HOUSTON, Aug. 7, 2019 /PRNewswire/ -- Talos Energy Inc. ("Talos," or the "Company") (NYSE: TALO) today announced its financial and operational results for the second quarter of 2019 and an operations update.
Key second quarter highlights include:
- Production of 59.0 thousand barrels of oil equivalent per day ("MBoe/d"), or 5.4 million barrels of oil equivalent ("MMBoe") in total, of which 75% was oil and 81% was liquids.
- Revenue(1) of $286.8 million and average realized prices of $64.13/Bbl of oil and $2.45/Mcf of natural gas, net of deductions. 92% of operating revenues were derived from oil production and reflect a significant basis differential premium to the average WTI benchmark price of $59.81/Bbl during the same period.
- Net Income of $94.8 million ($1.74 earnings per share - diluted) and Adjusted Net Income(2) of $67.8 million ($1.25 adjusted earnings per share - diluted).
- Adjusted EBITDA(2) of $206.9 million. Adjusted EBITDA excluding hedges(2) in the quarter was $216.5 million.
- Adjusted EBITDA Margin(2) per Boe of $38.54, or approximately 72%, and Adjusted EBITDA Margin excluding hedges(2) per Boe of $40.32, or approximately 75%. The Company's Adjusted EBITDA Margin excluding hedges(2) on a percentage basis is the highest in Talos's history.
- As of June 30, 2019, liquidity position of $358.9 million, including $269.8 million available under the Bank Credit Facility and approximately $89.1 million of cash. Pro forma for the Company's credit facility commitment increase to $850.0 million on July 3, liquidity was $608.9 million.
- As of June 30, 2019, the Company's total debt principal balance was $798.8 million, inclusive of the $86.9 million finance lease on the HP-I. Net Debt to Last Twelve Months ("LTM") Adjusted EBITDA(2) was 1.2x. Net Debt to the annualized second quarter 2019 Adjusted EBITDA(2) ("Annualized Adjusted EBITDA") is less than 0.9x.
- Capital expenditures, inclusive of plugging and abandonment costs, were $187.4 million with approximately $156.2 million related to the U.S. Gulf of Mexico and $31.2 million related to offshore Mexico.
- With a capital program front-loaded in the first half of 2019, the Company participated in five drilling projects in the second quarter, with success in the Bulleit and Orlov projects in the deepwater U.S. Gulf of Mexico, new production established in the Ewing Bank drilling program in the shallow water U.S. Gulf of Mexico, the successful conclusion of the Zama appraisal and the ongoing program in the Block 2 and 31 contractual areas in offshore Mexico.
(1) | Includes $8.5 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, Net Debt to LTM Adjusted EBITDA and Net Debt to Annualized 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 pleased with the Company's performance during the second quarter of 2019. This was the Company's best quarter on record in terms of production, Adjusted EBITDA, and Adjusted EBITDA Margin excluding hedges on a percentage basis, even with lower commodity prices and slightly higher service costs from a year ago. These strong results highlight our well-executed in-basin consolidation and the industrial logic of our business combination with Stone Energy that closed in the second quarter of 2018, as well as the benefits of our strategy of drilling in and around infrastructure we own or have access to, strong asset management and a continued focus on controlling costs.
"We executed numerous successful drilling projects in both deepwater and shallow water in the U.S. Gulf of Mexico and two drilling programs in offshore Mexico. Our annual capital program was significantly front-loaded in the first half of the year with five rigs working during the second quarter. Even with this high level of activity, our U.S. Gulf of Mexico business generated meaningful free cash flow in the second quarter. We believe that reinvesting cash flows from the U.S. Gulf of Mexico business into our globally recognized Zama discovery will help accelerate the value realization of that asset, and we are extremely proud of our progress on that front. In the second half of the year, we expect to continue generating a significant amount of free cash flow from our U.S. Gulf of Mexico business that will be further enhanced by having concluded the Zama appraisal in the second quarter.
"We further strengthened our financial profile in the second quarter with a $250 million increase to our credit facility commitments and the addition of incremental 2020 hedges at attractive average pricing. These improvements will allow the Company to maintain optionality and flexibility as we move forward, underpinned by our peer-leading balance sheet and leverage profile."
RECENT DEVELOPMENTS AND OPERATIONS UPDATE
Drilling and Exploration Activities - U.S. Gulf of Mexico
Deepwater
- Bulleit Prospect: Drilling operations are concluding on the Green Canyon 21 Bulleit prospect. The 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 experienced delays and additional costs during drilling due to difficult hole conditions below the DTR-10 Sand that necessitated a side track of the original well path to a new directional plan. Additionally, the rig was moved off location to ensure safe operations during Hurricane Barry. The well will be completed in the first half of 2020 and then tied back to the Talos-owned and operated Green Canyon 18 ("GC 18") facility located approximately 10 miles west of Bulleit. The Bulleit prospect, originally generated by EnVen Energy ("EnVen"), is now 50.0% owned and operated by Talos, with EnVen and Otto Energy owning 33.3% and 16.7%, respectively.
- Orlov Prospect: The Green Canyon 200 Orlov prospect initially encountered approximately 100 feet of net true vertical thickness ("TVT") oil pay in the main target Aspen J sand, as well as additional pay sands in shallower zones along the same trap. The operator, Fieldwood Energy ("Fieldwood"), currently has a rig on location and will soon commence an operation to re-enter the well and drill an appraisal sidetrack to optimize the well location in relation to the discovered resources. Initial production from Orlov is expected in the first quarter of 2020 and will be tied back to the Fieldwood-operated Bullwinkle facility. Talos owns a 30% working interest in the Orlov project.
Shallow Water
- Ewing Bank 306 A-2 ST-2: Production was brought online via a dual completion in the deepest two of five hydrocarbon-bearing zones in the first week of May of 2019 at a production rate of approximately 1.3 MBoe/d gross, 1.0 MBoe/d net to Talos. Subsequently, the well reached a production rate of approximately 1.7 MBoe/d gross, 1.4 MBoe/d net to Talos. Talos owns a 100% working interest in the project.
- Ewing Bank 306 A-10 ST-2: The A-10 ST-2 was successfully drilled in the second quarter, finding approximately 95 feet of net TVD pay in the Miocene geological section that was first discovered in the A-20 ST well drilled in 2018. Production was brought online on July 24 of 2019 and reached a production rate of approximately 2.6 MBoe/d gross, 2.1 MBoe/d net to Talos. Talos owns a 100% working interest in the project.
- Grand Isle 82 A-22: Drilling commenced on July 2 and will target a series of Miocene sands at approximately 14,600 feet TVD. If successful, Talos expects the well to generate an initial production rate of 2.5 - 3.5 MBoe/d gross, 2.2 - 3.1 MBoe/d net to Talos, with first production expected in the fourth quarter of 2019. Talos owns a 100% working interest in the project.
Drilling and Exploration Activities - Mexico
Block 7 - Zama Appraisal Program
- Completion of Appraisal Program: Talos has concluded its three-well appraisal of the Zama discovery with highly encouraging results. The Zama-3 well was drilled to test the southern extent of the reservoir. Well results included the logging of approximately 1,000 feet of gross TVD sand and 748 feet of gross TVD oil pay, with better than expected net-to-gross ratios across the pay sections and the capture of a new record whole core (717 feet). The Zama appraisal program was completed 39 days ahead of schedule and under budget. Appraisal operations were successfully completed with zero lost-time incidents or environmental issues.
- Appraisal Data: Throughout the appraisal program, Talos collected a substantial amount of data, including approximately 1,450 feet of whole core, 59 fluid samples from the reservoir, over 200 pressure points, 25 logging runs and two extended flow tests. This data will be incorporated into an independent, third party resource estimate to be prepared by Netherland, Sewell & Associates, Inc. by year end 2019. Talos expects updated resource guidance to fall in the upper half of its previously disclosed pre-appraisal estimated range of gross recoverable resources of 400 - 800 MMBoe.
- Progress to FID: Front-End Engineering & Design ("FEED") work is advancing via an engagement with io Oil & Gas Consulting (a joint venture between Baker Hughes GE and McDermott International, Inc.) to optimize the recovery and economic development of the field. Talos has significantly narrowed the number of potential development concepts and the prevailing concept design will be the basis for development. Additionally, unitization discussions with Petróleos Mexicanos ("Pemex") are ongoing with the goal of reaching a Final Investment Decision ("FID") in 2020.
Block 2 and Block 31 Exploration Program
In October of 2018, Talos announced a cross-assignment transaction with a subsidiary of Pan American Energy ("PAE"), pursuant to which Talos conveyed a 25% participation interest (i.e. half of its interest) in Block 2 to PAE in exchange for a 25% participation interest from PAE in Block 31, resulting in a four well program consisting of two wells on each of Blocks 2 and 31.
- Block 2: The Yaluk-1EXP, the second well on Block 2, was drilled in the second quarter of 2019 and encountered a non-commercial quantity of hydrocarbons. Net costs to Talos were approximately $8.0 million.
- Block 31: The first project on Block 31, the Xaxamani-2EXP well, spud in July and reached total depth ("TD") in early August with encouraging results. It is the first well in the Olmeca project area, which is a shallow oil project set up by the Xaxamani-1 exploratory well drilled in 2003, which logged oil pay in several intervals. PAE expects to perform a drill stem test in the Xaxamani-2EXP before moving to the Tolteca well, which has similar objectives. The project is located in very shallow waters (approximately 60 feet) and less than two miles from shore. Talos will provide more details at the conclusion of the program.
Asset Management Activities
In the second quarter of 2019, Asset Management workover and recompletion activities accounted for incremental production of 0.9 MBoe/d gross, 0.7 MBoe/d, net to Talos. Asset Management-related capital expenditures in the second quarter also included $8 million related to a recompletion campaign on two wells in the Pompano field, for which production did not start until July. The Pompano A-5 well was finalized on July 5 and is currently producing approximately 1.1 MBoe/d gross, 1.0 MBoe/d, net to Talos. The Cardona #6 subsea well was recompleted on July 17 and is producing approximately 2.6 MBoe/d gross, 1.5 MBoe/d, net to Talos. The combined production conversion cost of these two wells is $3,200/Boe/d, with the production impact beginning in the third quarter of 2019.
Liquidity and Derivatives Activities
- Borrowing Base & Liquidity: Effective July 3, Talos elected to increase commitments under its syndicated credit facility to the reaffirmed borrowing base level of $850 million, up from $600 million in the first half of 2019. After adjusting June 30 figures for the revised commitment level, pro forma liquidity, including cash, would be $608.9 million, with 39% of the facility drawn. In addition, Talos added three additional lenders to the syndicate.
- Hedging Updates: In the second quarter Talos added additional hedging of 2020 oil production of approximately 3.4 million barrels. As of June 30, 2019, the Company's weighted average swap price for 2020 is $56.80/bbl and the weighted average put and call prices for the costless collars were $55.00 and $64.23, respectively.
SECOND QUARTER 2019 RESULTS | ||||
Key Financial Highlights: | ||||
Three months ended | ||||
Period Results ($ million, except per share and Boe): | ||||
Revenues(1) | $ | 286.8 | ||
Net Income | $ | 94.8 | ||
Net Income per diluted share | $ | 1.74 | ||
Adjusted Net Income(2) | $ | 67.8 | ||
Adjusted Earnings per diluted share(2) | $ | 1.25 | ||
Adjusted EBITDA(2) | $ | 206.9 | ||
Adjusted EBITDA excl. hedges(2) | $ | 216.5 | ||
Capital Expenditures (including Plugging & Abandonment) | $ | 187.4 | ||
Adjusted EBITDA Margin(2): | ||||
Adjusted EBITDA (% of Revenue) | 72 | % | ||
Adjusted EBITDA per Boe | $ | 38.54 | ||
Adjusted EBITDA excl. hedges (% of Revenue) | 75 | % | ||
Adjusted EBITDA excl. hedges per Boe | $ | 40.32 | ||
Production, Realized Prices and Revenue
Production: Production for the second quarter of 2019 was 5.4 million barrels of oil equivalent, comprised of 4.0 million barrels of oil, 0.4 million barrels of NGLs and 6.0 billion cubic feet ("Bcf") of natural gas. Oil and NGL production accounted for 81% of the total production for the second quarter of 2019.
Realized Prices: Oil price realizations, net of certain gathering, transportation, quality differentials and other costs, was $64.13 per barrel. Realizations continues to be robust, representing an average for the quarter of $4.32 per barrel above the average WTI price over the same period.
Revenue: Total revenue for the three months ended June 30, 2019 was $286.8 million. Total revenue includes $8.5 million of federal royalty refunds, classified as other revenue.
Three months ended | ||
Production Volumes: | ||
Oil production volume (MBbls) | 4,006 | |
NGL production volume (MBbls) | 362 | |
Natural Gas production volume (MMcf) | 6,008 | |
Total production volume (MBoe) | 5,369 | |
Average Net Daily Production Volumes: | ||
Oil (MBbl/d) | 44.0 | |
NGL (MBbl/d) | 4.0 | |
Natural Gas (MMcf/d) | 66.0 | |
Total average net daily volume (MBoe/d) | 59.0 | |
Average Realized Prices (excluding hedges)(3): | ||
Oil ($/Bbl) | 64.13 | |
NGL ($/Bbl) | 18.36 | |
Natural Gas ($/Mcf) | 2.45 | |
Average Realized Price ($/Boe) | 51.83 | |
Average NYMEX Prices: | ||
WTI ($/Bbl) | 59.81 | |
Henry Hub ($/MMBtu) | 2.64 | |
Revenues ($ million): | ||
Oil | 256.9 | |
NGL | 6.6 | |
Natural Gas | 14.8 | |
Operating Revenue | 278.3 | |
Other revenue | 8.5 | |
Total revenue | 286.8 | |
The table below provides additional detail of the Company's production by major assets for the three months ended June 30, 2019:
Three months ended June 30, 2019 | ||||||||||||
Production | % Oil | % Liquids | % Operated | |||||||||
Average Net Daily Production Volumes by Asset (MBoe/d): | ||||||||||||
Green Canyon | ||||||||||||
Phoenix Complex | 22.8 | 80 | % | 87 | % | 100 | % | |||||
Green Canyon 18 | 1.1 | 88 | % | 89 | % | 100 | % | |||||
Green Canyon Area | 23.9 | 81 | % | 87 | % | 100 | % | |||||
Mississippi Canyon | ||||||||||||
Amberjack | 2.1 | 91 | % | 93 | % | 100 | % | |||||
Pompano | 11.5 | 84 | % | 90 | % | 100 | % | |||||
Ram Powell | 5.8 | 57 | % | 70 | % | 100 | % | |||||
Gunflint | 1.3 | 78 | % | 88 | % | 0 | % | |||||
Mississippi Canyon Area | 20.7 | 77 | % | 84 | % | 94 | % | |||||
Shelf and Other Deepwater | ||||||||||||
Shelf | 12.7 | 60 | % | 66 | % | 89 | % | |||||
Other Deepwater | 1.7 | 71 | % | 78 | % | 71 | % | |||||
Shelf and Other Deepwater Area | 14.4 | 61 | % | 67 | % | 87 | % | |||||
Total average net daily volumes (MBoe/d) | 59.0 | 75 | % | 81 | % | 95 | % | |||||
Subsequent Events: Production from the U.S. Gulf of Mexico was significantly impacted in the month of July due to precautionary shut-ins of facilities and evacuations associated with Hurricane Barry. According to the Bureau of Safety and Environmental Enforcement's ("BSEE") daily reports, impacts from the storm peaked on July 14 resulting in approximately 1.4 million barrels per day of oil production shut-in, or 73% of all U.S. Gulf of Mexico oil production. Although there was no major storm related damage, the production impact to Talos spanned approximately one week and also peaked on July 14 with Talos shutting in approximately 85% of its production in the period. Talos expects the production deferral from Hurricane Barry to impact only the third quarter of 2019 financial results.
Production rates from the Boris #3 well, which significantly surpassed Talos's initial production expectation when the well was brought online in the last week of April, have recently stabilized near the low end of the Company's pre-drill estimated range of 3.0 - 5.0 MBoe/d gross, or 2.8 - 4.6 MBoe/d net to Talos after royalties.
As a result of Hurricane Barry and stabilization of the Boris #3 production rate, Talos expects average daily production in the third quarter of 2019 to be negatively impacted by approximately 4.0 - 6.0 MBoe/d, net to Talos, relative to the Company's expectations.
Expenses
Lease operating expenses ("LOE"): Total LOE for three months ended June 30, 2019 was $42.7 million, inclusive of insurance costs. LOE per Boe for the quarter was $7.95/Boe.
Workover and maintenance expenses: Workover and maintenance expense for the three months ended June 30, 2019 was $12.3 million. Workover and maintenance expenses per Boe for the quarter was $2.29/Boe.
General and administrative expenses ("G&A"): General and administrative expenses for the three months ended June 30, 2019 were $16.2 million, excluding $2.0 million of stock-based compensation and $0.7 million in transaction-related costs. G&A per Boe for the quarter was $3.02/Boe.
Three months ended | $ / Boe | |||
Lease Operating Expenses | $ | 42.7 | $ | 7.95 |
Workover and Maintenance Expenses | $ | 12.3 | $ | 2.29 |
General & Administrative Expenses (excluding non-cash items) | $ | 16.2 | $ | 3.02 |
Price risk management activities: Price risk management activities for the three months ended June 30, 2019 resulted in a $9.5 million cash payment on our derivative contracts.
Other Financial Metrics
Net income, Adjusted Earnings per Share and Adjusted EBITDA: Net income was $94.8 million, or $1.74 earnings per diluted share. After certain adjustments, the Adjusted Earnings per Diluted Share in the second quarter was $1.25. Adjusted EBITDA in the second quarter of 2019 was $206.9 million.
Capital Expenditures: Capital expenditures in the second quarter of 2019 were $187.4 million, inclusive of plugging & abandonment costs. The table below provides additional detail of the Company's capital expenditures:
($ millions) | Three months ended | |
U.S. drilling & completions | $ | 85.8 |
Mexico appraisal & exploration | 30.0 | |
Asset management | 24.5 | |
Seismic and G&G / Land / Capitalized G&A(4) | 18.9 | |
Total Capital Expenditures | 159.2 | |
Plugging & Abandonment | 28.3 | |
Total Capital Expenditures and Plugging & Abandonment | $ | 187.4 |
Financial position: As of June 30, 2019, the Company had approximately $798.8 million in total debt, including deferred financing costs and original issue discount. The balance includes $396.9 million of second lien notes, $315.0 million of borrowings under the Company's credit facility and the HP-I finance lease obligation with a balance of approximately $86.9 million.
Liquidity position: As of June 30, 2019, liquidity position of $358.9 million, including $269.8 million available under the Bank Credit Facility and approximately $89.1 million of cash. Pro forma for the Company's credit facility commitment increase on July 3, liquidity was $608.9 million.
Leverage and credit metrics: LTM Adjusted EBITDA for the twelve month period ended June 30, 2019 was $616.4 million. As of June 30, 2019, the Company's total debt was $798.8 million and Net Debt was $709.7 million, both including the finance lease. Therefore, Net Debt to LTM Adjusted EBITDA ratio was 1.2x. Net Debt to an annualized second quarter 2019 Adjusted EBITDA is less than 0.9x.
(1) | Includes $8.5 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, Net Debt to LTM Adjusted EBITDA and Net Debt to Annualized 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 $1.2 million of Mexico expenditures. |
CONFERENCE CALL AND WEBCAST INFORMATION
Talos will host a conference call, which will also be broadcast live over the internet, on August 8, 2019 at 10:00 AM CT. 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 August 15, 2019 and can be accessed by dialing 1-877-344-7529 and using access code 10133698.
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 June 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.
TALOS ENERGY INC. | ||||||
CONDENSED CONSOLIDATED BALANCE SHEETS | ||||||
(In thousands, except share amounts) | ||||||
June 30, 2019 | December 31, 2018 | |||||
(Unaudited) | ||||||
ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | $ | 89,105 | $ | 139,914 | ||
Restricted cash | - | 1,248 | ||||
Accounts receivable | ||||||
Trade, net | 110,504 | 103,025 | ||||
Joint interest, net | 35,741 | 20,244 | ||||
Other | 28,828 | 19,686 | ||||
Assets from price risk management activities | 23,633 | 75,473 | ||||
Prepaid assets | 38,370 | 38,911 | ||||
Income tax receivable | - | 10,701 | ||||
Other current assets | 2,085 | 7,644 | ||||
Total current assets | 328,266 | 416,846 | ||||
Property and equipment: | ||||||
Proved properties | 3,925,116 | 3,629,430 | ||||
Unproved properties, not subject to amortization | 165,041 | 108,209 | ||||
Other property and equipment | 28,244 | 33,191 | ||||
Total property and equipment | 4,118,401 | 3,770,830 | ||||
Accumulated depreciation, depletion and amortization | (1,879,486) | (1,719,609) | ||||
Total property and equipment, net | 2,238,915 | 2,051,221 | ||||
Other long-term assets: | ||||||
Assets from price risk management activities | 5,508 | - | ||||
Other well equipment inventory | 9,914 | 9,224 | ||||
Operating lease assets | 6,732 | - | ||||
Other assets | 2,700 | 2,695 | ||||
Total assets | $ | 2,592,035 | $ | 2,479,986 | ||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||
Current liabilities: | ||||||
Accounts payable | $ | 115,086 | $ | 51,019 | ||
Accrued liabilities | 186,354 | 188,650 | ||||
Accrued royalties | 42,651 | 38,520 | ||||
Current portion of long-term debt | - | 443 | ||||
Current portion of asset retirement obligations | 65,757 | 68,965 | ||||
Liabilities from price risk management activities | 18,781 | 550 | ||||
Accrued interest payable | 10,068 | 10,200 | ||||
Current portion of operating lease liabilities | 1,315 | - | ||||
Other current liabilities | 18,140 | 22,071 | ||||
Total current liabilities | 458,152 | 380,418 | ||||
Long-term liabilities: | ||||||
Long-term debt, net of discount and deferred financing costs | 697,130 | 654,861 | ||||
Asset retirement obligations | 327,583 | 313,852 | ||||
Liabilities from price risk management activities | 2,464 | - | ||||
Operating lease liabilities | 15,637 | - | ||||
Other long-term liabilities | 93,028 | 123,359 | ||||
Total liabilities | 1,593,994 | 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 outstanding as of June 30, 2019 and December 31, 2018 | - | - | ||||
Common stock $0.01 par value; 270,000,000 shares authorized; 54,191,693 and 54,155,768 shares issued and outstanding as of June 30, 2019 and December 31, 2018, respectively | 542 | 542 | ||||
Additional paid-in capital | 1,339,507 | 1,334,090 | ||||
Accumulated deficit | (342,008) | (327,136) | ||||
Total stockholders' equity | 998,041 | 1,007,496 | ||||
Total liabilities and stockholders' equity | $ | 2,592,035 | $ | 2,479,986 | ||
TALOS ENERGY INC. | |||||||||||||||
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||||||||||
(In thousands, except per common share amounts) | |||||||||||||||
(Unaudited) | |||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Revenues and other: | |||||||||||||||
Oil revenue | $ | 256,908 | $ | 180,161 | $ | 412,587 | $ | 307,854 | |||||||
Natural gas revenue | 14,746 | 16,448 | 29,193 | 29,171 | |||||||||||
NGL revenue | 6,645 | 7,297 | 11,711 | 12,731 | |||||||||||
Other | 8,511 | - | 12,032 | - | |||||||||||
Total revenue | 286,810 | 203,906 | 465,523 | 349,756 | |||||||||||
Operating expenses: | |||||||||||||||
Direct lease operating expense | 37,975 | 34,060 | 78,804 | 58,975 | |||||||||||
Insurance | 4,184 | 4,259 | 8,295 | 6,934 | |||||||||||
Production taxes | 506 | 564 | 1,088 | 955 | |||||||||||
Total lease operating expense | 42,665 | 38,883 | 88,187 | 66,864 | |||||||||||
Workover and maintenance expense | 12,296 | 17,714 | 35,315 | 24,619 | |||||||||||
Depreciation, depletion and amortization | 95,806 | 67,726 | 160,393 | 116,766 | |||||||||||
Write-down of oil and natural gas properties | 12,361 | - | 12,361 | - | |||||||||||
Accretion expense | 9,945 | 9,492 | 19,552 | 14,252 | |||||||||||
General and administrative expense | 18,865 | 30,880 | 36,474 | 39,460 | |||||||||||
Total operating expenses | 191,938 | 164,695 | 352,282 | 261,961 | |||||||||||
Operating income | 94,872 | 39,211 | 113,241 | 87,795 | |||||||||||
Interest expense | (24,932) | (21,678) | (50,150) | (41,420) | |||||||||||
Price risk management activities income (expense) | 29,990 | (91,176) | (79,589) | (143,152) | |||||||||||
Other income (expense) | 831 | (1,269) | 1,264 | (1,078) | |||||||||||
Income (loss) before income taxes | 100,761 | (74,912) | (15,234) | (97,855) | |||||||||||
Income tax (expense) benefit | (5,997) | - | 362 | - | |||||||||||
Net income (loss) | $ | 94,764 | $ | (74,912) | $ | (14,872) | $ | (97,855) | |||||||
Net income (loss) per common share: | |||||||||||||||
Basic | $ | 1.75 | $ | (1.69) | $ | (0.27) | $ | (2.59) | |||||||
Diluted | $ | 1.74 | $ | (1.69) | $ | (0.27) | $ | (2.59) | |||||||
Weighted average common shares outstanding: | |||||||||||||||
Basic | 54,178 | 44,336 | 54,167 | 37,826 | |||||||||||
Diluted | 54,451 | 44,336 | 54,167 | 37,826 | |||||||||||
TALOS ENERGY INC. | |||||||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||
(In thousands) | |||||||
(Unaudited) | |||||||
Six Months Ended June 30, | |||||||
2019 | 2018 | ||||||
Cash flows from operating activities: | |||||||
Net loss | $ | (14,872) | $ | (97,855) | |||
Adjustments to reconcile net loss to net cash provided by operating activities | |||||||
Depreciation, depletion, amortization and accretion expense | 179,945 | 131,018 | |||||
Write-down of oil and natural gas properties | 12,361 | - | |||||
Amortization of deferred financing costs and original issue discount | 2,393 | 2,607 | |||||
Equity based compensation, net of amounts capitalized | 3,220 | 1,559 | |||||
Price risk management activities expense | 79,589 | 143,152 | |||||
Net cash paid on settled derivative instruments | (12,562) | (54,056) | |||||
Settlement of asset retirement obligations | (32,206) | (43,896) | |||||
Changes in operating assets and liabilities: | |||||||
Accounts receivable | (32,118) | 19,462 | |||||
Other current assets | 12,259 | (13,576) | |||||
Accounts payable | 23,646 | (53,126) | |||||
Other current liabilities | (37,164) | 52,543 | |||||
Other non-current assets and liabilities, net | (1,870) | 19,279 | |||||
Net cash provided by operating activities | 182,621 | 107,111 | |||||
Cash flows from investing activities: | |||||||
Exploration, development and other capital expenditures | (229,601) | (140,968) | |||||
Cash (paid for) acquired in acquisitions | (32,916) | 293,001 | |||||
Proceeds from sale of other property and equipment | 5,369 | - | |||||
Net cash provided by (used in) investing activities | (257,148) | 152,033 | |||||
Cash flows from financing activities: | |||||||
Redemption of Senior Notes and other long-term debt | (10,567) | (25,046) | |||||
Proceeds from Bank Credit Facility | 75,000 | 294,000 | |||||
Repayment of Bank Credit Facility | (25,000) | (54,000) | |||||
Repayment of LLC Bank Credit Facility | - | (403,000) | |||||
Other deferred payments | (9,921) | (17,469) | |||||
Payments of finance lease | (6,759) | (6,958) | |||||
Employee stock transactions | (283) | - | |||||
Net cash provided by (used in) financing activities | 22,470 | (212,473) | |||||
Net increase (decrease) in cash, cash equivalents and restricted cash | (52,057) | 46,671 | |||||
Cash, cash equivalents and restricted cash: | |||||||
Balance, beginning of period | 141,162 | 33,433 | |||||
Balance, end of period | $ | 89,105 | $ | 80,104 | |||
Supplemental Non-Cash Transactions: | |||||||
Capital expenditures included in accounts payable and accrued liabilities | $ | 165,310 | $ | 38,205 | |||
Supplemental Cash Flow Information: | |||||||
Interest paid, net of amounts capitalized | $ | 31,413 | $ | 23,635 | |||
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", "Adjusted EBITDA", "Adjusted EBITDA excluding hedges", "Adjusted EBITDA Margin", "Adjusted EBITDA Margin excluding hedges", "Net Debt", "LTM Adjusted EBITDA," "Annualized Adjusted EBITDA," "Net Debt to LTM Adjusted EBITDA" and "Net Debt to Annualized 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 Adjusted EBITDA; reconciliation of Adjusted EBITDA Margin
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", "Adjusted EBITDA", "Adjusted EBITDA excluding hedges", "Adjusted EBITDA Margin", "Adjusted EBITDA Margin Excluding Hedges", "Net Debt", "Annualized Adjusted EBITDA" and "Net Debt to Annualized 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 Adjusted EBITDA; reconciliation of Adjusted EBITDA Margin
"Adjusted EBITDA" is not a measure of net income (loss) as determined by GAAP. We use this measure as a supplemental measure because we believe it provides meaningful information to our investors. We define Adjusted EBITDA as net income (loss) plus interest expense, income tax expense, depreciation, depletion and amortization, accretion expense, loss on debt extinguishment, transaction related costs, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), non-cash (gain) loss on sale of assets, non-cash write-down of oil and natural gas properties, non-cash write-down of other well equipment inventory and non-cash equity based compensation expense. We believe the presentation of Adjusted EBITDA is important 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. Adjusted EBITDA has limitations as an analytical tool 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) or any other measure of financial performance presented in accordance with GAAP.
"Adjusted EBITDA excluding hedges" is defined as 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" is defined as Adjusted 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 Adjusted EBITDA, from Adjusted EBITDA to 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 September 30, | Three Months December 31, | Three Months March 31, | Three Months June 30, | ||||||||
Reconciliation of net income (loss) to Adjusted EBITDA: | ||||||||||||
Net income (loss) | $ | 13,109 | $ | 306,286 | $ | (109,636) | $ | 94,764 | ||||
Interest expense | 24,837 | 23,857 | 25,218 | 24,932 | ||||||||
Income Tax Expense (Benefit) | - | 2,922 | (6,359) | 5,997 | ||||||||
Depreciation, depletion and amortization | 87,808 | 84,145 | 64,587 | 95,806 | ||||||||
Write-down of oil and natural gas properties | - | - | - | 12,361 | ||||||||
Accretion expense | 10,162 | 10,930 | 9,607 | 9,945 | ||||||||
Loss on debt extinguishment | 356 | - | - | - | ||||||||
Transaction related costs | 7,595 | 4,579 | 2,493 | 710 | ||||||||
Derivative fair value (gain) loss(1) | 53,330 | (256,917) | 109,579 | (29,990) | ||||||||
Net cash receipts (payments) on settled derivative instruments(1) | (40,746) | (16,345) | (3,019) | (9,543) | ||||||||
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 | 570 | 764 | 1,259 | 1,961 | ||||||||
Adjusted EBITDA | $ | 157,021 | $ | 158,755 | $ | 93,729 | $ | 206,943 | ||||
Net cash receipts (payments) on settled derivative instruments(1) | 40,746 | 16,345 | 3,019 | 9,543 | ||||||||
Adjusted EBITDA excluding hedges | $ | 197,767 | $ | 175,100 | $ | 96,748 | $ | 216,486 | ||||
Production and Revenue: | ||||||||||||
Boe(2) | 5,052 | 4,910 | 3,782 | 5,369 | ||||||||
Revenue | 282,868 | 258,664 | 175,192 | 278,299 | ||||||||
Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin: | ||||||||||||
Adjusted EBITDA divided by Revenue (%) | 56 | % | 61 | % | 54 | % | 72 | % | ||||
Adjusted EBITDA per Boe(2) | $ | 31.08 | $ | 32.33 | $ | 24.78 | $ | 38.54 | ||||
Adjusted EBITDA excl hedges divided by Revenue (%) | 70 | % | 68 | % | 55 | % | 75 | % | ||||
Adjusted EBITDA excl hedges per Boe(2) | $ | 39.15 | $ | 35.66 | $ | 25.58 | $ | 40.32 | ||||
(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 Adjusted Net Income and Adjusted Earnings per Share
"Adjusted Net Income" is not a measure of net income (loss) as determined by GAAP. We use this measure as a supplemental measure because we believe it provides meaningful information to our investors. We define Adjusted Net Income as net income (loss) plus accretion expense, loss on debt extinguishment, transaction related costs, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives) and non-cash equity based compensation expense. We believe the presentation of Adjusted Net Income is important 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 has limitations as an analytical tool 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) or any other measure of financial performance presented in accordance with GAAP.
"Adjusted Earnings per Share" is defined as Adjusted Net Income divided by the number of common shares.
($ thousands, except per share amounts) | Three Months Ended, June 30, 2019 | |
Reconciliation of Net Income to Adjusted Net Income: | ||
Net income | $ | 94,764 |
Accretion expense | 9,945 | |
Transaction related costs | 710 | |
Derivative fair value (gain) loss(1) | (29,990) | |
Net cash receipts (payments) on settled derivative instruments(1) | (9,543) | |
Non-cash equity-based compensation expense | 1,961 | |
Adjusted Net Income | $ | 67,847 |
Weighted average common shares outstanding at June 30, 2019: | ||
Basic | 54,178 | |
Diluted | 54,451 | |
Net Income per common share (Income Per Share): | ||
Basic | $ | 1.75 |
Diluted | $ | 1.74 |
Adjusted Net Income per common share (Adjusted Earnings Per Share): | ||
Basic | $ | 1.25 |
Diluted | $ | 1.25 |
(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. |
Reconciliation of Net Debt, Net Debt to LTM Adjusted EBITDA and Net Debt to Annualized Adjusted EBITDA
"Net Debt" is not a measure of Debt as determined by GAAP. We define Net Debt as the total Debt principal of the Company plus the Finance Lease balance minus Cash.
"Net Debt to LTM Adjusted EBITDA" is defined as Net Debt divided by the LTM Adjusted EBITDA.
"Net Debt to Annualized Adjusted EBITDA" is defined as Net Debt divided by the Annualized 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.
Reconciliation of Net Debt ($ thousand) at June 30, 2019: | ||
Debt principal | $ | 711,928 |
Finance Lease | 86,910 | |
Gross Debt | $ | 798,838 |
Cash | (89,105) | |
Net Debt | $ | 709,733 |
Reconciliation of LTM Adjusted EBITDA: | ||
Adjusted EBITDA for the three month period ended September 30, 2018 | $ | 157,021 |
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 | |
LTM Adjusted EBITDA | $ | 616,448 |
Reconciliation of Annualized Adjusted EBITDA: | ||
Adjusted EBITDA for the three month period ended June 30, 2019 | $ | 206,943 |
x4 | ||
Annualized Adjusted EBITDA | $ | 827,772 |
Reconciliation of Net Debt to Adjusted EBITDA | ||
Net Debt / LTM Adjusted EBITDA | 1.15x |
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 June 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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