Annual Report (10-k)

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 pro duction 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, 2 018, 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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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:  

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 th e 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 rese rves 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 informati on 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 e stimates of NSAI . Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expect ed. 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 Regu lation 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 t he 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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As of December 31, 2018, we had wells actively drilling or completing and wells suspended or awaiting completion, as follows:

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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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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 pr ovides a limit of $50 0 million for each occurrence and in the aggregate, and includes varying deductibles . O ur 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 $15 5 million per named windstorm and in the aggregate, and is also subject to a maximum of $25 m illion 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 aggrega te 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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