Talos Energy : Announces Fourth Quarter And Full Year 2018 Financial And Operational Results

HOUSTON, March 13, 2019 /PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its financial and operational results for the fourth quarter and full year 2018.

Key Highlights of the Fourth Quarter 2018:

• Year-end 2018 proved reserves of 151.7 million barrels of oil equivalent ("MMBoe"), of which 76% is proved developed
• Standardized measure of discounted future net cash flows of $3.3 billion and PV-10⁽¹⁾ of proved reserves of $3.9 billion, with proved developed producing ("PDP") reserves accounting for $2.5 billion
• Production of 53.4 thousands of barrels of oil equivalent per day ("MBoe/d"), or 4.9 MMBoe in the fourth quarter
• Net Income of $306.3 million and Earnings Per Share of $5.66 in the fourth quarter
• Adjusted Net Income⁽²⁾ of $49.3 million and Adjusted Earnings Per Share⁽²⁾ of $0.91 in the fourth quarter
• Adjusted EBITDA⁽²⁾ of $158.8 million in the fourth quarter. Excluding hedges, Adjusted EBITDA⁽²⁾ was $175.1 million
• Adjusted EBITDA Margin⁽²⁾ of 61% or $32.33 per barrel of oil equivalent ("Boe") in the fourth quarter. Excluding hedges, the Adjusted EBITDA Margin⁽²⁾ was 68% or $35.66 per Boe.
• As of December 31, 2018, liquidity position of $460.3 million, including $320.4 million available under the $600.0 million Bank Credit Facility and approximately $139.9 million of cash. In the fourth quarter of 2018 the Company's Borrowing Base was increased by approximately 42% to $850 million; however, Talos elected to maintain the commitments at $600 million
• As of December 31, 2018 the Company's total debt principal balance was $766.2 million, inclusive of $93.7 million capital lease. Net Debt to Annualized Adjusted EBITDA⁽²⁾ was 1.0x
• Capital expenditures, inclusive of Plugging and Abandonment costs, was $142.4 million in the fourth quarter

 

(1)	PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. See "Supplemental Non-GAAP Information" below for additional detail and reconciliations of GAAP to non-GAAP measures, including a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash flows at December 31, 2018.
(2)	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 are non-GAAP financial measures. See "Supplemental Non-GAAP Information" below for additional detail and reconciliations of GAAP to non-GAAP measures.

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 prior to 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 a historical basis.

Additional Highlights

	Three months ended December 31, 2018		Year ended December 31, 2018
	As Reported		As Reported		Pro Forma
Total production volumes (MBoe)	4,910		16,742		19,143
Oil (MBbl/d) - Avg daily production	38.9		32.2		36.8
NGLs (MBbl/d) - Avg daily production	3.2		3.2		3.7
Natural Gas (MMcfe/d) - Avg daily production	67.6		62.4		71.7
Total average daily (MBoe/d)	53.4		45.9		52.4
Period results ($ million):
Revenues	$258.7		$891.3		$1,013.2
Net Income	$306.3		$221.5		$274.6
Earnings per share	$5.66		$4.81		$5.96
Adjusted Net Income(1)	$49.3		$122.4		$173.8
Adjusted Earnings per share(1)	$0.91		$2.66		$3.77
Adjusted EBITDA(1)	$158.8		$502.7		$585.0
Adjusted EBITDA excl. hedges(1)	$175.1		$613.9		$701.7
Capital Expenditures (including Plug & Abandonment)	$142.4		$397.8		$452.4
Adjusted EBITDA margin(1):
Adjusted EBITDA (% of revenue)	61%		56%		58%
Adjusted EBITDA per Boe	$32.33		$30.03		$30.56
Adjusted EBITDA excl hedges (% of revenue)	68%		69%		69%
Adjusted EBITDA excl hedges per Boe	$35.66		$36.67		$36.66

(1)	Adjusted Net Income, Adjusted Earnings per share, 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: "2018 was a transformative year for the company, as we combined the best aspects of two companies, following our merger with Stone Energy.  The benefits of the combination have shown results immediately, as we are a stronger, free cash flow positive company with ample liquidity and a significant inventory of drilling locations in both the US Gulf of Mexico and offshore Mexico. Our strategy of executing asset management and drilling projects around existing infrastructure in the US Gulf of Mexico complements our high impact exploration and development projects in offshore Mexico."

"In the last twelve months we have seen our proved developed reserves increase 20%, as compared to the pro forma reserves at December 31, 2017. We have also added three small bolt-on transactions at a low entry cost, including the Gunflint acquisition in January of 2019. We have increased our liquidity position and continued to improve our already robust leverage metrics. We have also re-affirmed the potential of our globally recognized Zama discovery through our ongoing appraisal program."

"Our average daily production in 2018 on a pro forma basis was 52.4 MBoe/d, which was on the high end of our pro forma guidance range of 49.0 – 53.0 MBoe/d, allowing us to generate $585 million of pro forma Adjusted EBITDA for the full year 2018, inclusive of hedges, and a pro forma capital program of $452 million, inclusive of plugging and abandoning activities ("P&A").  Although the merger with Stone required us to spend more capital in 2018 on P&A and non-recurring repairs and maintenance than we normally would have, in 2019 those costs are expected to go down materially."

"In the US Gulf of Mexico, we executed a series of deepwater subsea tie-back projects in 2018 and early 2019, namely the Mt. Providence well, which was connected to our Pompano facility, and the Tornado 3 and Boris 3 wells, that will flow back to the Helix Producer 1 ("HP-1") in our operated Phoenix complex once the wells are completed. The HP-1 dry-dock project in the first quarter of 2019 was flawlessly executed by the Talos team and our partner Helix Energy Solutions, and we expect the production in the Phoenix complex to be restarted in the coming days. Soon thereafter we expect to bring the impactful Tornado 3 and Boris 3 wells online, which will put Talos in a position to grow production year over year while continuing to generate free cash flow in the current price environment for 2019.  In shallow water, our asset management and drilling activities have allowed assets such as Ewing Bank 305/306 to achieve production levels not seen in the last 15 years."

"We also continue to be active and to execute on our business development and commercial activities. In addition to the aforementioned bolt-on acquisitions, we have acquired the Antrim stranded discovery from ExxonMobil and have entered into partnerships to drill two deepwater projects in 2019, the Bulleit and Orlov prospects."

"In Mexico on the Zama project, our operations execution has been outstanding. As part of the ongoing appraisal program we confirmed the oil-water contact per our geological model and have encountered more sand than expected in the first down-dip location. We are excited about the impact this discovery will have in the Mexican economy and to Talos shareholders. Also in offshore Mexico, we will start to execute on the inventory we acquired as part of the cross-assignment of interest between Block 2 and Block 31, which includes the low-risk but high impact Olmeca project on Block 31."

"In conclusion, we are very happy with our 2018 results, but we are already looking forward to 2019 and beyond. We will continue to relentlessly execute on our operations and strategy of responsibly growing production at an appropriate pace that allows for the continued generation of positive free cash flow while diligently pursuing additional business development opportunities that fit our asset footprint and core competencies. We believe this is only the beginning of the Talos journey."

RECENT DEVELOPMENTS AND OPERATIONS UPDATE

Drilling and Exploration Activities

Deepwater

• Helix Producer 1 dry-dock: the HP-1 departed the shipyard on March 7, 2019. After a period of sea trials, Talos expects production from the Phoenix complex to re-start on or about March 20, 2019, resulting in a total shut-in period of 56 days. The production impact of the shut-in in the Phoenix complex in the first quarter of 2019 is estimated to be between 9.0 – 13.0 MBoe/d, whereas the annualized impact for full year 2019 production is estimated to be between 2.0 – 3.0 MBoe/d. This impact is already accounted for in our annual guidance, as the shut-in in the Phoenix complex was a known, expected event.
• The Tornado 3 well was drilled in December, 2018 and is scheduled to begin completions operations in late March, with an expected duration of 21 days. The well is anticipated to commence production by early second quarter 2019, with an expected gross production rate between 10.0 MBoe/d – 15.0 MBoe/d, or 5.0 MBoe/d – 7.5 MBoe/d net to Talos after royalties. Talos is the operator and owns a 65% working interest, with Kosmos Energy owning the remaining 35% working interest.
• The Boris 3 well was spud in January 2019 and was drilled to a total depth of approximately 15,000 feet and logged approximately 75 feet gross and 56 feet net of true vertical pay, 360 feet up-dip of 27 MMBoe of historical production in the B-4 Sand. Boris 3 is scheduled to begin completion operations in mid-April with an expected duration of 21 days and is expected to initiate production in the second quarter of 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 to Talos after royalties. Talos is the operator and owns 100% working interest in all Boris wells.
• Bulleit prospect: Talos has signed a participation agreement with a subsidiary of EnVen Corporation to drill the Green Canyon 21 Bulleit prospect. Talos will be the operator and has an initial working interest of 66.7% in the lease. Bulleit is an amplitude-supported Pliocene prospect with similar seismic attributes to the analogous sand section in Talos's Green Canyon 18 field, which has produced approximately 39 MMBoe to date. Talos expects to spud the well in the second quarter of 2019. If successful, the well would be completed and tied back to the Talos owned and operated Green Canyon 18 ("GC 18") facility approximately 10 miles away. Talos anticipates first production within 12-18 months from spud date and estimates that Bulleit has the potential to deliver initial production between 8.0 MBoe/d – 15.0 MBoe/d gross on an unrisked basis.
• Orlov prospect: Talos has signed a participation agreement to engage in the drilling of the Green Canyon 200 Orlov prospect. Fieldwood Energy will be the operator and Talos has a working interest of 30% in the prospect. Orlov is an amplitude-supported Miocene prospect with similar geophysical and structural attributes to the Talos operated Boris field, which has produced approximately 27 MMBoe to date. Talos expects the well to spud near the end of the first quarter of 2019. If successful, the well would be completed and tied-back to the Fieldwood operated Green Canyon 158 Bullwinkle facility. Talos anticipates first production within 12-18 months from spud date and estimates that Orlov has the potential to deliver between 8.0 MBoe/d – 15.0 MBoe/d gross on an unrisked basis

Mexico

Block 7 – Zama appraisal program

As previously announced, the Zama-2 appraisal penetration was successfully and safely completed approximately 28 days ahead of schedule and 25% below projected costs. The well confirmed a contiguous Zama Upper Miocene sandstone interval thicker than the Zama-1 discovery well and slightly thicker than the pre-drill estimates for the Zama-2 well, with high quality rock properties analogous to Upper Miocene sands in the US Gulf of Mexico.

The Zama-2 penetration also reached the oil-water contact slightly deeper than the anticipated depth and consistent with our geophysical models. Preliminary pressure data indicates that the reservoir area around the Zama-2 appraisal well is connected to the Zama-1 discovery well and Talos expects the Zama-2 vertical sidetrack and the Zama-3 wells will provide additional information about the reservoir connectivity and consistency.

The next step of the appraisal program is currently underway with an up-dip vertical penetration in the Zama reservoir from the main bore hole of the Zama-2 well, called the Zama 2-ST, which has been cored and a drill stem test will be performed in the coming weeks. The second appraisal well, Zama-3, will be drilled to the south of the original discovery well and will help delineate the reservoir continuity and quality in the southern part of the field and will be cored to better understand the reservoir geology.

Block 2 and Block 31 Exploration program

Talos and its partners expect to drill two exploration wells in Block 2 and two delineation wells in Block 31 in 2019.

• In Block 2, the well to test the Acan prospect is expected to spud in the second quarter of 2019.
• In Block 31, the Olmeca-1 well is expected to be drilled in the second half of 2019. The Olmeca complex has been significantly de-risked by the Xaxamani-1 well drilled by Pemex in 2003. The 2019 drilling campaign will be to appraise the same geological structure initially tested by Pemex and, if successful, a final investment decision to develop these assets could be reached in 2020.

Business Development Activities

Acquisition of the Antrim Discovery from ExxonMobil

On January 23, 2019, Talos and ExxonMobil ("Exxon") executed an Acquisition Agreement through which Talos acquired 100% interest in the Antrim Project in Green Canyon Block 364 ("GC 364").

Exxon drilled an exploratory well in GC 364 in November 2017 that encountered hydrocarbons in a sub-salt Miocene reservoir and subsequently divested of the discovery well and the GC 364 lease to Talos for further appraisal and a possible development.

Talos plans to drill an additional well to further appraise the discovered resource. The Company is still developing a detailed timeline for the appraisal and development plan over the next few years with significant time ahead of the June 2025 lease expiration. If the appraisal is successful, Talos is currently considering a tie-back to the Talos owned and operated GC 18 facility acquired from Whistler in 2018.

In addition to a nominal upfront cash consideration payment by Talos, Exxon will receive an overriding royalty interest in the lease as well as a future cash payment upon the earlier of 30 days following the completion of drilling operations on the first well or by the end of the third quarter of 2020.

Gunflint Acquisition

On January 11, 2019, Talos acquired an approximate 9.6% non-operated working interest in the Gunflint producing asset for $29.6 million from Samson Offshore Mapleleaf, LLC. Gunflint is located in the Company's Mississippi Canyon core area. The asset's average production for October and November of 2018 was approximately 1.5 - 1.8 MBoe/d and as of November 30, 2018, had proved reserves of 2.2 MMBoe (approximately 80% proved developed) - both production and reserves are net to the Company's acquired interest, which are not included in our year-end reserves.

PROVED RESERVES – AS OF DECEMBER 31, 2018

As of December 31, 2018, Talos had proved reserves of 151.7 MMBoe, with 81% comprised of liquids (74% crude oil and 7% NGLs). As compared to the pro forma year-end 2017 reserves, the Company achieved 100% reserve replacement rate. Talos accomplished this replacement rate in a year that the drilling program was mainly designed to convert proved undeveloped reserves into proved developed reserves while integrating the Stone merger. As such, proved developed reserves increased approximately 20% year over year, and is not inclusive of the recently successful Boris 3 well in the Phoenix complex, which is still classified as proved undeveloped in the year-end reserves. The recently announced Gunflint transaction is also not included in the year end reserves.

The discovered resources associated with the Company's offshore Mexico assets are not yet qualified as proved reserves per Securities and Exchange Commission (the "SEC") rules and, therefore, are not included in any of the information provided in this press release.

The standardized measure of proved reserves and the present value of the Company's proved reserves, discounted at 10% ("PV-10")⁽¹⁾, at year-end 2018 were $3.3 billion and $3.9 billion, respectively. Standardized measure and PV-10 include the present value of all asset retirement obligations associated with the relevant assets and properties.  

The following table summarizes our proved reserves at December 31, 2018:

	Summary of Proved Reserves(2)
	MBoe			Percent of Total Proved			Percent Oil			Standardized Measure (in thousands)			PV-10(1) (in thousands)
Proved Developed Producing		78,072			51%			80%					$	2,510,213
Proved Developed Non-Producing		37,456			25%			62%						680,942
Total Proved Developed		115,528			76%			74%						3,191,155
Proved Undeveloped		36,211			24%			75%						734,108
Total Proved		151,739								$	3,340,246		$	3,925,263

(1)	PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. See "Supplemental Non-GAAP Information" below for additional detail and reconciliations of GAAP to non-GAAP measures, including a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash flows at December 31, 2018.
(2)	Proved oil, natural gas and NGL reserves attributable to our net interests in oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc.

The following table summarizes our proved reserves by asset at December 31, 2018:

		Proved Reserves
Operating Area		MBoe				% Oil				% Natural Gas				% NGLs				% Proved Developed
United States Core Properties
Phoenix Complex			63,931				78	%			14	%			8	%			55	%
Pompano			28,206				81	%			14	%			5	%			100	%
Ram Powell			18,094				59	%			28	%			13	%			100	%
Amberjack			8,148				88	%			10	%			2	%			100	%
United States Core Properties Subtotal			118,379				77	%			16	%			7	%			76	%
Other United States Properties(1)			33,360				65	%			30	%			5	%			78	%
Total United States			151,739				74	%			19	%			7	%			76	%

(1)	Other United States Properties includes Gulf of Mexico shelf and deepwater.

In accordance with guidelines established by the SEC, the Company's estimated proved reserves as of December 31, 2018 were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each commodity, calculated as the unweighted arithmetic average of the price on the first day of each month for the year end December 31, 2018. The West Texas Intermediate spot price and the Henry Hub spot price were utilized as the referenced price and appropriately adjusted for quality, transportation, fees, energy content and basis differentials. Therefore, the standardized measure and PV-10 of Talos's proved reserves at December 31, 2018, are based on an average crude oil price of $65.56 per barrel and an average natural gas price of $3.10 per MMBtu, prior to being adjusted for quality, transportation, fees, energy content and basis differentials. The average adjusted product prices used in determining standardized measure and PV-10 are $69.42 per barrel of oil, $29.50 per barrel of NGL, and $3.08 per Mcf of gas.

FOURTH QUARTER 2018 RESULTS

Production, Realized Prices and Revenue

Production: Production for the fourth quarter of 2018 was 4.9 million Boe and was comprised of 3.6 million barrels of oil, 0.3 million barrels of NGLs and 6.2 billion cubic feet ("Bcf") of natural gas. Oil and NGLs production accounted for 79% of the total production for the fourth quarter of 2018.

During the quarter, Talos evacuated non-essential personnel and shut-in production on certain Gulf of Mexico assets as a result of Hurricane Michael, which negatively impacted production. Talos suffered no damage to its assets. In addition to Hurricane Michael, production was negatively affected by several minor third-party downtime events.

Although a certain level of third party downtime is expected and planned for, these interruptions in production were limited to the fourth quarter and are not expected to have a material impact going forward.

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 year ended December 31, 2018:

	Three months ended December 31, 2018		Year ended December 31, 2018
	As Reported		As Reported		Pro Forma
Production volumes
Oil production volume (MBbl)	3,583		11,771		13,445
NGL production volume (MBbl)	290		1,176		1,336
Natural Gas production volume (MMcf)	6,223		22,771		26,174
Total production volume (MBoe)	4,910		16,742		19,143
Average net daily production volumes
Oil (MBbl/d)	38.9		32.2		36.8
NGL (MBbl/d)	3.2		3.2		3.7
Natural Gas (MMcf/d)	67.6		62.4		71.7
Total average net daily (MBoe/d)	53.4		45.9		52.4
Average realized prices (excluding hedges)(1)
Oil ($/Bbl)	63.04		66.42		66.35
NGL ($/Bbl)	29.47		30.50		30.20
Natural Gas ($/Mcf)	3.90		3.23		3.09
Barrel of oil equivalent ($/Boe)	52.68		53.24		52.93

(1)	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 December 31, 2018:

	Three months ended December 31, 2018
	Production (MBoe/d)		Oil (%)		Liquids (%)
Average net daily production volumes by asset
Green Canyon
Phoenix Complex	16.8		80%		87%
Green Canyon 18	1.1		90%		93%
Mississippi Canyon
Amberjack	2.2		90%		92%
Pompano	10.3		87%		88%
Ram Powell	6.8		60%		73%
Shelf and Other
Shelf / Other	16.1		59%		65%
Total average net daily (MBoe/d)	53.4		73%		79%

Revenue: Total revenue for the three months ended December 31, 2018 was $258.7 million underpinned by a good production profile in the quarter, especially oil production, and a supportive commodity price environment in the first few weeks of the period.

The table below summarizes the revenue by commodity for the three months and year ended December 31, 2018 and provides additional relevant information:

	Three months ended December 31, 2018		Year ended December 31, 2018
	As Reported		As Reported		Pro Forma
Revenues ($ million)
Oil	225.9		781.8		892.0
NGL	8.6		35.9		40.4
Natural Gas	24.2		73.6		80.8
Total Revenue	258.7		891.3		1,013.2
Average realized prices (excluding hedges)(1)
Oil ($/Bbl)	$ 63.04		66.42		66.35
NGL ($/Bbl)	$ 29.47		30.50		30.20
Natural Gas ($/Mcf)	$ 3.90		3.23		3.09
Barrel of oil equivalent ($/Boe)	$ 52.68		53.24		52.93
Average NYMEX prices
WTI ($/Bbl)	$ 58.81		64.77		64.77
Henry Hub ($/MMBtu)	$ 3.64		3.09		3.09

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

Expenses

Lease operating expense ("LOE"): Total lease operating expense for the three months ended December 31, 2018 was $49.7 million, inclusive of insurance costs.

LOE for the full year 2018 was $163.3million and, on a pro forma basis, was $177.9 million, also inclusive of insurance costs. 

Workover and maintenance expense: For the three months ended December 31, 2018 was $15.3 million. These costs include approximately $7.4 million non-recurring expenses primarily related to structural maintenance, including the HP-1 dry-dock.

Workover and maintenance expense for the full year 2018 on a pro forma basis was $71.5 million.

General and administrative expense ("G&A"): General and administrative expense for the three months ended December 31, 2018 was $24.7 million, which included $0.8 million of non-cash equity based compensation and $4.6 million in transaction and integration costs mainly related to the Stone Combination and the Whistler acquisition.

General and administrative expense for the full year was $85.8 million, which included $32.5 million in transaction related costs.

G&A for the full year 2018 on a pro forma basis, was $70.6 million, which excluded transaction costs related to the Stone Combination; however, it is inclusive of $3.3 million of transaction costs mainly related to the acquisition of Whistler. It is also inclusive of $3.1 million of non-cash equity based compensation. Normalizing these one-time and non-cash items, our pro forma full year G&A was $64.1 million.

Price risk management activities: Price risk management activities for the three months ended December 31, 2018 resulted in a $16.3 million expense related to cash settlement on our derivative contracts.

Other Financial Metrics

Net Income and Adjusted EBITDA: Net income was $306.3 million or $5.66 per share in the fourth quarter of 2018 and net income of $221.5 million or $4.81 per share for the full year 2018. On a pro forma basis, for the full year, net income was $274.6 million or $5.96 per share.

Adjusted EBITDA for the three months ended on December 31, 2018 was $158.8 million and Adjusted EBITDA margin was 61%, or $32.33 per Boe. For the full year, Adjusted EBITDA was $502.7 million, with a margin of 56% or $30.03 per Boe. Excluding the effect of hedges, the margins would have been 68% or $35.66 per Boe for the fourth quarter and 69% or $36.67 per Boe for the full year.

Pro forma Adjusted EBITDA for the full year 2018 was $585.0 million, with a margin of 58% or $30.56 per Boe. Excluding the effect of hedges, the pro forma margins would have been 69% or $36.66 per Boe for the full year.

Capital Expenditures: Capital expenditures in the fourth quarter of 2018 were $142.4 million, inclusive of Plugging & Abandonment costs. For the full year of 2018, capital expenditures were $397.8 million, also inclusive Plugging & Abandonment costs.

The pro forma capital expenditures for 2018 were $452.4 million, inclusive of Plugging & Abandonment costs. Pro forma capital expenditures for the year excludes $29.8 million of accrued, but unpaid change of control costs for the seismic data acquired in connection with the Stone Combination. As part of the negotiation between the parties, these costs will be paid in 2019, 2020 and 2021 in equal installments. It also excludes non-cash equity based compensation and $9.0 million of corporate office renovation costs, which were reimbursed by the property manager, thus resulting in a zero cash impact to Talos.

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

	Three months ended December 31, 2018		Year ended December 31, 2018
($ million)	As Reported		As Reported		Pro Forma
U.S. Drilling & Completions	81.2		163.1		181.2
Mexico Appraisal & Exploration	12.8		14.5		14.5
Asset Management	15.7		52.5		54.2
Seismic and G&G / Land / Capitalized G&A	5.4		47.6		60.5
Total Capital Expenditures	115.1		277.7		310.4
Plug & Abandonment	27.3		112.9		142.0
Total Capital Expenditures & Plug & Abandonment	142.4		390.6		452.4

Financial position: As of December 31, 2018, the Company had approximately $672.5 million in 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 $10.6 million building loan. In addition to the Company's long-term debt, as of December 31, 2018, Talos had a capital lease obligation with a balance of approximately $93.7 million.

Liquidity position: As of December 31, 2018, the Company had a liquidity position of approximately $460.3 million, which included $320.3 million available under the $600.0 million bank credit facility and approximately $139.9 million of cash. In the fourth quarter of 2018, the Company's borrowing base was increased by approximately 42% to $850 million; however, Talos elected to maintain the commitments at $600 million.

Leverage and credit metrics: Annualized Adjusted EBITDA for the six month period ended December 31, 2018 was $631.6 million. As of December 31, 2018, the Company's total debt was $766.2 million and net debt was $626.2 million, both including capital lease. Therefore, the Net Debt to Annualized Adjusted EBITDA ratio of Talos was 1.0x.

DERIVATIVE POSITION

The tables below provide additional detail on the Company's hedge position for the full year 2019, which is inclusive of hedge transactions entered into by March 13, 2019.

Oil Hedges

					Weighted Average Price
	Swaps	Collars	Puts	Total	Swaps	Put Strike	Call Strike	Blend Avg.
Period	(MBbls)	(MBbls)	(MBbls)	(Bbls/d)	($/Bbl)	($/Bbl)	($/Bbl)	($/Bbl)
01/19-12/19	10,094	-	-	27,654	$        55.54	-	-	$        55.54
01/20-12/20	1,367	1,095	-	6,746	$        57.07	$        55.00	$        60.64	$        56.15

Gas Hedges

					Weighted Average Price
	Swaps	Collars	Puts	Total	Swaps	Put Strike	Call Strike	Blend Avg.
Period	(MMBtu)	(MMBtu)	(MMBtu)	(MMBtu/d)	($/MMBtu)	($/MMBtu)	($/MMBtu)	($/MMBtu)
01/19-12/19	13,324	3,150	-	45,133	$          2.90	$          3.00	$          3.96	$          2.92

CONFERENCE CALL AND WEBCAST INFORMATION

Talos will host a conference call, which will also be broadcast live over the internet, on Thursday, March 14, 2019 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 Thursday, March 21, 2019 and can be accessed by dialing 1-877-344-7529 and using access code 10128499.

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
[e-mail] 

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 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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2018, filed with the SEC on November 5, 2018, and in our Annual Report on Form 10-K for the year ended December 31, 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.  

Proved reserves attributable to the Gunflint assets as of November 30, 2018 were estimated by Talos Energy Inc.'s internal reserve engineer based upon information furnished by Samson Offshore Mapleleaf, LLC, as seller, but have not been audited or prepared by any third-party independent petroleum engineer.

TALOS ENERGY INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
	Year Ended December 31,
	2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	139,914		$	32,191
Restricted cash		1,248			1,242
Accounts receivable
Trade, net		103,025			62,871
Joint interest, net		20,244			13,613
Other		19,686			12,486
Assets from price risk management activities		75,473			1,563
Prepaid assets		38,911			17,931
Inventory		—			840
Income tax receivable		10,701			—
Other current assets		7,644			2,148
Total current assets		416,846			144,885
Property and equipment:
Proved properties		3,629,430			2,440,811
Unproved properties, not subject to amortization		108,209			72,002
Other property and equipment		33,191			8,857
Total property and equipment		3,770,830			2,521,670
Accumulated depreciation, depletion and amortization		(1,719,609)			(1,430,890)
Total property and equipment, net		2,051,221			1,090,780
Other long-term assets:
Assets from price risk management activities		—			345
Other well equipment		9,224			2,577
Other assets		2,695			706
Total assets	$	2,479,986		$	1,239,293
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	51,019		$	72,681
Accrued liabilities		188,650			87,973
Accrued royalties		38,520			24,208
Current portion of long-term debt		443			24,977
Current portion of asset retirement obligations		68,965			39,741
Liabilities from price risk management activities		550			49,957
Accrued interest payable		10,200			8,742
Other current liabilities		22,071			15,188
Total current liabilities		380,418			323,467
Long-term debt, net of discount and deferred financing costs		654,861			672,581
Asset retirement obligations		313,852			174,992
Liabilities from price risk management activities		—			18,781
Other long-term liabilities		123,359			103,559
Total liabilities		1,472,490			1,293,380
Commitments and contingencies (Note 11)
Stockholders' Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2018 and December 31, 2017		—			—
Common stock $0.01 par value; 270,000,000 shares authorized; 54,155,768 and 31,244,085 shares issued and outstanding as of December 31, 2018 and December 31, 2017, respectively		542			312
Additional paid-in capital		1,334,090			489,870
Accumulated deficit		(327,136)			(544,269)
Total stockholders' equity (deficit)		1,007,496			(54,087)
Total liabilities and stockholders' equity	$	2,479,986		$	1,239,293

 

TALOS ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per common share amounts)
	Three Months Ended December 31, 2018			Year Ended December 31, 2018			Year Ended December 31, 2017
Revenues:
Oil revenue	$	225,861		$	781,815		$	344,781
Natural gas revenue		24,246			73,610			48,886
NGL revenue		8,557			35,863			16,658
Other		—			—			2,503
Total revenue		258,664			891,288			412,828
Operating expenses:
Direct lease operating expense		44,923			145,988			109,180
Insurance		4,283			15,342			10,743
Production taxes		456			1,989			1,460
Total lease operating expense		49,662			163,319			121,383
Workover and maintenance expense		15,258			64,961			32,825
Depreciation, depletion and amortization		84,145			288,719			157,352
Accretion expense		10,930			35,344			19,295
General and administrative expense		24,696			85,816			36,673
Total operating expenses		184,691			638,159			367,528
Operating income (loss)		73,973			253,129			45,300
Interest expense		(23,857)			(90,114)			(80,934)
Price risk management activities income (expense)		256,917			60,435			(27,563)
Other income		2,175			1,012			329
Net income (loss) before income taxes		309,208			224,462			(62,868)
Income tax expense		(2,922)			(2,922)			—
Net income (loss)	$	306,286		$	221,540		$	(62,868)
Net income (loss) per common share:
Basic	$	5.66		$	4.81		$	(2.01)
Diluted	$	5.66		$	4.81		$	(2.01)
Weighted average common shares outstanding:
Basic		54,156			46,058			31,244
Diluted		54,159			46,061			31,244

 

TALOS ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
	Three Months Ended December 31, 2018			Year Ended December 31, 2018			Year Ended December 31, 2017
Cash flows from operating activities:
Net income (loss)	$	306,286		$	221,540		$	(62,868)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense		95,075			324,063			176,647
Impairment		244			244			260
Amortization of deferred financing costs and original issue discount		664			4,253			2,383
Equity based compensation, net of amounts capitalized		764			2,893			875
Price risk management activities (income) expense		(256,917)			(60,435)			27,563
Net cash received (paid) on settled derivative instruments		(16,345)			(111,147)			23,834
Settlement of asset retirement obligations		(27,272)			(112,946)			(32,573)
Changes in operating assets and liabilities:
Accounts receivable		3,674			(786)			(9,132)
Other current assets		11,900			(2,624)			(4,441)
Accounts payable		5,204			(48,825)			2,409
Other current liabilities		(8,366)			32,044			46,364
Other non-current assets and liabilities, net		4,847			15,171			4,732
Net cash provided by operating activities		119,758			263,445			176,053
Cash flows from investing activities:
Exploration, development and other capital expenditures		(66,565)			(240,914)			(155,177)
Cash (paid) received for acquisitions, net of cash acquired		—			278,409			(2,464)
Net cash provided by (used in) investing activities		(66,565)			37,495			(157,641)
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt		(106)			(25,257)			(1,000)
Proceeds from Bank Credit Facility		—			319,000			10,000
Repayment of Bank Credit Facility		—			(54,000)			—
Repayment of LLC Bank Credit Facility		—			(403,000)			(15,000)
Deferred financing costs		(12)			(17,002)			—
Payments of capital lease		(3,078)			(12,952)			(12,412)
Contributions from Sponsors		—			—			—
Distributions to Sponsors		—			—			—
Net cash provided by (used in) financing activities		(3,196)			(193,211)			(18,412)
Net increase (decrease) in cash, cash equivalents and restricted cash		49,997			107,729			—
Cash, cash equivalents and restricted cash:
Balance, beginning of period		91,165			33,433			33,433
Balance, end of period	$	141,162		$	141,162		$	33,433
Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities				$	100,664		$	40,626
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized				$	53,476		$	47,994

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", "Annualized Adjusted EBITDA", "Net Debt to Annualized Adjusted EBITDA" and "PV-10." 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):

	Three Months Ended September 30, 2018		Three Months Ended December 31, 2018		Year Ended December 31, 2018
($ thousands)	As Reported		As Reported		As Reported		Pro Forma
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$                    13,109		$                   306,286		$   221,540		$     274,577
Interest expense	24,837		23,857		90,114		87,274
Income Tax Expense	-		2,922		2,922		5,577
Depreciation, depletion and amortization	87,808		84,145		288,719		319,762
Accretion expense	10,162		10,930		35,344		45,278
Loss on debt extinguishment	356		-		1,764		356
Transaction related costs	7,595		4,579		32,484		3,323
Derivative fair value (gain) loss(1)	53,330		(256,917)		(60,435)		(36,222)
Net cash receipts (payments) on settled derivative instruments(1)	(40,746)		(16,345)		(111,147)		(116,705)
Non-cash (gain) loss on sale of assets	-		(1,710)		(1,710)		(1,710)
Non-cash write-down of other well equipment inventory	-		244		244		244
Non-cash equity-based compensation expense	570		764		2,893		3,241
Adjusted EBITDA	$                  157,021		$                   158,755		$   502,732		$     584,995
Net cash receipts (payments) on settled derivative instruments(1)	40,746		16,345		111,147		116,705
Adjusted EBITDA excluding hedges	197,767		175,100		613,879		701,700
Production and Revenue:
Boe(2)	5,052		4,910		16,742		19,143
Revenue	282,868		258,664		891,288		1,013,184
Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin:
Adjusted EBITDA divided by Revenue (%)	56%		61%		56%		58%
Adjusted EBITDA per Boe(2)	$                      31.08		$                       32.33		$       30.03		$         30.56
Adjusted EBITDA excl hedges divided by Revenue (%)	70%		68%		69%		69%
Adjusted EBITDA excl hedges per Boe(2)	$                      39.15		$                       35.66		$       36.67		$         36.66

(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.

	Three Months Ended December 31, 2018			Year Ended December 31, 2018
($ thousands)	As Reported			As Reported			Pro Forma
Reconciliation of Net Income to Adjusted Net Income:
Net income	$	306,286		$	221,540		$	274,577
Accretion expense		10,930			35,344			45,278
Loss on debt extinguishment		-			1,764			356
Transaction related costs		4,579			32,484			3,323
Derivative fair value (gain) loss(1)		(256,917)			(60,435)			(36,222)
Net cash receipts (payments) on settled derivative instruments(1)		(16,345)			(111,147)			(116,705)
Non-cash equity-based compensation expense		764			2,893			3,241
Adjusted Net Income	$	49,297		$	122,443		$	173,848
Weighted average common shares outstanding:
Basic		54,156			46,058			46,058
Diluted		54,159			46,061			46,061
Net Income per common share
Basic	$	5.66			4.81			5.96
Diluted		5.66			4.81			5.96
Adjusted Earnings per share
Basic	$	0.91			2.66			3.77
Diluted		0.91			2.66			3.77

(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 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, Annualized Adjusted EBITDA and Net Debt to Annualized 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.

	December 31, 2018
Reconciliation of Net Debt ($ thousand):
Debt principal	$	672,495
Capital Lease		93,668
Gross Debt		766,163
Cash		(139,914)
Net Debt	$	626,249
Reconciliation of Annualized 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 six month period ended December 31, 2018		315,776
		×2
Annualized Adjusted EBITDA		631,552
Reconciliation of Net Debt to Adjusted EBITDA
Net Debt / Annualized Adjusted EBITDA		1.0x

The Annualized 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 Annualized Adjusted EBITDA ratio equal to or lower than 3.0x. For purposes of covenant compliance, Annualized Adjusted EBITDA, with certain adjustments, is calculated the following way:

• 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

Reconciliation of PV-10 to Standardized Measure

"PV-10" is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure.  PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash flows at December 31, 2018:

	December 31, 2018
Standardized measure	$	3,340,246
Plus: present value of future income taxes discounted at 10%		585,017
PV-10		3,925,263

 

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SOURCE Talos Energy