EX-99.1

EX-99.1 2 d648962dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

LOGO

TALOS ENERGY ANNOUNCES THIRD QUARTER 2018 FINANCIAL AND OPERATIONAL RESULTS

Houston, November 5, 2018 – Talos Energy Inc. (“Talos” or the “Company”) (NYSE: TALO) today announced its financial and operational results for the quarter ended September 30, 2018.

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 Third Quarter 2018


	Three months ended September 30, 2018			Nine months ended September 30, 2018
	As Reported			As Reported			Pro Forma
Total production volumes (MBoe)		5,052			11,832			14,233
Oil (MBbl/d) – Average net daily production		38.1			30.0			36.1
NGLs (MBbl/d) – Average net daily production		4.5			3.2			3.8
Natural Gas (MMcfe/d) – Average net daily production		73.7			60.6			73.1
Total average net daily (MBoe/d)		54.9			43.3			52.1
Period results ($ million):
Revenues	$	282.9		$	632.6		$	754.5
Net Income	$	13.1		($	84.7	)	($	30.6	)
Adjusted EBITDA⁽¹⁾	$	157.0		$	344.0		$	426.0
Adjusted EBITDA excl. hedges⁽¹⁾	$	197.8		$	438.8		$	526.6
Adjusted EBITDA margin⁽¹⁾:
Adjusted EBITDA (%)		56	%		54	%		56	%
Adjusted EBITDA per Boe	$	31.08		$	29.07		$	29.95
Adjusted EBITDA excl hedges (%)		70	%		69	%		70	%
Adjusted EBITDA excl hedges per Boe	$	39.15		$	37.08		$	37.00

Additional Highlights

•

Capital expenditures in the third quarter of $109.9 million

•

As of September 30, 2018 the Company’s total debt principal was $769.3 million, including capital lease. Net Debt to annualized Adjusted EBITDA⁽¹⁾ was 1.1x

•

Liquidity position of $419.0 million as of September 30, 2018, including $329.0 million available under the $600.0 million Bank Credit Facility (Borrowing Base) and approximately $89.9 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.

“We are very pleased with our continued integration of Stone and we believe the third quarter represents much of what we are trying to accomplish, with successes in all phases of our business. We are growing production and pleased with our third quarter production of 54.9 MBoe/d, growing our drilling inventory and achieving key milestones in our offshore Mexico projects, all while generating cash flow well in excess of our capital program”, said Timothy S. Duncan, President and CEO of Talos.

“We continue to deliver on the drilling front with several successes to date in our shallow water program, and we look forward to kicking off our deepwater drilling campaign in the fourth quarter, which will focus on bringing substantial production online in the second quarter of 2019. We will also commence the appraisal of our Zama discovery in Mexico in the fourth quarter of this year, for which our Mexico team has worked very hard to prepare.”

“The Whistler acquisition in the third quarter was another low-cost reserve and infrastructure add in our Green Canyon core area. Not only are we encouraged by the existing potential drilling opportunities within the acquired leases, but we were also the high bidder in the latest federal lease sale in the Gulf of Mexico to acquire additional low cost drilling inventory that can be tied-back to the Whistler facility, making the economics of the acquisition even more impactful.”

“In Mexico, in addition to announcing a historic Pre-Unitization Agreement with Pemex ahead of our announcement of the Zama appraisal plan approval, we also announced a cross-assignment of interest transaction with Pan American Energy of a 25% participating interest in our Block 2 for the same interest in Block 31. We look forward to appraising the globally recognized Zama discovery and the Block 2/31 swap allows us to pull in additional net resources by aggregating more drilling prospects across the entire acreage position for similarly sized capital investment.”

“There has been a lot of progress in the six months following the Stone combination and we are excited about the value creation opportunities we have achieved across the Company, and we are committed to continuing to deliver organic production and reserves growth through the drill-bit.”

RECENT DEVELOPMENTS AND OPERATIONS UPDATE

Drilling and Exploration Activities

Deepwater

•

Noble Don Taylor: Talos signed a two-well commitment with a subsidiary of Noble Corporation plc for the drilling and completion of two deepwater wells in the Company’s Phoenix Complex – Tornado #3 and Boris #3.

•

The Tornado #3 well will be spud in November 2018 and is expected to be brought online in 2Q 2019. Tornado #3 is expected to produce between 10.0 – 15.0 MBoe/d gross, or 5.0 – 7.5 MBoe/d net, after royalties. Talos is the operator of the field and holds a 65% working interest in all Tornado wells with Kosmos Energy owning the remaining 35%.

•

The Boris #3 well, which will be batch-drilled with Tornado #3 and is also expected to come online in 2Q 2019. Talos expects Boris #3 to have initial production between 3.0 – 5.0 MBoe/d gross, or 2.8 – 4.6 MBoe/d net, after royalties. Talos owns 100% working interest in all Boris wells.

•

In mid-to-late November, we expect Murphy Oil to spud the King Cake prospect as the operator. King Cake is a high-impact exploration target in the Atwater Valley area, in which Talos owns 12.5% working interest.

•

The Mt. Providence well began producing on July 10, 2018, approximately 60 days ahead of the originally scheduled completion date in early September. Initial gross production was approximately 4.2 MBoe/d (3.7 MBoe/d net, after royalties), which is above the previously announced guidance range of 2.0 – 4.0 MBoe/d. Talos owns 100% of the Mt. Providence subsea well, which is tied into the wholly owned Pompano production facility.

Shelf

•

The Ewing Bank block 306 (“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 initial completion was made in the deepest pay zones in the third quarter with an initial production rate of approximately 2.2 MBoe/d gross (1.8 MBoe/d net, after royalties), well above our estimated range of 1.2 – 1.5 MBoe/d gross. Production started in September 2018. Talos is the operator and owns 100% working interest in EW306

•

Talos has successfully drilled two wells in the Main Pass block 72 (“MP72”) field. The A-8ST1 well, drilled to an approximate depth of 9,800 feet, penetrated four stacked sands encountering approximately 175 feet of hydrocarbon pay (approximately 60% oil). The A-8ST1 has been cased and will be completed following the drilling of the A-11ST1 well. The A-11ST1 well has been drilled to approximately 7,800 feet and has encountered hydrocarbon pay in its primary target. The total depth of the A-11ST1 well will be approximately 9,700 feet. Production from both wells is expected in December at a combined rates of approximately 1,000 – 1,500 Boe/d gross (approximately 800 – 1,200 Boe/d net, after royalties). Talos owns 100% working interest in MP72.

Mexico

Pre-Unitization Agreement with Pemex

Talos and its partners in Block 7 offshore Mexico signed a Pre-Unitization Agreement (“PUA”) with Pemex that enables information sharing related to the Zama discovery and its potential extension into Pemex’s neighboring block. It also establishes a clear path for the signing of a Unit Agreement and Unit Operating Agreement in the event a shared reservoir is confirmed, with a defined process based on international practices to determine the resulting participation of each party in the potential overall development.

The PUA was previously approved by the Ministry of Energy (SENER) in Mexico.

Approval of the Zama Appraisal Plan

The Mexican oil & gas regulator, the National Hydrocarbons Commission (“CNH”) has approved the appraisal plan for the Zama discovery.

The approval by the CNH was a key approval required to commence the appraisal of the Zama discovery. CNH has also approved the consortium drilling permits, which are required to commence drilling operations. Talos estimates that it will spud the first appraisal well, Zama-2, in late November of 2018 and that the appraisal program will be completed by mid-2019.

The appraisal plan includes three new reservoir penetrations. The first well in the program, Zama-2, will be deepened by approximately 500 meters to test an exploration prospect called Marte. The estimated cost to deepen the Zama-2 wellbore for the Marte test is approximately $10.0 million gross, with Talos’s share expected to be approximately $3.5 million. Talos expects its net share of the costs to be approximately $75.0 million to $80.0 million for the entire appraisal campaign.

Agreement with Pan American Energy to cross-assign interests in Block 2 and Block 31

Talos entered into a transaction with, Hokchi Energy, S.A. de C.V., a subsidiary of Pan American Energy (“Pan American”), to cross-assign its Participating Interest (“PI”) in Block 2 and Pan American’s PI in Block 31, both in the Sureste Basin offshore Mexico.

Under the agreed conditions for the swap, Talos will assign a 25% PI in Block 2 to Pan American in exchange for a 25% PI in Block 31, which is immediately to the south of Block 2. On October 30^th, CNH approved the PI transfer of Block 2 to Pan American. Approval of the transfer of the Block 31 PI to Talos and the transfer of operatorship of Block 2 to Pan American are expected in the coming weeks. Once that occurs and the transaction is closed, Pan American will be the operator of both blocks and Talos will own a 25% PI on Block 2 and a 25% PI on Block 31. The goal of this transaction is to better aggregate each party’s inventory into one potential development program to increase scale in terms of total resources and total combined production. The contract areas are located in water depths between 100 and 150 feet (25 and 35 meters).

Business Development Activities

Acquisition of Whistler Energy II, LLC (“Whistler”)

On August 31, Talos acquired Whistler for a net cash consideration of $14.5 million. The production from the assets in the first half of 2018 averaged approximately 1,500 Boe/d net of royalties, representing an acquisition metric of $9,667 per net Boe/d.

The acquired assets include a 100% working interest in three blocks in the Central Gulf of Mexico – Green Canyon 18, Green Canyon 60 and Ewing Bank 988 (collectively the “Green Canyon 18 Field”), which comprises 16,494 acres – and a fixed production platform located on Green Canyon Block 18 (“GC18 Production Facility”) in approximately 750 feet of water. All leases are held-by-production. The GC18 Production Facility, which is approximately 18 miles north of the Talos operated Phoenix Field and Tornado discovery, currently has a nameplate production capacity of 30 thousand barrels of oil per day and 30 million cubic feet of gas per day, or approximately 35,000 Boe/d of total capacity, with potential for additional expansion.

The strategic benefit of this acquisition goes beyond the current producing leases. Talos had already licensed recent vintage wide azimuth seismic data in the area, which we will reprocess to assist in the re-mapping of the producing reservoirs and potentially generate additional drilling prospects. Additionally, in the latest federal lease sale in the Gulf of Mexico, the Company was the high bidder on new leases containing at least three drilling prospects that could be tied back to the GC18 Production Facility.

Gulf of Mexico Lease Sale

Talos was the fifth most active bidder in the latest Gulf of Mexico lease sale held by the Bureau of Ocean Energy Management (“BOEM”) on August 15, 2018. Talos was the high bidder on six deepwater and eight shallow water blocks.

Talos had 100% success rate on the 14 blocks it bid on in the lease sale. These blocks cover approximately 75,000 net acres and, once awarded, Talos will pay approximately $5.3 million for all leases combined, for an average cost of $71/acre. Two of the deepwater leases have a seven-year primary lease term, while the others have a five-year lease term. The royalty rate for the deepwater blocks is 18.75%, whereas the royalty rates for the shallow water blocks is 12.50%. At the time of this update 13 of 14 blocks have been awarded.

The Company has identified eight prospects on these blocks, with a possibility of an additional two. All but one of the identified prospects can potentially be a tieback to production facilities owned or accessible by Talos.

Planned 2019 Downtime

Helix Producer 1 dry-dock

In the first quarter of 2019, the Helix Producer 1 will undergo a regulatory required dry-dock period. Regulators require the ship to go to dry-dock twice every five years. Therefore, in the first quarter of 2019, we expect the Phoenix and Tornado fields to be shut-in for approximately 45 – 60 days.

The impact on the first quarter 2019 production is estimated to be between 9.0 – 13.0 MBoe/d, whereas the annualized estimated impact for full year 2019 production is estimated between 2.0 – 3.0 Mboe/d.

THIRD QUARTER 2018 RESULTS

Production, Realized Prices and Revenue

Production: Production for the third quarter of 2018 was 5.1 million Boe and was comprised of 3.5 million barrels of oil, 0.4 million barrels of NGLs and 6.8 billion cubic feet (“Bcf”) of natural gas. Oil and NGLs production accounted for 78% of the total production for the third quarter of 2018.

Production was negatively affected by two unplanned third-party downtime events in the third quarter. Helix required a 12 day downtime in the Helix Producer 1 (“HP-1”), to address operational issues of the vessel, which shut-in production from the Phoenix and Tornado fields for the same period. The negative impact on the third quarter production as a result of the HP-1 downtime was an average daily production of approximately 2.4 MBoe/d.

In addition, Talos evacuated non-essential personnel and shut-in production on certain Gulf of Mexico assets for three days during Tropical Storm Gordon, which negatively impacted the average daily production by approximately 0.7 MBoe/d. Talos suffered no damage to its assets.

These interruptions in production were limited to the third quarter and are not expected to have a material impact on Talos’ expected total annual production.

We expect the Company’s full year 2018 production on a pro forma basis to be at the top of the Company’s 49 MBoe/d – 53 Mboe/d guided range.

The table below provides additional detail of the Company’s oil, natural gas and NGLs production volumes and sales prices per unit for the three months and nine months ended on September 30, 2018:


	Three months ended September 30, 2018		Nine months ended September 30, 2018
	As Reported		As Reported		Pro Forma
Production volumes
Oil production volume (MBbls)		3,507		8,188		9,862
NGL production volume (MBbls)		414		886		1,046
Natural Gas production volume (MMcf)		6,783		16,548		19,951
Total production volume (MBoe)		5,052		11,832		14,233

Average net daily production volumes
Oil (MBbl/d)		38.1		30.0		36.1
NGL (MBbl/d)		4.5		3.2		3.8
Natural Gas (MMcf/d)		73.7		60.6		73.1
Total net average daily (Mboe/d)		54.9		43.3		52.1

Average realized prices (excluding hedges)⁽²⁾
Oil ($/Bbl)	$	70.74	$	67.90	$	67.55
NGL ($/Bbl)	$	35.21	$	30.82	$	30.40
Natural Gas ($/Mcf)	$	2.98	$	2.98	$	2.84
Barrel of oil equivalent ($/Boe)	$	55.99	$	53.47	$	53.01

(2)	Average realized prices are net of certain gathering, transportation and other costs

The table below provides additional detail of the Company’s production by major assets for the three months ended on September 30, 2018:


	Three months ended September 30, 2018
	Production (MBoe/d)		Oil (%)			Liquids (%)
Average net daily production volumes by asset
*Green Canyon*
Phoenix / Tornado		16.4		79	%		87	%
Green Canyon 18⁽³⁾		0.4		89	%		89	%
*Mississippi Canyon*
Amberjack		1.9		93	%		93	%
Pompano		11.7		80	%		89	%
Ram Powell		8.4		59	%		72	%
*Shelf and Other*
Shelf / Other		16.1		55	%		61	%

Total net average daily (Mboe/d)		54.9		69	%		78	%

(3)	The acquisition of Whistler Energy II closed on August 31; as such, the Whistler assets only contributed production for one month of the third quarter.

Revenue: Total revenue for the three months ending September 30, 2018 was $282.9 million underpinned by a strong production profile in the quarter and a rising commodity price environment.

The table below summarizes the revenue by commodity for the three and nine months ended September 30, 2018 and provides additional relevant information:


	Three months ended September 30, 2018		Nine months ended September 30, 2018
	As Reported		As Reported		Pro Forma
Revenues ($ million)
Oil		248.1		556.0		666.2
NGL		14.6		27.3		31.8
Natural Gas		20.2		49.4		56.6
Total Revenue		282.9		632.7		754.5

Average realized prices (excluding hedges)⁽²⁾
Oil ($/Bbl)	$	70.74	$	67.90	$	67.55
NGL ($/Bbl)	$	35.21	$	30.82	$	30.40
Natural Gas ($/Mcf)	$	2.98	$	2.98	$	2.84
Barrel of oil equivalent ($/Boe)	$	55.99	$	53.47	$	53.01

Average NYMEX prices
WTI ($/Bbl)	$	69.50	$	66.75	$	66.75
Henry Hub ($/MMBtu)	$	2.90	$	2.90	$	2.90

(2)	Average realized prices are net of certain gathering, transportation and other costs

Expenses

Lease operating expense (“LOE”): Total direct lease operating expense for the three months ended September 30, 2018 was $46.8 million.

Direct LOE for the full year 2018 on a pro forma basis is expected to be close to the mid-point of the $170 million – $180 million guided range.

Other operating expense: Other operating expense for the three months ended September 30, 2018 was $35.2 million, of which $25.1 is related to workover and maintenance expenses. These costs include approximately $7.6 million non-recurring expenses related to inspecting and re-attaching the buoy system related to the HP-1 shut-in and repairs on South Marsh Island block 130 (“SMI130”). Additionally, it includes several major maintenance projects in our fixed structures and some post-closing work on the Ram-Powell facility. Maintenance projects are typically more prevalent in the second and third quarters with better weather and more working daylight offshore.

Workover and maintenance expenses will likely be above the $49 million – $54 million guided range for the full year 2018, on a pro forma basis.

General and administrative expense: General and administrative expense for the three months ended September 30, 2018 was $21.7 million and included $7.4 million in transaction and integration costs related to the Stone Combination. With transaction related costs are normalized, the Company’s G&A for the quarter was $2.87 per Boe.

G&A expenses for the full year 2018 on a pro forma basis is expected to be close to the mid-point of the $57 million – $62 million guided range.

Price risk management activities: Price risk management activities for the three months ended September 30, 2018 resulted in a $53.3 million expense related to cash settlement on our derivative contracts.

Other Financial Metrics

Net Income (Loss) and Adjusted EBITDA: Net income in the third quarter of 2018 was $13.1 million and in the first nine months of the year was ($84.7) 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 first nine months of the year was ($30.6) 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 September 30, 2018 was $157.0 million and Adjusted EBITDA margin was 56%, or $31.08 per Boe. For the first nine months of 2018, Adjusted EBITDA was $344.0 million, with a margin of 54% or $29.07 per Boe. Excluding the effect of hedges, the margins would have been 70% or $39.15 per Boe for the third quarter and 69% or $37.08 per Boe for the first nine months of the year.

Pro forma Adjusted EBITDA for the first nine months of 2018 was $426.2 million, with a margin of 56% or $29.95 per Boe. Excluding the effect of hedges, the pro forma margins would have been 70% or $37.00 per Boe for the first nine months of the year.

Capital Expenditures: Capital expenditures in the third quarter of 2018 were approximately $109.9 million, inclusive of Plugging & Abandonment costs. For the first nine months of 2018, capital expenditures were $255.5 million, also inclusive Plugging & Abandonment costs.

The pro forma capital expenditures for the nine months ended on September 30, 2018 were $310.0 million, inclusive of Plugging & Abandonment costs. Pro forma capital expenditures for the first nine months of 2018 excludes $33.4 million of accrued, but unpaid change of control costs for the seismic acquired as part of the Stone Combination. These costs will be paid in 2019, 2020 and 2021.

The table below provides additional detail of the Company’s capital expenditures:


	Three months ended September 30, 2018		Nine months ended September 30, 2018
($ million)	As Reported		As Reported		Pro Forma
U.S. Drilling & Completions		41.1		81.9		100.0
Mexico Appraisal & Exploration		0.6		1.7		1.7
Asset Management		14.1		36.7		38.5
Seismic and G&G / Land / Capitalized G&A		12.3		49.4		55.1

Total Capital Expenditures		68.1		169.7		195.3

Plug & Abandonment		41.8		85.7		114.7

Total Capital Expenditures & Plug & Abandonment		109.9		255.4		310.0

The majority of the remaining capital budget for the year is expected to be utilized on U.S. Drilling & Completions activities, primarily on Tornado #3, King Cake, MP 72 and the commencement of the Zama appraisal campaign.

Capital expenditures for the full year 2018, on a pro forma basis, is expected on the low end of the $430 million – $450 million guided range.

Financial position: As of September 30, 2018, the Company had approximately $672.6 million of long-term debt, excluding deferred financing costs and original issue discount. The balance includes $396.9 million of second lien notes, $265.0 million of borrowings under the bank credit facility and a $10.7 million building loan. In addition to the Company’s long-term debt, as of September 30, 2018, Talos had a capital lease obligation with a balance of approximately $96.7 million.

Liquidity position: As of September 30, 2018, the Company had a liquidity position of approximately $419.0 million, which included $329.0 million available under the $600.0 million bank credit facility and approximately $89.9 million of cash.

Leverage and credit metrics: The Annualized third quarter Adjusted EBITDA was $628.1 million. As of September 30, 2018, the Company’s total debt was $769.3 million and net debt was $679.4 million, both including capital lease. Therefore, the Net Debt to annualized Adjusted EBITDA ratio of Talos was 1.1x.

UPDATED INVESTOR PRESENTATION

Talos will post an updated Investor presentation to its website later this week. The presentation can be found on the Company’s website at www.talosenergy.com/investors.

CONFERENCE CALL AND WEBCAST INFORMATION

Talos will host a conference call, which will also be broadcast live over the internet, on Tuesday, November 6, 2018 at 10:00 am Eastern Time (9:00 am 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, November 20, 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 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.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 Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, filed with the Securities and Exchange Commission (the “SEC”) on August 9, 2018, and in our Quarterly Report on Form 10-Q for the quarter ended September 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.

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, 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 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 September 30, 2018			Nine Months Ended September 30, 2018
($ thousands)	As Reported			As Reported			Pro Forma
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$	13,109		$	(84,746	)	$	(30,645	)
Interest expense		24,837			66,257			63,417
Depreciation, depletion and amortization		87,808			204,574			235,617
Accretion expense		10,162			24,414			34,348
Loss on debt extinguishment		356			1,764			356
Transaction related costs		7,595			27,905			335
Derivative fair value (gain) loss⁽¹⁾		53,330			196,482			220,695
Net cash receipts (payments) on settled derivative instruments⁽¹⁾		(40,746	)		(94,802	)		(100,360	)
Non-cash equity-based compensation expense		570			2,129			2,477

Adjusted EBITDA	$	157,021		$	343,977		$	426,240

Net cash receipts (payments) on settled derivative instruments⁽¹⁾		40,746			94,802			100,360

Adjusted EBITDA excluding hedges		197,767			438,779			526,600

Production and Revenue:
Boe⁽²⁾		5,052			11,832			14,234
Revenue		282,868			632,624			754,520
Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin:
Adjusted EBITDA divided by Revenue (%)		56	%		54	%		56	%
Adjusted EBITDA per Boe⁽²⁾	$	31.08		$	29.07		$	29.95
Adjusted EBITDA excl hedges divided by Revenue (%)		70	%		69	%		70	%
Adjusted EBITDA excl hedges per Boe⁽²⁾	$	39.15		$	37.08		$	37.00

(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.


	September 30, 2018
Reconciliation of Net Debt ($ thousand):
Debt principal	$	672,602
Capital Lease		96,747

Gross Debt		769,349
Cash		(89,920	)

Net Debt	$	679,429

Reconciliation of Annualized Adjusted EBITDA:
Adjusted EBITDA for the three months ended September 30, 2018		157,021
		×4
Annualized Adjusted EBITDA		628,084
Reconciliation of Net Debt to Adjusted EBITDA
Net Debt / Annualized Adjusted EBITDA		1.1x

The annualized information in this document is to provide additional relevant information to our investors and creditors. Beginning on September 30, 2018, Talos needs 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, with certain adjustments, 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