HOUSTON, Aug. 6, 2018 /PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its financial and operational results for the second quarter ended June 30, 2018, and reaffirmed the previously released pro forma full year 2018 production, expenses and capital expenditure guidance.
Combination with Stone Energy Corporation
On May 10, 2018, Talos Energy LLC and Stone Energy Corporation ("Stone") completed a strategic transaction pursuant to which both became wholly-owned subsidiaries of the Company ("Stone Combination"). Talos Energy LLC was considered the accounting acquirer in the Stone Combination under accounting principles generally accepted in the United States of America ("GAAP"). Accordingly, the Company's historical financial and operating data, which cover periods prior to May 10, 2018, reflect only the assets, liabilities and operations of Talos Energy LLC (as the Company's predecessor through May 10, 2018), and do not reflect the assets, liabilities and operations of Stone prior to May 10, 2018.
The pro forma financial information set forth in this press release gives pro forma effect to the Stone Combination as if it occurred on January 1, 2018. Stone's acquisition of the Ram Powell deepwater assets on May 1, 2018 and Ram Powell's respective financial results are included in the Company's pro forma results from May 1, 2018 onwards. Unless expressly stated as pro forma, the financial and operating data in this press release is presented in accordance with GAAP.
Key highlights of the second quarter 2018 | |||||||
Three months | Six months ended | ||||||
GAAP | Pro | GAAP | Pro | ||||
Total production volumes (MBoe) | 3,915 | 4,696 | 6,831 | 9,182 | |||
Oil (MBbl/d) - Average daily production | 29.1 | 35.1 | 25.9 | 35.1 | |||
NGLs (MBbl/d) - Average daily production | 3.0 | 3.6 | 2.6 | 3.5 | |||
Natural Gas (MMcf/d) - Average daily production | 65.4 | 77.3 | 55.6 | 72.8 | |||
Total average daily (MBoe/d) | 43.0 | 51.6 | 37.7 | 50.7 | |||
Period results ($MM): | |||||||
Revenues | $ 204 | $ 244 | $ 350 | $ 472 | |||
Net Income (Loss) | $ (75 ) | $ (46 ) | $ (98 ) | $ (51 ) | |||
Adjusted EBITDA(1) | $ 101 | $ 128 | $ 187 | $ 269 | |||
Adjusted EBITDA excl. hedges(1) | $ 135 | $ 163 | $ 241 | $ 329 | |||
Adjusted EBITDA margin(1): | |||||||
Adjusted EBITDA margin (%) | 50 % | 52 % | 53 % | 57 % | |||
Adjusted EBITDA margin per Boe | $ 25.89 | $ 27.18 | $ 27.37 | $ 29.30 | |||
Adjusted EBITDA margin excl. hedges (%) | 66 % | 67 % | 69 % | 70 % | |||
Adjusted EBITDA margin excl. hedges per Boe | $ 34.48 | $ 34.79 | $ 35.28 | $ 35.79 | |||
Additional highlights
• | As of June 30, 2018 the Company's total debt principal was $748 million, including capital lease. Net Debt to pro forma annualized Adjusted EBITDA(1) was 1.2x |
• | Liquidity position of approximately $433 million as of June 30, 2018, including $354 million available under the $600 million Bank Credit Facility (Borrowing Base) and approximately $79 million of cash |
(1) | Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA Margin, Adjusted EBITDA Margin excluding hedges, Net Debt 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, "It was a historical quarter for Talos, as we closed our transformational acquisition of Stone and the Ram Powell deepwater asset, both in May 2018. These assets will also provide significant scale and diversity to our base business, which we expect will allow us to continue to maintain positive free cash flow after investing in our capital program and servicing our debt. Production from the acquired assets will be more impactful in the second half of 2018, since Ram Powell was only partially included in the second quarter. The commencement of production from the Mt. Providence well in July, at the high end of our production rate expectations, will also positively impact the remainder of the year as compared to the first six months.
"Our growth capital is focused on two main goals, which are investing in projects that utilize our existing infrastructure to add high margin barrels with superior pricing, and continuing to pursue moderate risk but high impact exploration efforts, following the success of our significant Zama discovery in offshore Mexico. We continue to stay on schedule on both fronts.
"We also continue to find synergies related to the combination with Stone and our integration team is focused on realizing these savings by year end. The strength of the combined business will deepen our inventory portfolio and will also put us in a position to pursue accretive business development opportunities in the core areas where we currently operate."
Reaffirmation of 2018 pro forma Full-Year Financial and Operating guidance
The Company reaffirms the previously released 2018 pro forma full-year financial and operating guidance. This guidance is subject to all cautionary statements and limitations described under "Cautionary Statement About Forward-Looking Statements" below:
Pro Forma Full-Year Production | Low | High |
Oil (MMBbl) | 12.5 | 13.5 |
Natural Gas (Bcf) | 27.0 | 30.0 |
NGL (MMBbl) | 0.9 | 1.0 |
Total (MMBoe) | 18.0 | 19.5 |
Average Daily Production (MBoe/d) | 49 | 53 |
Oil / Liquids percentage | 74 % | 76 % |
Pro Forma Full-Year Operating and Capital Expenses ($mm) | Low | High |
Lease Operating Expenses | $ 170 | $ 180 |
Workover and Maintenance Expense | $ 49 | $ 54 |
G&A - excludes combination related costs | $ 57 | $ 62 |
Capital Expenditures | $ 430 | $ 450 |
Recent Developments and Operations Update
U.S. Gulf of Mexico
- On July 10, 2018, our Mt. Providence well began producing 60 days ahead of the originally scheduled completion date of early September. The Mt. Providence well was successfully drilled in January 2018 by Stone. We completed the well and connected it to the 100% Talos owned Pompano platform in the Company's Mississippi Canyon Complex within six months of concluding drilling operations. The well is currently producing 3,850 Boe per day ("Boe/d") gross (3,370 Boe/d net).
- We drilled the first two development wells in our 2018 Shelf drilling program - Ship Shoal 224 ("SS224") E21ST and Ewing Banks 306 ("EW306") A20 - during the first half of 2018:
- SS224 E21ST is currently producing at approximately 750 Boe/d gross (610 Boe/d net)
- The EW306 A20 well encountered approximately 120 feet of pay across 5 sands. The A20 well successfully targeted three previously defined field sands and discovered two deeper reservoirs. The deeper discovery will be completed first with an expected initial production rate of approximately 1,250 - 1,500 Boe/d gross (1,000 - 1,200 Boe/d net) starting in the third quarter of 2018. Talos owns 100% working interest ("WI") in EW306
- Our asset management activities, typically consisting of smaller recompletions and well work, added approximately 2,000 Boe/d in the second quarter and year to date have added approximately 2,600 Boe/d, using the 30 day average of their first month of production. These opportunities represent low conversion costs, quick payouts, lower unit cost per barrel and allow us to better manage the timing of the plugging obligations of our more mature assets.
Mexico
- In April of 2018, Talos submitted the appraisal plan relating to Block 7 for the Zama discovery to the Mexican industry regulator, the National Hydrocarbons Commission ("CNH"). This appraisal plan involves, at a minimum, the drilling of three boreholes, a Drill Stem Test (DST) and extensive coring and reservoir fluid sampling. Talos has been in consultation with the CNH and anticipates timely approval of the appraisal plan. The first well in the appraisal program is planned to spud in the fourth quarter of 2018 utilizing the semi-submersible rig Ensco 8503, which is the same rig that drilled the Zama #1 discovery well in 2017. We expect the appraisal program to last through mid-year 2019.
- In July 2018, Talos requested approval from the Mexico Ministry of Energy ("SENER") to enter into a Preliminary Unitization Agreement ("PUA") with Pemex for a potential unit involving the Zama field in Block 7 and the Pemex grant to the east of Block 7. The PUA serves primarily to create a clear path to signing the governing Unit Agreement and Unit Operating Agreement for the Zama discovery. This will allow for a timely Final Investment Decision ("FID") and commencement of development activities, with a goal of first production from Zama in 2022.
- In addition to Zama, the appraisal campaign proposes to deepen one wellbore to test the Marte prospect in Block 7.
- We are also focusing our efforts on executing our first exploration project on Block 2, which is located in approximately 100 feet of water. The first well will test the Bacab prospect, which is expected to be drilled in the second quarter of 2019.
SECOND QUARTER 2018 RESULTS
Production, Realized Prices and Revenue
Production: Production for the second quarter of 2018 was 3.9 million Boe compared to 2.6 million Boe for the second quarter of 2017. Second quarter of 2018 production was comprised of 2.7 million barrels of oil, 0.3 million barrels of NGLs and 5.9 billion cubic feet ("Bcf") of natural gas. Oil and NGLs production accounted for 75% of the total production for the second quarter of 2018, as compared to 73% of the same period in 2017.
On a pro forma basis, production for the second quarter of 2018 was 4.7 million Boe. Second quarter of 2018 pro forma production was comprised of 3.2 million barrels of oil, 0.3 million barrels of NGLs and 7.0 Bcf of natural gas. Oil and NGLs production accounted for 75% of the total pro forma production for the second quarter of 2018.
Production was negatively affected by two unplanned third-party downtime events in the second quarter. Helix required an eight-day downtime in the Helix Producer 1 ("HP-1"), effectively shutting-in production from the Phoenix and Tornado fields by the same number of days. In addition, downtime in third-party pipelines further affected the quarter by curtailing production from several shallow water fields. These brief interruptions were limited to the second quarter and are not expected to have an impact in our reaffirmed annual production guidance.
The table below provides additional detail of our oil, natural gas and NGLs production volumes and sales prices per unit for the three months and six months ended on June 30, 2018:
Three months ended | Six months ended | ||||||
GAAP | Pro | GAAP | Pro | ||||
Production volumes | |||||||
Oil production volume (MBbls) | 2,651 | 3,197 | 4,682 | 6,355 | |||
NGL production volume (MBbls) | 273 | 326 | 471 | 632 | |||
Natural Gas production volumes (MMcf) | 5,948 | 7,032 | 10,069 | 13,168 | |||
Total production volumes (MBoe) | 3,915 | 4,696 | 6,831 | 9,182 | |||
Average daily production volumes | |||||||
Oil (MBbl/d) | 29.1 | 35.1 | 25.9 | 35.1 | |||
NGLs (MBbl/d) | 3.0 | 3.6 | 2.6 | 3.5 | |||
Natural Gas (MMcf/d) | 65.4 | 77.3 | 55.6 | 72.8 | |||
Total average daily (MBoe/d) | 43.0 | 51.6 | 37.7 | 50.7 | |||
Average realized prices (excluding hedges) | |||||||
Oil ($/Bbl) | $ 67.96 | $ 67.91 | $ 65.75 | $ 65.78 | |||
NGLs ($/Bbl) | $ 26.73 | $ 26.38 | $ 27.03 | $ 27.25 | |||
Natural Gas ($/Mcf) | $ 2.77 | $ 2.67 | $ 2.90 | $ 2.76 | |||
Barrel of oil equivalent ($/Boe) | $ 52.08 | $ 52.06 | $ 51.20 | $ 51.37 | |||
Revenue: Total revenue for the three months ended June 30, 2018 was $203.9 million compared to $95.4 million for the three months ended June 30, 2017, an increase of approximately $108.5 million, or 114%.
Oil revenue increased approximately $101.4 million, or 129%, during the three months ended June 30, 2018. This increase was primarily due to an increase of $21.98 per Bbl in our realized oil sales price and a 10.3 MBbl per day increase in oil production volumes, 9.6 MBbl per day of which was attributable to the Stone Combination.
Natural gas revenue increased approximately $3.6 million, or 28%, during the three months ended June 30, 2018. This increase was primarily due to a 19.1 MMcf per day increase in gas volumes, 22.6 MMcf per day of which was attributable to the Stone Combination, partially offset by a $0.29 per Mcf decrease in our realized gas sales price.
NGL revenue increased approximately $3.9 million, or 112%, during the three months ended June 30, 2018. This increase was due to an increase of $6.03 per Bbl in our realized NGL sales price and a 1.2 MBbl per day increase in NGL volumes, all of which were attributable to the Stone Combination.
Expenses
Lease operating expense: Total lease operating expense for three months ended June 30, 2018 was $38.9 million compared to $31.9 million for the three months ended June 30, 2017, an increase of approximately $6.9 million, or 22%. This increase was primarily related to $9.9 million of lease operating expense in connection with the Stone Combination, partially offset by a $2.9 million decrease due to additional reimbursements related to our production handling agreements primarily in the Phoenix Field.
Depreciation, depletion and amortization: Depreciation, depletion and amortization expense for the three months ended June 30, 2018 was $67.7 million compared to $36.2 million for the three months ended June 30, 2017, an increase of approximately $31.6 million, or 87%. This increase is primarily due to a $3.33 per Boe, or 24%, increase in the depletion rate on our proved oil and natural gas properties during the three months ended June 30, 2018. Depletion on a per Boe basis increased primarily due to an increase in proved properties related to the Stone Combination and higher estimated future development costs related to proved undeveloped reserves in the Phoenix Field.
General and administrative expense: General and administrative expense for the three months ended June 30, 2018 was $30.9 million compared to $7.5 million for the three months ended June 30, 2017, an increase of approximately $23.4 million, or 313%. This increase was primarily attributable to $18.3 million in transaction related costs related to the Stone Combination and additional general and administrative expenses as a result of the combined company. In connection with the Stone Combination, we expect to capture significant synergies, and Talos is focused on realizing these savings by year-end 2018.
Other operating expense: Other operating expense for the three months ended June 30, 2018 was $27.2 million compared to $13.5 million for the three months ended June 30, 2017, an increase of approximately $13.7 million, or 101%. This increase was primarily related to an increase of $4.5 million and $4.1 million in workover and maintenance expense and accretion expense, respectively, in connection with the Stone Combination. This increase also relates to a $5.0 million increase in repairs and maintenance during the three months ended June 30, 2018 primarily related to $1.3 million in repairs on SMI 130 and inspection and reconnection support in the Phoenix Field of $1.2 million.
Price risk management activities: Price risk management activities for the three months ended June 30, 2018 resulted in a $91.2 million expense compared to income of $39.0 million for the three months ended June 30, 2017. The change of approximately $130.2 million was attributable to an $87.4 million decrease in the fair value of our open derivative contracts and a $42.8 million decrease in cash settlement gains for the three months ended June 30, 2018.
Other financial metrics
Net Income (Loss) and Adjusted EBITDA: Net Income (Loss) in the second quarter of 2018 was ($75) million and in the first six months of the year ($98) million. The loss numbers are primarily due to non-cash mark-to-market expenses associated with unrealized commodity hedges. Pro forma Net Income (Loss) in the second quarter of 2018 was ($46) million and in the first six months of the year ($51) million. The pro forma loss numbers are primarily due to non-cash mark-to-market expenses associated with unrealized commodity hedges.
Adjusted EBITDA for the three months ended on June 30, 2018 was $101 million and Adjusted EBITDA margin was 50%, or $25.89 per Boe. For the first half of 2018, Adjusted EBITDA was $187 million, with a margin of 53% or $27.37 per Boe. Excluding the effect of hedges, the margins would have been 66% or $34.48 per Boe for the second quarter and 69% or $35.28 for the first six months of the year.
Pro forma Adjusted EBITDA for the three months ended June 30, 2018 was $128 million and pro forma Adjusted EBITDA margin was 52%, or $27.18 per Boe. For the first half of 2018, pro forma Adjusted EBITDA was $269 million, with a margin of 57% or $29.30 per Boe. Excluding the effect of hedges, the pro forma margins would have been 67% or $34.79 per Boe for the second quarter and 70% or $35.79 per Boe for the first six months of the year.
Financial position: As of June 30, 2018, the Company had approximately $648 million of long-term debt, excluding deferred financing costs and original issue discount. The balance includes $397 million of second lien notes, $240 million of borrowings under the bank credit facility and an $11 million building loan. In addition to the Company's long-term debt, as of June 30, 2018, Talos had a capital lease obligation with a balance of approximately $100 million.
Liquidity position: As of June 30, 2018, the Company had a liquidity position of approximately $433 million, which included $354 million available under the $600 million bank credit facility and approximately $79 million of cash.
Leverage and credit metrics: The pro forma annualized Adjusted EBITDA for the six months ended on June 30, 2018 was $538 million. As of June 30, 2018, the Company's total debt was $748 million and net debt was $669 million, both including capital lease. Therefore, the Net Debt to annualized pro forma Adjusted EBITDA ratio of Talos was 1.2x.
CONFERENCE CALL AND WEBCAST INFORMATION
Talos will host a conference call, which will also be broadcast live over the internet, on Tuesday, August 7, 2018 at 10:00 am Eastern Time (9:00am Central Time).
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 1-877-870-4263 (U.S. toll-free), 1-855-669-9657 (Canada toll-free) or 1-412-317-0790 (international). Please dial in approximately 10 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 Tuesday, August 14, 2018 and can be accessed by dialing 1-877-344-7529 and using access code 10122717.
ABOUT TALOS ENERGY
Talos is a technically driven independent exploration and production company with operations in the United StatesGulf of Mexico and in the shallow waters off the coast of Mexico. Our focus in the United StatesGulf of Mexico is the exploration, acquisition, exploitation and development of shallow and deepwater assets near existing infrastructure. The shallow waters off the coast of Mexico provide us high impact exploration opportunities in an emerging basin. The Company's website is located at 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" 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 business or employee relationships resulting from the business combination between Talos Energy LLC and Stone Energy Corporation, competitive responses to such business combination, 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, litigation relating to the business combination, and other factors that may affect our future results and business, generally, including those discussed under the heading "Risk Factors" in our final consent solicitation statement/prospectus, dated April 9, 2018, filed with the Securities and Exchange Commission (the "SEC") pursuant to Rule 424(b)(3) under the Securities Act and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, 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 STATEMENTS OF OPERATIONS (In thousands, except per common share amounts) (Unaudited) | |||||||
Three Months Ended | Six Months Ended | ||||||
2018 | 2017 | 2018 | 2017 | ||||
Revenues: | |||||||
Oil revenue | $ 180,161 | $ 78,719 | $ 307,854 | $ 162,487 | |||
Natural gas revenue | 16,448 | 12,888 | 29,171 | 26,062 | |||
NGL revenue | 7,297 | 3,436 | 12,731 | 7,069 | |||
Other | - | 383 | - | 1,632 | |||
Total revenue | 203,906 | 95,426 | 349,756 | 197,250 | |||
Operating expenses: | |||||||
Direct lease operating expense | 34,060 | 28,871 | 58,975 | 56,735 | |||
Insurance | 4,259 | 2,688 | 6,934 | 5,409 | |||
Production taxes | 564 | 380 | 955 | 645 | |||
Total lease operating expense | 38,883 | 31,939 | 66,864 | 62,789 | |||
Workover and maintenance expense | 17,714 | 8,225 | 24,619 | 17,047 | |||
Depreciation, depletion and amortization | 67,726 | 36,157 | 116,766 | 76,088 | |||
Accretion expense | 9,492 | 5,321 | 14,252 | 10,509 | |||
General and administrative expense | 30,880 | 7,470 | 39,460 | 17,216 | |||
Total operating expenses | 164,695 | 89,112 | 261,961 | 183,649 | |||
Operating income | 39,211 | 6,314 | 87,795 | 13,601 | |||
Interest expense | (21,678) | (20,805) | (41,420) | (39,577) | |||
Price risk management activities income (expense) | (91,176) | 38,995 | (143,152) | 84,888 | |||
Other income (expense) | (1,269) | 103 | (1,078) | 157 | |||
Total other income (expense) | (114,123) | 18,293 | (185,650) | 45,468 | |||
Income (loss) before income taxes | (74,912) | 24,607 | (97,855) | 59,069 | |||
Income tax expense (benefit) | - | - | - | - | |||
Net income (loss) | $ (74,912) | $ 24,607 | $ (97,855) | $ 59,069 | |||
Net income (loss) per common share: | |||||||
Basic | $ (1.38) | $ 1.23 | $ (1.81) | $ 2.95 | |||
Diluted | $ (1.38) | $ 1.23 | $ (1.81) | $ 2.95 | |||
Weighted average common shares outstanding: | |||||||
Basic | 54,156 | 20,038 | 54,156 | 20,038 | |||
Diluted | 54,156 | 20,038 | 54,156 | 20,038 | |||
TALOS ENERGY - PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per common share amounts) (Unaudited) | |||
Three Months Ended | Six Months Ended | ||
2018 | 2018 | ||
Revenues: | |||
Oil revenue | $ 217,098 | $ 418,052 | |
Natural gas revenue | 18,754 | 36,377 | |
NGL revenue | 8,601 | 17,223 | |
Total revenue | 244,453 | 471,652 | |
Operating expenses: | |||
Direct lease operating expense | 39,460 | 73,197 | |
Insurance | 4,870 | 9,426 | |
Production taxes | 635 | (1,175) | |
Total lease operating expense | 44,965 | 81,448 | |
Workover and maintenance expense | 19,786 | 31,169 | |
Depreciation, depletion and amortization | 74,316 | 147,809 | |
Accretion expense | 12,399 | 24,186 | |
General and administrative expense | 16,935 | 33,289 | |
Total operating expenses | 168,401 | 317,901 | |
Operating income | 76,052 | 153,751 | |
Interest expense | (15,046) | (38,580) | |
Price risk management activities income (expense) | (105,841) | (167,365) | |
Other income (expense) | (861) | 983 | |
Total other income (expense) | (121,748) | (204,962) | |
Income (loss) before income taxes | (45,696) | (51,211) | |
Income tax expense (benefit) | - | - | |
Net income (loss) | $ (45,696) | $ (51,211) | |
Net income (loss) per common share: | |||
Basic | $ (0.84) | $ (0.95) | |
Diluted | $ (0.84) | $ (0.95) | |
Weighted average common shares outstanding: | |||
Basic | 54,156 | 54,156 | |
Diluted | 54,156 | 54,156 | |
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 EBITDA", "Adjusted EBITDA excluding hedges", "Adjusted EBITDA margin", "Adjusted EBITDA margin excluding hedges", "Net Debt" 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, 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 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 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 this supplemental metric provides useful information to our investors, as this metric best shows how the actual commodity price changes impact 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 this supplemental metric provides useful information to our investors, as they can see how much we retain in Adjusted EBITDA terms as compared to the Revenue generated and how much per barrel we generate after accounting for certain operational and corporate costs, which Adjusted EBITDA is intended to represent.
"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):
Three Months Ended | Six Months Ended | ||||||
GAAP | Pro Forma | GAAP | Pro Forma | ||||
Reconciliation of net income (loss) to Adjusted EBITDA: | |||||||
Net income (loss) | $ (74,912) | $ (45,696) | $ (97,855) | $ (51,211) | |||
Interest expense | 21,678 | 15,043 | 41,420 | 38,580 | |||
Depreciation, depletion and amortization | 67,726 | 74,316 | 116,766 | 147,809 | |||
Accretion expense | 9,492 | 12,399 | 14,252 | 24,186 | |||
Loss on debt extinguishment | - | - | 1,408 | - | |||
Transaction related costs | 18,362 | - | 20,310 | - | |||
Derivative fair value (gain) loss(1) | 91,176 | 105,841 | 143,152 | 167,365 | |||
Net cash receipts (payments) on settled derivative instruments(1) | (33,627) | (35,756) | (54,056) | (59,614) | |||
Non-cash equity-based compensation expense | 1,456 | 1,456 | 1,559 | 1,907 | |||
Adjusted EBITDA | $ 101,351 | $ 127,603 | $ 186,956 | $ 269,022 | |||
Net cash receipts (payments) on settled derivative instruments(1) | 33,627 | 35,756 | 54,056 | 59,614 | |||
Adjusted EBITDA excluding hedges | $ 134,978 | $ 163,359 | $ 241,012 | $ 328,636 | |||
Production and Revenue: | |||||||
Boe(2) | 3,915 | 4,696 | 6,831 | 9,182 | |||
Revenue | 203,906 | 244,453 | 349,756 | 471,652 | |||
Adjusted EBITDA margin and Adjusted EBITDA margin excluding hedges: | |||||||
Adjusted EBITDA margin divided by Revenue (%) | 50 % | 52 % | 53 % | 57 % | |||
Adjusted EBITDA margin per Boe(2) | $ 25.89 | $ 27.18 | $ 27.37 | $ 29.30 | |||
Adjusted EBITDA margin excl hedges divided by Revenue (%) | 66 % | 67 % | 69 % | 70 % | |||
Adjusted EBITDA margin excl hedges per Boe(2) | $ 34.48 | $ 34.79 | $ 35.28 | $ 35.79 | |||
(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 Debt 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 Capital Lease balance minus Cash.
"Net Debt to Annualized Adjusted EBITDA" is defined as Net Debt divided by the Annualized Adjusted EBITDA.
We believe the presentation of Net Debt and Net Debt to Annualized Adjusted EBITDA is important to provide management and investors with additional important information to evaluate items required or permitted in calculating covenant compliance under our debt agreements.
June 30, 2018 | |
Reconciliation of Net Debt: | |
Debt principal | $ 647,706 |
Capital Lease | 99,663 |
Gross Debt | 747,369 |
Cash | (78,860) |
Net Debt | $ 668,509 |
Reconciliation of Pro Forma Annualized Adjusted EBITDA: | |
Pro forma Adjusted EBITDA for the six months ended June 30, 2018 | $ 269,022 |
x2 | |
Annualized pro forma Adjusted EBITDA | $ 538,044 |
Reconciliation of Net Debt to Annualized Pro Forma Adjusted EBITDA | |
Net Debt / Annualized pro forma Adjusted EBITDA | 1.2x |
The annualized information in this document is to provide additional relevant information to our investors and creditors. Beginning on September 30, 2018, Talos will need to comply with a financial covenant included in our Bank Credit Facility that requires us to maintain a Net Debt to Annualized Adjusted EBITDA equal to or lower than 3.0x, with the Annualized Adjusted EBITDA calculated the following way:
- On September 30, 2018: four times the Adjusted EBITDA for the third quarter of 2018
- On December 31, 2018: two times the Adjusted EBITDA for the six month period ended on December 31, 2018
- On March 31, 2019: Adjusted EBITDA for the nine month period ended on March 31 divided by nine and multiplied by 12
- On June 30, 2019: Adjusted EBITDA for the 12 month period ended on June 30, 2019
- For every subsequent quarter: trailing 12 month Adjusted EBITDA
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