Antero Resources Announces Fourth Quarter 2022 Results, Year End Reserves and 2023 Capital Budget and Guidance

February 15, 2023 at 4:15 PM·19 min read

DENVER, Feb. 15, 2023 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources," "Antero," or the "Company") today announced its fourth quarter 2022 financial and operating results, year end 2022 estimated proved reserves and 2023 capital budget and guidance. The relevant consolidated financial statements are included in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2022.

Antero Resources logo. (PRNewsFoto/Antero Resources Corporation)

Fourth Quarter 2022 Highlights:

Net production averaged 3.2 Bcfe/d, including 182 MBbl/d of liquids
Realized pre-hedge natural gas price of $6.27 per Mcf
Net income was $730 million, Adjusted Net Income was $328 million (Non-GAAP)
Adjusted EBITDAX was $565 million (Non-GAAP); net cash provided by operating activities was $475 million
Free Cash Flow was $272 million (Non-GAAP), before Changes in Working Capital
Purchased $199 million of shares

Full Year 2022 Highlights:

Reduced total debt by $942 million and purchased $940 million of shares
Total long-term debt at year end was $1.18 billion
Net Debt to trailing last twelve month Adjusted EBITDAX was 0.4x (Non-GAAP)
Estimated proved reserves increased to 17.8 Tcfe at year end 2022 and proved developed reserves were 13.4 Tcfe (75% proved developed), a 5% increase from the prior year
Estimated future development cost for 4.4 Tcfe of proved undeveloped reserves is $0.43 per Mcfe

2023 Capital Budget and Guidance Highlights:

Net production is expected to average 3.25 to 3.3 Bcfe/d, including 184 to 195 MBbl/d of liquids (NGLs and oil)
Drilling and Completion capital budget is $875 to $925 million
Targeting return of capital to shareholders of 50% of Free Cash Flow

Paul Rady, Chairman, CEO and President of Antero Resources commented, "2022 was a transformative year for Antero. We reduced debt by approximately $1 billion, bringing our total debt reduction since 2019 to over $2.5 billion. We also executed our return of capital program by purchasing over 25 million shares. Antero's differentiated strategy of liquids-rich development and utilization of firm transportation to sell our gas along the LNG corridor is expected to drive continued premium price realizations in the quarters ahead. As we enter 2023, this financial and operational momentum puts Antero in its strongest position in the Company's history."

Michael Kennedy, CFO of Antero Resources said, "In 2023, we plan to continue to focus on reducing debt and returning capital to our shareholders. Our aggressive focus on debt reduction will allow us to maintain low leverage throughout various commodity cycles, while still returning Free Cash Flow to our shareholders. In 2023, we anticipate a return of capital program of approximately 50% of our Free Cash Flow."

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."

2022 Debt Reduction and Return of Capital Program			Year Ended December 31, 2022
Total shares purchased (MM shares) ⁽¹⁾			25.2

Shares purchased ($MM)			$940
Absolute debt reduction ($MM)			$942
Total debt reduction and return of capital ($MM)			$1,882


⁽¹⁾	The total number of shares purchased includes 2.1 million shares of Antero common stock related to satisfying tax withholding obligations incurred upon the vesting of restricted stock units and performance share units held by our employees.

Free Cash Flow

During the fourth quarter, Antero generated $272 million of Free Cash Flow before Changes in Working Capital. Free Cash Flow after Changes in Working Capital was $188 million. In 2022, Antero generated $2.0 billion in Free Cash Flow before Changes in Working Capital and $1.9 billion in Free Cash Flow after Changes in Working Capital.

	Three Months Ended December 31,				Year Ended December 31,
	2021		2022		2021		2022
Net cash provided by operating activities	$	475,164		475,285		1,660,116		3,051,342
Less: Net cash used in investing activities		(205,329)		(225,249)		(710,784)		(943,612)
Less: Proceeds from sale of assets, net		—		(1,600)		(3,192)		(2,747)
Less: Distributions to non-controlling interests in Martica		(32,641)		(60,022)		(97,424)		(173,537)
Free Cash Flow	$	237,194		188,414		848,716		1,931,446
Changes in Working Capital ⁽¹⁾		(64,634)		83,156		(151,722)		24,773
Free Cash Flow before Changes in Working Capital	$	172,560		271,570		696,994		1,956,219

(1)

Working capital adjustments for the three months and year ended December 31, 2021 include $61.1 million and $114.7 million, respectively, in net increases in current assets and liabilities and $3.5 million and $37.0 million, respectively, in increases in accounts payable and accrued liabilities for additions to property and equipment. Working capital adjustments for the three months and year ended December 31, 2022 include $97.6 million and $62.8 million, respectively, in net decreases in current assets and liabilities and $14.4 million and $38.0 million, respectively, in increases in accounts payable and accrued liabilities for additions to property and equipment. See the cash flow statement in this release for details.

2023 Capital Budget and Guidance

Antero's 2023 drilling and completion capital budget is $875 to $925 million. The budget reflects approximately 10% year over year service cost inflation. Net production is expected to average between 3.25 and 3.3 Bcfe/d during 2023.

Land capital guidance is $150 million as Antero continues to focus on its organic leasing program that extends the Company's premium drilling locations in the Marcellus liquids-rich fairway. Antero expects approximately 50% of the 2023 land budget to be utilized in the first quarter of 2023. In 2022, Antero added approximately 80 drilling locations in the core of the Appalachia liquids area at an average cost of under $1 million per location, more than offsetting Antero's maintenance capital plan that assumes an average of 60 to 65 net wells per year. Within the 2023 land budget, approximately $50 million is required for maintenance capital purposes, and approximately $100 million is 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' 2023 capital budget.

Capital Budget ($ in Millions)	Low	High
Drilling & Completion	$875	$925
Land	$150	$150
Total E&P Capital	$1,025	$1,075

# of Wells	Net Wells	Average Lateral Length (Feet)
Drilled Wells	65 to 70	14,500
Completed Wells	60 to 65	13,500

Note: Number of completed wells including the drilling partnership total 75 to 80 gross wells.

The following is a summary of Antero Resources' 2023 production, pricing and cash expense guidance:

Production Guidance	Low	High
Net Daily Natural Gas Equivalent Production (Bcfe/d)	3.25	3.3
Net Daily Natural Gas Production (Bcf/d)	2.1	2.15
Total Net Daily Liquids Production (MBbl/d):	184	195
Net Daily C3+ NGL Production (MBbl/d)	105	110
Net Daily Ethane Production (MBbl/d)	70	75
Net Daily Oil Production (MBbl/d)	9	10

Realized Pricing Guidance (Before Hedges)	Low	High
Natural Gas Realized Price Premium vs. NYMEX Henry Hub ($/Mcf)	$0.10	$0.20
C3+ NGL Realized Price Differential vs. Mont Belvieu ($/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⁾	$2.40	$2.50
Marketing Expense, Net of Marketing Revenue ($/Mcfe)	$0.07	$0.09
G&A Expense ($/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.

Early Hedge Settlement

In the first quarter of 2023, Antero executed an early settlement of its 2024 natural gas swaptions for approximately $200 million. Antero believes that the lower natural gas strip may result in reduced industry activity providing support to natural gas prices ahead of the expected increase in LNG export demand beginning in 2024.

Firm Transportation Buyout

In the first quarter of 2023, Antero terminated a firm transportation commitment related to an unutilized pipeline to local Appalachian markets for $24 million. The termination of this contract was at a discounted value to commitments through 2025 and reduces net marketing expense by $13 million annually.

Fourth Quarter 2022 Financial Results

Net daily natural gas equivalent production in the fourth quarter averaged 3.2 Bcfe/d, including 182 MBbl/d of liquids. Weather-related downtime in December and lower recovered ethane volumes negatively impacted volumes during the quarter by approximately 60 MMcfe/d.

Antero's average realized natural gas price before hedging was $6.27 per Mcf, representing a 6% increase compared to the prior year period. Antero realized a $0.01 per Mcf premium to the average first-of-month ("FOM") NYMEX Henry Hub price. The Company's realized natural gas price was negatively impacted by scheduled maintenance at the Cove Point LNG facility during the month of October that required volumes to be sold at reduced in-basin prices. In addition, Antero typically sells approximately 75% of its natural gas at first-of-month pricing and the remaining 25% at gas daily pricing. Gas daily prices averaged approximately 10% below FOM prices during the fourth quarter, including 15% below during the month of December.

The following table details average net production and average realized prices for the three months ended December 31, 2022:

	Three Months Ended December 31, 2022
									Combined
									Natural
	Natural Gas		Oil		C3+ NGLs		Ethane		Gas Equivalent
	(MMcf/d)		(Bbl/d)		(Bbl/d)		(Bbl/d)		(MMcfe/d)
Average Net Production		2,133		8,589		110,548		62,801		3,224

									Combined
									Natural
	Natural Gas		Oil		C3+ NGLs		Ethane		Gas Equivalent
Average Realized Prices	($/Mcf)		($/Bbl)		($/Bbl)		($/Bbl)		($/Mcfe)
Average realized prices before settled derivatives	$	6.27	$	71.08	$	39.88	$	18.96	$	6.07
NYMEX average price	$	6.26	$	82.65					$	6.26
Premium / (Discount) to NYMEX	$	0.01	$	(11.57)					$	(0.19)

Settled commodity derivatives ⁽¹⁾	$	(2.16)	$	(0.48)	$	(0.20)	$	—	$	(1.44)
Average realized prices after settled derivatives	$	4.11	$	70.60	$	39.68	$	18.96	$	4.63
Premium / (Discount) to NYMEX	$	(2.15)	$	(12.05)					$	(1.63)

(1)

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, 2022.

Antero's average realized C3+ NGL price was $39.88 per barrel. Antero shipped 30% of its total C3+ NGL net production on Mariner East 2 for export and realized a $0.07 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA. Antero sold the remaining 70% of C3+ NGL net production at a $0.02 per gallon discount to Mont Belvieu pricing at Hopedale, OH. The resulting blended price on 111 MBbl/d of net C3+ NGL production was a $0.01 per gallon premium to Mont Belvieu pricing.

	Three Months Ended December 31, 2022
	Pricing Point	Net C3+ NGL Production (Bbl/d)	% by Destination	Premium (Discount) To Mont Belvieu ($/Gal)
Propane / Butane exported on ME2	Marcus Hook, PA	33,360	30 %	$0.07
Remaining C3+ NGL volume	Hopedale, OH	77,188	70 %	($0.02)
Total C3+ NGLs/Blended Premium		110,548	100 %	$0.01

All-in cash expense, which includes lease operating, gathering, compression, processing, and transportation, production and ad valorem taxes was $2.47 per Mcfe in the fourth quarter, a 1% increase compared to $2.45 per Mcfe average during the fourth quarter of 2021. The increase was due primarily to higher natural gas, fuel costs, and inflation that impacted gathering, processing and transportation costs during the quarter. Net marketing expense was $0.12 per Mcfe in the fourth quarter, an increase from $0.09 per Mcfe during the fourth quarter of 2021. The increase in net marketing expense was due to higher unutilized firm transportation costs related to the maintenance at the Cove Point LNG terminal during the month of October.

Fourth Quarter 2022 Operating Update

Antero placed 18 horizontal Marcellus wells to sales during the fourth quarter with an average lateral length of 14,200 feet. Twelve of these wells have been on line for at least 60 days and the average 60-day rate per well was 26 MMcfe/d with approximately 1,200 Bbl/d of liquids per well assuming 25% ethane recovery. The remaining 6 wells were completed in late December.

Fourth Quarter 2022 Capital Investment

Antero's accrued drilling and completion capital expenditures for the three months ended December 31, 2022, were $203 million. In addition to capital invested in drilling and completion activities, the Company invested $32 million in land during the fourth quarter.

Year End Proved Reserves

At December 31, 2022, Antero's estimated proved reserves were 17.8 Tcfe, in line with the prior year. Estimated proved reserves were comprised of 58% natural gas, 41% NGLs and 1% oil.

Estimated proved developed reserves were 13.4 Tcfe, a 5% increase over the prior year. The percentage of estimated proved reserves classified as proved developed increased to 75% at year end 2022, compared to 72% at year end 2021. At year end 2022, Antero's five year development plan included 265 PUD locations. Antero's proved undeveloped locations have an average estimated BTU of 1264, with an average lateral length just over 14,000 feet.

Antero's 4.4 Tcfe of estimated proved undeveloped reserves will require an estimated $1.9 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.43 per Mcfe.

The following table presents a summary of changes in estimated proved reserves (in Tcfe).

Proved reserves, December 31, 2021 ⁽¹⁾		17.7
Extensions, discoveries, and other additions		0.6
Revisions		0.7
Production		(1.2)
Proved reserves, December 31, 2022 ⁽¹⁾		17.8


⁽¹⁾	Proved reserves are reported consolidated with Martica Holdings, LLC. Martica Holdings, LLC had 167 Bcfe and 92 Bcfe of proved reserves as of December 31, 2021 and 2022, respectively.

Commodity Derivative Positions

Antero did not enter into any new natural gas, NGL or oil hedges during the fourth quarter of 2022.

Please see Antero's Annual Report on Form 10-K for the year ended December 31, 2022, 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 16, 2023 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 23, 2023 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 137344438. 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 23, 2023 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,
	2021		2022
Net income and comprehensive income attributable to Antero Resources Corporation	$	901,385		730,296
Net income and comprehensive income attributable to noncontrolling interests		56,636		63,832
Unrealized commodity derivative (gains)		(1,025,870)		(618,134)
Amortization of deferred revenue, VPP		(11,403)		(9,478)
Loss (gain) on sale of assets		595		(1,600)
Impairment of property and equipment		20,905		69,982
Equity-based compensation		5,248		12,221
Loss on early extinguishment of debt		10,355		652
Equity in earnings of unconsolidated affiliate		(19,464)		(17,464)
Contract termination		—		5,000
Tax effect of reconciling items ⁽¹⁾		244,471		120,101
		182,858		355,408
Martica adjustments ⁽²⁾		(25,509)		(27,063)
Adjusted Net Income	$	157,349		328,345

Diluted Weighted Average Shares Outstanding		340,106		316,356


(1)	Deferred taxes were approximately 24% and 21% for 2021 and 2022, 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,
	2021		2022
Credit Facility	$	—		34,800
5.000% senior notes due 2025		584,635		—
8.375% senior notes due 2026		325,000		96,870
7.625% senior notes due 2029		584,000		407,115
5.375% senior notes due 2030		600,000		600,000
4.250% convertible senior notes due 2026		81,570		56,932
Unamortized discount, net		(27,772)		—
Unamortized debt issuance costs		(21,989)		(12,241)
Total long-term debt	$	2,125,444		1,183,476
Less: Cash and cash equivalents		—		—
Net Debt	$	2,125,444		1,183,476

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, less proceeds from asset sales 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 return of capital. 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, 2021 and 2022. 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 December 31,				Year Ended December 31,
	2021		2022		2021		2022
Reconciliation of net income (loss) to Adjusted EBITDAX:
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	901,385		730,296		(186,899)		1,898,771
Net income and comprehensive income attributable to noncontrolling interests		56,636