Talos Energy Announces Third Quarter 2023 Operational and Financial Results

Source Press Release
Company Talos Energy Inc.Repsol 
Tags Exploration, Carbon Capture (CCS/CCUS), Hedging, Production/Development, Upstream Activities, Capital Spending, Guidance, Financial & Operating Data, Strategy - Corporate
Date November 06, 2023

Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its operational and financial results for fiscal quarter ended September 30, 2023.

Third Quarter 2023 Highlights:          

  • Production of 63.7 thousand barrels of oil equivalent per day ("MBoe/d") (76% oil, 83% liquids), inclusive of 2.4 MBoe/d of impacts from sustained loop currents requiring intermittent shut-ins of Talos's HP-1 floating production unit and associated infrastructure, as well as additional downtime.
  • Revenue of $383.1 million, driven by realized prices (excluding hedges) of $80.75 per barrel for oil, $17.02 per barrel for natural gas liquids ("NGLs"), and $2.81 per thousand cubic feet ("Mcf") for natural gas.
  • Net Loss of $2.1 million, or $0.02 Net Loss per diluted share, and Adjusted Net Income* of $18.6 million, or $0.15 Adjusted Net Income per diluted share*.
  • Adjusted EBITDA* of $248.8 million and Upstream Adjusted EBITDA* of $255.2 million.
  • Capital expenditures of $194.6 million, inclusive of plugging and abandonment and Carbon Capture & Sequestration ("CCS").
  • Net cash provided by operating activities of $65.7 million.
  • Adjusted Free Cash Flow* of $8.5 million, excluding the $74.85 million cash received at closing of the partial sale in Talos Energy Mexico 7, S. de R.L. de C.V. ("Talos Mexico") to an affiliate of Grupo Carso.

Talos President and Chief Executive Officer Timothy S. Duncan commented: "During the third quarter, we were pleased with the advancements we made on several aspects of our business. Our operations team is working hard on our Lime Rock and Venice discoveries, which are expected to come online as scheduled in early 2024. We have recently signed an important exploration agreement with Repsol, where we are pooling resources with the goal of developing an inventory of impactful wells that could be tied to existing Talos infrastructure. Additionally, we closed the Talos Mexico transaction with Grupo Carso and are encouraged about growing our partnership and progressing Zama toward FID and first oil. Our CCS portfolio continues to receive strong endorsement from the industry, as we welcomed Equinor as a partner with a 25% interest in Bayou Bend following its purchase from Carbonvert. Lastly, at Harvest Bend, we have several EPA Class VI permit applications in process."

Duncan continued: "Weather-related disruptions in the Gulf of Mexico typically impact our production and drilling operations during the third quarter of the year. This quarter, we experienced production downtime related to sustained loop currents in the Green Canyon area which impacted the floating production unit in our Phoenix Field. However, our oil-weighted assets continued to deliver strong realizations, with a netback margin of close to $45 per barrel of oil equivalent. As that production is restored and new developments are added, we look forward to positive momentum as we close out the year."

RECENT DEVELOPMENTS AND OPERATIONS UPDATE

Drilling Joint Venture: In November 2023, Talos and an affiliate of Repsol entered into a 50/50 partnership to conduct a seismic reprocessing project covering approximately 400,000 gross acres, of which 96,500 acres are under lease by Talos, in the deepwater Green Canyon and Atwater Valley areas of the U.S. Gulf of Mexico. The joint venture aims to identify future subsea tie-back exploitation and exploration prospects in the area using Talos's Neptune facility as the host platform.

Mexico Divestiture: In September 2023, Talos announced the closing of the sale of a 49.9% equity interest in Talos Mexico to an affiliate of Grupo Carso. Talos received $74.85 million in cash at closing, with an additional $49.90 million due upon first production, for an aggregate price of $124.75 million. Talos Mexico, now owned 50.1% by Talos and 49.9% by Grupo Carso, holds a 17.4% unitized interest in the Zama project.

Exploration and Production Updates:

Lime Rock and Venice: Completion, construction, and subsea installation operations for Talos's Lime Rock and Venice discoveries remain on track. The Company anticipates first production by early 2024 from both wells, which will be tied-backed to the Talos-owned and operated Ram Powell facility. Talos owns a 60% working interest in both wells.

Non-Operated Updates: Drilling of the Marmalard well, operated by Murphy Oil Corporation, was recently completed, finding pay sands in both field targets, and will be moving to completion operations in an effort to achieve first production in early 2024. Talos holds an 11.4% working interest. The Odd Job subsea pump project, operated by Kosmos Energy, intended to sustain long-term production from the field, continues to progress and remains on track to be in service by mid-2024. Talos holds a 17.5% working interest.

Downtime Updates: During the third quarter 2023, sustained loop currents requiring intermittent shut-ins of Talos's HP-1 floating production unit and associated infrastructure impacted production by approximately 2.4 MBoe/d for the quarter, or 0.8 MBoe/d for the full year 2023. On Talos's operated Neptune facility, Talos continues to work on optimization efforts, including new chemical treatments and topside modifications, expected to be completed in the fourth quarter 2023. The Claiborne #1 well, operated by Beacon Offshore Energy LLC, was shut-in early in the third quarter 2023, impacting production by approximately 1.2 MBoe/d. The operator is planning a rig intervention for the fourth quarter 2023 to reinstate production in the first quarter of 2024. Talos holds a 25.25% working interest.

TLCS Updates:

Stratigraphic Wells: The Bayou Bend CCS partnership expects to spud the Talos-operated offshore stratigraphic well during the fourth quarter 2023. As previously announced, the partnership also expects to drill a Chevron-operated onshore stratigraphic well in the first half 2024. Talos Low Carbon Solutions ("TLCS") also intends to drill its first stratigraphic wells at its Harvest Bend CCS and Coastal Bend CCS projects in 2024. 

Class VI Permits: TLCS's first EPA Class VI permit application filed in August 2023 for its Harvest Bend CCS project received administrative completeness status in October 2023. This first step of the EPA's permitting process determines that the permit application contains all required information. The next step is technical review. In October 2023, TLCS filed its second Class VI permit application for two additional wells at its Harvest Bend CCS project. TLCS aims to file additional Class VI permit applications in 2024 for its Bayou Bend CCS, Harvest Bend CCS,  and Coastal Bend CCS projects. 

Capital Raise: Talos continues to explore a capital raise in TLCS. The Company will provide further updates when available.

THIRD QUARTER 2023 RESULTS

Key Financial Highlights:

($ thousands, except per share and per BOE amounts)  Three Months Ended
September 30, 2023 
 
Total revenues  383,135   
Net Loss  (2,103)   
Net Loss per diluted share  (0.02)   
Adjusted Net Income*  18,565   
Adjusted Net Income per diluted share*  0.15   
Adjusted EBITDA*  248,817   
Adjusted EBITDA excluding hedges*  255,130   
Upstream Adjusted EBITDA*  255,228   
Upstream Adjusted EBITDA excluding hedges*  261,541   
Capital Expenditures (including Plug & Abandonment)  194,638   
Upstream Adjusted EBITDA Margin:     
Upstream Adjusted EBITDA per Boe*  43.59   
Upstream Adjusted EBITDA excluding hedges per Boe*  44.67   

Production

Production was 63.7 MBoe/d for the third quarter 2023 and was 76% oil and 83% liquids.

  Three Months Ended
September 30, 2023 
 
Average net daily production volumes     
Oil (MBbl/d)    48.4   
Natural Gas (MMcf/d)    65.3   
NGL (MBbl/d)    4.4   
Total average net daily (MBoe/d)    63.7   

  Three Months Ended September 30, 2023   
  Production    % Oil    % Liquids    % Operated   
Average net daily production volumes by Core Area (MBoe/d)                 
Green Canyon Area    20.8      84    90    87 
Mississippi Canyon Area    31.1      80    87    72 
Shelf and Gulf Coast    11.8      50    60    60 
Total average net daily (MBoe/d)    63.7      76    83    75 

Lease Operating & General and Administrative Expenses

Total lease operating expenses, inclusive of workover and maintenance and insurance costs for the quarter, were $103.5 million or $17.69/Boe. Upstream General and Administrative expenses* for the quarter, excluding non-cash equity-based compensation, was $20.7 million, or $3.54/Boe. Upstream General and Administrative expenses* is shown inclusive of $1.7 million in transaction-related expenses.

($ thousands, except per BOE amounts)  Three Months Ended
September 30, 2023 
  Per Boe   
Lease Operating Expenses  103,548    17.69   
Upstream General & Administrative Expenses (excluding non-cash equity-based compensation)*  20,711    3.54   

Capital Expenditures

Upstream capital expenditures, including plugging and abandonment and settled decommissioning obligations, totaled $180.5 million for the third quarter 2023.

($ thousands)  Three Months Ended
September 30, 2023 
  Nine Months Ended
September 30, 2023 
 
Upstream Capital Expenditures         
U.S. drilling & completions  85,239    317,900   
Mexico appraisal & exploration    94      291   
Asset management(1)    20,949      81,677   
Seismic and G&G, land, capitalized G&A and other    12,448      48,493   
Total Upstream Capital Expenditures    118,730      448,361   
Plugging & Abandonment    23,414      71,097   
Decommissioning Obligations Settled(2)    38,368      40,415   
Total Upstream  180,512    559,873   

   
(1)  Asset management consists of capital expenditures for development-related activities primarily associated with recompletions and improvements to our facilities and infrastructure. 
(2)  Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. 

CCS expenses totaled $5.0 million for the third quarter 2023, which is accounted for in the Company's reported Adjusted EBITDA* figure. CCS capital expenditures totaled $14.1 million for the third quarter 2023, which mainly includes investments in Bayou Bend and funding for general ongoing operations.

($ thousands)  Three Months Ended
September 30, 2023 
  Nine Months Ended
September 30, 2023 
 
CCS Investments         
CCS Expenses  5,045    13,562   
CCS Capital Expenditures    14,126      37,183   
Total CCS Investments  19,171    50,745   

Liquidity and Leverage

At September 30, 2023, Talos had approximately $752.9 million of liquidity, with $750.0 million undrawn on its credit facility and approximately $13.6 million in cash, less approximately $10.8 million in outstanding letters of credit.

On September 30, 2023, Talos had $1,096.0 million in total debt. Net Debt* was $1,082.4 million. Net Debt to Pro Forma Last Twelve Months ("LTM") Adjusted EBITDA* was 1.1x.

Footnotes:

*See "Supplemental Non-GAAP Information" for details and reconciliations of GAAP to non-GAAP financial measures.

OPERATIONAL & FINANCIAL GUIDANCE UPDATES

For the fourth quarter 2023, Talos expects average daily production of 66.5 - 68.5 MBoe/d.

    Fourth Quarter 2023   
    Low    High   
Production  Oil (MMBbl)    4.5      4.6   
  Natural Gas (Mcf)    7.2      7.4   
  NGL (MMBbl)    0.4      0.4   
  Total Production (MMBoe)    6.1      6.3   
  Avg Daily Production (MBoe/d)    66.5      68.5   

For the full year 2023, Talos's average daily production per day is projected toward the low end of the current guidance of 66.0 - 71.0 MBoe/d given the fourth quarter 2023 production guidance update,

Cash operating expenses and general and administrative expenses are expected towards the low end of the current range of $410 - $430 million and $90 - $95 million, respectively.

Overall, capital expenditures, inclusive of plugging and abandonment, settled decommissioning obligations, and CCS Investments are projected to be in line with the current total guidance range. Specifically, Upstream capital expenditures are expected towards the low end of the current guided range of $650 - $675 million and CCS Investments are projected at or below the low end of the current range of $70 - $90 million. Plugging and abandonment and decommissioning spending for the full year 2023 is now estimated to be $120 - $130 million.

Note: Due to the forward-looking nature a reconciliation of Cash Operating Expenses and G&A to the most directly comparable GAAP measure could not reconciled without unreasonable efforts.

HEDGES

The following table reflects contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of November 6, 2023:

  Instrument Type  Avg. Daily
Volume 
  W.A. Swap    W.A. Sub-
Floor 
  W.A. Floor    W.A. Ceiling   
Crude – WTI    (Bbls)    (Per Bbl)    (Per Bbl)    (Per Bbl)    (Per Bbl)   
October - December 2023  Fixed Swaps    12,000    75.25    ---    ---    ---   
October - December 2023  Collar    7,826    ---    ---    67.76    86.40   
October - December 2023  3-Way Collar    9,200    ---    51.86    65.11    109.25   
January - March 2024  Fixed Swaps    18,000    73.98    ---    ---    ---   
January - March 2024  Collar    3,000    ---    ---    70.00    83.67   
January - March 2024  3-Way Collar    3,200    ---    57.27    70.00    98.01   
April - June 2024  Fixed Swaps    21,500    73.86    ---    ---    ---   
April - June 2024  Collar    1,000    ---    ---    70.00    75.00   
July - September 2024  Fixed Swaps    13,000    75.48    ---    ---    ---   
July - September 2024  Collar    1,000    ---    ---    70.00    75.00   
October - December 2024  Fixed Swaps    12,000    74.65    ---    ---    ---   
October - December 2024  Collar    1,000    ---    ---    70.00    75.00   
January - March 2025  Fixed Swaps    10,000    71.97    ---    ---    ---   
April - June 2025  Fixed Swaps    6,000    75.28    ---    ---    ---   
July - September 2025  Fixed Swaps    6,000    75.28    ---    ---    ---   
October - December 2025  Fixed Swaps    6,000    75.28    ---    ---    ---   
                       
Natural Gas – HH NYMEX    (MMBtu)    (Per MMBtu)    (Per MMBtu)    (Per MMBtu)    (Per MMBtu)   
October - December 2023  Fixed Swaps    20,000    4.22    ---    ---    ---   
October - December 2023  Collar    10,000    ---    ---    5.25    8.46   
January - March 2024  Fixed Swaps    25,000    3.48    ---    ---    ---   
January - March 2024  Collar    10,000    ---    ---    4.00    6.90   
April - June 2024  Fixed Swaps    25,000    3.33    ---    ---    ---   
April - June 2024  Collar    10,000    ---    ---    4.00    6.90   
July - September 2024  Fixed Swaps    10,000    3.52    ---    ---    ---   
July - September 2024  Collar    10,000    ---    ---    4.00    6.90   
October - December 2024  Fixed Swaps    10,000    3.52    ---    ---    ---   
October - December 2024  Collar    10,000    ---    ---    4.00    6.90   
January - March 2025  Fixed Swaps    20,000    4.14    ---    ---    ---   
April - June 2025  Fixed Swaps    10,000    3.91    ---    ---    ---   
July - September 2025  Fixed Swaps    10,000    3.91    ---    ---    ---   
October - December 2025  Fixed Swaps    10,000    3.91    ---    ---    ---   

CONFERENCE CALL AND WEBCAST INFORMATION 

Talos will host a conference call, which will be broadcast live over the internet, on Tuesday, November 7, 2023 at 10:00 AM Eastern Time (9:00 AM Central Time). Listeners can access the conference call through a webcast link on the Company's website at: https://www.talosenergy.com/investor-relations/events-calendar/default.aspx. Alternatively, the conference call can be accessed by dialing (888) 348-8927 (U.S. toll-free), (855) 669-9657 (Canada toll-free) or (412) 902-4263 (international). Please dial in approximately 15 minutes before the teleconference is scheduled to begin and ask to be joined into the Talos Energy call. A replay of the call will be available one hour after the conclusion of the conference until November 14, 2023 and can be accessed by dialing (877) 344-7529 and using access code 4883529.

Talos Energy Inc. Consolidated Balance Sheets (In thousands, except share amounts)   
   
  September 30, 2023    December 31, 2022   
  (Unaudited)       
ASSETS         
Current assets:         
Cash and cash equivalents  13,631    44,145   
Accounts receivable:         
Trade, net    181,384      150,598   
Joint interest, net    93,798      54,697   
Other, net    10,744      6,684   
Assets from price risk management activities    11,497      25,029   
Prepaid assets    86,077      84,759   
Other current assets    14,457      1,917   
Total current assets    411,588      367,829   
Property and equipment:         
Proved properties    7,691,828      5,964,340   
Unproved properties, not subject to amortization    267,297      154,783   
Other property and equipment    33,795      30,691   
Total property and equipment    7,992,920      6,149,814   
Accumulated depreciation, depletion and amortization    (3,985,613)      (3,506,539)   
Total property and equipment, net    4,007,307      2,643,275   
Other long-term assets:         
Restricted cash    101,760      —   
Assets from price risk management activities    4,550      7,854   
Equity method investments    141,682      1,745   
Other well equipment inventory    44,643      25,541   
Notes receivable, net    15,805      —   
Operating lease assets    12,313      5,903   
Other assets    13,452      6,479   
Total assets  4,753,100    3,058,626   
LIABILITIES AND STOCKHOLDERSʼ EQUITY         
Current liabilities:         
Accounts payable  125,557    128,174   
Accrued liabilities    205,095      219,769   
Accrued royalties    54,092      52,215   
Current portion of long-term debt    33,109      —   
Current portion of asset retirement obligations    69,288      39,888   
Liabilities from price risk management activities    55,042      68,370   
Accrued interest payable    30,536      36,340   
Current portion of operating lease liabilities    2,859      1,943   
Other current liabilities    54,221      60,359   
Total current liabilities    629,799      607,058   
Long-term liabilities:         
Long-term debt    1,018,774      585,340   
Asset retirement obligations    747,560      501,773   
Liabilities from price risk management activities    8,981      7,872   
Operating lease liabilities    18,888      14,855   
Other long-term liabilities    267,036      176,152   
Total liabilities    2,691,038      1,893,050   
Commitments and contingencies         
Stockholdersʼ equity:         
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding
as of September 30, 2023 and December 31, 2022 
  —      —   
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares
issued as of September 30, 2023 and December 31, 2022, respectively 
  1,275      826   
Additional paid-in capital    2,541,906      1,699,799   
Accumulated deficit    (433,615)      (535,049)   
Treasury stock, at cost; 3,400,000 and zero shares as of September 30, 2023 and December 31,
2022, respectively 
  (47,504)      —   
Total stockholdersʼ equity    2,062,062      1,165,576   
Total liabilities and stockholdersʼ equity  4,753,100    3,058,626   

Talos Energy Inc. Consolidated Statements of Operations (In thousands, except per share amounts) (Unaudited)   
   
  Three Months Ended September 30,    Nine Months Ended September 30,   
  2023    2022    2023    2022   
Revenues:                 
Oil  359,404    295,585    995,081    1,078,800   
Natural gas    16,871      68,360      53,383      181,747   
NGL    6,860      13,183      24,463      49,232   
Total revenues    383,135      377,128      1,072,927      1,309,779   
Operating expenses:                 
Lease operating expense    103,548      81,760      286,075      229,156   
Production taxes    600      955      1,813      2,670   
Depreciation, depletion and amortization    163,359      92,323      480,476      295,174   
Accretion expense    21,256      13,179      63,430      42,400   
General and administrative expense    24,888      25,289      121,257      70,742   
Other operating (income) expense    (57,287)      (366)      (55,172)      12,142   
Total operating expenses    256,364      213,140      897,879      652,284   
Operating income (expense)    126,771      163,988      175,048      657,495   
Interest expense    (45,637)      (29,265)      (128,850)      (91,531)   
Price risk management activities income (expense)    (98,802)      114,180      (13,668)      (231,133)   
Equity method investment income (expense)    (2,493)      991      2,938      14,599   
Other income (expense)    2,193      692      10,450      31,991   
Net income (loss) before income taxes    (17,968)      250,586      45,918      381,421   
Income tax benefit (expense)    15,865      (121)      55,516      (2,256)   
Net income (loss)  (2,103)    250,465    101,434    379,165   
                 
Net income (loss) per common share:                 
Basic  (0.02)    3.03    0.86    4.60   
Diluted  (0.02)    2.99    0.85    4.54   
Weighted average common shares outstanding:                 
Basic    124,103      82,576      118,459      82,406   
Diluted    124,103      83,818      119,262      83,438   

Talos Energy Inc. Consolidated Statements of Cash Flows (In thousands) (Unaudited) 
 
  Nine Months Ended September 30,   
  2023    2022   
Cash flows from operating activities:         
Net income (loss)  101,434    379,165   
Adjustments to reconcile net income to net cash provided by operating activities:         
Depreciation, depletion, amortization and accretion expense    543,906      337,574   
Amortization of deferred financing costs and original issue discount    11,247      10,614   
Equity-based compensation expense    9,080      11,677   
Price risk management activities (income) expense    13,668      231,133   
Net cash received (paid) on settled derivative instruments    (10,474)      (368,483)   
Equity method investment (income) expense    (2,938)      (14,599)   
Settlement of asset retirement obligations    (71,097)      (60,304)   
(Gain) loss on sale of assets    (66,115)      390   
Changes in operating assets and liabilities:         
Accounts receivable    3,821      23,783   
Other current assets    (12,992)      (28,576)   
Accounts payable    (30,063)      16,677   
Other current liabilities    (89,511)      (6,682)   
Other non-current assets and liabilities, net    (57,155)      6,559   
Net cash provided by (used in) operating activities    342,811      538,928   
Cash flows from investing activities:         
Exploration, development and other capital expenditures    (438,506)      (209,592)   
Proceeds from (cash paid for) acquisitions, net of cash acquired    17,617      (3,500)   
Proceeds from (cash paid for) sale of property and equipment, net    66,183      1,690   
Contributions to equity method investees    (29,372)      (2,250)   
Proceeds from sale of equity method investments    —      15,000   
Investment in intangible assets    (7,796)      —   
Net cash provided by (used in) investing activities    (391,874)      (198,652)   
Cash flows from financing activities:         
Redemption of senior notes    (15,000)      (6,060)   
Proceeds from Bank Credit Facility    675,000      35,000   
Repayment of Bank Credit Facility    (460,000)      (350,000)   
Deferred financing costs    (11,775)      (211)   
Other deferred payments    (841)      —   
Payments of finance lease    (12,117)      (19,764)   
Purchase of treasury stock    (47,504)      —   
Employee stock awards tax withholdings    (7,454)      (4,603)   
Net cash provided by (used in) financing activities    120,309      (345,638)   
         
Net increase (decrease) in cash, cash equivalents and restricted cash    71,246      (5,362)   
Cash, cash equivalents and restricted cash:         
Balance, beginning of period    44,145      69,852   
Balance, end of period  115,391    64,490   
         
Supplemental non-cash transactions:         
Capital expenditures included in accounts payable and accrued liabilities  90,688    78,191   
Supplemental cash flow information:         
Interest paid, net of amounts capitalized  108,931    89,187   

SUPPLEMENTAL NON-GAAP INFORMATION 

Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP. These non-GAAP financial measures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP measures which may be reported by other companies.

Reconciliation of General and Administrative Expenses to Upstream General and Administrative Expenses

We believe the presentation of Upstream General and Administrative Expenses excluding non-cash equity-based compensation provides management and investors with (i) important supplemental indicators of the operational performance of our core upstream business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Upstream General & Administrative Expenses has limitations as an analytical tool and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to general and administrative expenses, net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following:

General and Administrative Expenses. General and administrative expenses consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment.

Upstream General and Administrative Expenses. Upstream general and administrative expenses consist of general and administrative expenses for the Upstream Segment.

($ thousands)  Three Months Ended
September 30, 2023 
 
Reconciliation of General & Administrative Expenses to Upstream General & Administrative Expenses
(excluding non-cash equity-based compensation): 
   
Total General and administrative expense  24,888   
CCS Segment    (2,472)   
Unallocated corporate    (1,362)   
Non-cash equity-based compensation expense    (343)   
Upstream General & Administrative Expenses (excluding non-cash equity-based compensation)  20,711   

Reconciliation of Net Income (Loss) to EBITDA, Adjusted EBITDA and Upstream Adjusted EBITDA"

EBITDA," "Adjusted EBITDA" and "Upstream Adjusted EBITDA" provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA, Adjusted EBITDA, and Upstream Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following:

EBITDA. Net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion and amortization; and accretion expense.

Adjusted EBITDA. EBITDA plus non-cash write-down of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, derivative fair value (gain) loss, net cash receipts (payments) on settled derivatives, (gain) loss on debt extinguishment, non-cash write-down of other well equipment inventory and non-cash equity-based compensation expense.

Adjusted EBITDA excluding hedges. We have historically provided as a supplement to—rather than in lieu of—Adjusted EBITDA including hedges, provides useful information regarding our results of operations and profitability by illustrating the operating results of our oil and natural gas properties without the benefit or detriment, as applicable, of our financial oil and natural gas hedges. By excluding our oil and natural gas hedges, we are able to convey actual operating results using realized market prices during the period, thereby providing analysts and investors with additional information they can use to evaluate the impacts of our hedging strategies over time.

Upstream Adjusted EBITDA. Adjusted EBITDA plus equity method investment loss, general and administrative expense, other operating expenses (income), other income, and non-cash equity-based compensation expense attributable to CCS and unallocated corporate costs.

We also present Adjusted EBITDA excluding hedges and Upstream Adjusted EBITDA excluding hedges as a percentage of revenue and on a per barrel of oil equivalent basis, respectively, to further analyze our business, which are outlined below:

Adjusted EBITDA Margin and Upstream Adjusted EBITDA Margin. Adjusted EBITDA divided by Revenue, as a percentage. It is also defined as Upstream Adjusted EBITDA divided by the total production volume, expressed in Boe, in the period, and described as dollar per Boe. We believe the presentation of Adjusted EBITDA margin is important to provide management and investors with information about how much we retain in Adjusted EBITDA terms as compared to the revenue we generate and how much per barrel of Upstream Adjusted EBITDA we generate after accounting for certain operational and corporate costs.

The following tables present a reconciliation of the GAAP financial measure of Net Income (loss) to EBITDA, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA Margin and Adjusted EBITDA Margin excluding hedges, and Upstream Adjusted EBITDA, Upstream Adjusted EBITDA excluding hedges, Upstream Adjusted EBITDA Margin, and Upstream Adjusted EBITDA Margin excluding hedges for each of the periods indicated (in thousands, except for Boe, $/Boe and percentage data):

  Three Months Ended   
($ thousands)  September 30,
2023 
  June 30,
2023 
  March 31,
2023 
  December 31,
2022 
 
Reconciliation of Net Income (Loss) to Adjusted EBITDA:                 
Net Income (loss)  (2,103)    13,677    89,860    2,750   
Interest expense    45,637      45,632      37,581      33,967   
Income tax expense (benefit)    (15,865)      6,892      (46,543)      281   
Depreciation, depletion and amortization    163,359      169,794      147,323      119,456   
Accretion expense    21,256      22,760      19,414      13,595   
EBITDA    212,284      258,755      247,635      170,049   
Transaction and other (income) expenses(1)    (64,321)      3,513      22,009      4,343   
Decommissioning obligations(2)    7,972      741      741      21,005   
Derivative fair value (gain) loss(3)    98,802      (26,197)      (58,937)      41,058   
Net cash received (paid) on settled derivative instruments(3)    (6,313)      8,162      (12,323)      (57,076)   
Loss on extinguishment of debt    —      —      —      1,569   
Non-cash equity-based compensation expense    393      4,749      3,938      4,276   
Adjusted EBITDA    248,817      249,723      203,063      185,224   
Add: Net cash (received) paid on settled derivative instruments(3)    6,313      (8,162)      12,323      57,076   
Adjusted EBITDA excluding hedges  255,130    241,561    215,386    242,300   
Revenue:                 
Revenue - Operations    383,135      367,210      322,582      342,201   
Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin:                 
Adjusted EBITDA divided by - Total revenue incl hedges (%)    66    67    65    65 
Adjusted EBITDA divided by - Total revenue (%)    67    66    67    71 

   
(1)  For the three months ended September 30, 2023, transaction expenses include $1.5 million in costs related to the EnVen Acquisition, inclusive of $0.9 million in severance expense. For the three months ended June 30, 2023, transaction expenses include $2.7 million in costs related to the EnVen Acquisition, inclusive of $1.4 million in severance expense. For the three months ended March 31, 2023, transaction expenses include $35.2 million in costs related to the EnVen Acquisition, inclusive of $22.6 million in severance expense. Transaction expenses are included in "General and administrative expense" on our consolidated statements of operations. Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended September 30, 2023, it includes a $66.2 million gain on the Mexico divestiture. For the three months ended March 31, 2023, it includes a $8.6 million gain on the funding of the capital carry of its investment in Bayou Bend by Chevron that is included in "Equity method investment income (expense)" on our consolidated statements of operations. 
(2)  Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency and are included in "Other operating (income) expense" on our consolidated statements of operations. 
(3)  The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. 

($ thousands, except per BOE amounts)  Three Months Ended
September 30, 2023 
 
Reconciliation of Adjusted EBITDA to Upstream Adjusted EBITDA:     
Adjusted EBITDA  248,817   
CCS and Corporate Unallocated Costs:     
Equity method investment loss    2,611   
General and administrative expense    3,835   
Other operating expense    127   
Other income    (5)   
Transaction and other income (expenses)(1)    (106)   
Non-cash equity-based compensation expense    (51)   
Upstream Adjusted EBITDA    255,228   
Add: Net cash paid on settled derivative instruments(2)    6,313   
Upstream Adjusted EBITDA excluding hedges  261,541   
Production:     
Boe(3)    5,855   
Upstream Adjusted EBITDA margin and Upstream Adjusted EBITDA excl hedges margin:     
Upstream Adjusted EBITDA per Boe(3)  43.59   
Upstream Adjusted EBITDA excl hedges per Boe(2)(3)  44.67   

   
(1)  Transaction and other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. 
(2)  The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. 
(3)  One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. 

Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow and Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow"

Adjusted Free Cash Flow" before changes in working capital provides management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Free Cash Flow has limitations as an analytical tool and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following:

Capital Expenditures and Plugging & Abandonment. Actual capital expenditures and plugging & abandonment recognized in the quarter, inclusive of accruals.

Interest Expense. Actual interest expense per the income statement.

Talos did not pay any cash income taxes in the period, therefore cash income taxes have no impact to the reported Adjusted Free Cash Flow before changes in working capital number.

($ thousands)  Three Months Ended
September 30, 2023 
 
Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow (before changes in working capital):     
Adjusted EBITDA  248,817   
Upstream capital expenditures    (118,730)   
Plugging & abandonment    (23,414)   
Decommissioning obligations settled    (38,368)   
CCS capital expenditures    (14,126)   
Interest expense    (45,637)   
Adjusted Free Cash Flow (before changes in working capital)  8,542   
 
($ thousands)  Three Months Ended
September 30, 2023 
 
Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow (before
changes in working capital): 
   
Net cash provided by operating activities(1)  65,728   
(Increase) decrease in operating assets and liabilities    126,248   
Upstream capital expenditures(2)    (118,730)   
Decommissioning obligations settled    (38,368)   
CCS capital expenditures    (14,126)   
Transaction and other (income) expenses(3)    1,859   
Decommissioning obligations(4)    7,972   
Amortization of deferred financing costs and original issue discount    (3,618)   
Income tax benefit    (15,865)   
Other adjustments    (2,558)   
Adjusted Free Cash Flow (before changes in working capital)  8,542   

   
(1)  Includes settlement of asset retirement obligations. 
(2)  Includes accruals and excludes acquisitions. 
(3)  The transaction expenses include $1.5 million in costs related to the EnVen Acquisition, inclusive of $0.9 million in severance expense. Other income (expenses) includes miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. 
(4)  Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. 

Reconciliation of Net Income to Adjusted Net Income (Loss) and Adjusted Earnings per Share"

Adjusted Net Income (Loss)" and "Adjusted Earnings per Share" are to provide management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Net Income (Loss) and Adjusted Earnings per Share have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), earnings per share or any other measure of financial performance presented in accordance with GAAP.

Adjusted Net Income (Loss). Net income (loss) plus accretion expense, transaction related costs, derivative fair value (gain) loss, net cash receipts (payments) on settled derivative instruments and non-cash equity-based compensation expense.

Adjusted Earnings per Share. Adjusted Net Income (Loss) divided by the number of common shares.

  Three Months Ended
September 30, 2023 
 
($ thousands, except per share amounts)      Basic per Share    Diluted per Share   
Reconciliation of Net Loss to Adjusted Net Income:             
Net Loss  (2,103)    (0.02)    (0.02)   
Transaction and other (income) expenses(1)    (64,321)    (0.52)    (0.51)   
Decommissioning obligations(2)    7,972    0.06    0.06   
Derivative fair value loss(3)    98,802    0.80    0.79   
Net cash received on paid derivative instruments(3)    (6,313)    (0.05)    (0.05)   
Non-cash income tax benefit    (15,865)    (0.13)    (0.13)   
Non-cash equity-based compensation expense    393    0.00    0.00   
Adjusted Net Income(4)  18,565    0.15    0.15   
             
Weighted average common shares outstanding at September 30, 2023:             
Basic    124,103           
Diluted    124,964           

   
(1)  The transaction expenses include $1.5 million in costs related to the EnVen Acquisition, inclusive of $0.9 million in severance expense. Other income (expenses) includes miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. It includes a $66.2 million gain on the Mexico divestiture. 
(2)  Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. 
(3)  The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted Net Income (Loss) on an unrealized basis during the period the derivatives settled. 
(4)  The per share impacts reflected in this table were calculated independently and may not sum to total adjusted basic and diluted EPS due to rounding. 

Reconciliation of Total Debt to Net Debt and Net Debt to LTM Adjusted EBITDA

We believe the presentation of Net Debt, LTM Adjusted EBITDA, and Net Debt to LTM Adjusted EBITDA is important to provide management and investors with additional important information to evaluate our business. These measures are widely used by investors and ratings agencies in the valuation, comparison, rating and investment recommendations of companies.

Net Debt. Total Debt principal minus cash and cash equivalents.

Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA.

($ thousands)  September 30, 2023   
Reconciliation of Net Debt:     
12.00% Second-Priority Senior Secured Notes – due January 2026  638,541   
11.75% Senior Secured Second Lien Notes – due April 2026    242,500   
Bank Credit Facility – matures March 2027    215,000   
Total Debt    1,096,041   
Less: Cash and cash equivalents    (13,631)   
Net Debt  1,082,410   
     
Calculation of LTM Adjusted EBITDA:     
Adjusted EBITDA for three months period ended December 30, 2022  185,224   
Adjusted EBITDA for three months period ended March 31, 2022    203,063   
Adjusted EBITDA for three months period ended June 30, 2023    249,723   
Adjusted EBITDA for three months period ended September 30, 2023    248,817   
LTM Adjusted EBITDA  886,827   
     
Acquired Assets Adjusted EBITDA:     
Adjusted EBITDA for three months period ended December 31, 2022    73,891   
Adjusted EBITDA for the period January 1, 2023 to February 13, 2023    33,120   
LTM Adjusted EBITDA from Acquired Assets  107,011   
     
Pro Forma LTM Adjusted EBITDA  993,838   
     
Reconciliation of Net Debt to Pro Forma LTM Adjusted EBITDA:     
Net Debt / Pro Forma LTM Adjusted EBITDA(1)  1.1x   

   
(1)  Net Debt / Pro Forma LTM Adjusted EBITDA figure excludes the Finance Lease. Had the Finance Lease been included, Net Debt / Pro Forma LTM Adjusted EBITDA would have been 1.2x. 

Source: EvaluateEnergy® ©2024 EvaluateEnergy Ltd