared to the prior year. Our significant leverage to NGL prices, which today are up over 15%, or $5 per barrel from the fourth quarter of 2023, also boosts our 2024 outlook. This reduced maintenance capital combined with sharply higher NGL prices is expected to generate Free Cash Flow in 2024 despite today’s challenging natural gas strip.”
For a discussion of the non-GAAP financial measures including Adjusted Net Income, Adjusted EBITDAX, Free Cash Flow and Net Debt please see “Non-GAAP Financial Measures.”
2024 Guidance
Antero’s 2024 drilling and completion capital budget is $650 to $700 million. Net production is expected to average between 3.3 and 3.4 Bcfe/d during 2024. Efficiency gains, a lower base decline rate and an average lateral length increase of 2,000 feet per well allows for a maintenance capital program with 26% lower capital than the prior year.
Land capital guidance is $75 million to $100 million, down 41% from the prior year. Antero continues to focus on its organic leasing program that extends the Company’s premium drilling locations in the Marcellus liquids-rich fairway. Within the 2024 land budget, approximately $50 million is required for maintenance capital purposes, with the remaining capital targeted for incremental drilling locations and for mineral acquisitions to increase its net revenue interest in future drilling locations. The Company believes this organic leasing program is the most cost efficient approach to lengthening its core inventory position.
The following is a summary of Antero Resources’ 2024 capital budget.
|
Capital Budget ($ in Millions) |
Low |
High |
|||||
|
Drilling & Completion |
$650 |
$700 |
|||||
|
Land |
$75 |
$100 |
|||||
|
Total E&P Capital |
$725 |
$800 |
|||||
|
# of Wells |
Net Wells |
Average Lateral |
|||||
|
Drilled Wells |
40 to 45 |
14,700 |
|||||
|
Completed Wells |
45 to 50 |
15,500 |
|
Note: Number of drilled gross wells total 50 to 55 and completed gross wells total 55 to 60. |
The following is a summary of Antero Resources’ 2024 production, pricing and cash expense guidance:
|
Production Guidance |
Low |
High |
|||||||||
|
Net Daily Natural Gas Equivalent Production (Bcfe/d) |
3.3 |
3.4 |
|||||||||
|
Net Daily Natural Gas Production (Bcf/d) |
2.16 |
2.17 |
|||||||||
|
Total Net Daily Liquids Production (MBbl/d): |
192 |
204 |
|||||||||
|
Net Daily C3+ NGL Production (MBbl/d) |
112 |
117 |
|||||||||
|
Net Daily Ethane Production (MBbl/d) |
70 |
75 |
|||||||||
|
Net Daily Oil Production (MBbl/d) |
10 |
12 |
|||||||||
|
Realized Pricing Guidance (Before Hedges) |
Low |
High |
|||||||||
|
Natural Gas Realized Price Premium vs. NYMEX Henry Hub ($/Mcf) |
$0.00 |
$0.10 |
|||||||||
|
C3+ NGL Realized Price Differential vs. Mont Belvieu ($/Bbl) |
($1.00) |
$1.00 |
|||||||||
|
Ethane Realized Price Differential vs. Mont Belvieu ($/Bbl) |
($1.00) |
$1.00 |
|||||||||
|
Oil Realized Price Differential vs. WTI Oil ($/Bbl) |
($10.00) |
($14.00) |
|||||||||
|
Cash Expense Guidance |
Low |
High |
|||||||||
|
Cash Production Expense ($/Mcfe)(1) |
$2.45 |
$2.55 |
|||||||||
|
Marketing Expense, Net of Marketing Revenue ($/Mcfe) |
$0.04 |
$0.06 |
|||||||||
|
G&A Expense ($/Mcfe)(2) |
$0.12 |
$0.14 |
|||||||||
|
(1) |
Includes lease operating expenses and gathering, compression, processing and transportation expenses (“GP&T”) and production and ad valorem taxes. |
|
(2) |
Excludes equity-based compensation. |
Free Cash Flow
During the fourth quarter of 2023, Free Cash Flow before Changes in Working Capital was $90 million.
|
Three Months Ended |
|||||||
|
December 31, |
|||||||
|
2022 |
2023 |
||||||
|
Net cash provided by operating activities |
$ |
475,285 |
312,175 |
||||
|
Less: Net cash used in investing activities |
(225,249) |
(226,630) |
|||||
|
Less: Proceeds from sale of assets, net |
(1,600) |
— |
|||||
|
Less: Distributions to non-controlling interests in Martica |
(60,022) |
(24,578) |
|||||
|
Free Cash Flow |
$ |
188,414 |
60,967 |
||||
|
Changes in Working Capital (1) |
83,156 |
29,203 |
|||||
|
Free Cash Flow before Changes in Working Capital |
$ |
271,570 |
90,170 |
||||
|
(1) |
Working capital adjustments for the three months ended December 31, 2022 include $97.6 million in net decreases in current assets and liabilities and $14.4 million in increases in accounts payable and accrued liabilities for additions to property and equipment. Working capital adjustments for the three months ended December 31, 2023 include $9.3 million in net increases in current assets and liabilities and $38.5 million in decreases in accounts payable and accrued liabilities for additions to property and equipment. See the cash flow statement in this release for details. |
Fourth Quarter 2023 Financial Results
Net daily natural gas equivalent production in the fourth quarter averaged 3.4 Bcfe/d, including 190 MBbl/d of liquids.
Antero’s average realized natural gas price before hedging was $2.72 per Mcf, a $0.16 per Mcf discount to the average first-of-month (“FOM”) NYMEX Henry Hub price. The wider discount to NYMEX was due to higher volumes being sold into the Columbia Gas Appalachia Hub as a result of pipeline maintenance on the Tennessee 500 Leg Pipeline. During the quarter, Antero sold approximately 15% of its volume into the Columbia Gas Appalachia Hub, 5% above levels prior to this pipeline maintenance.
The following table details average net production and average realized prices for the three months ended December 31, 2023:
|
Three Months Ended December 31, 2023 |
||||||||||||||||
|
Natural |
||||||||||||||||
|
Natural |
Oil |
C3+ NGLs |
Ethane |
Gas |
||||||||||||
|
(MMcf/d) |
(Bbl/d) |
(Bbl/d) |
(Bbl/d) |
(MMcfe/d) |
||||||||||||
|
Average Net Production |
2,280 |
12,543 |
118,674 |
58,761 |
3,420 |
|||||||||||
|
Three Months Ended December 31, 2023 |
||||||||||||||||
|
Natural |
||||||||||||||||
|
Natural |
Oil |
(C3+ NGLs |
Ethane |
Gas |
||||||||||||
|
Average Realized Prices |
($/Mcf) |
($/Bbl) |
($/Bbl) |
($/Bbl) |
($/Mcfe) |
|||||||||||
|
Average realized prices before settled derivatives |
$ |
2.72 |
64.77 |
37.72 |
9.13 |
3.52 |
||||||||||
|
NYMEX average price (1) |
$ |
2.88 |
78.32 |
2.88 |
||||||||||||
|
Premium / (Discount) to NYMEX |
$ |
(0.16) |
(13.55) |
0.64 |
||||||||||||
|
Settled commodity derivatives (2) |
$ |
(0.04) |
(0.19) |
(0.04) |
— |
(0.03) |
||||||||||
|
Average realized prices after settled derivatives |
$ |
2.68 |
64.58 |
37.68 |
9.13 |
3.49 |
||||||||||
|
Premium / (Discount) to NYMEX |
$ |
(0.20) |
(13.74) |
0.61 |
||||||||||||
|
(1) |
The average index prices for natural gas and oil represent the New York Mercantile Exchange average first-of-month price and the Energy Information Administration (EIA) calendar month average West Texas Intermediate future price, respectively. |
|
(2) |
These commodity derivative instruments include contracts attributable to Martica Holdings LLC (“Martica”), Antero’s consolidated variable interest entity. All gains or losses from Martica’s derivative instruments are fully attributable to the noncontrolling interests in Martica, which includes portions of the natural gas and all oil and C3+ NGL derivative instruments during the three months ended December 31, 2023. |
Antero’s average realized C3+ NGL price was $37.72 per barrel. Antero shipped 35% of its total C3+ NGL net production on Mariner East 2 (“ME2”) for export and realized a $0.08 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA. Antero sold the remaining 65% of C3+ NGL net production at a $0.01 per gallon discount to Mont Belvieu pricing at Hopedale, OH. The resulting blended price on 119 MBbl/d of net C3+ NGL production was a $0.02 per gallon premium to Mont Belvieu pricing.
|
Three Months Ended December 31, 2023 |
||||||||
|
Pricing Point |
Net C3+ NGL Production |
% by |
Premium (Discount) To Mont Belvieu |
|||||
|
Propane / Butane on ME2 – Exported |
Marcus Hook, PA |
41,382 |
35 % |
$0.08 |
||||
|
Remaining C3+ NGL Volume – Sold Domestically |
Hopedale, OH |
77,292 |
65 % |
($0.01) |
||||
|
Total C3+ NGLs / Blended Premium |
118,674 |
100 % |
$0.02 |
|||||
All-in cash expense, which includes lease operating, gathering, compression, processing and transportation, production and ad valorem taxes was $2.32 per Mcfe in the fourth quarter, a 6% decrease compared to $2.47 per Mcfe average during the fourth quarter of 2022. The decrease was due to lower production tax and transportation expense due to lower fuel costs as a result of lower commodity prices. Net marketing expense was $0.05 per Mcfe in the fourth quarter, a decrease from $0.12 per Mcfe during the fourth quarter of 2022. The decrease in net marketing expense was due to an increase in production and a decrease in firm transportation commitments compared to the year ago period.
Fourth Quarter 2023 Operating Results
Antero placed 14 Marcellus wells and 7 Utica wells to sales during the fourth quarter with an average lateral length of 15,500 feet.
Marcellus highlights include:
Marcellus wells placed to sales during the fourth quarter that have been on line for at least 60 days had an average lateral length of 16,000 feet. The average 60-day rate per well was 28 MMcfe/d with approximately 1,580 Bbl/d of liquids per well assuming 25% ethane recovery.
The remaining wells were completed in late December and had an average lateral length of approximately 17,500 feet.
Utica highlights include:
The Utica wells placed to sales during the fourth quarter that have been on line for at least 60 days had an average lateral length of 14,600 feet. The average 60-day rate per well was 25 MMcfe/d with approximately 1,340 Bbl/d of liquids per well assuming no ethane recovery.
Set two Company single day records averaging 15 completion stages in a day at two separate pads during the quarter
Fourth Quarter 2023 Capital Investment
Antero’s drilling and completion capital expenditures for the three months ended December 31, 2023, were $164 million.
In addition to capital invested in drilling and completion activities, the Company invested $14 million in land during the fourth quarter. During the quarter, Antero added approximately 5,000 net acres, representing 19 incremental drilling locations. In 2023, Antero added approximately 31,000 net acres representing 111 incremental drilling locations at an average cost of under $1 million per location.
Year End Proved Reserves
At December 31, 2023, Antero’s estimated proved reserves were 18.1 Tcfe, an increase of 2% from the prior year. Estimated proved reserves were comprised of 59% natural gas, 40% NGLs and 1% oil.
Estimated proved developed reserves were 13.8 Tcfe, a 3% increase over the prior year. The percentage of estimated proved reserves classified as proved developed increased to 76% at year end 2023. At year end 2023, Antero’s five year development plan included 248 PUD locations. Antero’s proved undeveloped locations have an average estimated BTU of 1269, with an average lateral length just under 14,000 feet.
Antero’s 4.3 Tcfe of estimated proved undeveloped reserves will require an estimated $1.84 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.42 per Mcfe.
The following table presents a summary of changes in estimated proved reserves (in Tcfe).
|
Proved reserves, December 31, 2022 (1) |
17.8 |
||
|
Extensions, discoveries and other additions |
0.4 |
||
|
Revisions of previous estimates |
0.8 |
||
|
Revisions to five-year development plan |
0.4 |
||
|
Price revisions |
(0.1) |
||
|
Production |
(1.2) |
||
|
Proved reserves, December 31, 2023 (1) |
18.1 |
|
(1) |
Proved reserves are reported consolidated with Martica Holdings, LLC. Martica Holdings, LLC had 92 Bcfe and 75 Bcfe of proved reserves as of December 31, 2022 and 2023, respectively. |
Commodity Derivative Positions
Antero did not enter into any new natural gas, NGL or oil hedges during the fourth quarter of 2023.
Please see Antero’s Annual Report on Form 10-K for the quarter ended December 31, 2023, for more information on all commodity derivative positions. For detail on current commodity positions, please see the Hedge Profile presentations at www.anteroresources.com.
Conference Call
A conference call is scheduled on Thursday, February 15, 2024 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference “Antero Resources.” A telephone replay of the call will be available until Thursday, February 22, 2024 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13743571. 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 until Thursday, February 22, 2024 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company’s website before the 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, and is not incorporated by reference into this press release.
Non-GAAP Financial Measures
Adjusted Net Income
Adjusted Net Income as set forth in this release represents net income, adjusted for certain items. Antero believes that Adjusted Net Income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted Net Income is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income as an indicator of financial performance. The GAAP measure most directly comparable to Adjusted Net Income is net income. The following table reconciles net income to Adjusted Net Income (in thousands):
|
Three Months Ended December 31, |
|||||||
|
2022 |
2023 |
||||||
|
Net income and comprehensive income attributable to Antero Resources Corporation |
$ |
730,296 |
94,764 |
||||
|
Net income and comprehensive income attributable to noncontrolling interests |
63,832 |
21,169 |
|||||
|
Unrealized commodity derivative gains |
(618,134) |
(37,272) |
|||||
|
Amortization of deferred revenue, VPP |
(9,478) |
(7,700) |
|||||
|
Gain on sale of assets |
(1,600) |
— |
|||||
|
Impairment of property and equipment |
69,982 |
6,556 |
|||||
|
Equity-based compensation |
12,221 |
14,531 |
|||||
|
Loss on early extinguishment of debt |
652 |
— |
|||||
|
Loss on convertible note inducement |
— |
288 |
|||||
|
Equity in earnings of unconsolidated affiliate |
(17,464) |
(23,966) |
|||||
|
Contract termination and loss contingency |
5,000 |
4,956 |
|||||
|
Tax effect of reconciling items (1) |
120,101 |
9,271 |
|||||
|
355,408 |
82,597 |
||||||
|
Martica adjustments (2) |
(27,063) |
(11,473) |
|||||
|
Adjusted Net Income |
$ |
328,345 |
71,124 |
||||
|
Diluted Weighted Average Shares Outstanding |
316,356 |
311,956 |
|||||
|
(1) |
Deferred taxes were approximately 21% and 22% for 2022 and 2023, respectively. |
|
(2) |
Adjustments reflect noncontrolling interest in Martica not otherwise adjusted in amounts above. |
Net Debt
Net Debt is calculated as total long-term debt less cash and cash equivalents. Management uses Net Debt to evaluate the Company’s financial position, including its ability to service its debt obligations.
The following table reconciles consolidated total long-term debt to Net Debt as used in this release (in thousands):
|
December 31, |
|||||||
|
2022 |
2023 |
||||||
|
Credit Facility |
$ |
34,800 |
417,200 |
||||
|
8.375% senior notes due 2026 |
96,870 |
96,870 |
|||||
|
7.625% senior notes due 2029 |
407,115 |
407,115 |
|||||
|
5.375% senior notes due 2030 |
600,000 |
600,000 |
|||||
|
4.250% convertible senior notes due 2026 |
56,932 |
26,386 |
|||||
|
Unamortized debt issuance costs |
(12,241) |
(9,975) |
|||||
|
Total long-term debt |
$ |
1,183,476 |
1,537,596 |
||||
|
Less: Cash and cash equivalents |
— |
— |
|||||
|
Net Debt |
$ |
1,183,476 |
1,537,596 |
||||
Free Cash Flow
Free Cash Flow is a measure of financial performance not calculated under GAAP and should not be considered in isolation or as a substitute for cash flow from operating, investing, or financing activities, as an indicator of cash flow or as a measure of liquidity. The Company defines Free Cash Flow as net cash provided by operating activities, less net cash used in investing activities, which includes drilling and completion capital and leasehold capital, plus payments for early contract termination or derivative monetization, less proceeds from asset sales or derivative monetization and less distributions to non-controlling interests in Martica.
The Company has not provided projected net cash provided by operating activities or a reconciliation of Free Cash Flow to projected net cash provided by operating activities, the most comparable financial measure calculated in accordance with GAAP. The Company is unable to project net cash provided by operating activities for any future period because this metric includes the impact of changes in operating assets and liabilities related to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. The Company is unable to project these timing differences with any reasonable degree of accuracy without unreasonable efforts.
Free Cash Flow is a useful indicator of the Company’s ability to internally fund its activities, service or incur additional debt and estimate our ability to return capital to shareholders. There are significant limitations to using Free Cash Flow as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company’s net income, the lack of comparability of results of operations of different companies and the different methods of calculating Free Cash Flow reported by different companies. Free Cash Flow does not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Adjusted EBITDAX
Adjusted EBITDAX is a non-GAAP financial measure that we define as net income (loss), adjusted for certain items detailed below.
Adjusted 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. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income or loss, 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. Adjusted EBITDAX provides no information regarding our capital structure, borrowings, interest costs, capital expenditures, 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, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:
is widely used by investors in the oil and natural gas industry to measure operating performance without regard to items excluded from the calculation of such term, which may vary substantially from company to company depending upon accounting methods and the 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 and legal structure from our operating structure;
is used by our management team for various purposes, including as a measure of our operating performance, in presentations to our Board of Directors, and as a basis for strategic planning and forecasting: and
is used by our Board of Directors as a performance measure in determining executive compensation.
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects 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 Adjusted EBITDAX reported by different companies.
The GAAP measures most directly comparable to Adjusted EBITDAX are net income (loss) and net cash provided by operating activities. The following table represents a reconciliation of Antero’s net income (loss), including noncontrolling interest, to Adjusted EBITDAX and a reconciliation of Antero’s Adjusted EBITDAX to net cash provided by operating activities per our consolidated statements of cash flows, in each case, for the three months and years ended December 31, 2022 and 2023. Adjusted EBITDAX also excludes the noncontrolling interests in Martica, and these adjustments are disclosed in the table below as Martica related adjustments.
|
Three Months Ended |
Year Ended |
||||||||||||
|
December 31, |
December 31, |
||||||||||||
|
2022 |
2023 |
2022 |
2023 |
||||||||||
|
Reconciliation of net income to Adjusted EBITDAX: |
|||||||||||||
|
Net income and comprehensive income attributable to Antero Resources Corporation |
$ |
730,296 |
94,764 |
1,898,771 |
242,919 |
||||||||
|
Net income and comprehensive income attributable to noncontrolling interests |
63,832 |
21,169 |
127,201 |
98,925 |
|||||||||
|
Unrealized commodity derivative gains |
(618,134) |
(37,272) |
(295,229) |
(394,046) |
|||||||||
|
Payments for derivative monetizations |
— |
— |
— |
202,339 |
|||||||||
|
Amortization of deferred revenue, VPP |
(9,478) |
(7,700) |
(37,603) |
(30,552) |
|||||||||
|
(Gain) loss on sale of assets |
(1,600) |
— |
471 |
(447) |
|||||||||
|
Interest expense, net |
25,120 |
32,608 |
125,372 |
117,870 |
|||||||||
|
Loss on early extinguishment of debt |
652 |
— |
46,027 |
— |
|||||||||
|
Loss on convertible note inducements |
— |
288 |
169 |
374 |
|||||||||
|
Income tax expense |
140,390 |
29,981 |
448,692 |
75,994 |
|||||||||
|
Depletion, depreciation, amortization and accretion |
169,959 |
174,992 |
685,227 |
693,210 |
|||||||||
|
Impairment of property and equipment |
69,982 |
6,556 |
149,731 |
51,302 |
|||||||||
|
Exploration expense |
628 |
603 |
3,651 |
2,691 |
|||||||||
|
Equity-based compensation expense |
12,221 |
14,531 |
35,443 |
59,519 |
|||||||||
|
Equity in earnings of unconsolidated affiliate |
(17,464) |
(23,966) |
(72,327) |
(82,952) |
|||||||||
|
Dividends from unconsolidated affiliate |
31,284 |
31,284 |
125,138 |
125,138 |
|||||||||
|
Contract termination, loss contingency, transaction expense and other |
5,031 |
4,981 |
25,288 |
55,491 |
|||||||||
|
602,719 |
342,819 |
3,266,022 |
1,217,775 |
||||||||||
|
Martica related adjustments (1) |
(38,012) |
(20,373) |
(163,081) |
(97,257) |
|||||||||
|
Adjusted EBITDAX |
$ |
564,707 |
322,446 |
3,102,941 |
1,120,518 |
||||||||
|
Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities: |
|||||||||||||
|
Adjusted EBITDAX |
$ |
564,707 |
322,446 |
3,102,941 |
1,120,518 |
||||||||
|
Martica related adjustments (1) |
38,012 |
20,373 |
163,081 |
97,257 |
|||||||||
|
Interest expense, net |
(25,120) |
(32,608) |
(125,372) |
(117,870) |
|||||||||
|
Amortization of debt issuance costs, debt discount and other |
878 |
(337) |
4,336 |
2,264 |
|||||||||
|
Exploration expense |
(628) |
(603) |
(3,651) |
(2,691) |
|||||||||
|
Changes in current assets and liabilities |
(97,558) |
9,259 |
(62,808) |
143,278 |
|||||||||
|
Contract termination, loss contingency, transaction expense and other |
(5,031) |
(4,782) |
(25,288) |
(43,391) |
|||||||||
|
Payments for derivative monetizations |
— |
— |
— |
(202,339) |
|||||||||
|
Other items |
25 |
(1,573) |
(1,897) |
(2,305) |
|||||||||
|
Net cash provided by operating activities |
$ |
475,285 |
312,175 |
3,051,342 |
994,721 |
||||||||
|
(1) |
Adjustments reflect noncontrolling interests in Martica not otherwise adjusted in amounts above. |
Drilling and Completion Capital Expenditures
For a reconciliation between cash paid for drilling and completion capital expenditures and drilling and completion accrued capital expenditures during the period, please see the capital expenditures section below (in thousands):
|
Three Months Ended December 31, |
||||||
|
2022 |
2023 |
|||||
|
Drilling and completion costs (cash basis) |
$ |
191,556 |
204,494 |
|||
|
Change in accrued capital costs |
11,058 |
(40,265) |
||||
|
Adjusted drilling and completion costs (accrual basis) |
$ |
202,614 |
164,229 |
|||
Notwithstanding their use for comparative purposes, the Company’s non-GAAP financial measures may not be comparable to similarly titled measures employed by other companies.
Antero Resources is an independent natural gas and natural gas liquids company engaged in the acquisition, development and production of unconventional properties located in the Appalachian Basin in West Virginia and Ohio. In conjunction with its affiliate, Antero Midstream (NYSE: AM), Antero is one of the most integrated natural gas producers in the U.S. 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 not under Antero Resources’ control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as those regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management, return of capital, expected results, future commodity prices, future production targets, realizing potential future fee rebates or reductions, including those related to certain levels of production, future earnings, leverage targets and debt repayment, future capital spending plans, improved and/or increasing capital efficiency, estimated realized natural gas, NGL and oil prices, impacts of geopolitical and world health events, expected drilling and development plans, projected well costs and cost savings initiatives, future financial position, the participation level of our drilling partner and the financial and production results to be achieved as a result of that drilling partnership, the other key assumptions underlying our projections, and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources 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. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil, most of which are difficult to predict and many of which are beyond the Antero Resources’ control. These risks include, but are not limited to, commodity price volatility, inflation, supply chain or other disruption, lack of availability and cost of drilling, completion and production equipment and services and cost of drilling, completion and production equipment and services, environmental risks, drilling and completion and other operating risks, marketing and transportation risks, regulatory changes or changes in law, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, conflicts of interest among our stockholders, impacts of geopolitical and world health events, cybersecurity risks, our ability to achieve our greenhouse gas reduction targets and the costs associated therewith, the state of markets for, and availability of, verified quality carbon offsets and the other risks described under the heading “Item 1A. Risk Factors” in Antero Resources’ Annual Report on Form 10-K for the year ended December 31, 2023.
|
ANTERO RESOURCES CORPORATION Consolidated Balance Sheets (In thousands, except per share amounts) |
|||||||
|
December 31, |
|||||||
|
2022 |
2023 |
||||||
|
Assets |
|||||||
|
Current assets: |
|||||||
|
Accounts receivable |
$ |
35,488 |
42,619 |
||||
|
Accrued revenue |
707,685 |
400,805 |
|||||
|
Derivative instruments |
1,900 |
5,175 |
|||||
|
Prepaid expenses |
10,580 |
12,901 |
|||||
|
Other current assets |
31,872 |
14,192 |
|||||
|
Total current assets |
787,525 |
475,692 |
|||||
|
Property and equipment: |
|||||||
|
Oil and gas properties, at cost (successful efforts method): |
|||||||
|
Unproved properties |
997,715 |
974,642 |
|||||
|
Proved properties |
13,234,777 |
13,908,804 |
|||||
|
Gathering systems and facilities |
5,802 |
5,802 |
|||||
|
Other property and equipment |
83,909 |
98,668 |
|||||
|
14,322,203 |
14,987,916 |
||||||
|
Less accumulated depletion, depreciation and amortization |
(4,683,399) |
(5,063,274) |
|||||
|
Property and equipment, net |
9,638,804 |
9,924,642 |
|||||
|
Operating leases right-of-use assets |
3,444,331 |
2,965,880 |
|||||
|
Derivative instruments |
9,844 |
5,570 |
|||||
|
Investment in unconsolidated affiliate |
220,429 |
222,255 |
|||||
|
Other assets |
17,106 |
25,375 |
|||||
|
Total assets |
$ |
14,118,039 |
13,619,414 |
||||
|
Liabilities and Equity |
|||||||
|
Current liabilities: |
|||||||
|
Accounts payable |
$ |
77,543 |
38,993 |
||||
|
Accounts payable, related parties |
80,708 |
86,284 |
|||||
|
Accrued liabilities |
461,788 |
381,340 |
|||||
|
Revenue distributions payable |
468,210 |
361,782 |
|||||
|
Derivative instruments |
97,765 |
15,236 |
|||||
|
Short-term lease liabilities |
556,636 |
540,060 |
|||||
|
Deferred revenue, VPP |
30,552 |
27,101 |
|||||
|
Other current liabilities |
1,707 |
1,295 |
|||||
|
Total current liabilities |
1,774,909 |
1,452,091 |
|||||
|
Long-term liabilities: |
|||||||
|
Long-term debt |
1,183,476 |
1,537,596 |
|||||
|
Deferred income tax liability, net |
759,861 |
834,268 |
|||||
|
Derivative instruments |
345,280 |
32,764 |
|||||
|
Long-term lease liabilities |
2,889,854 |
2,428,450 |
|||||
|
Deferred revenue, VPP |
87,813 |
60,712 |
|||||
|
Other liabilities |
59,692 |
59,431 |
|||||
|
Total liabilities |
7,100,885 |
6,405,312 |
|||||
|
Commitments and contingencies |
|||||||
|
Equity: |
|||||||
|
Stockholders’ equity: |
|||||||
|
Preferred stock, $0.01 par value; authorized – 50,000 shares; none issued |
— |
— |
|||||
|
Common stock, $0.01 par value; authorized – 1,000,000 shares; 297,393 shares issued and 297,359 shares |
2,974 |
3,035 |
|||||
|
Additional paid-in capital |
5,838,848 |
5,846,541 |
|||||
|
Retained earnings |
913,896 |
1,131,828 |
|||||
|
Treasury stock, at cost; 34 shares and zero shares as of December 31, 2022 and 2023, respectively |
(1,160) |
— |
|||||
|
Total stockholders’ equity |
6,754,558 |
6,981,404 |
|||||
|
Noncontrolling interests |
262,596 |
232,698 |
|||||
|
Total equity |
7,017,154 |
7,214,102 |
|||||
|
Total liabilities and equity |
$ |
14,118,039 |
13,619,414 |
||||
|
ANTERO RESOURCES CORPORATION Consolidated Statements of Operations and Comprehensive Income (In thousands, except per share amounts) |
||||||||||||
|
(Unaudited) |
||||||||||||
|
Three Months Ended December 31, |
Year Ended December 31, |
|||||||||||
|
2022 |
2023 |
2022 |
2023 |
|||||||||
|
Revenue and other: |
||||||||||||
|
Natural gas sales |
$ |
1,229,594 |
570,690 |
5,520,419 |
2,192,349 |
|||||||
|
Natural gas liquids sales |
515,148 |
461,212 |
2,498,657 |
1,836,950 |
||||||||
|
Oil sales |
56,169 |
74,744 |
275,673 |
247,146 |
||||||||
|
Commodity derivative fair value gains (losses) |
191,729 |
28,400 |
(1,615,836) |
166,324 |
||||||||
|
Marketing |
81,585 |
50,732 |
416,758 |
206,122 |
||||||||
|
Amortization of deferred revenue, VPP |
9,478 |
7,700 |
37,603 |
30,552 |
||||||||
|
Other revenue and income |
1,584 |
665 |
5,162 |
2,529 |
||||||||
|
Total revenue |
2,085,287 |
1,194,143 |
7,138,436 |
4,681,972 |
||||||||
|
Operating expenses: |
||||||||||||
|
Lease operating |
29,109 |
26,888 |
99,595 |
118,441 |
||||||||
|
Gathering, compression, processing and transportation |
642,502 |
661,325 |
2,605,380 |
2,642,358 |
||||||||
|
Production and ad valorem taxes |
59,758 |
41,163 |
287,406 |
158,855 |
||||||||
|
Marketing |
115,733 |
67,887 |
531,304 |
284,965 |
||||||||
|
Exploration and mine expenses |
2,142 |
603 |
7,409 |
2,700 |
||||||||
|
General and administrative (including equity-based compensation expense) |
49,876 |
54,929 |
172,909 |
224,516 |
||||||||
|
Depletion, depreciation and amortization |
169,210 |
174,719 |
680,600 |
689,966 |
||||||||
|
Impairment of property and equipment |
69,982 |
6,556 |
149,731 |
51,302 |
||||||||
|
Accretion of asset retirement obligations |
749 |
273 |
4,627 |
3,244 |
||||||||
|
Contract termination and loss contingency |
5,000 |
4,956 |
25,099 |
52,606 |
||||||||
|
Gain (loss) on sale of assets |
(1,600) |
— |
471 |
(447) |
||||||||
|
Other operating expense |
— |
— |
— |
336 |
||||||||
|
Total operating expenses |
1,142,461 |
1,039,299 |
4,564,531 |
4,228,842 |
||||||||
|
Operating income |
942,826 |
154,844 |
2,573,905 |
453,130 |
||||||||
|
Other income (expense): |
||||||||||||
|
Interest expense, net |
(25,120) |
(32,608) |
(125,372) |
(117,870) |
||||||||
|
Equity in earnings of unconsolidated affiliate |
17,464 |
23,966 |
72,327 |
82,952 |
||||||||
|
Loss on early extinguishment of debt |
(652) |
— |
(46,027) |
— |
||||||||
|
Loss on convertible note inducements |
— |
(288) |
(169) |
(374) |
||||||||
|
Total other expense |
(8,308) |
(8,930) |
(99,241) |
(35,292) |
||||||||
|
Income before income taxes |
934,518 |
145,914 |
2,474,664 |
417,838 |
||||||||
|
Income tax expense |
(140,390) |
(29,981) |
(448,692) |
(75,994) |
||||||||
|
Net income and comprehensive income including noncontrolling interests |
794,128 |
115,933 |
2,025,972 |
341,844 |
||||||||
|
Less: net income and comprehensive income attributable to noncontrolling interests |
63,832 |
21,169 |
127,201 |
98,925 |
||||||||
|
Net income and comprehensive income attributable to Antero Resources Corporation |
$ |
730,296 |
94,764 |
1,898,771 |
242,919 |
|||||||
|
Net income per common share—basic |
$ |
2.44 |
0.31 |
6.18 |
0.81 |
|||||||
|
Net income per common share—diluted |
$ |
2.31 |
0.30 |
5.78 |
0.78 |
|||||||
|
Weighted average number of common shares outstanding: |
||||||||||||
|
Basic |
299,035 |
301,825 |
307,202 |
299,793 |
||||||||
|
Diluted |
316,356 |
311,956 |
329,223 |
311,597 |
||||||||
|
ANTERO RESOURCES CORPORATION Consolidated Statements of Cash Flows (In thousands) |
||||||||||
|
Year Ended December 31, |
||||||||||
|
2021 |
2022 |
2023 |
||||||||
|
Cash flows provided by (used in) operating activities: |
||||||||||
|
Net income (loss) including noncontrolling interests |
$ |
(154,109) |
2,025,972 |
341,844 |
||||||
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||
|
Depletion, depreciation, amortization and accretion |
745,829 |
685,227 |
693,210 |
|||||||
|
Impairments |
90,523 |
149,731 |
51,302 |
|||||||
|
Commodity derivative fair value losses (gains) |
1,936,509 |
1,615,836 |
(166,324) |
|||||||
|
Losses on settled commodity derivatives |
(1,183,400) |
(1,911,065) |
(25,383) |
|||||||
|
Payments for derivative monetizations |
(4,569) |
— |
(202,339) |
|||||||
|
Deferred income tax expense (benefit) |
(74,293) |
447,845 |
74,407 |
|||||||
|
Equity-based compensation expense |
20,437 |
35,443 |
59,519 |
|||||||
|
Equity in earnings of unconsolidated affiliate |
(77,085) |
(72,327) |
(82,952) |
|||||||
|
Dividends of earnings from unconsolidated affiliate |
136,609 |
125,138 |
125,138 |
|||||||
|
Amortization of deferred revenue |
(45,236) |
(37,603) |
(30,552) |
|||||||
|
Amortization of debt issuance costs, debt discount and other |
12,492 |
4,336 |
2,264 |
|||||||
|
Settlement of asset retirement obligations |
— |
(1,050) |
(718) |
|||||||
|
Contract termination and loss contingency |
— |
— |
12,100 |
|||||||
|
Loss (gain) on sale of assets |
(2,232) |
471 |
(447) |
|||||||
|
Loss on early extinguishment of debt |
93,191 |
46,027 |
— |
|||||||
|
Loss on convertible note inducements and equitizations |
50,777 |
169 |
374 |
|||||||
|
Changes in current assets and liabilities: |
||||||||||
|
Accounts receivable |
(55,567) |
43,510 |
7,550 |
|||||||
|
Accrued revenue |
(166,128) |
(116,243) |
306,880 |
|||||||
|
Prepaid expenses and other current assets |
316 |
(27,530) |
14,890 |
|||||||
|
Accounts payable including related parties |
(1,184) |
32,374 |
(16,837) |
|||||||
|
Accrued liabilities |
77,584 |
(5,620) |
(62,419) |
|||||||
|
Revenue distributions payable |
246,757 |
23,337 |
(106,429) |
|||||||
|
Other current liabilities |
12,895 |
(12,636) |
(357) |
|||||||
|
Net cash provided by operating activities |
1,660,116 |
3,051,342 |
994,721 |
|||||||
|
Cash flows provided by (used in) investing activities: |
||||||||||
|
Additions to unproved properties |
(79,138) |
(149,009) |
(151,135) |
|||||||
|
Drilling and completion costs |
(601,175) |
(780,649) |
(964,346) |
|||||||
|
Additions to other property and equipment |
(35,623) |
(14,313) |
(16,382) |
|||||||
|
Proceeds from asset sales |
3,192 |
2,747 |
447 |
|||||||
|
Change in other assets |
2,632 |
(2,388) |
(9,351) |
|||||||
|
Change in other liabilities |
(672) |
— |
— |
|||||||
|
Net cash used in investing activities |
(710,784) |
(943,612) |
(1,140,767) |
|||||||
|
Cash flows provided by (used in) financing activities: |
||||||||||
|
Repurchases of common stock |
— |
(873,744) |
(75,355) |
|||||||
|
Issuance of senior notes |
1,800,000 |
— |
— |
|||||||
|
Repayment of senior notes |
(1,554,657) |
(1,027,559) |
— |
|||||||
|
Borrowings on Credit Facility |
5,006,000 |
6,308,900 |
4,501,400 |
|||||||
|
Repayments on Credit Facility |
(6,023,000) |
(6,274,100) |
(4,119,000) |
|||||||
|
Payment of debt issuance costs |
(31,474) |
(814) |
(605) |
|||||||
|
Sale of noncontrolling interest |
51,000 |
— |
— |
|||||||
|
Distributions to noncontrolling interests |
(97,424) |
(173,537) |
(128,823) |
|||||||
|
Employee tax withholding for settlement of equity compensation awards |
(13,270) |
(66,132) |
(30,367) |
|||||||
|
Convertible note inducements and equitizations |
(85,648) |
(169) |
(374) |
|||||||
|
Other |
(859) |
(575) |
(830) |
|||||||
|
Net cash provided by (used in) financing activities |
(949,332) |
(2,107,730) |
146,046 |
|||||||
|
Net increase in cash and cash equivalents |
— |
— |
— |
|||||||
|
Cash and cash equivalents, beginning of period |
— |
— |
— |
|||||||
|
Cash and cash equivalents, end of period |
$ |
— |
— |
— |
||||||
|
Supplemental disclosure of cash flow information: |
||||||||||
|
Cash paid during the period for interest |
$ |
141,930 |
155,006 |
113,910 |
||||||
|
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment |
$ |
37,049 |
38,035 |
(60,762) |
||||||
The following table sets forth selected financial data for the three months ended December 31, 2022 and 2023:
|
(Unaudited) |
||||||||||||
|
Three Months Ended |
Amount of |
|||||||||||
|
December 31, |
Increase |
Percent |
||||||||||
|
2022 |
2023 |
(Decrease) |
Change |
|||||||||
|
Production data (1) (2): |
||||||||||||
|
Natural gas (Bcf) |
196 |
210 |
14 |
7 |
% |
|||||||
|
C2 Ethane (MBbl) |
5,778 |
5,406 |
(372) |
(6) |
% |
|||||||
|
C3+ NGLs (MBbl) |
10,170 |
10,918 |
748 |
7 |
% |
|||||||
|
Oil (MBbl) |
790 |
1,154 |
364 |
46 |
% |
|||||||
|
Combined (Bcfe) |
297 |
315 |
18 |
6 |
% |
|||||||
|
Daily combined production (MMcfe/d) |
3,224 |
3,420 |
196 |
6 |
% |
|||||||
|
Average prices before effects of derivative settlements (3): |
||||||||||||
|
Natural gas (per Mcf) |
$ |
6.27 |
2.72 |
(3.55) |
(57) |
% |
||||||
|
C2 Ethane (per Bbl) (4) |
$ |
18.96 |
9.13 |
(9.83) |
(52) |
% |
||||||
|
C3+ NGLs (per Bbl) |
$ |
39.88 |
37.72 |
(2.16) |
(5) |
% |
||||||
|
Oil (per Bbl) |
$ |
71.08 |
64.77 |
(6.31) |
(9) |
% |
||||||
|
Weighted Average Combined (per Mcfe) |
$ |
6.07 |
3.52 |
(2.55) |
(42) |
% |
||||||
|
Average realized prices after effects of derivative settlements (3): |
||||||||||||
|
Natural gas (per Mcf) |
$ |
4.11 |
2.68 |
(1.43) |
(35) |
% |
||||||
|
C2 Ethane (per Bbl) (4) |
$ |
18.96 |
9.13 |
(9.83) |
(52) |
% |
||||||
|
C3+ NGLs (per Bbl) |
$ |
39.68 |
37.68 |
(2.00) |
(5) |
% |
||||||
|
Oil (per Bbl) |
$ |
70.60 |
64.58 |
(6.02) |
(9) |
% |
||||||
|
Weighted Average Combined (per Mcfe) |
$ |
4.63 |
3.49 |
(1.14) |
(25) |
% |
||||||
|
Average costs (per Mcfe): |
||||||||||||
|
Lease operating |
$ |
0.10 |
0.09 |
(0.01) |
(10) |
% |
||||||
|
Gathering and compression |
$ |
0.77 |
0.69 |
(0.08) |
(10) |
% |
||||||
|
Processing |
$ |
0.74 |
0.79 |
0.05 |
7 |
% |
||||||
|
Transportation |
$ |
0.66 |
0.62 |
(0.04) |
(6) |
% |
||||||
|
Production and ad valorem taxes |
$ |
0.20 |
0.13 |
(0.07) |
(35) |
% |
||||||
|
Marketing expense, net |
$ |
0.12 |
0.05 |
(0.07) |
(58) |
% |
||||||
|
General and administrative (excluding equity-based compensation) |
$ |
0.13 |
0.13 |
— |
— |
% |
||||||
|
Depletion, depreciation, amortization and accretion |
$ |
0.57 |
0.56 |
(0.01) |
(2) |
% |
||||||
|
(1) |
Production volumes exclude volumes related to VPP transaction. |
|
(2) |
Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and may not reflect their relative economic value. |
|
(3) |
Average sales prices shown in the table reflect both the before and after effects of the Company’s settled commodity derivatives. The calculation of such after effects includes gains on settlements of commodity derivatives, which do not qualify for hedge accounting because the Company does not designate or document them as hedges for accounting purposes. Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value. |
|
(4) |
The average realized price for the three months ended December 31, 2022 and 2023 includes $10 million and $2 million, respectively, of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before the effects of derivatives for the three months ended December 31, 2022 and 2023 would have been $17.22 per Bbl and $8.78 per Bbl, respectively. |
SOURCE Antero Resources Corporation