PR Newswire
HOUSTON
, Nov. 4, 2025 /PRNewswire/ — Chord Energy Corporation (NASDAQ: CHRD) (“Chord”, “Chord Energy” or the “Company”) today reported financial and operating results for the third quarter 2025.
Key Takeaways and Updates:
- Strong Execution: Efficient execution and strong asset performance in 3Q25 delivered oil volumes above midpoint of guidance, with E&P and other CapEx below midpoint of guidance;
- Updated FY25 Outlook: Raised oil volume guidance and maintained CapEx guidance excluding XTO impacts;
- 4-Mile Lateral Update: TIL’d three additional 4-mile laterals since August. Wells executed faster and below initial cost estimates, with encouraging early time production;
- Shareholder Returns: Returned 69% of Adjusted FCF(1) to shareholders through the base dividend of $1.30 per share and $83.0MM of share repurchases;
- Marketing Optimization: Executed numerous agreements YTD expected to deliver $30MM-$50MM annualized FCF savings. See “Marketing Optimization Update” below for additional information; and
- XTO Acquisition: Completed acquisition of Williston Basin assets from XTO Energy Inc. and affiliates (collectively “XTO”), subsidiaries of Exxon Mobil Corporation, on October 31, 2025 (the “XTO Acquisition”). Total cash consideration paid was $542.2MM, including a $55MM deposit paid in 3Q25. See “2025 Outlook Update” below for additional information.
3Q25 Operational and Financial Highlights:
- Production: 155.7 MBopd (280.9 MBoepd), above midpoint of guidance;
-
CapEx:
$321.9MM (excluding $11.7MM of reimbursed non-op CapEx), below midpoint of guidance reflecting program timing; -
LOE:
$9.62/Boe, towards high-end of guidance reflecting curtailment of Marcellus volumes and activity timing; - GAAP Results: Net cash from operations $559.0MM; net income $130.1MM ($2.26/diluted share); and
- Non-GAAP Results(1): Adjusted EBITDA $577.8MM; Adjusted FCF $218.6MM ($230.3MM, excluding $11.7MM of reimbursed non-op CapEx); Adjusted Net Income $134.5MM ($2.35/diluted share).
|
|
“Chord’s operational momentum continues and the team delivered solid results in the third quarter,” said Danny Brown, Chord Energy’s President and Chief Executive Officer. “Third quarter oil volumes and capital were favorable to guidance and Chord raised FY25 oil volume guidance for the second time this year, excluding impacts from the recent acquisition. In addition, the purchase of certain XTO assets closed at the end of October, which extends our inventory runway in core areas while allowing for further capital efficiency through longer lateral development. Chord’s strategy revolves around strong capital allocation and continuous improvement. On that front, we’re pleased to announce continued progress in de-risking the 4-mile program, including the successful execution on three incremental 4-mile wells. Chord continues to drive efficiency through every aspect of the business which puts the Company in a strong position to lengthen inventory and enhance economics amidst persistent commodity volatility.”
3Q25 Operational and Financial Update:
The following table presents select 3Q25 operational and financial data compared to guidance released on May 6, 2025:
|
|
|
|
||
|
Oil Volumes (MBopd) |
155.7 |
153.5 – 157.5 |
||
|
NGL Volumes (MBblpd) |
55.1 |
50.5 – 54.5 |
||
|
Natural Gas Volumes (MMcfpd) |
420.1 |
430.0 – 442.0 |
||
|
Total Volumes (MBoepd) |
280.9 |
275.7 – 285.7 |
||
|
E&P & Other CapEx ($MM)(2) |
$333.7 |
$315 – $345 |
||
|
Oil Discount to WTI ($/Bbl) |
$(1.41) |
$(1.75) – $0.25 |
||
|
NGL Realization (% of WTI) |
8 % |
5% – 15% |
||
|
Natural Gas Realization (% of Henry Hub) |
26 % |
20% – 30% |
||
|
LOE ($/Boe) |
$9.62 |
$8.70 – $9.70 |
||
|
Cash GPT ($/Boe)(1) |
$2.86 |
$2.65 – $3.15 |
||
|
Cash G&A ($MM)(1) |
$16.5 |
$20.0 – $25.0 |
||
|
Production Taxes (% of Oil, NGL and Natural Gas Sales) |
8.2 % |
8.3% – 8.8% |
||
|
Cash Interest ($MM)(1) |
$18.5 |
$17.0 – $19.0 |
||
|
Cash Tax (% of Adjusted EBITDA)(3) |
1.2 % |
0% – 6% |
|
___________________ |
|
|
(1) |
Non-GAAP financial measure. See “Non-GAAP Financial Measures” below for a reconciliation to the most directly comparable financial measures under GAAP. |
|
(2) |
3Q25 includes $11.7MM of reimbursed non-op CapEx. |
|
(3) |
Cash taxes paid during the three months ended September 30, 2025 were $7.0MM, or 1.2% of Adjusted EBITDA. Guidance range based on NYMEX WTI between $60/Bbl – $80/Bbl. |
Chord had 25.0 gross (17.0 net) operated TILs in 3Q25.
Return of Capital:
Chord declared a base dividend of $1.30 per share of common stock. The dividend will be payable on December 5, 2025 to shareholders of record as of November 19, 2025. Details regarding the Return of Capital calculation can be found in the Company’s most recent investor presentation located on its website at https://ir.chordenergy.com/presentations.
The Company repurchased 788,444 shares of common stock at a weighted average price of $105.27 per share totaling $83.0MM in 3Q25, representing 100% of shareholder returns after the base dividend. Shares issued and outstanding as of September 30, 2025 were 56.9MM (57.3MM on a fully-diluted basis), compared to 57.6MM (58.1MM on a fully-diluted basis) as of June 30, 2025.
Marketing Optimization Update:
Chord has executed numerous marketing agreements year-to-date expected to deliver $30MM-$50MM of annualized FCF savings. These agreements encompass crude oil, natural gas and water marketing and midstream services across the Company’s Williston Basin acreage position, reflecting Chord’s ongoing commitment to continuous improvement, cost efficiency and value creation.
Chord remains focused on further optimizing its marketing and midstream cost structure by streamlining contract structures and partnering with high-quality service providers. These efforts support the Company’s broader continuous improvement initiatives to reduce controllable costs and enhance sustainable FCF generation.
Operations Update:
- 4-Mile Laterals: Chord advanced its 4-mile lateral program, with three new 4-mile wells TIL’d since August—each ahead of schedule and under budget. The State Line well in Montana is demonstrating encouraging early production performance, with tracer data indicating contribution from the full lateral. The Violet-Olson wells in the Wheelock area of North Dakota are free-flowing and also showing encouraging early results after successful post-frac cleanouts and tracer data indicating contribution from the full lateral. Chord’s first 4-mile well (Rystedt) has matched production from two 2-mile well analogs after only six months. Year-to-date, Chord has TIL’d four 4-mile laterals and expects to TIL a total of seven 4-mile laterals in FY25. Operational efficiency and strong performance support the potential for substantially more 4-mile wells in the 2026 program.
- Execution: In 2025, the Chord team improved operations, driving efficiencies which led to higher volumes for lower capital spending, while achieving an excellent safety record. Drilling days have dropped from 2024 levels, simulfrac increased daily lateral footage completed, and post-frac cleanouts are now more efficient. The facilities team also lowered costs by using modular prefabricated designs and optimizing wells per facility.
- Production/LOE: Chord continues to lower failure rates, supported by autonomous rod lift operations, while also shortening cycle-times and reducing costs associated with restoring down wells. Chord has lowered downtime year-over-year, which has driven higher free cash flow from both higher volumes and lower costs. 3Q25 LOE was towards the upper-end of guidance largely reflecting the curtailment of volumes in the Marcellus and activity timing.
2025 Outlook Update:
Chord expects to bring back a second completions crew in 4Q25. Guidance outlined below reflects this outlook and also the impact from the XTO Acquisition. The Company continues to monitor the macro environment and retains flexibility to reduce activity if conditions warrant.
Chord expects to generate Adjusted EBITDA of approximately $2.4B and Adjusted FCF of approximately $840MM at midpoint of guidance ($60/Bbl WTI and $3.75/MMBtu Henry Hub in 4Q25). Chord plans to TIL115 – 125 gross operated wells (~80% working interest) in FY25, with 23 – 33 gross operated TILs planned in 4Q25 (~80% working interest).
Highlights of Chord’s updated FY25 guidance include:
- Volumes: Excluding the impacts of the XTO Acquisition, 4Q25 oil volumes are increasing 1.0 MBopd vs August outlook to 147.0 MBopd at midpoint of guidance. Excluding the XTO Acquisition, FY25 oil volumes are increasing to 153.3 MBopd at midpoint of guidance. Oil volumes associated with the XTO Acquisition are expected to contribute approximately 4.0 MBopd in 4Q25 leading to total 4Q25 volumes of 151.0 MBopd at midpoint of guidance. FY25 total volumes were adjusted to reflect production curtailments in the Marcellus;
- CapEx: Adding $15MM of CapEx to FY25 to support maintaining XTO volumes in 2026; otherwise, FY25 CapEx of $1.35B at midpoint of guidance is unchanged vs August outlook. Adjusting 4Q25 CapEx to reflect the XTO related capital and minor schedule shifting from 3Q25 to 4Q25;
- Differentials: Adjusting to reflect 3Q performance and current market conditions;
- LOE: Adjusting FY25 to $9.73/Boe at midpoint of guidance to reflect 3Q25 performance (affected by curtailed Marcellus volumes), the inclusion of XTO in 4Q25 and activity timing. 4Q25 adjusted to $9.70/Boe at midpoint of guidance to reflect continued curtailment of Marcellus volumes and impacts from the XTO Acquisition;
- Cash G&A: Lowering FY25 to $90MM at midpoint of guidance to reflect YTD performance;
- Cash Interest: Increasing FY25 to $79MM at midpoint of guidance to reflect the issuance of 2030 Senior Notes in September; and
- Cash Taxes: Expecting 4Q25 cash taxes of 1.5% of Adjusted EBITDA at midpoint of guidance ($50/Bbl – $70/Bbl WTI).
The following table presents select operational and financial guidance for the periods presented:
|
|
|
|
||
|
Oil Volumes (MBopd) |
149.0 – 153.0 |
153.8 – 154.8 |
||
|
NGL Volumes (MBblpd) |
49.5 – 53.5 |
51.7 – 52.7 |
||
|
Natural Gas Volumes (MMcfpd) |
421.0 – 433.0 |
420.4 – 423.4 |
||
|
Total Volumes (MBoepd) |
268.7 – 278.7 |
275.6 – 278.1 |
||
|
E&P & Other CapEx ($MM) |
$315 – $345 |
$1,350 – $1,380 |
||
|
Oil Discount to WTI ($/Bbl) |
$(2.80) – $(0.80) |
$(2.15) – $(1.65) |
||
|
NGL Realization (% of WTI) |
5% – 15% |
10% – 13% |
||
|
Natural Gas Realization (% of Henry Hub) |
30% – 40% |
38% – 40% |
||
|
LOE ($/Boe) |
$9.20 – $10.20 |
$9.60 – $9.85 |
||
|
Cash GPT ($/Boe)(1) |
$2.70 – $3.00 |
$2.85 – $2.92 |
||
|
Cash G&A ($MM)(1) |
$20 – $25 |
$87 – $92 |
||
|
Production Taxes (% of Oil, NGL and Natural Gas Sales) |
8.3% – 8.8% |
7.6% – 7.7% |
||
|
Cash Interest ($MM)(1) |
$25 – $27 |
$78 – $80 |
||
|
Cash Tax (% of Adjusted EBITDA)(2) |
0% – 3% |
3% – 4% |
|
___________________ |
|
|
(1) |
Non-GAAP financial measure. See “Non-GAAP Financial Measures” below for more information. |
|
(2) |
Reflects 4Q25 WTI prices between $50/Bbl – $70/Bbl. |
Select Operational and Financial Data:
The following table presents select operational and financial data for the periods presented:
|
|
|
|
|||
|
|
|||||
|
Crude oil (MBopd) |
155.7 |
156.7 |
158.8 |
||
|
NGLs (MBblpd) |
55.1 |
54.1 |
51.7 |
||
|
Natural gas (MMcfpd)(3) |
420.1 |
425.9 |
421.8 |
||
|
Total production (MBoepd) |
280.9 |
281.9 |
280.8 |
||
|
|
|
|
|
||
|
|
|||||
|
Crude oil, without realized derivatives ($/Bbl) |
$ 63.59 |
$ 61.62 |
$ 73.51 |
||
|
Differential to NYMEX WTI ($/Bbl) |
(1.41) |
(2.15) |
(1.51) |
||
|
Crude oil, with realized derivatives ($/Bbl) |
64.16 |
62.58 |
73.58 |
||
|
Crude oil realized derivatives (gain) loss ($MM) |
(8.3) |
(13.7) |
(1.0) |
||
|
NGL, without realized derivatives ($/Bbl) |
4.89 |
5.80 |
6.31 |
||
|
NGL, with realized derivatives ($/Bbl) |
4.89 |
5.80 |
6.31 |
||
|
Natural gas, without realized derivatives ($/Mcf)(3) |
0.81 |
1.10 |
0.44 |
||
|
Natural gas, with realized derivatives ($/Mcf) |
1.11 |
1.11 |
0.44 |
||
|
Natural gas realized derivatives (gain) loss ($MM) |
(11.5) |
(0.4) |
— |
||
|
|
|||||
|
|
|||||
|
Crude oil revenues |
$ 910.8 |
$ 878.9 |
$ 1,073.9 |
||
|
NGL revenues |
24.8 |
28.6 |
30.0 |
||
|
Natural gas revenues |
31.2 |
42.8 |
17.1 |
||
|
Total oil, NGL and natural gas revenues |
$ 966.8 |
$ 950.3 |
$ 1,121.0 |
||
|
|
|||||
|
Net cash provided by operating activities: |
$ 559.0 |
$ 1,076.7 |
$ 663.2 |
||
|
|
|||||
|
Adjusted EBITDA |
$ 577.8 |
$ 547.2 |
$ 674.5 |
||
|
Adjusted FCF(4) |
218.6 |
140.8 |
312.5 |
||
|
Adjusted Net Income Attributable to Common Stockholders |
134.5 |
103.2 |
212.8 |
||
|
|
|||||
|
LOE |
$ 248.6 |
$ 257.0 |
$ 247.1 |
||
|
Gathering, processing and transportation expenses (“GPT”) |
73.1 |
74.1 |
77.4 |
||
|
Production taxes |
79.5 |
69.0 |
101.0 |
||
|
Depreciation, depletion and amortization |
374.9 |
377.0 |
360.2 |
||
|
Total select operating expenses |
$ 776.1 |
$ 777.1 |
$ 785.7 |
||
|
|
|||||
|
Basic earnings (loss) per share |
$ 2.26 |
$ (6.71) |
$ 3.63 |
||
|
Diluted earnings (loss) per share |
2.26 |
(6.77) |
3.59 |
||
|
Adjusted diluted earnings per share (Non-GAAP)(1) |
2.35 |
1.79 |
3.40 |
|
___________________ |
|
|
(1) |
Non-GAAP financial measure. See “Non-GAAP Financial Measures” below for a reconciliation to the most directly comparable financial measures under GAAP. |
|
(2) |
Marcellus natural gas volumes were 117.5 MMcfpd in 3Q25, 129.9 MMcfpd in 2Q25 and 114.2 MMcfpd in 3Q24. |
|
(3) |
Marcellus natural gas realized prices were $2.16/Mcf in 3Q25, $2.49/Mcf in 2Q25 and $1.32/Mcf in 3Q24. |
|
(4) |
3Q25 includes $11.7M of reimbursed non-op CapEx. |
Capital Expenditures:
The following table presents the Company’s capital expenditures (“CapEx”) by category for the periods presented (in millions):
|
|
|
|
|
||||
|
|
|||||||
|
E&P(1) |
$ 354.8 |
$ 354.5 |
$ 333.6 |
$ 1,042.9 |
|||
|
Other |
0.6 |
1.1 |
0.0 |
1.7 |
|||
|
Total E&P and other CapEx |
355.4 |
355.6 |
333.6 |
1,044.6 |
|||
|
Capitalized interest |
1.1 |
1.1 |
1.1 |
3.3 |
|||
|
Acquisitions |
17.9 |
8.3 |
1.6 |
27.8 |
|||
|
|
$ 374.4 |
$ 365.0 |
$ 336.3 |
$ 1,075.7 |
|
(1) |
3Q25 and YTD25 include $11.7MM of reimbursed non-op CapEx. |
Balance Sheet and Liquidity:
The following table presents key balance sheet data and liquidity metrics as of September 30, 2025 (in millions):
|
|
|
|
Revolving credit facility(1) |
$ 2,000.0 |
|
Revolver borrowings |
$ — |
|
Senior notes |
1,500.0 |
|
Total debt |
$ 1,500.0 |
|
Cash and cash equivalents(2) |
$ 142.0 |
|
Letters of credit |
32.1 |
|
Liquidity(2) |
$ 2,109.9 |
|
___________________ |
|
|
(1) |
$2.75B borrowing base and $2.0B of elected commitments. |
|
(2) |
Pro-forma for XTO closing payment of $487.2MM on October 31, 2025. |
Contact:
Chord Energy Corporation
Bob Bakanauskas, VP, Investor Relations
(281) 404-9600
[email protected]
Conference Call Information
Investors, analysts and other interested parties are invited to listen to the webcast:
|
Date: |
Wednesday, November 5, 2025 |
|
|
Time: |
10:00 a.m. Central |
|
|
Live Webcast: |
https://app.webinar.net/6nwV2ADPEYv |
To join the conference call by phone without operator assistance (including sell-side analysts wishing to ask a question), you may register and enter your phone number at https://emportal.ink/45glAYZ to receive an instant automated call back and be immediately placed into the call.
You may also use the following dial-in information to join the conference call by phone with operator assistance:
|
Dial-in: |
1-800-836-8184 |
|
|
Intl. Dial-in: |
1-646-357-8785 |
|
|
Conference ID: |
68869 |
A recording of the conference call will be available beginning at 1:00 p.m. Central on the day of the call and will be available until Wednesday, November 12, 2025 by dialing:
|
Replay dial-in: |
1-888-660-6345 |
|
|
Intl. replay: |
1-646-517-4150 |
|
|
Replay access: |
68869 # |
The call will also be available for replay for approximately 30 days at https://www.chordenergy.com
Forward-Looking Statements and Cautionary Statements
Certain statements in this press release, other than statements of historical facts, that address activities, events or developments that Chord expects, believes or anticipates will or may occur in the future, including any statements regarding the benefits and synergies of the Enerplus combination, future opportunities for Chord, future financial performance and condition, guidance and statements regarding Chord’s expectations, beliefs, plans, financial condition, objectives, assumptions or future events or performance are forward-looking statements based on assumptions currently believed to be valid. Forward-looking statements are all statements other than statements of historical facts. The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “potential,” “may,” “might,” “anticipate,” “likely,” “plan,” “positioned,” “strategy” and similar expressions or other words of similar meaning, and the negatives thereof, are intended to identify forward-looking statements. Specific forward-looking statements include statements regarding Chord’s plans and expectations with respect to the return of capital plan, production levels and reinvestment rates, anticipated financial and operating results and other guidance and the effects, benefits and synergies of the Enerplus combination. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995.
These statements are based on certain assumptions made by Chord based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of Chord, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include, but are not limited to, changes in crude oil, NGL and natural gas prices, uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil, NGLs and natural gas, the actions taken by OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations, changes in trade policies and regulations, including increases or change in duties, current and potentially new tariffs or quotas and other similar measures, as well as the potential impact of retaliatory tariffs and other actions, war between Russia and Ukraine, military conflicts in the Red Sea Region and war between Israel and Hamas and the potential for escalation of hostilities across the surrounding countries in the Middle East and their effect on commodity prices, changes in general economic and geopolitical conditions, including as a result of the federal government shutdown, inflation rates and the impact of associated monetary policy responses, including increased interest rates, the ability to realize the anticipated benefits from the XTO Acquisition, developments in the global economy, as well as any public health crisis and resulting demand and supply for crude oil, NGLs and natural gas, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as Chord’s ability to access them, the proximity to and capacity of transportation facilities, the availability of midstream service providers, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting Chord’s business and other important factors that could cause actual results to differ materially from those projected as described in Chord’s reports filed with the U.S. Securities and Exchange Commission (the “SEC”).
Any forward-looking statement speaks only as of the date on which such statement is made and Chord undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements. Additional information concerning other risk factors is also contained in Chord’s most recently filed Annual Report on Form 10-K for the year ended December 31, 2024, subsequent Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other SEC filings.
About Chord Energy
Chord Energy Corporation is an independent exploration and production company with quality and sustainable long-lived assets primarily in the Williston Basin. The Company is uniquely positioned with a best-in-class balance sheet and is focused on rigorous capital discipline and generating free cash flow by operating efficiently, safely and responsibly to develop its unconventional onshore oil-rich resources in the continental United States. For more information, please visit the Company’s website at www.chordenergy.com.
Comparability of Financial Statements
The results reported for the three and nine months ended September 30, 2025 and the three months ended September 30, 2024 reflect the consolidated results of Chord, including combined operations with Enerplus Corporation (“Enerplus”), while the results reported for the nine months ended September 30, 2024 reflect the consolidated results of Chord, including the combined operations with Enerplus beginning on May 31, 2024, unless otherwise noted.
|
|
|||
|
|
|
||
|
|
|||
|
Current assets |
|||
|
Cash and cash equivalents |
$ 629,208 |
$ 36,950 |
|
|
Accounts receivable, net |
1,210,328 |
1,298,973 |
|
|
Inventory |
108,498 |
94,299 |
|
|
Prepaid expenses |
27,740 |
30,875 |
|
|
Derivative instruments |
86,200 |
35,944 |
|
|
Other current assets |
2,178 |
82,077 |
|
|
Total current assets |
2,064,152 |
1,579,118 |
|
|
Property, plant and equipment |
|||
|
Oil and gas properties (successful efforts method) |
13,934,970 |
12,770,786 |
|
|
Other property and equipment |
59,970 |
58,158 |
|
|
Less: accumulated depreciation, depletion and amortization |
(3,215,842) |
(2,142,775) |
|
|
Total property, plant and equipment, net |
10,779,098 |
10,686,169 |
|
|
Derivative instruments |
4,942 |
5,629 |
|
|
Investment in unconsolidated affiliate |
124,562 |
142,201 |
|
|
Long-term inventory |
29,101 |
25,973 |
|
|
Operating right-of-use assets |
17,304 |
38,004 |
|
|
Goodwill |
— |
530,616 |
|
|
Other assets |
78,155 |
24,297 |
|
|
Total assets |
$ 13,097,314 |
$ 13,032,007 |
|
|
|
|||
|
Current liabilities |
|||
|
Accounts payable |
$ 61,627 |
$ 68,751 |
|
|
Revenues and production taxes payable |
670,974 |
752,742 |
|
|
Accrued liabilities |
761,381 |
732,296 |
|
|
Accrued interest payable |
5,177 |
4,693 |
|
|
Derivative instruments |
— |
1,230 |
|
|
Advances from joint interest partners |
2,180 |
2,434 |
|
|
Current operating lease liabilities |
24,623 |
37,629 |
|
|
Other current liabilities |
1,792 |
84,203 |
|
|
Total current liabilities |
1,527,754 |
1,683,978 |
|
|
Long-term debt |
1,478,827 |
842,600 |
|
|
Deferred tax liabilities |
1,603,141 |
1,496,442 |
|
|
Asset retirement obligations |
400,382 |
282,369 |
|
|
Derivative instruments |
1,094 |
1,016 |
|
|
Operating lease liabilities |
5,770 |
15,190 |
|
|
Other liabilities |
6,405 |
8,150 |
|
|
Total liabilities |
5,023,373 |
4,329,745 |
|
|
Commitments and contingencies |
|||
|
Stockholders’ equity |
|||
|
Common stock, $0.01 par value: 240,000,000 shares authorized, 67,150,747 shares issued and 56,865,300 shares outstanding at September 30, 2025; and 240,000,000 shares authorized, 66,967,779 shares issued and 60,070,893 shares outstanding at December 31, 2024 |
675 |
673 |
|
|
Treasury stock, at cost: 10,285,447 shares at September 30, 2025 and 6,896,886 shares at December 31, 2024 |
(1,293,994) |
(936,157) |
|
|
Additional paid-in capital |
7,333,496 |
7,336,091 |
|
|
Retained earnings |
2,033,764 |
2,301,655 |
|
|
Total stockholders’ equity |
8,073,941 |
8,702,262 |
|
|
Total liabilities and stockholders’ equity |
$ 13,097,314 |
$ 13,032,007 |
|
|
|
|||||||
|
|
|
||||||
|
|
|
|
|
||||
|
|
|||||||
|
Oil, NGL and gas revenues |
$ 966,847 |
$ 1,121,012 |
$ 3,020,537 |
$ 2,771,841 |
|||
|
Purchased oil and gas sales |
345,234 |
329,455 |
687,150 |
1,024,567 |
|||
|
Total revenues |
1,312,081 |
1,450,467 |
3,707,687 |
3,796,408 |
|||
|
|
|||||||
|
Lease operating expenses |
248,604 |
247,055 |
738,644 |
582,908 |
|||
|
Gathering, processing and transportation expenses |
73,052 |
77,353 |
220,467 |
194,467 |
|||
|
Purchased oil and gas expenses |
340,947 |
329,622 |
684,060 |
1,021,739 |
|||
|
Production taxes |
79,509 |
100,973 |
223,116 |
244,410 |
|||
|
Depreciation, depletion and amortization |
374,919 |
360,214 |
1,101,725 |
757,036 |
|||
|
General and administrative expenses |
21,861 |
52,115 |
92,778 |
159,904 |
|||
|
Impairment and exploration |
2,034 |
7,269 |
545,957 |
14,908 |
|||
|
Total operating expenses |
1,140,926 |
1,174,601 |
3,606,747 |
2,975,372 |
|||
|
Gain (loss) on sale of assets, net |
(365) |
(2,973) |
4,628 |
13,814 |
|||
|
Operating income |
170,790 |
272,893 |
105,568 |
834,850 |
|||
|
|
|||||||
|
Net gain on derivative instruments |
20,724 |
52,721 |
82,674 |
29,753 |
|||
|
Net gain (loss) from investment in unconsolidated affiliate |
(4,646) |
1,089 |
(10,507) |
23,246 |
|||
|
Interest expense, net of capitalized interest |
(18,717) |
(19,146) |
(53,324) |
(38,946) |
|||
|
Loss on debt extinguishment |
— |
— |
(3,494) |
— |
|||
|
Other income (expense), net |
2,146 |
(2,657) |
6,692 |
4,253 |
|||
|
Total other income (expense), net |
(493) |
32,007 |
22,041 |
18,306 |
|||
|
Income before income taxes |
170,297 |
304,900 |
127,609 |
853,156 |
|||
|
Income tax expense |
(40,186) |
(79,584) |
(167,566) |
(215,126) |
|||
|
|
$ 130,111 |
$ 225,316 |
$ (39,957) |
$ 638,030 |
|||
|
|
|||||||
|
Basic |
$ 2.26 |
$ 3.63 |
$ (0.72) |
$ 12.61 |
|||
|
Diluted |
$ 2.26 |
$ 3.59 |
$ (0.72) |
$ 12.34 |
|||
|
|
|||||||
|
Basic |
57,157 |
61,802 |
57,141 |
50,388 |
|||
|
Diluted |
57,157 |
62,629 |
57,195 |
51,507 |
|||
|
|
|||
|
|
|||
|
|
|
||
|
|
|||
|
Net income (loss) |
$ (39,957) |
$ 638,030 |
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|||
|
Depreciation, depletion and amortization |
1,101,725 |
757,036 |
|
|
Loss on debt extinguishment |
3,494 |
— |
|
|
Gain on sale of assets |
(4,628) |
(13,814) |
|
|
Impairment |
539,323 |
9,838 |
|
|
Deferred income taxes |
106,699 |
146,882 |
|
|
Net (gain) loss from investment in unconsolidated affiliate |
10,507 |
(23,246) |
|
|
Net gain on derivative instruments |
(82,674) |
(29,753) |
|
|
Equity-based compensation expenses |
19,464 |
16,053 |
|
|
Deferred financing costs amortization and other |
(19,282) |
6,407 |
|
|
Working capital and other changes: |
|||
|
Change in accounts receivable, net |
71,401 |
(19,112) |
|
|
Change in inventory |
(12,343) |
(6,937) |
|
|
Change in prepaid expenses |
4,686 |
8,090 |
|
|
Change in accounts payable, interest payable and accrued liabilities |
(56,034) |
70,538 |
|
|
Change in other assets and liabilities, net |
(6,711) |
(29,240) |
|
|
Net cash provided by operating activities |
1,635,670 |
1,530,772 |
|
|
|
|||
|
Capital expenditures |
(1,044,820) |
(877,381) |
|
|
Acquisitions |
(27,434) |
(652,672) |
|
|
Acquisition deposit |
(55,000) |
— |
|
|
Proceeds from divestitures |
10,735 |
21,788 |
|
|
Derivative settlements |
31,954 |
(17,760) |
|
|
Contingent consideration received |
25,000 |
25,000 |
|
|
Distributions from investment in unconsolidated affiliate |
9,182 |
6,914 |
|
|
Net cash used in investing activities |
(1,050,383) |
(1,494,111) |
|
|
|
|||
|
Proceeds from revolving credit facility |
3,687,000 |
2,250,000 |
|
|
Principal payments on revolving credit facility |
(4,132,000) |
(1,780,000) |
|
|
Repayment and discharge of senior notes |
(401,432) |
(63,000) |
|
|
Issuance of senior notes |
1,500,000 |
— |
|
|
Deferred financing costs |
(21,881) |
(3,313) |
|
|
Repurchases of common stock |
(357,837) |
(239,804) |
|
|
Tax withholding on vesting of equity-based awards |
(22,100) |
(57,979) |
|
|
Dividends paid |
(243,418) |
(437,725) |
|
|
Payments on finance lease liabilities |
(1,384) |
(1,242) |
|
|
Proceeds from warrants exercised |
23 |
30,454 |
|
|
Net cash provided by (used in) financing activities |
6,971 |
(302,609) |
|
|
Increase (decrease) in cash and cash equivalents |
592,258 |
(265,948) |
|
|
|
|||
|
Beginning of period |
36,950 |
317,998 |
|
|
End of period |
$ 629,208 |
$ 52,050 |
|
|
|
|||
|
Change in accrued capital expenditures |
$ (252) |
$ 42,306 |
|
|
Change in asset retirement obligations |
102,364 |
3,869 |
|
|
Non-cash consideration exchanged in Arrangement |
— |
3,732,137 |
|
|
Dividends payable |
1,173 |
20,572 |
|
Non-GAAP Financial Measures
The following are non-GAAP financial measures not prepared in accordance with GAAP that are used by management and external users of the Company’s financial statements, such as industry analysts, investors, lenders and rating agencies. The Company believes that the foregoing are useful supplemental measures that provide an indication of the results generated by the Company’s principal business activities. However, these measures are not recognized by GAAP and do not have a standardized meaning prescribed by GAAP. Therefore, these measures may not be comparable to similar measures provided by other issuers. From time to time, the Company provides forward-looking forecasts of these measures; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measures to the most directly comparable forward-looking GAAP measures because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measures. The reconciling items in future periods could be significant. To see how the Company reconciles its historical presentations of these non-GAAP financial measures to the most directly comparable GAAP measures, please visit the Investors—Documents & Disclosures—Non-GAAP Reconciliation page on the Company’s website at https://ir.chordenergy.com/non-gaap.
Cash GPT
The Company defines Cash GPT as total GPT expenses less non-cash valuation charges on pipeline imbalances and non-cash mark-to-market adjustments on transportation contracts accounted for as derivative instruments. Cash GPT is not a measure of GPT expenses as determined by GAAP. Management believes that the presentation of Cash GPT provides useful additional information to investors and analysts to assess the cash costs incurred to market and transport the Company’s commodities from the wellhead to delivery points for sale without regard to the change in value of its pipeline imbalances, which vary monthly based on commodity prices, and without regard to the non-cash mark-to-market adjustments on transportation contracts classified as derivative instruments.
The following table presents a reconciliation of the GAAP financial measure of GPT expenses to the non-GAAP financial measure of Cash GPT for the periods presented:
|
|
|
||||||
|
|
|
|
|
||||
|
|
|||||||
|
|
$ 73,052 |
$ 77,353 |
$ 220,467 |
$ 194,467 |
|||
|
Pipeline imbalances |
734 |
(2,114) |
(988) |
(2,796) |
|||
|
Loss on derivative transportation contract(1) |
— |
— |
— |
(5,877) |
|||
|
|
|
|
|
|
|||
|
___________________ |
|
|
(1) |
The Company had a buy/sell transportation contract that qualified as a derivative. The changes in the fair value of this contract were recorded to GPT expense. As of June 30, 2024, the term of this contract expired. |
Cash G&A
The Company defines Cash G&A as total G&A expenses less G&A expenses directly attributable to certain merger and acquisition activity, non-cash equity-based compensation expenses and other non-cash charges. Cash G&A is not a measure of G&A expenses as determined by GAAP. Management believes that the presentation of Cash G&A provides useful additional information to investors and analysts to assess the Company’s operating costs in comparison to peers without regard to the aforementioned charges, which can vary substantially from company to company.
The following table presents a reconciliation of the GAAP financial measure of G&A expenses to the non-GAAP financial measure of Cash G&A for the periods presented:
|
|
|
||||||
|
|
|
|
|
||||
|
|
|||||||
|
|
$ 21,861 |
$ 52,115 |
$ 92,778 |
$ 159,904 |
|||
|
Merger costs(1) |
(77) |
(17,503) |
(8,141) |
(80,297) |
|||
|
Equity-based compensation expenses |
(6,464) |
(5,918) |
(19,461) |
(16,053) |
|||
|
Other non-cash adjustments |
1,215 |
(829) |
1,408 |
633 |
|||
|
|
|
|
|
|
|||
|
___________________ |
|
|
(1) |
Includes costs directly attributable to the arrangement with Enerplus for the three and nine months ended September 30, 2025 and 2024. |
Cash Interest
The Company defines Cash Interest as interest expense plus capitalized interest less amortization of deferred financing costs. Cash Interest is not a measure of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on the Company’s debt to finance its operating activities and the Company’s ability to maintain compliance with its debt covenants.
The following table presents a reconciliation of the GAAP financial measure of interest expense to the non-GAAP financial measure of Cash Interest for the periods presented:
|
|
|
||||||
|
|
|
|
|
||||
|
|
|||||||
|
|
$ 18,717 |
$ 19,146 |
$ 53,324 |
$ 38,946 |
|||
|
Capitalized interest |
1,128 |
1,839 |
3,316 |
3,707 |
|||
|
Amortization of deferred financing costs |
(1,359) |
(1,140) |
(3,885) |
(3,398) |
|||
|
|
|
|
|
|
|||
Adjusted EBITDA and Adjusted Free Cash Flow
The Company defines Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion and amortization (“DD&A”), merger costs, exploration expenses, impairment expenses, loss on debt extinguishment and other similar non-cash or non-recurring charges. The Company defines Adjusted Free Cash Flow as Adjusted EBITDA less Cash Interest and E&P and other capital expenditures (excluding capitalized interest and acquisition capital).
Adjusted EBITDA and Adjusted Free Cash Flow are not measures of net income or cash flows from operating activities as determined by GAAP. Management believes that the presentation of Adjusted EBITDA and Adjusted Free Cash Flow provides useful additional information to investors and analysts for assessing the Company’s results of operations, financial performance, ability to generate cash from its business operations without regard to its financing methods or capital structure and the Company’s ability to maintain compliance with its debt covenants.
The following table presents reconciliations of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Adjusted Free Cash Flow for the periods presented:
|
|
|
||||||
|
|
|
|
|
||||
|
|
|||||||
|
|
$ 130,111 |
$ 225,316 |
$ (39,957) |
$ 638,030 |
|||
|
Interest expense, net of capitalized interest |
18,717 |
19,146 |
53,324 |
38,946 |
|||
|
Loss on debt extinguishment |
— |
— |
3,494 |
— |
|||
|
Income tax expense |
40,186 |
79,584 |
167,566 |
215,126 |
|||
|
Depreciation, depletion and amortization |
374,919 |
360,214 |
1,101,725 |
757,036 |
|||
|
Merger costs(1) |
77 |
17,503 |
8,141 |
80,297 |
|||
|
Impairment and exploration expenses(2) |
2,034 |
7,269 |
545,957 |
14,908 |
|||
|
(Gain) loss on sale of assets |
365 |
2,973 |
(4,628) |
(13,814) |
|||
|
Net gain on derivative instruments |
(20,724) |
(52,721) |
(82,674) |
(29,753) |
|||
|
Realized gain (loss) on commodity price derivative contracts |
19,770 |
953 |
33,609 |
(4,305) |
|||
|
Net (gain) loss from investment in unconsolidated affiliate |
4,646 |
(1,089) |
10,507 |
(23,246) |
|||
|
Distributions from investment in unconsolidated affiliate |
2,395 |
2,323 |
7,132 |
6,914 |
|||
|
Equity-based compensation expenses |
6,464 |
5,918 |
19,461 |
16,053 |
|||
|
Other non-cash adjustments |
(1,185) |
7,118 |
(3,145) |
11,018 |
|||
|
|
|
|
|
|
|||
|
Cash interest |
(18,486) |
(19,845) |
(52,755) |
(39,255) |
|||
|
E&P and other capital expenditures |
(333,652) |
(329,187) |
(1,044,680) |
(901,245) |
|||
|
Cash taxes paid |
(7,000) |
(13,000) |
(73,099) |
(38,500) |
|||
|
|
|
|
|
|
|||
|
|
$ 558,967 |
$ 663,198 |
$ 1,635,670 |
$ 1,530,772 |
|||
|
Changes in working capital |
(13,515) |
(41,416) |
(999) |
(23,339) |
|||
|
Interest expense, net of capitalized interest |
18,717 |
19,146 |
53,324 |
38,946 |
|||
|
Current income tax expense (benefit) |
(17,463) |
3,401 |
60,868 |
68,243 |
|||
|
Merger costs(1) |
77 |
17,503 |
8,141 |
80,297 |
|||
|
Exploration expenses |
2,026 |
1,345 |
6,630 |
5,071 |
|||
|
Realized gain (loss) on commodity price derivative contracts |
19,770 |
953 |
33,609 |
(4,305) |
|||
|
Distributions from investment in unconsolidated affiliate |
2,395 |
2,323 |
7,132 |
6,914 |
|||
|
Deferred financing costs amortization and other |
7,986 |
936 |
19,282 |
(6,407) |
|||
|
Other non-cash adjustments |
(1,185) |
7,118 |
(3,145) |
11,018 |
|||
|
|
|
|
|
|
|||
|
Cash interest |
(18,486) |
(19,845) |
(52,755) |
(39,255) |
|||
|
E&P and other capital expenditures(3) |
(333,652) |
(329,187) |
(1,044,680) |
(901,245) |
|||
|
Cash taxes paid |
(7,000) |
(13,000) |
(73,099) |
(38,500) |
|||
|
|
|
|
|
|
|||
|
___________________ |
|
|
(1) |
Includes costs directly attributable to the arrangement with Enerplus for the three and nine months ended September 30, 2025 and 2024. |
|
(2) |
Includes non-cash goodwill impairment charge of $539.3 million for the nine months ended September 30, 2025, as a result of the decline in the Company’s market capitalization during the second quarter. |
|
(3) |
3Q25 E&P and other capital expenditures and Adjusted Free Cash Flow include $11.7MM of reimbursed non-op CapEx. |
Adjusted Net Income and Adjusted Diluted Earnings Per Share
Adjusted Net Income and Adjusted Diluted Earnings Per Share are supplemental non-GAAP financial measures that are used by management and external users of the Company’s financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted Net Income as net income after adjusting for (1) the impact of certain non-cash items, including non-cash changes in the fair value of derivative instruments, non-cash changes in the fair value of the Company’s investment in an unconsolidated affiliate, impairment, loss on debt extinguishment and other similar non-cash charges (2) merger costs and (3) the impact of taxes based on an estimated tax rate applicable to those adjusting items in the same period. Adjusted Net Income is not a measure of net income as determined by GAAP.
The Company calculates earnings per share under the two-class method in accordance with GAAP. The two-class method is an earnings allocation formula that computes earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Adjusted Diluted Earnings Per Share is calculated as (i) Adjusted Net Income (ii) less distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of diluted shares outstanding for the periods presented.
The following table presents reconciliations of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted Net Income and the GAAP financial measure of diluted earnings per share to the non-GAAP financial measure of Adjusted Diluted Earnings Per Share for the periods presented:
|
|
|
||||||
|
|
|
|
|
||||
|
|
|||||||
|
|
$ 130,111 |
$ 225,316 |
$ (39,957) |
$ 638,030 |
|||
|
Net gain on derivative instruments |
(20,724) |
(52,721) |
(82,674) |
(29,753) |
|||
|
Realized gain (loss) on commodity price derivative contracts |
19,770 |
953 |
33,609 |
(4,305) |
|||
|
Net (gain) loss from investment in unconsolidated affiliate |
4,646 |
(1,089) |
10,507 |
(23,246) |
|||
|
Distributions from investment in unconsolidated affiliate |
2,395 |
2,323 |
7,132 |
6,914 |
|||
|
Impairment(1) |
5 |
5,919 |
539,323 |
9,838 |
|||
|
Merger costs(2) |
77 |
17,503 |
8,141 |
80,297 |
|||
|
(Gain) loss on sale of assets, net |
365 |
2,973 |
(4,628) |
(13,814) |
|||
|
Amortization of deferred financing costs |
1,359 |
1,140 |
3,885 |
3,398 |
|||
|
Loss on debt extinguishment |
— |
— |
3,494 |
— |
|||
|
Other non-cash adjustments |
(1,185) |
7,118 |
(3,145) |
11,018 |
|||
|
Tax impact(3) |
(1,570) |
4,145 |
5,572 |
(9,802) |
|||
|
|
135,249 |
213,580 |
481,259 |
668,575 |
|||
|
Distributed and undistributed earnings allocated to participating securities |
(780) |
(734) |
(2,004) |
(2,681) |
|||
|
|
$ 134,469 |
$ 212,846 |
$ 479,255 |
$ 665,894 |
|||
|
|
|
||||||
|
|
|
|
|
||||
|
|
$ 2.28 |
$ 3.60 |
$ (0.70) |
$ 12.39 |
|||
|
Net gain on derivative instruments |
(0.36) |
(0.84) |
(1.45) |
(0.58) |
|||
|
Realized gain (loss) on commodity price derivative contracts |
0.35 |
0.02 |
0.59 |
(0.08) |
|||
|
Net (gain) loss from investment in unconsolidated affiliate |
0.08 |
(0.02) |
0.18 |
(0.45) |
|||
|
Distributions from investment in unconsolidated affiliate |
0.04 |
0.04 |
0.12 |
0.13 |
|||
|
Impairment(1) |
— |
0.09 |
9.43 |
0.19 |
|||
|
Merger costs(2) |
— |
0.28 |
0.14 |
1.56 |
|||
|
(Gain) loss on sale of assets, net |
0.01 |
0.05 |
(0.08) |
(0.27) |
|||
|
Amortization of deferred financing costs |
0.02 |
0.02 |
0.07 |
0.07 |
|||
|
Loss on debt extinguishment |
— |
— |
0.06 |
— |
|||
|
Other non-cash adjustments |
(0.02) |
0.11 |
(0.05) |
0.21 |
|||
|
Tax impact(3) |
(0.04) |
0.06 |
0.11 |
(0.19) |
|||
|
|
2.36 |
3.41 |
8.42 |
12.98 |
|||
|
Less: Distributed and undistributed earnings allocated to participating securities |
(0.01) |
(0.01) |
(0.04) |
(0.05) |
|||
|
|
$ 2.35 |
$ 3.40 |
$ 8.38 |
$ 12.93 |
|||
|
Diluted weighted average shares outstanding (in thousands) |
57,157 |
62,629 |
57,195 |
51,507 |
|||
|
Tax rate applicable to adjustment items(3) |
23.5 % |
26.1 % |
23.5 % |
25.2 % |
|||
|
_____________________ |
|
|
(1) |
Includes non-cash goodwill impairment charge of $539.3 million for the nine months ended September 30, 2025 as a result of the decline in the Company’s market capitalization during the second quarter of 2025. |
|
(2) |
Includes costs directly attributable to the arrangement with Enerplus for the three and nine months ended September 30, 2025 and 2024. |
|
(3) |
The tax impact is computed by applying an estimated tax rate to the adjustments for certain non-cash and non-recurring items. |
View original content to download multimedia:https://www.prnewswire.com/news-releases/chord-energy-reports-third-quarter-2025-financial-and-operating-results-declares-base-dividend-and-issues-updated-outlook-302604593.html
SOURCE Chord Energy
