HOUSTON, Nov. 6, 2019 /PRNewswire/ -- Talos Energy Inc. ("Talos," or the "Company") (NYSE: TALO) today announced its financial and operational results for the third quarter of 2019 and provided an operations update.
Key third quarter highlights include:
- Production of 52.6 thousand barrels of oil equivalent per day ("MBoe/d"), or 4.8 million barrels of oil equivalent ("MMBoe") in total, of which 73% was oil and 80% was liquids. As previously disclosed, third quarter production was impacted by Hurricane Barry, resulting in the deferral of approximately 4.0 MBoe/d.
- Revenue(1) of $228.9 million and average realized prices of $59.54/Bbl of oil and $2.12/Mcf of natural gas, net of deductions. 93% of operating revenues were derived from oil production and reflect a significant realized price premium, which is net of transport and quality deductions, of $3.09/Bbl above the average WTI benchmark price of $56.45/Bbl during the same period.
- Net Income of $73.3 million ($1.35 earnings per share - diluted) and Adjusted Net Income(2) of $44.3 million ($0.81 adjusted earnings per share - diluted).
- Adjusted EBITDA(2) of $157.8 million and Adjusted EBITDA excluding hedges(2) of $152.4 million. Adjusted EBITDA Margin(2) per Boe of $32.57, or 69%, and Adjusted EBITDA Margin excluding hedges(2) per Boe of $31.47, or 67%.
- Capital expenditures of $115.8 million, including investment of $99.7 million in the U.S. Gulf of Mexico and $16.1 million in offshore Mexico.
- As of September 30, 2019, liquidity position of $612.1 million. Net Debt to Last Twelve Months ("LTM") Adjusted EBITDA(2) was 1.1x.
- In the third quarter of 2019, the Company had a successful discovery in offshore Mexico Block 31, executed two separate exploration transactions with BP and ExxonMobil, respectively, and drilled and completed its Grand Isle 82 A-22 exploration well, which achieved first production in October 2019.
- The Company was added to the S&P SmallCap 600 Index on November 1, 2019. Talos was included in the Index as one of just 19 exploration and production companies and was the sixth largest by market capitalization amongst the Energy Sector designated companies. Talos was also included in the S&P SmallCap 600 GICS Oil and Gas Exploration and Production Sub-Industry Index.
(1) | Includes $1.0 million of federal royalty refund. |
(2) | Adjusted Net Income, Adjusted Earnings per Share, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA Margin and Adjusted EBITDA Margin excluding hedges and Net Debt to LTM Adjusted EBITDA are non-GAAP financial measures. See "Supplemental Non-GAAP Information" below for additional detail and reconciliations of GAAP to non-GAAP measures. |
President and Chief Executive Officer Timothy S. Duncan commented: "I am proud of our team for achieving another positive earnings quarter, bolstered by another period of generating significant free cash flow in our U.S. Gulf of Mexico business. Our focus on investing in opportunities around core infrastructure that we own or operate continues to allow us to achieve top quartile net back margins, which are enhanced by better than expected results of our cost control initiatives throughout 2019. We also continue to balance those investments with high impact exploration projects, including more success in offshore Mexico.
As we begin to focus on our 2020 drilling campaign, success in our Bulleit project and acceleration of first oil at Orlov provide a strong foundation, with additional potential upside from our exploration activities related to our recent Puma West and Hershey transactions. Among other activities, we plan to execute a platform rig contract for a near-field drilling program around assets we acquired in the past year and we look forward to progressing our offshore Mexico discoveries closer to final investment decisions.
We believe our strategy of combining low entry cost M&A with field development upside and high impact exploration, while also maintaining a prudent financial and conservative leverage profiles and strong free cash flow generation, allows us to grow equity value while maintaining a strong balance sheet. We are excited about the direction of the Company moving forward."
RECENT DEVELOPMENTS AND OPERATIONS UPDATE
Drilling and Exploration Activities - U.S. Gulf of Mexico
- Puma West Prospect: Talos entered an agreement with BP to drill the Puma West prospect located on Green Canyon Block 821. BP is the operator of the prospect holding a 50% working interest, Talos retained a 25% working interest, and Chevron now also has a 25% working interest. The Puma West well is being drilled by the Seadrill West Auriga ultra-deepwater drillship and was spud in October, targeting Miocene sands similar to those seen in the Mad Dog development located less than 15 miles away.
- Bulleit Prospect: As previously disclosed, the Green Canyon Block 21 Bulleit exploration well encountered approximately 140 feet of net true vertical depth ("TVD") oil pay in the shallow target, the DTR-10 Sand, and approximately 110 feet of net TVD oil pay in the deeper MP Sand. Talos expects first production in the third quarter of 2020 with a possible initial flow rate of 7.0 - 10.0 MBoe/d gross, 2.8 - 4.0 MBoe/d net. Talos holds a 50.0% working interest in the Bulleit prospect and is the operator, with EnVen and Otto Energy holding 33.3% and 16.7% working interests, respectively.
- Orlov Prospect: After successfully discovering oil pay in the main target Aspen J sand in the Green Canyon 200 Orlov project, the operator, Fieldwood Energy, is finalizing drilling operations and plans to complete the well by year end. Talos expects that the project could produce 7.0 - 10.0 MBoe/d gross, 1.8 - 2.5 MBoe/d net with first production recently accelerated and now expected in early first quarter of 2020. Talos owns a 30% working interest in the project.
- Hershey Prospect: Talos acquired a 100% working interest and operatorship of Green Canyon Blocks 326, 327, 370 and 371, constituting approximately 23,000 gross acres. The Hershey prospect is targeting a potential large sub-salt Miocene accumulation with potential oil-weighted, gross unrisked resources of 100 - 300 MMBoe. Consideration for the transaction is 100% contingent-based and the agreement contains no well commitment. Talos expects to initiate a process to sell-down a portion of its working interest in the project in the fourth quarter of 2019.
- 2020 Rig Contracts: In advance of the Company's 2020 drilling and completions program, Talos is finalizing contractual terms with two drilling contractors following a competitive bidding process. One contractor is expected to provide a deepwater drillship to be used for the Company's deepwater exploration and exploitation activities. The second contractor is expected to provide a platform rig to be used for near-field drilling opportunities in assets that were acquired over the last 18 months, starting with our Green Canyon 18 asset in the first quarter of 2020, with the option of subsequently moving to our Pompano and Amberjack assets in our Mississippi Canyon core area in the fourth quarter of 2020.
Drilling and Exploration Activities - Mexico
- Block 7: Following the successful completion of the Zama appraisal program, Talos is working with Netherland, Sewell & Associates, Inc. to complete a formal resource report by year end 2019. The Company reiterates its previously stated resource guidance in the upper half of its pre-appraisal estimated range of 400 - 800 MMBoe gross recoverable resources. Talos has initiated early FEED work to allow for the earliest possible initial production date and is utilizing all of the appraisal data to create an optimal development plan for the field. Zama unitization discussions with Petróleos Mexicanos ("Pemex") are ongoing. As previously announced in September 2019, the Company was also recently granted a two-year contract term extension as well as regulatory approvals to allow for exploration activities on additional retained acreage in Block 7, which is separate and incremental to the Zama asset.
- Block 31: The Block 31 exploration project consisted of two wells, Xaxamani-2EXP and Tolteca-1EXP, both drilled in the third quarter of 2019. The Xaxamani-2EXP well logged approximately 148 feet (45 meters) of gross TVD pay, with a net to gross ratio of approximately 78% in two shallow oil sands. Subsequently, the Tolteca-1EXP well logged approximately 123 feet (37 meters) of gross TVD pay, with a net to gross ratio of approximately 97%, all located in the deeper of the two sands found in the Xaxamani-2EXP well. The Tolteca-1EXP well expected to find an oil-water contact but logged hydrocarbons "full to base," exceeding pre-drill expectations for reservoir thickness and areal extent, thereby increasing resource expectations not only in the drilling program to date, but also increasing expectations of similar geophysical anomalies that could open up a shallow oil play in the contract area.
The Xaxamani discovery is located approximately one mile from shore in less than 100 feet of water. Talos holds a 25% working interest in Block 31. Since 2017, Talos has now drilled or participated in eight wells in offshore Mexico, including five exploration wells, resulting in two material oil discoveries.
Derivatives Activities
- Derivatives Update: The following table reflects the contracted volumes and weighted average prices the Company will receive under its derivative contracts as of September 30, 2019. During the third quarter of 2019, Talos hedged additional fourth quarter 2019 and fiscal year 2020 oil production of 1,967,500 Bbls and natural gas production of 2,750,000 MMBtu. The weighted average prices the Company will receive under these West Texas Intermediate and Henry Hub swap contracts are $55.40 per Bbl and $2.45 per MMBtu, respectively.
Production Period | Instrument Type | Average Daily Volumes | Weighted Average Swap Price | Weighted Average Put Price | Weighted Average Call Price | |||||||||||||
Crude Oil - WTI: | (Bbls) | (per Bbl) | (per Bbl) | (per Bbl) | ||||||||||||||
Oct 2019 - Dec 2019 | Swap | 29,468 | $ | 56.04 | $ | - | $ | - | ||||||||||
Jan 2020 - Dec 2020 | Swap | 13,492 | $ | 56.13 | $ | - | $ | - | ||||||||||
Jan 2020 - Dec 2020 | Costless collars | 7,481 | $ | - | $ | 55.00 | $ | 64.23 | ||||||||||
Natural Gas - Henry Hub NYMEX: | (MMBtu) | (per MMBtu) | (per MMBtu) | (per MMBtu) | ||||||||||||||
Oct 2019 - Dec 2019 | Swap | 37,475 | $ | 2.92 | $ | - | $ | - | ||||||||||
Jan 2020 - Dec 2020 | Swap | 16,216 | $ | 2.78 | $ | - | $ | - | ||||||||||
THIRD QUARTER 2019 RESULTS | |||
Key Financial Highlights: | |||
Period results ($ million): | |||
Revenues(1) | $ | 228.9 | |
Net Income | $ | 73.3 | |
Earnings per share - diluted | $ | 1.35 | |
Adjusted Net Income(2) | $ | 44.3 | |
Adjusted Earnings per share - diluted(2) | $ | 0.81 | |
Adjusted EBITDA(2) | $ | 157.8 | |
Adjusted EBITDA excl. hedges(2) | $ | 152.4 | |
Capital Expenditures (including Plug & Abandonment) | $ | 115.8 | |
Adjusted EBITDA Margin(2): | |||
Adjusted EBITDA (% of Revenue - Operations) | 69 | % | |
Adjusted EBITDA per Boe | $ | 32.57 | |
Adjusted EBITDA excl. hedges (% of Revenue - Operations) | 67 | % | |
Adjusted EBITDA excl. hedges per Boe | $ | 31.47 | |
Production, Realized Prices and Revenue
Production for the third quarter of 2019 was 4.8 MMBoe, with oil production accounting for 73% of the total. Oil price realizations, net of certain gathering, transportation, quality differentials and other costs, were $59.54 per barrel, representing an average for the quarter of $3.09 per barrel above the average WTI price over the same period. As previously disclosed, third quarter production was impacted by Hurricane Barry, which prompted the shut-in of approximately 85% of the Company's production for approximately one week on average, and resulted in the production deferral of approximately 4.0 MBoe/d.
Three Months Ended | ||
Production volumes | ||
Oil production volume (MBbls) | 3,559 | |
NGL production volume (MBbls) | 299 | |
Natural Gas production volume (MMcf) | 5,909 | |
Total production volume (MBoe) | 4,843 | |
Average net daily production volumes | ||
Oil (MBbl/d) | 38.7 | |
NGL (MBbl/d) | 3.2 | |
Natural Gas (MMcf/d) | 64.2 | |
Total average net daily (MBoe/d) | 52.6 | |
Average realized prices (excluding hedges)(3) | ||
Oil ($/Bbl) | $59.54 | |
NGL ($/Bbl) | $11.32 | |
Natural Gas ($/Mcf) | $2.12 | |
Average Realized Price ($/Boe) | $47.04 | |
Average NYMEX prices | ||
WTI ($/Bbl) | $ | 56.45 |
Henry Hub ($/MMBtu) | $ | 2.23 |
Revenues ($ million) | ||
Oil | $ | 211.9 |
NGL | 3.4 | |
Natural Gas | 12.6 | |
Revenue - Operations | 227.9 | |
Other revenue | 1.0 | |
Total revenue | $ | 228.9 |
Three Months Ended September 30, 2019 | |||||||||||||||
Production | % Oil | % Liquids | % Operated | ||||||||||||
Average net daily production volumes by asset (MBoe/d) | |||||||||||||||
Green Canyon | |||||||||||||||
Phoenix Complex | 18.7 | 81 | % | 87 | % | 100 | % | ||||||||
Green Canyon 18 | 1.0 | 89 | % | 91 | % | 100 | % | ||||||||
Green Canyon Area | 19.7 | 81 | % | 87 | % | 100 | % | ||||||||
Mississippi Canyon | |||||||||||||||
Amberjack | 2.1 | 90 | % | 92 | % | 99 | % | ||||||||
Pompano | 10.9 | 83 | % | 89 | % | 100 | % | ||||||||
Ram Powell | 4.9 | 61 | % | 74 | % | 100 | % | ||||||||
Gunflint | 1.1 | 79 | % | 84 | % | 0 | % | ||||||||
Mississippi Canyon Area | 19.0 | 77 | % | 84 | % | 94 | % | ||||||||
Shelf and Other Deepwater | |||||||||||||||
Shelf | 12.6 | 55 | % | 61 | % | 88 | % | ||||||||
Other deepwater | 1.3 | 73 | % | 77 | % | 73 | % | ||||||||
Shelf and Other Deepwater Area | 13.9 | 61 | % | 67 | % | 87 | % | ||||||||
Total average net daily (MBoe/d) | 52.6 | 73 | % | 80 | % | 94 | % | ||||||||
Expenses
Total lease operating expenses ("LOE") for the third quarter of 2019 were $47.6 million, inclusive of insurance costs, or $9.83/Boe. LOE/Boe for the quarter was negatively impacted by reduced production volumes as a result of the production shut-in related to Hurricane Barry. Workover and maintenance expense for the quarter was $14.2 million, or $2.93/Boe. Workover and maintenance expense was also negatively impacted by Hurricane Barry with approximately $2.0 million of incremental, one-time expenses. General and administrative expenses ("G&A") for the quarter were $15.4 million (excluding $1.9 million of stock-based compensation), or $3.18/Boe. Total G&A expenses continues to be lower than expected due to continuous focus on cost control; however, G&A/Boe for the quarter was negatively impacted by the deferred production volumes associated with Hurricane Barry.
Three Months Ended | Per Boe | |||||
Lease Operating Expenses | $ | 47.6 | $ | 9.83 | ||
Workover and Maintenance Expenses | $ | 14.2 | $ | 2.93 | ||
General & Administrative Expenses (excluding non-cash items)(5) | $ | 15.4 | $ | 3.18 | ||
Other Financial Metrics
Capital Expenditures & Asset Management Activities
Capital expenditures for the third quarter of 2019 were $115.8 million, inclusive of plugging & abandonment costs. Asset management workover and recompletion activities accounted for incremental production of 2.7 MBoe/d gross, 1.5 MBoe/d, net to Talos in the third quarter. The combined net production conversion cost was $3,422 per Boe/d.
Three Months Ended | ||
Capital Expenditures | ||
U.S. Drilling & Completions | $ | 52.6 |
Mexico Appraisal & Exploration | 12.6 | |
Asset Management | 14.0 | |
Seismic and G&G / Land / Capitalized G&A | 14.5 | |
Total Capital Expenditures | $ | 93.6 |
Plugging & Abandonment | 22.2 | |
Total Capital Expenditures and Plugging & Abandonment | $ | 115.8 |
Liquidity
As of September 30, 2019, the Company had approximately $795.3 million in total debt, inclusive of the HP-I finance lease, and a liquidity position of $612.1 million, including $521.4 million available under the Bank Credit Facility and approximately $90.7 million of cash. LTM Adjusted EBITDA(2) for the twelve month period ended September 30, 2019 was $617.2 million. Net Debt to LTM Adjusted EBITDA(2) ratio was 1.1x.
2019 GUIDANCE UPDATES
Updates and adjustments to the Company's 2019 full year financial guidance are listed in the table below.
2019 Guidance ($ millions) | |||||
Production (MBoe/d) | 53 - 56 | Full Year 2019 production is expected near the low end of the previously guided range, driven mainly by already disclosed impacts from Hurricane Barry, Boris 3 production and Pompano shut-in in the first quarter of 2019 | |||
Lease Operating Expenses(4) | $195 - $205 | Expected near lower end of range | |||
Workover & Maintenance Expenses | $60 - $65 | Expected near higher end of range | |||
General & Administrative Expenses(4)(5) | $60 - $65 | Expected near lower end of range | |||
Capital Expenditures(6) | $540 - $550 | Updated range, primarily driven by: 1) $20 - $25 million: Puma West well cost 2) $15 - $20 million: Success-driven capital expenditures as a result of the expected full realization of development spending for Bulleit, Orlov and Ewing Bank 306 3) $30 - $35 million: Timing shifts mainly related to acceleration of non-operated projects, including pull-forward of Orlov first oil | |||
(1) | Includes $1 million of federal royalty refund. |
(2) | Adjusted Net Income, Adjusted Earnings per Share, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA Margin and Adjusted EBITDA Margin excluding hedges and Net Debt to LTM Adjusted EBITDA are non-GAAP financial measures. See "Supplemental Non-GAAP Information" below for additional detail and reconciliations of GAAP to non-GAAP measures. |
(3) | Average realized prices are net of certain gathering, transportation, quality differentials and other costs. |
(4) | Includes insurance costs. |
(5) | Excludes non-cash stock based compensation expense. |
(6) | Includes $70 - $75 million of Mexico capital expenditures. |
CONFERENCE CALL AND WEBCAST INFORMATION
Talos will host a conference call, which will also be broadcast live over the internet, on November 7, 2019 at 9:00 AM CST. Listeners can access the conference call live over the internet through a webcast link on the Company's website at: https://www.talosenergy.com/investors. Alternatively, the conference call can be accessed by dialing 1-888-348-8927 (U.S. toll-free), 1-855-669-9657 (Canada toll-free) or 1-412-902-4263 (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 call through November 14, 2019 and can be accessed by dialing 1-877-344-7529 and using access code 10136203.
ABOUT TALOS ENERGY
Talos Energy (NYSE: TALO) is a technically driven independent exploration and production company focused on safely and efficiently maximizing cash flows and long-term value through its operations, currently in the United StatesGulf of Mexico and offshore Mexico. As one of the U.S. Gulf of Mexico's largest public independent producers, we leverage decades of geology, geophysics and offshore operations expertise towards the acquisition, exploration, exploitation and development of assets in key geological trends that are present in many offshore basins around the world. Our activities in offshore Mexico provide high impact exploration opportunities in an oil rich emerging basin. For more information, visit www.talosenergy.com.
INVESTOR RELATIONS CONTACT
Sergio Maiworm
+1.713.328.3008
investor@talosenergy.com
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
This communication may contain "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this communication, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "project," "forecast, "may," "objective," plan" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.
We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, potential adverse reactions or changes to competitive responses to the business combination between Talos Energy LLC and Stone Energy Corporation, the possibility that the anticipated benefits of such business combination are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of the two companies, and other factors that may affect our future results and business, generally, including those discussed under the heading "Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on March 14, 2019, and in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, to be filed with the SEC subsequent to the issuance of this communication.
Should one or more of these risks occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, to reflect events or circumstances after the date of this communication.
Estimates for our future production volumes are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation and marketing of oil and gas are subject to disruption due to transportation and processing availability, mechanical failure, human error, hurricanes and numerous other factors. Our estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production volumes will be as estimated.
Cautionary Note to Investors
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms. In this communication, the Company uses certain broader terms such as "gross unrisked resources" and "gross recoverable resources" that the SEC's guidelines strictly prohibit the Company from including in filings with the SEC. These types of estimates do not represent, and are not intended to represent, any category of reserves based on SEC definitions, are by their nature more speculative than estimates of proved, probable and possible reserves and do not constitute "reserves" within the meaning of the SEC's rules. These estimates are subject to greater uncertainties, and accordingly, are subject to a substantially greater risk of actually being realized. Investors are urged to consider closely the disclosures and risk factors in the reports the Company files with the SEC.
Talos Energy Inc. Condensed Consolidated Balance Sheets (In thousands, except per share amounts) | ||||||||
September 30, 2019 | December 31, 2018 | |||||||
(Unaudited) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 90,682 | $ | 139,914 | ||||
Restricted cash | - | 1,248 | ||||||
Accounts receivable | ||||||||
Trade, net | 108,354 | 103,025 | ||||||
Joint interest, net | 17,562 | 20,244 | ||||||
Other | 31,768 | 19,686 | ||||||
Assets from price risk management activities | 43,058 | 75,473 | ||||||
Prepaid assets | 39,378 | 38,911 | ||||||
Income tax receivable | - | 10,701 | ||||||
Other current assets | 1,952 | 7,644 | ||||||
Total current assets | 332,754 | 416,846 | ||||||
Property and equipment: | ||||||||
Proved properties | 4,012,100 | 3,629,430 | ||||||
Unproved properties, not subject to amortization | 178,174 | 108,209 | ||||||
Other property and equipment | 28,690 | 33,191 | ||||||
Total property and equipment | 4,218,964 | 3,770,830 | ||||||
Accumulated depreciation, depletion and amortization | (1,967,610) | (1,719,609) | ||||||
Total property and equipment, net | 2,251,354 | 2,051,221 | ||||||
Other long-term assets: | ||||||||
Assets from price risk management activities | 7,820 | - | ||||||
Other well equipment inventory | 9,251 | 9,224 | ||||||
Operating lease assets | 8,082 | - | ||||||
Other assets | 2,624 | 2,695 | ||||||
Total assets | $ | 2,611,885 | $ | 2,479,986 | ||||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 95,737 | $ | 51,019 | ||||
Accrued liabilities | 169,152 | 188,650 | ||||||
Accrued royalties | 37,763 | 38,520 | ||||||
Current portion of long-term debt | - | 443 | ||||||
Current portion of asset retirement obligations | 63,404 | 68,965 | ||||||
Liabilities from price risk management activities | 3,832 | 550 | ||||||
Accrued interest payable | 21,058 | 10,200 | ||||||
Current portion of operating lease liabilities | 1,416 | - | ||||||
Other current liabilities | 18,993 | 22,071 | ||||||
Total current liabilities | 411,355 | 380,418 | ||||||
Long-term liabilities: | ||||||||
Long-term debt, net of discount and deferred financing costs | 697,192 | 654,861 | ||||||
Asset retirement obligations | 321,808 | 313,852 | ||||||
Liabilities from price risk management activities | 750 | - | ||||||
Operating lease liabilities | 17,249 | - | ||||||
Other long-term liabilities | 88,707 | 123,359 | ||||||
Total liabilities | 1,537,061 | 1,472,490 | ||||||
Commitments and contingencies (Note 11) | ||||||||
Stockholders' equity: | ||||||||
Preferred stock, $0.01 par value; 30,000,000 shares authorized; no shares issued or | - | - | ||||||
Common stock $0.01 par value; 270,000,000 shares authorized; 54,196,145 and 54,155,768 shares | 542 | 542 | ||||||
Additional paid-in capital | 1,342,993 | 1,334,090 | ||||||
Accumulated deficit | (268,711) | (327,136) | ||||||
Total stockholders' equity | 1,074,824 | 1,007,496 | ||||||
Total liabilities and stockholders' equity | $ | 2,611,885 | $ | 2,479,986 | ||||
Talos Energy Inc. Condensed Consolidated Statements of Operations (In thousands, except per common share amounts) (Unaudited) | ||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2019 | 2018 | 2019 | 2018 | |||||||||||||
Revenues and other: | ||||||||||||||||
Oil revenue | $ | 211,899 | $ | 248,100 | $ | 624,486 | $ | 555,954 | ||||||||
Natural gas revenue | 12,545 | 20,193 | 41,738 | 49,364 | ||||||||||||
NGL revenue | 3,384 | 14,575 | 15,095 | 27,306 | ||||||||||||
Other | 1,029 | - | 13,061 | - | ||||||||||||
Total revenue | 228,857 | 282,868 | 694,380 | 632,624 | ||||||||||||
Operating expenses: | ||||||||||||||||
Direct lease operating expense | 43,439 | 42,090 | 122,243 | 101,065 | ||||||||||||
Insurance | 4,167 | 4,125 | 12,462 | 11,059 | ||||||||||||
Production taxes | (21) | 578 | 1,067 | 1,533 | ||||||||||||
Total lease operating expense | 47,585 | 46,793 | 135,772 | 113,657 | ||||||||||||
Workover and maintenance expense | 14,210 | 25,084 | 49,525 | 49,703 | ||||||||||||
Depreciation, depletion and amortization | 88,125 | 87,808 | 248,518 | 204,574 | ||||||||||||
Write-down of oil and natural gas properties | 1,417 | - | 13,778 | - | ||||||||||||
Accretion expense | 7,316 | 10,162 | 26,868 | 24,414 | ||||||||||||
General and administrative expense | 17,321 | 21,660 | 53,795 | 61,120 | ||||||||||||
Total operating expenses | 175,974 | 191,507 | 528,256 | 453,468 | ||||||||||||
Operating income | 52,883 | 91,361 | 166,124 | 179,156 | ||||||||||||
Interest expense | (23,123) | (24,837) | (73,273) | (66,257) | ||||||||||||
Price risk management activities income (expense) | 43,760 | (53,330) | (35,829) | (196,482) | ||||||||||||
Other income (expense) | 567 | (85) | 1,831 | (1,163) | ||||||||||||
Income (loss) before income taxes | 74,087 | 13,109 | 58,853 | (84,746) | ||||||||||||
Income tax benefit | (790) | - | (428) | - | ||||||||||||
Net income (loss) | $ | 73,297 | $ | 13,109 | $ | 58,425 | $ | (84,746) | ||||||||
Net income (loss) per common share: | ||||||||||||||||
Basic | $ | 1.35 | $ | 0.24 | $ | 1.08 | $ | (1.96) | ||||||||
Diluted | $ | 1.35 | $ | 0.24 | $ | 1.07 | $ | (1.96) | ||||||||
Weighted average common shares outstanding: | ||||||||||||||||
Basic | 54,200 | 54,156 | 54,178 | 43,329 | ||||||||||||
Diluted | 54,430 | 54,164 | 54,364 | 43,329 | ||||||||||||
Talos Energy Inc. Condensed Consolidated Statements of Cash Flows (In thousands) (Unaudited) | ||||||||
Nine Months Ended September 30, | ||||||||
2019 | 2018 | |||||||
Cash flows from operating activities: | ||||||||
Net income (loss) | $ | 58,425 | $ | (84,746) | ||||
Adjustments to reconcile net loss to net cash provided by operating activities | ||||||||
Depreciation, depletion, amortization and accretion expense | 275,386 | 228,988 | ||||||
Write-down of oil and natural gas properties | 13,778 | - | ||||||
Amortization of deferred financing costs and original issue discount | 3,723 | 3,589 | ||||||
Equity based compensation, net of amounts capitalized | 5,164 | 2,129 | ||||||
Price risk management activities expense | 35,829 | 196,482 | ||||||
Net cash paid on settled derivative instruments | (7,202) | (94,802) | ||||||
Settlement of asset retirement obligations | (54,406) | (85,674) | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable | (14,729) | (4,460) | ||||||
Other current assets | 11,384 | (14,524) | ||||||
Accounts payable | 32,541 | (54,029) | ||||||
Other current liabilities | (26,753) | 40,410 | ||||||
Other non-current assets and liabilities, net | (727) | 10,324 | ||||||
Net cash provided by operating activities | 332,413 | 143,687 | ||||||
Cash flows from investing activities: | ||||||||
Exploration, development and other capital expenditures | (372,920) | (174,349) | ||||||
Cash (paid for) acquired in acquisitions | (32,916) | 278,409 | ||||||
Proceeds from sale of other property and equipment | 5,369 | - | ||||||
Net cash provided by (used in) investing activities | (400,467) | 104,060 | ||||||
Cash flows from financing activities: | ||||||||
Redemption of Senior Notes and other long-term debt | (10,567) | (25,151) | ||||||
Proceeds from Bank Credit Facility | 75,000 | 319,000 | ||||||
Repayment of Bank Credit Facility | (25,000) | (54,000) | ||||||
Repayment of LLC Bank Credit Facility | - | (403,000) | ||||||
Deferred financing costs | (1,268) | (16,990) | ||||||
Other deferred payments | (9,921) | - | ||||||
Payments of finance lease | (10,344) | (9,874) | ||||||
Employee stock transactions | (326) | - | ||||||
Net cash provided by (used in) financing activities | 17,574 | (190,015) | ||||||
Net increase (decrease) in cash, cash equivalents and restricted cash | (50,480) | 57,732 | ||||||
Cash, cash equivalents and restricted cash: | ||||||||
Balance, beginning of period | 141,162 | 33,433 | ||||||
Balance, end of period | $ | 90,682 | $ | 91,165 | ||||
Supplemental Non-Cash Transactions: | ||||||||
Capital expenditures included in accounts payable and accrued liabilities | $ | 24,622 | $ | 36,775 | ||||
Supplemental Cash Flow Information: | ||||||||
Interest paid, net of amounts capitalized | $ | 36,011 | $ | 27,307 | ||||
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 are "Adjusted Net Income," "Adjusted Earnings per Share," "EBITDA", "Adjusted EBITDA," "Adjusted EBITDA excluding hedges," "Adjusted EBITDA Margin," "Adjusted EBITDA Margin excluding hedges," "Net Debt," "LTM Adjusted EBITDA" and "Net Debt to LTM Adjusted EBITDA." These disclosures 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 Net Income (Loss) to EBITDA and Adjusted EBITDA
"EBITDA" and "Adjusted EBITDA" are to 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 and 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, loss on debt extinguishment, transaction related costs, derivative fair value (gain) loss, net cash receipts (payments) on settled derivatives, non-cash (gain) loss on sale of assets, non-cash write-down of other well equipment inventory and non-cash equity-based compensation expense.
We also present Adjusted EBITDA excluding hedges and as a percentage of revenue to further analyze our business, which are outlined below:
Adjusted EBITDA excluding hedges. Adjusted EBITDA plus net cash receipts (payments) on settled derivative instruments. We believe the presentation of Adjusted EBITDA excluding hedges is important to provide management and investors with information about the impact of actual commodity price changes on our business.
Adjusted EBITDA Margin. EBITDA divided by Revenue, as a percentage. It is also defined as 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 we generate after accounting for certain operational and corporate costs.
Adjusted EBITDA Margin excluding hedges bears the same definition and our intended utility of Adjusted EBITDA Margin, but using Adjusted EBITDA excluding hedges instead of Adjusted EBITDA.
The following table presents a reconciliation of the GAAP financial measure of net income (loss) to EBITDA, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA Margins and Adjusted EBITDA Margins excluding hedges for each of the periods indicated (in thousands, except for Boe, $/Boe and percentage data):
($ thousands, except per Boe) | Three Months December 31, | Three Months March 31, | Three Months June 30, | Three Months | |||||||||||
Reconciliation of net income (loss) to Adjusted EBITDA: | |||||||||||||||
Net income (loss) | $ | 306,286 | $ | (109,636) | $ | 94,764 | $ | 73,297 | |||||||
Interest expense | 23,857 | 25,218 | 24,932 | 23,123 | |||||||||||
Income tax expense (benefit) | 2,922 | (6,359) | 5,997 | 790 | |||||||||||
Depreciation, depletion and amortization | 84,145 | 64,587 | 95,806 | 88,125 | |||||||||||
Accretion expense | 10,930 | 9,607 | 9,945 | 7,316 | |||||||||||
EBITDA | 428,140 | (16,583) | 231,444 | 192,651 | |||||||||||
Write-down of oil and natural gas properties | - | - | 12,361 | 1,417 | |||||||||||
Loss on debt extinguishment | - | - | - | - | |||||||||||
Transaction related costs | 4,579 | 2,493 | 710 | 146 | |||||||||||
Derivative fair value (gain) loss(1) | (256,917) | 109,579 | (29,990) | (43,760) | |||||||||||
Net cash receipts (payments) on settled derivative instruments(1) | (16,345) | (3,019) | (9,543) | 5,360 | |||||||||||
Non-cash (gain) loss on sale of assets | (1,710) | - | - | - | |||||||||||
Non-cash write-down of other well equipment inventory | 244 | - | - | - | |||||||||||
Non-cash equity-based compensation expense | 764 | 1,259 | 1,961 | 1,944 | |||||||||||
Adjusted EBITDA | $ | 158,755 | $ | 93,729 | $ | 206,943 | $ | 157,758 | |||||||
Net cash receipts (payments) on settled derivative instruments(1) | 16,345 | 3,019 | 9,543 | (5,360) | |||||||||||
Adjusted EBITDA excluding hedges | $ | 175,100 | $ | 96,748 | $ | 216,486 | $ | 152,398 | |||||||
Production and Revenue: | |||||||||||||||
Boe(2) | 4,910 | 3,782 | 5,369 | 4,843 | |||||||||||
Revenue - Operations | 258,664 | 175,192 | 278,299 | 227,828 | |||||||||||
Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin: | |||||||||||||||
Adjusted EBITDA divided by Revenue - Operations (%) | 61 | % | 54 | % | 74 | % | 69 | % | |||||||
Adjusted EBITDA per Boe(2) | $ | 32.33 | $ | 24.78 | $ | 38.54 | $ | 32.57 | |||||||
Adjusted EBITDA excl hedges divided by Revenue - Operations (%) | 68 | % | 55 | % | 78 | % | 67 | % | |||||||
Adjusted EBITDA excl hedges per Boe(2) | $ | 35.66 | $ | 25.58 | $ | 40.32 | $ | 31.47 | |||||||
(1) | 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 a cash basis during the period the derivatives settled. |
(2) | 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 Net Income (Loss) to Adjusted Net Income and Adjusted Earnings per Share
"Adjusted Net Income" 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 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. 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 divided by the number of common shares.
($ thousands, except per share amounts) | Three Months Ended | ||
Reconciliation of Net Income to Adjusted Net Income: | |||
Net Income | $ | 73,297 | |
Accretion expense | 7,316 | ||
Transaction related costs | 146 | ||
Derivative fair value (gain) loss(1) | (43,760) | ||
Net cash receipts (payments) on settled derivative instruments(1) | 5,360 | ||
Non-cash equity-based compensation expense | 1,944 | ||
Adjusted Net Income | $ | 44,303 | |
Weighted average common shares outstanding at September 30, 2019: | |||
Basic | 54,200 | ||
Diluted | 54,430 | ||
Net Income per common share (Earnings Per Share): | |||
Basic | $ | 1.35 | |
Diluted | $ | 1.35 | |
Adjusted Net Income per common share (Adjusted Earnings Per Share): | |||
Basic | $ | 0.82 | |
Diluted | $ | 0.81 | |
(1) | 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 on a cash basis during the period the derivatives settled. |
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 of the Company plus the Finance Lease balance minus Cash.
Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA.
Reconciliation of Total Debt to Net Debt ($ thousands) at September 30, 2019: | |||
Debt principal | $ | 711,928 | |
Finance lease | 83,324 | ||
Total Debt | 795,252 | ||
Cash | (90,682) | ||
Net Debt | $ | 704,570 | |
Calculation of LTM EBITDA: | |||
Adjusted EBITDA for the three month period ended December 31, 2018 | 158,755 | ||
Adjusted EBITDA for the three month period ended March 31, 2019 | 93,729 | ||
Adjusted EBITDA for the three month period ended June 30, 2019 | 206,943 | ||
Adjusted EBITDA for the three month period ended September 30, 2019 | 157,758 | ||
LTM Adjusted EBITDA | 617,185 | ||
Calculation of Net Debt to LTM Adjusted EBITDA: | |||
Net Debt / LTM Adjusted EBITDA | 1.1 |
The Adjusted EBITDA information included in this communication provides additional relevant information to our investors and creditors. Talos needs to comply with a financial covenant included in its Bank Credit Facility that requires it to maintain a Net Debt to LTM Adjusted EBITDA ratio equal to or lower than 3.0x. For purposes of covenant compliance, LTM Adjusted EBITDA, with certain adjustments, is calculated, as of September 30, 2019 and in subsequent quarters, as the sum of quarterly Adjusted EBITDA for the 12-month period ended on that quarter.
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