Water Discharges.  The primary federal law for oil spill liability is the Oil Pollution Act (the “OPA”) which amends and augments oil spill provisions of the federal Water Pollution Control Act (the “Clean Water Act”).  OPA imposes certain duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters, including the OCS or adjoining shorelines.  A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located.  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 and natural resource release related 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, the BOEM raised OPA’s damages liability cap to $137.7 million.million; however, a party cannot take advantage of liability limits if the 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 cleanup.  OPA requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill, and to prepare and submit for approval oil spill response plans.  These oil spill response plans must detail the action to be taken in the event of a spill; identify contracted spill response equipment, materials, and trained personnel; and identify the time necessary to deploy these resources in the event of a spill. In addition, OPA currently requires a minimum financial responsibility demonstration of between $35$35.0 million and $150$150.0 million for companies operating on the OCS.  We are currently required to demonstrate, on an annual basis, that we have ready access to $150$150.0 million that can be used to respond to an oil spill from our facilities on the OCS.

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the monitoring and discharge of pollutants, including produced waters and other natural gas wastes, into federal and state waters.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state.an analogous state agency.  The EPA has also adopted regulations requiring certain onshore oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.  The treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from our onshore gas processing plant may have significant costs.  Obtaining permits has the potential to delay, restrict or cancel the development of oil and natural gas projects.  These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs.  Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil.

Marine Protected Areas and Endangered and Threatened Species.  Executive Order 13158, issued in May 2000, directs federal agencies to safeguard existing Marine Protected Areas (“MPAs”) in the United States and establish new MPAs.  The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable.  It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment.  In addition, Federal Lease Stipulations include regulations regarding the taking of protected marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species).

Certain flora and fauna that have been officially classified as “threatened” or “endangered” are protected by the federal Endangered Species Act, as amended (“ESA”).  This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area.  Additionally, the U.S. Fish and Wildlife Service may make determinations on the listing of species as threatened or endangered under the ESA and litigation with respect to the listing or non-listing of certain species may result in more fulsome protections for non-protected or lesser-protected species.  We conduct operations on leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist.  We own aDuring 2017, we reached an agreement with the various governmental agencies to remove the topside structure on our non-producing platform in the Gulf of Mexico located in a National Marine Sanctuary.  As a result, we are subjectSanctuary in the U.S. Gulf of Mexico and leave the bottom of the platform structure below the water line in place.  The project was completed during 2018 and allows the marine growth attached to additional federal regulation, including regulations issued byand around the National Oceanicstructure to remain and Atmospheric Administration.continue to grow.  Unique regulations related to operations in a sanctuary include prohibition of drilling activities within certain protected areas, restrictions on the types of water and other substances that may be discharged, required depths of discharge in connection with drilling and production activities and limitations on mooring of vessels.  During 2017, we reached an agreement with the various governmental agencies to remove the topside structure on our non-producing platform located in the National Marine Sanctuary and leave the bottom of the platform structure below the water line in place.  This bottom portion of the platform structure will remain due to the density and diversity of marine growth attached to and around the structure.  

Other federal statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the National Environmental Policy Act, the Coastal Zone Management Act, the Emergency Planning and Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Magnuson-Stevens Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act.  These laws and related implementing regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands.  These and other protected areas may require certain mitigation measures to avoid harm to wildlife, and such laws and regulations may impose substantial liabilities for pollution resulting from our operations.  The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities.

Financial Information

We operate our business as a single segment. See Selected Financial Data under Part II, Item 6 and Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for our financial information.

Seasonality

Generally, the demand for and price of natural gas increases during the winter months and decreases during the summer months.  However, these seasonal fluctuations are somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas.  As utilities continue to switch from coal to natural gas, some of this seasonality has been reduced as natural gas is used for both heating and cooling.  In addition, the demand for oil is higher in the winter months, but does not fluctuate seasonally as much as natural gas. Seasonal weather changes affect our operations.  Tropical storms and hurricanes occur in the Gulf of Mexico during the summer and fall, which require us to evacuate personnel and shut in production until the storm subsides.  Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which delays the installation of production facilities, thereby delaying production and sales of our oil and natural gas.

Employees

As of December 31, 2017,2019, we employed 298291 people. We are not a party to any collective bargaining agreements and we have not experienced any strikes or work stoppages. We consider our relations with our employees to be good.

Additional Information

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, other reports and amendments to those reports with the SEC. Our reports filed with the SEC are available free of charge to the general public through our website at www.wtoffshore.com.  These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC.  This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Investor Relations, W&T Offshore, Inc., Nine Greenway Plaza, Suite 300, Houston, Texas 77046 or by calling (713) 297-8024.  These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549.  The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.  Information on our website is not a part of this Form 10-K.

IItemtem 1A. Risk Factors

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to us and our industry could materially impact our future performance and results of operations. We have provided below a list of known material risk factors that should be reviewed when considering buying or selling our securities. These are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.

Risks Relating to Our Industry, Our Business and Our Financial Condition

Crude oil, natural gas and NGL prices can fluctuate widely due to a number of factors that are beyond our control. Depressed oil, natural gas or NGL prices could adversely affect our business, financial condition, cash flow, liquidity or results of operations and could affect our ability to fund future capital expenditures needed to find and replace reserves, meet our financial commitments and to implement our business strategy.

The price we receive for our crude oil, NGLs and natural gas production directly affects our revenues, profitability, access to capital, ability to produce these commodities economically and future rate of growth.  Crude oil, NGLs and natural gas are commodities and historically have been subject to wide price fluctuations, sometimes in response to minor changes in supply and demand.  These markets for crude oil, NGLs and natural gas have been volatile and will likely continue to be volatile in the future. Although prices increased during 2017 from 2016 and 2015 levels, these past three years of lower prices have substantially decreased our revenues on a per unit basis and reduced the amount of crude oil, NGLs and natural gas that we could produce economically.  The prices we receive for our production and the volume of our production depend on numerous factors beyond our control.  These factors include the following:

The prices of crude oil and NGLs began declining in the second half of 2014 and continued declining until reaching a bottom in the first quarter of 2016, and then slowly rising in 2017.  The average price per barrel of West Texas Intermediate (“WTI”) crude oil was over $90.00 in 2014, approximately $49.00 in 2015, approximately $43.00 per barrel in 2016 and approximately $50.00 per barrel in 2017.  During 2014, the average Henry Hub spot price for natural gas was above $4.00 per MMBtu compared to approximately $2.60 per MMBtu during 2015, approximately $2.50 per MMBtu in 2016 and approximately $3.00 per MMBtu in 2017.  This decrease and volatility in prices has impacted all companies throughout the oil and gas industry.  Although oil prices have increased from the lows of the first quarter of 2016, margins are still below historical levels.  Low prices for crudeHistorically, oil, NGLs and natural gas prices couldhave been volatile and subject to wide price fluctuations in response to domestic and global changes in supply and demand, economic and legal forces, events and uncertainties, and numerous other factors beyond our control, including:  

These factors and the volatility of the energy markets, which we expect to continue, make it extremely difficult to predict future commodity prices with any certainty. The average price for oil decreased during 2019 compared to 2018, but was higher compared to the average prices in 2017 and 2016, while prices for natural gas and NGLs decreased to their lowest levels since 2016.

Low prices for our products relative to the cost to find, develop and produce products reduces our profitability and can materially and adversely affect our future business, financial condition, results of operations, liquidity, ability to finance planned capital expenditures, ability to fund our ARO, ability to repay any borrowings per our debt agreements, ability to secure supplemental bonding, ability to secure collateral for such bonding, if required, and ability to meet our other financial obligations.

The borrowing base under our Credit Agreement may be reduced or may not be extended by our lenders.

Availability of borrowings and letters of credit under theour Credit Agreement is determined by establishment of a borrowing base, which is periodically redetermined during the year based on our lenders’ viewreview of crude oil, NGLs and natural gas prices and on our proved reserves.  During 2017,2019, there were no changes in theto our borrowing base under the Credit Agreement, from year-end 2016, but during 2016,2018, the borrowing base was reducedincreased from $350$150.0 million to $150$250.0 million.  The borrowing base was lowered primarily dueis subject to declines in commodity pricesscheduled semi-annual redeterminations to occur around May 15^th and a decrease in proved reserves.November 14^th of each year and additional redeterminations that may be requested at the discretion of either the lenders or the Company.  The borrowing base could be further reduced in the future as a result of the continued impact of lowlower commodity prices, our lenders’ outlook for future prices or our inability to replace reserves as a result of constrained capital spending.  To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base,base; such excess or deficiency(referred to as a “Borrowing Base Deficiency”) is required to be repaid within 90150 days in threefive equal monthly payments.  In addition to the borrowing base limitation, the Credit Agreement limits our ability to incur additional indebtedness if we cannot comply with specified baskets, financial covenants andor ratios.

We may not have the financial resources in the future to repay an excess or deficiencya Borrowing Base Deficiency resulting from a borrowing base redetermination as required under our Credit Agreement, which could result in an event of default.  Additionally, a material reduction of our current cash position could substantially limit our ability to comply with other cash needs, such as collateral needs for existing or additional supplemental surety bonds or other financial assurances issued to the BOEM for our decommissioning obligations.  Further, the failure to repay an excess or deficiencya Borrowing Base Deficiency that may result from a borrowing base redetermination under our Credit Agreement may result in a cross-default under our other debt agreements.agreement.  If crude oil, NGLs and natural gas prices fall back to the levels experienced in 2016, this would adversely affect our cash flow, which could result in further reductions in our borrowing base, adversely affect prospects for alternative credit availability or affect our ability to satisfy our covenants and ratios under our Credit Agreement.

The Credit Agreement matures on November 8, 2018 and our lenders have indicated that they are unwilling to extend the Credit Agreement given the current maturities of our other debt instruments, including the potential maturity acceleration of two of our debt instruments to February 28, 2019.  We may not be able to execute our plans to address this issue, which would cause us to operate without a revolving bank credit facility.

We may be unable to provide the financial assurances if the BOEM submits future demands to cover our decommissioning obligations in the amounts and under the time periods required by the BOEM.  If extensions and modifications to the BOEM’s demands are needed and cannot be obtained, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases.  

The 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, the BOEM issued the NTL #2016-N01 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.  NTL #2016-N01 became effective in September 2016, but the BOEM has since extended indefinitely the start date for implementation.

In December 2016, we received the December 2016 Order totaling approximately $29.5 million for our sole liability properties.  However, following the BOEM’s action in January 2017 to extend the implementation date of NTL #2016-N01 for a period of six months, the BOEM elected to include sole liability properties as being covered under the extension and thus issued us a letter on February 21, 2017, rescinding the December 2016 Order, while the BOEM reviewed its financial assurance program.  In June 2017, the BOEM further extended the start date for the implementation of NTL #2016-N01 indefinitely beyond June 30, 2017.  This extension currently remains in effect; however, the BOEM reserved the right to re-issue sole liability orders in the future, including in the event that it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning sole liabilities.

  As of the filing date of this Form 10-K, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders or financial assurance obligations.  Following completion of its review, the BOEM may elect to retain NTL #2016-N01 in its current form or may make revisions thereto and, thus, until the review is completed and the BOEM determines what additional financial assurance may be required by us, we cannot provide assurance that such financial assurance coverage can be obtained.  Moreover, the BOEM could in the future make other demands for additional financial assurances covering our obligations under sole liability properties and/or our non-sole liability properties.  The BOEM may reject our proposals and make demands that exceed the Company’s capabilities.  

If we fail to comply with the current or future orders of the BOEM to provide additional surety bonds or other financial assurances, the 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.

We may be required to post cash collateral pursuant to our agreements with sureties under our existing bonding arrangements, which could have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan, our ARO plan and comply with our existing debt instruments.

Pursuant to the terms of our agreements with various sureties under our existing bonding arrangements or under any additional bonding arrangements we may enter into, we may be required to post collateral at any time, on demand, at the surety’s discretion.  We have received such demands and have provided collateral to a couple of our existing sureties.  If additional collateral is required to support surety bond obligations, this collateral would probably be in the form of cash or letters of credit.  Given current commodity prices’ effect on our creditworthiness and the willingness of the surety to post bonds without the requisite collateral, we cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for additional bonds.

If we are required to provide collateral, our liquidity position will be negatively impacted and may require us to seek alternative financing.  To the extent we are unable to secure adequate financing; we may be forced to reduce our capital expenditures in the current year and/or future years.  In addition, a reduction in our liquidity may impair our ability to comply with the financial and other restrictive covenants in our indebtedness.  Moreover, if we default on our Credit Agreement, then we would need a waiver or amendment from our bank lenders to prevent the acceleration of the outstanding debt under our Credit Agreement.  There is no assurance that the bank lenders will waive or amend the Credit Agreement.  Realization of any of these factors could have a material adverse effect on our financial condition, results of operations and cash flows.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 in this Form 10-K for additional information.  

We have a significant amount of indebtedness.indebtedness and limited borrowing capacity under our Credit Agreement.  Our leverage and debt service obligations may have a material adverse effect on our financial condition, results of operations and business prospects, and we may have difficulty paying our debts as they become due.

As of December 31, 2017,2019, we had $889.8$730.0 million principal amount of indebtedness outstanding, all of which consistswas secured, and additionally had $5.8 million of $189.8letters of credit obligations outstanding.  Our borrowing availability under our Credit Agreement was $139.2 million principal amountas of unsecured indebtednessDecember 31, 2019, as we had $105.0 million in borrowings in addition to the letters of credit obligations outstanding.  Our leverage and $700.0 million principal amount of secured indebtedness.  Our current availability on our revolving bank credit facility is the full borrowing base of $150.0 million.  We did not incur any borrowings on our revolving bank credit facility during 2017.  For example, our leveragedebt service obligations could:

Any of the above listed factors could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Our ability to pay our expenses and fund our working capital needs and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors.  We will not be able to control many of these factors, such as commodity prices, other economic conditions and governmental regulation.  Substantially all of our oil, NGLs and natural gas properties are pledged as collateral under our Credit Agreement and are also pledged as collateral on a subordinate basis under certain other debt agreements.  Sustained or lowerthe Indenture of the Senior Second Lien Notes (the “Indenture”) dated as of October 18, 2018, entered into by and among the Company, the Guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”).  Lower crude oil, NGLs and natural gas prices in the future will continue towould adversely affect our cash flow and could result in further reductions in our borrowing base, reduce prospects for alternate credit availability, and affect our ability to satisfy the covenants and ratios under our Credit Agreement.  Further assetAsset sales may also reduce available collateral and availability under our Credit Agreement.  In addition, we cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations.

If we are unable to service our indebtedness and other obligations, we may be required to further restructure or refinance all or part of our existing debt, sell assets, reduce capital expenditures, borrow more money or raise equity.  WeHowever, we may not be able to further restructure or refinance our debt, reduce capital expenditures, sell assets, borrow more money or raise equityaccomplish any of these transactions on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness.  In addition, our ability to comply with the financial and other restrictive covenants in our debt instruments is uncertain and will be affected by our future performance and events or circumstances beyond our control.  Failure to comply with these covenants would result in an event of default under such indebtedness, the potential acceleration of our obligation to repay outstanding debt and the potential foreclosure on the collateral securing such debt, and could cause a cross-default under our other outstanding indebtedness.  Any of the above risks could have a material adverse effect on our business, financial condition, cash flows and results of operations and could lead to a restructuring.operations.

We may be able to incur substantially more debt. This could exacerbate the risks associated with our indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to the terms of our debt agreements. As of December 31, 2017,2019, we had $700.0$730.0 million principal amount of secured indebtedness outstanding and $189.8 million principal amount of unsecured indebtedness outstanding (which does not include amounts recorded in the carrying value of certain debt instruments for future payment-in-kind (“PIK”) and cash interest payments).indebtedness. The components of our indebtedness are:

If new debt is added to our current debt levels, the related risks that we face could intensify.  As of December 31, 2017, the various debt agreements allowed for approximately $200 million of second lien debt and approximately $400 million of third lien debt.  Our level of indebtedness may prevent us from engaging in certain transactions that might otherwise be beneficial to us by limiting our ability to obtain additional financing, limiting our flexibility in operating our business or otherwise.  In addition, we could be at a competitive disadvantage against other less leveraged competitors that have more cash flow to devote to their business.

Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions.

The indentures and credit agreements governing our indebtedness contain a number of significant restrictive covenants in addition to covenants restricting the incurrence of additional debt.  These covenants limit our ability and the ability of our restricted subsidiaries, among other things, to:

Our revolving bank credit facilityCredit Agreement requires us, among other things, to maintain certain financial ratios and satisfy certain financial condition tests or reduce our debt.  These restrictions may also limit our ability to obtain future financings, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities.  We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us from the restrictive covenants under our indentures governing our other debt instruments.outstanding notes.

A breach of any covenant in the agreements governing our debt would result in a default under such agreement after any applicable grace periods.  A default, if not waived, could result in acceleration of the debt outstanding under such agreement and in a default with respect to, and acceleration of, the debt outstanding under any other debt agreements.  The accelerated debt would become immediately due and payable.  If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance such accelerated debt.  Even if new financing were then available, it may not be on terms that are acceptable to us.

A significant amount of our indebtedness will accelerate if we are not able to extend, renew, refund, defease, discharge, replace or refinance our Unsecured Senior Notes by certain dates under various debt agreements, which would adversely impact our liquidity. 

The maturity of the Third Lien PIK Toggle Notes and the 1.5 Lien Term Loan will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes are not extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  The Unsecured Senior Notes mature on June 15, 2019 with a principal balance of $189.8 million.  Assuming the PIK option is fully utilized for the Third Lien PIK Toggle Notes, the principal balance would be approximately $164.5 million as of February 28, 2019.  For the 1.5 Lien Term Loan, no PIK option is available and the principal of $75.0 million would be unchanged as of February 28, 2019.  Thus, a total of $239.5 million may become due on February 28, 2019.

In addition, the lenders under our Credit Agreement, which matures on November 8, 2018, have indicated that they are unwilling to extend the Credit Agreement, and other lenders may be unwilling to extend a replacement revolving credit facility, unless and until the potential maturity acceleration of our Third Lien PIK Toggle Notes and the 1.5 Lien Term Loan to February 28, 2019 is addressed.  Each of our Second Lien Term Loan and Second Lien PIK Toggle Notes require us to offer to repay or repurchase the Second Lien Term Loan and Second Lien PIK Toggle Notes, as applicable, at par plus accrued and unpaid interest if, by May 16, 2019, the aggregate outstanding principal amount of Unsecured Senior Notes that have not been repurchased, redeemed, discharged, defeased or called for redemption exceeds $50.0 million.  

We may not be able to execute on various financing alternatives under consideration to address these maturity issues, which include having sufficient available cash or net proceeds from replacement financings to redeem the Unsecured Senior Notes, which are currently callable at par, and the 1.5 Lien Term Loan, which is callable after September 7, 2018 at 102.75% of par.  In addition, certain amendments under the 1.5 Lien Term Loan and the Credit Agreement will likely be required in the event replacement financing is not utilized.  We may not have available funds to make these payments, which may cause us to be in default if we are unable to refinance the Unsecured Senior Notes before February 28, 2019.  A default, if not waived, could result in acceleration of the debt outstanding under such agreement and in a default with respect to, and acceleration of, the debt outstanding under any other debt agreements.  The accelerated debt would become immediately due and payable.  If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance such accelerated debt.  Even if new financing were then available, it may be on less favorable terms or on terms that are not acceptable to us.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 in this Form 10-K for additional information.  

We may be unable to access the equity or debt capital markets to meet our obligations.

Sustained or lower

Lower crude oil, NGLs and natural gas prices will adversely affect our cash flow and may lead to further reductions in the borrowing base, which could also lead to reduced prospects for alternate credit availability.  The capital markets we have historically accessed as an alternative source of equity and debt capital are currently verymay be constrained.  Other capital sources may arise with significantly different terms and conditions. Certain investors may exclude oil and gas companies from their investing portfolios due to environmental, social and governance factors.  These limitations in the capital markets may affect our ability to grow and limit our ability to replace our reserves of oil and gas.

Our plans for growth may include accessing the equity and debt capital markets.  If those markets are unavailable, or if we are unable to access alternative means of financing on acceptable terms, we may be unable to implement all of our drilling and development plans, make acquisitions or otherwise carry out our business strategy, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

If we default on our secured debt, the value of the collateral securing our secured debt may not be sufficient to ensure repayment of all of such debt.

As of December 31, 2017,2019, we had $700.0$730.0 million principal amount of secured indebtedness outstanding, (which does not include amounts recorded in the carrying value of certain debt instruments for PIK and cash interest payments).outstanding.  If in the future we default on one or more issues or tranchesany of our secured debt, we cannot assure youprovide assurance that the proceeds from the sale of the collateral will be sufficient to repay all of our secured debt in full.  In addition, we have certain rights to issue or incur additional secured debt, including up to $149.7$139.2 million as of December 31, 2017,2019, available for borrowing onunder our revolving bank credit facility,Credit Agreement, that would be secured by additional liens on the collateral and an issuance or incurrence of such additional secured debt would dilute the value of the collateral securing our outstanding secured debt.  If the proceeds of any sale of the collateral are not sufficient to repay all amounts due in respect of our secured debt, then claims against our remaining assets to repay any amounts still outstanding under our secured obligations would be unsecured and our ability to pay our other unsecured obligations and any distributions in respect of our capital stock would be significantly impaired.

The collateral securing the various issues of our secured debt has not been appraised.  The value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the collateral.  The value of the assets pledged as collateral for our secured debt could be impaired in the future as a result of changing economic conditions, commodity prices, competition or other future trends.  Likewise, we cannot assure youprovide assurance that the pledged assets will be saleable or, if saleable, that there will not be substantial delays in their liquidation.

In addition, to the extent that third parties hold prior liens, such third parties may have rights and remedies with respect to the property subject to such liens that, if exercised, could adversely affect the value of the collateral securing our secured debt.

With respect to some of the collateral securing our secured debt, any collateral trustee’s security interest and ability to foreclose on the collateral will also be limited by the need to meet certain requirements, such as obtaining third party consents, paying court fees that may be based on the principal amount of the parity lien obligations and making additional filings.  If we are unable to obtain these consents, pay such fees or make these filings, the security interests may be invalid and the applicable holders and lenders will not be entitled to the collateral or any recovery with respect thereto.  We cannot assure youprovide assurance that any such required consents, fee payments or filings can be obtained on a timely basis or at all.  These requirements may limit the number of potential bidders for certain collateral in any foreclosure and may delay any sale, either of which events may have an adverse effect on the sale price of the collateral.  Therefore, the practical aspect of realizing value from the collateral may, without the appropriate consents, fees and filings, be limited.

We may be unable to provide the financial assurancesin the amounts and under the time periods required by the BOEM if the BOEM submits future demands to cover our decommissioning obligations.  If in the future the BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases.

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS.  As of the filing date of this Form 10-K, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders, requests or financial assurance obligations.  The BOEM, however, could in the future make demands for additional financial assurances covering our obligations under our properties, which could exceed the Company’s capabilities to provide.  If the BOEM issues future orders to provide additional surety bonds or other additional financial assurances to cover these obligations and we fail to comply with such future orders, the 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.

We may be required to post cash collateral pursuant to our agreements with sureties under our existing or future bonding arrangements, which could have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan, our ARO plan and comply with our existing debt instruments.

Pursuant to the terms of our agreements with various sureties under our existing bonding arrangements, including the arrangements entered into in connection with our acquisition of the Mobile Bay Properties, or under any future bonding arrangements we may enter into, we may be required to post collateral at any time, on demand, at the surety’s sole discretion.  If additional collateral is required to support surety bond obligations, this collateral would probably be in the form of cash or letters of credit.  We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for future bonds.

If we are required to provide additional collateral, our liquidity position will 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 in the current year or future years, may be unable to execute our ARO plan or may be unable to comply with our existing debt instruments.   See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 in this Form 10-K for additional information.

If crude oil, NGLs and natural gas prices decrease from their current levels, we may be required to further write down the carrying values and/or the estimates of total reserves of our oil and natural gas properties.

Accounting rules applicable to us require that we review the carrying value of our oil and natural gas properties quarterly for possible impairment.  Impairment of proved properties under our full cost oil and gas accounting method is largely driven by the present value of future net revenues of proved reserves estimated using the SEC mandated 12-month unweighted first-day-of-the-month commodity prices.  In addition to commodity prices, impairment assessments of proved properties include the evaluation of development plans, production data, economics and other factors.  As crude oil, NGLs and natural gas prices declined in 2015, we incurred impairment charges in each quarter in 2015 totaling $987.2 million for the year.  Such write-downs associated with impairments would constitute a non-cash charge to earnings.  As prices fell further duringWe experienced impairment write-downs of our oil and gas properties in 2016 we incurred impairment charges in the first three quartersand 2015 primarily as a result of 2016 which totaled $279.1 million.  Weoil and natural gas price declines, but did not incur any such write-downs during 2019, 2018 or 2017.  If prices fall significantly below 2016current levels, this may cause write-downs during 20182020 or in future periods.  In addition, lower crude oil, NGLs and natural gas prices may reduce our estimates of the proved reserve volumes that may be economically recovered, which would reduce the total value of our proved reserves.

No assurance can be given that we will not experience additional ceiling test impairments in future periods, which could have a material adverse effect on our results of operations in the periods taken.  Also, no assurance can be given that commodity price decreases will not affect our reserve volumes.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview and Critical Accounting Policies – Impairment of oil and natural gas properties under Part II, Item 7 and Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K for additional information on the ceiling test.

We may be limited in our ability to maintain or recognize additional proved undeveloped reserves under current SEC guidance.

Current SEC guidance requires that proved undeveloped reserves (“PUDs”) may only be classified as such if a development plan has been adopted indicating that they are reasonably certain to be drilled within five years of the date of booking.  This rule may limit our potential to book additional PUDs as we pursue our drilling program.  If current prices decline, we also may be compelled to postpone the drilling of PUDs until prices recover.  If we postpone drilling of PUDs beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped.  In addition, if we are unable to demonstrate funding sources for our development plan with reasonable certainty, we may have to write-off all or a portion of our PUDs.

Our PUDs comprised 16%15% of our total proved reserves as of December 31, 20172019 and require additional expenditures and/or activities to convert these into producing reserves.  As circumstances change, we cannot provide assurance that all future expenditures will be made and that activities will be entirely successful in converting these reserves into proved producing reserves or PUDs during the time periods we have planned, at the costs we have budgeted, which could result in the write-off of previously recognized proved reserves.  Although weWe are the operator for substantially all the fields containingof our PUDs as of December 31, 2017, in2019.  In the past,future, however, we were not the operator for a portioncould have more of our PUDs which if this were to occur in the future,non-operated fields, which may put us in a position of not being able to control the timing of development activities.  Furthermore, there can be no assurance that all of our PUDs will ultimately be produced duringactivities for the time periods we have planned, at the costs we have budgeted, or at all, which could result in the write-off of previously recognized reserves.non-operated fields.

Relatively short production periods for our Gulf of Mexico properties based on proved reserves subject us to high reserve replacement needs and require significant capital expenditures to replace our proved reserves at a faster rate than companies whose proved reserves have longer production periods.  Our failure to replace those proved reserves would result in decreasing proved reserves, production and cash flows over time.

Unless we conduct successful development and exploration activities at sufficient levels or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced.  Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors.  High production rates generally result in recovery of a relatively higher percentage of reserves during the initial few years of production.  All of our current production is from the Gulf of Mexico.  ReservesProved reserves in the Gulf of Mexico generally decline more rapidlyhave shorter reserve lives than proved reserves in many other producing regions of the United States.States due to the difference in rules related to booking proved undeveloped reserves between conventional and unconventional basins.  Our independent petroleum consultant estimates that 50%35% of our total proved reserves will be depleted within three years.  As a result, our need to replace proved reserves and production from new investments is relatively greater than that of producers who recover lower percentages of their proved reserves over a similar time period, such as those producers who have a larger portion of their proved reserves in areas other than the Gulf of Mexico.  We may not be able to develop, find or acquire additional proved reserves in sufficient quantities to sustain our current production levels or to grow production beyond current levels.  In addition, due to the significant time requirements involved with exploration and development activities, particularly for wells in the deepwater or wells not located near existing infrastructure, actual oil and natural gas production from new wells may not occur, if at all, for a considerable period of time following the commencement of any particular project.

Significant capital expenditures are required to replace our reserves.  If we are not able to obtain new oil and gas leases or replace reserves, we will not be able to sustain production at current levels.levels, which may have a material adverse effect on our business, financial condition, or results of operations.

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable.  Unless we replace the reserves we produce through successful exploration, development or acquisition activities, our proved reserves and production will decline over time.  Our exploration, development and acquisition activities require substantial capital expenditures.  Historically, we have funded our capital expenditures and acquisitions with cash on hand, cash provided by operating activities, securities offerings and bank borrowings.  The capital markets we have historically accessed are currentlymay be constrained because of our relatively high leverage and we believe our access to capital markets remainsmay be limited at this time.  Ourin the future.  Excluding acquisitions, our capital expenditures in 20172019 were below historical levels and we continue to have a lowhigher than the amount spent in 2018.  The higher end of our capital expenditure budget range for 20182020 is substantially the same as the amount spent in order to conserve capital and target projects with a high probability of acceptable returns.2019, excluding acquisitions.  Future cash flows are subject to a number of variables, such as the level of production from existing wells, the prices of oil, NGLs and natural gas, and our success in developing and producing new reserves.  Any reductions in our capital expenditures to stay within internally generated cash flow (which could be adversely affected if commodity prices decline) and cash on hand will make replacing produceddepleted reserves more difficult.  These limitations in the capital markets and our recently constrainedcurrent capital budget may adversely affect our ability to sustain our production at 2017 levels.  We cannot be certain that financing for future capital expenditures will be available if needed, and to the extent required, on acceptable terms.  For additional financing risks, see “–Risks Relating to Our Industry, Our Business and Our Financial Condition.”

Additional deepwater drilling laws, regulations and other restrictions, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and other relatedoffshore-related developments in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

In recent years, we have expanded our drilling efforts onhave included deepwater projects in the Gulf of Mexico.  The BSEE and the BOEM have over time imposed new and more stringent permitting procedures, safety regulations and regulatory safety and performance requirementsenvironmental regulations for new wells to be drilled in the deepwater of 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 delayshave impacted the manner in which we have conducted our business in the processing andpast.  Examples of areas where these stringent regulations have affected operations include new or amended measures for obtaining approval of drilling permits, and exploration plans, development plans, oil spill-response submissions and decommissioning plansplans.  These stringent regulations, and possible additional regulatory initiatives, could result in difficult and more costly actions and adversely affect or delay new drillingincreased cost to our development efforts and ongoing development efforts.  business operations.

Moreover, the trend in the United States over the past decade has been for these governmental agencies are continuingto continue to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, are continuing tonecessary, develop and implement new, more restrictive requirements.requirements, although in recent years under the Trump Administration, there have been actions seeking to mitigate certain of those more rigorous standards.  For example, in April 2016, the BSEE under the Obama Administration published a final rule on well control that, among other things, imposesimposed rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deepwater and high temperature, high pressure drilling activities, and enhanced reporting requirements.  Also,Pursuant to certain executive orders issued by President Trump in April 2016,2017, however, the BOEM publishedBSEE initiated a proposed rule that would update existing air emissions requirements relating to offshore oil and natural gas activity on the OCS.  The BOEM regulates these air emissions in connection with its review of the well control rule and other offshore rules and initiatives to determine whether they are consistent with the stated policy of encouraging energy exploration and development plans,production, while ensuring that any such activity is safe and ROWs and 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. These rules and other potential rulemakings could further restrict offshore air emissions.

In May 2017, the Department of the Interior Secretary Ryan Zinke issued Order 3350 (“Order 3350”) directing the BSEE and the BOEM to reconsider a number of regulatory initiatives governing oil and natural gas exploration in offshore federal waters related to safety, air quality control and performance-related activities.  Examples of such regulatory initiatives being reconsidered include NTL #2016-N01 and the rules relating to blow-out preventers and well control.  Following completion of their reviews, these agencies are to provide recommendations on whether such regulatory initiatives should continue or be implemented.  Moreover, Order 3350 directed the BOEM to immediately cease all activities to promulgate the April 2016 proposed rule relating to offshore air quality control.environmentally responsible.  One consequence of this review is that in December 2017,May 2019, the BSEE published proposedfinal revisions to its regulations regarding offshore drilling safety equipment, which proposal includes the removal ofexisting 2016 rule on well control that, among other things, eliminated the requirement for offshore operatorsa BSEE-approved verification organization to certify throughoversee third parties which provide certifications of certain critical well control functions.  Another consequence of this BSEE review was an independent third partyindefinite delay in implementation of NTL #2016-N01 that, their critical safety and pollution prevention equipment (e.g., subsea safety equipment, including blowout preventers) is operational and functioning as designedif implemented, could result in significant increases in financial assurances for our operating on the OCS.  There exists the possibility that certain of these recent mitigatory actions under the Trump Administration could be withdrawn or revised in the most extreme conditions.  The December 2017 proposed rule has not been finalized and there remains substantial uncertaintyfuture as a result of litigation or by a different presidential administration to impose or re-implement more stringent standards.  Moreover, due primarily to the scopethreat of climate change arising from GHG emissions, certain candidates seeking the office of President of the United States in 2020 have pledged to take actions to ban new mineral leases on federal properties, including offshore leases on the OCS.  Additionally, litigation risks are also increasing, as a number of cities and extent of any revisionsother local governments have sought to existingbring suit against the largest oil and natural gas safetyexploration and performance-related regulationsproduction companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and other regulatory initiatives that ultimately will be adopted by the BSEEtherefore are responsible for roadway and the BOEM pursuant to those agencies’ review process.

To the extentinfrastructure damages as a result, or alleging that the BOEM andcompanies have been aware of the BSEE do not reduceadverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.

These regulatory actions, or any new rules, regulations, or legal initiatives or controls, whether under the stringency of existing oil and gas safety and performance-related regulations and other regulatory initiatives, the regulatory requirements imposed by such existingTrump Administration or future,another administration, that impose increased costs or more stringent regulations or other regulatory initiativesoperational standards could delay operations,or 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 the BOEM and BSEE could result in increased financial assurance requirementssupplemental bonding and incurrence of associated added costs and limit operational activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities.facilities or result in the suspension or cancellation of leases.  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.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

We are and could be exposed to uninsured losses in the future. We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells.  The current policy limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements.  With respect to coverage for named windstorms, we have a $150.0$162.5 million aggregate limit covering all of our higher valued properties, and a $150.0 million aggregate limit for all of our other properties, subject to a retention (deductible) of $30.0 million. Included within the $150.0$162.5 million aggregate limit is total loss only (“TLO”) coverage on our Mahogany platform, which has no retention.

The occurrence of a significant accident or other event not covered in whole or in part by our insurance could have a material adverse impact on our financial condition and operations.  Our insurance does not protect us against all operational risks.  We do not carry business interruption insurance.  In May and June 2017,2019, we entered into our insurance policies covering well control and hurricane damage (described above) and for general liability and pollution.  These policies are effective for one year from their respective execution date.  These policies reduce, but in no way totally mitigate our risk as we are exposed to amounts for retention and co-insurance, limits on coverage and events that are not insured.  Renewal of these policies at a cost commensurate with current premiums is not assured.  We also have other smaller per-occurrence retention amounts for various other events.  In addition, pollution and environmental risks are generally not fully insurable, as gradual seepage and pollution are not covered under our policies.  Because third-party drilling contractors are used to drill our wells, we may not realize the full benefit of workmen’s compensation laws in dealing with their employees.

OPA requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill.  We are currently required to demonstrate, on an annual basis, that we have ready access to $150$150.0 million that can be used to respond to an oil spill from our facilities on the OCS.  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.

For some risks, we have not obtained insurance as we believe the cost of available insurance is excessive relative to the risks presented.  We may take on further risks in the future if we believe the cost is excessive to the risks.  The occurrence of a significant event not fully insured or indemnified against losses could have a material adverse effect on our financial condition and results of operations.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Hurricane Remediation, Insurance Claimsand Insurance Coverage under Part II, Item 7 in this Form 10-K for additional information on insurance coverage.

Insurance for well control and hurricane damage may become significantly more expensive for less coverage and some losses currently covered by insurance may not be covered in the future.

In the past, hurricanes in the Gulf of Mexico have caused catastrophic losses and property damage.  Well control insurance coverage becomes limited from time to time and the cost of such coverage becomes both more costly and more volatile.  In the past, we have been able to renew our policies each annual period, but our coverage has varied depending on the premiums charged, our assessment of the risks and our ability to absorb a portion of the risks.  The insurance market may further change dramatically in the future due to hurricane damage, major oil spills or other events.

In the future, our insurers may not continue to offer what we view as reasonable coverage, or our costs may increase substantially as a result of increased premiums.  There could be an increased risk of uninsured losses that may have been previously insured.  We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurance companies will not pay our claims.  The occurrence of any or all of these possibilities could have a material adverse effect on our financial condition and results of operations.

Commodity derivative positions may limit our potential gains.

In order to manage our exposure to price risk in the marketing of our oil and natural gas, and as required under our Credit Agreement, we periodically enter into oil and natural gas price commodity derivative positions with respect to a portion of our expected production.  During the firstfourth quarter of 2017,2019, we entered into derivative contracts for natural gas, which expire in December 2022 and crude oil derivative contracts, which expire in December 2020.  During the fourth quarter of 2018, we entered into commodity derivative contracts for crude oil, which expired on or before December 31, 2017.  As of the filing date of this Form 10-K, we did not have any open commodity derivative positions.will expire in May 2020.  We may enter into more derivative contracts in the future.  While these commodity derivative positions are intended to reduce the effects of volatile crude oil and natural gas prices, they may also limit future income if crude oil and natural gas prices were to rise substantially over the price established by such positions.  In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

See Financial Statements and Supplementary Data– Note 810 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information on derivative transactions.

Competition for oil and natural gas properties and prospects is intense; some of our competitors have larger financial, technical and personnel resources that may give them an advantage in evaluating and obtaining properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil, NGLs and natural gas and securing trained personnel.  Many of our competitors have financial resources that allow them to obtain substantially greater technical expertise and personnel than we have.  We actively compete with other companies in our industry when acquiring new leases or oil and natural gas properties.  For example, new leases acquired from the BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder.  Our competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit.  Our competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay or finance.  On the acquisition opportunities made available to us, we compete with other companies in our industry for such properties through a private bidding process, direct negotiations or some combination thereof.  Our competitors may have significantly more capital resources and less expensive sources of capital.  In addition, they may be able to generate acceptable rates of return from marginal prospects due to their lower costs of capital.  If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.  The availability of properties for acquisition depends largely on the divesting practices of other oil and natural gas companies, commodity prices, general economic conditions and other factors we cannot control or influence.  Additional requirements and limitations recently imposed on us and our ability to finance such acquisitions may put us at a competitive disadvantage for acquiring properties.  These risks are described above in the risk factor entitled: We may be unable to provide the financial assurances if the BOEM submits future demands to cover our decommissioning obligations in the amounts and under the time periods required by the BOEM.  If extensions and modifications to the BOEM’s demands are needed and cannot be obtained, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases.

We conduct exploration, development and production operations on the deep shelf and in the deepwater of the Gulf of Mexico, which presents unique operating risks.

The deep shelf and the deepwater of the Gulf of Mexico are areas that have had less drilling activity due, in part, to their geological complexity, depth and higher cost to drill and ultimately develop.  There are additional risks associated with deep shelf and deepwater drilling that could result in substantial cost overruns and/or result in uneconomic projects or wells.  Deeper targets are more difficult to interpret with traditional seismic processing.  Moreover, drilling costs and the risk of mechanical failure are significantly higher because of the additional depth and adverse conditions, such as high temperature and pressure.  For example, the drilling of deepwater wells requires specific types of rigs with significantly higher day rates, as compared to the rigs used in shallower water.  Deepwater wells have greater mechanical risks because the wellhead equipment is installed on the sea floor.  Deepwater development costs can be significantly higher than development costs for wells drilled on the conventional shelf because deepwater drilling requires larger installation equipment, sophisticated sea floor production handling equipment, expensive state-of-the-art platforms and infrastructure investments.  Deep shelf development can also be more expensive than conventional shelf projects because deep shelf development requires more drilling days and higher drilling and service costs due to extreme pressure and temperatures associated with greater depths.  Accordingly, we cannot assure youprovide assurance that our oil and natural gas exploration activities in the deep shelf, the deepwater and elsewhere will be commercially successful.

Our estimates of future ARO may vary significantly from period to period and are especially significant because our operations are concentrated in the Gulf of Mexico.

We are required to record a liability for the present value of our ARO to plug and abandon inactive non-producing wells, to remove inactive or damaged platforms, and inactive or damaged facilities and equipment, collectively referred to as “idle iron,” and to restore the land or seabed at the end of oil and natural gas production operations.  TheseIn December 2018, BSEE issued an updated NTL reaffirming the obligations of offshore operators to timely decommission idle iron by means of abandonment and removal.  Pursuant to the idle iron NTL requirements, in September 2019, BSEE issued us letters, directing us to plug and abandon certain wells that the agency identified as no longer capable of production in paying quantities by specified timelines, with the earliest deadline being December 31, 2020.   In response, we are currently evaluating the list of wells proposed as idle iron by BSEE and currently anticipate that those wells determined to be idle iron will be decommissioned by the specified timelines or at times as otherwise determined by BSEE following further discussions with the agency.  While we have established AROs for well decommissioning, additional AROs, significant in amount, may be necessary to conduct plugging and abandonment of the wells designated by BSEE as idle iron but we do not expect the costs to plug and abandon these wells will have a material effect on our financial condition, results of operations or cash flows.  Nevertheless, these decommissioning activities are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths.depths, and there exists the possibility that increased liabilities beyond what we established as AROs may arise and the pace for completing these activities could be adversely affected by idle iron decommissioning activities being pursued by other offshore oil and gas lessees that may also have received similar BSEE directives, which could restrict the availability of equipment and experienced workforce necessary to accomplish this work.  Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or such requirements may be interpreted more restrictively, and asset removal technologies are constantly evolving, which may result in additional or increased costs.  As a result, we may make significant increases or decreases to our estimated ARO in future periods.  For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes.  The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform, from which the work was anticipated to be performed, is damaged or toppled rather than structurally intact.  Accordingly, our estimate of future ARO will differ dramatically from our recorded estimate if we have a damaged platform.

The additional requirements under the BOEM’s NTL #2016-N01, if ever fully implemented, would increase our operating costs and reduce the availability of surety bonds due to the increased demands for such bonds in a low-price commodity environment.  While the current implementation timeline has been extended indefinitely, except in certain circumstances where there was a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, this timeline could change at the BOEM’s discretion and the BOEM may re-issue sole liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  Under NTL #2016-N01, the BOEM has given broader interpretation authority to the BOEM’s district personnel, which increases the difficulty in complying with this NTL should it be fully implemented.  In addition, increased demand for salvage contractors and equipment could result in increased costs for decommissioning activities, including plugging and abandonment operations. These items have, and may further increase our costs and may impact our liquidity adversely.

We may be obligated to pay costs related to other companies that have filed for bankruptcy or have indicated they are unable to pay their share of costs in joint ownership arrangements.

In our contractual arrangements of joint ownership of oil and natural gas interests with other companies, we are obligated to pay our share of operating, capital and decommissioning costs, and have the right to a share of revenues after royalties and certain other cash inflows.  If one of the companies in the arrangement is unable to pay its agreed upon share of costs, generally the other companies in the arrangement are obligated to pay the non-paying company’s obligations.  Under joint operating agreements (“JOAs”) among working interest owners, the non-paying company would typically lose the right to future revenues, which would be applied to the non-paying company’s share of operating, capital and decommissioning costs.  If future revenues are insufficient to defray these additional costs, especially in cases where the well has stopped producing and is being decommissioned, we could be obligated to pay certain costs of the defaulting party.  In addition, the liability to the U.S. Government for obligations of lessees under federal oil and gas leases, including obligations for decommissioning costs, is generally joint and several among the various co-owners of the lease, which means that any single owner may be liable to the U.S. Government for the full amount of all lessees’ obligations under the lease.  In certain circumstances, we also could be liable for decommissioning liabilities on federal oil and gas leases that we previously owned and the assignee to whom we assigned the leases or any future assignee of those leases is bankrupt or unable to pay its decommissioning costs.  For example, we have in the past received a demand for payment of suchdecommissioning costs related to property interests that were sold several years prior.  These indirect obligations would affect our costs, operating profits and cash flows negatively and could be substantial.

We may not be in a position to control the timing of development efforts, associated costs or the rate of production of the reserves from our non-operated properties.

As we carry out our drilling program, we may not serve as operator of all planned wells.  In that case, we have limited ability to exercise influence over the operations of some non-operated properties and their associated costs.  Our dependence on the operator and other working interest owners and our limited ability to influence operations and associated costs of properties operated by others could prevent the realization of anticipated results in drilling or acquisition activities.  The success and timing of exploration and development activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development activities may be unsuccessful for many reasons, including adverse weather conditions, cost overruns, equipment shortages, geological issues, technical difficulties and mechanical difficulties.  Moreover, the successful drilling of a natural gas or oil well does not assure us that we will realize a profit on our investment.  A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells hinder our efforts to replace reserves.

Our oil and natural gas exploration and production activities, including well stimulation and completion activities, involve a variety of operating risks, including:

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:

Offshore operations are also subject to a variety of operating risks related to the marine environment, such as capsizing, collisions and damage or loss from tropical storms, hurricanes or other adverse weather conditions.  These conditions can cause substantial damage to facilities and interrupt production.  Companies that incur environmental liabilities frequently also confront third-party claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.  Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointlyhave strict joint and severally liableseveral liability under CERCLA or similar state statues for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

Legislation has been proposed from time to time in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes.”  A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could potentially subject such wastes to more stringent handling, disposal and cleanup requirements.  Other wastes handled at exploration and production sites or generated in the course of providing well services also may not fall within the RCRA oil and gas wastes exclusion.  Stricter standards for waste handling, disposal and cleanup may be imposed on the oil and natural gas industry in the future.  Additionally, NORM may contaminate minerals extraction and processing equipment used in the oil and natural gas industry.  We may have liability for releases of hazardous substances at our properties by prior owners, operators, other third parties, or at properties we have sold.  As a result, we could incur substantial liabilities that could reduce or eliminate funds available for exploration, development and acquisitions or result in the loss of property and equipment.

The geographic concentration of our properties in the Gulf of Mexico subjects us to an increased risk of loss of revenues or curtailment of production from factors specifically affecting the Gulf of Mexico.

The geographic concentration of our properties along the U.S. Gulf Coast and adjacent waters on and beyond the OCS means that some or all of our properties could be affected by the same event should the Gulf of Mexico experience:

Because a majority of our properties could experience the same conditions at the same time, these conditions could have a greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area.  For example, during 2019, net production of approximately 2.1 MMBoe was deferred during 2019 due to pipeline issues, maintenance and well issues.  During 2018, net production of approximately 1.6 MMBoe was deferred during 2018 due to pipeline issues, maintenance, well issues and other events; and during 2017, net production of approximately 1.7 MMBoe was deferred during 2017 due to Hurricane Nate, pipeline issues and other events.  A similar amount was deferred during 2016 due to events outside of our control.  

Properties that we acquire may not produce as projected and we may be unable to immediately identify liabilities associated with these properties or obtain protection from sellers of such properties.

Our business strategy includes growing by making acquisitions, which may include acquisitions of exploration and production companies, producing properties and undeveloped leasehold interests.  Our acquisition of oil and natural gas properties requires assessments of many factors that are inherently inexact and may be inaccurate, including the following:

Our assessment of the acquired properties will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies.  In the course of our due diligence, we have historically not physically inspected every well, platform or pipeline.  Even if we had physically inspected each of these, our inspections may not have revealed structural and environmental problems, such as pipeline corrosion, well bore issues or groundwater contamination.  We may not be able to obtain contractual indemnities from the seller for liabilities associated with such risks.  We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.

Increasing our reserve base through acquisitions has historically been an important part of our business strategy.  We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.businesses, such as our recent acquisition of the Mobile Bay Properties.  In particular, we may face significant challenges in consolidating functions and integrating procedures, personnel and operations in an effective manner.  The failure to successfully integrate such properties or businesses into our business may adversely affect our business and results of operations.  Any acquisition we make may involve numerous risks, including:

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties.  To the extent that we acquire properties substantially different from the properties in our primary operating region or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as with acquisitions within our primary operating region.  We may not be successful in addressing these risks or any other problems encountered in connection with any acquisition we may make.

Estimates of our proved reserves depend on many assumptions that may turn out to be inaccurate.  Any material inaccuracies in the estimates or underlying assumptions will materially affect the quantities of and present value of future net revenues from our proved reserves.

The process of estimating oil and natural gas reserves is complex.  It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors.  Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of our reserves at December 31, 2017.2019.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Oil and natural gas reserve quantities, under Part II, Item 7 for a discussion of the estimates and assumptions about our estimated oil and natural gas reserves information reported in Business under Part I, Item 1, Properties under Part I, Item 2 and Financial Statements and Supplementary Data – Note 2120 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K.

In order to prepare our year-end reserve estimates, our independent petroleum consultant projected our production rates and timing of development expenditures.  Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data.  The extent, quality and reliability of this data can vary and may not be under our control.  The process also requires economic assumptions about matters such as crude oil and natural gas prices, operating expenses, capital expenditures, taxes and availability of funds.  Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates.  Any significant variance could materially affect the estimated quantities and present value of our reserves.  In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our proved oil and natural gas reserves is the current market value of our estimated oil and natural gas reserves.  In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month unweighted first-day-of-the-month average price for each product and costs in effect on the date of the estimate.  Actual future prices and costs may differ materially from those used in the present value estimate.

Prospects that we decide to drill may not yield oil or natural gas in commercial quantities or quantities sufficient to meet our targeted raterates of return.

A prospect is an area in which we own an interest, could acquire an interest or have operating rights, and have what our geoscientists believe, based on available seismic and geological information, to be indications of economic accumulations of oil or natural gas.  Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial seismic data processing and interpretation.  There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable.  The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities.  We cannot assure that the analysis we perform using data from other wells, more fully explored prospects and/or producing fields will accurately predict the characteristics and potential reserves associated with our drilling prospects.  Sustained low crude oil, NGLs and natural gas pricing will also significantly impact the projected rates of return of our projects without the assurance of significant reductions in costs of drilling and development.  To the extent we drill additional wells in the deepwater and/or on the deep shelf, our drilling activities could become more expensive.  In addition, the geological complexity of deepwater and deep shelf formations may make it more difficult for us to sustain our historical rates of drilling success. As a result, we can offer no assurance that we will find commercial quantities of oil and natural gas and, therefore, we can offer no assurance that we will achieve positive rates of return on our investments.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production.  The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities.  Our ability to market our production depends substantially on the availability and capacity of gathering systems, pipelines and processing facilities, which in most cases are owned and operated by third parties.  Our failure to obtain such services on acceptable terms could materially harm our business.  We may be required to shut in wells because of a reduction in demand for our production or because of inadequacy or unavailability of pipelines or gathering system capacity.  If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.  We have, in the past, been required to shut in wells when hurricanes have caused or threatened damage to pipelines and gathering stations.  For example, in September 2008, as a result of Hurricane Ike, two of our operated platforms and eight non-operated platforms were toppled and a number of platforms, third-party pipelines and processing facilities upon which we depend to deliver our production to the marketplace were damaged.  In 2012, under threat of Hurricane Isaac, we shut in most of our offshore production for a period of 10 to 25 days.  Similar shut-ins of lower magnitude occurred in 2013 from Tropical Storm Karen and inwells during 2017 from Hurricane Nate.Nate and in 2018 from Hurricane Michael for several days.

In some cases, our wells are tied back to platforms owned by third-parties who do not have an economic interest in our wells and we cannot be assured that such parties will continue to process our oil and natural gas.

Currently, a portion of our oil and natural gas is processed for sale on platforms owned by third-parties with no economic interest in our wells and no other processing facilities would be available to process such oil and natural gas without significant investment by us.  In addition, third-party platforms could be damaged or destroyed by hurricanes which could reduce or eliminate our ability to market our production.  As of December 31, 2017, 10 2019, six fields, accounting for approximately 0.80.9 MMBoe (or 6%6.2%) of our 20172019 production, are tied back to separate, third-party owned platforms.  There can be no assurance that the owners of such platforms will continue to process our oil and natural gas production.  If any of these platform operators ceases to operate their processing equipment, we may be required to shut in the associated wells, construct additional facilities or assume additional liability to re-establishreestablish production.

If third-party pipelines connected to our facilities become partially or fully unavailable to transport our crude oil and natural gas or if the prices charged by these third-party pipelines increase, our revenues or costs could be adversely affected.

We depend upon third-party pipelines that provide delivery options from our facilities.  Because we do not own or operate these pipelines, their continued operation is not within our control.  These pipelines may become unavailable for a number of reasons, including testing, maintenance, capacity constraints, accidents, government regulation, weather-related events or other third-party actions.  If any of these third-party pipelines become partially or fully unavailable to transport crude oil and natural gas, or if the gas quality specification for the natural gas pipelines changes so as to restrict our ability to transport natural gas on those pipelines, our revenues could be adversely affected.  For example, in 2017,2019 and 2018, various pipelines were shut down at various times causing production deferral of approximatelyapproximately 0.5 MMBoe and 0.4 MMBoe.MMBoe, respectively.

Certain third-party pipelines have submitted or have made plans to submit requests in the past to increase the fees they charge us to use these pipelines.  These increased fees, if approved, could adversely impact our revenues or increase our operating costs, either of which would adversely impact our operating profits, cash flows and reserves.

We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration, development, production and transportation of crude oil and natural gas and operational safety.  Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with such legal requirements may harm our business, results of operations and financial condition.  We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as:

Under these laws and regulations, we could be liable for:

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions.  We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.  It is also possible that a portion of our oil and natural gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated.  See Business – Regulation under Part I, Item 1 in this Form 10-K for a more detailed explanation of regulations impacting our business.

Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to MPAs and endangered species laws and regulations.threatened species.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection.  These laws and regulations:

Failure to comply with these laws and regulations may result in:

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition.  Under these environmental laws and regulations, we could be held strictly liableincur strict joint and several liability for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and regardless of whether our operations met previous standards in the industry at the time they were conducted.  Our permits require that we report any incidents that cause or could cause environmental damages.

Future environmental

New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement could significantly increase our capital expenditures and operating costs or could result in delays, tolimitations or limitations oncancelations to our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows.  See Business – Environmental Regulations under Part I, Item 1 in this Form 10-K for a more detailed description of our environmental, marine species, and endangered and threatened species regulations.

The ONNR’sONRR’s revised interpretations on determining appropriate allowances related to transportation and processing costs for natural gas could cause us to pay substantial amounts in back royalties and in future royalties.

The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federalfederal oil and gas leases.  The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant for which we had gas processed.  In the second quarter of 2015, pursuant to the initiative, the Company received requests from the ONRR for additional data regarding the Company’s transportation and processing allowances on natural gas production that was processed through a specific processing plant.  The Company also received a preliminary determination notice from the ONRR asserting its preliminary determination that the Company’s allocation of certain processing costs and plant fuel use at another processing plant were impermissibly allowed as deductions in the determination of royalties owed under Federalfederal oil and gas leases.  The Company has submitted responses covering certain plants and certain time periods and has not yet received responses as to the preliminary determination asserting the reasonableness of its revised allocation methodology of such costs.  These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under the Company’s Federal oil and gas leases for current and prior periods.  Through December 31, 2017,2019, we paid $2.1$3.1 million of additional royalties and expect to pay more in the future.  We are not able to determine the range of any additional royalties or if such amounts would be material.

Should we fail to comply with all applicable FERC, CFTC and FTC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1.2 million per day for each violation and disgorgement of profits associated with any violation.  While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements.  We also must comply with the anti-market manipulation rules enforced by FERC.  Under the Commodity Exchange Act and regulations promulgated thereunder by the CFTC and under the Energy Independence and Security Act of 2007 and regulations promulgated thereunder by the FERC, the CFTC and FTC have adopted anti-market manipulation rules relating to the prices or futures of commodities.  Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, the FERC, the CFTC or the FTC from time to time.  Failure to comply with those regulations in the future could subject us to civil penalty liability.  See Business – Regulation under Part I, Item 1 in this Form 10-K for further description of our regulations.

Climate change legislation or regulations restricting emissions of GHG

Our operations are subject to various risks that could result in increasedincreasing operating costs, limiting the areas in which oil and reducednatural gas production may occur, and reducing demand for the oil and natural gas that we produce.

Climate change continues to attract considerable public, governmental and scientific attention.  As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHG.  These efforts have included consideration of cap-and-trade programs, carbon taxes, greenhouse gasGHG reporting and tracking programs, and regulations that directly limit greenhouse gasGHG emissions from certain sources.  At the federal level, the U.S. Congress has from time to time considered climate change legislation but no comprehensive climate change legislation has been implemented.adopted.  The EPA, however, has adopted regulations under the existing CAA to restrict emissions of GHG.  For example, the EPA imposes preconstruction and operating permit requirements on certain large stationary sources that are already potential sources of certain other significant pollutant emissions.  The EPA also adopted rules requiring the monitoring and reporting of greenhouse gasGHG emissions on an annual basis from specified large greenhouse gasGHG emission sources in the United States, including onshore and offshore oil and natural gas production facilities.  Federal agencies have also begun directly regulating emissions of methane, a greenhouse gas,GHG, from oil and natural gas operations as described above.  Compliance with these rules could result in increased compliance costs on our operations.

In addition,

State implementation of these revised air emission standards could result in stricter permitting requirements, delay, limit or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.  At the international level, there exists the United States Congress has from time to time considered adopting legislation to reduce emissions of GHG andNations-sponsored “Paris Agreement,” which is a number of states and grouping of states have already taken legal measures to reduce emissions of GHG primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.  Most of these cap and trade programs work by requiring major sources of emissions, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances.  The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. On an international level, the United States is one of numerous nations that prepared an international climate changenon-binding agreement in Paris, France in December 2015, requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020.  This “Paris Agreement” was signed by the United States in April 2016 and became effective in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions but does include pledges to voluntarily limit or reduce future emissions.  In August 2017, the U.S. State Department officially informedthrough individually determined reduction goals every five years after 2020, although the United NationsStates has announced its withdrawal from such agreement, effective November 4, 2020.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in federal political risks in the United States in the form of pledges made by certain candidates seeking the office of the intentPresident of the United States in 2020.  Critical declarations made by one or more presidential candidates include proposals to withdrawban hydraulic fracturing of oil and natural gas wells and ban new leases for production of minerals on federal properties, including onshore lands and offshore waters.  Other actions to oil and natural gas production activities that could be pursued by presidential candidates may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquefied natural gas export facilities, as well as the rescission of the United States’ withdrawal from the Paris Agreement. TheAgreement in November 2020.  Litigation risks are also increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors.  Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies.  Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, providesand foreign citizenry concerned about climate change not to provide funding for a four-year exit process beginning when it took effectfossil fuel producers.  Limitation of investments in November 2016, which wouldand financings for fossil fuel energy companies could result in an effective exit datethe restriction, delay or cancellation of November 2020. The United States’ adherence to the exit process and/drilling programs or the terms on which the United States may re-enter the Paris Agreementdevelopment or a separately negotiated agreement are unclear at this time.production activities.

The adoption of legislation or regulatory programs to reduce or eliminate future emissions of GHG could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements.  Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce.  Consequently, legislation and regulatory programs to reduce or eliminate future emissions of GHG could have an adverse effect on our business, financial condition and results of operations.  Additionally, with concerns over GHG emissions, certain non-governmental activists have recently directed their efforts at shifting funding away from companies with energy-related assets, which couldpolitical, financial and litigation risks may result in limitationsour restricting or restrictions on certain sourcescanceling production activities, incurring liability for infrastructure damages as a result of funding forclimatic changes, or impairing the energy sector.ability to continue to operate in an economic manner.  Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events.  Our offshore operations are particularly at risk from severe climatic events.  If any such climate effects were to occur, they could have an adverse effect on our business, financial condition and results of operations.  See – Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses. – under this Item 1A.

Derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, among other things, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.  The Commodity Futures Trading Commission (the “CFTC”)CFTC has finalized certainmost of its regulations under the Dodd-Frank Act, but others remain to be finalized or implemented.  It is not possible at this time to predict when this will be accomplished or whatwith certainty the termsfull effects of the finalDodd-Frank Act and CFTC rules will be, soor the impacttiming of those rules is uncertain at this time.such effects.

The CFTC has designated certain types of swaps (thus far, only certain interest rate swaps and credit default swaps) for mandatory clearing and exchange trading, and may designate other types of swaps for mandatory clearing and exchange trading in the future.  To the extent we engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply with or to take steps to qualify for an exemption to such requirements.  Although we are availing ourselves of the end-user exception to the mandatory clearing and exchange trading requirements for swaps designed to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.  If any of our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or execute them on a derivatives contract or swap facility market.

In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps.  Although we expect to qualify for the end-user exception from margin requirements for swaps to other market participants, such as swap dealers, these rules may change the cost and availability of the swaps we use for hedging.  If any of our swaps do not qualify for the commercial end-user exception, we could be required to post initial or variation margin, which would impact our liquidity and reduce our cash. This would in turn reduce our ability to execute hedges to reduce risk and protect cash flows.

The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing commodity price contracts.  If we reduce our use of commodity price contracts as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and make cash distributions to our unitholders.  Further, to the extent our revenues are unhedged, they could be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices.

Our operations could be adversely impacted by security breaches, including cyber-security breaches, which could affect our production of oil and natural gas or could affect other parts of our business.

We rely on our information technology infrastructure and management information systems to operate and record aspects of our business.  Although we take measures to protect against cybersecurity risks, including unauthorized access to our confidential and proprietary information, our security measures may not be able to detect or prevent every attempted breach.  Similar to other companies, we have experienced cyber-attacks, although we have not suffered any material losses related to such attacks.  Security breaches include, among other things, illegal hacking, computer viruses, or acts of vandalism or terrorism.  A breach could result in an interruption in our operations, malfunction of our platform control devices, disabling of our communication links, unauthorized publication of our confidential business or proprietary information, unauthorized release of customer or employee data, violation of privacy or other laws and exposure to litigation. Any of these security breaches could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

The loss of members of our senior management could adversely affect us.

To a large extent, we depend on the services of our senior management.  The loss of the services of any of our senior management, including Tracy W. Krohn, our Founder, Chairman of the Board, Chief Executive Officer and President; John D. Gibbons,Janet Yang, our SeniorExecutive Vice President and Chief Financial Officer; Thomas P. Murphy,William J. Williford, our SeniorExecutive Vice President and Chief Operations Officer; andGeneral Manager of Gulf of Mexico; Stephen L. Schroeder, our Senior Vice President and Chief Technical Officer,Officer; and Shahid A. Ghauri, our Vice President, General Counsel and Corporate Secretary, could have a negative impact on our operations.  We do not maintain or plan to obtain for the benefit of the Company any insurance against the loss of any of these individuals.  See Executive Officers of the Registrant under Part I following Item 3 in this Form 10-K for more information regarding our senior management team.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

In past years, legislation was proposed that would have made significant changes to U.S. tax laws, including certain U.S. federal income tax provisions currently available to oil and gas companies.  Such legislative proposals have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures.  Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation.  The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available to us, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

The Tax Cuts and Jobs Act (“TCJA”) of 2017 modified certain U.S. Federal income tax provisions available to corporations.  Along with lowering the corporate income tax rate, the TCJA changed certain income tax rules and deductions including cost recovery, limits on the deductions of interest expense, the elimination of the deduction from domestic production activities and utilization of net operating losses.  These changes will have an impact on our taxation and generally take effect for tax years beginning after 2017.  The TCJA did not (i) repeal the percentage depletion allowance for oil and gas properties, (ii)  eliminate current deductions for intangible drilling and development costs, or (iii) extend the amortization period for certain geological and geophysical expenditures.    

Counterparty credit risk may negatively impact the conversion of our accounts receivables to cash.

Substantially all of our accounts receivable result from crude oil, NGLs and natural gas sales or joint interest billings to third parties in the energy industry.  This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by any adverse changes in economic or other conditions.  In recent years, market conditions resulted in downgrades to credit ratings of some of our oil and gas customers and joint interest partners.  While we have not experienced collection issues from our customers, we have experienced collection issues from several of our joint interest partners.

IItemtem 1B. Unresolved Staff Comments

None.

IItemtem 2. Properties

 Our producing fields are located in federal and state waters in the Gulf of Mexico in water depths ranging from less than 10 feet up to 7,300 feet.  The reservoirs in our offshore fields are generally characterized as having high porosity and permeability, with high initial production rates.  The following map provides the locations of our 10 largest fields as of December 31, 2017, based on quantities of proved reserves on an energy equivalent basis.rates relative to other domestic reservoirs.  At December 31, 2017, these fields2019, the following two areas of operations accounted for approximately 80% of67% our proved reserves.

The following table provides information for our 10 largest fieldsreserves determined using quantities of proved net reserves on an energy equivalent basis as of December 31, 2017.  Deepwaterbasis.  “Shelf” refers to acreage in overunder 500 feet of water.  The following table provides information for these fields:

On December 31, 2019, we had two areas of operations of major significance, which we define as having year-end proved reserves of 10% or more of the Company’s total proved reserves, calculated on an energy equivalent basis.  These areas are the Mobile Bay Properties, which are offshore Alabama but also include the associated gas treatment plant located onshore in severalAlabama, and the Ship Shoal 349 field (Mahogany) located on the conventional shelf in the Gulf of our offshore fields are owned by our wholly-owned subsidiary, W & T Energy VI, LLC.Mexico.  Unless indicated otherwise, “drilling” or “drilled” in the field descriptions below refers to when the drilling reached target depth, as this measurement usually has a higher correlation to changes in proved reserves compared to using the SEC’s definition for completion:

Volume measurements:

Our Fields

On December 31, 2017, we had two fields of major individual significance (which we define as having year-end proved reserves of 15% or more of the Company’s total proved reserves, calculated on an energy equivalent basis): the Ship Shoal 349 field (Mahogany) located on the conventional shelf in the Gulf of Mexico and the Fairway Field, located in the Mobile Bay area of Alabama, which includes the associated Yellowhammer gas processing plant located onshore in Alabama.completion.  Following are descriptions of these fields.areas of operations: 

Mobile Bay Properties

The recently acquired Mobile Bay Properties consist of interests located off the coast of Alabama, in state coastal and federal Gulf of Mexico waters approximately 70 miles south of Mobile, Alabama.  The field area includes 16 Alabama state water lease blocks and four Federal OCS lease blocks.  These properties include seven major platforms and 27 flowing wells, in up to 50 feet of water.  Exxon first discovered Norphlet gas play in 1978 with the first gas production from the Mary Ann Field in 1988.  We acquired varied operated working interests ranging from 25% to 100% in nine producing fields from Exxon effective January 1, 2019, and we became the operator of the fields in December 2019.  Cumulative field production through 2019 is approximately 576.6 MMBoe gross.  The Mobile Bay Properties produce from the Jurassic age Norphlet eolian sandstone at an average depth of 21,000’ total vertical depth.  As of December 31, 2019, 56 Norphlet wells have been drilled on the Mobile Bay Properties, 45 wells were successful and 27 wells are currently producing.  

We acquired the Mobile Bay Properties at the end of August 2019 and included the results of operations effective September 1, 2019 within our Consolidated Results of Operations.  During September 2019 to December 2019, transitioning activities occurred to transfer operatorship of the Mobile Bay Properties from Exxon to W&T.  Given the limited history and the change in operatorship, production volumes, realized prices received and production costs are omitted.

Ship Shoal 349 Field (Mahogany).

Ship Shoal 349 field is located off the coast of Louisiana, approximately 235 miles southeast of New Orleans, Louisiana.  The field area covers Ship Shoal federal OCS blocks 349 and 359, with a single production platform on Ship Shoal block 349 in 375 feet of water. Phillips Petroleum Company discovered the field in 1993.  We initially acquired a 25% working interest in the field from BP Amoco in 1999.  In 2003, we acquired an additional 34% working interest through a transaction with ConocoPhillips that increased our working interest to approximately 59%, and we became the operator of the field in December 2004.  In early 2008, we acquired the remaining working interest from Apache Corporation (“Apache”) and we now own a 100% working interest in this field.field except for an interest in one well owned in the Joint Venture Drilling Program.  Cumulative field production through 20172019 is approximately 46.4approximately 53.2 MMBoe gross.  This field is a sub-salt development with nine productive horizons below salt at depths up to 18,000 feet.  As of December 31, 2017, 282019, 31 wells have been drilled and 2326 were successful.  Since acquiring an interest and subsequently taking over as operator, we have directly participated in drilling 1417 wells with a 100% success rate.  During 2017,2018, one well was completed which had been drilled to target depth during 2016.  Three additional2017, and in addition, two wells were drilled and completed during 2017, two of which2018.  During 2019, one well was drilled, completed and producing in 2019, and significant workover activities were completed in 2017 with the third expecteddone to be completed in the first half of 2018. All of the wells drilled under a plan developed in 2010 have been successful.  Total proved reserves associated with our interest in this field were 21.6 MMBoe at December 31, 2017, 19.8 MMBoe at December 31, 2016 and 22.3 MMBoe at December 31, 2015.increase production.

The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Ship Shoal 349 field over the past three years: