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 Talos Energy LLC Announces Third Quarter 2017 Financial and Operating Results

 

HOUSTON, TX — November 21, 2017 — Talos Energy LLC ("Talos” or the "Company”) today announced its financial and operating results for the third quarter ended September 30, 2017.

Financial and operating highlights for the third quarter 2017 include:

·        Production for the third quarter 2017 averaged 28.7 thousand barrels of oil equivalent per day ("MBoe/d”) representing a 32% increase over the third quarter of 2016.

·        Total revenue for the third quarter 2017 was $100.0 million compared to $63.8 million for the third quarter 2016.

·        Direct lease operating expense for the third quarter 2017 was $9.68 per barrel of oil equivalent, a decrease of 26% from the third quarter 2016.

·        Successful exploration test on the Zama-I well in the shallow waters off the coast of Mexico.

·        Completion of the Tornado II drilling campaign in the Phoenix Field resulting in two positive outcomes, a successful exploration test penetration in a fault block adjacent to the Company’s initial Tornado discovery in 2016 and a sidetrack well to delineate the initial discovery where completion operations are currently underway.

Tim Duncan, Talos President and Chief Executive Officer, commented, "Our results for the third quarter continue to reflect the Company’s ability to utilize the best geophysical techniques to reduce investment risk and deliver visible growth and attractive returns through the Company’s drilling program. The Tornado II drilling campaign in the US Gulf of Mexico provides another high impact well with near term production potential and future drilling inventory with compelling economics. Our exploration success offshore Mexico provides long-term opportunities in a world class basin. More importantly, we have been able to grow our production and add these discoveries within operating cash flows, and we are proactively hedging to ensure this trend continues.”

FINANCIAL RESULTS

Talos recorded a net loss from operations of $36.2 million for the third quarter 2017. The net loss includes $36.7 million from mark-to-market losses on open oil and natural gas derivative contracts. Adjusted earnings before interest, taxes, depreciation and amortization ("Adjusted EBITDA”) was $67.7 million, or $25.67 per barrel of oil equivalent sold. See the definition of Adjusted EBITDA and a reconciliation to net income in the "Non-GAAP Financial Measure” schedule below.

Production volumes for the third quarter of 2017 were 28.7 MBoe/d compared to 21.8 MBoe/d for the third quarter of 2016. The production mix for the third quarter of 2017 was 69% oil, 24% natural gas and 7% natural gas liquids ("NGLs”). The increase in production volumes was primarily attributable to a 9.5 MBoe/d increase in production volumes from the Tornado well, GC 281 #1ST (T-9), in the Phoenix Field, which commenced on October 27, 2016, partially offset by production deferrals resulting from the effects of weather and third party pipeline downtime, which we expect to continue in early fourth quarter.

Total revenue for the third quarter 2017 was $100.0 million compared to $63.8 million for the third quarter of 2016. Third quarter 2017 revenues exclude $8.6 million of realized derivative settlements. Prices realized during the third quarter of 2017 averaged $46.02 per Bbl of oil, $2.97 per Mcf of natural gas and $23.19 per Bbl of NGLs.

Total lease operating expense for the third quarter 2017 was $28.6 million, or 10.83 per Boe, compared to $29.3 million, or 14.59 per Boe, for the third quarter 2016.

Depreciation, depletion and amortization expense for the third quarter 2017 was $37.7 million compared to $28.9 million for the third quarter 2016. The increase is primarily due to an increase in production volumes in the third quarter 2017.

General and administrative expense for the third quarter 2017 was $9.7 million compared to $6.8 million for third quarter 2016. The increase was primarily attributable to a $3.4 million increase in transaction related costs offset by a $0.4 million decrease in employee related expenses.

Price risk management expense for the third quarter 2017 was $28.1 million compared to income of $11.4 million for third quarter 2016. The decrease of $39.5 million was attributable to a $15.3 million decrease in mark to market fair value of our open derivative contracts and a $24.2 million decrease in cash settlement gains.

OPERATING RESULTS

United States Gulf of Mexico — Asset Management

We continue to focus on our shallow water recompletion and well work program with two projects underway at the end of the third quarter 2017. During 2017, the Company has performed 15 recompletions and well work projects, of which 11 were successful with initial production from these projects of approximately 3,000 gross Boe/d. The Company will continue to focus on low risk projects that offer attractive yields in today’s commodity price environment. We expect to perform 8-12 additional recompletions and well work projects during the remainder of 2017.

United States Gulf of Mexico — Drilling Portfolio

In October 2017, the Company completed the Tornado II deepwater drilling campaign in the Phoenix Field of the Gulf of Mexico in approximately 2,700 feet of water. The Tornado II drilling campaign consisted of an exploratory test penetration in a fault block adjacent to the Company’s initial Tornado discovery in 2016, followed by a sidetrack well to delineate the initial reservoir.

The test penetration was drilled to a total vertical depth of approximately 21,107 feet and logged approximately 222 feet measured depth (176 feet total vertical depth) of net oil pay across the B-5 and B-6 sands. The discovered resource increases the Company’s existing drilling inventory and will be considered in the development of the 2018 drilling campaign.

The sidetrack delineation well, known as the GC 281 #2ST well, was drilled to a total vertical depth of approximately 21,057 feet and logged approximately 297 feet total measured depth (282 feet total vertical depth) of net oil pay across the B-5 and B-6 sands. Initial production from the GC 281 #2ST is expected during the fourth quarter of 2017 and will be tied into the existing Phoenix Field subsea infrastructure, which flows to the Helix Producer I ("HP-I”), a dynamically positioned floating production facility. To execute the Tornado II drilling program, the Company contracted the Ensco 8503, a dynamically positioned floating drilling rig that also drilled the Company’s historic Zama-1 discovery in Mexico.

In October 2017, the Company finalized drilling plans and executed an offshore day work drilling contract with Ensco Offshore Company to utilize the Ensco 75 to drill the EW 306 A-15ST#3 well, a deeper pool exploration well targeting two amplitude-supported Upper Miocene objectives. The sidetrack well will be drilled from the existing EW 305A platform and is expected to spud in January 2018. If the sidetrack is successful, Talos would immediately commence completion and hook-up operations with initial production occurring by the end of the first quarter 2018.

Offshore Mexico

In July 2017, the Company completed drilling operations on the offshore Mexico Zama-I exploration well, reaching a total depth of 13,480 feet. The Zama-I well is the first offshore exploration well to be drilled in Mexico by the private sector. Well results confirmed the base of the reservoir section, with no penetration of an oil-water contact. The well was also drilled deeper into a higher risk formation, but no additional commercial quantities of hydrocarbons were encountered. The gross oil bearing interval is over 1,100 feet with petrophysical data indicating excellent rock properties and an oil sample with 30 degree API gravity oil. Initial gross oil in-place estimates for the Zama-I well are from 1.4 to 2.0 billion barrels. The well has been suspended as a future producer. The Company is now analyzing all the data gathered from Zama-I and evaluating the optimal methods for appraisal and development of the discovery.

CAPITAL SUMMARY

Our additions to property and equipment, excluding acquisitions, plugging and abandonment costs and asset retirement costs, on an accrual basis were $49.8 million, which included $32.9 million for drilling of the Tornado II well. Additionally, we incurred $15.0 million on plugging and abandonment during the third quarter 2017.

 

Exploration

 

$

35,422

 

Development

 

 

13,036

 

Geological and geophysical/seismic

 

 

1,068

 

Land and lease

 

 

182

 

Other

 

 

132

 

Total

 

$

49,840

 

LIQUIDITY UPDATE

As of September 30, 2017, the Company’s available liquidity was $115.4 million consisting of $47.4 million in cash and $68.0 million of available capacity under our revolving credit facility. On October 31, 2017, Talos executed the ninth amendment to our credit agreement deferring the next borrowing base redetermination to January 2018 pending further analysis on the Tornado II completion.

OIL AND NATURAL GAS DERIVATIVES

The following table reflects the contracted volumes and weighted average prices we will receive under our derivative contracts as of September 30, 2017:

 

Production Period

 

Instrument

Type

 

Average

Daily

Volumes

 

 

Weighted

Average

Swap Price

 

 

Weighted

Average

Put Price

 

 

Weighted

Average

Call Price

 

Crude Oil – LLS:

 

 

 

(Bbls)

 

 

(per Bbl)

 

 

(per Bbl)

 

 

(per Bbl)

 

October 2017 – December 2017

 

Swap

 

 

2,873

 

 

$

72.14

 

 

$

 

 

$

 

Crude Oil – WTI:

 

 

 

(Bbls)

 

 

(per Bbl)

 

 

(per Bbl)

 

 

(per Bbl)

 

October 2017 – December 2017

 

Swap

 

 

6,451

 

 

$

53.84

 

 

$

 

 

$

 

October 2017 – December 2017

 

Costless

Collar

 

 

7,473

 

 

$

 

 

$

47.17

 

 

$

55.92

 

January 2018 – December 2018

 

Swap

 

 

13,922

 

 

$

53.99

 

 

$

 

 

$

 

January 2019 – December 2019

 

Swap

 

 

8,105

 

 

$

52.19

 

 

$

 

 

$

 

Natural Gas – Henry Hub NYMEX:

 

 

 

(MMBtu)

 

 

(per MMBtu)

 

 

(per MMBtu)

 

 

(per MMBtu)

 

October 2017 – December 2017

 

Swap

 

 

34,692

 

 

$

3.06

 

 

$

 

 

$

 

January 2018 – December 2018

 

Swap

 

 

26,346

 

 

$

3.00

 

 

$

 

 

$

 

January 2019 – December 2019

 

Swap

 

 

10,146

 

 

$

2.99

 

 

$

 

 

$

 

Subsequent to September 30, 2017, we entered into 2018 WTI crude oil swap contracts for 10,000 Bbls per day at $53.48 per Bbl and 2019 WTI crude oil swap contracts for 5,100 Bbls per day for the first half of the year at 53.58.

ABOUT TALOS ENERGY LLC

Talos is a technically driven independent exploration and production company with operations in the United States Gulf of Mexico and in the shallow waters off the coast of Mexico. Our focus in the United States Gulf 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.talosenergyllc.com.

FORWARD-LOOKING STATEMENTS

The information in this press release includes "forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this press release, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. 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 all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas and NGLs. 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, and the other risks described in "Item 1A, Risk Factors” in the Company’s 2016 Annual Report.

Should one or more of the risks or uncertainties described in the Company’s 2016 Annual Report 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, included in the Company’s 2016 Annual Report 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, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this press release.

NON-GAAP FINANCIAL MEASURES

This news release contains certain non-GAAP financial measures that management believes are good tools for internal use and the investment community in evaluating Talos Energy LLC’s overall financial performance. These non-GAAP financial measures are broadly used to value and compare companies in the crude oil and natural gas industry, although no all companies define these measures in the same way. In addition, these non-GAAP measures are not a substitute for financial measures prepared in accordance with GAAP, and should therefore be considered only as supplemental to such GAAP financial measures. Please see the attached schedules for reconciliations of the differences between the non-GAAP financial measures used in this news release and the most directly comparable GAAP financial measures.


Adjusted EBITDA

"Adjusted EBITDA” is not a measure of net income (loss) as determined by accounting principles generally accepted in the United States of America ("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 and provision for income taxes, depreciation, depletion and amortization, accretion expense, transaction related costs, impairment, adjusted for 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 substitutes 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.

The following table presents a reconciliation of the GAAP financial measure of net loss to Adjusted EBITDA for each of the periods indicated (in thousands, except for Boe data):

 

 

 

Three Months Ended September 30, 2017

 

Reconciliation of net loss to Adjusted EBITDA:

 

 

 

 

Net income (loss)

 

$

(36,177

)

Interest expense

 

 

21,464

 

Depreciation, depletion and amortization

 

 

37,746

 

Accretion expense

 

 

4,299

 

Transaction related costs

 

 

3,383

 

Derivative fair value gain(1)

 

 

28,086

 

Net cash receipts on settled derivative instruments(1)

 

 

8,619

 

Non-cash equity-based compensation

 

 

275

 

Adjusted EBITDA

 

$

67,695

 

Production:

 

 

 

 

Boe(2)

 

 

2,637

 

Other Financial Data:

 

 

 

 

Adjusted EBITDA per Boe(2)

 

$

25.67

 

 

(1)        The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity 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.

CONTACT: INQUIRIES TO THE COMPANY

Timothy S. Duncan
President & CEO
713-328-3000
investor@talosenergyllc.com 

 




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