TALOS ENERGY INC. - Annual Report: 2018 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2018

OR

Commission File Number 01-38497

Talos Energy Inc.

(Exact name of Registrant as specified in its Charter)

Registrant’s telephone number, including area code: (713) 328-3000

Securities registered pursuant to Section 12(b) of the Act: Common Stock, Par Value $0.01 Per Share; Common stock traded on the NYSE stock market

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ☐ NO ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. YES ☐ NO ☒

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ☒ NO ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YES ☒ NO ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ☐ NO ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on the closing price of the shares of common stock on The NYSE Stock Market on June 30, 2018, was $281,311,750.

The number of shares of registrant’s Common Stock outstanding as of March 6, 2019 was 54,155,805.

Portions of the registrant’s definitive proxy statement relating to the Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

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GLOSSARY

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

Barrel or Bbl. One stock tank barrel, or 42 United States gallons liquid volume.

Boe. One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

Boepd. Barrels of oil equivalent per day.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Deepwater. Water depths of more than 600 feet.

Developed acres. The number of acres that are allocated or assignable to producing wells or wells capable of production.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

Gross acres or gross wells. The total acres or wells in which the Company owns a working interest.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBblpd. One thousand barrels of crude oil or other liquid hydrocarbons per day.

MBoe. One thousand barrels of oil equivalent.

MBoepd. One thousand barrels of oil equivalent per day.

Mcf. One thousand cubic feet of natural gas.

Mcfpd. One thousand cubic feet of natural gas per day.

MMBoe. One million barrels of oil equivalent.

MMBtu. One million British thermal units (“Btus”).

MMcf. One million cubic feet of natural gas.

MMcfpd. One million cubic feet of natural gas per day.

Net acres or net wells. The sum of the fractional working interests the Company owns in gross acres or gross wells.

NGL. Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasoline.

NYMEX. The New York Mercantile Exchange.

NYMEX Henry Hub. Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub Index.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed reserves. In general, proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. The Securities and Exchange Commission provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X.

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Proved reserves. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves. In general, proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The Securities and Exchange Commission provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X.

PV-10. The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related expenses such as general and administrative expenses, derivatives, debt service and future income tax expense or (ii) depreciation depletion and amortization expense.

SEC. The Securities and Exchange Commission.

SEC pricing. The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2018 and ending December 1, 2018, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The Securities and Exchange Commission provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

Shelf. Water depths up to 600 feet.

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the SEC and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. For the year ending December 31, 2018, we were subject to U.S. federal and state income taxes at the entity level. For the tax years ending December 31, 2017 and 2016, we were not subject to U.S. federal or state income taxes (in most states) at the entity level and thus made no provision for U.S. federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

WTI or West Texas Intermediate. A light crude oil produced in the United States with an API gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “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 (the “Exchange Act”). All statements, other than statements of historical fact included in this report, 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 report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective, “plan,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about:

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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, failure  to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects, geologic risk, drilling and other operating risks, well control risk, 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 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 the other risks discussed in Part I, Item 1A, “Risk Factors” which are included herein.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.

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Part 1

Items 1. Business

Overview

We are a technically driven independent exploration and production company with operations in the United States Gulf of Mexico and offshore Mexico. Our focus in the United States Gulf of Mexico is the acquisition of deep water assets with existing infrastructure and the exploration, exploitation and development of such assets in key geological trends. Offshore Mexico provides us high impact exploration opportunities in an oil rich emerging basin. We use our access to an extensive seismic database and our deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. As of December 31, 2018, deepwater assets represent 83% of our proved reserves.

We have historically focused our operations in the Gulf of Mexico because we believe this area provides us with favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic databases, extensive infrastructure and an attractive acquisition market and because we have significant experience and technical expertise in the basin. Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate a large and expanding inventory of high-quality prospects, which we believe greatly improves our development and exploration success. The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate acquisition and joint venture opportunities.

In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio management approach to stochastically evaluate all of our drilling prospects, whether they are generated organically from our existing acreage or are acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy capital as efficiently as possible.

Talos Energy Inc. was incorporated on November 14, 2017 under the laws of the state of Delaware for the purpose of effecting the previously disclosed business combination between Talos Energy LLC (“Talos Energy”) and Stone Energy Corporation (“Stone”), pursuant to which each of Talos Energy and Stone became our wholly-owned subsidiary. We refer to this business combination as the “Stone Combination,” and its date of consummation, May 10, 2018, as the “Closing Date.” In addition, as used in this report and unless otherwise indicated or the context otherwise requires, references to “we,” “us,” “our,” “Talos Energy Inc.,” “Talos” and the “Company” refer to, from and after the Closing Date, Talos Energy Inc. and its consolidated subsidiaries and prior to the Closing Date, Talos Energy and its consolidated subsidiaries.

Prior to the Stone Combination, Talos Energy Inc. had not conducted any material activities other than those incident to its incorporation and certain matters contemplated by that certain Transaction Agreement (the “Transaction Agreement”), dated as of November 21, 2017, among Stone, Talos Energy, us and Sailfish Merger Sub Corporation (“Merger Sub”). The transactions contemplated by the Transaction Agreement were accounted for as a business combination in accordance with accounting principles generally accepted in the United States of America (“GAAP”), with Talos Energy treated as the “acquirer” and Stone treated as the “acquired” company for financial reporting purposes. Accordingly, the reported financial condition and results of operations of Talos Energy Inc. reflect the assets, liabilities and results of operations of Talos Energy (as our predecessor) prior to the Closing Date, and do not reflect the assets, liabilities and results of operations of Stone prior to such date. The assets, liabilities and results of operations of Talos Energy Inc. have not been, and will not be, restated retrospectively to reflect the historical financial position or results of operations of Stone.

For more information on Talos Energy, our predecessor for financial reporting purposes, please read “—Talos Energy LLC.” For more information on the Stone Combination, please read “— Stone Combination.”

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Talos Energy LLC

Talos Energy was formed in 2011 under the laws of the state of Delaware and commenced commercial operations on February 6, 2013. Prior to February 6, 2013, Talos Energy had incurred only certain general and administrative expenses associated with the start-up of its operations.  

On February 3, 2012, Talos Energy completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”, and together with the Apollo Funds, the “Sponsors”) and members of management pursuant to which Talos Energy received a private equity capital commitment.

On February 6, 2013, Talos Energy acquired all of the equity of Energy Resource Technology GOM, LLC (“ERT”) and its subsidiary from Helix Energy Solutions Group, Inc. (“Helix”) for approximately $625.2 million (inclusive of purchase price and working capital adjustments of approximately $15.2 million), and payments for ongoing guarantees from Helix to third-parties. Additionally, Talos Energy agreed to assign Helix an overriding royalty interest in certain properties acquired in the transaction at closing. We refer to this purchase as the “ERT Acquisition.” The ERT Acquisition was effective December 1, 2012 and closed on February 6, 2013. Prior to the closing of the ERT Acquisition, the Sponsors and members of management had invested an aggregate of approximately $325 million in Talos Energy to fund a portion of the ERT Acquisition as well as to fund other asset purchases.

In September 2015, Talos Energy, together with consortium partners Sierra Oil and Gas S. de R.L de C.V. (“Sierra”) and Premier Oil Plc (“Premier”, and together with Talos Energy and Sierra, the “Consortium”) executed two Production Sharing Contracts (“PSCs”) with the National Hydrocarbons Commission (“CNH”), Mexico’s oil and gas regulator, for Blocks 2 and 7 of Round 1. The PSCs were awarded to the Consortium during the first tender of Mexico’s oil and natural gas fields in over 80 years. Blocks 2 and 7 are located in the Sureste Basin, a prolific proven hydrocarbon province, in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, respectively. Blocks 2 and 7 contain approximately 162,904 gross acres with numerous high impact prospects in well-established and emerging plays. In 2017, the Consortium drilled Zama-1, the initial exploration well in Block 7, resulting in the discovery of the Zama Field.  As of December 31, 2018, we were in the process of appraising the discovery.

Stone Combination

On the Closing Date, we consummated the transactions contemplated by the Transaction Agreement and Talos Energy and Stone became our wholly-owned subsidiaries. Pursuant to the Transaction Agreement, the following transactions, among others, occurred: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and our direct wholly-owned subsidiary (the “Merger”), and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right to receive one share of our common stock, par value $0.01 (the “Common Stock”) and (ii) the Sponsors contributed all of the equity interests in Talos Production LLC (“Talos Production”) (which at that time owned 100% of the equity interests in Talos Energy) to us in exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”).

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Concurrently with the consummation of the Transaction Agreement, we consummated the transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among us, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% senior notes due 2022 (“9.75% Senior Notes”) issued by Talos Production  and Talos Production Finance, Inc. (together, the “Talos Issuers”) to us in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Senior Secured Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Secured Notes due 2022 issued by Stone (“7.50% Stone Senior Notes”) for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes.

Substantially concurrent therewith, we consummated an exchange offer and consent solicitation, pursuant to which the holders of the 7.50% Stone Senior Notes, excluding the 7.50% Stone Senior Notes held by the Franklin Noteholders and the MacKay Noteholders, exchanged their 7.50% Stone Senior Notes for 11.00% Senior Secured Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50% Stone Senior Notes. Approximately $81.5 million in aggregate principal amount of the 7.50% Stone Senior Notes were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Stone Senior Notes remained outstanding as of the Closing Date.

As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”) the former stakeholders of Talos Energy held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date.

Business Strategy

We intend to increase stockholder value through the following strategies:

Grow Production, Reserves and Cash Flow by Developing Our Attractive Asset Base in a Capital Efficient Manner.

Our team is focused on continuously improving capital efficiency, and we believe the combination of our experience and the existing infrastructure in the U.S. Gulf of Mexico will allow us to continue to benefit from attractive finding and development costs. We also benefit from our proven ability to increase production from legacy fields and identified projects. Furthermore, we intend to use our technical expertise and seismic database to find additional drilling projects in proximity to our existing assets.

Expand Our Reserves and Production Through Lease Acquisitions and Diversified Business Development.

We intend to deploy our expertise and seismic resources to identify and acquire attractive leasehold acreage in federal lease sales for the U.S. Gulf of Mexico. In many cases, acreage available in the federal lease sales has not been evaluated with the latest reprocessed seismic data, resulting in an opportunity for us to identify previously unknown drilling prospects. In the latest federal lease of the August 2018 sale, we were the fifth most active bidder in the U.S. Gulf of Mexico, and we were the high bidder on 14 lease blocks. During that sale, we focused on blocks that adjoin our existing properties, and we have identified specific prospects through reprocessed seismic data. In addition, our proven track record through the drillbit and our strong financial position frequently attracts potential drilling partners. Our deep industry relationships, technical expertise and extensive regional seismic database allow us to effectively identify and evaluate these third-party proposed drilling projects. We intend to continue to strategically pursue these types of drilling projects with other operators on a selected basis.

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Evaluate and Pursue Accretive Acquisitions.

We intend to continue to opportunistically expand our asset base by evaluating the supply of acquisition opportunities in the U.S. Gulf of Mexico and offshore Mexico. Our acquisition strategy is focused on operated deepwater assets with a geological setting that can benefit from our ability to use our seismic database and our reprocessing expertise to re-evaluate the acquired assets. By applying our disciplined valuation methodology, we seek to reduce the risk of underperformance of the acquired properties while maintaining upside potential. In addition, we may consider acquisition opportunities in other offshore basins with analogous geologies that are suitable for our operational and technical expertise to the extent we believe they will create additional value for stockholders.

Maintain High Operatorship to Leverage Our Technical Expertise.

We operate properties that generate approximately 94% of our production, and we strive to maintain a majority of operational control over our producing properties. We believe that maintaining control of our production enables us to apply leading practices to every aspect of our operations. In addition, maintaining high operatorship allows us to leverage our technical team’s deep regional experience and modern seismic expertise in order to generate attractive investment opportunities on our properties while concurrently controlling execution. Lastly, maintaining operational control allows us to sustain our focus on maximizing our returns through reduced development cycle times and efficient capital utilization.

Properties

United States Gulf of Mexico Properties

Our area of focus in the United States is the Gulf of Mexico deepwater, which is generally considered to comprise water depths over 600 feet. Our strategy is focused in areas characterized by clearly defined infrastructure, well known production history and geological well control, which reduces operational and investment risk. We believe the potential for large discoveries and increasing success rates in the sub-salt and mini-basin lower Pliocene and Miocene plays have resulted in increased industry focus on this area over the last decade.  

We believe our deepwater operations in the U.S. Gulf of Mexico provide significant potential growth opportunities through our planned drilling program. Through our technical approach of starting with known hydrocarbon systems and applying modern seismic reprocessing techniques, we have generated a substantial inventory of deepwater prospects that we believe are capable of delivering predictable production growth. We focus our exploitation and exploration efforts around our existing infrastructure. This subsea tie-back strategy allows for better project economics and shorter periods between a discovery and production.

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In the United States, at December 31, 2018, we had an interest in 271.0 gross producing wells (228.9 net producing wells) on 885,888 gross (624,891 net) total acres, of which 477,190 gross (342,604 net) are developed acres. We operate properties that contain 98% of our proved reserves at December 31, 2018.

At December 31, 2018, our core properties in the United States, which represent approximately 68% of our 2018 production and 78% of our December 31, 2018 proved reserves are illustrated below:

The following table sets forth certain information regarding our core properties in the United States:

Phoenix Field—The Phoenix Field is comprised of six operated blocks, which include Green Canyon Blocks 236, 237, 238, 280, 281, and 282, located in the deepwaters offshore Louisiana.

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There are no conventional fixed or moored production platforms in the field-instead the subsea wells are tied back to a dynamically positioned floating production unit, the Helix Producer I (“HP-I”). The HP-I interconnects with the Phoenix Field through a production buoy that can be disconnected if the HP-I cannot maintain its position on station, such as the approach of a hurricane or in the event of a mechanical problem with the dynamic positioning system. There are eight active wells in the Phoenix Field and the average net daily production for the year ended December 31, 2018 was 17,907 Boepd.

Pompano Field— The Pompano Field is comprised of seven operated blocks which include Viosca Knoll Blocks 989 and 990, and Mississippi Canyon Blocks 26, 27, 28, 29 and 72 located in the deepwaters offshore Louisiana. The Pompano Field’s three current subsea systems are tied back to a fixed leg platform with a total of 23 active wells. The field’s average net daily production since the Closing Date of the Stone Combination was 10,534 Boepd.

Ram Powell Field— The Ram Powell Field is comprised of six operated blocks which include Viosca Knoll Blocks 911, 912, 913, 955, 956 and 957 located in the deepwaters offshore Louisiana. The Ram Powell Field has eight active dry tree wells that are located on a tension leg platform in Viosca Knoll Block 956. The field’s average net daily production since the Closing Date of the Stone Combination was 7,856 Boepd.

Amberjack Field—The Amberjack Field is comprised of three operated blocks which include Mississippi Canyon Block 108, 109 and 110. The Amberjack Field has 29 active conventional dry tree wells located on a fixed structure platform in Mississippi Canyon Block 109. The field’s average net daily production since the Closing Date of the Stone Combination was 2,021 Boepd.

Mexico Properties

In September 2015, we, together with the Consortium, executed a PSC with the CNH for each of Blocks 2 and 7 of Round 1. The PSCs were awarded to the Consortium during the first tender of Mexico’s oil and natural gas fields in over 80 years. Blocks 2 and 7 are located in the Sureste Basin, a prolific proven hydrocarbon province, in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, respectively. Blocks 2 and 7 contain approximately 162,904 gross acres with numerous high impact prospects in well-established and emerging plays. Our participation interest (“PI”) in Block 2 is currently 20% and our PI in Block 7 is 35%. We are the operator of Block 7.

The PSCs include a cost recovery feature pursuant to which eligible costs in relation to the minimum work program activities are recoverable in-kind at a rate of 125% of costs from future production volumes. Production volumes are allocated in-kind between the Consortium and the United Mexican States on a monthly basis based on the contractual value of the hydrocarbons as defined in the PSCs. Up to 60% of the monthly contractual value of the hydrocarbons will be allocated to the Consortium to recover eligible costs incurred in petroleum activities. Eligible costs exceeding 60% of the current month contractual value of the hydrocarbons will be recoverable in future periods. Between 7.5% and 14% of the contractual value of the oil will be allocated to the United Mexican States in the form of a royalty, depending upon the price of a barrel of oil, with a collar between $48.00 and $100.00 per Bbl. The allocation for the royalty on natural gas is 0% when the price per MMBtu is below $5.00 and, if the natural gas price exceeds $5.00 per MMBtu, the royalty allocation percentage is calculated as the price per MMBtu divided by 100. The remaining value of the hydrocarbons after the allocation for cost recovery and royalties is considered operating profit under the PSCs. The allocation of operating profit to the Consortium after the allocation for cost recovery and royalties on Blocks 2 and 7 is 44% and 31%, respectively. Additionally, in the event that the cumulative project internal rate of return in any one month exceeds 25%, the barrels of oil allocated to the Consortium after cost recovery (“Profit Oil”) is reduced on a sliding scale. The reduction in Profit Oil varies linearly between 0% and 75% of the entitled amount. The maximum 75% reduction occurs once the cumulative project internal rate of return meets or exceeds 40%.

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At December 31, 2018, our core properties in Mexico are presented in the following acreage map:

In the fourth quarter of 2018, we spud the Zama-2 well, the first appraisal well to be drilled in the field. The Zama-2 well confirmed the results of the original Zama-1 exploration well. The Zama appraisal campaign is expected to be completed by mid-year 2019. If the appraisal of the Zama Field confirms our initial estimates, we expect to announce a Final Investment Decision in 2020, following Mexican government approval of the development plan. In addition to Zama, other prospects within Block 7 are being analyzed and matured to potentially be drilled over the next several years, assuming an extension of the Exploration Period is approved by the CHH. See Part II, Item 8. Financial Statements and Supplementary Data — Note 4 — Property, Plant & Equipment for further detail on Mexico properties.

Pre-Unitization Agreement with Pemex. In September 2018, we and our consortium partners in Block 7 signed a Pre-Unitization Agreement (“PUA”) with Pemex Exploration y Produccion (“Pemex”) related to certain tracts within the Amoca-Yaxche-03 allocation and the contiguous Block 7 PSC. Both areas are situated in the offshore portion of the Sureste Basin. The two year PUA enables information sharing related to the Zama discovery and potential extension into Pemex’s neighboring block. The PUA has been approved by the Mexican Secretariat of Energy (“SENER”).

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In February 2019, the CHN granted approval for drilling in the Acan-1 exploration well in Block 2. Operations are expected to begin in March 2019 and extend into the second quarter. Soon thereafter, we plan to participate in two prospects in Block 31. Beyond the Acan prospects, we believe that Blocks 2 and 31 contain a significant portfolio of compelling prospects with strong technical ties to offsetting discoveries.

Recent Developments

Gunflint Acquisition

On January 11, 2019, pursuant to a Purchase Sale Agreement with Samson Offshore Mapleleaf, LLC we acquired an approximate 9.6% non-operated working interest in the Gunflint Field located in the Mississippi Canyon area for $29.6 million.

HP-I Dry-Dock Downtime

During the first quarter of 2019, the HP-I entered into its regulatory required dry-dock period. Regulators require the ship to go to dry-dock twice every five years. On May 7, 2019, the HP-I completed its dry-dock requirement and departed the shipyard. After a period of sea trials, we expect production from the Phoenix Field to commence in late March 2019. The annualized production impact of the shut-in in the Phoenix Field is estimated to be between 2.0 MBoepd and 3.0 MBoepd.

Drilling and Exploration Activities

The Tornado 3 well’s drilling operations completed in December 2018 and completed in January 2019. We expect production to commence by early second quarter, 2019, with an expected net production rate between 10.0 MBoepd and 15.0 MBoepd. We are the operator and own a 65% working interest.

The Boris 3 wells started drilling operations in January 2019 and completed in February 2019. We expect production to commence in the second quarter of 2019, with a net production between or 2.8 Mboepd and 4.6 MBoepd. We are the operator and own a 100% working interest.

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Summary of Reserves

Our estimated proved reserves totaled 151.7 MMBoe at December 31, 2018. The following table summarizes our estimated proved reserves as of December 31, 2018, 2017 and 2016 which are all located in the United States.

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 the standardized measure of discounted future net cash flows to PV-10 of our proved reserves at December 31, 2018, 2017, and 2016.

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Changes in Proved Developed Reserves

Our proved developed reserves as of December 31, 2018 increased by 61.8 MMBoe to 115.5 MMBoe from 53.7 MMBoe at December 31, 2017, a 115% increase. This increase was due to:  

Development of Proved Undeveloped Reserves

The following table discloses our estimated PUD reserve activities during the year ended December 31, 2018:

Our PUD reserves at December 31, 2018 decreased by 10.7 MMBoe, or 23% primarily due to:

Extensions and Discoveries. We added 3.1 MMBoe of PUD reserves through an evaluation of Green Canyon Block 18 which was initially acquired in the Whistler Acquisition. See Part II, Item 8. Financial Statements and Supplementary Data — Note 3 — Acquisitions, for more information.

Revisions of Previous Estimates. Downward reserves revisions of 4.5 MMBoe primarily due to timing of development of certain PUD locations to move beyond 5 years of 3.3 MMBoe and downward revisions of 1.2 MMBoe. The revisions were caused by a new geological data and changes in overall project economics, and expiration of a block. Future development costs related to the PUD revisions decreased by $4.0 million primarily due to a review of completion strategy and optimization of capital expenditures in the Phoenix Field.

Acquired. We added a 0.7 MMBoe PUD reserves in Bayou Hebert Field through the Stone Combination.

Conversion to Proved Developed Producing. 2017 PUD to proved developed conversions of 10.0 MMBoe are primarily attributable to the Phoenix Field, Tornado #3ST and two wells in Main Pass Block 74, A8ST and A11ST.

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We annually review all PUD reserves to ensure an appropriate plan for development exists. Our PUD reserves are required to be converted to proved developed reserves within five years of the date they are first booked as PUD reserves. Future development costs associated with our PUD reserves at December 31, 2018 totaled approximately $396.7 million, primarily attributable the Phoenix Field’s $317.3 million future development costs. When considering capital expenditures associated with other exploration projects and abandonment obligations, we expect to fund the development of PUD reserves using cash flows from operations and, if needed, availability under the Bank Credit Facility, in each future annual period prior to the five year expiration. Our 2019 drilling program includes development of PUD reserves, and the conversion rate may not be uniform due to obligatory wells, newly acquired PUD reserves and production performance targets.

 Internal Controls over Reserve Estimates and Reserve Estimation Procedures

At December 31, 2018, 2017 and 2016, 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. (“NSAI”), independent petroleum engineers and geologists, as described in further detail below.

Our policies regarding internal controls over the determination of reserves estimates require reserves reserve quantities, reserves categorization, future producing rates, future net revenue and the present value of such future net revenue to prepared using the definitions set forth in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and guidance. These internal controls, which are intended to ensure reliability of our reserves estimations, include, but are not limited to, the following:

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil, natural gas and NGLs that are ultimately recovered.

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During the reserves audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil, natural gas and NGL production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. When compared on a well by well basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. NSAI determined that its estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X. NSAI issued unqualified audit opinions on our reserves as of December 31, 2018, 2017 and 2016 based upon its evaluations. NSAI concluded that our estimates of reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPEE. The NSAI reports are filed as exhibits this report.

Technologies Used in Reserve Estimation

The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reservoir engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:

Qualifications of Primary Internal Engineer

Floyd Bone, our Director of Reserves, is the technical person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating reserve audits conducted by NSAI. Mr. Bone has over 44 years of industry experience with positions of increasing responsibility, including 36 years as a reserves evaluator or manager. Mr. Bone’s further professional qualifications include a State of Texas Professional Engineering License, extensive internal and external reserve training and asset evaluation. In addition, Mr. Bone is an active participant in industry reserve seminars and professional industry groups, and has been a member of the SPEE for over 44 years. Mr. Bone reports directly to our Vice President of Corporate Development.

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Drilling Activity

The following table sets forth our drilling activity:

As of December 31, 2018, we had wells actively drilling or completing and wells suspended or awaiting completion, as follows:

Productive Wells

The number of our productive wells is as follows:

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Acreage

Gross and net developed and undeveloped acreage is as follows:  

Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are those leased acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well holding such lease. The terms of our leases on undeveloped acreage as of December 31, 2018 are scheduled to expire as shown in the table below (the terms of which may be extended by drilling and production operations):

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Crude Oil, Natural Gas and NGL Production, Prices and Production Costs

Our production volumes, average sales prices and average production costs are as follows:

Crude Oil, Natural Gas and NGL Production, Prices and Production Costs—Significant Fields

Phoenix Field

The following table sets forth certain information regarding our production volumes, average sales prices and average production costs for the Phoenix Field, which consisted of 15% or more of our total estimated proved reserves at December 31, 2018, 2017 and 2016:

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Pompano Field

The following table sets forth certain information regarding our production volumes, average sales prices and average production costs for the Pompano Field, which consisted of 15% or more of our total estimated proved reserves at December 31, 2018. The information below includes the period form the Closing Date of the Stone Combination, May 10, 2018, through December 31, 2018.

Expenditures and Costs Incurred

For information on property development, exploration and acquisition costs, see Part II, Item 8. Financial Statements and Supplementary Data — Note 14 — Supplemental Oil and Gas Disclosures.

Title to Properties

We believe that we have satisfactory title to our oil and natural gas properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, and carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes and development obligations under oil and natural gas leases. As is customary in the industry in the case of undeveloped properties, often limited investigation of record title is made at the time of acquisition. Title search investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. To the extent title opinions or other investigations reflect defects affecting such undeveloped properties, we are typically responsible for curing any such title defects at our expense.

Commodity Price Risks and Price Risk Management Activities

Production from our properties is marketed using methods that are consistent with industry practices. Sales prices for oil and natural gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. We enter into derivative contracts on our oil and natural gas production primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. For additional information regarding our commodity price risk and commodity derivative instruments, see Part II, Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

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Significant Customers

Oil and natural gas companies spend capital on exploration, drilling and production operations expenditures, the amount of which is generally dependent on the prevailing view of future oil and natural gas prices which are subject to many external factors which may contribute to significant volatility in future prices. We market substantially all of our oil, natural gas and NGL production from the properties we operate and those we do not operate. Our customers consist primarily of major oil and gas companies, well-established oil and pipeline companies and independent oil and natural gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when necessary. For the year ended December 31, 2018, 65% and 18% of our oil, natural gas and NGL revenues were attributable to Shell Trading (US) Company and Phillips 66, respectively, which are the customers that individually represented 10% or more of our oil, natural gas and NGL revenues.

Competitive Conditions

The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of oil and natural gas leases, equipment and personnel required to find and produce reserves and in the gathering and marketing of oil, natural gas and NGLs. We compete with large integrated oil and natural gas companies as well as independent exploration and production companies. Certain of our competitors may have significantly more financial or other resources available to them. In addition, certain of the larger integrated companies may be better able to respond to industry changes, including price fluctuation, oil and natural gas demand and governmental regulations.

However, we believe our high quality oil-weighted production base, proven expertise in utilizing seismic technology to identify, evaluate and develop exploitation and exploration opportunities, balanced mix of assets in the Gulf of Mexico deep and shallow waters and significant operating control give us a strong competitive position relative to many of our competitors.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis. Generally, but not always, the demand for gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers may impact general seasonal changes in demand.

Insurance Matters

Our oil and natural gas operations are subject to risks incident to the operation of oil and gas wells, including but not limited to uncontrolled flows of oil, gas, brine or well fluids into the environment, blowouts, cratering, mechanical difficulties, fires, explosions or other physical damage, pollution or other risks, any of which could result in substantial losses to us. In addition, our oil and natural gas properties are located in the Gulf of Mexico, which makes us more vulnerable to tropical storms and hurricanes. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and the suspension of operations. Damages arising from such occurrences may result in lawsuits asserting large claims. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on our financial condition, results of operations and cash flow. Although we obtain insurance against some of these risks, we cannot insure against all possible losses. As a result, any damage or loss not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flow.

We have insurance policies to cover some of our risk of loss associated with our operations, and we maintain the amount of insurance we believe is prudent. However, not all of our business activities can be insured at the levels we desire because of either limited market availability or unfavorable economics (limited coverage for the underlying cost).

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Our general property damage insurance provides varying ranges of coverage based upon several factors, including well counts and the cost of replacement facilities. Our general liability insurance program provides a limit of $500 million for each occurrence and in the aggregate, and includes varying deductibles. Our Offshore Pollution Act insurance is subject to a maximum of up to $150 million for each occurrence and in the aggregate, including a $100,000 retention. Coverage is provided for damage to our assets resulting from a named Gulf of Mexico windstorm; however, such coverage is subject to a maximum of $155 million per named windstorm and in the aggregate, and is also subject to a maximum of $25 million per occurrence retention. We separately maintain an operators extra expense policy with additional coverage for an amount up to $500 million for Gulf of Mexico deepwater drilling wells, $150 million for Gulf of Mexico shelf drilling wells, $75 million for Gulf of Mexico producing and shut-in wells, $50 million for drilling and workover in inland waters and $25 million for drilling and workover in onshore fields that would cover costs involved in making a well safe after a blow-out or getting the well under control; re-drilling a well to the depth reached prior to the well being out of control or blown out; costs for plugging and abandoning the well; and costs for clean-up and containment and for damages caused by contamination and pollution. For our Mexico insurance policies, we maintain $250 million in operators extra expense coverage for operations and $500 million per occurrence and aggregate limit for general liability.

We may increase or decrease insurance coverage around our key strategic assets, including potentially purchasing catastrophic bond instruments. Our highest value assets, which are located in the Phoenix Field, produce through the HP-I floating production system, which has the capability to disconnect and move away in the event of a storm, mitigating the risk of property damage.

We customarily have reciprocal agreements with our customers and vendors in which each contracting party is responsible for its respective personnel for liability related to work performed for us. Under these agreements, we generally are indemnified against third party claims related to the injury or death of our customers’ or vendors’ personnel, subject to the application of various states’ laws.

Government Regulation

Exploration and development and the production and sale of oil, natural gas and NGLs are subject to extensive federal, state, local and foreign regulations. An overview of these regulations is set forth below. We do not believe that compliance with existing requirements will have a material adverse effect on our financial position, results of operations or cash flows. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

General Overview

Our oil and natural gas operations are subject to various federal, state, local and foreign laws and regulations. Generally speaking, these regulations relate to matters that include, but are not limited to:

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Outer Continental Shelf (“OCS”) Regulation. Our operations on federal oil and natural gas leases in the Gulf of Mexico are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”) and the Bureau of Ocean Energy Management (“BOEM”), both agencies of the U.S. Department of the Interior (“DOI). These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the federal Outer Continental Shelf Lands Acts (“OCSLA”). These laws and regulations are subject to change, and many new requirements, including those related to safety, permitting and performance, were imposed by BSEE and BOEM subsequent to the 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S Environmental Protection Agency (the “EPA”), lessees must obtain a permit from BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, P&A of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities.

These rules are frequently subject to change. For example, in 2016, BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deepwater, high temperature, high pressure drilling activities, and enhanced reporting requirements. Pursuant to President Trump’s Executive Orders dated March 28, 2017, and April 28, 2017 (the “Executive Orders”), BSEE initiated a review of the well control regulations to determine whether the rules are consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. In October 2017, BSEE announced, in a report published by the DOI, that it is considering several revisions to the regulations and that it is in the process of determining the most effective way to engage stakeholders in the process. In another example, the BSEE published a final rule in September 2018 amending its production safety systems regulations, which includes the imposition of operational and design standards and the removal of the requirement of offshore operators to certify through an independent third party that their critical safety and pollution prevention equipment (e.g. subsea safety equipment, including blowout preventers) is operation and functioning as designed in the most extreme conditions.

In a third example, BOEM published a proposed rule in April 2016 that would update existing air emissions requirements relating to offshore oil and natural gas activity on the OCS. BOEM regulates these air emissions in connection with its review of exploration and development plans, rights of way (“ROWs”) and rights of use (“RUEs”) applications. The proposed rule would bolster existing air emissions requirements by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the EPA to affect human health and public welfare. Pursuant to the Executive Orders, BOEM is reviewing the proposed air quality rule. In October 2017, the DOI announced that it is currently reviewing recommendations on how to proceed, including promulgating final rules for certain necessary provisions and issuing a new proposed rule that may withdraw certain provisions and seek additional input on others.

Compliance with new and future regulations could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. In addition, under certain circumstances, BSEE may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect our financial condition and operations.

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Furthermore, hurricanes in the Gulf of Mexico can have a significant impact on oil and natural gas operations. The effects from past hurricanes have included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs. BOEM and BSEE continue to be concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the potential for future damage, BOEM and BSEE have periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not more stringent, requirements will be issued by BOEM and BSEE for future hurricane seasons. New requirements, if any, could increase our operating costs and/or capital expenditures.

In addition, in order to cover the various decommissioning obligations of lessees on the OCS, BOEM generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. For example, in the Notice to Lessees and operators (“NTL”) #2016-N01 (the “2016 NTL”), BOEM announced updated financial assurance and risk management requirements for offshore leases. The 2016 NTL details procedures to determine a lessee’s ability to carry out its lease obligations—primarily the decommissioning of facilities—and whether to require lessees to furnish additional financial assurance to meet BOEM’s estimate of the lessees decommissioning obligations. The 2016 NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure only a small portion of its OCS liabilities based upon the lessee’s financial capacity and financial strength. The 2016 NTL also allows lessees to meet their additional financial security requirements pursuant to an individually approved tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances. The 2016 NTL became effective in September 2016, but the BOEM has since extended indefinitely beyond June 30, 2017 the start date for implementation of this NTL, except for certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, so as to provide BOEM with time to review its complex financial assurance program.

In late 2016, we received orders from BOEM to provide additional financial assurance in material amounts relating to our OCS properties (the “BOEM 2016 Orders”). We entered into discussions with BOEM regarding the requested additional financial security and submitted a proposed tailored plan for the posting of additional financial security to the agency for review. However, the BOEM has indefinitely delayed beyond June 30, 2017 implementation of the 2016 NTL, has rescinded the BOEM 2016 Orders while BOEM reviews its financial assurance program and, to date, has taken no action with respect to our previously submitted proposed tailored plan.

We remain in active discussions with our government regulators and our industry peers with regard to any future rule making and financial assurance requirements. The BOEM is continuing to review and reconsider its financial assurance program and thus the amounts of any financial assurance that may be demanded by the agency is uncertain at this time. Notwithstanding the 2016 NTL, BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The BOEM could also make new demands for additional financial assurance in material amounts in the event the agency chooses to implement the 2016 NTL.  Such demands could exceed our ability to provide any additional financial assurance that may be required by BOEM in the future. The future cost of compliance with our existing supplemental bonding requirements, including the obligations imposed upon us as a result of the 2016 NTL, to the extent implemented, as well as any other future BOEM directives, or any other changes to BOEM’s rules applicable to our or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows, and results of operations.

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Regulation in Shallow Waters Off the Coast of Mexico. Our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz and Tabasco states, and in other Mexican offshore areas where we are assessing other exploration opportunities, are subject to regulation by SENER, the CNH and other Mexican regulatory bodies. The CNH is responsible for, among other things, overseeing the tender procedures for awarding contracts for the exploration and production of oil and natural gas in Mexican waters, managing and supervising contracts that have been awarded, and approving exploration and production plans. The PSCs that we and our consortium partners have entered into for the development of these acreages contain terms that impose on us the duty to comply with various laws and regulations. These laws and regulations govern, among other things, the exploration and exploitation of hydrocarbons (including certain national content requirements), the treatment, conveyance, marketing, transport and storage of petroleum, and requirements for industrial safety, operational security, and facility decommissioning. Failure to comply can result in the imposition of monetary penalties, revocation of permits, rescission of the relevant PSC, suspension of operations, and ordered decommissioning of offshore facilities and systems. The laws and regulations governing activities in the Mexican energy sector are relatively new, having been significantly reformed in 2013, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.

Environmental Regulations

We are subject to various federal, state, local and foreign regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things:

Based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and it is possible such expenses will continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters and the cost of compliance could be significant. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, natural resource damages or the issuance of injunctive relief (including orders to cease operations). Both onshore and offshore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted. Moreover, some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts onshore or offshore drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected.

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We expect to continue making expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully insured against all such risks. Our insurance coverage provides for the reimbursement to us of certain costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure against pollution and similar environmental risks. We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our consolidated financial position or our results of operations. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.

Water Discharges. Our discharges into waters of the United States are limited by the federal Clean Water Act (“CWA”) and analogous state laws. The CWA prohibits any discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, except in compliance with permits issued by federal and state governmental agencies. These discharge permits also include monitoring and reporting obligations. Failure to comply with the CWA, including discharge limits set by permits issued pursuant to the CWA, may also result in administrative, civil or criminal enforcement actions. Violations of the CWA can result in suspension, debarment or the imposition of statutory disability, each of which prevents companies and individuals from participating in government contracts and receiving some non-procurement government benefits. The CWA also requires the preparation of oil spill response plans and spill prevention, control and countermeasure plans.

Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”) holds owners and operators of offshore oil production or handling facilities, including the lessee or permittee of the area where an offshore facility is located, strictly liable for the costs of removing oil discharged into waters of the United States and for certain damages from such spills. OPA assigns joint and several strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. In addition, in January 2018, BOEM raised OPA’s damages liability cap to $137.7 million; however, a party cannot take advantage of liability limits if a spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating regulation, or if the party failed to report a spill or cooperate fully in the clean-up. OPA also requires responsible parties to maintain evidence of financial responsibility in prescribed amounts. OPA currently requires a minimum financial responsibility demonstration of between $35 million to $150 million for companies operating on the OCS, although BOEM may increase this amount in certain situations. From time to time, the United States Congress has proposed amendments to OPA raising the financial responsibility requirements. If OPA is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires federal agencies, including the DOI, to consider the impacts their actions have on the human environment, and to prepare detailed statements for major federal actions having the potential to significantly impact the environment. These requirements can lead to additional costs and delays in permitting for operators as the DOI or its bureaus may need to prepare Environmental Assessments (“EA”) and more detailed Environmental Impact Statements (“EIS”) in support of its leasing and other activities that have the potential to significantly affect the quality of the environment. If the EA indicates that no significant impact is likely, then the agency can release a finding of no significant impact and carry on with the proposed action. Otherwise, the agency must then conduct a full-scale EIS. The NEPA process involves public input through comment. These comments, as well as the agency’s analysis of the proposed project, can result in changes to the nature of a proposed project, such as by limiting the scope of the project or requiring resource-specific mitigation. The adequacy of the agency’s NEPA process can be challenged in federal court by process participants. This process may result in delaying the permitting and development of projects, and result in increased costs.

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Endangered Species Act. The Endangered Species Act (“ESA”) restricts activities that may affect federally identified endangered and threatened species or their habitats. Additionally, the Migratory Bird Treaty Act (“MBTA”) implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. Under the MBTA, the taking, killing or possessing of migratory birds is unlawful without a permit. The Marine Mammal Protection Act similarly prohibits the taking of marine mammals without authorization. We conduct operations on oil and natural gas leases in areas where certain species that are protected by the ESA, MBTA and Marine Mammal Protection Act are known to exist and where other species that potentially could be protected under these statutes. The U.S. Fish and Wildlife Service or the National Marine Fisheries Service may designate critical habitat that it believes is necessary for survival of a threatened or endangered species. A critical habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for oil and natural gas development. These statutes may result in operating restrictions or a temporary, seasonal or permanent ban in affected areas.

Hazardous Substances and Waste Management. The Resource Conservation and Recovery Act (“RCRA”) generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy,” the EPA and state agencies may regulate these wastes as solid wastes. However, pursuant to a consent decree issued by the U.S. District Court for the District of Columbia in 2016, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations that could result in oil and natural gas exploration and production wastes being regulated as hazardous wastes, or sign a determination that revision of the regulations is unnecessary. If EPA proposes rulemaking for revised oil and gas regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in increased costs to manage and dispose of generated wastes. Also, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

Comprehensive Environmental Response, Compensation and Liability Act. Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible persons” may be subject to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Further, it is not uncommon for coastal landowners or other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Air Emissions. The Clean Air Act (“CAA”) and comparable state statutes restrict the emission of air pollutants and affect both onshore and offshore oil and natural gas operations. New facilities may be required to obtain separate construction and operating permits before construction work can begin or operations may start, and existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has developed, and continues to develop, more stringent regulations governing emissions of toxic air pollutants, and is considering the regulation of additional air pollutants and air pollutant parameters. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.

Worker Health and Safety. The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

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Climate Change. From time to time, the United States Congress has considered a variety of tax, energy-related or environmental market-based mechanisms to promote or induce the reduction of emissions of Green House Gasses (“GHG”s) by several commercial or industrial sectors. In addition, more than one half of the states already have begun implementing legal measures such as renewable energy requirements or cap and trade programs to reduce emissions of GHGs.

Additionally, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. The Paris Agreement entered into force on November 4, 2016. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

In addition, the EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal CAA. The EPA has adopted rules regulating GHG emissions under the existing CAA, including a rule regulating emissions of GHGs from certain large stationary sources through preconstruction and operating permit requirements. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, on an annual basis. Currently, our operations include one active floating production unit (the HP-I,) and our facilities at the Ram Powell and Pompano Fields are subject to those EPA GHG reporting requirements.

The EPA has also taken steps to limit methane emissions, a GHG, from certain new modified or reconstructed facilities in the oil and natural gas sector through the adoption of a final rule in June 2016 establishing Subpart OOOOa standards for methane emissions. However, in 2017, the EPA published a proposed rule to stay certain portions of these Subpart OOOOa standards for two years but the rule was not finalized. Rather, in February 2018, the EPA finalized amendments to certain requirements of the June 2016 final rule, and in September 2018 the EPA proposed additional amendments, including rescission of certain requirements and revisions to other requirements, such as fugitive emission monitoring frequency. In the event that the EPA’s June 2016 rule should remain or be placed in effect, or should any other new methane emission standards be imposed on the oil and natural gas sector, such requirements could result in increased costs to our operations as well as result in restrictions, delays or cancellations in such operations, which costs, restrictions, delays or cancellations could adversely affect our business.

Environmental Regulation in Shallow Waters Off the Coast of Mexico. Our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz and Tabasco states, and in other Mexican offshore areas where we are assessing other exploration opportunities, are subject to regulation by the Mexican National Agency of Industrial Safety and Environmental Protection of the Hydrocarbons Sector (“ASEA”). We must obtain ASEA-issued permits and comply with ASEA regulations governing hydrocarbon activities, including requirements for environmental impact and risk assessments, industrial safety, waste management, water and air emissions, operational security, and facility decommissioning. Failure to comply with applicable laws and regulations can result in the imposition of monetary penalties, revocation of permits, suspension of operations, and ordered decommissioning of offshore facilities and systems. The laws and regulations governing the protection of health, safety, and the environment from activities in the Mexican energy sector are relatively new, having been significantly reformed in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.

Under the PSCs, we are jointly and severally liable, along with Sierra and Premier, for the performance of all obligations under the PSCs, including exploration, appraisal, extraction, and abandonment activities and compliance with all environmental regulations, and failure to perform such obligations could result in contractual recession of the PSCs.

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Federal Regulation of Sales and Transportation of Natural Gas

Our sales of natural gas are affected directly or indirectly by the availability, terms and cost of natural gas transportation. The prices and terms for access to pipeline transportation of natural gas are subject to extensive federal and state regulation. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”) and by regulations and orders promulgated under the NGA and/or NGPA by the Federal Energy Regulatory Commission (“FERC”). In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the United States Congress and by FERC regulations. However, certain offshore gathering and transportation services we rely upon are subject to limited FERC regulation and are regulated by the states.

Pursuant to authority delegated to it by the Energy Policy Act of 2005 (“EPAct 2005”), the FERC promulgated anti-manipulation regulations establishing violation enforcement mechanisms that make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC to (i) use or employ any device, scheme or artifice to defraud, (ii) make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (iii) engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any entity. The EPAct 2005 also amended the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes and regulations, up to $1,269,500 per violation, per day for 2019 (this amount is adjusted annually for inflation). The FERC may also order disgorgement of profits and corrective action. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes annual reporting requirements for entities that purchase or sell a certain volume of natural gas in a given calendar year. We believe, however, that neither the EPAct 2005 nor the regulations promulgated by FERC as a result of the EPAct 2005 will affect us in a way that materially differs from the way they affect other natural gas producers, gatherers and marketers with which we compete.

Our sales of oil and natural gas are also subject to market manipulation and anti-disruptive requirements under the Commodity Exchange Act (“CEA”) as amended by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), and regulations promulgated thereunder by the U.S. Commodity Futures Trading Commission (the “CFTC”). The CFTC prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

The current statutory and regulatory framework governing interstate natural gas transactions is subject to change in the future, and the nature of such changes is impossible to predict. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by the United States Congress, the applicable federal agencies, or the various state legislatures, and what effect, if any, the proposals might have on our operations. The natural gas industry historically has been very heavily regulated. In the past, the federal government regulated the prices at which natural gas could be sold. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. However, we are subject to reporting requirements imposed by FERC. There is always some risk, however, that the United States Congress may reenact price controls in the future. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines or impose additional reporting or other requirements upon our operations, and we cannot predict what future action the FERC will take. Therefore, there is no assurance that the current regulatory approach recently pursued by the FERC and the United States Congress will continue. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

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Federal Regulation of Sales and Transportation of Crude Oil

The FERC regulates the interstate pipeline of crude oil, petroleum products, and other liquids, such as NGLs. Our sales of crude oil and condensate are currently not regulated and are made at negotiated prices. There is always some risk, however, that the United States Congress may reenact crude oil, petroleum products and NGL price controls in the future. We cannot predict whether new legislation to regulate crude oil, or the prices charged for crude oil might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements.

Our ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”), and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. Certain regulations implemented by the FERC in recent years and certain pending rulemaking and other proceedings could result in an increase in the cost of transportation service on certain petroleum products pipelines. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other crude oil and condensate producers with which we compete.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to other crude oil and condensate producers with which we compete.

Our SP 49 Pipeline LLC system is subject to regulation by FERC under the ICA, the Energy Policy Act of 1992, and the rules and orders promulgated thereunder.  The ICA requires that tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory.  FERC-regulated liquids pipelines, including SP 49 Pipeline LLC, typically use the FERC indexing methodology to change its rates. The FERC, however, retained cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach that may be used in certain specified circumstances.  The FERC reviews the index formula every five years. Effective July 1, 2016, the annual index adjustment for the five-year period ending June 30, 2021, will equal the producer price index for finished goods for the applicable year plus an adjustment factor of 1.23%. Pipelines may raise their rates to the rate ceiling level generated by application of the annual index adjustment factor each year; however, a shipper may challenge such increase if the increase in the pipeline’s rates was substantially in excess of the actual cost increases incurred by the pipeline during the relevant year. Because the indexing methodology for the next five-year period is tied to an inflation index and is not based on pipeline-specific costs, the indexing methodology could hamper our ability to recover cost increases. On March 15, 2018, FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating, among other things, that with respect to oil and refined products pipelines subject to FERC jurisdiction, the impacts of the Revised Policy Statement and the Tax Cuts and Jobs Act of 2017 on the costs of FERC-regulated oil and NGL pipelines will be reflected in FERC’s next five-year review of the oil pipeline index, which will generate the index level to be effective July 1, 2021. FERC’s establishment of a just and reasonable rate, including the determination of the appropriate oil pipeline index, is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect FERC’s determination of the appropriate pipeline index. Accordingly, depending on FERC’s application of its indexing rate methodology for the next five-year term of index rates, the Revised Policy Statement and tax effects related to the Tax Cuts and Jobs Act of 2017 may impact our revenues associated with any transportation services we may provide pursuant to cost-of-service based rates in the future, including indexed rates.

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FERC historically has not investigated rates of liquids pipelines on its own initiative when those rates have not been the subject of a protest or complaint by a shipper. FERC issued an Advance Notice of Proposed Rulemaking on October 20, 2016, that addressed issues related to FERC’s indexing methodology and liquids pipeline reporting practices. If implemented, the proposals in this rulemaking could affect the profitability of certain liquids pipelines.

We have an undivided interest in a pipeline owned by CKB Petroleum, Inc. that is subject to FERC jurisdiction under the ICA, but FERC has granted us a temporary waiver of the filing and reporting requirements. This pipeline is still subject to FERC’s jurisdiction under the ICA and is still subject to the other requirements of the ICA. If the facts upon which the waiver was granted change materially, we are required to inform the FERC, which may result in revocation of the waiver.  If conditions change such that the pipeline no longer qualifies for a waiver, we may be subject to regulation by FERC of the rates, terms, and conditions of service on the CKB Petroleum, Inc. pipeline, however these burdens generally would not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar pipelines.

The FERC also implements the OCSLA pertaining to transportation and pipeline issues, which requires that all pipelines operating on or across the OCS provide nondiscriminatory transportation service. We own and operate pipelines that are located in the OCS and are subject to the non-discrimination requirements in the OCSLA.

Employees

We had 374 employees as of March 6, 2019.

Available Information

We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, all amendments to those reports, and all other information filed with or furnished to the SEC available, free of charge, through our website, https://www.talosenergy.com, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. The filings are also available by accessing the SEC’s website at https://www.sec.gov.

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Item 1A. Risk Factors

Certain factors may have a material adverse effect on our business, financial condition, and results of operations. You should consider carefully the risks and uncertainties described below, in addition to other information contained in this Annual Report on Form 10-K, including our consolidated financial statements and related notes. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, may also become important factors that adversely affect our business. If any of the following risks actually occur, our business, financial condition, results of operations and future prospects could be materially and adversely affected. In that event, the trading price of our common stock could decline, and you could lose part or all of your investment.

Oil and natural gas prices are volatile. Significant declines in commodity prices in the future may adversely affect our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.

Our revenues, cash flows, profitability, and future rate of growth substantially depend upon the market prices of oil and natural gas. Prices affect our cash flows available for capital expenditures and our ability to access funds under our Bank Credit Facility and through the capital markets. The amount available for borrowing under our Bank Credit Facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves, and is subject to periodic redeterminations based on pricing models to be determined by the lenders at such time. Oil and natural gas prices significantly declined in the second half of 2014, with sustained lower prices continuing throughout 2015, 2016 and 2017. Despite a modest recovery from late 2017 to mid-2018, commodity prices could remain suppressed or decline further in the future, which will likely have material adverse effects on our proved reserves and borrowing base. Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, which is impacted by declining prices. Significant price declines could cause us to take ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See the Risk Factor entitled “Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other impairments of our asset carrying values” for further discussion.

In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period January 1, 2016 through December 31, 2018, the NYMEX WTI crude oil price per Bbl ranged from a low of $30.62 to a high of $70.76, and the NYMEX natural gas price per MMBtu ranged from a low of $1.71 to a high of $4.72. The high, low and average prices for NYMEX WTI and NYMEX Henry Hub are monthly contract prices. The prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others:

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These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because oil, natural gas, and NGLs accounted for approximately 74%, 19%, and 7%, respectively, of our estimated proved reserves as of December 31, 2018, and approximately 70%, 23%, and 7%, respectively, of our 2018 production on an MBoe basis, our financial results are sensitive to movements in oil, natural gas, and NGL prices.

We are required to meet a minimum work program expressed in work units during a four-year exploration period according to our PSCs with the CNH.

On September 11, 2018, we entered into a transaction with Hokchi, a subsidiary of PAE, to cross assign 25% PIs in Block 2 and Block 31, both in the Sureste Basin off the coast of Mexico. Our assignment of a 25% PI in Block 2 to Hokchi closed on December 21, 2018, and Hokchi has assumed operator responsibilities with respect to Block 2. Hokchi’s assignment of Block 31 to us will be completed upon final approval by the CNH. In addition, Premier exercised its option to reduce its PI in Block 2 to zero and assign a 5% PI to each of Sierra and us. Such assignment is also subject to CNH’s approval. Upon the completion of the Hokchi Cross Assignment and Premier’s option exercise, Hockchi will be the operator of both blocks, we will own a 25% PI in Block 31 and our PI in Block 2, and our pro rata portion of the minimum work program on Block 2 will decrease from 45% to 25%. We posted  an additional $8.7 million required in letters of credit to cover our pro rata portion of the minimum work program on Block 31 pursuant to the relevant PSC.

If we or the Consortium is unable to meet a minimum work program, we could be liable along with the other members in the Consortium for the remaining financial guarantee, and the CNH could rescind the PSC for a default.

Our debt level and the covenants in our current or future agreements governing our debt, including our Bank Credit Facility and the indenture for our 11.00% Senior Secured Notes, could negatively impact our financial condition, results of operations, and business prospects. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.

The terms of the agreements governing our debt impose significant restrictions on our ability to take a number of actions that we may otherwise desire to take, including:

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Our level of indebtedness, and the covenants contained in the agreements governing our debt, including the Bank Credit Facility and the indenture for our 11.00% Senior Secured Notes, have important consequences on our operations, including:

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Sustained low oil and natural gas prices have a material and adverse effect on our liquidity position. Our cash flow is highly dependent on the prices we receive for oil and natural gas, which have declined significantly as compared to mid-2014.

We depend on our Bank Credit Facility for a portion of our future capital needs. We are required to comply with certain debt covenants and certain financial ratios under the Bank Credit Facility. Our borrowing base under the Bank Credit Facility, which is redetermined semi-annually, is based on an amount established by the lenders after their evaluation of our proved oil and natural gas reserve values. If, due to a redetermination of our borrowing base, our outstanding borrowings plus outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency. Our Bank Credit Facility allows us to cure a borrowing base deficiency through any combination of the following actions: (i) repay amounts outstanding sufficient to cure the borrowing base deficiency within 30 days after the existence of such deficiency; (ii) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after the existence of such deficiency; (iii) pay the deficiency in four equal monthly installments with the first installment due within 30 days after the existence of such deficiency; or (iv) any combination of the above. We are required to elect one of the foregoing options within 10 days after the existence of such deficiency.

We may not have sufficient funds to make such repayments. If we do not repay our debt out of cash on hand, we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell assets, or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity financings, or proceeds from the sale of assets are available to pay or refinance such debt. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our debt, including our Bank Credit Facility and the indenture for our 11.00% Senior Secured Notes, may also prohibit us from taking such actions. Factors that affect our ability to raise cash through offerings of our capital stock, a refinancing of our debt, or a sale of assets include financial market conditions and our market value and operating performance at the time of such offerings, refinancing, or sale of assets. We cannot assure you that any such offerings, restructuring, refinancing, or sale of assets would be successfully completed.

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Regulatory requirements and permitting procedures imposed by the BOEM and the BSEE could significantly delay our ability to obtain permits to drill new wells in offshore waters.

BSEE and BOEM have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill response, and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, are continuing to develop and implement new, more restrictive requirements. For example, in April 2016, BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation, and maintenance of blow-out preventers, real-time monitoring of deepwater, high temperature, high pressure drilling activities, and enhanced reporting requirements. Pursuant to the Executive Orders, BSEE initiated a review of the well control regulations to determine whether the rules are consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. One consequence of this review is that in September 2018, BSEE published final revisions to its regulations regarding offshore drilling safety equipment, which includes the removal of the requirement for offshore operators to certify through an independent third party that their critical safety and pollution prevention equipment (e.g., subsea safety equipment, including blowout preventers) is operational and functioning as designed in the most extreme conditions.

Also, in April 2016, BOEM published a proposed rule that would update existing air emissions requirements relating to offshore oil and natural gas activity on the OCS. BOEM regulates these air emissions in connection with its review of exploration and development plans, rights of way and rights of use, and/or easement applications. The proposed rule would bolster existing air emissions requirements by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the EPA to affect human health and public welfare. Pursuant to the Executive Orders, BOEM has ceased rulemaking activities for and is reviewing the proposed air quality rule. In October 2017, the DOI announced that it is currently reviewing recommendations on how to proceed, including promulgating final rules for certain necessary provisions and issuing a new proposed rule that may withdraw certain provisions and seek additional input on others.

Compliance with new and future regulations could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Furthermore, among other adverse impacts, to the extent that BOEM and BSEE do not reduce the stringency of existing oil and gas safety and performance-related regulations and other regulatory initiatives, the regulatory requirements imposed by such existing or future, more stringent regulations or other regulatory initiatives could delay operations, disrupt our operations, or increase the risk of leases expiring before exploration and development efforts have been completed due to the time required to develop new technology. Additionally, if left unchanged, the existing, or future, more stringent oil and gas safety and performance-related regulations and other regulatory initiatives imposed by BOEM and BSEE could result in incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties or shut-in production at one or more of our facilities. Also, if material spill incidents were to occur in the future, the United States or other countries where such an event may occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.

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New guidelines issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS may have a material adverse effect on our business, financial condition, or results of operations.

BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS.  In July 2016, BOEM issued the 2016 NTL to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs or RUEs.  The 2016 NTL became effective in September 2016, but BOEM has since extended indefinitely beyond June 30, 2017 the start date for implementing this NTL, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, so as to provide BOEM with time to review its complex financial assurance program.

In late 2016, we received orders from BOEM to provide additional financial assurance in material amounts relating to our OCS properties (the “BOEM 2016 Orders”). We entered into discussions with BOEM regarding the requested additional financial security and submitted a proposed tailored plan for the posting of additional financial security to the agency for review. However, as noted, BOEM has indefinitely delayed beyond June 30, 2017 implementation of the 2016 NTL, has rescinded the BOEM 2016 Orders while BOEM reviews its financial assurance program and, to date, has taken no action with respect to our previously submitted proposed tailored plan.

As of the filing date of this Annual Report on Form 10-K, we have no outstanding BOEM orders for financial assurance obligations, although we are in discussions with the agency regarding providing financial assurance in what we view as the normal course of business for one well, Mount Providence, that was completed July 2018.  Following completion of its review of its financial assurance program, BOEM may elect to retain the 2016 NTL in its current form or may make revisions thereto. Thus, until the review is completed and BOEM determines what additional financial assurance may be required by us, we cannot provide any assurance of the amount of any additional financial assurance, which may be material, that may be ordered by BOEM and required in any proposed tailored plan that we may submit to BOEM in the future for approval, or that such additional financial assurance amounts can be obtained.  Moreover, BOEM could in the future make new demands for additional financial assurances in material amounts relating to the decommissioning of our OCS properties. BOEM may reject our proposals to satisfy any such additional financial assurance coverage and make demands that exceed our capabilities.

If we fail to comply with the current or future orders of BOEM to provide additional surety bonds or other financial assurances, BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.

In addition, if fully implemented, the 2016 NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which could in turn force these operators to seek additional surety bonds and could, consequently, challenge the surety bond market’s capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of their lien on the operator’s collateral. Moreover, depressed oil prices could result in sureties seeking additional collateral to support existing bonds, such as cash or letters of credit, and we cannot provide assurance that we will be able to satisfy collateral demands for future bonds to comply with supplemental bonding requirements of BOEM. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.

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We have a subsidiary that is subject to a plea agreement with the Department of Justice (“DOJ”) pursuant to which certain exploration and production activities must comply with a Safety and Environmental Compliance Program (“SECP”). Noncompliance with the SECP could result in a violation of the plea agreement and provide a basis for revocation or modification of probation.

In February 2014, we received a grand jury subpoena from the DOJ addressing activities that occurred on the Ship Shoal 225A production platform operated by one of our subsidiaries, ERT. On November 30, 2015, ERT was charged with two violations of the OCSLA in connection with hot work and blowout preventer testing activities, and with two violations of the CWA for self-reported activities surrounding overboard discharge sampling and unpermitted discharges. On January 6, 2016, ERT pled guilty to these charges. On April 6, 2016, the United States District Court for the Eastern District of Louisiana (the “Court”) accepted ERT’s plea and sentenced ERT, consistent with the plea agreement, to pay a penalty of $4.2 million, which ERT has paid. The Court placed ERT on probation for three years. The conditions of probation include compliance with an agreed SECP, pursuant to which ERT and another subsidiary of ours must implement enhanced safety and environmental compliance inspections, reviews and audits, implement a comprehensive training program, implement enhanced operational controls to better manage, detect and prevent safety and environmental violations, and preparation and implementation of a schedule for decommissioning. Any failure to comply with the SECP could result in a violation of the plea agreement and provide a basis for revocation or modification of probation, which could adversely our financial condition and operations.

A financial crisis may impact our business and financial condition and may adversely impact our ability to obtain funding under our Bank Credit Facility or in the capital markets.

We use our cash flows from operating activities and borrowings under our Bank Credit Facility to fund our capital expenditures, and we rely on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. However, we may not be able to access adequate funding under our Bank Credit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination or a breach or default under our Bank Credit Facility, including a breach of a financial covenant or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. In addition, we may face limitations on our ability to access the debt and equity capital markets and complete asset sales, an increased counterparty credit risk on our derivatives contracts, and the requirement by our contractual counterparties to post collateral guaranteeing performance.

We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.

We spend a substantial amount of capital for the acquisition, exploration, exploitation, development, and production of oil and natural gas reserves. We fund our capital expenditures primarily through operating cash flows, cash on hand and borrowings under our Bank Credit Facility, if necessary. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A further reduction in commodity prices may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital is subject to a number of variables, including:

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If low oil and natural gas prices, operating difficulties, declines in reserves or other factors, many of which are beyond our control, cause our revenues, cash flows from operating activities, and the borrowing base under our Bank Credit Facility to decrease, we may be limited in our ability to fund the capital necessary to complete our capital expenditure program. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot be sure that additional debt or equity financing will be available, and we cannot be sure that cash flows provided by operations will be sufficient to meet these requirements. For example, the ability of oil and gas companies to access the equity and high yield debt markets has been significantly limited since the significant decline in commodity prices as compared to mid-2014. Access to the equity and high yield debt markets continue to be limited.

We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production. Accordingly, we are dependent upon distributions from Talos Production to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock.

We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production. We have no independent means of generating revenue. To the extent Talos Production has available cash, we will cause Talos Production to make distributions of cash to us, directly and indirectly through our wholly owned subsidiaries, to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock. As we have never declared or paid any cash dividends on our common stock, we anticipate that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead expenses, will be retained by Talos Production to satisfy its operational and other cash needs. Accordingly, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Although we do not expect to pay dividends on our common stock, if our board of directors decides to do so in the future, our ability to do so may be limited to the extent Talos Production is limited in its ability to make distributions to us, including the significant restrictions the agreements governing Talos Production’s debt impose on the ability of Talos Production to make distributions and other payments to us. To the extent that we need funds and Talos Production is restricted from making such distributions under applicable law or regulation or under the terms of our financing agreements, or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.

Our production, revenue, and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, the Gulf of Mexico and in the shallow waters off the coast of Mexico. Unlike other entities that are geographically diversified, we may not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate, and result in our dependency upon a single or limited number of hydrocarbon basins. In addition, the geographic concentration of our properties in the Gulf of Mexico and in the shallow waters off the coast of Mexico means that some or all of our properties could be affected should the region experience:

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Because all or a number of our properties could experience many of the same conditions at the same time, these conditions may have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

We may experience significant shut-ins and losses of production due to the effects of hurricanes in the Gulf of Mexico and in the shallow waters off the coast of Mexico.

Our production is primarily associated with our properties in the Gulf of Mexico and in the shallow waters off the coast of Mexico. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes and tropical storms in the Gulf of Mexico. We are unable to predict what impact future hurricanes and tropical storms might have on our future results of operations and production.

A significant portion of our production, revenue and cash flow is concentrated in our Phoenix Field and our Pompano Field. Because of this concentration, any production problems, impacts of adverse weather or inaccuracies in reserve estimates could have a material adverse impact on our business.

For the year ended December 31, 2018, approximately 39% and 15% of our historical production and 41% and 17% of our historical oil, natural gas, and NGL revenue was attributable to our Phoenix Field and our Pompano Field, respectively, both of which are located in the federal waters offshore in the Gulf of Mexico. This concentration in these fields means that any impact on our production from these fields, whether because of mechanical problems, adverse weather, well containment activities, changes in the regulatory environment, or otherwise, could have a material effect on our business. We produce the Phoenix Field through the HP-I, a dynamically positioned floating production facility that is operated by Helix. The HP-I interconnects the Phoenix Field through a production buoy that can be disconnected if the HP-I cannot maintain its position on station, such as in the event of a mechanical problem with the dynamic positioning system or the approach of a hurricane. Because the HP-I may have to be disconnected from the Phoenix Field if circumstances require, our production from the Phoenix Field may be subject to more frequent interruptions than if the Phoenix Field was produced by a more conventional platform. We are also required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the United States Coast Guard, during which time we are unable to produce the Phoenix Field. As of the filing date of this Annual Report on Form 10-K, Helix has dry-docked the HP-I, and the shut-in is estimated to through March 2019. On September 10, 2016, the HP-I was disconnected from the production buoy and released for dry dock for 28 days. Upon completion of the dry dock, the HP-I remained disconnected from the buoy connecting it to the Phoenix Field due to Federal Emergency Management Agency testing of test upgrades to the power management system, preventing us from reconnecting the HP-I to the Phoenix Field for a further five days. Once the buoy was connected, Phoenix Field production remained shut-in for an additional five days to conduct buoy remediation of the swivel piping. In addition, for 25 days in March 2015, we were required to disconnect the HP-I from the production buoy due to upgrades to the power management system of the vessel, which is an integral part of the dynamic positioning system. The upgrade work was followed by sea trials that tested the dynamic positioning system and were required by various regulatory groups, including the United States Coast Guard.

The HP-I is part of the Helix Well Containment Group (“HWCG”), which is a consortium that is available to respond to any deepwater well control event, such as the Macondo well oil spill. If such an event were to occur and the HWCG was to be utilized for well control, the HP-I, which is the vessel that would be used to respond to the deepwater well control event, would be required to disconnect from the Phoenix Field until such time as the well control event was resolved and the HP-I could return to the Phoenix Field. During such time period, we would not be able to produce the Phoenix Field. In the event the HP-I has to disconnect from the Phoenix Field, our production, revenue, and cash flow could be adversely affected, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, all of our production from the Phoenix Field flows through the Green Canyon 19 connection facility operated by Shell GOM Pipeline Company LLC. To the extent Shell GOM Pipeline Company LLC temporarily shuts in its Green Canyon 19 connection facility, whether for maintenance or otherwise, we would not able to produce the Phoenix Field during this period of time, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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If the actual reserves associated with the Phoenix Field are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, all of our production from the Pompano Field flows through the Pompano Pipeline System operated by Crimson Gulf LLC. To the extent Crimson Gulf LLC temporarily shuts in the Pompano Pipeline System,   whether for maintenance or otherwise, we would not be able to produce the Pompano Field during this period of time, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

If the actual reserves associated with the Pompano Field are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are not insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, named Gulf of Mexico windstorm, oil pollution, construction all risk, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses.

We have general liability insurance coverage with an annual aggregate limit of $500 million. We selectively purchase physical damage insurance coverage for our pipelines, platforms, facilities and umbilicals for losses resulting from named windstorms and operational activities.

Our operational control of well coverage is expected to provide limits that vary by well location and depth and range from a combined single limit of $25 million to $500 million per occurrence. Exploratory deepwater wells have a coverage limit of up to $500 million per occurrence. Additionally, we maintain up to $150 million in oil pollution liability coverage. Our operational control of well and physical damage policy limits is scaled proportionately to our working interests. Our general liability program utilizes a combination of assured’s interest and scalable limits. All of our policies described above are subject to deductibles, sub-limits, or self-insurance. Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider, subject to the application of various states’ laws.

An operational or hurricane or other adverse weather-related event may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest. Such events may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have production interruption insurance.

We reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the Gulf of Mexico, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

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Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other impairments of our asset carrying values.

We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs to acquire, explore for and develop oil and gas properties. Under the full cost method of accounting, we compare, at the end of each financial reporting period for each cost center, the present value of estimated future net cash flows from proved reserves (based on a trailing 12-month average, hedge-adjusted commodity price and excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the estimated discounted future net cash flows. A write-down of oil and gas properties does not impact cash flows from operating activities, but does reduce net income. The risk that we are required to write-down the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings. Any required write-downs or impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local governmental regulations that materially affect our operations.

Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Regulated matters include: permits for exploration, development and production operations; limitations on our drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions on the way we can discharge materials into the environment; bonds or other financial responsibility requirements to cover drilling contingencies and well P&A and other decommissioning costs; reports concerning operations, the spacing of wells and unitization and pooling of properties; regulations regarding the rate, terms and conditions of transportation service or the price, terms, and conditions related to the purchase and sale of oil and natural gas; and taxation. Failure to comply with these laws and regulations can result in the assessment of administrative, civil or criminal penalties, the issuance of remedial obligations and the imposition of injunctions limiting or prohibiting certain of our operations. In addition, because we hold federal leases, the federal government requires that we comply with numerous additional regulations applicable to government contractors.

In July 2017, we, along with partners Sierra and Premier, reported the discovery of a significant reservoir of crude oil in the Sureste basin offshore Mexico through the Zama-1 well. Data from the Zama-1 well indicates that it is possible the deposit could be part of a field that extends into an exploration block in which the state entity Pemex holds exploration and development rights.

The Ministry of Energy of Mexico has promulgated guidelines to establish procedures for conducting the unitization of shared reservoirs and approving the terms and conditions of unitization and unit operating agreements, as well as the authority to direct parties holding rights in a potentially shared reservoir to appraise and potentially form a unit for development of such reservoir. 

Even with the final regulations in place, there are still some uncertainties regarding the unitization process, including the selection of a unit operator and the exact length of time that will take to obtain approvals of any unit agreements. Any unit operating agreement eventually agreed to by the relevant parties or any unit order issued by a governmental entity in Mexico could be adverse to us and affect the value that we are able to recognize from the reservoir discovery, including but not limited to an agreement or unit order that would require us to allow a third party to develop and produce the crude oil reservoir identified through the Zama-1 well.

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In addition, the OPA requires operators of U.S. offshore facilities to prove that they have the financial capability to respond to costs that may be incurred in connection with potential oil spills. Under the OPA and other environmental statutes such as the CERCLA, the RCRA and analogous state laws, owners and operators of certain defined onshore and offshore facilities are strictly liable for spills of oil and other regulated substances, subject to certain limitations. Consequently, a spill from one of our facilities subject to laws such as the OPA, CERCLA and RCRA could require the expenditure of additional, and potentially significant, amounts of capital, or could have a material adverse effect on our earnings, results of operations, competitive position or financial condition. We cannot predict the ultimate cost of compliance with these requirements or their impact on our earnings, operations or competitive position.