UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-K

 

þ

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20142016

or

¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number 1-32414

 

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)

 

 

Texas

 

72-1121985

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer

Identification Number)

 

 

Nine Greenway Plaza, Suite 300

Houston, Texas

 

77046-0908

(Address of principal executive offices)

 

(Zip Code)

(713) 626-8525

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Each Class

 

Name of Each Exchange on Which Registered

Common Stock, par value $0.00001

 

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No   þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  þ

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every interactive data file required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

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

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

 

Large accelerated filer

 

¨

  

Accelerated filer

 

þ

 

 

 

 

Non-accelerated filer

 

¨  

  

Smaller reporting company

 

¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  þ

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $571,144,000$81,638,000 based on the closing sale price of $16.37$2.32 per share as reported by the New York Stock Exchange on June 30, 2014.2016.

The number of shares of the registrant’s common stock outstanding on March 3, 2015February 28, 2017 was 75,899,415.137,674,372.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement relating to the Annual Meeting of Shareholders, to be filed within 120 days of the end of the fiscal year covered by this report, are incorporated by reference into Part III of this Form 10-K.

 

 

 

 


W&T OFFSHORE, INC.

TABLE OF CONTENTS

 

 

  

 

  

Page

PART I

 

Item 1.

  

Business

  

 

1

  

Item 1A.

  

Risk Factors

  

 

1011

  

Item 1B.

  

Unresolved Staff Comments

  

 

2732

  

Item 2.

  

Properties

  

 

2833

  

Item 3.

  

Legal Proceedings

  

 

4246

  

 

  

Executive Officers of the Registrant

  

 

4349

  

Item 4.

  

Mine Safety Disclosures

  

 

4350

  

PART II

  

 

  

 

 

 

Item 5.

  

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

  

 

4450

  

Item 6.

  

Selected Financial Data

  

 

4653

  

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

  

 

5158

  

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

  

 

6681

  

Item 8.

  

Financial Statements and Supplementary Data

  

 

6782

  

Item 9.

  

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

  

 

119139

  

Item 9A.

  

Controls and Procedures

  

 

119139

  

Item 9B.

  

Other Information

  

 

119139

  

PART III

  

 

  

 

 

  

Item 10.

  

Directors, Executive Officers and Corporate Governance

  

 

120140

  

Item 11.

  

Executive Compensation

  

 

120140

  

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

  

 

120140

  

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

  

 

120140

  

Item 14.

  

Principal Accountant Fees and Services

  

 

120140

  

PART IV

  

 

  

 

 

 

Item 15.

  

Exhibits and Financial Statement Schedules

  

 

121141

  

Signatures

  

 

127149

  

Index to Consolidated Financial Statements

  

 

6782

  

Glossary of Oil and Natural Gas Terms

  

 

124146

  

i


FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  These forward-looking statements involve risks, uncertainties and assumptions.  If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions.  All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future.  These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances.  Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors, and market risks are discussed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of this Annual Report on Form 10-K and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission (“SEC”).  Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We assume no obligation, nor do we intend, to update these forward-looking statements, unless required by law.  Unless the context requires otherwise, references in this Annual Report on Form 10-K to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.

 

 

 

iii


PARTPART I

Item 1. Business

W&T Offshore, Inc. is an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties primarily in the Gulf of Mexico and the Permian Basin in West Texas.Mexico.  W&T Offshore, Inc. is a Texas corporation originally organized as a Nevada corporation in 1988, and successor by merger to W&T Oil Properties, Inc., a Louisiana corporation organized in 1983.  Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. and our wholly-ownwholly-owned subsidiary, W & T Energy VI, LLC, a Delaware limited liability company.    

The Gulf of Mexico is an area where we have developed significant technical expertise and where high production rates associated with hydrocarbon deposits have historically provided us the best opportunity to achieve a rapid return on our invested capital.  We have leveraged our historic experience in the conventional shelf (water depths of less than 500 feet) to develop higher impact capital projects in the Gulf of Mexico in both the deepwater (water depths in excess of 500 feet) and the deep shelf (well depths in excess of 15,000 feet and water depths of less than 500 feet).  We have acquired rights to explore and develop new prospects and acquired existing oil and natural gas properties in both the deepwater and the deep shelf, while at the same time continuing our focus on the conventional shelf.  Over the last several years, we have shiftedincreased our focus more toward the deepwater and to onshore in the Permian Basin of West Texas.  In the deepwater, we have completed numerous acquisitions and drilled both exploration and development wells.  Ouractivities in the deepwater, acreagewhich has expanded considerably and currently represents almost halfled to a greater percentage of our offshore acreage on a gross acreage basis.

Our onshore activities have been primarily in the Permian Basin in West Texas, where most of our leasehold interests were acquired in a single 2011 acquisition.  During 2014, we reassigned most of our interest in East Texas acreage acquired in 2011 back to the original assignor and currently have limited leasehold interest in East Texas and Louisiana.  total production coming from deepwater wells.

As of December 31, 2014,2016, we have interests in offshore leases covering approximately 1.1 million750,000 gross acres (0.7 million(450,000 net acres) spanning across the outer continental shelfOuter Continental Shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama.  On a gross acreage basis, the conventional shelf constitutes approximately 52%490,000 gross acres and deepwater constitutes approximately 48%260,000 gross acres of our offshore acreage.  Onshore, we have leasehold interests in approximately 50,000 gross acres (40,000 net acres), substantially all of which are in Texas. Approximately 58% of our total net offshore acreage is developed, and approximately 62% of our total net onshore acreage is developed.

Based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum consultants, our total proved reserves at December 31, 20142016 were 120.074.0 million barrels of oil equivalent (“MMBoe”) or 720.0444.0 billion cubic feet of gas equivalent (“Bcfe”).  Approximately 57%64% of our proved reserves as of such date were classified as proved developed producing, 12%23% as proved developed non-producing and 31%13% as proved undeveloped.  Classified by product, our proved reserves at December 31, 20142016 were 52%44% crude oil, 13%11% natural gas liquids (“NGLs”) and 35%45% natural gas.  These percentages were determined using the energy-equivalent ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs.  This energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly.  Our total proved reserves had an estimated present value of future net revenues discounted at 10% (“PV-10”) of $2.6 billion.$755 million before consideration of cash outflows related to asset retirement obligations (“ARO”).  Our PV-10 after considering future cash outflows related to asset retirement obligations (“ARO”) and without deducting future income taxesARO was $2.3 billion,$478 million, and our standardized measure of discounted future cash flows was $1.7 billionalso $478 million as of December 31, 2014.2016, as no future income taxes were estimated to be paid due to our current tax position.  Neither PV-10 nor PV-10 after ARO is a financial measure defined under generally accepted accounting principles (“GAAP”).  For additional information about our proved reserves and a reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows, see Properties – Proved ReserveReserves under Part I, Item 2 in this Form 10-K.

We seek to increase our reserves through acquisitions, exploratory and infill drilling, recompletions and workovers.  WeWith respect to acquisitions, we have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to add reserves, production and cash flow post-acquisition.  OurAlthough the current economic environment has caused us to take a conservative approach towards acquisitions, our acquisition team strivescontinues to findidentify and evaluate properties that will fit our profile and that we believe will add strategic and financial value to our company.Company.  During 2016 and 2015, we did not consummate any material acquisitions and we reduced our capital expenditures.  In 2015, we sold our interest in the Yellow Rose field discussed below.


In September 2016, we consummated a transaction whereby we exchanged approximately $710.2 million principal amount, or 79%, of our 8.500% Senior Notes due 2019 (the “Unsecured Senior Notes”) for $301.8 million principal amount of new secured notes and 60.4 million shares of our common stock.  In conjunction with the transaction, we closed on a new $75.0 million, 11.00%, 1.5 Lien Term Loan (the “1.5 Lien Term Loan”), and two amendments were made effective under our Fifth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”) (collectively, the “Exchange Transaction”).  See Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7, and in Financial Statements and Supplementary DataNote 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for a full description of the transaction, the new debt instruments and the accounting for the transaction.

From time to time, as part of our business strategy, we sell various properties.  In October 2015, we sold our ownership interests in the Yellow Rose onshore field to Ajax Resources, LLC (“Ajax”).  The field is located in the Permian Basin, West Texas, and covers approximately 25,800 net acres.  In addition to the cash purchase price, we were assigned a non-expense bearing overriding royalty interest (“ORRI”) equal to a variable percentage in production from the working interests assigned to Ajax, which percentage varies on a sliding scale from one percent for each month that the prompt month New York Mercantile Exchange (“NYMEX”) trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than $90.00 per barrel.  Our internal estimate of the assigned proved reserves at the date of the sale to Ajax was 19.0 MMBoe, consisting of approximately 71% oil, 11% NGL and 18% natural gas.  In 2016 and 2014, we did not have any significant property sales.  

In September 2014, we acquired an additional ownership interest in the Mobile Bay blocks 113 and 132 located offshorein Alabama state waters (the “Fairway Field”) and the associated Yellowhammer gas processing plant (collectively “Fairway”), which increased our ownership interest from 64.3% to 100%.  Internal estimates of additional proved reserves associated with the increased ownership interest in the Fairway Field as of the acquisition date were approximately 4.4 MMBoe (26.4 Bcfe), comprised of approximately 26% NGLs and 74% natural gas, all of which were classified as proved developed.

1


In May 2014, we acquired from Woodside Energy (USA) Inc. (“Woodside”) certain oil and gas leasehold interests in the Gulf of Mexico (the “Woodside Properties”).  The Woodside Properties consistedconsist of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks. Internal estimates

Under current commodity pricing conditions, we expect to continue to focus on conserving capital and maintaining liquidity.   We expect 2017 production to be slightly higher than 2016, but factors such as natural production declines, unplanned downtime and well performance could lead to lower production in 2017.  In addition, our capital expenditure plan for 2017 allocates approximately $125 million to projects in producing fields that we believe are low-risk and will provide a high rate of proved reserves associated withreturn.  While we will continue to evaluate opportunistic acquisitions, we expect that our acquisition activities may be reduced until the Woodside Properties as ofoutlook for the acquisition date were approximately 1.6 MMBoe (9.4 Bcfe), comprised of approximately 89% oil, 1% NGLs and 10% natural gas, all of which were classified as proved developed.

In November and December 2013, we acquired from Callon Petroleum Operating Company (“Callon”) certain oil and gas leasehold interests in the Gulf of Mexico (the “Callon Properties”). The Callon Properties consist of a 15% working interest in the Medusa field (deepwater Mississippi Canyon blocks 582 and 583), interest in associated production facilities and various interests in other non-operated fields. Internal estimates of proved reserves associated with the Callon Properties as of the acquisition dates were approximately 2.1 MMBoe (12.7 Bcfe), comprised of approximately 67% oil and 33% natural gas, all of which were classified as proved developed.

In October 2012, we acquired from Newfield Exploration Company and its subsidiary, Newfield Exploration Gulf Coast LLC (together, “Newfield”), certain oil and gas leasehold interests in the Gulf of Mexico (the “Newfield Properties”). The Newfield Properties consisted of leases covering 78 federal offshore blocksfuture commodity pricing environment improves or unless financing is available on approximately 416,000 gross acres (268,000 net acres) predominantly in the deepwater. Internal estimates of proved reserves associated with the Newfield Properties as of the acquisition date were approximately 7.0 MMBoe (42.0 Bcfe), comprised of approximately 36% oil, 3% NGLs and 61% natural gas, all of which were classified as proved developed.

From time to time, as part ofreasonable terms that would not significantly impair our business strategy, we sell various properties. In 2014, we had no significant property sales.  In 2013, we sold our non-operated working interests in the Green Canyon 60 field, the Green Canyon 19 field and the West Delta area block 29, all located in the Gulf of Mexico. In 2012, we sold our non-operated working interest in the South Timbalier 41 field located in the Gulf of Mexico.available liquidity.

Additional information on these acquisitions and divestitures can be found under Properties in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7, and in Financial Statements and Supplementary Data - Note 27 – Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K.

Our exploration efforts have historically been in areas in reasonably close proximity to known proved reserves, but starting in 2013,2012, some of our exploration projects were higher risk deepwater projects with potentially higher returns than our previous risk/reward profile. Historically, we have financed our drilling capital expenditures with operating cash flow.  The investment associated with drilling an offshore well and future development of an offshore project principally depends upon water depth, the depth of the well, the complexity of the geological formations involved and whether the well or project can be connected to existing infrastructure or will require additional investment in infrastructure.  Deepwater and deep shelf drilling projects can be substantially more capital intensive than those on the conventional shelf and onshore.shelf.  Certain risks are inherent in our business specifically and in the oil and natural gas industry generally, any one of which can negatively impact our rate of return on shareholders’ equityinvested capital if it occurs.  When projects are extremely capital intensive and involve substantial risk, we often seek participants to share the risk.  Onshore wells are less capital intensive than offshore wells, but the amount of reserves discovered and developed on a per well basis has historically been less from onshore wells than from offshore wells. We completed six,one, five and foursix offshore wells (gross) in 2016, 2015 and 33, 40 and 77 onshore wells (gross) in 2014, 2013 and 2012, respectively.


We generally sell our crude oil, NGLs and natural gas at the wellhead at current market prices or transport our production to “pooling points” where it is sold.  We are required to pay gathering and transportation costs with respect to a majority of our products.  Our products are marketed several different ways depending upon a number of factors including the availability of purchasers at the wellhead, the availability and cost of pipelines near the well or related production platforms, the availability of third-party processing capacity, market prices, pipeline constraints and operational flexibility.

2


Our currentDue to the substantially lower commodity price environment experienced since the first half of 2014 and the outlook for the remainder of 2017, we have set our 2017 capital expenditure budget for 2015at $125 million.  Although this is $200an increase from the $49 million not including any potential acquisitions. This compares toof capital expenditures incurred in 2016, our current plan for 2017 is still a significant reduction from 2015 and 2014 investment levels of $231 million and $630 million, and $636 million for 2014 and 2013, respectively.  TheWe have flexibility in our 2017 capital expenditure budget for 2015 is significantly lower than recent annual expenditures primarily due to the dramatic decline in crude oil prices.  The 2015 budget is being allotted as follows: 38% for exploration, 61% for development and less than 1% for other items. Geographically, the budget is split 92% for offshore and 8% for onshore, with the substantial majority of offshore dedicated to the deepwater. Through February 2015,because we have not closed any acquisitions, but we continueno long term rig commitments and no current pressure from co-owners to evaluate and bid on opportunities as they arise. We anticipate funding our 2015 capital budget and any potential acquisitions with cash flow from operating activities, cash on hand and borrowings under our revolving bank credit facility. The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises.  Hence, our 2015 capital budget has been set with these premises in mind.  For the portiondrill or complete a well.  Some of our capital budget relatedexpenditures planned for 2017 are expected to drilling,impact production in 2017, while most are expected to impact production in 2018 and beyond.  We expect 2017 production to be slightly higher than 2016, but factors such as natural production declines, timing of well completions, unplanned downtime and well performance could lead to flat or even lower production in 2017.  In addition, our operating policy has beenplans include spending $78 million in 2017 for ARO, compared to fund these expenditures with cash flow provided by operations.$72 million spent on ARO in 2016.  We continue to closely monitor commoditycurrent and forecasted prices and may reviseto assess if changes are needed to our capital budget if conditions warrant. We strive to be as flexible as possible and believe this strategy holds the best promise for value creation and growth and managing the volatility inherent in our business.plans. See Risk Factors under Part I, Item 1A in this Form 10-K for additional information.

Business Strategy

Our business strategy is to acquire, explore and develop oil and natural gas reserves on the Outer Continental Shelf (“OCS”),OCS, the area of our historical success and technical expertise, which we believe has yieldedwill yield desirable rates of return commensurate with our perception of risks.  The rapid and extended decline in crude oil, NGLs and natural gas prices that occurredcommenced in the backsecond half of 2014 and continued into the first part of 2015 has created a great deal ofmore uncertainty about future exploration and development.  We believe this uncertainty will continue until such time asAlthough commodity prices stabilized at higher levels during the costssecond half of goods2016 compared to the first half of 2016, prices are still low from historical levels and services utilizedprice volatility occurring in supportthe last three years continues to affect our evaluation of explorationpotential returns and production become more closely aligned with prevailing commodity prices.risks of our drilling projects.  We also believe attractive acquisition opportunities will continue to become available in the Gulf of Mexico as the major integrated oil companies and other large independent oil and gas exploration and production companies continue to divest properties to focus on larger and more capital-intensive projects that better match their long-term strategic goals.  Because of ongoing market volatility, more specifically, the reduction in oil and natural gas prices occurring in the last six months,Also, we expect to find opportunities will arise as other less well-capitalized producers may seek to divest their properties both onshorefor short-term cash flow needs.   Our plans for the short-term include operating within cash flow, maintaining liquidity, meeting our financial obligations, and offshore.pursuing acquisitions meeting our criteria.

   Our business strategy may need to be significantly altered to comply with financial assurance requirements and other regulatory hurdles, which may have a material adverse impact on our liquidity.  See Risk Factors under Part I, Item 1A and Financial Statements and Supplementary Data – Note 19 – Subsequent Events under Part II, Item 8 in this Form 10-K for additional information on this significant risk to our business and recent events.    

We believe a portion of our Gulf of Mexico acreage has exploration potential below currently producing zones, including deep shelf reserves at subsurface depths greater than 15,000 feet.  Although the cost to drill deep shelf wells is usually significantly higher than shallower wells, the reserve targets are typically larger, and the use of existing infrastructure, when available, can increase the economic potential of these wells.

In addition to pursuing offshore  Pursuit of acquisition opportunities in the Gulf of Mexico will be dependent on a number of factors, including commodity prices, access to capital markets, financial assurance requirements, other regulatory challenges, possible debt covenant restrictions, ARO and onshore opportunities in Texas, when market conditions improve, weother cash needs of the business.  We plan to continue to evaluate other areas that could be compatible with our technical expertiseacquisition opportunities and could yield desirable rates of return commensurate with our perception of risks. We may acquire or expand our offshore and onshore holdings through exploration, development and acquisition activities if attractive opportunities arise.financing options.


We believe our business approach has contributed to our success and has positioned us to capitalize on new opportunities.  Historically, we have limited our annual capital spending for drilling activities to operating cash flow, and we have used capacity under our revolving bank credit facility and the capital markets for acquisitions, development and to balance working capital fluctuations.  The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises.

Competition

The oil and natural gas industry is highly competitive.  We currently operate in the Gulf of Mexico and onshore in Texas and compete for the acquisition of oil and natural gas properties primarily on the basis of price for such properties.  We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas concernscompanies and individual producers and operators.  Many of these competitors are large, well established companies that have financial and other resources substantially greater than ours.ours and greater ability to provide the extensive regulatory financial assurances required for offshore properties.  Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment.environment and to finance acquisitions without compromising our ability to continue as a going concern.  For a more thorough discussion of how competition could impact our ability to successfully complete our business strategy, see Risk Factors under Part I, Item 1A in this Form 10-K.

3


Oil and Natural Gas Marketing and Delivery Commitments

We sell our crude oil, NGLs and natural gas to third-party customers.  We are not dependent upon, or contractually limited to, any one customer or small group of customers.  However, in 2014,2016, approximately 47%43% of our sales were to Shell Trading (US) Co. and 20% were to Vitol Inc., with no other customer comprisedcomprising greater than 10% of our sales.  See Financial Statements  and Supplementary Data – Note 1 – Significant Accounting Policies – Concentration of Credit Risk under Part II, Item 8 in this Form 10-K for additional information about our sales to customers.2016 revenues.  Due to the free trading nature of the oil and natural gas markets and because oil and natural gas are freely traded commodities with numerous purchasers in the Gulf of Mexico, and Texas, we do not believe the loss of a single customer or a few customers would materially affect our ability to sell our production.  We do not have any agreements which obligate us to deliver material quantities to third parties.

Regulation

General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulationregulations as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion.  Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members.  The Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) regulations, pursuant to the Outer Continental Shelf Lands Act (“OCSLA”), apply to our operations on Federal leases in the Gulf of Mexico.  

The Federal Energy Regulatory Commission (“FERC”) regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”).  In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting wellhead sales of natural gas, effective January 1, 1993.  While salesSales by producers of natural gas and all sales of crude oil, condensate and NGLs can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.prices.

In addition, theThe Federal Trade Commission, the FERC and the Commodity Futures Trading Commission (“CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets.  These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets.  WithWe are required to observe the market-related regulations enforced by these agencies with regard to our physical sales of crude oil or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by theseundertake.  

These departments and agencies which holdhave substantial enforcement authority.authority and the ability to grant and suspend operations, and to levy substantial penalties for non-compliance.  Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.  See Risk Factors under Part I, Item 1A in this Form 10-K for certain risks related to these and other regulations.


Federal leases.  Most of our offshore operations are conducted on federal oil and natural gas leases.  These leases are awarded based on competitive bidding and contain relatively standardized terms.  These leases require compliance with BOEM, BSEE, and other government agency regulations and orders that are subject to interpretation and change.  The BOEM and BSEE also regulate the plugging and abandonment of wells located on the OCS and, following cessation of operations, the removal or appropriate abandonment of all production facilities, structures and pipelines on the OCS (collectively, these activities are referred to as “decommissioning”).  

Decommissioning and financial assurance requirements.  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 Notice to Lessees #2016-N01 (“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, rights of way (“ROWs”) and rights of use and easement (“RUEs”).  This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07.  Under the new NTL, qualifying operators may self-insure for an amount up to 10% of their tangible net worth.  In addition, the NTL implements a phase-in period for establishing compliance with additional security obligations for certain categories of properties covered under the NTL, whereby a lessee may seek compliance with its additional security requirements under a “tailored plan” that is approved by the BOEM and would require securing phased in compliance in three approximately equal installments during a one-year period from the date of the BOEM approval of the tailored plan.  In January 2017, in a notice to stakeholders, the BOEM announced that it was extending the implementation timeline for providing financial assurance under NTL #2016-N01 by an additional six months (the “January 2017 Extension”).  However, the January 2017 Extension did not apply to “sole liability properties.”  “Sole liability properties” are leases, ROWs or RUEs for which the holder is the only liable party, i.e., there are no co-lessees, operating rights owners and/or other grant holders, and no prior interest holders liable to meet the lease and/or grant obligations.  In February 2017, the BOEM withdrew orders affecting “sole liability properties” issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program.  The February 2017 notice stated that any implementation issues associated with those sole liability orders will be discussed as part of the ongoing, six-month interactive process BOEM had initiated to gather input on other components of NTL #2016-N01 pursuant to the January 2017 Extension.  However, the BOEM reserved the right to re-issue sole liability orders before the end of the six-month period if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning sole liabilities.  See Risk Factors under Part I, Item 1A, Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 and Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for more discussion on decommissioning and financial assurance requirements.

Reporting of decommissioning expenditures.  During December 2015, the BSEE issued a final rule requiring lessees to submit summaries of actual expenditures for decommissioning of wells, platforms, and other facilities required under the BSEE’s existing regulations.  The BSEE has reported that it will use this summary information to better estimate future decommissioning costs, and the BOEM typically relies upon the BSEE’s estimates to set the amount of required bonds or other forms of financial security in order to minimize the government’s perceived risk of potential decommissioning liability.

“Unbundling.” The Office of Natural Resources Revenue (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 Federal 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 utilized during that period.  


Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost of transportation.  The price and terms for access to pipeline transportation are subject to extensive regulation.  In recent years, theThe FERC has undertaken various initiatives to increase competition within the natural gas industry.  As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limitedallows non-pipeline natural gas sellers, including producers, fromto effectively competingcompete with interstate pipelines for sales to local distribution companies and large industrial and commercial customers.  The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies.  In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services.  The rates for such storage and transportation services are subject to FERC ratemaking authority, and FERC exercises its authority either by applying cost-of-service principles or granting market based rates.

Similarly, the natural gas pipeline industry may also beis subject to state regulations, which may change from time to time.  During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (“Competition Bill”) and H.B. 1920 (“LUG Bill”). The Competition Bill gives the Railroad Commission of Texas (“RRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and intrastate transportation pipelines in formal rate proceedings. It also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation, or gathering of natural gas. The LUG Bill modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested, provides producers with an annual audit right, and provides the RRC with the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. The RRC was subject to a sunset review during 2013 and was authorized to operate for an additional four years.  Its next scheduled sunset review is in 2017.

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The Outer Continental Shelf Lands Act (“OCSLA”),OCSLA, which is administered by the Bureau of Ocean Energy Management (“BOEM”)BOEM and the FERC, requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service.  One of the FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the OCS market, to provide producers and shippers working in the OCS with greater assurance of open access service on pipelines located on the OCS, and to provide non-discriminatory rates and conditions of service on such pipelines.  On June 18, 2008, theThe BOEM issued a final rule, effective August 18, 2008 that implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines on the OCS.

In December 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as us, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million British thermal units (“MMBtu”) during a calendar year must annually report starting May 1, 2009, such sales and purchases to the FERC.FERC to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices.  It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704.  Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.  These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state legislatures, state commissions and the courts.  The natural gas industry historically has been very heavily regulated.  As a result, there is no assurance that the less stringent regulatory approach recently pursued by the FERC, Congress and Congressthe states will continue.

While the changes by these federal and state regulatorsregulations for the most part affect us only indirectly, they are intended to further enhance competition in natural gas markets.  We cannot predict what further action the FERC, the BOEM or state regulators will take on these matters; however, we do not believe that any such action taken will affect us differently, in any material way, than other natural gas producers with which we compete.

Oil and NGLs transportation rates.  Our sales of crude oil, condensate and NGLs are not currently regulated and are transacted at market prices.  In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act.  The price we receive from the sale of crude oil and NGLs is affected by the cost of transporting those products to market.  Interstate transportation rates for crude oil, NGLs and other products are regulated by the FERC.  In general, interstate crude oil, condensate and NGL pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. The FERC has established an indexing system for such transportation, which generally allows such pipelines to take an annual inflation-based rate increase.


In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.statutes and regulations.  As it relates to intrastate crude oil, condensate and natural gas liquidsNGL pipelines, state regulation is generally less rigorous than the federal regulation of interstate pipelines.  State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests, which are infrequent and are usually resolved informally.

We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate or natural gas liquidsNGL pipelines will affect us in a way that materially differs from the way they affect other crude oil, condensate and natural gas liquidsNGL producers or marketers.

Regulation of oil and natural gas exploration and production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels.  Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the location of wells, the method of drilling, casing, operating, plugging and abandoning wells, and governing the surface use and restoration of properties upon which wells are drilled.  Many states also have statutes or regulations addressing conservation of oil and gas resources, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing of such wells.

Federal leases. Most of our offshore operations are conducted on federal oil and natural gas leases, which are administered by the BOEM pursuant to the OCSLA. These leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require compliance with detailed BOEM, Bureau of Safety and Environmental Enforcement (“BSEE”), and other government agency regulations and orders that are subject to interpretation and change. The BOEM and BSEE have promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities, structures and pipelines. See Risk Factors under Part I, Item 1A in this Form 10-K for more information on new regulations and interpretations.

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To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees demonstrate financial strength and reliability according to regulations or post bonds or other acceptable assurances that such obligations will be satisfied.  The significant reductions in oil and natural gas pricing since the middle of 2014 may also adversely impact the BOEM’s financial assurance determinations with respect to the Company. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases.  In August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements for companies operating in federal waters. If the BOEM were to increase its financial assurance requirements substantially, such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated.  Any such suspension or termination could materially adversely affect our financial condition and results of operations.  In addition, the BOEM can require supplemental bonding from operators for decommissioning, plugging, and abandonment liabilities. According to federal regulations, the BOEM will waive its supplemental bonding requirements when a lessee or its guarantor can demonstrate the financial capability and reliability to meet these obligations.  We have demonstrated our financial capability and reliability to the satisfaction of the BOEM and the agency does not require that the Parent Company post any supplemental bonds to cover our operations on the OCS.

In December 2013 and January 2014, we were notified by the Office of Natural Resources Revenue (“ONRR”) of an underpayment of royalties on certain Federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment.  In March 2014, we received notice from the ONRR of a statutory fine of $2.3 million relative to such underpayment.  We believe the fine is excessive and extreme considering the circumstances and in relation to the amount of underpayment.  On April 23, 2014, we filed a request for a hearing on the record and a general denial of the ONRR’s allegations contained in the notice.  We intend to contest the fine to the fullest extent possible. The ultimate resolution may result in a waiver of the fine, a reduction of the fine, or payment of the full amount plus interest covering several years.  As no amount has been determined as more likely than any other within the range of possible resolutions, no amount has been accrued as of December 31, 2014 per authoritative guidance.  However, we cannot state with certainty that our estimate of the exposure is accurate concerning this matter.

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

Environmental Regulations

General. We are subject to complex and stringent federal, state and local environmental laws.  These laws, among other things, govern the issuance of permits to conduct exploration, drilling and producing operations, the amounts and types of materials that may be released into the environment, the discharge and disposal of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities.  Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with, and which carrya failure to comply may result in substantial administrative, civil and even criminal penalties for failure to comply.or the suspension or cessation of operations in affected areas.  Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person.  Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas.  In addition, state laws often require various forms of remedial action to prevent and address pollution, such as the closure of inactive oil and gas waste pits and the plugging of abandoned wells.  The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability.  The cost of remediation, reclamation and abandonment of wells, platforms and other facilities in the Gulf of Mexico may require us to incur significant costs.is significant.  These costs are considered a normal, recurring cost of our on-going operations.  Our domestic competitors are generally subject to the same laws and regulations.

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Hazardous Substances and Wastes.  The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment.  These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances.  Under CERCLA, such persons are subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies.  In addition, companies that incur liability frequently also confront third-party claims because it is not uncommon for neighboring landowners and other third parties to file 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 jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.  In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.


The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 (“RCRA”), regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites.  RCRA currently excludes drilling fluids, produced waters and certain other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste.waste,Disposaland the disposal of such non-hazardous oil and natural gas exploration, development and production wastes is usually regulated by state law.  Other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, however, various environmental groups have challenged the Environmental Protection Agency’s (“EPA”) exemption of certain oil and gas wastes from RCRA.  For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016.  Under the decree, the EPA must propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary.  If the EPA proposes a rulemaking for revised oil and gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021.  In addition, legislation is frequently proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes,wastes.”  therebyA loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could potentially subjectingsubject such wastes to more stringent handling, disposal and cleanup requirements.  If such legislation were enacted, it could have a significant impactOther wastes handled at exploration and production sites or generated in the course of providing well services may not fall within the RCRA exclusion.  Moreover, stricter standards for waste handling and disposal may be imposed on our operating costs as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.the future.  Additionally, Naturally Occurring Radioactive Materials (“NORM”) may contaminate minerals extraction and processing equipment used in the oil and natural gas industry.  The waste resulting from such contamination is regulated by federal and state laws.  Standards have been developed for: worker protection; treatment, storage, and disposal of NORM and NORM waste; management of NORM-contaminated waste piles, containers and tanks; and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws.  We do not anticipate any material expenditures in connection with our compliance with RCRA and applicable state laws related to NORM waste.

Air Emissions and Climate Change.  Air emissions from our operations are subject to the Federal Clean Air Act (“CAA”) and comparable state and local requirements.  We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.  For example, the U.S. Environmental Protection Agency (“EPA”) has established air emission controls requirements for oil and natural gas production and natural gas processing operations.  Specifically, the EPA established New Source Performance Standards for emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards for hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA rules require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent any hydrocarbons that come to the surface during completion of the fracturing process. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules establish new leak detection requirements for natural gas processing plants. These rules may require a numberEPA has developed, and continues to develop, stringent regulations governing emissions of modifications to our operations includingtoxic air pollutants at specified sources.   Moreover, the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our operating results. However, we believe our operations will not be materially adversely affected by any such requirements,U.S. Congress and the requirements are not expectedEPA, in addition to be any more burdensomesome state and regional efforts, have in recent years considered legislation or regulations to us than to other similarly situated companies involved in oilreduce emissions of greenhouse gases.  These efforts have included consideration of cap-and-trade programs, carbon taxes, and naturalgreenhouse gas explorationmonitoring and production activities.

Climate Change. Thereporting programs.  In the absence of federal greenhouse gas limitations, the EPA has determined that greenhouse gas emissions of carbon dioxide, methane and other “greenhouse gases” present an endangermenta danger to public health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and it has adopted regulations that, among other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations tothings, restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA has adopted two setsCAA and may require the installation of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction incontrol technologies to limit emissions of greenhouse gases.  For example, in June 2016, the EPA published new source performance standards that require new, modified, or reconstructed facilities in the oil and natural gas sector to reduce methane gas and volatile organic compound emissions.  These regulations would apply to any new or significantly modified facilities that we construct in the future that would otherwise emit large volumes of greenhouse gases from motor vehiclestogether with other criteria pollutants.  Also, certain of our operations are subject to EPA rules requiring the monitoring and the other of which requires preconstruction and operating permits for certain large stationary sources. The EPA also requires theannual reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including certain onshore oil and natural gasoffshore production facilities, on an annual basis. We believe we are in compliance withsources.  See Risk Factors under Part I, Item 1A of this new emission reporting requirement as it applies to our operations.  Form 10-K for further discussion.


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In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases 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.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases 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, NGLs and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases 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. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

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 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 December 2014, the BOEM issued a final rule, effective January 12, 2015, which raiseshas raised OPA’s damages liability cap from $75 million to $133.65$134 million.  OPA also 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 million and $150 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to a maximum of $150 million.OCS.  We are currently required to demonstrate, on an annual basis, that we have ready access to $150 million that can be used to respond to an oil spill from our facilities on the OCS.  As a result of the BP Deepwater Horizon incident, legislation has been proposed in Congress to increase the minimum level of financial responsibility to $300 million or more. If OPA is amended to increase the minimum level of financial responsibility to $300 million, 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.

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.  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.  Costs may be associated with theThe treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our onshore facilities.gas processing plant may have significant costs.  Obtaining permits has the potential to delay 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.  We currently maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.

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Hydraulic Fracturing.  Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand or other proppants and chemicals under pressure into the formation to fracture the rock formation and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (the “SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance covering such activities in February 2014. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources.  We follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities including disclosure requirements. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells that require hydraulic fracturing.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA is performing a study of the potential environmental effects of hydraulic fracturing on drinking water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal. The EPA has indicated that it expects to issue its study report in 2015. The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards in 2015. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

Protected and Endangered 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.  This order has the potential to adversely affect our operations by restricting areas in which we may carry out future development and exploration projects and/or causing us to incur increased operating expenses.

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).  The BSEE also issues numerous regulations under the nomenclature Notice to Lessees (“NTL”) that provide formal guidelines on implementation of OCS regulations and standards. We believe we are in compliance in all material respects with the requirements regarding protection of marine species.

Certain flora and fauna that have been officially classified as “threatened” or “endangered” are protected by the Endangered Species Act.Act (“ESA”).  This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area.  IfWe conduct operations on leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species are located in an area where we wish to conduct seismic surveys, development or abandonment operations, the workthat potentially could be prohibitedlisted as threatened or delayed or expensive mitigation could be required.

endangered under the ESA may exist.  We own a non-producing platform in the Gulf of Mexico located in a National Marine Sanctuary.  As a result, we are subject to additional federal regulation, including regulations issued by the National Oceanic and Atmospheric Administration.  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.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief.


Other 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 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.

9Financial Information


We maintain liability insurance and well control insurance for all ofoperate our operations. In addition, we maintain property and hurricane damage insurance coverage for some, but not all, of our properties, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain does not cover the risks described above from gradual pollution events which occur overbusiness as a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover such risks or that such insurance will be available at a cost that would justify its purchase. The occurrence of a significant environmental event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.single segment. See Management’s Discussion and Analysis ofSelected Financial Condition and Results of Operations – Liquidity and Capital Resources – Hurricane Remediation, Insurance Claims and Insurance CoverageData under Part II, Item 76 and Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for additional information on insurance coverage.our financial information.

Seasonality

For a discussion of seasonal changes that affect our business, see Management’s Discussion and Analysis of Financial Condition and Results of Operations – Inflation and Seasonality under Part II, Item 7 in this Form 10-K.

Employees

As of December 31, 2014,2016, we employed 339302 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 otheramendments 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.


Item 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 the Oil and Natural GasOur Industry, Our Business and Our BusinessFinancial Condition

Substantial or extendedFurther declines in crude oil, NGLs and natural gas prices mayor an extended period of currently depressed prices will adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our future capital expenditure obligations and 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 and future rate of growth.  Oil,Crude oil, NGLs and natural gas are commodities and are subject to wide price fluctuations in response to relatively minor changes in supply and demand.  LowerThe significantly reduced prices for our crude oil, NGLs and natural gas production may not only decreasein 2016 and 2015 have substantially decreased our revenues on a per unit basis but mayand have also reducereduced the amount of crude oil, NGLs and natural gas that we can produce economically.  Historically, the markets for crude oil, NGLs and natural gas have been volatile and will likely continue to be volatile in the future.  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:

·

changes in global supply and demand for oil, NGLs and natural gas;

changes in global supply and demand for crude oil, NGLs and natural gas;

·

the actions of the Organization of Petroleum Exporting Countries (“OPEC”);

the actions of the Organization of Petroleum Exporting Countries (“OPEC”);

·

the price and quantity of imports of foreign oil, NGLs, natural gas and liquefied natural gas;

the price and quantity of imports of foreign crude oil, NGLs, natural gas and liquefied natural gas;

·

acts of war, terrorism or political instability in oil producing countries;

acts of war, terrorism or political instability in oil producing countries;

·

economic conditions;

economic conditions;

·

political conditions and events, including embargoes, affecting oil-producing activities;

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·

the level of global oil and natural gas exploration and production activities;

·

the level of global oil, NGLs and natural gas inventories;

the level of global oil and natural gas exploration and production activities;

·

weather conditions;

the level of global crude oil, NGLs and natural gas inventories;

·

technological advances affecting energy consumption;

weather conditions;

·

the price and availability of alternative fuels; and

technological advances affecting energy consumption;

·

geographic differences in pricing.

the price and availability of alternative fuels; and

geographic differences in pricing.

The prices of crude oil, domestic natural gas and NGLs have declined substantially since Junestarting in the second half of 2014.  The average price per barrel of West Texas Intermediate (“WTI”) crude oil has decreased from $107was over $90.00 in 2014, approximately $49.00 in 2015 and approximately $43.00 per barrel in the middle of June 2014 to as low as $44 per barrel in January 2015.2016.  This decrease in prices has impacted all companies throughout the oil and gas producers to varying degrees depending on hedging strategies.industry.  Natural gas and NGLsNGL prices have also been negatively affected by excess natural gas production, high levels of stored natural gas and weather conditions affecting demand.  In recent months,During 2014, the average Henry Hub spot pricesprice for natural gas have declined to prices lower than $3.00was above $4.00 per McfMMBtu compared to average pricesapproximately $2.60 per MMBtu during 20142015 and approximately $2.50 per MMBtu in excess of $4.00 per Mcf. There have been significant recent development2016.  Development activities in shale and other resource plays which have the potential to yield a significant amount of natural gas and NGLs production, as well as natural gas and NGLs produced in connection with increased domestic oil drilling activities.  The potential increases in natural gas supplies resultingAlthough oil prices have increased somewhat from the large-scale developmentlows of these unconventional resource reserves could continuethe first quarter of 2016, margins are still low compared to have an adverse impact on the price of natural gas and NGLs.historical levels.  An environment of further or continued lowerlow crude oil, NGLs and natural gas prices would materially and adversely affect our future business, financial condition, results of operations, liquidity, and/or ability to finance planned capital expenditures.expenditures, ability to fund our ARO, ability to repay any borrowings per our debt agreements, to secure supplemental bonding, to secure collateral for such bonding, if required, and to meet our other financial obligations.


The borrowing base under our Credit Agreement may be reduced by our lenders.

IfAvailability of borrowings and letters of credit under the Credit Agreement is determined by establishment of a borrowing base, which is periodically redetermined during the year based on our lenders’ view of crude oil, NGLs and natural gas prices and on our proved reserves.  The borrowing base under the Credit Agreement was reduced during 2016, and was $150 million as of December 31, 2016 compared to $750 million as of December 31, 2014.  The lower borrowing base was primarily due to declines in commodity prices.  The borrowing base could be further reduced in the future as a result of the continued impact of low 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; such excess or deficiency is required to be repaid within 90 days in three 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 financial covenants and ratios.

We may not have the financial resources in the future to repay an excess or 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 BOEM for our decommissioning obligations.  Further, the failure to repay an excess or deficiency that may result from a borrowing base redetermination under our Credit Agreement may result in a cross-default under our other debt agreements.  Continued low crude oil, NGLs and natural gas prices in the future would continue to 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.

We may be unable to provide the financial assurances demanded by the BOEM 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 current or future 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 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.  This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07.  In January 2017, the BOEM issued the January 2017 Extension for non-sole liability properties.  During 2016 and in January and February 2017, we received notices from the BOEM concerning financial assurances of our decommissioning obligations, which are summarized below.  

In the first quarter of 2016, we received several orders from the BOEM demanding the Company to secure financial assurances in the aggregate of $260.8 million, with amounts specified with respect to certain designated leases, ROWs and RUEs.  We filed various appeals to the Interior Board of Land Appeals (the “IBLA”) under the Department of the Interior concerning these orders.  The IBLA, acknowledging the BOEM and the Company were seeking to resolve the BOEM demands through settlement discussions, stayed the effectiveness of these orders several times, with the current stay effective to May 31, 2017.  

In September 2016, we received notice from the BOEM confirming that we do not qualify to self-insure a portion of any additional financial assurance under NTL #2016-N01.

In October 2016, we received from the BOEM proposal letters outlining what additional security the BOEM proposes to require for leases, ROWs and RUEs in which we are designated operator. 

In December 2016, the BOEM issued to us an Order to Provide Additional Security for our sole liability properties.  Sole liability properties are leases, ROWs or RUEs for which the holder is the only liable party, i.e., there are no co-lessees, operating rights owners and/or other grant holders, and no prior interest holders liable to meet the lease and/or grant obligations.      


In January 2017, the BOEM, in a notice to stakeholders, issued the January 2017 Extension which extended the implementation timeline for NTL #2016-N01 by an additional six months as to non-sole liability leases, ROWs and RUEs, except in circumstances in which the BOEM determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  The extension does not affect the demand to provide financial assurance for leases, ROWs and RUEs constituting sole liability properties.  The BOEM stated that the extension was needed to provide the BOEM and industry the opportunity to focus on providing additional security for sole liability properties, and to allow an opportunity for additional time and conversation concerning the non-sole liability properties.  

In February 2017, the BOEM withdrew the orders it issued in December 2016 affecting so called “sole liability properties” to allow time for the new President’s administration to review the complex financial assurance program.  This withdrawal rescinded the Order to Provide Additional Security issued to us in December 2016.  However, the BOEM may re-issue sole liability orders before the end of the six-month period if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  

As suggested by the BOEM in its January and February notices to stakeholders, we intend to use the six month extension granted by the BOEM as an opportunity to propose and negotiate acceptable plans dealing with both sole and non-sole liability properties.

While we expect to be able address the financial assurances of our sole and non-sole liability properties in accordance with the guidelines under NTL #2016-N01, we cannot provide any assurance at this time on when the BOEM will direct that such financial assurance coverage must be submitted or how to structure such coverage, and if we are able to fund such coverage.  We could in the future receive further or revised demands from the BOEM 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.


We have a significant amount of indebtedness.  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, 2016, we had approximately $1.0 billion recorded as debt, which includes $189.8 million principal amount of unsecured indebtedness and $683.9 million principal amount of secured indebtedness outstanding and less than $1 million in outstanding letters of credit.  Our current availability on our revolving bank credit facility is approximately $150 million and we had no borrowings outstanding on our revolving bank credit facility.  For example, our leverage could:

increase our vulnerability to general adverse economic and industry conditions;

limit our ability to fund future working capital requirements, capital expenditures and ARO, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets;

limit our opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt obligations or to comply with any restrictive terms of our debt obligations;

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

impair our ability to obtain additional financing in the future; and

place us at a competitive disadvantage compared to our competitors that have less debt.

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 also pledged as collateral on a subordinate basis under certain other debt agreements.  Sustained or lower crude oil, NGLs and natural gas prices in the future will continue to 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 asset 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.  We may not be able to further restructure or refinance our debt, reduce capital expenditures, sell assets, borrow more money or raise equity 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 indebtedness 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.

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, 2016, we had $189.8 million of unsecured indebtedness and approximately $683.9 million of secured indebtedness outstanding (excluding $0.5 million of letters of credit and amounts included in the carrying value of certain debt for future payment-in-kind (“PIK”) and cash interest payments).  The components of our indebtedness are:


$0.5 million of letters of credit;

$75.0 million in aggregate principal amount of 1.5 Lien Term Loan;

$300.0 million in aggregate principal amount of the 9.00% Term Loan, due May 2020 (the “Second Lien Term Loan”);

$163.0 million of Second Lien PIK Toggle Notes;

$145.9 million of Third Lien PIK Toggle Notes; and

$189.8 million in aggregate principal amount of the Unsecured Senior Notes.

If new debt is added to our current debt levels, the related risks that we and our subsidiaries face could intensify. 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:

make loans and investments;

incur additional indebtedness or issue preferred stock;

create certain liens;

sell assets;

enter into agreements that restrict dividends or other payments from our subsidiaries to us;

consolidate, merge or transfer all or substantially all of the assets of our company;

engage in transactions with our affiliates;

maintain certain cash balances;

pay dividends or make other distributions on capital stock or subordinated indebtedness; and

create unrestricted subsidiaries.

Our revolving bank credit facility 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.

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.


We may not be able to extend, renew, refund, defease, discharge, replace or refinance our Unsecured Senior Notes by February 28, 2019.  

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.  Assuming the PIK option is fully utilized for the Third Lien PIK Toggle Notes; the principal balance would grow and would be approximately $172.7 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 $247.7 million may become due on February 28, 2019.   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 then.  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.

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

Sustained or 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 very constrained.  Other capital sources may arise with significantly different terms and conditions.  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 capital and credit markets.  If the debt or equity capital markets do not improve, 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, 2016, we had secured debt outstanding of $836.7 million which includes the outstanding principal, PIK and accrued interest and certain letter of credit reimbursement obligations.  If in the future we default on one or more issues or tranches of our secured debt, we cannot assure you 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 $149.5 million as of December 31, 2016, available for borrowing on our revolving bank credit facility, 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 you 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 you 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.

If crude oil, NGLs and natural gas prices decrease from their current levels, or decrease further, we will likelymay 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 periodically review the carrying value of our oil and natural gas properties quarterly for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we will likely be required to write down the carrying value of our oil and natural gas properties. Such write-downs constitute a non-cash charge to earnings.  Impairment of proved properties under our full cost oil and gas accounting method is largely driven by the present valuesvalue of future net revenues of proved reserves estimated using SEC mandated 12-month unweighted first-day-of-the-month commodity prices.  SinceIn addition to commodity prices, impairment assessments of proved properties include the evaluation of development plans, production data, economics and other factors.  As crude oil, natural gas and NGLs prices did not declinedeclined in 2014 until after June 2014, and more prominently2015, we incurred impairment charges in each quarter in 2015 totaling $987 million for the year.  Such write-downs constitute a non-cash charge to earnings.  As prices fell further during 2016, we incurred impairment charges in the fourth quarterfirst three quarters of 2014, the2016 which totaled $279 million.  If prices fall below levels received during 2016, this would impact of the recent pricing downturns will continue to adversely affect our SEC average pricing as recent and current prices roll into the SEC average prices used in evaluating impairment of our proved reserves under the full cost accounting “ceiling test”.   While we have not had any ceiling test impairments since 2009, sustained current prices or further declines in prices forestimated future revenues.  In addition, lower crude oil, NGLs and natural gas will likely result in future ceiling test impairments.  You should not assumeprices may reduce our estimates of the reserve volumes that may be economically recovered, which would reduce the $2.6 billion present value of future net revenues, PV-10, from our proved oil and natural gas reserves shown elsewhere in this document is the current markettotal value of our estimated oil and natural gasproved reserves.  (PV-10 is not a financial measure defined under GAAP.  For additional information about our proved reserves and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, see Properties – Proved Reserve under Part I, Item 2 in this Form 10-K.)  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.  For example, the average price used in the standardized measure of discounted cash flows for December 31, 2014 for crude oil was $91.12 per barrel and the average price of WTI crude oil in December 2014 was $59.29 per barrel.   

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.  As a result of lower oil, NGLs and natural gas prices, we may also reduceAlso, no assurance can be given that commodity price decreases will not affect our estimates of the reserve volumes that may be economically recovered, which would reduce the total value of our proved reserves.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 proved undeveloped reserves under current SEC guidance.

Current SEC guidance requires proved undeveloped reserves (“PUDs”) may only be classified as such if a development plan has been adopted indicating that they are scheduledreasonably certain to be drilled within five years of the date of booking.  This rule may limit our potential to book additional proved undeveloped reservesPUDs as we pursue our drilling program.  If current low price conditions persist,prices decline, we also may be compelled to further postpone the drilling of proved undeveloped reservesPUDs until prices recover.  Further, ifIf we postpone drilling of proved undeveloped reservesPUDs 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.

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As of December 31, 2014, approximately 31%Our PUDs comprised 13% of our total proved reserves were undevelopedas of December 31, 2016 and approximately 12% of our total proved reserves were developed non-producing.  There can be no assurance that all of those reserves will ultimately be developed or produced.

Our undeveloped proved reserves and developed non-producing proved reserves require additional future expenditures and/or activities to convert these into producing reserves.  WeAs circumstances change, we cannot provide assurance thesethat all future expenditures will be made and that activities will be entirely successful in converting these reserves.  Additionally,Although we are the operator for all the fields containing our PUDs as of December 31, 2016, in the past, we were not the operator for approximately 17%a portion of our undeveloped proved reserves and approximately 11% of our proved developed non-producing reserves, so we may not bePUDs, which could have put us in a position of not being able to control the timing of all development activities.  Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reservesPUDs will ultimately be produced during 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.


Relatively short production periods for our Gulf of Mexico properties subject us to high reserve replacement needs and require significant capital expenditures to replace our reserves at a faster rate than companies whose reserves have longer production periods.  Our failure to replace those reserves would result in decreasing 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.  The majorityAll of our current production is from the Gulf of Mexico.  Reserves in the Gulf of Mexico generally decline more rapidly than from reserves in many other producing regions of the United States.  Our independent petroleum consultant estimates that 42%55% of our total proved reserves will be depleted within three years.  As a result, our need to replace reserves and production from new investments is relatively greater than that of producers who recover lower percentages of their reserves over a similar time period, such as those producers who have a larger portion of their reserves in areas other than the Gulf of Mexico.  We may not be able to develop, find or acquire additional 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 replace reserves, we will not be able to sustain production at current levels.

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 currently constrained butand we believe we couldour access otherto capital markets if the need arises. These limitations in the capital markets may affectremains limited at this time.  Compared to prior years, we significantly reduced our ability to grow and changes in our capitalization structure may significantly affect our financial risk profile.  Furthermore, we cannot be certain that financing for future capital expenditures will be available if needed,in 2016 and continue to have a low capital expenditure budget for 2017 in order to conserve capital and target projects with the extent required, onhighest probability of acceptable terms. For additional financing risks, see “– Risks Related to Financings.”

returns.  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 by declining commodity prices) and cash on hand will make replacing produced reserves more difficult.  If our cash flow from operations and cash on hand are not sufficient to fund our capital expenditure budget, we may be limited in our ability to access additional debt, equity or other methods of financing on an economic or timely basis to replace our proved reserves.

Lower oil and natural gas prices could negatively impact our ability to borrow.

As of December 31, 2014, borrowing availability under our revolving bank credit facility was $750 million, less outstanding borrowings of $447 million and letters of credit of less than $1 million, resulting in net availability of $302 million.  Availability is determined semi-annually by our lenders and is based on oil, NGLs and natural gas prices and on our proved reserves.  Substantially all of our oil and natural gas properties are pledged as collateral under the Fifth Amended and Restated Credit Agreement (the “Credit Agreement”) governing our revolving bank credit facility.  The Credit Agreement limits our ability to incur additional indebtedness based on specified financial covenants, ratios or other criteria.  Sustained and/or lower oil, NGLs and natural gas pricesThese limitations in the future could result in a reduction in credit availabilitycapital markets and alsoour recently constrained capital budget may adversely affect our ability to satisfy these covenants, ratios orsustain our production at 2016 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 criteria and thus could reduce our ability to incur additional indebtedness and our ability to replace reserves.

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The Company could face additional requirements if it does not comply with the terms of its probation.

On January 3, 2013, the Company (i) pled guilty to one felony count under the Clean Water Act for altering monthly produced water discharge samples for the Ewing Banks 910 platform in 2009 and one misdemeanor count under the Clean Water Act for failure to report the discharge of a small amount of oil from the same platform in November 2009, (ii) paid a $0.7 million fine and $0.3 million for community service and (iii) entered into an environmental compliance program subject to a third-party audit. Under the agreement, the Company was placed on a three-year term of probation, which ends on January 3, 2016. The probation terms require that the Company commit no further environmental law violations, comply with an Environmental Compliance Plan during the probation period and take no adverse action against personnel who cooperatedrestrictions, delays in the investigation. The agreement further stipulates that the Government will not seek any further criminal charges against the Company in this matter. Failure to comply with the termsprocessing and approval of the agreement could lead to additional requirements and/or operating restrictions.

More stringent regulatory initiatives relating to offshore explorationdrilling permits and production activities may have an adverse effect on our results of operations, financial position and liquidity.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in the deep water of the Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, there have been many proposals, and substantial rules adopted, by governmental and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. The federal government, acting through the U.S. Department of the Interior and its implementing agencies that have since evolved into the present day BOEM and BSEE, has issued various rules, NTLs and temporary drilling moratoria.  These rules and requirements impose or result in added environmental and safety measures upon exploration, development, oil spill-response and production operatorsdecommissioning plans, and other related developments in the Gulf of Mexico includingmay have a material adverse effect on our business, financial condition, or results of operations.

In recent years, we have expanded our drilling efforts on deepwater projects in the following:

·

The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements.

·

The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers.

·

The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams.

·

The Workplace Safety Rule requires operators to employ a comprehensive safety and environmental management system (“SEMS”).  The purpose of SEMS is to reduce human and organizational errors as root causes of work-related accidents and offshore spills; develop protocols as to who at the facility has the ultimate operational safety and decision-making authority; establish procedures to provide all personnel with “stop work” authority; and, to have their SEMS periodically audited by an independent third party auditor approved by BSEE.

TheseGulf of Mexico.  The BSEE and the BOEM have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters.  Compliance with these added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill-response, and decommissioning plans and possible additional regulatory initiatives may serve to effectively slow down the pace ofcould result in difficult and more costly actions and adversely affect or delay new drilling and production operationsongoing development efforts.  Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico dueand, as a result, are continuing to adjustmentsdevelop and implement new, more restrictive requirements.  For example, in operating proceduresApril 2016, the BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation and certification practices as well as increased lead timesmaintenance of blow-out preventers, real-time monitoring of deepwater and high temperature, high pressure drilling activities, and enhanced reporting requirements.  Also, in April 2016, the BOEM published a proposed rule that would update existing air emissions requirements relating to obtain explorationoffshore oil and production plan reviews, develop drilling applications, and apply for and receive new well permits.  These new requirements also increase the cost of preparing permit applications and increase the cost of each new well, particularly for wells drilled in the deepwaternatural gas activity on the OCS.  WeThe BOEM regulates these air emissions in connection with its review of exploration and development plans, 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 subsequent rulemakings could become subjectfurther restrict offshore air emissions.  

Among other adverse impacts, these additional measures could delay operations, disrupt our operations or increase the risk of leases expiring before exploration and development efforts have been completed due to fines,the time required to develop new technology.  This would result in increased financial assurance requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties or orders requiring us to modifyshut-in production at one or suspendmore of our operations in the Gulf of Mexico if we fail to comply with these requirements.  Moreover, if similar oilfacilities.  If material spill incidents were to occur in the future, in the Gulf of MexicoUnited States or elsewhereother countries where we conduct operations, the relevant governmental authoritiessuch an event may occur could elect to again issue directives to temporarily cease drilling activities.  Inactivities and, in any event, they may from time to time issue further safety and environmental regulatory initiativeslaws and regulations regarding offshore oil and natural gas exploration and development, activities,any of which any one or more of such events could have a material adverse effect on our production activities as well asbusiness.  We cannot predict with any certainty the full impact of any new laws or regulations on our financial position, results ofdrilling operations and liquidity.

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Requirements imposed by the BOEM and BSEE related to the decommissioning, plugging, and abandonment of offshore facilities could significantly impactor on the cost or availability of operating our business.

In additioninsurance to the NTLs discussed previously, the BOEM issued NTL No. 2010-G05 dated effective October 15, 2010 that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron” – wells, platforms and pipelines that are no longer producingcover some or serving exploration or support functions related to an operator’s lease – in the Gulf of Mexico. This NTL sets forth more stringent standards for decommissioning timing requirements by requiring that any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulfur zones are appropriately isolated. Similarly, platforms or other facilities which are no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts which could cause an increase, perhaps materially, in our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future ARO required to meet such increased costs. We have continued to review and revise our ARO estimates each year following BOEM’s issuance of this NTL. The increase in decommissioning activity in the Gulf of Mexico expected over the next few years as a result of the NTL may result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related ARO.

To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees demonstrate financial strength and reliability according to regulations or post bonds or other acceptable assurances that such obligations will be satisfied.  In addition, in August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements for companies operating in federal waters.  If BOEM were to increase its financial assurance requirements substantially, such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. The significant reductions in oil and natural gas pricing since the middle of 2014 may also adversely impact the BOEM’s financial assurance determinations with respect to the Company. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated.  Any such suspension or termination could materially adversely affect our financial condition and results of operations. In addition, the BOEM can require supplemental bonding from operators for decommissioning, plugging, and abandonment liabilities if financial strength and reliability criteria are not met.  

Proposed rules regulating air emissions from oil and gas operations could cause us to incur increased capital expenditures and operating costs.

The EPA has adopted new regulations under the CAA that, among other things, require additional emissions controls for the production of oil, NGLs and natural gas, including New Source Performance Standards to address emissions of sulfur dioxide and VOCs and a separate set of emission standards to address hazardous air pollutants frequentlyrisks associated with such production activities. The final regulations require, among other things, the reduction of VOC emissions through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. Compliance with these requirements could significantly increase our costs of development and production.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.  As of December 31, 2016, we carry named windstorm coverage of $150 million for a total loss only (“TLO”) on our Ship Shoal 349 (Mahogany) platform and do not have named wind storm coverage on any other of our properties.  We currently carry insurance coverage for certain events besides the named windstorm coverage for Mahogany in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which includes named windstorm TLO coverage for Mahogany).  Along with having exposure for named wind storms at all of our properties, and limited coverage at our Mahogany property, we have additional exposure due to retention amounts within the Energy Package and limitations of the policies.

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 2014,2016, we renewedentered into our insurance policies covering well control, hurricane damage, general liability and pollution.  These policies reduce, but do notin no way totally mitigate our risk as we are exposed to amounts for retention and co-insurance, limits on coverage and some events that are not insured.  These policies expire in May and June 2015.2017.  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 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 mayhave not obtainobtained insurance ifas 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 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 Claims and Insurance Coverage under Part II, Item 7 in this Form 10-K for additional information on insurance coverage.

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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.

Due to insurance claims in recent years associated withIn the past, hurricanes in the Gulf of Mexico and globalhave caused catastrophic losses and property damage and welldamage.  Well control insurance coverage has become more limited and the cost of such coverage has become both more costly and more volatile.volatile over the past five years.  The insurance market may further change dramatically in the future due to thehurricane damage, major oil spill that occurred in 2010 at BP’s Macondo well inspills or other events.  

  In the deepwater Gulf of Mexico. As of December 31, 2014, virtually all offuture, our PV-10 value of proved reserves attributable to our Gulf of Mexico properties is on platforms that are covered under our current insurance policies for named windstorm damage. Our insurers may not continue to offer us the type and level of our currentwhat we view as reasonable coverage, or our costs may increase substantially as a result of increased premiums and therepremiums.  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, we may periodically enter into oil and natural gas price commodity derivative positions with respect to a portion of our expected production.  As of December 31, 2016, we did not have any open commodity derivative positions.  During the first quarter of 2017, we entered into commodity derivative contracts and may enter into more 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:

·

our production is less than expected;

our production is less than expected;

·

there is a widening of price differentials between delivery points for our production and the delivery points assumed in the hedge arrangements; or

there is a widening of price differentials between delivery points for our production and the delivery points assumed in the hedge arrangements; or

·

the counterparties to the derivative contracts fail to perform under the terms of the contracts.

the counterparties to the derivative contracts fail to perform under the terms of the contracts.

See Financial Statements and Supplementary Data– Note 68 – 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.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 abilitycompetitors may have significantly more capital resources and less expensive sources of capital.  In addition, they may be able to acquire additionalgenerate acceptable rates of return from marginal prospects anddue to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.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: Requirements imposedWe may be unable to provide the financial assurances demanded by the BOEM to cover our decommissioning obligations in the amounts and BSEE relatedunder the time periods required by the BOEM.  If extensions and modifications to the decommissioning, plugging,BOEM’s current or future demands are needed and abandonment ofcannot 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 facilities could significantly impact the cost of operating our business.leases.  

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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, and limited availability, 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 investment in infrastructure.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 you that our oil and natural gas exploration activities in the deep shelf, the deepwater and elsewhere will be commercially successful.


Our estimates of future asset retirement obligationsARO 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, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations.  These costs 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.  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 restrictive interpretation,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 couldwill differ dramatically from whatour recorded estimate if we may ultimately incur ashave a result of platform damage.damaged platform.

As described above inDuring 2016, the risk factor titled “Newadditional requirements imposed by the BOEM and BSEE related to the decommissioning, plugging, and abandonment of offshore facilities could significantly impact the cost of operating our business,”under the BOEM’s NTL 2010-G05 increased our liability for ARO by accelerating#2016-N01, once fully implemented, will increase the time frame for plugging, abandonment and removal for somecosts of our platformsoperations and reduce the availability of surety bonds due to the increased demands for such bonds in a low-price commodity environment.  In December 2016, the BOEM further increasedissued an order on our sole liability after issuing regulation interpretationsproperties for additional financial assurances.  In January 2017, in a notice to stakeholders, the BOEM issued the January 2017 Extension, which affected scope and requirements.extended the implementation timeline for providing financial assurance under NTL #2016-N01 by an additional six months for non-sole liability properties with certain exceptions.  In addition,February 2017, the potential increaseBOEM withdrew the orders it issued in decommissioning activityDecember 2016 affecting sole liability properties to allow time for the new Administration to review the complex financial assurance program.  This withdrawal rescinded the Order to Provide Additional Security issued to us in December 2016.  However, the Gulf of Mexico overBOEM may re-issue sole liability orders before the next several years as a resultend of the six-month period if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  The BOEM’s NTL could likely result#2016-N01 has given broader interpretation authority to BOEM’s district personnel, which increases the difficulty in compliance with the new NTL.  In addition, increased demand for salvage contractors and equipment resultingcould result in increased estimates ofcosts for plugging and abandonment operations.  These items have, and removalmay further increase our costs and increasesmay 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 gas interests with other companies, we are obligated to pay our share of operating, capital and decommission 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 is bankrupt or unable to pay its decommissioning costs.  For example, we have in the past received a demand for payment of such costs related ARO.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.  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:

·

the timing and amount of capital expenditures;

the timing and amount of capital expenditures;

·

the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

·

the operator’s expertise and financial resources;

the operator’s expertise and financial resources;

·

approval of other participants in drilling wells and such participants’ financial resources;

approval of other participants in drilling wells and such participants’ financial resources;

·

selection of technology; and

selection of technology; and

·

the rate of production of the reserves.

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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, which include, among other things, hydraulic fracturing, involve a variety of operating risks, including:

·

fires;

fires;

·

explosions;

explosions;

·

blow-outs and surface cratering;

blow-outs and surface cratering;

·

uncontrollable flows of natural gas, oil and formation water;

uncontrollable flows of natural gas, oil and formation water;

·

natural disasters, such as tropical storms, hurricanes and other adverse weather conditions;

natural disasters, such as tropical storms, hurricanes and other adverse weather conditions;

·

inability to obtain insurance at reasonable rates;

inability to obtain insurance at reasonable rates;

·

failure to receive payment on insurance claims in a timely manner, or for the full amount claimed;

failure to receive payment on insurance claims in a timely manner, or for the full amount claimed;

·

pipe, cement, subsea well or pipeline failures;

pipe, cement, subsea well or pipeline failures;

·

casing collapses or failures;

casing collapses or failures;

·

mechanical difficulties, such as lost or stuck oil field drilling and service tools;

mechanical difficulties, such as lost or stuck oil field drilling and service tools;

·

abnormally pressured formations or rock compaction; and

abnormally pressured formations or rock compaction; and

·

environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, encountering NORM, and discharges of brine, well stimulation and completion fluids, toxic gases, or other pollutants into the surface and subsurface environment.

environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, encountering NORM, and discharges of brine, well stimulation and completion fluids, toxic gases, or other pollutants into the surface and subsurface environment.


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:

·

injury or loss of life;

injury or loss of life;

·

damage to and destruction of property, natural resources and equipment;

damage to and destruction of property, natural resources and equipment;

·

pollution and other environmental damage;

pollution and other environmental damage;

·

clean-up responsibilities;

clean-up responsibilities;

·

regulatory investigation and penalties;

regulatory investigation and penalties;

·

suspension of our operations;

suspension of our operations;

·

repairs required to resume operations; and

repairs required to resume operations; and

·

loss of reserves.

loss of reserves.

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 jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.  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.

17


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:

·

severe weather, including tropical storms and hurricanes;

severe weather, including tropical storms and hurricanes;

·

delays or decreases in production, the availability of equipment, facilities or services;

delays or decreases in production, the availability of equipment, facilities or services;

·

changes in the status of pipelines that we depend on for transportation of our production to the marketplace;

changes in the status of pipelines that we depend on for transportation of our production to the marketplace;

·

delays or decreases in the availability of capacity to transport, gather or process production; and

delays or decreases in the availability of capacity to transport, gather or process production; and

·

changes in the regulatory environment.

changes in the regulatory environment.

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, net production of approximately 8.7 Bcfe was deferred as a result of damage caused primarily by Hurricane Ike in 2009 and Hurricane Isaac caused net production deferral of approximately 2.9 Bcfe in 2012.

As  In 2016, 2015 and 2014, we increase our onshore operations, we will be subjectexperienced production deferrals of lower amounts due to different risk factors that could impact loss of revenues or curtailment of production for these geographies.

Onshore oilother events, such as pipeline shut-ins and gas exploration and production operations share similar risk factors to offshore, but also have some different regulations, interpretation of regulations and enforcement by the particular state in which the operations are conducted. Until 2011, our experience has primarily been with offshore operations. We are subject to and must comply with the various state regulations and work effectively with the state agencies, and failure to do so may impact our operations.platform maintenance.


Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight rock formations. We utilize hydraulic fracturing techniques in connection with developing our properties in the Spraberry field and other onshore properties. The process involves the injection of water, sand or other proppants and chemicals under pressure into the rock formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. The EPA, however, recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWA Underground Injection Control Program and issued permitting guidance covering such activities in February 2015. In addition, the EPA has commenced a broad study of the potential environmental effects of hydraulic fracturing activities, and the agency has indicated that it expects to issue its study report in 2015. A number of other federal agencies, including the U.S. Department of Energy, Department of Interior, and White House Council on Environmental Quality, are also studying various aspects of hydraulic fracturing. The results of these studies could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. From time to time, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local governments have adopted, and other states and local governments are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations, including states in which we operate. For example, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to associated permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

18


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 against them.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:

·

acceptable prices for available properties;

acceptable prices for available properties;

·

amounts of recoverable reserves;

amounts of recoverable reserves;

·

estimates of future oil, NGLs and natural gas prices;

estimates of future crude oil, NGLs and natural gas prices;

·

estimates of future exploratory, development and operating costs;

estimates of future exploratory, development and operating costs;

·

estimates of the costs and timing of plugging and abandonment; and

estimates of the costs and timing of plugging and abandonment; and

·

estimates of potential environmental and other liabilities.

estimates of potential environmental and other liabilities.

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 is an important part of our business strategy.  We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.  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:

·

a significant increase in our indebtedness and working capital requirements;

a significant increase in our indebtedness and working capital requirements;

·

the inability to timely and effectively integrate the operations of recently acquired businesses or assets;

the inability to timely and effectively integrate the operations of recently acquired businesses or assets;

·

the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets, including liabilities arising from the operation of the acquired businesses or assets before our acquisition;

the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets, including liabilities arising from the operation of the acquired businesses or assets before our acquisition;

·

our lack of drilling history in the geographic areas in which the acquired business operates;

our lack of drilling history in the geographic areas in which the acquired business operates;

·

customer or key employee loss from the acquired business;

customer or key employee loss from the acquired business;

·

increased administration of new personnel;

increased administration of new personnel;

·

additional costs due to increased scope and complexity of our operations; and

additional costs due to increased scope and complexity of our operations; and

·

potential disruption of our ongoing business.

potential disruption of our ongoing business.

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.


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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, 2014.2016.  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 21 – 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, which prices are not reflective of the substantially lower prices realized in December 2014 and January 2015.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 rate 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.  The recent downturn inSustained 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 and various onshore 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.


20


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.

In some cases, our wells are tied back to platforms owned by partiesthird-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 partiesthird-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, 2014, 122016, 10 fields, accounting for approximately 12.86.9 Bcfe (or 12%8%) of our 20142016 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-establish production.

If third-party pipelines connected to our facilities become partially or fully unavailable to transport our crude oil and natural gas or oil, 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.  If any of these third-party pipelines become partially or fully unavailable to transport crude oil and natural gas, and oil, 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 2013, various pipelines were shut down causing production deferral of approximately 6.3 Bcfe.  Our Mississippi Canyon 506 field (Wrigley) was the field most significantly affected by the shutdowns in recent years, as it was shut down for all of 2013 and more than half of 2014.

Certain third-party pipelines have submitted or have made plans to submit requests to increase the fees they charge us to use these pipelines.  These increased fees could adversely impact our revenues or 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:

·

land use restrictions;

land use restrictions;

lease permit restrictions;


·

lease permit restrictions;

·

drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds;

·

spacing of wells;

spacing of wells;

·

unitization and pooling of properties;

unitization and pooling of properties;

·

safety precautions;

safety precautions;

·

operational reporting;

operational reporting;

·

reporting of natural gas sales for resale; and

21taxation.


·

taxation.

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

·

personal injuries;

personal injuries;

·

property and natural resource damages;

property and natural resource damages;

·

well site reclamation costs; and

well site reclamation costs; and

·

governmental sanctions, such as fines and penalties.

governmental sanctions, such as fines and penalties.

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 regulatory risks.business.  

Our operations may incur substantial liabilities to comply with environmental laws, endangered species laws and regulations.

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:

·

require the acquisition of a permit before drilling commences;

require the acquisition of a permit or other approval before drilling or other regulated activity commences;

·

restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

·

limit or prohibit exploration or drilling activities on certain lands lying within wilderness, wetlands and other protected areas or that may affect certain wildlife, including marine mammals; and

limit or prohibit exploration or drilling activities on certain lands lying within wilderness, wetlands and other protected areas or that may affect certain wildlife, including marine mammals; and

·

impose substantial liabilities for pollution resulting from our operations.

impose substantial liabilities for pollution resulting from our operations.

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

·

the assessment of administrative, civil and criminal penalties;

the assessment of administrative, civil and criminal penalties;

·

loss of our leases;

loss of our leases;

·

incurrence of investigatory or remedial obligations; and

incurrence of investigatory,  remedial or corrective obligations; and

·

the imposition of injunctive relief.

the imposition of injunctive relief, which could prohibit, limit or restrict our operations in a particular area.


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 liable 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.  Examples of recent proposed and final regulations include the following:

Ground-Level Ozone Standards.  In October 2015, the EPA issued a final rule under the Clean Air Act lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 to 70 parts per billion.  The EPA must make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017. Certain areas of the country currently in compliance with the former ground-level ozone NAAQS standard may be reclassified as non-attainment and such reclassification may make it more difficult to construct new or modify existing infrastructure to control air pollution in newly designated non-attainment areas to be in compliance with NAAQS.  State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.

Reduction of Methane Emissions by the Oil and Gas Industry.  In June 2016, the EPA published new source performance standards for methane and volatile organic compound emissions from certain new, modified and reconstructed equipment, processes and activities across the oil and natural gas sector.  The new standard includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural gas processing plants.  

Protected and Endangered Species.  We conduct operations on leases in areas where certain species are known to exist that are currently protected or could become protected under state and federal laws.  The presence of protected species, Marine Protection Areas, and other similar areas where we operate could cause increased costs arising from species or habitat protection measures, or could result in limitations or prohibitions on our exploration and production activities.

These and other regulatory changes could significantly increase our capital expenditures and operating costs or could result in delays to or limitations on our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows.  See Business – Regulation under Part I, Item 1 in this Form 10-K for a more detailed description of our environmental risks.and endangered species regulations.

The ONNR’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 Federal oil and gas leases.  The ONRR’s initiate 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 Federal 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.  The Company is not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material.


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

Under the EP Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1 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, the CFTC has 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, or the CFTC 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 greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

The EPA has determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes.  Based on its findings,At the federal level, no comprehensive climate change legislation has been implemented.  The EPA, however, has begun adopting and implementingadopted regulations under the federal Clean Air Act to restrict emissions of greenhouse gases under existing provisions ofgases.  For example, the CAA. The EPA has adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which imposes preconstruction and operating permit requirements ofon certain large stationary sources.sources that are already potential sources of certain other significant pollutant emissions.  The EPA also adopted rules requiring the monitoring and reporting of greenhouse gas emissions on an annual basis from specified large greenhouse gas emission sources in the United States, as well as certainincluding onshore and offshore oil and natural gas production facilities,facilities.  Federal agencies have also begun directly regulating emissions of methane, a greenhouse gas, from oil and natural gas operations.  For example, in June 2016, the EPA published new source performance standards for methane and volatile organic compound emissions from certain new, modified and reconstructed equipment, processes and activities across the oil and natural gas sector.  Compliance with these rules could result in increased compliance costs on an annual basis.our operations.

22


In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-halfa number of thestates and grouping of states have already taken legal measures to reduce emissions of greenhouse gases 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.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases 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 emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.  Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events.  Our offshore operations are particularly at risk from severe climatic events.  If any such affectsclimate effects were to occur, they could have an adverse effect on our business, financial condition and results of operations.  Please seeSee – Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.under this Item 1A.


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

In July 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “DF Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.  The DF Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the DF Act.  Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In October 2011,one of its rulemaking proceedings still pending under the DF Act, the CFTC issued regulations to seton December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts in the major energy marketsvarious commodities (including oil and gas) and for swaps that are their economic equivalents. The initialUnder the proposed rules on position limits, rule was vacated by the United States District Court for the Districtcertain types of Colombia in September 2012.  However, in November 2013, the CFTC proposed new rules that would placehedging transactions are exempt from these limits on the size of positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptionsthat may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain bonaenumerated “bona fide hedging transactions.hedging” transactions or positions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us in connection with covered derivatives activities to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements.  Although the Company expects to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge its 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 the Company uses for hedging.  In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margins.  Posting of collateral could impact liquidity and reduce cash available to the Company for its needs.  The DF Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.  

The full impact of the DF Act and related regulatory requirements upon the Company’s business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted.  The DF Act and 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, reduce our ability to monetize or restructure our existing derivative contracts, increase our exposure to less creditworthy counterparties or reduce liquidity.  If we reduce our use of derivatives as a result of the DF Act 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.

Finally, the DF Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.  Our revenues could therefore be adversely affected if a consequence of the DF Act is to lower commodity prices.  Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

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We own a non-producing platform in a highly regulated National Marine Sanctuary, which increases our compliance costs and subjects us to risk of significant fines and penalties if we do not maintain rigorous compliance.

We own a non-producing platform located in a National Marine Sanctuary in the Gulf of Mexico that is subject to special federal laws and regulations.  ThisWe have been working with BSEE for over four years to obtain a permit to plug, abandon and remediate the well and production platform, is not producing and will be plugged, abandoned and remediated accordingbut BSEE has refused to regulations.provide a decommissioning permit.  Unique regulations related to operations in the National Marine Sanctuary include, among other things, prohibition of drilling activities within certain protected areas, restrictions on substances that may be discharged, depths of discharge in connection with drilling and production activities and limitations on mooring of vessels.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief, including cessation of production from wells associated with this platform.


Restrictions on our ability to obtain water for our onshore operations may have an adverse effect on our financial condition, results of operations and cash available for distribution.

Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes.  Historically, operators in the Permian Basin have been able to purchase water from local land owners for use in their operations. According to the Lower Colorado River Authority, during 2011 Texas experienced the lowest inflows of water of any year in recorded history. Severe drought conditions persisted over the past several years in certain parts of Texas and are projected to continue in 2015. As a result, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically drill for oil and natural gas, which could have an adverse effect on our consolidated financial condition, results of operations, cash flows and reserves.

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 face security exposure,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 cyber-security exposure, from unauthorized access to our facilitiesconfidential 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 systems. This exposure includesviruses, or acts of vandalism or terrorism.  A breach could result in an interruption in our operations, unauthorized access to sensitive information; malicious damage to our facilities, infrastructure, and computer systems; malicious damage to third-party facilities, infrastructure, and computer systems; safety exposure for our employees and contractors; and disruptionspublication of our operations. Cyber-security exposures in particular are fluidconfidential business or proprietary information, unauthorized release of customer or employee data, violation of privacy or other laws and adaptive, and include malicious software, unauthorized accessexposure to confidential data and disruptions to operations that use computers and data systems.  Although we utilize various procedures and controls to reduce these exposures, there can be no assurances that these procedures and controls will be sufficient to prevent such events from occurring. We do not carry business interruption insurance.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 and Chief Executive Officer; Jamie L. Vazquez, our President; John D. Gibbons, our Senior Vice President and Chief Financial Officer; Thomas P. Murphy, our Senior Vice President and Chief Operations Officer; and Stephen L. Schroeder, our Senior Vice President and Chief Technical Officer; and Thomas F. Getten, our Vice President, General Counsel and Corporate Secretary,Officer, 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.  Please readSee Executive Officers of the Registrant under Part I following Item 3 in this Form 10-K for more information regarding our senior management team.

The unavailability or high cost of certain types of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

The U.S. oil and natural gas industry may experience shortages in the availability of certain types of drilling rigs or experience drilling rigs with high costs in relation to the recent change in price of crude oil and natural gas. This could delay or adversely affect our exploration and development operations, which could have a material adverse effect on our business, financial condition or results of operations. If the unavailability or high cost of rigs, equipment, supplies or personnel were particularly severe in the offshore waters of the U.S. Gulf of Mexico or Texas, we could be materially and adversely affected because our operations and properties are concentrated in those areas.

24


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.

Legislation has beenIn past years, legislation was proposed that would if enacted into law, makehave made significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax preferencesprovisions currently available to oil and gas exploration and production companies.  These changes include,Such legislative proposals have included, but are 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, (iii) the elimination of the deduction for United Statescertain domestic production activities, and (iv) 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 tax reform legislation, to accompany lower federal income tax rates.  Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and gas companies.  It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective.take effect.  The passage of thisany legislation as a result of these proposals or any other similar changes in U.S. federal income tax lawlaws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and production,us, and any such changechanges could have a negativean adverse effect on theour financial position, results of our operations.operations and cash flows.

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 resulting in downgrades to credit ratings of energy merchants affected the liquidity of several of our purchasers.

Risks Related to Financings

Adverse changes in the financial and credit markets could negatively impact our economic growth. In addition, the continuation of the current commodity price environment, or further declines of oil, NGLs and natural gas prices can affect our ability to obtain funding on acceptable terms or under our current credit facility. These impacts may hinder or prevent us from meeting our future capital needs and may restrict or limit our ability to increase reserves of oil and natural gas.

The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises.  These limitations in the capital markets may affect our ability to grow and limit our ability to replace our reserves of oil and gas.

During 2012 and 2011, world financial markets were affected by the instability of the Euro and the uncertainty of some Euro-based countries to repay their debt. In addition, one credit agency downgraded the debt of the U.S. government. These types of events bring uncertainty to the financial markets and may produce volatility and may decrease financing availability. For example, in 2009, the global financial markets and economic conditions were severely distressed. There were concerns, both with respect to bank failures and bank liquidity, as to whether our banks would be able to meet their commitments under credit arrangements in place during that time. These concerns led to very few financing transactions being completed.

Our revolving bank credit facility is subject to a semi-annual borrowing base re-determination, and available credit could be reduced or eliminated at the sole discretion of the banks within the facility.  Our borrowing base may decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves, lending requirements or regulations, or the issuance of new indebtedness.  We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms.

If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due and could be required to repay any borrowings in excess of the redetermined borrowing base, or we may be unable to implement our exploratory and development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

25


We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may become insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay off our outstanding indebtedness. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or initiatives by our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our current or any future debt obligations, we may have to undertake alternative financing plans, such as:

·

refinancing or restructuring our debt;

·

selling assets;

·

reducing or delaying capital investments; and

·

seeking to raise additional capital.

Any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, financial condition and results of operations.

Our debt obligations could have important consequences. For example, they could:

·

increase our vulnerability to general adverse economic and industry conditions;

·

limit our ability to fund future working capital requirements and capital expenditures, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets;

·

limit our opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt obligations or to comply with any restrictive terms of our debt obligations;

·

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

·

impair our ability to obtain additional financing in the future; and

·

place us at a competitive disadvantage compared to our competitors that have less debt.

In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders will have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Assuming continuing oil and gas prices near levels realized in December 2014 and January 2015, we likely will be out of compliance with certain of our financial ratio maintenance covenants under our Credit Agreement sometime during 2015.  We intend to engage the lenders under the Credit Agreement in discussions regarding amending our financial ratio covenants at such time as our borrowing base is next redetermined, but we can provide no assurance that we will be successful in obtaining such an amendment.  While we believe we will obtain the appropriate covenant relief, if we are unable to obtain such an amendment from our lenders, we believe that we can find alternative financing, albeit at a higher cost, and we may have to reduce our cash outlays further for capital expenditures and other activities until such time as market conditions recover. Realization of any of these factors could adversely affect our financial condition, results of operations and cash flows.

26


Risks Related to Our Principal Shareholder, Tracy W. Krohn

We will be controlled by Tracy W. Krohn as long as he owns a majority of our outstanding common stock, and other shareholders will be unable to affect the outcome of shareholder voting during that time. This control may adversely affect the value of our common stock and inhibit potential changes of control.

Tracy W. Krohn owns and controls 39,876,501 shares of our common stock, representing approximately 52.5% of our voting interests as of February 15, 2015. As a result, Mr. Krohn has the ability to control the outcome of matters that require a simple majority of shareholders for approval and other investors, by themselves, will not be able to affect the outcome of virtually any shareholder vote. Mr. Krohn, subject to any duty owed to our minority shareholders under Texas law, is able to control all matters affecting us, including:

·

the composition of our board of directors and, through it, any determination with respect to our business direction and policies, including the appointment and removal of officers;

·

the determination of incentive compensation, which may affect our ability to retain key employees;

·

any determinations with respect to mergers or other business combinations;

·

our acquisition or disposition of assets;

·

our financing decisions and our capital raising activities;

·

our payment of dividends on our common stock, subject to the restrictions in our Credit Agreement and indentures; and

·

amendments to our amended and restated articles of incorporation or bylaws.

Mr. Krohn is generally not prohibited from selling a controlling interest in us to a third party. In addition, his concentrated control could discourage others from initiating any potential merger, takeover or other change of control transaction that might be beneficial to our business or shareholders. As a result, the market price of our common stock could be adversely affected.

Due to Mr. Krohn’s ownership and control, we are exempted from many New York Stock Exchange (“NYSE”) corporate governance rules, and, as a result, our other shareholders may not have the protections set forth in those rules, particularly in the event of conflicts of interest with Mr. Krohn.

Mr. Krohn owns a majority of our common stock, and, therefore, we are a “controlled company” within the meaning of the rules of the NYSE. As such, we are not required to comply with certain corporate governance rules of the NYSE that would otherwise apply to us as a listed company on that exchange. These rules are generally intended to increase the likelihood that boards will make decisions in the best interests of shareholders. Should the interests of Mr. Krohn differ from those of other shareholders, the other shareholders will not be afforded the protections of having all of the other directors on the board being independent from our principal shareholder.

Item 1B. Unresolved Staff Comments

None.

27


Item


Item 2. Properties

 

Our producing fields are located in federal and state waters in the Gulf of Mexico Alabama and Texas.  The offshore fields are found in water depths ranging from less than 10 feet up to 7,2007,300 feet.  The reservoirs in our offshore fields are generally characterized as having high porosity and permeability, which typically results inwith high initial production rates.  The reservoirs in our onshore fields are generally characterized as having low porosity and permeability and require stimulation and artificial lift to produce.  The following map provides the locations of our 10 largest fields as of December 31, 2014,2016, based on quantities of proved reserves on an energy equivalent basis.  At December 31, 2014,2016, these fields accounted for approximately 82%83% of our proved reserves.

 



28


The following table provides information for our 10 largest fields in descending orderdetermined using quantities of proved net reserves on an energy equivalent basis as of December 31, 2014, based on quantities on an energy equivalent basis.2016.  Deepwater refers to acreage in over 500 feet of water.  Our interests in several of our offshore fields are owned by our wholly-owned subsidiary, W & T Energy VI, LLC.  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.

 

 

 

Percent

Oil and

NGLs of

 

 

2014 Average Daily

Equivalent Sales Rate

(Boe/d) (1)

 

 

2014 Average Daily

Equivalent Sales Rate

(Mcfe/d) (1)

 

 

 

Percent

Oil and

NGLs of

 

 

2016 Average Daily

Equivalent Sales Rate

(Boe/d) (1)

 

Field Name

Field

Category

 

Net

Reserves (1)

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Field

Category

 

Proved

Reserves (1)

 

 

Gross

 

 

Net

 

Spraberry (Yellow Rose)

Onshore

 

 

89

%

 

 

4,502

 

 

 

3,408

 

 

 

27,013

 

 

 

20,450

 

Ship Shoal 349 (Mahogany)

Shelf

 

 

81

%

 

 

8,851

 

 

 

7,388

 

 

 

53,105

 

 

 

44,330

 

Shelf

 

 

84

%

 

 

5,909

 

 

 

4,924

 

Fairway

Shelf

 

 

26

%

 

 

5,253

 

 

 

4,305

 

 

 

31,515

 

 

 

25,830

 

Shelf

 

 

23

%

 

 

6,237

 

 

 

4,678

 

Viosca Knoll 783 (Tahoe/SE Tahoe)

Deepwater

 

 

26

%

 

 

6,292

 

 

 

4,668

 

 

 

37,753

 

 

 

28,007

 

Deepwater

 

 

27

%

 

 

4,974

 

 

 

3,383

 

Miss. Canyon 782 (Dantzler)

Deepwater

 

 

75

%

 

 

19,888

 

 

 

3,232

 

Miss. Canyon 698 (Big Bend)

Deepwater

 

 

93

%

 

 

18,251

 

 

 

2,966

 

Main Pass 108

Shelf

 

 

18

%

 

 

3,728

 

 

 

2,906

 

Miss. Canyon 243 (Matterhorn)

Deepwater

 

 

74

%

 

 

4,832

 

 

 

4,832

 

 

 

28,989

 

 

 

28,989

 

Deepwater

 

 

81

%

 

 

2,260

 

 

 

2,260

 

Main Pass 108

Shelf

 

 

18

%

 

 

2,862

 

 

 

2,356

 

 

 

17,173

 

 

 

14,133

 

Miss. Canyon 782 (Dantzler) (2)

Deepwater

 

 

73

%

 

 

 

 

 

 

 

 

 

 

 

 

Ewing Bank 910

Deepwater

 

 

67

%

 

 

3,233

 

 

 

1,408

 

Brazos A133

Shelf

 

 

 

 

 

2,587

 

 

 

1,078

 

Viosca Knoll 823 (Virgo)

Deepwater

 

 

39

%

 

 

2,094

 

 

 

1,303

 

 

 

12,567

 

 

 

7,820

 

Deepwater

 

 

30

%

 

 

1,605

 

 

 

994

 

East Cameron 321

Shelf

 

 

96

%

 

 

1,263

 

 

 

931

 

 

 

7,580

 

 

 

5,583

 

Main Pass 283

Shelf

 

 

40

%

 

 

1,636

 

 

 

1,336

 

 

 

9,819

 

 

 

8,014

 

 

(1)

The conversions to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bblbarrel of crude oil, condensate or NGLs (totals may not compute due to rounding).  The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

 

(2)

There has been no production in this field as of December 31, 2014.

Volume measurements:

BblMBoeone thousand barrels of oil equivalent

Mcf – Thousand cubic feet

Boe/d – barrel of oil equivalent per day

Mcfe/d – Thousand cubic feet of gas equivalent per day


29


Our Fields

On December 31, 2014,2016, 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 Spraberry field (Yellow Rose) is located in the Permian Basin in West Texas and: the Ship Shoal 349 field (Mahogany) is located on the conventional shelf in the Gulf of Mexico. Below is a descriptionMexico and the Fairway Field, located in the Mobile Bay area of Alabama, which includes the associated Yellowhammer gas processing plant located onshore in Alabama.  Following are descriptions of these fields.

Spraberry Field (Yellow Rose).

The Spraberry field is located in the Permian Basin in West Texas. We acquired a 100% working interest in approximately 21,900 net acres in connection with the acquisition of properties (the ‘Opal Properties”) from Opal Resources LLC and Opal Resources Operating LLC (collectively, “Opal”) in May 2011.  In separate transactions, we acquired approximately 9,500 net acres in 2011 and approximately 2,200 net acres in 2013. We are the operator for these properties.  The Spraberry field was discovered in 1935 and extends over several counties in West Texas comprising about 1.6 million acres. The field is 150 miles long and 75 miles wide, and it has undergone much change and expansion over the years, both aerially and vertically. The correlative interval is now over 3,500 feet thick and includes the Clearfork, Upper Spraberry, Lower Spraberry, Dean, and Wolfcamp formations. These formations are correlative over the area but are lenticular in nature and vary in thickness, porosity, and permeability even over short distances. The general completion technique includes hydraulic fracturing and installation of sucker rod pumps. During 2014, we drilled 38 wells, which included nine horizontal wells.  During 2013, we drilled 32 wells, which included five horizontal wells.  During 2012, we drilled 64 wells, which included one horizontal well. Cumulative field production through 2014 is approximately 6.4 MMBoe (38.3 Bcfe) from our wells. In 2015, we plan to drill one horizontal well. Total proved reserves associated with our interest in the Spraberry field were 37.3 MMBoe (223.6 Bcfe) at December 31, 2014, 38.2 MMBoe (229.3 Bcfe) at December 31, 2013 and 31.6 MMBoe (189.8 Bcfe) at December 31, 2012.

The following presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Spraberry field over the past three years.

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Net Sales:

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

1,000

 

 

 

1,075

 

 

 

751

 

NGLs (MBbls)

 

141

 

 

 

170

 

 

 

103

 

Natural gas (MMcf)

 

614

 

 

 

575

 

 

 

376

 

Total oil equivalent (MBoe)

 

1,244

 

 

 

1,341

 

 

 

916

 

Total natural gas equivalents (MMcfe)

 

7,464

 

 

 

8,047

 

 

 

5,496

 

Average daily equivalent sales (Boe/day)

 

3,408

 

 

 

3,674

 

 

 

2,503

 

Average daily equivalent sales (Mcfe/day)

 

20,450

 

 

 

22,046

 

 

 

15,016

 

Average realized sales prices:

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

$

85.53

 

 

$

93.75

 

 

$

88.11

 

NGLs ($/Bbl)

 

36.84

 

 

 

35.86

 

 

 

36.94

 

Natural gas ($/Mcf)

 

3.67

 

 

 

3.48

 

 

 

2.50

 

Oil equivalent ($/Boe)

 

74.77

 

 

 

81.21

 

 

 

77.38

 

Natural gas equivalent ($/Mcfe)

 

12.46

 

 

 

13.54

 

 

 

12.90

 

Average production costs (1):

 

 

 

 

 

 

 

 

 

 

 

Oil equivalent ($/Boe)

$

17.66

 

 

$

17.66

 

 

$

18.92

 

Natural gas equivalent ($/Mcfe)

 

2.94

 

 

 

2.94

 

 

 

3.15

 

(1)

Includes lease operating expenses and gathering and transportation costs.

Volume measurements:

Boe – barrel of oil equivalent

Mcf – thousand cubic feet

MBbls – thousand barrels for crude oil, condensate or NGLs

MMcf – million cubic feet

MBoe – thousand barrels of oil equivalent

MMcfe – million cubic feet equivalent



30


Ship Shoal 349 Field (Mahogany).

Ship Shoal 349 field is located off the coast of Louisiana, approximately 235 miles southeast of New Orleans, in 375 feet of water.Louisiana.  The field area covers Ship Shoal blocks 349 and 359, with a single production platform on Ship Shoal block 349.349 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.  Cumulative field production through 20142016 is approximately 37.343.5 MMBoe gross (223.6 Bcfe gross).gross.  This field is a sub-salt development with eight productive horizons below salt at depths up to 17,00019,000 feet.  In 2010, we developed a reservoir simulation model to determine the most optimal future development plan (the “2010 Development Plan”).  As a result, in 2011, we drilled and completed one development well and one exploration well.  In 2012, two additional wells were sidetracked, one well was drilled and completed, and another well was drilled to target depth.  In 2013, the well reaching target depth in 2012 was completed, one well was drilled and completed and we had one well being drilled.  In 2014, the well being drilled in 2013 was completed and we drilled and completed another well.  A third well was spud at year end 2014, and,drilling was suspending in January 2015, drilling on this well was suspended at an intermediate casing point pending higher crude oil prices.resumed during 2016 and completion occurred in the first quarter of 2017.  All of the wells drilled under the 2010 Development Plan have been successful.  Total proved reserves associated with our interest in this field were 18.819.8 MMBoe (112.9 Bcfe) at December 31, 2014, 22.92016, 22.3 MMBoe (137.7 Bcfe) at December 31, 20132015, and 22.718.8 MMBoe (136.3 Bcfe) at December 31, 2012.2014.

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

Year Ended December 31,

 

Year Ended December 31,

 

2014

 

 

2013

 

 

2012

 

2016

 

 

2015

 

 

2014

 

Net Sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

2,020

 

 

 

1,943

 

 

 

960

 

 

1,332

 

 

 

2,313

 

 

 

2,020

 

NGLs (MBbls)

 

104

 

 

 

90

 

 

 

85

 

 

159

 

 

 

97

 

 

 

104

 

Natural gas (MMcf)

 

3,433

 

 

 

3,328

 

 

 

2,108

 

 

1,871

 

 

 

3,764

 

 

 

3,433

 

Total oil equivalent (MBoe)

 

2,697

 

 

 

2,589

 

 

 

1,397

 

 

1,802

 

 

 

3,037

 

 

 

2,697

 

Total natural gas equivalents (MMcfe)

 

16,181

 

 

 

15,533

 

 

 

8,380

 

 

10,812

 

 

 

18,221

 

 

 

16,181

 

Average daily equivalent sales (Boe/day)

 

7,388

 

 

 

7,093

 

 

 

3,816

 

 

4,924

 

 

 

8,320

 

 

 

7,388

 

Average daily equivalent sales (Mcfe/day)

 

44,330

 

 

 

42,556

 

 

 

22,896

 

 

29,543

 

 

 

49,922

 

 

 

44,330

 

Average realized sales prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

$

87.21

 

 

$

98.69

 

 

$

102.55

 

$

31.97

 

 

$

42.73

 

 

$

87.21

 

NGLs ($/Bbl)

 

46.46

 

 

 

43.24

 

 

 

41.74

 

 

17.88

 

 

 

21.27

 

 

 

46.46

 

Natural gas ($/Mcf)

 

4.40

 

 

 

3.72

 

 

 

2.78

 

 

2.38

 

 

 

2.86

 

 

 

4.40

 

Oil equivalent ($/Boe)

 

72.73

 

 

 

80.39

 

 

 

77.24

 

 

27.67

 

 

 

36.77

 

 

 

72.73

 

Natural gas equivalent ($/Mcfe)

 

12.12

 

 

 

13.40

 

 

 

12.87

 

 

4.61

 

 

 

6.13

 

 

 

12.12

 

Average production costs (1):

 

 

 

 

 

 

 

 

 

 

 

Average production costs: (1)

 

 

 

 

 

 

 

 

 

 

 

Oil equivalent ($/Boe)

$

4.12

 

 

$

3.68

 

 

$

6.27

 

$

5.16

 

 

$

3.30

 

 

$

4.12

 

Natural gas equivalent ($/Mcfe)

 

0.69

 

 

 

0.61

 

 

 

1.05

 

 

0.86

 

 

 

0.55

 

 

 

0.69

 

(1)

Includes lease operating expenses and gathering and transportation costs.

Volume measurements:

 

 

Boe – barrel of oil equivalent

 

Mcf – thousand cubic feet

MBbls – thousand barrels for crude oil, condensate or NGLs

 

MMcf – million cubic feet

MBoe – thousand barrels of oil equivalent

 

MMcfe – million cubic feet of gas equivalent

 



31


The following is a description of the remainder of our top 10 properties, measured by proved reserves at December 31, 2014, three of which are located on the conventional shelf and five are located in the deepwater. We do not believe that individually any of these properties are of major significance (each has proved reserves which comprise less than 15% of our year-end total proved reserves, calculated on a natural gas equivalent basis).

Fairway Field.

The Fairway fieldField is comprised of Mobile Bay Area blocks 113 (Alabama State Lease #0531) and 132 (Alabama State Lease #0532) and located in 25 feet of water, approximately 35 miles south of Mobile, Alabama.  We acquired our initial 64.3% working interest, along with operatorship, in the Fairway field,Field and associated Yellowhammer gas processing plant, from Shell Offshore, Inc. (“Shell”) in August 2011 and acquired the remaining working interest of 35.7% in September 2014.  The field was discovered in 1985 with Well 113 #1 (now called JA).  Development drilling began in 1990 and was completed in 1991 with the addition of four wells, each drilled from separate surface locations.  The five producing wells came on line in late 1991.  As of December 31, 2014,2016, six wells have been drilled, one of which was a replacement well.  Cumulative field production through 20142016 is approximately 125.4129.9 MMBoe gross (752.3 Bcfe gross).gross.  This field is a Norphlet sand dune trend development with one producing horizon at an approximate depth of 21,300 feet.  During December 2014, production fromTotal proved reserves associated with our interest in this field net towere 13.7 MMBoe at December 31, 2016, 14.0 MMBoe at December 31, 2015, and 14.6 MMBoe at December 31, 2014.

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Net Sales:

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

9

 

 

 

10

 

 

 

7

 

NGLs (MBbls)

 

400

 

 

 

319

 

 

 

415

 

Natural gas (MMcf)

 

7,817

 

 

 

8,277

 

 

 

6,899

 

Total oil equivalent (MBoe)

 

1,712

 

 

 

1,708

 

 

 

1,571

 

Total natural gas equivalents (MMcfe)

 

10,272

 

 

 

10,250

 

 

 

9,428

 

Average daily equivalent sales (Boe/day)

 

4,678

 

 

 

4,680

 

 

 

4,305

 

Average daily equivalent sales (Mcfe/day)

 

28,065

 

 

 

28,083

 

 

 

25,830

 

Average realized sales prices:

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

$

41.15

 

 

$

47.22

 

 

$

101.94

 

NGLs ($/Bbl)

 

16.72

 

 

 

18.97

 

 

 

27.41

 

Natural gas ($/Mcf)

 

2.42

 

 

 

2.60

 

 

 

4.07

 

Oil equivalent ($/Boe)

 

17.32

 

 

 

16.40

 

 

 

25.53

 

Natural gas equivalent ($/Mcfe)

 

2.89

 

 

 

2.73

 

 

 

4.26

 

Average production costs: (1)

 

 

 

 

 

 

 

 

 

 

 

Oil equivalent ($/Boe)

$

7.95

 

 

$

8.96

 

 

$

10.73

 

Natural gas equivalent ($/Mcfe)

 

1.32

 

 

 

1.49

 

 

 

1.79

 

(1)

Includes lease operating expenses and gathering and transportation costs.

Volume measurements:

Boe – barrel of oil equivalent

Mcf – thousand cubic feet

MBbls – thousand barrels for crude oil, condensate or NGLs

MMcf – million cubic feet

MBoe – thousand barrels of oil equivalent

MMcfe – million cubic feet of gas equivalent



The following is a description of the remainder of our interest, averaged 47 Bblstop 10 properties, measured by proved reserves at December 31, 2016, two of which are located on the conventional shelf and six of which are located in the deepwater.  We do not believe that individually any of these properties are of major significance (each has proved reserves which comprise less than 15% of our year-end total proved reserves, calculated on a barrel of oil per day, 1,696 Bbls of NGLs per day and 25.9 MMcf of natural gas per day, for total production of 6,065 Boe per day (36.4 MMcfe per day)equivalent basis).

Viosca Knoll 783 Field (Viosca Knoll 783 Lease (Tahoe) and Viosca Knoll 784 Lease (SE Tahoe)).  The Viosca Knoll 783 field is located off the coast of Louisiana, approximately 140 miles southeast of New Orleans, Louisiana in 1,500 to 1,700 feet of water.  The field area covers Viosca Knoll blocks 783 and 784, with subsea tiebacks to two platforms in Main Pass 252.  Shell discovered the Tahoe prospect in 1984 and the SE Tahoe prospect in 1996.  We acquired a 70% working interest in the Tahoe lease and a 100% working interest in the SE Tahoe lease from Shell in 2010.  We are the operator forof these properties.  Cumulative field production through 20142016 is approximately 96.3100.1 MMBoe gross (577.6 Bcfe gross).gross.  The Tahoe prospect is a supra-salt (above the salt layer) development with two productive horizons at depths ranging to 10,300 feet.  The SE Tahoe prospect is also a supra-salt development with one productive horizon at a depth of 9,325 feet.  As of December 31, 2014,2016, 16 wells have been drilled at the Tahoe prospect, eight of which have been successful and one successful well has been drilled at the SE Tahoe prospect.  During December 2014,2016, production from this field, net to our interest, averaged 212 Bbls125 barrels of crude oil per day, 1,362 Bbls977 barrels of NGLs per day and 18.8 MMcf12,989 Mcf of natural gas per day, for total production of 4,7003,267 Boe per day (28.2 MMcfe per day).

Mississippi Canyon 243 Field (Matterhorn).  Mississippi Canyon 243 field is located off the coast of Louisiana, approximately 100 miles southeast of New Orleans, in 2,552 feet of water.  The field area covers Mississippi Canyon block 243, with a single floating, tension leg production platform on Mississippi Canyon block 243.  Société Nationale Elf Aquitaine discovered the field in 2002.  We acquired a 100% working interest in the field from Total E&P USA Inc. (“Total E&P”) in 2010.  Cumulative field production through 2014 is approximately 31.7 MMBoe gross (190.4 Bcfe gross).  This field is a supra-salt development with 17 productive horizons at depths ranging to 9,850 feet.  As of December 31, 2014, 30 wells have been drilled, 13 of which have been successful.  During 2013, we drilled one well, which began production in 2013, and we drilled another well, that had reached target depth but had not yet been completed. During 2014, the well that had reached target depth in 2013 was completed.  During December 2014, production from this field, net to our interest, averaged 1,553 Bbls of oil per day, 463 Bbls of NGLs per day and 12.2 MMcf of natural gas per day, for total production of 4,051 Boe per day (24.3 MMcfe per day).

Main Pass 108 Field.  Main Pass 108 field consists of Main Pass blocks 107, 108 and 109.  This field is located off the coast of Louisiana approximately 50 miles east of Venice in 50 feet of water.  We acquired our working interests in these blocks, which range from 33% to 100%, in a transaction with Kerr-McGee Oil and Gas Corporation and we are the operator for the majority of these properties.  The field produces from a number of low relief, predominantly stratigraphically trapped sands.  The productive interval ranges in age from Upper Miocene Big A through Middle Miocene Big Hum.  As of December 31, 2014, 48 wells have been drilled in this field, 30 of which were successful.  Cumulative field production through 2014 is approximately 53.1 MMBoe gross (318.7 Bcfe gross).  One new well reached target depth in 2011 and began production in 2012.  In addition, one workover was performed in 2012.  In 2013, we drilled and completed one well, which began production during 2013.  During December 2014, production from this field, net to our interest, averaged 118 Bbls of oil per day, 178 Bbls of NGLs per day and 10.7 MMcf of natural gas per day, for total production of 2,086 Boe per day (12.5 MMcfe per day).day.

Mississippi Canyon 782 Field (Dantzler).   Mississippi Canyon 782 field is located off the coast of Louisiana, approximately 160 miles southeast of New Orleans, Louisiana in 6,600 feet of water.  The field area covers Mississippi Canyon block 782 and 738.  We have a 20% working interest, which is operated by Noble Energy.  We, along with Noble Energy, discovered the field in 2013.  This field is currently under developmentdeveloped as a subsea tieback to the Thunderhawk Field approximately 12 miles to the northwest.  The field is a three-way closure trapped against a salt wall.  There arewith two pay horizons, the upper Miocene U5 and U6 sands.age pay horizons.  Cumulative field production through 2016 is approximately 3.4 MMBoe gross.  As of December 31, 2014,2016, two wells have been drilled, both of which have been successful, with one well beginning production in the fourth quarter of 2015 and the other well beginning production in the first quarter of 2016.  During December 2016, production from this field, net to our interest, averaged 1,863 barrels of crude oil per day, 91 barrels of NGLs per day and 1,432 Mcf of natural gas per day, for total production of 2,193 Boe per day.  

Mississippi Canyon 698 Field (Big Bend).  Mississippi Canyon 698 is approximately 160 miles southeast of New Orleans, Louisiana in 7,221 feet of water.  The field area covers portions of Mississippi Canyon blocks 697, 698, and 742.  We have a 20% working interest, which is operated by Noble Energy.  We, along with Noble Energy, discovered the field in 2012.  This field is a subsea tieback to the Thunderhawk Field approximately 18 miles to the northwest.  Cumulative field production through 2016 is approximately 6.9 MMBoe gross.  The field is a supra-salt development with two productive horizons at depths ranging from 14,660’ to 15,533’ total vertical depth.  As of December 31, 2016, one well has been drilled and successful, with the well beginning production in the fourth quarter of 2015.  During December 2016, production from this field, net to our interest, averaged 2,187 barrels of crude oil per day, 53 barrels of NGLs per day and 983 Mcf of natural gas per day, for total production of 2,404 Boe per day.

Main Pass 108 Field.  Main Pass 108 field consists of Main Pass blocks 107, 108 and 109.  This field is located off the coast of Louisiana approximately 50 miles east of Venice, Louisiana in 50 feet of water.  We acquired our working interests in these blocks, which range from 33% to 100%, in a transaction with Kerr-McGee Oil and Gas Corporation (“Kerr-McGee”) and we are the operator of this field.  The field produces from a number of low relief, predominantly stratigraphically trapped sands.  The productive interval ranges in age from Upper Miocene Big A through Middle Miocene Big Hum.  As of December 31, 2016, 48 wells have been drilled in this field, 30 of which were successful.  Cumulative field production through 2016 is approximately 47.3 MMBoe gross.  One new well reached target depth in 2011 and began production in 2012.  In addition, one workover was performed in 2012.  In 2013, we drilled and completed one well, which began production during 2013.  During December 2016, production from this field, net to our interest, averaged 211 barrels of crude oil per day, 317 barrels of NGLs per day and 17,190 Mcf of natural gas per day, for total production of 3,393 Boe per day.


Mississippi Canyon 243 Field (Matterhorn).  Mississippi Canyon 243 field is located off the coast of Louisiana, approximately 100 miles southeast of New Orleans, Louisiana in 2,552 feet of water.  The field area covers Mississippi Canyon block 243, with a single floating, tension leg production platform.  Société Nationale Elf Aquitaine discovered the field in 2002.  We acquired a 100% working interest in the field from Total E&P USA Inc. (“Total E&P”) in 2010.  Cumulative field production through 2016 is approximately 35.9 MMBoe gross.  This field is a supra-salt development with 17 productive horizons, with the maximum depth of 9,850 feet.  As of December 31, 2016, 30 wells have been drilled, 13 of which have been successful.  During 2013, we drilled one well, which began production in 2013.  We also began drilling another well in 2013, which was completed during 2014.  During December 2016, production from this field, net to our interest, averaged 1,261 barrels of crude oil per day, 193 barrels of NGLs per day and 3,151 Mcf of natural gas per day, for total production of 1,979 Boe per day.

Ewing Bank 910.  Ewing Bank 910 is located approximately 68 miles off the Louisiana coast in 560 feet of water.  The field area covers Ewing Bank blocks 910 and 954, and South Timbalier block 320 and 311.  Kerr-McGee discovered the field in 1996.  We own a 100% working interest in the main field pays, having acquired a 40% working interest from Kerr-McGee in 2006 and the remaining 60% from Petrobras America Inc. in 2014.  Three recently successful deep wells are subject to a 50% working interest with Walter Oil and Gas Corporation.  A single production platform is located on Block 910.  Cumulative field production through 2016 is approximately 16.0 MMBoe gross.  Production occurs from Pliocene and upper Miocene channel/levee sands set up by a combination of stratigraphic and structural traps.  A newly acquired wide angle azimuth seismic data set is expected to help confirm several recently identified drilling opportunities in the field area.  Since its discovery, 11 wells have been drilled, of which bothnine were successful.  During December 2016, production from this field, net to our interest, averaged 994 barrels of crude oil per day, 209 barrels of NGLs per day and 3,722 Mcf of natural gas per day, for total production of 1,824 Boe per day.

Brazos A-133 Field.  Brazos A-133 field is located 85 miles east of Corpus Christi, Texas in 200 feet of water.  The field was discovered in 1978 by Cities Service Oil Company with production commencing in the same year.  There are five active platforms, three of which are production platforms.  Cumulative field production through 2016 is approximately 154.1 MMBoe gross from the Middle Miocene Tex W and Big Hum sections.  The bulk of the production is from the Big Hum CM-7 sand, which is a 4-way closure downthrown to the Corsair Fault and bisected by antithetic faults.  The top of the CM-7 sand is at a subsea depth of 12,000 feet.  Since its discovery, 22 wells have been successfuldrilled, of which 17 were successful.  We own a 50% working interest, of which 25% was obtained through a transaction with Kerr-McGee in 2006 and are targetedan additional 25% was obtained through a transaction with Chevron U.S.A. Inc. in 2015.  During December 2016, production from this field, net to our interest, averaged 3 barrels of crude oil per day and 6,291 Mcf of natural gas per day, for firsttotal production in the first quarter of 2016.1,052 Boe per day.

32


Viosca Knoll 823 Field (Virgo).  Viosca Knoll 823 field is located off the coast of Louisiana, approximately 125 miles southeast of New Orleans, Louisiana in 1,014 feet of water.  The field area covers Viosca Knoll block 823 and Viosca Knoll block 822, with a single fixed leg production platform on Viosca Knoll block 823.  Total E&P discovered the field in 1997.  We acquired a 64% working interest in the field from Total E&P in 2010 and we are the operator forof this property.  Cumulative field production through 20142016 is approximately 21.722.8 MMBoe gross (130.4 Bcfe gross).gross.  This field is a supra-salt development with 17 productive horizons at depths ranging to 13,335 feet.  As of December 31, 2014,2016, 14 wells have been drilled, 10 of which have been successful.  During December 2014,2016, production from this field, net to our interest, averaged 128 Bbls381 barrels of crude oil per day, 145 Bbls88 barrels of NGLs per day and 5.2 MMcf8,341 Mcf of natural gas per day, for total production of 1,1371,859 Boe per day (6.8 MMcfe per day).day.


East Cameron 321. East Cameron 321 field is located approximately 97 miles off the Louisiana coastline in 225 feet of water.  Two production facilities, the “A” and “B” platforms, are located on the block.  This field has multiple sands that are productive in faulted, structural traps.  These sands are Pleistocene Ang B in age.  As of December 31, 2014, 76 wells have been drilled of which 58 have been successful.  In 2014 we drilled and completed one well.  Cumulative field production through 2014 is approximately 94.6 MMBoe gross (567.3 Bcfe) gross.  We own a 100% working interest in the field and are the operator of the field.  This field is producing at a restricted rate as a result of a damaged departing gas sales line.  During January to October 2014, which was prior to the departing gas sales line damage, production from this field, net to our interest, averaged 890 Bbls of oil per day and 0.2 MMcf of natural gas per day, for total production of 928 Boe per day (5.6 MMcfe per day).

Main Pass 283. Main Pass 283 field consists of Main Pass blocks 284, 279 and 283 and Viosca Knoll Block 734.  This field is located off the coast of Louisiana approximately 75 miles east of Venice in 315 feet of water.  We acquired our working interests in these blocks in 2003, which range from 50% to 100%, in a transaction with ConocoPhillips.  The field produces from a number of low relief, predominantly stratigraphically trapped sands.  The productive interval ranges in age from Upper Miocene Big A through Middle Miocene Cristellaria I.  Cumulative field production through 2014 is approximately 24.3 MMBoe gross (145.8 Bcfe gross).  As of December 31, 2014, 12 wells have been drilled in this field, of which 10 were successful.  During December 2014, production from this field, net to our interest, averaged 398 Bbls of oil per day, 195 Bbls of NGLs per day and 3.9 MMcf of natural gas per day, for total production of 1,251 Boe per day (7.5 MMcfe per day).

Proved Reserves

Our proved reserves were estimated by NSAI, our independent petroleum consultant, and amounts provided in this Annual Report on Form 10-K are consistent with filings we make with other federal agencies.  Our proved reserves as of December 31, 20142016 are summarized below and the mix by product was 52%44% oil, 13%11% NGLs and 35%45% natural gas determined using the energy-equivalent ratio noted below.  

 

 

 

 

 

 

 

 

 

 

 

 

Total Energy-Equivalent Reserves (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Energy-Equivalent Reserves (2)

 

 

 

 

 

Classification of Proved Reserves (1)

Oil

(MMBbls)

 

 

NGLs

(MMBbls)

 

 

Natural Gas

(Bcf)

 

 

Oil

Equivalent

(MMBoe)

 

 

Natural Gas

Equivalent

(Bcfe)

 

 

% of

Total

Proved

 

 

PV-10 (3)

(In millions)

 

Oil

(MMBbls)

 

 

NGLs

(MMBbls)

 

 

Natural Gas

(Bcf)

 

 

Oil

Equivalent

(MMBoe)

 

 

Natural Gas

Equivalent

(Bcfe)

 

 

% of

Total

Proved

 

 

PV-10 (3)

(In millions)

 

Proved developed producing

 

29.8

 

 

 

9.2

 

 

 

177.7

 

 

 

68.7

 

 

 

412.2

 

 

 

57

%

 

$

1,903

 

 

16.6

 

 

 

6.1

 

 

 

147.5

 

 

 

47.3

 

 

 

283.9

 

 

 

64

%

 

$

449

 

Proved developed non-producing

 

5.9

 

 

 

1.5

 

 

 

43.4

 

 

 

14.6

 

 

 

87.5

 

 

 

12

%

 

 

304

 

 

10.0

 

 

 

1.5

 

 

 

35.6

 

 

 

17.4

 

 

 

104.3

 

 

 

23

%

 

 

229

 

Total proved developed

 

35.7

 

 

 

10.7

 

 

 

221.1

 

 

 

83.3

 

 

 

499.7

 

 

 

69

%

 

 

2,207

 

 

26.6

 

 

 

7.6

 

 

 

183.1

 

 

 

64.7

 

 

 

388.2

 

 

 

87

%

 

 

678

 

Proved undeveloped

 

26.0

 

 

 

5.1

 

 

 

33.8

 

 

 

36.7

 

 

 

220.3

 

 

 

31

%

 

 

398

 

 

6.3

 

 

 

0.6

 

 

 

14.7

 

 

 

9.3

 

 

 

55.8

 

 

 

13

%

 

 

77

 

Total proved

 

61.7

 

 

 

15.8

 

 

 

254.9

 

 

 

120.0

 

 

 

720.0

 

 

 

100

%

 

$

2,605

 

 

32.9

 

 

 

8.2

 

 

 

197.8

 

 

 

74.0

 

 

 

444.0

 

 

 

100

%

 

$

755

 

 

Volume measurements:

 

 

MMBbls – million barrels for crude oil, condensate or NGLs

 

Bcf – billion cubic feet

MBoeMMBoe – million barrels of oil equivalent

 

Bcfe – billion cubic feet of gas equivalent

(1)

In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 20142016 were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average commodity price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the year end December 31, 2014. Prices2016.  The WTI posted price and the Henry Hub spot price were adjusted by leaseutilized as the referenced price and after adjusting for quality, transportation, fees, energy content and regional price differentials. Fordifferentials, the average realized prices were $36.28 per barrel for oil, $16.82 per barrel for NGLs and $2.47 per Mcf for natural gas.  In determining the West Texas Intermediate postedestimated realized price was used in the calculation and, after adjustments, a price of $91.12 per Bbl was used in computing the amounts above. Forfor NGLs, a ratio was computed for each field of the NGLs realized price compared to the crude oil realized price.  Then, this ratio was applied to the crude oil price using SEC guidance. The NGLs price of $34.63 per Bbl was used in computing the amounts above. For natural gas, the average Henry Hub spot price was used in the calculation and the adjusted price of $4.27 per Mcf was used in computing the amounts above.  Such prices were held constant throughout the estimated lives of the reserves.  Future production and development costs and ARO are based on year-end costs with no escalations.

33


(2)

Energy equivalents are determined using the energy-equivalent ratio of six Mcf of natural gas to one Bblbarrel of crude oil, condensate or NGLs (totals may not compute due to rounding).  The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent price for oil and NGLs may differ significantly.

(3)

We refer to PV-10 as the present value of estimated future net revenues of estimated proved reserves as calculated by our independent petroleum consultant using a discount rate of 10%.  This amount includes projected revenues, estimated production costs and estimated future development costs and excludes ARO.  We have also included PV-10 after ARO below.  PV-10 after ARO includes the present value of ARO related to proved reserves using a 10% discount rate and no inflation of current costs.  Neither PV-10 nor PV-10 after ARO are financial measures defined under GAAP; therefore, the following table reconciles these amounts to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure.  Management believes that the non-GAAP financial measures of PV-10 and PV-10 after ARO are relevant and useful for evaluating the relative monetary significance of oil and natural gas properties.  PV-10 and PV-10 after ARO are used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities.  We believe the use of pre-tax measures is valuable because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid.  Management believes that the presentation of PV-10 and PV-10 after ARO provide useful information to investors because they are widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies.  PV-10 and PV-10 after ARO are not measures of financial or operating performance under GAAP, nor are they intended to represent the current market value of our estimated oil and natural gas reserves.  PV-10 and PV-10 after ARO should not be considered in isolation or as substitutes for the standardized measure of discounted future net cash flows as defined under GAAP.  Investors should not assume that PV-10, or PV-10 after ARO, from our proved oil and natural gas reserves shown above represent a current market value of our estimated oil and natural gas reserves.


The reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves is as follows (in millions):

As of

December 31,

2014

 

December 31,

2016

 

Present value of estimated future net revenues (PV-10)

$

2,605

 

$

755

 

Present value of estimated ARO, discounted at 10%

 

(301

)

 

(277

)

PV-10 after ARO

 

2,304

 

 

478

 

Future income taxes, discounted at 10%(1)

 

(601

)

 

 

Standardized measure of discounted future net cash flows

$

1,703

 

$

478

 

(1)

No future income taxes were estimated to be paid as our present tax position has sufficient tax basis to offset any future taxes.  State income taxes were disregarded due to immateriality.  

Changes in Proved Reserves

Our total proved reserves increased more than production, resulting in a net increase, andat December 31, 2016 were 120.074.0 MMBoe compared to 76.4 MMBoe at December 31, 2014 compared to 117.7 MMBoe at December 31, 2013.  The change between periods is a result2015, representing an overall decrease of extensions and discoveries of 9.7 MMBoe, acquisitions of 6.1 MMBoe and positive net revisions of 4.1 MMBoe, partially offset by 17.62.4 MMBoe.  After accounting for 15.4 MMBoe of production.  Increases for extensions and discoveries2016 production, total revisions were primarily at Mississippi Canyon 782 (Dantzler) related to two wells and the Spraberry field related to 51 wells.  Increases from acquisitionsa positive 13.0 MMBoe.  Positive technical revisions were primarily14.2 MMBoe, while negative revisions due to acquiring interests in the Woodside Properties and increasing ownership in the Fairway field.  Revisionslower commodity prices were impacted by various fields, with the primary changes being increases at the Fairway and Mississippi Canyon 800 fields, partially offset by decreases at the Spraberry and Ship Shoal 349 (Mahogany) fields.  estimated to be 1.2 MMBoe.  

See Development of Proved Undeveloped ReserReservesves below for a table reconciling the change in proved undeveloped reserves during 2014.2016.  See Financial Statements and Supplementary Data– Note 21 – Supplemental Oil and Gas Disclosuresunder Part II, Item 8 in this Form 10-K for additional information.

Our estimates of proved reserves, PV-10 and standardized measure as of December 31, 20142016 are calculated based upon SEC mandated 20142016 unweighted average first-day-of-the-month crude oil and natural gas benchmark prices, which are substantially above prices realized in December 2014may or may not represent current prices.  Using the SEC methodology and January 2015.  The pricesprior to certain adjustments for quality, transportation, fees, energy content and regional price differentials, the price of crude oil NGLs anddeclined to $39.25 per barrel for 2016 year-end compared to $46.79 per barrel for 2015 year-end.  For natural gas, have declined substantially since June 2014.  The spotthe price of WTI crude oil has decreased from $107.00 per barrel in the middle of June 2014 to as low as $44.00 per barrel in January 2015.  In recent months, Henry Hub spot prices for natural gas have declined to lower than $3.00$2.48 per McfMMBtu for 2016 year-end compared to average$2.59 per MMBtu for 2015 year-end.  If prices during 2014 well in excess of $4.00 per Mcf. Sustained lower prices will result infall below the prices used in our estimates through year-end 2015 being substantially lower,2016 levels, which, absent significant proved reserve additions, willmay reduce future estimated proved reserve volumes due to lower economic limits and economic return thresholds for undeveloped reserves, as well as impact our results of operations, cash flows, quarterly full cost impairment ceiling tests and volume-dependent depletion cost calculations.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 in this Form 10-K for additional information.  

34


Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process

Our estimated proved reserve information as of December 31, 20142016 included in this Form 10-K was prepared by our independent petroleum consultants, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.  The scope and results of their procedures are summarized in a letter included as an exhibit to this Form 10-K.  The primary technical person at NSAI responsible for overseeing the preparation of the reserves estimates presented herein has B.S. and M.S. degrees in Civil Engineeringbeen practicing consulting petroleum engineering at NSAI since 2013 and has been a Registered Professional Engineer in the State of Texas for 26 years and a member of the Society of Petroleum Engineers for over 30 years. He has over 37 years total experience in the oil and gas industry, with over 2314 years of reservoir engineeringprior industry experience. His areas of experience are the continental shelf and deepwater Gulf of Mexico, San Juan Basin, onshore and offshore Mexico, offshore Africa, and unconventional gas sources worldwide.  NSAI has informed us that he meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in the application of industry standard practices to engineering evaluations as well as the application of SEC and other industry definitions and guidelines.


We maintain an internal staff of reservoir engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of the data, methods and assumptions used in the preparation of the reserves estimates.  Additionally, our senior management reviews any significant changes to our proved reserves on a quarterly basis.  Our Director of Reservoir Engineering Director has served in that capacity since 2013, as Reservoir Engineering Manager since 2006,over 27 years of oil and as Staff Reservoir Engineer upon joininggas industry experience and has managed the preparation of public company reserve estimates the last 13 years.  He joined the Company in 2004. Prior to joiningmid-2016 after spending the Company, hepreceding 12 years as Director of Corporate Engineering for Freeport-McMoRan Oil & Gas.  He has also served as a Reservoir Engineer at Shell, then VP of Reservoir Engineering at Freeport-McMoRanin various engineering and strategic planning roles with both Kerr-McGee Oil & Gas and later as Manager Acquisitions Engineering at Matrix Oil & Gas.with Conoco, Inc.  He receivedearned a Bachelor of Science degree in Petroleum Engineering Science from Iowa StateTexas A&M University in 1972.1989 and a Master’s degree in Business Administration from the University of Houston in 1999.

Reserve Technologies

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.  The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate.  To achieve reasonable certainty, our independent petroleum consultant employed technologies that have been demonstrated to yield results with consistency and repeatability.  The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests.  The accuracy of the estimates of our reserves is a function of:

·

the quality and quantity of available data and the engineering and geological interpretation of that data;

the quality and quantity of available data and the engineering and geological interpretation of that data;

·

estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results;

estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results;

·

the accuracy of various mandated economic assumptions such as the future prices of oil and natural gas; and

the accuracy of various mandated economic assumptions such as the future prices of crude oil, NGLs and natural gas; and

·

the judgment of the persons preparing the estimates.

the judgment of the persons preparing the estimates.

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

Reporting of Natural Gas and Natural Gas Liquids

We produce NGLs as part of the processing of our natural gas.  The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale.  We report all natural gas production information net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs.  We convert Bblbarrels to Mcfe using an energy-equivalent ratio of six Mcf to one Bblbarrel of oil, condensate or NGLs.  This energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ substantially.


35


Development of Proved Undeveloped Reserves

Our proved undeveloped reserves (“PUDs”) were estimated by NSAI, our independent petroleum consultant.  Future development costs associated with our PUDs at December 31, 20142016 were estimated at $865.8$98.9 million.

The following table presents our PUDs by field (in MMBoe):

As of December 31,

 

December 31,

 

2014

 

 

2013

 

 

2012

 

2016

 

 

2015

 

 

2014

 

Ship Shoal 349 (Mahogany)

 

2.1

 

 

 

1.3

 

 

 

4.8

 

 

4.5

 

 

 

4.0

 

 

 

2.1

 

Mississippi Canyon 243 (Matterhorn)

 

1.4

 

 

 

1.3

 

 

 

2.1

 

 

2.2

 

 

 

2.0

 

 

 

1.4

 

Viosca Knoll 823 (Virgo)

 

2.0

 

 

 

1.4

 

 

 

1.4

 

 

2.1

 

 

 

 

 

 

2.0

 

Spraberry (Yellow Rose)

 

24.9

 

 

 

25.7

 

 

 

19.6

 

Ewing Bank 910

 

0.5

 

 

 

0.5

 

 

 

 

Mississippi Canyon 698 (Big Bend) (1)

 

1.9

 

 

 

1.9

 

 

 

 

 

 

 

 

0.9

 

 

 

1.9

 

Mississippi Canyon 782 (Dantzler)

 

 

 

 

 

 

 

4.1

 

Mississippi Canyon 538/582 (Medusa)

 

0.3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

0.3

 

Mississippi Canyon 782 (Dantzler) (1)

 

4.1

 

 

 

 

 

 

 

High Island 21/22

 

 

 

 

 

 

 

2.7

 

Spraberry (Yellow Rose - sold in 2015)

 

 

 

 

 

 

 

24.9

 

Total

 

36.7

 

 

 

31.6

 

 

 

30.6

 

 

9.3

 

 

 

7.4

 

 

 

36.7

 

 

(1)

There has been no production at these fields as of December 31, 2014.

 

The following table presents a reconciliation of our PUDs (in MMBoe):

 

 

2014

 

 

2013

 

 

2012

 

Proved undeveloped reserves, beginning of year

 

31.6

 

 

 

30.6

 

 

 

40.5

 

Reductions:

 

 

 

 

 

 

 

 

 

 

 

Ship Shoal 349 (Mahogany)

 

 

 

 

(4.8

)

 

 

(11.8

)

Mississippi Canyon 243 (Matterhorn)

 

 

 

 

(0.7

)

 

 

(1.6

)

Spraberry (Yellow Rose) drilling, completions and technical

 

(2.3

)

 

 

(4.6

)

 

 

(9.7

)

Spraberry (Yellow Rose) well performance and viability

 

(2.4

)

 

 

(1.5

)

 

 

(0.2

)

High Island 21/22

 

 

 

 

(2.7

)

 

 

 

Subtotal - reductions

 

(4.7

)

 

 

(14.3

)

 

 

(23.3

)

Balance after reductions

 

26.9

 

 

 

16.3

 

 

 

17.2

 

Additions:

 

 

 

 

 

 

 

 

 

 

 

Ship Shoal 349 (Mahogany)

 

0.8

 

 

 

1.3

 

 

 

 

Viosca Knoll 823 (Virgo)

 

0.6

 

 

 

 

 

 

 

Spraberry (Yellow Rose) well additions and other

 

3.9

 

 

 

7.9

 

 

 

10.0

 

Spraberry (Yellow Rose) 40 acre down-spacing in 2013

 

 

 

 

4.2

 

 

 

 

Mississippi Canyon 698 (Big Bend) (2)

 

 

 

 

1.9

 

 

 

 

Mississippi Canyon 782 (Dantzler) (2)

 

4.1

 

 

 

 

 

 

 

High Island 21/22

 

 

 

 

 

 

 

2.7

 

Other changes

 

0.4

 

 

 

 

 

 

0.7

 

Subtotal - additions

 

9.8

 

 

 

15.3

 

 

 

13.4

 

Proved undeveloped reserves, end of year

 

36.7

 

 

 

31.6

 

 

 

30.6

 

Volume measurements:

MMBoe – million barrels of oil equivalent

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Proved undeveloped reserves, beginning of year

 

7.4

 

 

 

36.7

 

 

 

31.6

 

Reductions:

 

 

 

 

 

 

 

 

 

 

 

Ship Shoal 349 (Mahogany)

 

(1.9

)

 

 

 

 

 

 

Mississippi Canyon 698 (Big Bend)

 

(0.9

)

 

 

(1.0

)

 

 

 

Viosca Knoll 823 (Virgo)

 

 

 

 

(2.0

)

 

 

 

Mississippi Canyon 538/582 (Medusa)

 

 

 

 

(0.3

)

 

 

 

Mississippi Canyon 782 (Dantzler)

 

 

 

 

(4.1

)

 

 

 

Spraberry (Yellow Rose - sold in 2015)

 

 

 

 

(24.9

)

 

 

(4.7

)

Subtotal — reductions

 

(2.8

)

 

 

(32.3

)

 

 

(4.7

)

Balance after reductions

 

4.6

 

 

 

4.4

 

 

 

26.9

 

Additions:

 

 

 

 

 

 

 

 

 

 

 

Ship Shoal 349 (Mahogany)

 

2.4

 

 

 

1.9

 

 

 

0.8

 

Viosca Knoll 823 (Virgo)

 

2.1

 

 

 

 

 

 

0.6

 

Spraberry (Yellow Rose)

 

 

 

 

 

 

 

3.9

 

Mississippi Canyon 782 (Dantzler)

 

 

 

 

 

 

 

4.1

 

Mississippi Canyon 243 (Matterhorn)

 

0.2

 

 

 

0.6

 

 

 

 

Ewing Bank 910

 

 

 

 

0.5

 

 

 

 

Other changes

 

 

 

 

 

 

 

0.4

 

Subtotal — additions

 

4.7

 

 

 

3.0

 

 

 

9.8

 

Proved undeveloped reserves, end of year

 

9.3

 

 

 

7.4

 

 

 

36.7

 

 


Activity related to PUDs in 2016:

36During 2016, we drilled and converted one PUD location and 1.9 MMBoe to proved developed reserves (“PDs”).  Approximately $33.9 million of capital expenditures were incurred related to development of PUDs.  Development activity in 2016 resulted in reclassification of approximately 26% of the PUDs existing at December 31, 2015 to proved developed status.  


At our Ship Shoal 349 field (Mahogany), PUD reserves were added due to drilling the A-18 well to target depth and beginning completion activities.  Although the A-18 well was not completed by year-end 2016, the data available from the drilling activity and initial completion activities led to the conversion of the A-18 well from PUD to PD and resulted in the recognition of one additional offsetting PUD location.

At our Viosca Knoll 823 field (Virgo), PUD reserves were added as two locations were reclassified from probable to PUD, which we plan on drilling in the fourth quarter of 2017 or in early 2018.

At our Mississippi Canyon 243 field (Matterhorn), reserves associated with existing PUD locations were added due to performance evaluations of adjacent PDs and economic field life extension resulting from ongoing success in managing and reducing lease operating expenses.

At our Mississippi Canyon 698 field (Big Bend), updated field performance data demonstrated an additional take point is unnecessary to recover estimated proved reserves, therefore we determined the well previous classified as a PUD will not be drilled and it was removed from PUD reserves.    

Activity related to PUDs in 2015:

During 2015, we completed five offshore wells which affected the conversion of PUDs to PDs reserves and affected additional PUDs to be recognized.  Three of the five wells were drilled prior to 2015.  Approximately $141.0 million of capital expenditures was incurred related to these five wells during 2015.  Activity, divestitures and development assessments in 2015 resulted in reclassification of approximately 88% of the PUDs existing at December 31, 2014.

At our Spraberry field (Yellow Rose), our interests were divested and we were assigned an ORRI.

At our Mississippi Canyon 698 field (Big Bend), we completed one well which moved PUDs to PDs.

At our Viosca Knoll 823 field (Virgo), one well was removed from PUDs as the development timing was beyond the five year limitation and another well was removed from PUDs as it was determined to be uneconomic.

At our Mississippi Canyon 782 field (Dantzler), we completed two wells which moved PUDs into PDs.

At our Ship Shoal 349 field (Mahogany), PUD reserves were added based on performance, remapping and technical changes.

At our Mississippi Canyon 243 field (Matterhorn), PUD reserves were added due to the assessment related to two wells.

Activity related to PUDs in 2014:

·

During 2014, we drilled 20 development wells that converted PUDs to proved developed producing reserves (“PDPs”) and spent $149.5 million on development of PUDs.  Activity in 2014 allowed reclassification of approximately 15% of the PUDs existing at December 31, 2013.

During 2014, we drilled 20 development wells that converted PUDs to PDs and spent $149.5 million on development of PUDs.  Activity in 2014 allowed reclassification of approximately 15% of the PUDs existing at December 31, 2013.

At our Spraberry field (Yellow Rose), we drilled and completed 20 development wells, which moved PUDs to PDs.  In addition, PUDs were decreased due to certain wells being evaluated as uneconomic due to performance and for technical reasons.  PUDs were increased due to exploration drilling activity, both by us and offset operators.  

At our Ship Shoal 349 field (Mahogany), we experienced technical difficulties from a cracked casing, which led us to abandon the well.  As of December 31, 2014, we were in the process of drilling a new well (the A-18 well) which was expected to convert the PUDs to PDs, but stacked the rig in the first quarter of 2015 due to substantially reduced crude oil prices.  


·

At our Spraberry field (Yellow Rose), we drilled and completed 20 development wells, which moved PUDs to PDPs. In addition, PUDs were decreased due to certain wells being evaluated as uneconomic due to performance and for technical reasons.  PUDs were increased due to exploration drilling activity, both by us and offset operators.  Our drilling activity for 2015 is expected to be lower compared to 2014, then increasing in 2016 and beyond as prices recover.  

·

At our Ship Shoal 349 field (Mahogany), we experienced technical difficulties from a cracked casing, which led us to abandon the well.  As of December 31, 2014, we were in the process of drilling a new well (the A-18 well) which was expected to convert the undeveloped reserves to PDP’s, but have stacked the rig in the first quarter of 2015 due to substantially reduced oil prices.  We plan to commence drilling this well once oil prices recover.  

·

The PUDs at our Mississippi Canyon 782 field (Dantzler) were added as a result of drilling activity in 2013 and completion operations in 2014 to classify reserves as proved undeveloped.PUD.  This field is not operated by us so we are subject to the decisions of the operator.  Current plans are to complete the two wells in this field in 2015 that have been drilled to target depth and to begin production in the first quarter of 2016.

·

At our Viosca Knoll 823 field (Virgo), we have elected to add a PUD to replace declining reserves in the field.  This decision

At our Viosca Knoll 823 field (Virgo), a PUD location was added based upon reassessment of field performance and a revised reserve depletion plan.  The plan revision was made due to the magnitude of the reserve potential.  We perceived less risk in a sidetrack of an existing well compared to a major workover to produce these reserves.

Activity related to PUDs in 2013:the magnitude of the reserve potential.  

·

During 2013, we drilled numerous development wells that converted PUDs to PDPs and spent $270.4 million on development of PUDs.  Activity in 2013 allowed reclassification of approximately 47% of the PUDs existing at December 31, 2012.

·

At our Ship Shoal 349 field (Mahogany), we drilled and completed the SS 359 A14 BP2 well, which resulted in the conversion of all of the PUDs existing at 2012 to PDPs in 2013.  The SS 359 A14 BP2 well was the fifth well drilled under our 2010 Development Plan.  As of December 31, 2013, we were in the process of drilling our sixth well (SS 359 A015) under this multi-well program.  This multi-well program is expected to continue into 2014 and beyond.  Also, as a result of our successful drilling program, one new PUD location was added during 2013.  

·

The PUDs at our Mississippi Canyon 243 field (Matterhorn) and our Viosca Knoll 823 field (Virgo) were obtained through acquisitions in 2010. We drilled and completed one development well (MC 243 A2 ST2 BP2) at the Mississippi Canyon 243 field (Matterhorn), which moved PUDs to PDPs.  Also, one new PUD location was added during 2013.  Development of these two fields is expected to continue into future years.    

·

PUDs at our Spraberry field (Yellow Rose) were obtained primarily through an acquisition in 2011.  We drilled and completed 33 development wells, which moved PUDs to PDPs. In addition, PUDs were decreased due to certain wells being evaluated as uneconomical due to performance and for technical reasons.  PUDs were increased due to exploration drilling activity, both by us and other companies, and also from additions related to 40 acre down-spacing.  Our drilling plans for 2014 include an active drilling program in the Spraberry field (Yellow Rose) and we expect to continue our drilling activity beyond 2014.    

·

In the High Island 21/22 field, we drilled and completed the HI 0021 A1 BP1 well, which initially resulted in the conversion of all the PUDs to PDPs.  Subsequently, these PDPs were removed from proved reserves due to well performance.  

·

The additional PUDs at the Mississippi Canyon 698 field (Big Bend) were from our joint interest ownership in the non-operated field and are related to the MC 698 #1 well, which was drilled in 2012.


37


Activity related to PUDs in 2012:

·

During 2012, we drilled numerous development wells that converted PUDs to PDPs and spent $263.6 million on development of PUDs.  Activity in 2012 allowed reclassification of approximately 58% of the PUDs existing at December 31, 2011.

·

At our Ship Shoal 349 field (Mahogany), we completed one well, (SS 359 A5 ST) and two additional wells were side tracked. As of December 31, 2012, we were in the process of completing the SS 359 A9 ST well, which moved additional reserves from PUDs to PDPs.

·

We completed one well (MC 243 A4 ST) at Mississippi Canyon 243 field (Matterhorn) in 2012.

·

At our Spraberry field (Yellow Rose), we completed 53 development wells and 11 exploration wells. One of the wells completed was a horizontal well and two other horizontal wells reached target depth in 2012, which proved the concept and allowed additional horizontal PUD locations to be booked. Additionally, wells completed in 2011 and 2012 proved that the concept of down spacing to 40-acres was viable in a portion of the field, allowing the conversion of certain unproven locations to PUDs in 2012.    

·

In the High Island 21/22 field, a field study demonstrated that additional reserves could be recovered by drilling a replacement for a well that had experienced a mechanical failure. This allowed unproved reserves in 2011 to be reclassified as proved reserves in 2012.

See Business under Part I, Item 1, Our Fields in Item 2 above and Financial Statements and Supplementary Data – Note 27 – Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K for additional information.

We believe that we will be able to develop all but 1.41.3 MMBoe, of the reserves classified as PUDs, or approximately 96%14%, out of the total of 36.79.3 MMBoe classified as PUDs at December 31, 2014,2016, within five years from the date such reserves were initially recorded.  The lone exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan.  The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells.  These PUDs wereOne of the sidetrack PUD locations in this field was originally recorded in our proved reserves as of December 31, 2010.  The development of the 1.4 MMBoe of PUDsthis PUD will be delayed until an existing well is depleted and available to sidetrack.  Based on the latest reserve report, a well is expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDsthis PUD location in 2020.2023.    

Our capital budget for 20152017 is $125 million, which excludes potential acquisitions, with over 50% allocated for development is approximately $120 million. The capital allocateddevelopment.  Three of our four PUDs as of December 31, 2016 are scheduled to our development activities will assist usbe drilled in converting the PUDs to PDPs.  A recovery in crude oil prices could lead to an increase in development expenditures.2017.  


38


Acreage

The following summarizes our leasehold at December 31, 2014.2016.  Deepwater refers to acreage in over 500 feet of water.

Developed

Acreage

 

 

Undeveloped

Acreage

 

 

Total

Acreage

 

Developed

Acreage

 

 

Undeveloped

Acreage

 

 

Total

Acreage

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Shelf

 

507,102

 

 

 

331,450

 

 

 

77,985

 

 

 

77,985

 

 

 

585,087

 

 

 

409,435

 

 

419,077

 

 

 

270,583

 

 

 

76,642

 

 

 

76,642

 

 

 

495,719

 

 

 

347,225

 

Deepwater

 

179,331

 

 

 

76,434

 

 

 

359,746

 

 

 

212,603

 

 

 

539,077

 

 

 

289,037

 

 

153,423

 

 

 

63,306

 

 

 

110,698

 

 

 

42,005

 

 

 

264,121

 

 

 

105,311

 

Total Offshore

 

686,433

 

 

 

407,884

 

 

 

437,731

 

 

 

290,588

 

 

 

1,124,164

 

 

 

698,472

 

Onshore

 

30,228

 

 

 

25,952

 

 

 

24,500

 

 

 

15,749

 

 

 

54,728

 

 

 

41,701

 

Total

 

716,661

 

 

 

433,836

 

 

 

462,231

 

 

 

306,337

 

 

 

1,178,892

 

 

 

740,173

 

 

572,500

 

 

 

333,889

 

 

 

187,340

 

 

 

118,647

 

 

 

759,840

 

 

 

452,536

 

Approximately 58%74% of our total net offshore acreage is developed and approximately 62% of our total net onshore acreage is developed. Within the onshore net acreage, the Spraberry field (Yellow Rose) is approximately 90% developed and all the other onshore prospects combined are approximately 17% developed.held by production.  We have the right to propose future exploration and development projects on the majority of our acreage.

ForRegarding the offshore undeveloped leasehold, 59,49847,500 net acres (20%(40%) of the total 290,588118,647 net undeveloped offshore acres could expire in 2015, 35,9652017, 19,975 net acres (12%) could expire in 2016, 79,180 net acres (28%) could expire in 2017, 52,121 net acres (18%(17%) could expire in 2018, and 63,82432,720 net acres (22%(27%) could expire in 2019, and beyond. For the onshore undeveloped leasehold, 10,61211,912 net acres (67%) of the total 15,749 net undeveloped onshore acres could expire in 2015 and 5,088 net acres (33%(10%) could expire in 2016. Within the onshore net undeveloped acreage, the Spraberry field (Yellow Rose) comprises 2,4862020, and 6,720 net acres (6%) could expire in 2020 and the other onshore prospects comprise the remaining 13,263 acres of the total 15,749 net acres.  The expiration of the onshore undeveloped acreage may be extended through the purchase of new leasehold rights or extension of leasehold rights, but these potential arrangements were not contractual rights as of December 31, 2014.beyond.  In making decisions regarding drilling and operations activity for 20152017 and beyond, we give consideration to undeveloped leasehold that may expire in the near term in order that we might retain the opportunity to extend such acreage.

Our net offshore acreage decreased 39,06790,160 net acres (5%(17%) from December 31, 2013 and our net onshore acreage decreased 141,170 net acres (77%) from December 31, 2013. The decrease in our net onshore acreage was primarily2015 due to reassigning acres back to our original assignor at our Star Project in East Texas.lease expirations and relinquishments.  


Production

For the years 2014, 20132016, 2015 and 2012,2014, our net daily production averaged 48.3 MBoe, 49.3 MBoe41,980 Boe, 46,709 Boe, and 46.8 MBoe,48,317 Boe, respectively.  Production decreased in 20142016 from 20132015 primarily due to an out of period adjustment of 0.9 MBoe/day recorded in 2013, natural production declines, production deferrals and divestitures, partially offset by acquisitions and new production.  Production increased in 2013 from 2012 primarily due to acquisitions and increases in the Ship Shoal 349 field attributable to development activities and the out of period adjustment, partially offset by natural production declines and divestiture of the Yellow Rose properties, partially offset by production deferrals.from Mississippi Canyon 698 field (Big Bend) and the Mississippi Canyon 782 field (Dantzler), which began production in the fourth quarter of 2015, and from one well completed during the year.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations under Part II, Item 7 in this Form 10-K for additional information.

39


Production History

The following presents historical information about our produced oil, NGLs and natural gas volumes from all of our producing fields over the past three years.

Year Ended December 31,

 

Year Ended December 31,

 

2014

 

 

2013

 

 

2012

 

2016

 

 

2015

 

 

2014

 

Net Sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

7,176

 

 

 

7,018

 

 

 

6,033

 

 

7,201

 

 

 

7,751

 

 

 

7,176

 

NGLs (MBbls)

 

2,112

 

 

 

2,091

 

 

 

2,129

 

 

1,542

 

 

 

1,604

 

 

 

2,112

 

Oil and NGLs (MBbls)

 

9,288

 

 

 

9,110

 

 

 

8,163

 

 

8,743

 

 

 

9,355

 

 

 

9,288

 

Natural gas (MMcf)

 

50,088

 

 

 

53,257

 

 

 

53,825

 

 

39,731

 

 

 

46,163

 

 

 

50,088

 

Total oil equivalent (MBoe)

 

17,636

 

 

 

17,986

 

 

 

17,133

 

 

15,365

 

 

 

17,049

 

 

 

17,636

 

Total natural gas equivalents (MMcfe)

 

105,815

 

 

 

107,915

 

 

 

102,800

 

 

92,188

 

 

 

102,294

 

 

 

105,815

 

 

Volume measurements:

 

 

MBbls – thousand barrels for crude oil, condensate or NGLs

 

MMcf – million cubic feet

MBoe – thousand barrels of oil equivalent

 

MMcfe – million cubic feet equivalent

Refer to the descriptions of our 10 largest fields reported earlier in this Item 2, Properties, for historical information about our produced volumes from our Spraberry field (Yellow Rose) and Ship Shoal 349/359 field (Mahogany) and the Fairway Field over the past three fiscal years, each of which have proved reserves exceeding 15% of our total proved reserves.  Also refer to Selected Financial Data – Historical Reserve and Operating Information under Part II, Item 6 in this Form 10-K for additional historical operating data, including average realized sale prices and production costs.

Productive Wells

The following presents our ownership interest at December 31, 20142016 in our productive oil and natural gas wells.  A net well represents our fractional working interest of a gross well in which we own less than all of the working interest.

Offshore Wells

Oil Wells

 

 

Gas Wells

 

 

Total Wells

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Operated

 

86

 

 

 

75

 

 

 

59

 

 

 

46

 

 

 

145

 

 

 

121

 

Non-operated

 

28

 

 

 

8

 

 

 

35

 

 

 

11

 

 

 

63

 

 

 

19

 

Total offshore wells

 

114

 

 

 

83

 

 

 

94

 

 

 

57

 

 

 

208

 

 

 

140

 

Onshore Wells

Oil Wells

 

 

Gas Wells

 

 

Total Wells

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Operated

 

238

 

 

 

237

 

 

 

10

 

 

 

8

 

 

 

248

 

 

 

245

 

Non-operated

 

6

 

 

 

2

 

 

 

 

 

 

 

 

 

6

 

 

 

2

 

Total onshore wells

 

244

 

 

 

239

 

 

 

10

 

 

 

8

 

 

 

254

 

 

 

247

 

Total Productive Wells

Oil Wells (1)

 

 

Gas Wells (1)

 

 

Total Wells

 

Offshore Wells

Oil Wells (1)

 

 

Gas Wells (1)

 

 

Total Wells

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Operated

 

324

 

 

 

312

 

 

 

69

 

 

 

54

 

 

 

393

 

 

 

366

 

 

83

 

 

 

74

 

 

 

55

 

 

 

39

 

 

 

138

 

 

 

113

 

Non-operated

 

34

 

 

 

10

 

 

 

35

 

 

 

11

 

 

 

69

 

 

 

21

 

 

31

 

 

 

8

 

 

 

28

 

 

 

9

 

 

 

59

 

 

 

17

 

Total productive wells

 

358

 

 

 

322

 

 

 

104

 

 

 

65

 

 

 

462

 

 

 

387

 

Total offshore wells

 

114

 

 

 

82

 

 

 

83

 

 

 

48

 

 

 

197

 

 

 

130

 

 

(1)

Includes 11eleven gross (9.0(7.2 net) oil wells and ninesix gross (5.8(3.1 net) gas wells with multiple completions.


Drilling Activity

As presented in the tables below, our drilling activity decreased in 20142016 compared to 2013 in our onshore operations. In 2014,2015 and 2014.  As the Yellow Rose properties were divested during 2015 and we increased the onshore horizontal drilling activity compared to 2013, which take longer to drill and are more expensive on a per well basis compared to vertical wells.  Ourdo not currently have any onshore drilling activity is primarily inactivities, historical data for onshore drilling was excluded from the Spraberry field, which was acquired by acquisition in May 2011, coupled with additional leasehold interests acquired in 2011 and 2013.table below.

40


The tablestable below areis based on the SEC’s criteria of completion or abandonment to determine productive wells drilled.

Development and Exploration Drilling

The following table sets forth information related tosummarizes our development and exploration offshore wells drilledcompleted over the past three years.

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Gross Wells:

 

 

 

 

 

 

 

 

 

 

 

Productive:

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

1

 

 

 

4

 

 

 

3

 

Onshore

 

20

 

 

 

33

 

 

 

53

 

Non-productive

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

 

 

 

 

 

 

 

Onshore

 

 

 

 

 

 

 

 

Total development wells - gross

 

21

 

 

 

37

 

 

 

56

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Wells:

 

 

 

 

 

 

 

 

 

 

 

Productive:

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

1.0

 

 

 

4.0

 

 

 

3.0

 

Onshore

 

19.3

 

 

 

32.9

 

 

 

52.8

 

Non-productive

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

 

 

 

 

 

 

��

 

Onshore

 

 

 

 

 

 

 

 

Total development wells - net

 

20.3

 

 

 

36.9

 

 

 

55.8

 

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Development Wells Completed:

 

 

 

 

 

 

 

 

 

 

 

Gross Wells:

 

 

 

 

 

 

 

1.0

 

Net Wells:

 

 

 

 

 

 

 

1.0

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploration Wells Completed:

 

 

 

 

 

 

 

 

 

 

 

Gross Wells:

 

1.0

 

 

 

5.0

 

 

 

5.0

 

Net Wells:

 

0.5

 

 

 

1.2

 

 

 

3.4

 

 

Our success rates related to our gross development and exploration wells drilled was 100% in each of the last three years.

Exploration Drilling

The following table sets forth information related to our exploration drilling over the past three years.

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Gross Wells:

 

 

 

 

 

 

 

 

 

 

 

Productive:

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

5

 

 

 

1

 

 

 

1

 

Onshore

 

13

 

 

 

7

 

 

 

24

 

Non-productive

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

 

 

 

1

 

 

 

1

 

Onshore

 

 

 

 

 

 

 

 

Total exploration wells - gross

 

18

 

 

 

9

 

 

 

26

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Wells:

 

 

 

 

 

 

 

 

 

 

 

Productive:

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

3.4

 

 

 

1.0

 

 

 

0.3

 

Onshore

 

13.0

 

 

 

6.9

 

 

 

20.8

 

Non-productive

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

 

 

 

1.0

 

 

 

0.4

 

Onshore

 

 

 

 

 

 

 

 

Total exploration wells - net

 

16.4

 

 

 

8.9

 

 

 

21.5

 

Our success rates related to our gross exploration wells drilled during 2014, 2013 and 2012 were 100%, 89% and 96%, respectively.

41


Recent Drilling Activity

The following table sets forth During January 2017, we completed the A-18 offshore development well at the Ship Shoal 349 field (Mahogany). This well was spud in 2014, but drilling was suspended in 2015 drilling activity to February 15, 2015.

 

January 1, 2015 to February 15, 2015,

 

 

Development

 

 

Exploration

 

Gross Wells:

 

 

 

 

 

 

 

Productive:

 

 

 

 

 

 

 

Offshore

 

 

 

 

1

 

Onshore

 

1

 

 

 

1

 

Non-productive

 

 

 

 

 

 

 

Offshore

 

 

 

 

 

Onshore

 

 

 

 

 

Total wells - gross

 

1

 

 

 

2

 

 

 

 

 

 

 

 

 

Net Wells:

 

 

 

 

 

 

 

Productive:

 

 

 

 

 

 

 

Offshore

 

 

 

 

0.2

 

Onshore

 

0.3

 

 

 

1.0

 

Non-productive

 

 

 

 

 

 

 

Offshore

 

 

 

 

 

Onshore

 

 

 

 

 

Total wells - net

 

0.3

 

 

 

1.2

 

 As of February 15, 2015, we wereand resumed in the process of drilling and/or completing on a gross well basis five offshore exploration wells, six onshore exploration wells and five onshore development wells.2016.  

Capital Expenditures

The level of our investment in oil and gas properties changes from time to time depending on numerous factors, including the prices of crude oil, NGLs and natural gas,gas; acquisition opportunitiesopportunities; liquidity and financing options; and the results of our exploration and development activities.  Due to the sustained lower commodity price environment and the outlook for the remainder of 2017, we have set our 2017 capital expenditure budget at $125 million, which excludes potential acquisitions.  Although this is an increase from the $49 million capital expenditures incurred in 2016, our current plan for 2017 is a significant reduction from 2015 and 2014 investment levels of $231 million and $630 million, respectively.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Expenditures under Part II, Item 7 in this Form 10-K for additional capital expenditures information.

Item 3. Legal Proceedings

Financial Assurance Requirements by the BOEM.  In the first quarter of 2016, we received several orders from the BOEM demanding the Company to secure financial assurances in the aggregate of $260.8 million, with amounts specified with respect to certain designated leases, ROWs and RUEs.  We filed various appeals to the IBLA concerning these orders.  The IBLA, acknowledging the BOEM and the Company were seeking to resolve the BOEM orders through settlement discussions, stayed the effectiveness of these orders several times, with the current stay effective to May 31, 2017.  

In July 2016, the BOEM issued NTL #2016-N01, related to obligations for decommissioning activities on the OCS, to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional security may be required for OCS leases, ROWs and RUEs.  This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07.


In September 2016, we received notice from the BOEM confirming that we do not qualify to self-insure a portion of any additional financial assurance under NTL #2016-N01.  In October 2016, we received from the BOEM proposal letters outlining what additional security the BOEM proposes to require with respect to leases, ROWs and RUEs in which we are designated operator. 

In December 2016, the BOEM issued to us an Order to Provide Additional Security for our sole liability properties.  Sole liability properties are leases, ROWs, or RUEs for which the holder is the only liable party, i.e., there are no co-lessees, operating rights owners and/or other grant holders, and no prior interest holders liable to meet the lease and/or grant obligations.  

In January 2017, the BOEM, in a notice to stakeholders, extended the implementation timeline for NTL #2016-N01 by an additional six months with respect to non-sole liability properties, except in circumstances in which the BOEM determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  The extension did not affect the demand to provide financial assurance for leases, ROWs and RUEs constituting sole liability properties.  

  In February 2017, the BOEM withdrew the orders it issued in December 2016 affecting so called “sole liability properties” to allow time for the new President’s administration to review the complex financial assurance program.  This withdrawal rescinded the Order to Provide Additional Security issued to us in December 2016.  However, the BOEM may re-issue sole liability orders before the end of the six-month period if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.

As suggested by the BOEM in its January and February notices, we intend to use the six month extension granted by the BOEM as an opportunity to propose and negotiate acceptable plans dealing with both sole and non-sole liability properties.

Apache Lawsuit.  InOn December 15, 2014, Apache Corporation (“Apache”) filed a lawsuit against W&T Offshore, Inc., alleging that W&T breached the joint operating agreementa JOA related to, plugging andamong other things, the abandonment costs for threeof deepwater wells in the Mississippi Canyon area of the Gulf of Mexico.  That lawsuit, styled Apache Corporation v. W&T Offshore, Inc., was heard in the United States District Court for the Southern District of Texas.  Apache contends that W&T has failed to pay its proportional share of the costs associated with plugging and abandoning three wells that are subject to the JOA.  We contend that the costs incurred by Apache are excessive and unreasonable.  Apache seeks unspecifiedan award of actual damages, interest, court costs, and attorneys’ fees.  See Financial StatementsIn February 2015, we made a payment to Apache for our net share of the amount that we believe was reasonable to plug and Supplementary Data - Note 18 – Contingenciesabandon the wells. 

On October 28, 2016, the jury made the following findings:

1.

W&T failed to comply with the contract by failing to pay its proportionate share of the costs to plug and abandon the MC 674 wells.

2.

The amount of money to compensate Apache for W&T’s failure to pay its proportionate share of the costs to plug and abandon the MC 674 wells was $43.2 million.

3.

The $43.2 million referred to in #2 should be offset by $17.0 million.

4.

Apache acted in bad faith thereby causing W&T to not comply with the contract.

In November 2016, we filed a motion with the trial court requesting a judgment consistent with the jury’s finding that Apache acted in bad faith thereby causing W&T not to comply with the contract, which W&T asserted bars Apache from recovery for damages under Part II, Item 8applicable law, and if damages are not barred in their entirety, that any judgment for monetary damages should be offset by $17.0 million as determined by the jury. After Apache filed its opposing motion, a hearing was held by the trial court in December 2016.  As of the filing date of this Form 10-K,  for information on this matter.no judgment has been entered by the court.


Claims against Certain Insurance Underwriters.Companies . In June 2014, the United States Fifth Circuit Court of Appeals reversed a lower court’s ruling in holding that our excess liability policies (“Excess Policies”) cover removal-of-wreck and compelleddebris claims arising from Hurricane Ike, even though we exhausted the limits of our Energy Package (defined as certain insurance underwriterspolicies relating to reimburse costs incurred by us for removal of wreck related to damages we incurred during Hurricane Ike.our oil and gas properties which includes named windstorm coverage) with non-removal-of-wreck and debris claims.  Several of the underwriters haveinsurance companies did not paidpay us amounts we claim were due under such Excess Policies in accordance with the Fifth Circuit ruling.  We filed a lawsuit in September 2014 against certain underwritersinsurance companies for amounts owed, interest, attorney fees and damages.  After receiving reimbursements applied against our remaining Energy Package limits, reimbursement from certain underwriters of the Excess Policies of approximately $10 million and adjustmentsIn December 2016, we entered into settlement agreements with these companies with respect to claims the estimated potentialarising from Hurricane Ike which had been made subject to adjustment or request for reimbursement of removal-of-wreck costs is approximately $31by us, in which these companies agreed to pay such claims totaling $30.2 million, plus interest and attorney fees, which were received in December 2016 and January 2017.  This settlement did not include claims arising from Hurricane Ike that have not yet been made subject to adjustment or requested for reimbursement by us.

Monetary Sanctions by Government Authorities.  (Notices of Proposed Civil Penalty Assessment)  The Company currently has four open civil penalties issued by the BSEE arising from Incidents of Noncompliance (“INCs”) issued by the BSEE, which have not been settled as of the filing of this Form 10-K.  The INC’s underlying the civil penalties were issued during 2015 and 2016 and relate to four separate offshore locations with occurrence dates ranging from July 2012 to September 2014.  The proposed civil penalties for these INCs total $8.1 million.  As of December 31, 2016, the Company has accrued approximately $1.5 million, which is the Company’s best estimate of the final settlement once all appeals have been exhausted.  The Company’s position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs.

Notification by ONRR of Fine for Non-compliance.  In December 2013 and January 2014, we were notified by the ONRR of an underpayment of royalties on certain Federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment.  In March 2014, we received notice from the ONRR of a statutory fine of $2.3 million (subsequently reduced to approximately $1.1 million) relative to such underpayment.  We believe the fine is excessive considering the circumstances and in relation to the amount of underpayment.  A hearing on this matter was held with an Administrative Law Judge in August 2016.  A decision on this case has been deferred until March 2017 at the earliest.  The ultimate resolution may result in a waiver of the fine, a reduction of the fine, or payment of the full amount plus interest covering several years.  As no amount has been determined as more likely than any other within the range of possible resolutions, no amount has been accrued as of December 31, 2016 or 2015, respectively.

Appeal with ONRR.  In 2009, the Company recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of deepwater production through our subsea pipeline systems.  In 2010, the ONRR audited the calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken.  We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR.  We filed an appeal with the ONRR, which was denied in May 2014.  On June 17, 2014, we filed an appeal with the IBLA.  On January 27, 2017, the IBLA affirmed the decision of ONRR requiring W&T to pay approximately $4.7 million in additional royalties plus interest.  We are reviewing the decision with counsel to determine an appropriate course of action.  We have 180 days to file suit in federal district court for judicial review of final agency action.  Based on the date of the IBLA decision, the filing deadline is July 26, 2017.

Iberville School Board Lawsuit.  In August 2013, a citation was issued on behalf of plaintiffs, the State of Louisiana and the Iberville Parish School Board, in their suit against the Company (among others) in the 18th Judicial District Court for the Parish of Iberville, State of Louisiana.  This case involves claims by the Iberville Parish School Board that certain property in Louisiana had allegedly been contaminated or otherwise damaged by certain defendants’ oil and gas exploration and production activities.  The plaintiff’s claims include assessment costs, restoration costs, diminution of property value, punitive damages, and attorney fees and expenses, of which were not quantified in the claim.  The case was set for trial on August 15, 2016, but the trial date has been deferred until early 2017. We cannot currently estimate our potential exposure, if any, related to this lawsuit.  We are currently, and intend to continue vigorously defending this litigation.


Other Claims.  We are a party to various pending or threatened claims and complaints seeking damages if any.  or other remedies concerning our commercial operations and other matters in the ordinary course of our business.  In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties.  In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold.  In addition, the BOEM considers all owners of record title and/or operating rights interest in an OCS lease to be jointly and severally liable for the satisfaction of the financial assurance requirements and/or decommissioning obligations that have accrued to such owners.  Accordingly, we may be required to satisfy financial assurance requirements or decommissioning obligations of a defaulting owner of record title and/or operating rights interest in an OCS lease in which we are (or in some cases were) an owner of record title and/or operating rights interest in the same OCS lease.  We are also subject to federal and state administrative proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federal-owned properties.  Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

See Financial Statements and Supplementary Data - Note 1817 – Contingencies under Part II, Item 8 in this Form 10-K for additional information.  information on this matters described above.

Monetary Sanctions by Government Authorities.  During 2014, we paid a civil penalty assessment from the BSEE for $30,000 and we also paid the United States Coast Guard penalties for insignificant discharges (less than 0.0017 barrels in the aggregate) totaling less than $4,000.  In February 2015, the Company received a Notice of Proposed Civil Penalty Assessment from the BSEE affecting the Company’s operated platform A in the East Cameron 321 field in the Gulf of Mexico.  The BSEE proposed civil penalties totaled $990,000, which arose from two Incidents of Noncompliance (“INCs”) issued in 2014 during drilling operations.  No injuries or spills occurred related to these two issues and the Company is contesting the BSEE proposal.

42


Other Litigation. From time to time, we are party to other litigation or legal and administrative proceedings that we consider to be a part of the ordinary course of our business. Except for the matters noted above, we are not involved in any legal proceedings nor are we party to any pending or threatened claims that could, individually or in the aggregate, reasonably be expected to have a material adverse effect on our consolidated financial condition, cash flow or results of operations.

Executive Officers of the Registrant

The following lists our executive officers:

Name

Age (1)

 

 

Position

Tracy W. Krohn

 

6062

 

 

Founder, Chairman, Director and Chief Executive Officer

Jamie L. Vazquez

 

5456

 

 

President

John D. Gibbons

 

6163

 

 

Senior Vice President and Chief Financial Officer

Thomas P. Murphy

 

5254

 

 

Senior Vice President and Chief Operations Officer

Stephen L. Schroeder

 

5254

 

 

Senior Vice President and Chief Technical Officer

Thomas F. Getten

 

6769

 

 

Vice President, General Counsel and Secretary

(1)Ages as of February 23, 2017.

Ages as of February 23, 2015.

Tracy W. Krohn has served as Chief Executive Officer since he founded the Company in 1983 and as Chairman since 2004.  He also served as President of the Company until September 2008.  During 1996 to 1997, Mr. Krohn was Chairman and Chief Executive Officer of Aviara Energy Corporation.  Prior to founding the Company, from 1982 to 1983, Mr. Krohn was a senior engineer with Taylor Energy, and he began his career as a petroleum engineer and offshore drilling supervisor with Mobil Oil Corporation.

Jamie L. Vazquez joined the Company in 1998 as Manager of Land and in 2003 she was named Vice President of Land.  In September 2008, Ms. Vazquez was appointed President of the Company.  Prior to joining the Company, Ms. Vazquez was with CNG Producing Company for 17 years, holding positions of increasing responsibility ending as Manager, Land/Business Development Gulf of Mexico.

John D. Gibbons joined the Company in February 2007 as Senior Vice President and Chief Financial Officer.  Prior to joining the Company, Mr. Gibbons was Senior Vice President and Chief Financial Officer of Westlake Chemical Corporation from March 2006 to February 2007.  Prior to joining Westlake, Mr. Gibbons was with Valero Energy Corporation for 23 years, holding positions of increasing responsibility ending as Executive Vice President and Chief Financial Officer.

Thomas P. Murphy joined the Company in June 2012 as Senior Vice President and Chief Operations Officer.  From 2009 to 2012, Mr. Murphy worked at Woodside Energy USA Inc. as Vice President Engineering and Operations.  From 2008 to 2009 he worked for PetroQuest Energy, Inc. as Vice President Engineering.  From 2000 to 2008, Mr. Murphy worked for Devon Energy Corporation in a variety of positions, including Gulf of Mexico Deep-Water Development Supervisor, New Business Development Supervisor and culminating in his position as Sr. Exploration Advisor.


Stephen L. Schroeder joined the Company in 1998 and served as Production Manager from 1999 until 2005.  In 2005, Mr. Schroeder was named Vice President of Production and in July 2006 he was named Senior Vice President and Chief Operating Officer.  In June 2012, Mr. Schroeder was named Senior Vice President and Chief Technical Officer.  Prior to joining the Company, Mr. Schroeder was with Exxon USA for 12 years holding positions of increasing responsibility, ending with Offshore Division Reservoir Engineer.

Thomas F. Getten joined the Company in July 2006 as Vice President, General Counsel and Assistant Secretary.  In December 2011, Mr. Getten was appointed to the position of Corporate Secretary.  Prior to joining the Company, Mr. Getten served as a partner with King, LeBlanc & Bland, P.L.L.C., a New Orleans law firm, since February 2001.  From 1996 to December 2000, Mr. Getten served as Vice President, Secretary and General Counsel of Forcenergy Inc until its merger into Forest Oil Corporation.

Item 4. Mine Safety Disclosures

Not applicable.

 

43


PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed and principally traded on the NYSE under the symbol “WTI”.“WTI.”  The following table sets forth the high and low sales priceprices of our common stock as reported on the NYSE.

 

High

 

 

Low

 

High

 

 

Low

 

2014:

 

 

 

 

 

 

 

2016:

 

 

 

 

 

 

 

First Quarter

$

17.33

 

 

$

13.52

 

$

7.48

 

 

$

1.23

 

Second Quarter

 

19.78

 

 

 

14.00

 

 

2.74

 

 

 

1.93

 

Third Quarter

 

16.75

 

 

 

10.87

 

 

2.35

 

 

 

1.51

 

Fourth Quarter

 

11.32

 

 

 

5.34

 

 

3.47

 

 

 

1.31

 

2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015:

 

 

 

 

 

 

 

First Quarter

 

18.45

 

 

 

14.07

 

 

7.28

 

 

 

5.08

 

Second Quarter

 

15.86

 

 

 

10.68

 

 

6.80

 

 

 

5.24

 

Third Quarter

 

18.16

 

 

 

14.23

 

 

5.42

 

 

 

2.86

 

Fourth Quarter

 

20.43

 

 

 

14.77

 

 

4.00

 

 

 

2.05

 

 

As of March 3, 2015,February 28, 2017, there were 199187 registered holders of our common stock.

Dividends

UnderDuring 2016 and 2015, no dividends were paid as dividend payments have been suspended.  Dividends are subject to certain statutory requirements which include positive net equity.  Our Board of Directors decides the Credit Agreement, wetiming and amounts of any dividends for the Company.  Dividends are allowedsubject to pay annual dividendsperiodic review of up to $60.0 million per year if we are not in default. In addition, the indenture governing our 8.50% Senior Notes due in 2019 (the “8.50% Senior Notes”) contains restrictions onCompany’s performance, which includes the payment of dividends unless we meet certain restricted payments test.current economic environment and applicable debt agreement restrictions.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 and Financial Statements and Supplementary Data – Note 72 – Long-Term Debt under Part II, Item 8 in this Form 10-K for more information regarding covenants related to dividends in our Credit Agreement and the indenture governing the 8.50% Senior Notes.

The following reflects the frequency and amounts of all cash dividends declared during the two most recent fiscal years (in thousands, except per share data):debt agreements.

 

Aggregate

Dividends on

Common

Stock

 

 

Dividends per

Share of

Common

Stock

 

2014:

 

 

 

 

 

 

 

First Quarter

$

7,562

 

 

$

0.10

 

Second Quarter

 

7,566

 

 

 

0.10

 

Third Quarter

 

7,566

 

 

 

0.10

 

Fourth Quarter

 

7,566

 

 

 

0.10

 

2013:

 

 

 

 

 

 

 

First Quarter

 

6,020

 

 

 

0.08

 

Second Quarter

 

6,775

 

 

 

0.09

 

Third Quarter

 

6,775

 

 

 

0.09

 

Fourth Quarter (1)

 

39,276

 

 

 

0.52

 


(1)

Includes a regular dividend of $7.5 million ($0.10 per common share) and a special cash dividend of $31.8 million ($0.42 per common share).

Our Board of Directors decides on the dividend for the Company.  Dividends are subject to periodic review of the Company’s performance and the current economic environment and applicable debt agreement restrictions. In light of current market conditions, the Board of Directors has elected to suspend the regular quarterly dividend.

44


Stock Performance Graph

The graph below shows the cumulative total shareholder return assuming the investment of $100 in our common stock and the reinvestment of all dividends thereafter.  The information contained in the graph below is furnished and not filed, and is not incorporated by reference into any document that incorporates this Annual Report on Form 10-K by reference.

 

Our peer group is comprised of Apache Corporation, Bill Barrett Corp., Cabot Oil & Gas Corp., Comstock Resources, Inc., Energy XXI (Bermuda) Limited, Forest Oil Corp., Newfield Exploration Co., SM Energy Co., SandRidge Energy, Inc., Stone Energy Corp., and Swift Energy Company.

Forest Oil Corp. merged with another company during December 2014.  Its shares were included  Three of the companies in our peer group filed for Chapter 11 reorganization under the U.S. Bankruptcy Code in the last year.  The above peer group sinceinvestment returns assume that common stock investment value in the transaction did not occur until nearbankrupt companies was zero in the end of 2014.  year in which they filed for bankruptcy.


Securities Authorized for Issuance Underunder Equity Compensation Plans

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.  For descriptions of the plans and additional information, see Financial Statements and Supplementary Data – Note 10 –Incentive Compensation Plan and Note 11– Share-Based–Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 in this Form 10-K.

Issuer Purchases of Equity Securities

For the year 2014,2016, we did not purchase any of our equity securities.

The following table sets forth information about restricted stock units (“RSUs”) delivered by employees during the quarter ended December 31, 20142016 to satisfy tax withholding obligations on the vesting of restricted stock units.RSUs.

Period

 

Total

Number of

Restricted

Stock Units

Delivered

 

 

Average

Price per

Restricted

Stock Unit

 

 

Total Number of

Shares Purchased

as Part of Publicly

Announced

Plans or Programs

 

Maximum Number

(or Approximate Dollar

Value) of Shares that

May Yet be Purchased

Under the Plans

or Programs

October 1, 2014 - October 31, 2014

 

N/A

 

 

N/A

 

 

N/A

 

N/A

November 1, 2014 - November 30, 2014

 

N/A

 

 

N/A

 

 

N/A

 

N/A

December 1, 2014 - December 31, 2014

 

 

107,173

 

 

$

5.49

 

 

N/A

 

N/A

Period

 

Total

Number of

Restricted

Stock Units

Delivered

 

 

Average

Price per

Restricted

Stock Unit

 

 

Total Number of

Shares Purchased

as Part of Publicly

Announced

Plans or Programs

 

Maximum Number

(or Approximate Dollar

Value) of Shares that

May Yet be Purchased

Under the Plans

or Programs

October 1, 2016 - October 31, 2016

 

N/A

 

 

N/A

 

 

N/A

 

N/A

November 1, 2016 - November 30, 2016

 

N/A

 

 

N/A

 

 

N/A

 

N/A

December 1, 2016 - December 31, 2016

 

 

356,550

 

 

$

2.51

 

 

N/A

 

N/A

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


ItemItem 6. Selected Financial Data

SELECTED HISTORICAL FINANCIAL INFORMATION

The selected historical financial information set forth below should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and with Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K.

 

Year Ended December 31,

 

Year Ended December 31,

 

2014(1)

 

 

2013(2)

 

 

2012(3)

 

 

2011(4)

 

 

2010(5)

 

2016 (1)

 

 

2015 (1) (2)

 

 

2014 (3)

 

 

2013 (4)

 

 

2012 (5)

 

(In thousands, except per share data)

 

(In thousands, except per share data)

 

Consolidated Statement of Operations Information:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

$

652,776

 

 

$

718,944

 

 

$

629,548

 

 

$

643,222

 

 

$

453,435

 

$

268,950

 

 

$

349,191

 

 

$

652,776

 

 

$

718,944

 

 

$

629,548

 

NGLs

 

72,837

 

 

 

73,345

 

 

 

84,637

 

 

 

105,559

 

 

 

51,931

 

 

26,429

 

 

 

27,665

 

 

 

72,837

 

 

 

73,345

 

 

 

84,637

 

Natural gas

 

217,816

 

 

 

189,290

 

 

 

158,390

 

 

 

221,194

 

 

 

203,533

 

 

100,405

 

 

 

123,435

 

 

 

217,816

 

 

 

189,290

 

 

 

158,390

 

Other (6)

 

5,279

 

 

 

2,509

 

 

 

1,916

 

 

 

1,072

 

 

 

(3,116

)

 

4,202

 

 

 

6,974

 

 

 

5,279

 

 

 

2,509

 

 

 

1,916

 

Total revenues (7)

 

948,708

 

 

 

984,088

 

 

 

874,491

 

 

 

971,047

 

 

 

705,783

 

 

399,986

 

 

 

507,265

 

 

 

948,708

 

 

 

984,088

 

 

 

874,491

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses (8)

 

264,751

 

 

 

270,839

 

 

 

232,260

 

 

 

219,206

 

 

 

169,670

 

 

152,399

 

 

 

192,765

 

 

 

264,751

 

 

 

270,839

 

 

 

232,260

 

Production taxes

 

7,932

 

 

 

7,135

 

 

 

5,840

 

 

 

4,275

 

 

 

1,194

 

 

1,889

 

 

 

3,002

 

 

 

7,932

 

 

 

7,135

 

 

 

5,840

 

Gathering and transportation

 

19,821

 

 

 

17,510

 

 

 

14,878

 

 

 

16,920

 

 

 

16,484

 

 

22,928

 

 

 

17,157

 

 

 

19,821

 

 

 

17,510

 

 

 

14,878

 

Depreciation, depletion and amortization

 

490,469

 

 

 

430,611

 

 

 

336,177

 

 

 

299,015

 

 

 

268,415

 

 

194,038

 

 

 

373,368

 

 

 

490,469

 

 

 

430,611

 

 

 

336,177

 

Asset retirement obligations accretion

 

20,633

 

 

 

20,918

 

 

 

20,055

 

 

 

29,771

 

 

 

25,685

 

 

17,571

 

 

 

20,703

 

 

 

20,633

 

 

 

20,918

 

 

 

20,055

 

Ceiling test write-down of oil and natural gas

properties (6)

 

279,063

 

 

 

987,238

 

 

 

 

 

 

 

 

 

 

General and administrative expenses

 

86,999

 

 

 

81,874

 

 

 

82,017

 

 

 

74,296

 

 

 

53,290

 

 

59,740

 

 

 

73,110

 

 

 

86,999

 

 

 

81,874

 

 

 

82,017

 

Derivative (gain) loss

 

(3,965

)

 

 

8,470

 

 

 

13,954

 

 

 

(1,896

)

 

 

4,256

 

 

2,926

 

 

 

(14,375

)

 

 

(3,965

)

 

 

8,470

 

 

 

13,954

 

Total costs and expenses

 

886,640

 

 

 

837,357

 

 

 

705,181

 

 

 

641,587

 

 

 

538,994

 

 

730,554

 

 

 

1,652,968

 

 

 

886,640

 

 

 

837,357

 

 

 

705,181

 

Operating income

 

62,068

 

 

 

146,731

 

 

 

169,310

 

 

 

329,460

 

 

 

166,789

 

Operating income (loss)

 

(330,568

)

 

 

(1,145,703

)

 

 

62,068

 

 

 

146,731

 

 

 

169,310

 

Interest expense, net of amounts capitalized

 

78,396

 

 

 

75,581

 

 

 

49,994

 

 

 

42,516

 

 

 

37,706

 

 

92,271

 

 

 

97,336

 

 

 

78,396

 

 

 

75,581

 

 

 

49,994

 

Loss on extinguishment of debt (9)

 

 

 

 

 

 

 

 

 

 

22,694

 

 

 

 

Other income, net (10)

 

208

 

 

 

8,946

 

 

 

215

 

 

 

84

 

 

 

710

 

Gain on exchange of debt (7)

 

123,923

 

 

 

 

 

 

 

 

 

 

 

 

 

Other (income) expense, net (8)

 

(6,520

)

 

 

4,663

 

 

 

(208

)

 

 

(8,946

)

 

 

(215

)

Income (loss) before income tax expense

(benefit)

 

(16,120

)

 

 

80,096

 

 

 

119,531

 

 

 

264,334

 

 

 

129,793

 

 

(292,396

)

 

 

(1,247,702

)

 

 

(16,120

)

 

 

80,096

 

 

 

119,531

 

Income tax expense (benefit)

 

(4,459

)

 

 

28,774

 

 

 

47,547

 

 

 

91,517

 

 

 

11,901

 

 

(43,376

)

 

 

(202,984

)

 

 

(4,459

)

 

 

28,774

 

 

 

47,547

 

Net income (loss)

$

(11,661

)

 

$

51,322

 

 

$

71,984

 

 

$

172,817

 

 

$

117,892

 

$

(249,020

)

 

$

(1,044,718

)

 

$

(11,661

)

 

$

51,322

 

 

$

71,984

 

Basic and diluted earnings (loss) per common share

$

(0.16

)

 

$

0.68

 

 

$

0.95

 

 

$

2.29

 

 

$

1.58

 

$

(2.60

)

 

$

(13.76

)

 

$

(0.16

)

 

$

0.68

 

 

$

0.95

 

Dividends on common stock (11)

 

30,260

 

 

 

58,846

 

 

 

82,832

 

 

 

58,756

 

 

 

59,609

 

Dividends on common stock (9)

 

 

 

 

 

 

 

30,260

 

 

 

58,846

 

 

 

82,832

 

Cash dividends per common share

 

0.40

 

 

 

0.78

 

 

 

1.11

 

 

 

0.79

 

 

 

0.80

 

 

 

 

 

 

 

 

0.40

 

 

 

0.78

 

 

 

1.11

 

Consolidated Cash Flow Information:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash providing by operating activities

$

511,423

 

 

$

561,358

 

 

$

385,137

 

 

$

521,478

 

 

$

464,772

 

Capital expenditures - oil and natural gas properties

 

626,612

 

 

 

634,378

 

 

 

684,863

 

 

 

719,026

 

 

 

415,653

 

Net cash providing by operating activities (10)

$

14,180

 

 

$

133,228

 

 

$

474,821

 

 

$

562,708

 

 

$

358,353

 

Capital expenditures - oil and natural gas properties (11)

 

48,606

 

 

 

230,161

 

 

 

626,612

 

 

 

634,378

 

 

 

684,863

 


 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

2013

 

 

2012

 

 

(In thousands)

 

Consolidated Balance Sheet Information:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

70,236

 

 

$

85,414

 

 

$

233,666

 

 

$

15,800

 

 

$

12,245

 

Total assets

 

829,726

 

 

 

1,208,022

 

 

 

2,689,508

 

 

 

2,497,180

 

 

 

2,337,615

 

Long-term debt (including current portion)

 

1,020,727

 

 

 

1,196,855

 

 

 

1,352,120

 

 

 

1,195,883

 

 

 

1,076,506

 

Shareholders' equity (deficit)

 

(659,037

)

 

 

(526,491

)

 

 

509,308

 

 

 

540,610

 

 

 

541,187

 

 

 

December 31,

 

 

2014

 

 

2013

 

 

2012

 

 

2011

 

 

2010

 

 

(In thousands)

 

Consolidated Balance Sheet Information:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

23,666

 

 

$

15,800

 

 

$

12,245

 

 

$

4,512

 

 

$

28,655

 

Total assets

 

2,709,107

 

 

 

2,507,302

 

 

 

2,348,987

 

 

 

1,868,925

 

 

 

1,424,094

 

Long-term debt

 

1,360,057

 

 

 

1,205,421

 

 

 

1,087,611

 

 

 

717,000

 

 

 

450,000

 

Shareholders' equity

 

509,308

 

 

 

540,610

 

 

 

541,187

 

 

 

544,574

 

 

 

421,743

 


46


(1)

Revenue was lower than the prior year for 2016 and 2015 primarily due to lower commodity prices of oil, NGL’s and natural gas.

(2)

In the fourth quarter of 2015, we sold our interest in the Yellow Rose field.

(3)

In the second quarter of 2014, we acquired the Woodside Properties from Woodside and, in the third quarter of 2014, we acquired the remaining working interest in the Fairway PropertiesField and the associated Yellowhammer gas processing plant that we did not already own.

(2)(4)

In the fourth quarter of 2013, we acquired theproperties from Callon Properties from Callon.Petroleum Operating Company.

(3)(5)

In the fourth quarter of 2012, we acquired the Newfield Properties from Newfield.

(4)

In the second quarter of 2011, we acquired the Opal Properties from Opal and, in the third quarter of 2011, we acquired the Fairway Properties from Shell.

(5)

In the second quarter of 2010, we acquired certain properties from Total E&PNewfield Exploration Company and in the fourth quarter of 2010, we acquired certain properties from Shell.its subsidiary Newfield Exploration Gulf Coast LLC.

(6)

Included in other revenuesIn 2016 and 2015, we incurred impairment charges for 2010 is a reductionceiling test write-downs of $4.7 millionour oil and gas properties due to a disallowance by the ONRR of royalty relief for transportation of deepwater production through our subsea pipeline system that was originally recordedsubstantial reductions in 2009. We are contesting this ONRR adjustment.commodity prices.

(7)

IncludedIn 2016, we recorded a gain from the Exchange Transaction.   See Management’s Discussion and Analysis of Financial Condition and Results of Operations in total revenuesPart II, Item 7, and in Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for 2010 is $24.9 million related toa full description of the recoupment of royalties paid totransaction, the ONRR in prior periods based on price thresholds that were believed to limitnew debt instruments and the availability of royalty relief on certain properties subject toaccounting for the OCS Deepwater Relief Act of 1995.transaction.

(8)

Included in lease operating expenses are charges to In 2016, other (income)/expense, for hurricane-related repairs net, of insurance reimbursements. For the year 2010, the impact to lease operating expenses attributable to net hurricane –related expenses/reimbursements was an $11.7 million decrease. There was minimal impact to lease operating expenses in the other years presented.

(9)

In 2011, we expensed repurchase premiums, deferred financing costs and other costs totaling $22.0includes $7.7 million related to settlement of certain claims with insurance companies related to damages from Hurricane Ike.  In 2016 and 2015, other (income)/expense, net, include $1.4 million and $3.2 million, respectively, for write-downs of debt issuance costs related to reductions of the repurchaseborrowing base of $450.0 million in aggregate principal amount of our 8.25% Senior Notes due 2014.

(10)

the revolving bank credit facility.  In 2013, other income(income)/expense, net, consisted primarily of payments received in conjunction with an option exercised by a counterparty.

(11)(9)

The years 2013 2012, 2011 and 20102012 included special dividends of $31.8 million ($0.42 per share), and $59.0 million ($0.79 per share), $46.9 million ($0.63 per share) and $49.2 million ($0.66 per share), respectively.  No special dividends were paid in 2014.

(10)

2015 and 2014 were retrospectively adjusted to conform to the current year presentation related to the early adoption of certain accounting standards and for other conforming adjustments.  

(11)

Reported on an accrual basis.




HISTORICAL RESERVE AND OPERATING INFORMATION

The following presentstables present summary information regarding our estimated net proved oil, NGLs and natural gas reserves and our historical operating data for the years shown below.  Estimated net proved reserves are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December of the respective year in accordance with SEC guidelines.  For additional information regarding our estimated proved reserves, please read Business under Part I, Item 1 and Properties under Part I, Item 2 of this Form 10-K.  The selected historical operating data set forth below should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and with Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K.

 

December 31,

 

December 31,

 

2014

 

 

2013

 

 

2012

 

 

2011

 

 

2010

 

2016

 

 

2015

 

 

2014

 

 

2013

 

 

2012

 

Reserve Data: (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Estimated net proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MMBbls)

 

61.7

 

 

 

58.5

 

 

 

54.8

 

 

 

51.4

 

 

 

34.0

 

 

32.9

 

 

 

35.5

 

 

 

61.7

 

 

 

58.5

 

 

 

54.8

 

NGLs (MMBbls)

 

15.8

 

 

 

15.9

 

 

 

15.2

 

 

 

17.1

 

 

 

4.2

 

 

8.2

 

 

 

6.6

 

 

 

15.8

 

 

 

15.9

 

 

 

15.2

 

Natural Gas (Bcf)

 

254.9

 

 

 

259.9

 

 

 

285.1

 

 

 

289.7

 

 

 

256.3

 

 

197.8

 

 

 

205.4

 

 

 

254.9

 

 

 

259.9

 

 

 

285.1

 

Total barrel equivalents (MMBoe)

 

120.0

 

 

 

117.7

 

 

 

117.5

 

 

 

116.9

 

 

 

80.9

 

 

74.0

 

 

 

76.4

 

 

 

120.0

 

 

 

117.7

 

 

 

117.5

 

Total natural gas equivalents (Bcfe)

 

720.0

 

 

 

705.9

 

 

 

705.1

 

 

 

701.1

 

 

 

485.4

 

 

444.0

 

 

 

458.1

 

 

 

720.0

 

 

 

705.9

 

 

 

705.1

 

Proved developed producing (MMBoe)

 

68.7

 

 

 

60.6

 

 

 

62.6

 

 

 

54.3

 

 

 

39.4

 

 

47.3

 

 

 

57.6

 

 

 

68.7

 

 

 

60.6

 

 

 

62.6

 

Proved developed non-producing (MMBoe) (2)

 

14.6

 

 

 

25.5

 

 

 

24.3

 

 

 

22.1

 

 

 

25.8

 

 

17.4

 

 

 

11.4

 

 

 

14.6

 

 

 

25.5

 

 

 

24.3

 

Total proved developed (MMBoe)

 

83.3

 

 

 

86.1

 

 

 

86.9

 

 

 

76.4

 

 

 

65.2

 

 

64.7

 

 

 

69.0

 

 

 

83.3

 

 

 

86.1

 

 

 

86.9

 

Proved undeveloped (MMBoe)

 

36.7

 

 

 

31.6

 

 

 

30.6

 

 

 

40.5

 

 

 

15.7

 

 

9.3

 

 

 

7.4

 

 

 

36.7

 

 

 

31.6

 

 

 

30.6

 

Proved developed reserves as %

 

69.4

%

 

 

73.2

%

 

 

74.0

%

 

 

65.4

%

 

 

80.6

%

 

87.4

%

 

 

90.3

%

 

 

69.4

%

 

 

73.2

%

 

 

74.0

%

Reserve additions (reductions) (MMBoe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revisions(2)

 

4.1

 

 

 

(3.9

)

 

 

(4.7

)

 

 

8.6

 

 

 

3.4

 

 

13.0

 

 

 

(12.7

)

 

 

4.1

 

 

 

(3.9

)

 

 

(4.7

)

Extensions and discoveries

 

9.7

 

 

 

20.2

 

 

 

15.8

 

 

 

5.3

 

 

 

4.9

 

 

 

 

 

4.1

 

 

 

9.7

 

 

 

20.2

 

 

 

15.8

 

Purchases of minerals in place

 

6.1

 

 

 

2.4

 

 

 

7.0

 

 

 

39.0

 

 

 

25.3

 

 

 

 

 

1.0

 

 

 

6.1

 

 

 

2.4

 

 

 

7.0

 

Sales of minerals in place(3)

 

 

 

 

(0.5

)

 

 

(0.4

)

 

 

 

 

 

 

 

 

 

 

(19.0

)

 

 

 

 

 

(0.5

)

 

 

(0.4

)

Production

 

(17.6

)

 

 

(18.0

)

 

 

(17.1

)

 

 

(16.9

)

 

 

(14.5

)

 

(15.4

)

 

 

(17.0

)

 

 

(17.6

)

 

 

(18.0

)

 

 

(17.1

)

Net reserve additions

 

2.3

 

 

 

0.2

 

 

 

0.6

 

 

 

36.0

 

 

 

19.1

 

Net reserve additions (reductions)

 

(2.4

)

 

 

(43.6

)

 

 

2.3

 

 

 

0.2

 

 

 

0.6

 

(1)

The conversions to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bblbarrel of crude oil, condensate or NGLs (totals may not compute due to rounding).  The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

(2)

Approximately 1.4 MMBoe and 1.5 MMBoe of reserves as of December 31, 2013 and 2012, respectively, were shut in at our Mississippi Canyon 506 field (Wrigley)Revisions include changes due to a platform and pipeline outage.  Approximately 4.9 MMBoeprice estimated for reserves held at year-end for each year presented.  Revisions in 2015 also include revisions related to the Yellow Rose field up to the date of reserves were shut in at December 31, 2010 due to two pipeline outages impacting several fields, including our Main Pass 108 field.the sale.  

(3)

In 2015, sales related primarily to the sale of the Yellow Rose field.

Volume measurements:

 

 

MMBbls – million barrels of crude oil, condensate or NGLs

 

Bcf – billion cubic feet

MMBoe – million barrels of oil equivalent

 

Bcfe – billion cubic feet of gas equivalent

 




 

Year Ended December 31,

 

Year Ended December 31,

 

2014

 

 

2013(1)

 

 

2012

 

 

2011

 

 

2010

 

2016

 

 

2015

 

 

2014

 

 

2013 (1)

 

 

2012

 

Operating: (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

7,176

 

 

 

7,018

 

 

 

6,033

 

 

 

6,073

 

 

 

5,863

 

 

7,201

 

 

 

7,751

 

 

 

7,176

 

 

 

7,018

 

 

 

6,033

 

NGLs (MBbls)

 

2,112

 

 

 

2,091

 

 

 

2,129

 

 

 

1,892

 

 

 

1,190

 

 

1,542

 

 

 

1,604

 

 

 

2,112

 

 

 

2,091

 

 

 

2,129

 

Oil and NGLs (MBbls)

 

9,288

 

 

 

9,110

 

 

 

8,163

 

 

 

7,964

 

 

 

7,053

 

 

8,743

 

 

 

9,355

 

 

 

9,288

 

 

 

9,110

 

 

 

8,163

 

Natural gas (MMcf)

 

50,088

 

 

 

53,257

 

 

 

53,825

 

 

 

53,743

 

 

 

44,713

 

 

39,731

 

 

 

46,163

 

 

 

50,088

 

 

 

53,257

 

 

 

53,825

 

Total oil equivalent (MBoe)

 

17,636

 

 

 

17,986

 

 

 

17,133

 

 

 

16,921

 

 

 

14,505

 

 

15,365

 

 

 

17,049

 

 

 

17,636

 

 

 

17,986

 

 

 

17,133

 

Total natural gas equivalents (MMcfe)

 

105,815

 

 

 

107,915

 

 

 

102,800

 

 

 

101,528

 

 

 

87,032

 

 

92,188

 

 

 

102,294

 

 

 

105,815

 

 

 

107,915

 

 

 

102,800

 

Average daily equivalent sales (Boe/day)

 

48,317

 

 

 

49,276

 

 

 

46,813

 

 

 

46,360

 

 

 

39,741

 

 

41,980

 

 

 

46,709

 

 

 

48,317

 

 

 

49,276

 

 

 

46,813

 

Average daily equivalent sales (Mcfe/day)

 

289,904

 

 

 

295,657

 

 

 

280,875

 

 

 

278,158

 

 

 

238,445

 

 

251,879

 

 

 

280,256

 

 

 

289,904

 

 

 

295,657

 

 

 

280,875

 

Average realized sales prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

$

90.96

 

 

$

102.44

 

 

$

104.35

 

 

$

105.92

 

 

$

77.33

 

$

37.35

 

 

$

45.05

 

 

$

90.96

 

 

$

102.44

 

 

$

104.35

 

NGLs ($/Bbl)

 

34.49

 

 

 

35.07

 

 

 

39.75

 

 

 

55.81

 

 

 

43.65

 

 

17.14

 

 

 

17.25

 

 

 

34.49

 

 

 

35.07

 

 

 

39.75

 

Oil and NGLs ($/Bbl)

 

78.13

 

 

 

86.97

 

 

 

87.50

 

 

 

94.02

 

 

 

71.65

 

 

33.79

 

 

 

40.28

 

 

 

78.13

 

 

 

86.97

 

 

 

87.50

 

Natural gas ($/Mcf)

 

4.35

 

 

 

3.55

 

 

 

2.94

 

 

 

4.12

 

 

 

4.55

 

 

2.53

 

 

 

2.67

 

 

 

4.35

 

 

 

3.55

 

 

 

2.94

 

Oil equivalent ($/Boe)

 

53.49

 

 

 

54.58

 

 

 

50.93

 

 

 

57.32

 

 

 

48.87

 

 

25.76

 

 

 

29.34

 

 

 

53.49

 

 

 

54.58

 

 

 

50.93

 

Natural gas equivalent ($/Mcfe)

 

8.92

 

 

 

9.10

 

 

 

8.49

 

 

 

9.55

 

 

 

8.15

 

 

4.29

 

 

 

4.89

 

 

 

8.92

 

 

 

9.10

 

 

 

8.49

 

Average per Boe ($/Boe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

$

15.01

 

 

$

15.06

 

 

$

13.56

 

 

$

12.95

 

 

$

11.70

 

$

9.92

 

 

$

11.31

 

 

$

15.01

 

 

$

15.06

 

 

$

13.56

 

Gathering and transportation

 

1.14

 

 

 

0.95

 

 

 

0.85

 

 

 

1.01

 

 

 

1.16

 

 

1.49

 

 

 

1.01

 

 

 

1.14

 

 

 

0.95

 

 

 

0.85

 

Production costs

 

16.15

 

 

 

16.01

 

 

 

14.41

 

 

 

13.96

 

 

 

12.86

 

 

11.41

 

 

 

12.32

 

 

 

16.15

 

 

 

16.01

 

 

 

14.41

 

Production taxes

 

0.42

 

 

 

0.42

 

 

 

0.36

 

 

 

0.24

 

 

 

0.06

 

 

0.12

 

 

 

0.17

 

 

 

0.42

 

 

 

0.42

 

 

 

0.36

 

DD&A

 

28.98

 

 

 

25.10

 

 

 

20.79

 

 

 

19.43

 

 

 

20.28

 

 

13.77

 

 

 

23.11

 

 

 

28.98

 

 

 

25.10

 

 

 

20.79

 

General and administrative expenses

 

4.93

 

 

 

4.55

 

 

 

4.79

 

 

 

4.39

 

 

 

3.67

 

 

3.89

 

 

 

4.29

 

 

 

4.93

 

 

 

4.55

 

 

 

4.79

 

$

50.48

 

 

$

46.08

 

 

$

40.35

 

 

$

38.02

 

 

$

36.87

 

$

29.19

 

 

$

39.89

 

 

$

50.48

 

 

$

46.08

 

 

$

40.35

 

Average per Mcfe ($/Mcfe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

$

2.50

 

 

$

2.51

 

 

$

2.26

 

 

$

2.16

 

 

$

1.95

 

$

1.65

 

 

$

1.88

 

 

$

2.50

 

 

$

2.51

 

 

$

2.26

 

Gathering and transportation

 

0.19

 

 

 

0.16

 

 

 

0.14

 

 

 

0.17

 

 

 

0.19

 

 

0.25

 

 

 

0.17

 

 

 

0.19

 

 

 

0.16

 

 

 

0.14

 

Production costs

 

2.69

 

 

 

2.67

 

 

 

2.40

 

 

 

2.33

 

 

 

2.14

 

 

1.90

 

 

 

2.05

 

 

 

2.69

 

 

 

2.67

 

 

 

2.40

 

Production taxes

 

0.07

 

 

 

0.07

 

 

 

0.06

 

 

 

0.04

 

 

 

0.01

 

 

0.02

 

 

 

0.03

 

 

 

0.07

 

 

 

0.07

 

 

 

0.06

 

DD&A

 

4.83

 

 

 

4.18

 

 

 

3.47

 

 

 

3.24

 

 

 

3.38

 

 

2.30

 

 

 

3.85

 

 

 

4.83

 

 

 

4.18

 

 

 

3.47

 

General and administrative expenses

 

0.82

 

 

 

0.76

 

 

 

0.80

 

 

 

0.73

 

 

 

0.61

 

 

0.65

 

 

 

0.71

 

 

 

0.82

 

 

 

0.76

 

 

 

0.80

 

$

8.41

 

 

$

7.68

 

 

$

6.73

 

 

$

6.34

 

 

$

6.14

 

$

4.87

 

 

$

6.64

 

 

$

8.41

 

 

$

7.68

 

 

$

6.73

 

Wells drilled (gross):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

6

 

 

 

6

 

 

 

5

 

 

 

8

 

 

 

7

 

 

1

 

 

 

5

 

 

 

6

 

 

 

6

 

 

 

5

 

Onshore

 

33

 

 

 

40

 

 

 

77

 

 

 

40

 

 

 

2

 

 

 

 

 

5

 

 

 

33

 

 

 

40

 

 

 

77

 

Productive wells drilled (gross)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive wells drilled (gross):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

6

 

 

 

5

 

 

 

4

 

 

 

8

 

 

 

6

 

 

1

 

 

 

5

 

 

 

6

 

 

 

5

 

 

 

4

 

Onshore

 

33

 

 

 

40

 

 

 

77

 

 

 

39

 

 

 

 

 

 

 

 

5

 

 

 

33

 

 

 

40

 

 

 

77

 

 

49



(1)

In January 2014, we identified that we had been receiving an erroneous MMBtu conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe).  The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011.  The use of the incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense.  We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results and thus the adjustment was recognized in 2013.  The results for 2013 reflect a one-time increase in production of 1.9 Bcf in natural gas (with no corresponding increase in revenues) by using the correct conversion factor for the annual periods of 2011 and 2012.  Excluding the cumulative effect of the volumes adjustments related to 2011 and 2012, total production for 2013 would have been 106.0 Bcfe or 290.5 MMcfe per day and our combined average realized sales price would have been $9.26 per Mcfe.

(2)

The conversions to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bblbarrel of crude oil, condensate or NGLs (totals may not compute due to rounding).  The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

 

Volume measurements:

 

 

Bbl – barrel

 

Mcf – thousand cubic feet

Boe – barrel of oil equivalent

 

MMcf – million cubic feet

MBbls – thousand barrels for crude oil, condensate or NGLs

 

MMcfe – million cubic feet equivalent

MBoe – thousand barrels of oil equivalent

 

 

 

DD&A - depreciation, depletion, amortization and accretion


 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K.  The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs.  Our actual results could differ materially from those discussed in these forward-looking statements.  Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K, particularly in Risk Factors under Part I, Item 1A in this Form 10-K10-K.

Overview

We are an independent oil and natural gas producer with operations offshore in the Gulf of Mexico and onshore in the Permian Basin of West Texas.Mexico.  We have grown through acquisitions, exploration and development and currently hold working interests in approximately 6352 offshore fields in federal and state waters (61(50 producing and two fields capable of producing).  We currently have under lease approximately 1.2 million750,000 gross acres, includingwith approximately 0.6 million490,000 gross acres on the Gulf of Mexico Shelf,shelf and approximately 0.5 million260,000 gross acres in the deepwater and approximately 50,000 gross acres onshore, primarily in Texas.deepwater.  A substantial majority of our daily production is derived from wells we operate offshore.  We operate wells accounting for approximately 87% of our average daily production. We own interests in approximately 203164 offshore structures, 138107 of which are located in fields that we operate.  Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. and our wholly-ownwholly-owned subsidiary, W & T Energy VI, LLC.

In managing our business, we are concerned primarily with maximizing returnfocused on shareholders’ equity. To accomplish this primary goal, we focus on increasingmaintaining and growing production and reserves atin a profit.profitable and prudent manner.  We strive to growhave historically grown our reserves and production through acquisitions and our drilling programs.  WeWith respect to acquisitions, we have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to continue to add reserves post-acquisition.  Starting in mid-2014, commodity prices began to fall and continued falling during 2015 and 2016.  Towards the end of 2016 and during the first quarter of 2017, prices have recovered some from average realized prices during 2016, but are still well below 2014 levels.  Although our operating costs have also fallen during this time frame, our margins as a percentage of revenue have not recovered to the levels prior to 2015.  In reaction to the significant downturns during 2016 and 2015, we did not consummate any acquisitions of significance, we reduced our capital expenditures and we sold our interest in the Yellow Rose field discussed below.  Our plans for the short-term include operating within cash flow, maintaining liquidity, meeting our financial obligations, and pursuing acquisitions meeting our criteria.

Our drilling efforts in recent years have expanded in the deepwater of the Gulf of Mexico.  During 2016, our volumes included production from the deepwater fields, Big Bend and Dantzler, which commenced production in late 2015.  As of December 31, 2016, both fields were in our top ten fields based on reserves, net to our interest, on a Boe basis.  Both fields are composed of mostly oil and NGLs, having over 75% of reserves in oil and NGLs on a Boe basis.    

In September 2016, we consummated the Exchange Transaction whereby we exchanged approximately $710.2 million principal amount, or 79%, of our Unsecured Senior Notes for $301.8 million principal amount of new secured notes and 60.4 million shares of our common stock, and closed on a new $75.0 million 1.5 Lien Term Loan.  The funds from the 1.5 Lien Term Loan were used to partially pay down borrowings outstanding on the revolving bank credit facility and to pay transaction costs associated with the Exchange Transaction.  See the Liquidity and Capital Resources section of this Item 7, and Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for a full description of the transaction, the new debt instruments and the accounting for the transaction.


In October 2015, we sold our interests in the Yellow Rose onshore field in the Permian Basin to Ajax.  Our interest in the field covered approximately 25,800 net acres. During 2015, the Yellow Rose field accounted for approximately 5% and 6% of our production and revenues, respectively.   In connection with the sale, we retained a non-expense bearing ORRI equal to a variable percentage in production from the working interests sold, which percentage varies on a sliding scale from one percent for each month that the prompt month NYMEX trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than $90.00 per barrel.  Internal estimates of proved reserves at the date of the sale were 19.0 MMBoe, consisting of approximately 71% oil, 11% NGL and 18% natural gas.  Including adjustments from an effective date of January 1, 2015, the adjusted sales price was $370.9 million and the buyer assumed the ARO associated with our interests in the Yellow Rose field, which we had estimated at $6.9 million at the time of the sale.  We used a portion of the proceeds of the sale to repay all the outstanding borrowings under our revolving bank credit facility, while the remaining balance of approximately $100 million was added to available cash.

In September 2014, we acquired an additional ownership interest in the Fairway Field (Mobile Bay blocks 113 and 132132) located offshore Alabama)in Alabama state waters and the associated Yellowhammer gas processing plant, which increased our ownership interest from 64.3% to 100%.  Internal estimates of additional proved reserves associated with the increased ownership interest in the Fairway Field as of the acquisition date were approximately 4.4 MMBoe (26.4 Bcfe), comprised of approximately 26% NGLs and 74% natural gas, all of which were classified as proved developed.  Including adjustments from an effective date of July 1, 2014, the adjusted purchase price was $17.4 million and we assumed the additional ARO associated with the increased ownership interest in Fairway, which we have estimated to be $6.1 million.  The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

In May 2014, we acquired from Woodside certain oil and gas leasehold interests in the Gulf of Mexico (the “Woodside Properties”).  The Woodside Properties consisted of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks. Internal estimates of proved reserves associated with the Woodside Properties as of the acquisition dates were approximately 1.6 MMBoe (9.4 Bcfe), comprised of approximately 89% oil, 1% NGLs and 10% natural gas, all of which were classified as proved developed. Including adjustments from an effective date of November 1, 2013, the adjusted purchase price was $54.8 million and we assumed the ARO associated with the Woodside Properties, which we have estimated to be $11.3 million.  The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

In November and December 2013, we acquired from Callon certain oil and gas leasehold interests in the Gulf of Mexico.  The Callon Properties consist of a 15% working interest in the Medusa field (deepwater Mississippi Canyon blocks 582 and 583), interest in associated production facilities and various interests in other non-operated fields. Internal estimates of proved reserves associated with the Callon Properties as of the acquisition dates were approximately 2.1 MMBoe (12.7 Bcfe), comprised of approximately 67% oil and 33% natural gas, all of which were classified as proved developed.  Including adjustments from an effective date of July 1, 2013, the adjusted purchase price was $83.0 million and we assumed the ARO associated with the Callon Properties, which we have estimated to be $4.2 million. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

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In October 2012, we acquired from Newfield certain oil and gas leasehold interests. The Newfield Properties consisted of leases covering 78 federal offshore blocks on approximately 416,000 gross acres (268,000 net acres) predominantly in the deepwater. Internal estimates of proved reserves associated with the Newfield Properties as of the acquisition date were approximately 7.0 MMBoe (42.0 Bcfe), comprised of approximately 36% oil, 3% NGLs and 61% natural gas, all of which were classified as proved developed. Including adjustments from an effective date of July 1, 2012, the adjusted purchase price was $205.8 million and we assumed the ARO associated with the Newfield Properties, which we have estimated to be $31.7 million. The acquisition was initially funded from borrowings under our revolving bank credit facility and cash on hand. Subsequently in the same month, the amounts borrowed under our revolving bank credit facility were paid down with funds provided from the issuance of an additional $300.0 million of 8.50% Senior Notes.

See Financial Statements and Supplementary Data – Note 27 – Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K for additional information on acquisitions.acquisitions and divestitures.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production.  Our production volumes for 20142016 were comprised of approximately 41%47% oil and condensate, 12%10% NGLs and 47%43% natural gas, determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs.  The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices per Mcfe for crude oil, NGLs and natural gas may differ significantly.  For 2014,2016, our combined total production of oil, NGLs and natural gas was consistent with 2013, as we had new9.9% below 2015, primarily due to natural production from recently drilled wellsdeclines and acquisitions,divestiture of the Yellow Rose properties, partially offset by various pipeline outages, platform outages and maintenance shut-ins offshore and weather onshore.  During 2013, sales volumes also benefited from new wells that were brought on line along with production from acquisitions.  Thethe Big Bend and Dantzler fields, which began production in the fourth quarter of 2015, and from one well completed during the year 2013 was also negatively impacted by various pipeline outages, shut downs for maintenance, Tropical Storm Karen and various operational issues.  During 2012, sales volumes were negatively impacted by various pipeline outages, Hurricane Isaac and Tropical Storm Debbie.at our Ewing Bank 910 field.  

Our realized sales prices received for our crude oil, NGLs and natural gas production are affected by not only domestic production activities and political issues, but more importantly, international events, including both geopolitical and economic events.  For the first nine months of 2014, WTIDuring 2016 and Brent2015, crude oil, NGL, and natural gas realized prices averaged above $100 per barrel.  In fact, crude oilwere significantly below prior year prices.  Thus far in 2017, prices have averaged over $90 per barrel for WTIrecovered some and $100 per barrel for Brent forhave been higher than the last four years.  This in turnaverage prices occurring during 2016.  Partially offsetting the declining sales prices has led to significant cost inflationbeen a reduction in the oilcost of supplier goods and gas services industry.  Crude oil pricesin 2016 and 2015 compared to 2014, but these have fallennot decreased as quickly and dramatically recently from a peakas the price of $107 per barrel for WTIthe commodities that we sell; therefore, margins deteriorated significantly in June 2014 to the low $50s per barrel in December 20142016 and the mid $40s per barrel during January 2015.2015 along with total cash flows.  The current market imbalance is predominantly supply driven caused by a number of issues that are described below:below.  


The U.S. Energy Information Administration’s (“EIA”) data estimates the worldwide supply of crude oil will outpaceand other petroleum liquids outpaced consumption in 20142016 by approximately 800,0000.9 million barrels per day in addition to an oversupply in 2015 by 1.8 million barrels per day.  This was the third consecutive year that inventories had built and exerted downward pressure on prices.  For 20152017 and 2016,2018, EIA forecasts crude oil supply being above consumption by approximately 600,000 and 100,000 barrels per day, respectively, which is expected to keep downward pressure on prices.  Worldwide storage capacity exists for the excess oil in the next two years but this is only a temporary solution that has historically led to lower prices.  The extreme rapid decrease in crude oil prices appears to be due to supply-side growth.  Over the past five years, supply has increased at 1.7% per year, while consumption increased 1.5% per year.  Over the five year period, 2014 had the largest market imbalance, with supply increasing 2.3% compared to demand increasing at 1.0%.  For 2014, production growth from countries outside of OPEC grew at a record high of 2.0 million barrels per day over 2013, of which the U.S. grew production 1.60.3 million barrels per day and Canada grew production 0.3 million barrels per day.  OPEC production was relatively flat for 2014 compared to 2013.  OPEC members have taken no actions to reduce supplies and Saudi Arabia has made statements that it intends to protect its market share regardless of the price of crude oil.  Many countries, such as Russia, Iraq, Iran, Venezuela, have economies that are highly (or solely) dependent on oil revenues and do not have significant cash reserves like Saudi Arabia.  These countries are not able to reduce production to wait for higher prices in the future; therefore, these types of countries would not have the economic ability to withstand lower production, which would further hurt their economies and continue to pressure crude oil prices.  Iran, which has suffered under economic sanctions imposed by the United States and other NATO countries, is ramping up its production further exacerbating the excess crude oil supply situation.      

While many U. S. producers have reduced capital budgets for 2015 compared to 2014, the U.S. producers have projected constant or increased production of crude oil for 2015.  EIA estimates U.S. petroleum and other liquids production for 2014, 2015 and 2016 to be 14.0, 14.8 and 15.4 million barrels per day, respectively, and estimates Canada’s petroleum and other liquids production for 2014, 2015 and 2016 to be 4.4, 4.5 and 4.70.2 million barrels per day, respectively.  The increasing strengthCurrently, EIA estimates inventory builds in the U.S. dollar relative to other currencies has also had an impact on crude pricing.  Because all barrels are traded in U.S. dollars, as the U.S. dollar gains strength, crude prices are lower in U.S. dollars but are more expensive in other currencies.

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While the expectationsfirst two quarters of consumption growth have been lowered, consumption did grow in 2014 and is projected to grow over the next two years.  World-wide consumption growth of petroleum and other liquid products was estimated by EIA to be 1.0%, 1.1% and 1.1% for 2014, 2015 and 2016, respectively.  China and the U.S. are projected to be the leading contributors to world-wide growth for the next two years and Russia is projected to have the largest reduction in consumption2017, inventory usage in the next two years due tothird quarter of 2017, and an economic downturn.  Basedinventory build in the fourth quarter of 2017.  The high levels of excess inventory will likely exert downward pressure on prices in the above,near future.  Worldwide crude oil supply is expectedgrowth in 2016 from 2015 was estimated at 0.7%, while consumption growth was estimated at 1.6%.  The increases in production were primarily from OPEC, with Iran, Iraq and Saudi Arabia having the largest increases.  The forecast assumes the November 2016 OPEC production target agreement will be largely adhered to by many commentatorsthe countries within OPEC.  EIA forecasts supply increases in 2017 and 2018 of 1.1% and 1.4%, respectively, year over year.  EIA estimates consumption growing for most countries, except for Japan and Canada.  

According to exceed demand over the next two years.  Accordingly, we expect that prices will continuedata provided by EIA, U.S. production of crude oil (excluding other petroleum liquids) decreased in 2016 by 6% compared to stay depressed until such time as demand grows to meet supply or depressed prices drive producers to cut back production.

In addition to2015.  EIA’s estimate for 2017 and 2018 of U.S. crude oil production another factor affectingis an increase of 1.2% and 3.3%, respectively, year over year.  As noted below, the price of domestic crude oil is the ability to get production to market.  Over the past few years, the infrastructure (both pipeline and rail) to transport crude oil within the United States has seen a major and rapid change.  A number of pipelines have been builtrigs drilling for oil decreased dramatically in 2015 and completed, reversed flowed, or expanded to move crude oil from Cushing, Oklahoma (a major crude oil storage hub) primarily to the U.S. Gulf Coast but also to the Midwest as well.  Transportation capacity has also been added in major producing regions, like the Permian Basin, to move crude oil to the U.S. Gulf Coast rather than to Cushing.  Bothfurther decreased through most of these events have helped relieve the excess crude oil that built up in Cushing, which in turn allowed WTI pricing2016, and began to increase relative to Brent. Up toin the fourth quarter of 2013, WTI traded at a discount to Brent, while our Gulf Coast crude oil production traded at a premium to WTI.  The structural changes that have occurred as a result of new pipeline and rail infrastructure are expected to impact U.S. Gulf Coast crude oil pricing going forward.  Rail receiving capacity also expanded on the East Coast, and to some extent on the U.S. Gulf Coast, with more capacity being announced.  The average spread between Brent and WTI was $5.72 per barrel in 2014 compared to $10.52 per barrel in 2013 as a result of the increased domestic production and structural changes outlined above.  The Brent-WTI spread declined during 20142016 and the average spread for December 2014 was $3.04 per barrel.first quarter of 2017.

During 2014,2016, our average realized crude oil sales price was 11.2% lower$37.35, down from $45.05 per barrel (17.1% lower) for 2015.  The two primary benchmarks reported upon are the prices for WTI and Brent crude oil.  As reported by the EIA, WTI crude oil prices averaged $43.29 per barrel for 2016, down from $48.66 per barrel (11.0% lower) for 2015.  Brent crude average oil prices decreased to $43.67 per barrel for 2016, down from $52.32 per barrel (16.5% lower) for 2015.  WTI and Brent average crude oil prices in the fourth quarter of 2016 were higher than that realizedthe prior three quarters of 2016 presenting an upward trend in 2013.crude oil prices.  For 2016, WTI and Brent average prices were basically at parity.  Our average realized oil sales price percentage decrease($37.35 per barrel compared to a WTI benchmark price of $43.29 per barrel) for 2014 was lower than2016 differs from the benchmark crude oil benchmark WTIprices due to premiums or discounts (referred to as differentials), crude quality adjustments, volume weighting and other factors.  All of our oil during 2016 was produced offshore in the reduction in our offshore crude oil premiumsGulf of Mexico and is characterized as discussed above.  As reported by the EIA, WTI prices averaged $93.17 per barrel for 2014, down from $97.98 per barrel for 2013.  Brent prices decreased to $98.97 per barrel for 2014 from $108.53 per barrel for 2013.  Crude oil prices fell dramatically during the fourth quarter of 2014Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”), Poseidon and have fallen further thus far in 2015.  In December 2014 and January 2015, WTI average prices were $59.29 and $47.22, respectively.others.  WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors.  In addition, beginning inSimilar to crude oil prices, the fourth quarter of 2013 and continuing through 2014, the premiumsdifferentials for the Gulf of Mexicoour offshore crude oil have declined to virtually be at parity with one another as the crude being moved to the U.S. Gulf Coast increased and imports continued.  Over 85% of our oil is produced from offshore in the Gulf of Mexico and is characterized as Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”), Poseidon and others.also experienced volatility.  For example, the monthly average premiums todifferentials of WTI forversus LLS, HLS and Poseidon for 20142016 were $3.88, $3.52a positive $1.70 and $0.84, and a negative $1.20$3.57 per barrel, respectively, compared to $11.06, $11.02positive $3.72 and $5.58$2.76, and a negative $1.04 per barrel, respectively, for 2013.  Permian Basin crudes also have traded at a discount to WTI (at times the discount has been significant) in much2015.  The majority of 2014 as supply growth outpaced infrastructure capacity.  This bottleneck has been relieved recently with the new pipeline expansions from Longhorn, Bridge Tex and Cactus coming on line and allowing the WTI to Permian differentials to revert to more normal levels.  Our oil production in West Texas incurs discounts for transportation costs incurred by the purchaser, with larger discounts applied where theour crude oil is trucked duepriced similar to lackPoseidon and, therefore, is experiencing negative differentials.  In addition, a few of pipeline access.  our crude oil fields have a negative quality bank adjustment as the crude quality (as per American Petroleum Institute’s gravity and sulfur content measurement) is below the standard crude oil quality for the pipeline.

OurAn EIA report issued in early January 2017 projected WTI crude oil prices for 2017 and 2018 at $52.50 per barrel and $55.18 per barrel, respectively, and Brent crude oil prices for 2017 and 2018 at $53.50 per barrel and $56.18, respectively.  


During 2016, our average realized NGLs sales pricesprice decreased 1.7% during 2014 versus 2013.0.6% compared to 2015.  Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel.  During 2014,2016, average prices for domestic ethane increased 2%12% and average domestic propane prices increased 4%7% from the comparable 2013 period.2015.  Average price changes for other domestic NGLs ranged fromwere a decrease of 13%12% to a decrease of 7%, which caused the average realized NGLs sales price to decline.  Colder weather was a major factor for thean increase of 12% between 2016 and 2015.  Per EIA, production of ethane and propane increased in 2016 over 2015 by 11% and 2%, respectively.  Ethane inventories at year end were much higher than the price of propane during the winter months of 2014; however, propaneprior year, increasing 49%, and although ethane prices were belowhave increased from prior year levels, for the balance of 2014.  For December 2014, propane prices fell dramatically and were 48% below the 2014 average.  Other market factors and weather influence the price of ethane, as it is not used directly as a heating fuel.  However, cold weather drove up the price of natural gas, helping to increase the price of ethane, which is extracted from natural gas.  Once the cold weather passed, ethane prices declinedremain low compared to pre-winter pricinghistorical levels.  Propane inventory levels at year end were also much higher going into the heating season and prices for the balance of 2014 were below the comparable 2013 period.  Similar to propane, ethane prices for December 2014 fell dramatically and were 38% below the 2014 average.  The decreases in the prices of crude oil and natural gas have affected the prices of NGLs.are 27% higher than at year end 2015.  As long as U.S. crude oilethane and natural gas productionpropane inventories remain high, andthe possibility of a price recovery is unlikely.  As long as the price ratio of crude oil to natural gas remains wide (as measured on a six to one energy equivalency), the production of NGLs may continue to be high relative to historical norms, andwhich would in turn suggest continued downwardweak prices, or possibly further price pressure onreductions, especially for the priceprices of ethane.ethane and propane.  Many natural gas processing facilities have been and from time to time, will likely continue re-injecting ethane back into the natural gas stream after processing due to insufficient ethane demand, which negatively impacts production and natural gas prices.  Ethane demand is expected to increase in 2017 as petrochemical plants and expansion projects that consume ethane come online.  

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During 2016, our average realized natural gas sales price decreased 5.2% compared to 2015.  According to the EIA, spot prices for natural gas at Henry Hub (the primary U.S. price benchmark) were 17% higher3.8% lower in 2014 compared to 2013 largely due to above-average storage withdrawals in response to the colder winter weather early in 2014 and higher industrial demand.  The amount of heating degree days for the winter of 2014 was 13% higher than that of 2013, which was a primary causal factor for the increased demand.2016 from 2015.  Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues, other fuel competition (coal) and domestic economic conditions, and they have historically been subject to substantial fluctuation.  However, with the surplus of natural gas that has plagued the industry since 2012, natural gas prices have been weak and the fluctuations in prices have been limited to the lower end of the price range.  That phenomenon is likelyPrices in the fourth quarter of 2016 were above the previous three quarters, representing an upward trend, but price levels continue to continue accordingbe very weak.  Per EIA, the increase was attributable to many commentators. During 2014, our average realized sales price increased 22.5% to $4.35 per Mcf from 2013.  During December 2014,higher demand for electricity generation in the summer and declining production.  The U.S. natural gas prices have falleninventories at the end of 2016 were approximately 10% lower than a year earlier and 2% lower than the Henry Hub average pricefive year average.  U.S. consumption was 20% belowflat during 2016, with commercial electricity consumption increases offsetting decreases in residential usage.  U.S. supplies decreased 3% due primarily to slightly lower production in the average price for 2014.  lower 48 states.

Although theThe average price of natural gas increased during 2014 on a percentage basis, it is still weak from an overall economic standpoint, and we expect continued weakness in natural gas prices for a number of reasons, including (i) producers continuingmay continue to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas continuing to be produced as a by-product in conjunction with the high level of oil drilling (as evidenced by the year over year increase in natural gas production despite the decline in the number of rigs drilling for natural gas as explained below), (iii) production efficiency gains being achieved in the shale gas areas resulting from better hydraulic fracturing, horizontal drilling, pad drilling and production techniques and (iv)(iii) re-injecting ethane into the natural gas stream as indicated above, which increases the natural gas supply.

Per EIA natural gas working inventories at the end of the December 2014 were estimated at 3.1 trillion cubic feet, which is 8% above the comparable 2013 period.  EIA estimates the Henry Hub natural gas spot price was $4.52 per Mcf in 2014 and forecasts $3.55 and $3.98 per Mcf for 2015 and 2016, respectively.  Many research analysts are projecting thatprojects natural gas prices to increase in 2017 compared to 2016, and then to increase further in 2018.  Price increases will likely be lower than this forecastrelatively minor as natural gas production can ramp up relatively quickly.  U.S. production is projected to be about flat for 2017 compared to 2016, then to rise by EIA primarily2% in 2018.  Natural gas usage for power generation is expected to be between 32% and 33% in 2017 and 2018, compared to 34% in 2016 and 33% in 2015 due to growth inhigher natural gas supplies. EIA projectsprices compared to coal.  

During most of 2016, the number of rigs drilling for oil and natural gas in the U.S. supply to be higher than consumption for bothwas down significantly from 2014 levels.  Rig counts increased during the fourth quarter of 2016 and are approaching 2015 and 2016.  

levels.  According to Baker Hughes, the oil rig count at the end of 2014, 2015 and 2016 was 1,482, 536 and 525, respectively.  During 2016, the oil rig count low was 316 and the high was 525.  The U.S. natural gas rig count was 439 at the beginning of 2013.  The natural gas rig count decreased during 2013 to 372 rigs at the end of 20132014, 2015 and decreased further to2016 was 328, at162, and 132, respectively.  During 2016, the end of December 2014.  The natural gas rig count low was at a 21 year low during 2014.  As of mid-February,81 and the natural gas rig count decreased to 300.  Despite the decline in rigs drilling specifically for natural gas, the U.S. has experienced a year over year increase in natural gas production due to the many factors previously enumerated.  Oil wells have increased natural gas production as a by-product, with the number of rigs searching for oil increasing from 1,318 at the beginning of 2013 to 1,378 at the end of 2013, and further increasing to 1,482 as of the end of December 2014.  As of mid-February, the oil rig count decreased to 1,056.high was 148.  In the Gulf of Mexico, there were 48 rigs (29 oil, 19 natural gas) at the beginning of 2013, 59 rigs (39 oil, 20 natural gas) at the end of 2013 and 54 rigs (42 oil and 12 natural gas) as ofat the end of December 2014.  EIA estimates2014, 25 rigs (20 oil and five natural gas) at the percentageend of electricity fueled by natural gas to be 27% for 2014, and forecasts the percentage at 28% for both 2015, and 2016, influenced largely by22 rigs (22 oil and no natural gas) at the expected priceend of natural gas compared to2016.  The majority of rigs in the expected priceGulf of coal.  Industry sources have indicated that a natural gas price above $4.50 per Mcf for some period of time will probably cause even more power producers to switch back to coal from natural gas, which in effect creates limits on both the extent of a price rise and the duration of a price increase.  This will be the case until such time as demand for natural gas increases from either current consumers or new uses are developed to consume this resource.  The demand for natural gas is expected to continue to increase as the announced petrochemical facilities are constructed and power producers convert to consuming natural gas to reduce emissions to ever tighter emission regulations and standards.  Several companiesMexico are currently building or are planning to build liquefaction capacity to export liquefied natural gas due to significantly higher natural gas prices in Europe and Asia.“floaters” rather than jack-up rigs.


Our current capital expenditure budget for 2015 is $200 million, not including any potential acquisitions.  This is down from our 2014 and 2013 actual expenditures of approximately $630 million and $636 million, respectively.  The plan for 2015 reflects the significantly lower estimated crude oil prices and our attempt to always drill within cash flow from operating activities.  We continue to closely monitor current and forecasted prices to assess if changes are needed to our plans.  

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Should the recent price decline in oil continue, it would negatively impact our future revenues, earnings and liquidity, cause impairment write-downs of the carrying value of our oil and natural gas properties, reduce proved reserves, create issues with financial ratio compliance, and lead to a reduction of the borrowing base associated with our Credit Agreement, depending on the longevity and severity of such price weakness.  As required by the full cost accounting rules, we performedperform our ceiling test calculation as of December 31, 2014each quarter using the SEC pricing guidelines, which require using the 12-month average commodity price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price adjusted for price differentials.  The average price using the SEC required methodology at December 31, 2016 was $91.12$39.25 per barrel for WTI crude oil and $4.27$2.48 per McfMMBtu for Henry Hub natural gas.  (For reference,gas before adjustments.  Due to the prices atdecrease in the end of the year 201412-month average price for those two products were $53.45 per barrel forboth crude oil and $3.23 per Mcf for natural gas respectively.)  Based on the results of the SEC required calculation,during 2016, we were not required to record a write-downrecorded ceiling test write-downs of the carrying value of our oil and natural gas properties atin the first three quarters of 2016 totaling $279.1 million, but did not have a write-down during the fourth quarter of 2016.  For 2015, we recorded ceiling test write-downs in each quarter totaling $987.2 million for the full year.  Incurrence of further write downs is dependent primarily on the price of crude oil and natural gas, but also is affected by quantities of proved reserves, future development costs and future lease operating costs.

We performed a pro-forma calculation to determine if a further ceiling test impairment write-down would be likely in the first quarter of 2017 based only on changes to prices available during the first quarter of 2017.  In this pro-forma calculation, no changes were assumed for proved reserves from the December 31, 2014.  We are required to perform2016 levels other than price and no changes were assumed for other factors.  The pro-forma calculation indicated we would not incur a ceiling-test write-down in the first quarter of 2017 basely solely on a change in price.  This pro-forma calculation may not be predictive of the first quarter of 2017, as other factors besides price will impact the ceiling test calculation at the end of each quarter.  If WTI and Brent prices remain at levels occurring during December 2014 and January 2015, we estimate that we will likely recognize a non-cash ceiling test write-down during 2015, and could have a non-cash ceiling test write-down in more than one quarter of 2015. For the effect of lower commodity prices on liquidity, seecalculation.  

See Risk Factors - Risks Related to FinancingProperties – Proved Reserves under Part I, Item 1A2; Selected Financial Data under Part II, Item 6 and Financial Statements and Supplementary Data – Note 21 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K for additional information on our proved reserves.

As of December 31, 2016, we had $70.2 million of available cash and $149.5 million available on our revolving bank credit facility.  See the Liquidity and Capital Resources section of this Item 7, and Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for a description of our debt structure.

As to financial assurances for decommissioning obligations, in December 2016, the BOEM issued to us an Order to Provide Additional Security for our sole liability properties.  In January 2017, the BOEM granted an extension of six months related to NTL #2016-N01 for leases, ROWs and RUEs that are non-sole liability properties.  In February 2017, the BOEM withdrew the sole liability order it had issued to us in December 2016 to allow time for the new President’s administration to review the complex financial assurance program.  Any implementation issues associated with those orders will be discussed as part of the January 2017 Extension that the BOEM initiated to gather input on other components of the NTL #2016-N01.  See Liquidity and Capital Resources in this Item 7 in this Form 10-K for additional information aboutconcerning these financial assurances, our Credit Agreementliquidity and financing.  For the effect of lower commodity prices on revenues and earnings,other financial obligations.  In addition, see Quantitative and Qualitative Disclosures on Market RisksRisk Factors under Part II,I, Item 7A1A for risks related to our financial obligations.  

Many changes in laws, regulations, guidance, interpretations and policy continue to be proposed and issued in our industry.  At this time, we are unable to assess the potential impact as clarification is needed for items within the proposals.

Due to the sustained lower commodity price environment and the outlook for the remainder of 2017, we have set our 2017 capital expenditure budget at $125 million, which excludes potential acquisitions.  Although this is an increase from the $49 million capital expenditures incurred in 2016, our current plan for 2017 is a significant reduction from 2015 and 2014 investment levels of $231 million and $630 million, respectively.  We have the flexibility to make this reduction to our 2017 capital expenditure budget because we have no long term rig commitments and no pressure from co-owners to drill or complete a well.  The Ewing Bank 910 A-8 well began production during 2016 and the SS 349/359 (Mahogany) A-18 well was completed and begin production during the first quarter of 2017.  Some of our expenditures planned for 2017 are expected to impact production for 2017, while most are expected to impact 2018 production and beyond.  We expect 2017 production to be slightly higher than 2016, but factors such as natural production declines, unplanned downtime and well performance could lead to lower production in 2017.  In addition, our plans include spending $78.3 million in 2017 for ARO (discussed in more detail below), compared to $72.3 million spent on ARO in 2016.  We continue to closely monitor current and forecasted prices to assess if changes are needed to our plans. See Risk Factors under Part I, Item 1A in this Form 10-K for additional information.


Our operating costs includein 2016 included the expense of operating our wells, platforms and other infrastructure primarily in the Gulf of Mexico, and Texas and transporting our production to the points of sale.  During 2016, our lease operating expenses decreased approximately 12.3% compared to 2015 on a per Boe basis.  Our operating costs were lower in 2016 compared to 2015 primarily due to lower costs of goods and services from vendors combined with the sale of the Yellow Rose field in October 2015.  Partially offsetting were higher operating costs for the Big Bend and Dantzler fields, which began production in the fourth quarter of 2015, and lower product handling arrangement (“PHA”) fees for the Matterhorn field.  Our operating costs are generally comprised of several components, including direct operating costs, repairs and maintenance, gathering and transportation costs, production taxes, insurance premiums, workover costs and ad valorem taxes.  Our operating costs depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties.  Workover costs can vary significantly from year to year depending on the level of activity (either required or desired) and type of equipment used.  In those instances where a drilling rig is required as opposed to some other type of intervention vessel or equipment, the costs tend to be much higher and require more time.  During the last two years, we performed two offshore workovers each year that required the use of a drilling rig.  At our Spraberry field (Yellow Rose) operations more workover activity has been performed due to the expanded well count.

In recent years, we acquired and built platformshave operated or participated in wells near the outer edge of the continental shelf and operated wells in the deepwater of the Gulf of Mexico.  To the extent we continue ourexpanding deepwater operations, our operating costs will likelymay increase, especially as we find and produce more crude oil rather than natural gas.  While each field can present operating problemscomplexities that can add to the costs of operating a field, the production costs of a field are generally directly proportional to the number of production platforms built in the field.  As technologies have improved, oil and natural gas can be produced from larger acreage areas using a single platform, which may reduce the operating costs associated with future development projects.

Our offshore operations are exposed to potential damage from hurricanes and normally we obtain insurance to reduce, but not totally mitigate, our financial exposure risk.  See Liquidity and Capital Resources - Hurricane Remediation, Insurance Claims and Insurance Coverage under this Item 7 and Financial Statementsand Supplementary Data – Note 18 – Contingencies under Part II, Item 8 in this Form 10-K for additional information.

Applicable environmental regulations require us to remove our platforms after production has ceased, to plug and abandon all wells and to remediate any environmental damage our operations may have caused.  These types of activities are collectively referred to as decommissioning or ARO.  The costs per well associated with our ARO generally increase as we drill wells in deeper parts of the continental shelf and in the deepwater.  We generally do not pre-fund our ARO, but have obtained approximately $300 million in bonds and have restricted deposits for certain ARO arrangements.  Over the last ten years, we have spent over $700 million for ARO.  We estimated the present value of our liability related to our ARO at $390.6$334.4 million as of December 31, 2014.2016, of which $78.3 million is estimated to be spent during 2017.  Inherent in the present value calculation of our liability are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, changes to our credit-adjusted risk-free rate, timing of settlement and expenditure, and changes in the legal, regulatory, environmental and political environments.  Actual expenditures for ARO could vary significantly from these estimates.  Overestimates and have varied significantly in the last several years,past.  Prior to 2015, we have seensaw upward revisions in costs to do this work partly due to significant changes in the regulatory requirements and partly due to the escalation in the cost of goods and services required to do the work.  Lower crudeThe increase in oil prices are expectedthat occurred over several years before the decline that began in June 2014 led to lead to lowersignificant cost inflation of goods and services in the Gulf of Mexico and other producing basins.  During 2015 and 2016, most of the plug and abandonment service costs trended lower, although some costs increased due to scope changes and regulatory interpretation changes.  Overall, service costs related to plugging and abandonment were relatively lower in 2016 compared to 2015 on a reduction in the estimated liability.per project basis.  

Many changes in laws, regulations, guidance, interpretations and policy continue to be proposed and issued in our industry.  The process for obtaining offshore drilling permits, especially deepwater drilling permits, has expanded and lengthened in the past few years.  The most significant regulationregulatory changes in recent years are NTL #2016-N01 and interpretations related to unbundling costs at natural gas plants, which adversely impact royalty payments.  In addition, regulations have expanded related to potential environmental impacts, spill response documentation, compliance reviews and operator practices related to safety and implementing aenvironmental matters.  This has led to higher costs for revisions, training, implementations and monitoring related to our safety and environmental management system.systems.  The new regulations and increased review process increases the time to obtain drilling permits and increases the cost of operations.  Also, the regulations have changed related to plugging and abandonment of offshore wells and related infrastructure considerably, driving up both the time and cost to perform the work.  As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time.  See Business - Regulation under Part I, Item 1 in this Form 10-K for additional information.


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Results of Operations

Year Ended December 31, 20142016 Compared to Year Ended December 31, 20132015

Revenues.  Total revenues decreased $35.4$107.3 million, or 3.6%21.1%, to $948.7$400.0 million in 20142016 compared to 2013.2015.  Oil revenues decreased $66.2$80.2 million, or 9.2%23.0%, NGLs revenues decreased $0.5$1.2 million, or 0.7%4.5%, natural gas revenues increased $28.5decreased $23.0 million, or 15.1%18.7%, and other revenues increaseddecreased $2.8 million.  The oil revenue decrease was attributable to an 11.2% Bbla 17.1% per barrel decrease in the average realized sales price to $90.96$37.35 per Bblbarrel in 2016 from $102.44$45.05 per barrel in 2013, partially offset by2015 and a 2.3% increase7.1% decrease in sales volumes.  The NGLs revenue decrease was attributable to a 1.7%0.6% decrease in the average realized sales price to $34.49$17.14 per Bblbarrel in 20142016 from $35.07$17.25 per Bblbarrel in 2013, partially offset by an increase2015 and a decrease of 1.0%3.9% in sales volumes.  The decrease in natural gas revenue increase was attributable to a 22.5% increase5.2% decrease in the average realized natural gas sales price to $4.35$2.53 per Mcf in 2016 from $3.55$2.67 per Mcf for 2013, partially offset by2015 and a 13.9% decrease in sales volumes by 6.0%.volumes.  We experienced increases in production at the Big Bend and Dantzler fields, which began production in the fourth quarter of 2015.  Also, production increases were achieved at the Ewing Bank 910 field, the Main Pass 108, the Main Pass 98 field and the East Cameron 321 field.  Offsetting these production increases were production declines primarily from the A-5 wellsale of the Yellow Rose field in October 2015 (0.8 MMBoe); decreases at Mississippi Canyon 243 (Matterhorn), the A-14 well at Ship Shoal 349 (Mahogany), the return to production of Mississippi Canyon 506 (Wrigley), increases at FairwayMahogany, Matterhorn and Garden Banks 302 (Power Play) and other fields due to acquiring the remaining working interest in the field as well as productive well work in the field, new production from both Medusa and Neptune fields, and acquisitions consummated during 2014.  Production was negatively impacted for all commodities from natural production declines, productiondeclines; and various operational issues.  Production deferrals, affecting various fieldswhich occurred at Mahogany and the divestitures of certain fields in 2013.  The production deferralsother locations, were attributable to third-party pipeline outages, platform maintenance,operational issues, and various operational issues.  Wemaintenance.  For 2016, we estimate that production deferrals were 2.61.4 MMBoe during 2014.  Specifically, production at Mississippi Canyon 506 (Wrigley) was deferred as a result of maintenance at the host platform and comprised approximately 17% of the deferred production.  The Wrigley field resumed production during 2014.  In addition, production from selected wells at Ship Shoal 349 (Mahogany) was deferred duecompared to closure of a pipeline, a rig move and well work and weather was a contributing factor in the first quarter of 20141.8 MMBoe for production declines at West Texas and at selected offshore fields.The balance of the deferred production occurred at multiple locations. During 2013, estimated production deferrals were 2.2 MMBoe.2015.  

Revenues from oil and liquids as a percent of our total revenues were 76.5%73.8% for 20142016 compared to 80.5%74.3% for 2013.2015.  NGLs realized sales prices as a percent of crude oil realized prices increased to 37.9%45.9% for 20142016 compared to 34.2%38.3% for 2013.2015 as crude oil prices continued to decline during most of 2016.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, and facilities maintenance, on our facilities, and hurricane remediation costs net of insurance claims, decreased $6.1$40.4 million, or 20.9%, to $264.8$152.4 million in 20142016 compared to 2013.2015.  On a per Boe basis, lease operating expenses decreased to $15.01$9.92 per Boe during 20142016 compared to $15.06$11.31 per Boe during 2013.2015.  On a component basis, base lease operating expenses decreased $18.1 million, workover expense decreased $13.2$12.6 million, insurance premiums decreased $6.6 million, facilities maintenance expense decreased $4.6$2.1 million and insurance premiumsreimbursements increased $1.0 million (offset to expense).  Base lease operating expenses decreased $3.3 million,primarily due to lower costs from service providers and elimination of field expenses related to the sale of the Yellow Rose field, which was sold in October 2015; partially offset by increases in base lease operating expenses of $15.4 million.related to our new deepwater fields at Dantzler and Big Bend; and lower PHA fees (cost offsets) at our Matterhorn field.  The decrease in workover costs was primarily due to workovers at Main Pass 69the sale of the Yellow Rose field and Ship Shoal (Mahogany) occurringvarious activities that occurred in 2013,  which were partially offset by workovers at High Island 111 and High Island 129 occurring2015 that did not reoccur in 2014 and increased workover costs at Spraberry (Yellow Rose). The decrease in facilities maintenance expense was2016.  Insurance premium reductions are primarily due to revisions in the shutdown for scheduled maintenance at our Yellowhammer plant occurring in 2013.  Base lease operating expenses were higher primarily due to new fields acquired in 2014 and 2013, a decrease in fees charged out to a third party at Mississippi Canyon 243 and increasesEnergy Package related to new wells at Ship Shoal 349 (Mahogany) and Spraberry (Yellow Rose).named windstorms coverage.  

Production taxes.  Production taxes increaseddecreased to $7.9$1.9 million, or 37.1%, during 20142016 compared to $7.1$3.0 million in 20132015 primarily relateddue to increased production inlower commodity prices and the state waterssale of Alabama at our Fairway field, which was impacted by our increase in ownership effective in September 2014 and increases in overall production at the Yellow Rose field.  Partially offsetting were decreases in production and sales at our onshore operations.  Currently, production taxes are not a large component of our operating costs.  Most of our production is from federal waters where there are no production taxes, while onshore and state water operations are subject to production taxes.

Gathering and transportation costs.  Gathering and transportation costs increased to $19.8$22.9 million, or 33.6%, in 2016 compared to $17.2 million in 2014 compared to $17.5 million in 20132015 primarily due to escalationproduction increases from the Big Bend and Dantzler fields, both of which began producing in third-party transportation fees.the fourth quarter of 2015.

Depreciation, depletion, amortization and accretion.  DD&A, including accretion for ARO, increaseddecreased to $28.98$13.77 per Boe for 20142016 from $25.10$23.11 per Boe for 2013.2015.  On a nominal basis, DD&A increaseddecreased to $511.1$211.6 million, or 46.3%, for 20142016 from $451.5$394.1 million in 2013.2015.  DD&A on a per Boe and nominal basis increased in partdecreased primarily due to increasesthe ceiling test write-downs recorded during 2016 and 2015, and lower capital expenditures in relation to DD&A expense, which lowers the full-cost pool subject to DD&A.  In addition, the proceeds from the sale of our Yellow Rose field reduced the full cost pool from capital expenditures and estimatedalong with the removal of future development costs.  Our focuscosts associated with the Yellow Rose field proved reserves.  Other factors affecting the DD&A rate are changes to future development costs on expanding deepwater exploration and development necessarily increases costs prior to increasingremaining proved reserves leadingand changes to an increaseproved reserves.    


Ceiling test write-downof oil and natural gas properties. For 2016 and 2015, we recorded non-cash ceiling test write-downs of $279.1 million and $987.2 million, respectively, as the book value of our oil and natural gas properties exceeded the ceiling test limitation.  The write-down is the result of decreases in prices for all three commodities we sell, which are crude oil, NGLs and natural gas.  See Financial Statementsand Supplementary Data – Note 1 - Basis of Presentation under Part II, Item 8 in this Form 10-K, which provides a description of the rate.  ceiling test limit determination, and above under the section Overview in this Item regarding our prospects for a future significant ceiling test write-downs.

General and administrative expenses (“G&A”).  G&A increaseddecreased to $87.0$59.7 million, or 18.3%, for 2016 from $73.1 million for 2014 from $81.9 million for 20132015 primarily due to increasesdecreases in salaries, share-based compensation, contract labor costsheadcount related expense (salaries, benefits, and contractor expenses), elimination of certain employee benefits, increased reimbursements from stop-loss medical policies, and reductions in charge-outs to third-parties,legal settlements, partially offset by lower cash-based incentive compensation.higher legal costs.  G&A on a per BOE basis was $4.93$3.89 Boe for 20142016 compared to $4.55$4.29 per Boe for 2013.2015. See Financial Statements and Supplementary Data – Note 1110 – Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 in this Form 10-K for additional information.

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Derivative (gain)/lossnet gain. .  For 20142016, there was a $2.9 million derivative net loss recorded for derivative contracts for crude oil and 2013, ournatural gas.  As of December 31, 2016, we do not have any open derivative positions resulted incontracts.  We entered into derivative contracts for crude oil and natural gas during the second quarter of 2015, relating to 2015 and 2016 estimated production.  For 2015, there was a $14.4 million derivative net gain of $4.0 millionrecorded for derivative contracts for crude oil and a net loss $8.5 million, respectively, and related tonatural gas.  For both periods, the changeamount includes changes in the fair value of our then open crude oil commodity derivatives positions as a result of changes in crude oil prices.  During 2014, all open positions expired and closed.  For 2013, the contracts related to production anticipated in both 2013 and 2014 and reflect changes in the fair value for all open contracts recorded currently and for closedderivative contracts.  See Financial Statements and Supplementary Data – Note 68 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.

Interest expense. expense.  Interest expense incurred increasedwas $92.8 million in 2016, compared to $86.9$104.6 million in 2015.  The decrease was primarily attributable to the Exchange Transaction.  Interest expense was reduced for 2014 from $85.6 millionthe Unsecured Senior Notes exchanged on September 7, 2016.  For the debt issued in the Exchange Transaction, undiscounted future cash flows (principal, PIK and cash interest) are recorded as part of the carrying value of the debt under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”); therefore, no interest expense was recorded for 2013 primarilythe debt issued in the Exchange Transaction for the period of September 7, 2016 to December 31, 2016.  In addition, interest expense was lower due to higher balanceslower average borrowings on ourthe revolving bank credit facility.  During 2016 and 2015, interest of $0.5 million and $7.3 million, respectively, was capitalized to unevaluated oil and natural gas properties.  The decrease is primarily attributable to the sale of the Yellow Rose field during the fourth quarter of 2015 and reclassifying all other remaining unevaluated properties to the full-cost pool during 2016.  

Gain on exchange of debt.  A gain of $123.9 million was recorded related to the Exchange Transaction.  Under ASC 470-60, a gain was recognized as undiscounted future cash flows of the debt issued in the Exchange Transaction, plus the fair value of the common stock issued and deal transaction costs were less than the sum of the carrying value of the Unsecured Senior Notes exchanged combined with the funds received from the 1.5 Lien Term Loan issued.  See Liquidity and Capital Resources in this Item for a table on the calculation of the gain.      

Other (income) expense, net.  Other (income) expense, net was income of $6.5 million in 2016 and was an expense of $4.7 million for 2015.  For 2016, $7.7 million of income was recorded related to the settlements with certain insurance companies.  In both 2016 and 2015, write-downs of unamortized debt issuance costs were recorded related to a reduction in the borrowing base on the revolving bank credit facility.  The reductions in the borrowing base resulted in proportional reductions in 2016 and 2015 of $1.4 million and $3.2 million, respectively, in the unamortized debt issuance costs related to the revolving bank credit facility.  In addition, during 2015, a net loss on sale of assets of $1.0 million was recorded primarily related to the sale of computer equipment used for backup processes.  


Income tax benefit.Our income tax benefit for 2016 and 2015 was $43.4 million and $203.0 million, respectively, with the change attributable primarily to the deferred tax assets and the valuation allowance recorded for the respective periods.  Our annualized effective tax rate for 2016 and 2015 was 14.8% and 16.3%, respectively, and differs from the federal statutory rate of 35% primarily due to the valuation allowances recorded for our deferred tax assets in both periods.  During 2016 and 2015, we recorded increases to the valuation allowance of $52.9 million and $232.9 million, respectively, related to federal and state deferred tax assets.  Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods.  The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible.  In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. See Financial Statements and Supplementary Data – Note 12 – Income Taxes under Part II, Item 8 in this Form 10-K for additional information.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Revenues.  Total revenues decreased $441.4 million, or 46.5%, to $507.3 million in 2015 compared to 2014.  Oil revenues decreased $303.6 million, or 46.5%, NGLs revenues decreased $45.2 million, or 62.0%, natural gas revenues decreased $94.4 million, or 43.3%, and other revenues increased $1.7 million.  The oil revenue decrease was attributable to a 50.5% per barrel decrease in the average realized sales price to $45.05 per barrel in 2015 from $90.96 per barrel in 2014, partially offset by an 8.0% increase in sales volumes.  The NGLs revenue decrease was attributable to a 50.0% decrease in the average realized sales price to $17.25 per barrel in 2015 from $34.49 per barrel in 2014 and a decrease of 24.1% in sales volumes.  The decrease in natural gas revenue was attributable to a 38.6% decrease in the average realized natural gas sales price to $2.67 per Mcf in 2015 from $4.35 per Mcf for 2014 and a 7.8% decrease in sales volumes.  We experienced increases in production at Mahogany; Mississippi Canyon 582 (Medusa); Mississippi Canyon 506 (Wrigley) field; Atwater Valley 575 field (Neptune); Brazos A133 field (partially due to the acquisition of an additional working interest); and Dantzler and Big Bend, which began production in the fourth quarter of 2015.  Production was negatively impacted for all commodities from natural production declines, production deferrals affecting various fields and the divestiture of the Yellow Rose field.  

Revenues from oil and liquids as a percent of our total revenues were 74.3% for 2015 compared to 76.5% for 2014.  NGLs realized sales prices as a percent of crude oil realized prices increased to 38.3% for 2015 compared to 37.9% for 2014.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, and facilities maintenance, decreased $72.0 million, or 27.2%, to $192.8 million in 2015 compared to 2014.  On a per Boe basis, lease operating expenses decreased to $11.31 per Boe during 2015 compared to $15.01 per Boe during 2014.  On a component basis, workover expense decreased $26.0 million, base lease operating expenses decreased $24.5 million, facilities maintenance decreased $17.3 million and insurance premiums decreased $4.9 million.  The decrease in workover costs was primarily due to reductions in onshore activity and offshore activity at High Island 111 in 2014.  Base lease operating expenses decreased primarily due to lower cost from service providers, less onshore downhole well work and the sale of the Yellow Rose field, partially offset by increases from acquisitions, lower production handling fees, expenses related to our new deepwater fields at Dantzler and Big Bend, and expenses related to our new well at Ewing Banks 910.

Production taxes.  Production taxes decreased to $3.0 million, or 62.2%, during 2015 compared to $7.9 million in 2014 primarily due to lower commodity prices and the sale of the Yellow Rose field.  Currently, production taxes are not a large component of our operating costs.  Most of our production is from federal waters where there are no production taxes, while onshore and state water operations are subject to production taxes.

Gathering and transportation costs.  Gathering and transportation costs decreased to $17.2 million, or 13.4%, in 2015 compared to $19.8 million in 2014 primarily due to reductions related to transactions with the Terrebonne gas processing plant.


Depreciation, depletion, amortization and accretion.  DD&A, including accretion for ARO, decreased to $23.11 per Boe for 2015 from $28.98 per Boe for 2014.  On a nominal basis, DD&A decreased to $394.1 million, or 22.9%, for 2015 from $511.1 million in 2014.  DD&A on a per Boe and nominal basis decreased primarily due to the ceiling test write-downs recorded during the first three quarters of 2015 (the fourth quarter ceiling test write-down will affect the DD&A rate starting with the first quarter of 2016) and lower capital expenditures in relation to DD&A expense, which lowers the full-cost pool subject to DD&A.  In addition, the proceeds from the sale of our Yellow Rose field reduced the full cost pool along with the removal of future development costs associated with the Yellow Rose field reserves.  Additional factors affecting the DD&A rate are lower future development costs on remaining reserves and lower proved reserves.    

Ceiling test write-down of oil and natural gas properties. For 2015, we recorded a non-cash ceiling test write-down of $32.4 million in the fourth quarter of 2015 and $987.2 million for the full year as the book value of our oil and natural gas properties exceeded the ceiling test limitation.  The write-down is the result of decreases in prices for all three commodities we sell, which are crude oil, NGLs and natural gas.  No ceiling test write-down was recorded in 2014.  See Financial Statements and Supplementary Data – Note 1 - Basis of Presentation under Part II, Item 8 in this Form 10-K, which provides a description of the ceiling test limit determination.

General and administrative expenses.  G&A decreased to $73.1 million, or 16.0%, for 2015 from $87.0 million for 2014 primarily due to decreases in incentive compensation, a significant decrease in the use of contractors and much lower share-based compensation, partially offset by lower billings to joint venture partners, increased costs related to surety bonds, increases in medical claims and recording a contingent provision for proposed fines from the BSEE.  G&A on a per BOE basis was $4.29 Boe for 2015 compared to $4.93 per Boe for 2014. See Financial Statements and Supplementary Data – Note 10 – Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 in this Form 10-K for additional information.

Derivative net gain. For 2015, there was a $14.4 million derivative net gain recorded for derivative contracts for crude oil and natural gas.  We entered into derivative contracts for crude oil and natural gas during the second quarter of 2015, relating to 2015 and 2016 estimated production.  For 2014, the derivative net gain was $4.0 million and related to derivative contracts for crude oil.  During 2014, all open positions expired and closed.  For both periods, the amount includes changes in the fair value of commodity derivative contracts.  See Financial Statements and Supplementary Data – Note 8 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.

Interest expense.  Interest expense incurred was $104.6 million in 2015, up from $86.9 million in 2014.  The increase was primarily attributable to increased borrowings on the revolving bank credit facility and the issuance of the Second Lien Term Loan in May 2015 with an aggregate principal of $300.0 million and issued at a 1% discount to par.  The aggregate principal amount of our 8.50%Unsecured Senior Notes outstanding was $900.0 million duringin both years.periods.  During 2015 and 2014, interest of $7.3 million and 2013, $8.5 million, and $10.1 million, respectively, of interest werewas capitalized to unevaluated oil and natural gas properties.  The decrease is primarily attributable to reclassifying a portion of ourcertain unevaluated properties related to the Yellow Rose field to the full cost pool during 2014the fourth quarter of 2015 and reclassifying certain unevaluated properties during the fourth quarter of 2013.  See Financial Statements and Supplementary Data – Note 7 – Long-Term Debt under Part II, Item 8 in this Form 10-K for additional information.2014.  

Other income,(income) expense, net.  For 2015, $4.7 million of net expense was recorded.  During 2015, the borrowing base on the revolving bank credit facility was reduced.  The reductions in the borrowing base resulted in proportional reductions in the unamortized debt issuance costs of $3.2 million related to the revolving bank credit facility.  In addition, a net loss on sale of assets of $1.0 million was recorded primarily related to the sale of computer equipment used for backup processes.  For 2014,other income, net, was $0.2 million.  For 2013, other income was $8.9 million and consisted primarily of funds received in conjunction with a payment to us for an option exercised by a counterparty.


Income tax expense (benefit). Income tax expense. Our income tax benefit for 2015 was $203.0 million compared to an income tax benefit of $4.5 million for 2014, with the change attributable primarily to increases in the pre-tax loss for 2015 compared to income2014.  Our effective tax expenserate was 16.3% and differs from the federal statutory rate of $28.8 million for 201335% primarily due to recording a pre-tax lossvaluation allowance of $232.9 million related to federal and state deferred tax assets.  Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in 2014 compared to pre-taxfuture periods.  The realization of these assets depends on recognition of sufficient future taxable income in 2013.specific tax jurisdictions in which those temporary differences or net operating losses are deductible.In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.  Our effective tax rate for the year 2014 is distorted due to a small pre-tax loss; consequently, our permanent differences have a larger impact on our effective tax rate.  Our effective tax rate for 2013 was 35.9% and differed from the federal statutory rate of 35.0% primarily as a result of state income taxes.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Revenues. Total revenues increased $109.6 million, or 12.5%, to $984.1 million in 2013 compared to 2012. Oil revenues increased $89.4 million, or 14.2%, NGLs revenues decreased $11.3 million, or 13.3%, natural gas revenues increased $30.9 million, or 19.5%, and other revenues increased $0.6 million. The oil revenue increase was attributable to a 16.3% increase in sales volumes, partially offset by a $1.91 per Bbl decrease in the average realized sales price to $102.44 per Bbl. The NGLs revenue decrease was attributable to a 11.8% decrease in the average realized sales price to $35.07 per Bbl in 2013 from $39.75 per Bbl in 2012 and a slight decrease of 1.8% in sales volumes. The natural gas revenue increase was attributable to a 20.7% increase in the average realized natural gas sales price to $3.55 per Mcf from $2.94 per Mcf for 2012, with sales volumes decreasing slightly by 1.1%. Production for all commodities was positively impacted by production increases at Ship Shoal 349 and the onshore properties in West Texas.  In addition, production was positively impacted by the Newfield Properties acquired in the fourth quarter 2012, the Callon Properties acquired in the fourth quarter of 2013 and the volume adjustments described above in the Overview section.  Production was negatively impacted for all commodities from natural production declines and from production deferrals affecting various fields.  The production deferrals were attributable to third-party pipeline outages, platform maintenance, Tropical Storm Karen and various operational issues. We estimate production deferrals were 2.2 MMBoe during 2013 for all these issues.  Specifically, production at Mississippi Canyon 506 (Wrigley) continues to be deferred as a result of maintenance at Shell’s Cognac platform and related pipelines.  Also, production was deferred at our Fairway field due to well and maintenance issues and a turnaround at our Yellowhammer plant.  During 2012, we also experienced production deferrals primarily due to Hurricane Isaac and various pipeline outages, but not near the same magnitude as in 2013.  

Revenues from oil and liquids as a percent of our total revenues were 80.5% for 2013 compared to 81.7% for 2012. NGLs realized sales prices as a percent of oil realized prices decreased to 34.2% for 2013 compared to 38.1% for 2012.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, increased $38.6 million to $270.8 million in 2013 compared to 2012. On a per BOE basis, lease operating expenses increased to $15.06 per Boe during 2013 compared to $13.56 per Boe during 2012. On a component basis, workover expense increased $25.0 million primarily as a result of rig workovers on wells at our Ship Shoal 349/359 field and our Main Pass 69 field. Base lease operating expenses increased $14.5 million primarily as a result of the acquisition of the Newfield Properties, expanded onshore operations and ad valorem tax refunds received in 2012, partially offset by increased processing fees charged to third-parties. Facilities maintenance expense increased $5.1 million primarily attributable to a shutdown for scheduled maintenance at our Yellowhammer plant. Partially offsetting these increases were decreases in insurance premiums of $4.6 million and hurricane costs net of insurance claims of $1.5 million.

Production taxes. Production taxes increased to $7.1 million during 2013 compared to $5.8 million in 2012 primarily due to onshore production and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.

57


Gathering and transportation costs. Gathering and transportation costs increased to $17.5 million in 2013 compared to $14.9 million in 2012 primarily due to escalation in third-party transportation fees.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, increased to $25.10 per Boe for 2013 from $20.79 per Boe for 2012. On a nominal basis, DD&A increased to $451.5 million for 2013 from $356.2 million in 2012. DD&A on a per Boe basis and nominal basis increased primarily due to: increasing estimates of future development costs; moving costs to the full cost pool from the unevaluated pool; increasing our ARO estimates without a corresponding increase in proved reserves; and incurring higher than expected development costs related to proved reserves. The acquisitions of the Newfield Properties and the Callon Properties also attributed to the increase in DD&A per Boe.  In addition to the increase in DD&A per Boe, the nominal increase was affected by the increase in production volumes described above in Revenues, which include the cumulative effect of the volumes adjustments, as described above in the Overview section.

General and administrative expenses. G&A decreased slightly to $81.9 million for 2013 from $82.0 million for 2012 primarily due to lower litigation and settlement cost, mostly offset by increases in consulting services related to drilling operations, higher professional services, supplemental bonding fees and increased incentive compensation expense. G&A on a per Boe basis was $4.55 per Boe for 2013 compared to $4.79 per Boe for 2012. See Financial Statements and Supplementary Data – Note 1112Share-Based and Cash-Based Incentive Compensation Income Taxes under Part II, Item 8 in this Form 10-K for additional information.

Derivative loss. For 2013 and 2012, our derivative positions resulted in net losses of $8.5 million and $14.0 million, respectively, and relate to the change in the fair value of our crude oil commodity derivatives as a result of changes in crude oil prices. Although the contracts relate to production for both the current year and next year, changes in the fair value for all open contracts are recorded currently. See Financial Statements and Supplementary Data – Note 6 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.

Interest expense. Interest expense incurred increased to $85.6 million for 2013 from $63.3 million for 2012. The aggregate principal amount of our 8.50% Senior Notes outstanding was $900.0 million during 2013 compared to $600.0 million outstanding from January to September 2012 and $900.0 million from October 2012 to December 2012 due to the issuance of an additional $300.0 million of 8.50% Senior Notes. During 2013 and 2012, $10.1 million and $13.3 million, respectively, of interest were capitalized to unevaluated oil and natural gas properties. The decrease is primarily attributable to reclassifying unevaluated properties to the full cost pool during the fourth quarter of 2012. See Financial Statements and Supplementary Data – Note 7 – Long-Term Debt under Part II, Item 8 in this Form 10-K for additional information.

Other income, net. For 2013, other income was $8.9 million and consisted primarily of funds received in conjunction with a payment to us for an option exercised by a counterparty. For 2012, other income was $0.2 million.

Income tax expense. Income tax expense decreased to $28.8 million for 2013 compared to $47.5 million for 2012 due to lower pre-tax income and a lower effective tax rate. Our effective tax rate for 2013 was 35.9% and differed from the federal statutory rate of 35.0% primarily as a result of state income taxes. Our effective tax rate for 2012 was 39.8% and differed from the federal statutory rate of 35% primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the Internal Revenue Code (“IRC”) as a function of loss carrybacks to prior years and the impact of state income taxes.

Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings, and make related interest payments and pay dividends.satisfy our ARO.  We have funded such activities with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank borrowings.  These sources

If commodity prices were to return to the weak levels seen in the early part of 2016, especially relative to our cost of finding and producing new reserves, this could significantly affect our liquidity.  In addition, other events outside of our control could significantly affect our liquidity such as demands for additional financial assurances from the BOEM or a final judgment for monetary damages in our lawsuit with Apache.  If such events were to occur in the future, we may seek relief under the U.S. Bankruptcy Code, which relief may include (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of our assets and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks.

Additionally, a prolonged period of weak commodity prices could have historically been sufficient to fundother potential negative impacts including:

recognizing additional ceiling test write-downs of the carrying value of our ongoing cash requirements.

Cash flow and working capital. Net cash provided by operating activities for 2014 was $511.4 million, compared to $561.4 million for 2013. Cash flows from operating activities, before changes in working capital and ARO settlements, were $500.8 million in 2014, a decrease of $46.0 million compared to 2013.  The change in cash flows excluding working capital and ARO settlements was primarily due to lower revenues.  Our combined average realized sales price per Boe decreased 2.0%, with lower average realized sales prices of oil being partially offset by higher average realized natural gas sales prices.  Our combined production of oil, NGLs and natural gas on a Boe basis during 2014 decreased 1.9% from 2013.

58


The changes in working capital and ARO settlements led to a net reduction of $4.0 million in net cash provided by operating activities between 2014 and 2013. The reduction was primarily caused by large income tax refunds received in 2013 due to carryback of tax-based net operating losses and higher receivable collections received in 2013.  At the beginning of 2013, receivable balances were higher than historical trends and led to higher collections in 2013.  For 2014, receivable balances were lower due to lower average realized sales oil prices, but not as large a decrease as experienced in 2013.  Partially offsetting were reductions of escrowed deposits related to ARO arrangements.  Escrowed deposits are included within Prepaid and Other Assets on the Condensed Consolidated Statements of Cash Flows.  

Net cash used in investing activities during 2014 and 2013 was $630.0 million and $614.8 million, respectively, which represents our investments in both offshore and onshore oil and gas properties.properties;

reductions in our proved reserves and the estimated value thereof;

additional supplemental bonding and potential collateral requirements;

further reductions in our borrowing base under the Credit Agreement; and

our ability to fund capital expenditures needed to replace produced reserves, which must be replaced on a long-term basis to provide cash to fund liquidity needs described above.

During 2016, we engaged legal and financial advisors to assist the Board of Directors and our management team to evaluate the various alternatives available to us and executed the transaction described below:


Exchange Transaction.On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our Unsecured Senior Notes, due June 15, 2019 for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 (the “Second Lien PIK Toggle Notes”); (ii) $142.0 million in aggregate principal amount of 8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021 (the “Third Lien PIK Toggle Notes”); and (iii) 60.4 million shares of our common stock (the “Debt Exchange”).  The increasereduction in the debt principal from exchanging the Unsecured Senior Notes is primarily due to proceeds from properties sales and other items of $21.0 million receivedpresented in 2013 and no similar transactions occurred in 2014.  Partially offsetting were decreases in acquisition expenditures, as we paid $72.2 million related to the increased ownership in Fairway and for the acquisition of the Woodside Properties in 2014 (two separate transactions) compared to $82.4 million related to the acquisition of the Callon Properties in 2013.  following table (in thousands):

 

Closing on

 

 

September 7, 2016

 

8.50% Unsecured Senior Notes, due June 2019, exchanged -   Principal

$

710,171

 

 

 

 

 

Secured Debt Issued (principal):

 

 

 

9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020

 

159,763

 

8.50%/10.00% Third Lien PIK Toggle Notes due June 2021

 

142,031

 

Subtotal

 

301,794

 

 

 

 

 

Reduction of debt principal

$

408,377

 

Net cash provided by financing activities was $126.4 million during 2014. The net cash provided during 2014 was primarily attributable to net borrowings on our revolving bank credit facility of $157.0 million, which was partially offset by dividend payments of $30.3 million. Net cash provided by financing activities was $57.0 million during 2013.  The net cash provided during 2013 was primarily attributable to net borrowings on our revolving bank credit facility of $120.0 million, which was partially used for dividend payments of $58.8 million and debt issuance costs of $3.9 million.table above does not reflect accounting adjustments under ASC 470-60 (Troubled Debt Restructuring).

At December 31, 2014,the same time on closing on the Debt Exchange, we hadclosed on a cash balance$75.0 million, 11.00% 1.5 Lien Term Loan, due November 2019, with the largest holder of $23.7 million and $302.4 million of undrawn capacity available underour Unsecured Senior Notes.  The funds from the 1.5 Lien Term Loan were used to partially pay down borrowings outstanding on the revolving bank credit facility and to pay transaction costs associated with the Exchange Transaction.  We accounted for the Exchange Transaction as a Troubled Debt Restructuring under ASC 470-60.  Under ASC 470-60, the carrying value of the newly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Consolidated Statements of Operations from September 7, 2016 to December 31, 2016.  Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt.  Under ASC 470-60, interest payments related to the New Debt are reported in the financing section of the Statement of Cash Flows.


The following table presents all of our long-term debt, with December 31, 2016 being after the Exchange Transaction and June 30, 2016 and December 31, 2015 being prior to the Exchange Transaction (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30,

 

 

December 31,

 

 

December 31, 2016

 

 

2016

 

 

2015

 

 

 

 

 

 

PIK Payable/

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Payable/

 

 

Carrying

 

 

Principal/

 

 

Principal/

 

 

Principal

 

 

Other

 

 

Value

 

 

Other*

 

 

Other*

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revolving Bank Credit Facility,

      due November 2018

$

 

 

$

 

 

$

 

 

$

148,000

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

11.00% 1.5 Lien Term Loan,

     due November 2019

 

75,000

 

 

 

23,823

 

 

 

98,823

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9.00 % Second Lien Term Loan,

    due May 2020

 

300,000

 

 

 

 

 

 

300,000

 

 

 

300,000

 

 

 

300,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9.00%/10.75% Second Lien PIK Toggle Notes,

    due May 2020

 

163,007

 

 

 

60,898

 

 

 

223,905

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8.50%/10.00% Third Lien PIK Toggle Notes,

   due June 2021

 

145,897

 

 

 

67,549

 

 

 

213,446

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8.50% Unsecured Senior Notes,

    due June 2019

 

189,829

 

 

 

 

 

 

189,829

 

 

 

900,000

 

 

 

900,000

 

Subtotal

 

873,733

 

 

 

152,270

 

 

 

1,026,003

 

 

 

1,348,000

 

 

 

1,200,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt premium, discount, issuance costs,

     net of amortization

 

 

 

 

(5,276

)

 

 

(5,276

)

 

 

(2,949

)

 

 

(3,145

)

Total long-term debt

 

873,733

 

 

 

146,994

 

 

 

1,020,727

 

 

 

1,345,051

 

 

 

1,196,855

 

Current maturities of long-term debt

 

 

 

 

8,272

 

 

 

8,272

 

 

 

 

 

 

 

Long term debt, less current maturities

$

873,733

 

 

$

138,722

 

 

$

1,012,455

 

 

$

1,345,051

 

 

$

1,196,855

 

* Amounts also equal the carrying value as of these dates.

A gain of $123.9 million was recognized related to the Exchange Transaction.  Under ASC 470-60, a gain was recognized as the sum of (i) the future undiscounted payments (principal and interest) related to the New Debt, (ii) the fair value of the common stock issued and (iii) deal transaction costs of $18.9 million was less than the sum of (iv) the carrying value of the Unsecured Senior Notes exchanged and (v) the funds received from the 1.5 Lien Term Loan.  The 60,435,544 shares of common stock issued were valued at $1.76 per share, which hadwas the closing price on September 7, 2016.  



The following table presents the calculation of the gain on exchange of debt (in thousands):

 

Closing on

 

 

September 7, 2016

 

(i)  Future Undiscounted Payments related to New Debt:

 

 

 

 

 

 

9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020:

 

 

 

 

 

 

Principal

$

159,763

 

 

 

 

PIK Payable

 

27,292

 

 

 

 

Interest Payable

 

36,850

 

 

 

 

 

 

 

 

 

 

 

8.50%/10.00% Third Lien PIK Toggle Notes due June 2021:

 

 

 

 

 

 

Principal

 

142,031

 

 

 

 

PIK Payable

 

30,710

 

 

 

 

Interest Payable

 

40,705

 

 

 

 

 

 

 

 

 

 

 

11.00% 1.5 Lien Term Loan, due November 2019:

 

 

 

 

 

 

Principal

 

75,000

 

 

 

 

Interest Payable

 

26,393

 

 

 

 

 

 

 

 

 

 

 

(ii)  Fair value of common stock issued

 

106,366

 

 

 

 

 

 

 

 

 

 

 

(iii)  Exchange Transaction costs

 

18,934

 

 

 

 

 

 

 

 

 

 

 

(A) Sub-Total of (i), (ii) and (iii) above

 

 

 

$

664,044

 

 

 

 

 

 

 

 

(iv)  Carrying value of 8.50% Unsecured Senior Notes, due June 2019,

        exchanged:

 

 

 

 

 

 

Principal

 

710,171

 

 

 

 

Unamortized debt issuance costs and premium

 

2,796

 

 

 

 

 

 

 

 

 

 

 

(v)  11.00% 1.5  Lien Term Loan - funds received

 

75,000

 

 

 

 

 

 

 

 

 

 

 

(B) Sub-Total of (iv) and (v) above

 

 

 

 

787,967

 

 

 

 

 

 

 

 

Gain on exchange of debt  (A less B)

 

 

 

$

123,923

 

The funds received from the 1.5 Lien Term Loan were used to pay transaction costs related to the Exchange Transaction and to pay down borrowings on the revolving bank credit facility.  The balance of the borrowings on the revolving bank credit facility was paid down from available cash.

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.  A total of $247.7 million would become due on February 28, 2019 if acceleration were to occur.    

Credit Agreement and Other Long-Term Debt.  In conjunction with the Exchange Transaction, amendments were executed for the Credit Agreement.  The primary items related to the recent amendments were:

Borrowing base revisions have been suspended until April 2017, (referred to as a bank holiday), at which time the borrowing base will be redetermined per the normal timeframe described below.  Therefore, the borrowing base could not be changed during the fourth quarter of $750.02016 and remained at $150.0 million.

The First Lien Leverage Ratio limits were changed to 2.50 to 1.00 through June 30, 2017, and to 2.00 to 1.00 thereafter.

We are required to have deposit accounts only with banks under the Credit Agreement with certain exceptions.


We may not have unrestricted cash balances above $35 million if outstanding balances on the revolving bank credit agreement (including letters of credit) are greater than $5 million.

The margins on amounts borrowed were increased.  Borrowings primarily are executed as Eurodollar Loans, and the applicable margins range from 3.00% to 4.00%.

The commitment fee was changed to 50 basis points for all levels of utilization.

Availability as of December 31, 2014.

Credit agreement and long-term debt. 2016 was $149.5 million.  At December 31, 2014, $447.02016 and 2015, no amounts were outstanding and letters of credit were $0.5 million was outstandingand $0.9 million, respectively, under our revolving bank credit facility.  During the 2016, the outstanding borrowings on the revolving bank credit facility comparedranged from zero to $290.0 million at December 31, 2013. At December 31, 2014 and 2013, $900.0 million principal amount of our 8.50% Senior Notes were outstanding. We believe that cash provided by operations and borrowings available$340.0 million.

Availability under our revolving bank credit facility is sufficient to fund our ongoing cash requirements.  See Capital Expenditures below.  

On November 8, 2013, we entered into the Credit Agreement which provides a revolving bank credit facility of up to $1.2 billion. Letters of credit may be issued up to $300.0 million, provided availability under the revolving bank credit facility exists. This is a secured facility that is collateralized by our oil and natural gas properties. The Credit Agreement terminates on November 8, 2018 and replaced the Prior Credit Agreement. Availability under the Credit Agreement is subject to a semi-annual redetermination of our borrowing base re-determination set atthat occurs in the discretionspring and fall of our lenders,each year and the Company and the lenders may each request one additional re-determination per year. The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  See Risk Factors – Lower oilThe next redetermination is scheduled to occur in April 2017.  The lenders and natural gas prices could negatively impact our ability to borrow under Part I, Item 1A in this Form 10-K.the Company have the option for an additional redetermination every year.  Any determination by our lenders to change our borrowing base as a result of the current commodity price environment or otherwise, will result in a similar change in the availability under our revolving bank credit facility.  During 2014,To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base, was re-determined and set at $750.0 million.  Borrowingssuch excess is required to be repaid within 90 days in three equal monthly payments.  Letters of credit may be issued in amounts up to $150.0 million, provided availability under the revolving bank credit facility exists.  The revolving bank credit facility is secured and is collateralized by substantially all of our oil and natural gas properties.  The Credit Agreement bearterminates on November 8, 2018 and interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 1.75% to 2.75% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the greater of (a) Prime Rate, (b) Federal Funds Rate plus 0.5%, and (c) LIBOR plus 1.0%, plus applicable margin ranging from 0.75% to 1.75%.  The unused portion of the borrowing base is subject to a commitment fee ranging from 0.375% to 0.5%.     fees are payable quarterly in arrears.

We currently have 20 lenders within the revolving bank credit facility, with commitments ranging from $20.0$4.1 million to $58.0$11.6 million for the current borrowing base.  While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, any lack of or delay in funding by members of our banking group could negatively impact our liquidity position.

Conditions related to incurring additional debt, and conditions and limitations concerning early repayment of certain debt are discussed in Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K.

The Credit Agreement contains covenants that limit, among other things, the payment of cash dividends in excess of $60.0 million per year. In December 2012, we were granted a one-time waiver which allowed for cash dividends of up to $85.0 million during 2012. The Credit Agreement contains various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio and a maximum leverage ratio,which include thresholds on financial ratios, as defined in the agreements.Credit Agreement.  We were in compliance with all applicable covenants of the Credit Agreement and the other debt instruments as of December 31, 2014.  Assuming continuing oil and gas prices near levels realized in December 2014 and January 2015, we likely will be out of compliance with certain of2016.

For our financial ratio maintenance covenants under our Credit Agreement sometime during 2015.  We intend to engageother long-term debt, the lenders under the Credit Agreement in discussions regarding amending our financial ratio covenants at such time as our borrowing base is next redetermined, but we can provide no assurance that we will be successful in obtaining such an amendment.  While we believe we will obtain the appropriate covenant relief, if we are unable to obtain such an amendment from our lenders, we believe that we can find alternative financing and we may have to reduce our cash outlays further for capital expendituresrecorded amounts, maturity dates and other activities until such time as market conditions recover. Realization of any of these factors could adversely affect our financial condition, results of operations and cash flows.

59


During 2014, the outstanding borrowings on the revolving bank credit facility reached a high of $447.0 million, which was also the outstanding balance at December 31, 2014, primarily to fund acquisitions, our various deepwater development efforts and our ongoing onshore operations. Letters of credit outstanding as of December 31, 2014 were $0.6 million.  

The 8.50% Senior Notes mature on June 15, 2019 and interest is payable semi-annuallyprimary terms are described in arrears on June 15 and December 15 of each year. SeeFinancial Statements and Supplementary Data – Note 72 – Long-Term Debt under Part II, Item 8 in this Form 10-K10-K.  Interest on the 1.5 Lien Term Loan is paid quarterly in arrears and is paid in cash.  Interest on the Second Lien Term Loan, the Second Lien Toggle Notes, the Third Lien Toggle Notes and the Unsecured Senior Notes is paid semi-annually in arrears.  For the Second Lien Term Loan, interest is paid in cash.  For the Second Lien PIK Toggles Notes, we have the option of using PIK or paying in cash for the interest obligations up through March 6, 2018, then interest is paid in cash.  For the Third Lien PIK Toggles Notes, we have the option of using PIK or paying in cash for the interest obligations up through September 6, 2018, then interest is paid in cash.  Usage of the PIK option increases the principal amount of these notes.  For the Unsecured Senior Notes, interest is paid in cash.  

BOEM Matters.  In the first quarter of 2016, we received several orders from the BOEM demanding the Company to secure financial assurances in the aggregate of $260.8 million, with amounts specified with respect to certain designated leases, ROWs and RUEs.  We filed various appeals to the IBLA concerning these orders.  The IBLA, acknowledging the BOEM and the Company were seeking to resolve the BOEM demands through settlement discussions, stayed the effectiveness of these orders several times, with the current stay effective to May 31, 2017.  

In July 2016, the BOEM issued NTL #2016-N01, related to obligations for decommissioning activities on the OCS, to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional security may be required for OCS leases, ROWs and RUEs.  This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07.


In September 2016, we received notice from the BOEM confirming that we do not qualify to self-insure a portion of any additional financial assurance under NTL #2016-N01.  In October 2016, we received from the BOEM proposal letters outlining what additional security the BOEM proposes to require for leases, ROWs and RUEs in which we are designated operator.  

In December 2016, the BOEM issued to us an Order to Provide Additional Security for our sole liability properties.  Sole liability properties are leases, ROWs or RUEs for which the holder is the only liable party, i.e., there are no co-lessees, operating rights owners and/or other grant holders, and no prior interest holders liable to meet the lease and/or grant obligations.  

In January 2017, BOEM, in a notice to stakeholders, extended the implementation timeline for NTL #2016-N01 by an additional six months with respect to non-sole liability leases, ROWs and RUEs, except in circumstances in which BOEM determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  The extension did not affect the demand to provide financial assurance for leases, ROWs and RUEs constituting sole liability properties.  The BOEM stated that the extension was needed to provide the BOEM and industry the opportunity to focus on providing additional security for sole liability properties, and to allow an opportunity for additional information abouttime and conversation concerning the non-sole liability properties.  

In February 2017, the BOEM withdrew the orders it issued in December 2016 affecting so called “sole liability properties” to allow time for the new President’s administration to review the complex financial assurance program. This withdrawal rescinded the Order to Provide Additional Security issued to us in December 2016.  However, the BOEM may re-issue sole liability orders before the end of the six-month period if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  

As suggested by the BOEM in its January and February notices to stakeholders, we intend to use the six month extension granted by the BOEM as an opportunity to propose and negotiate acceptable plans dealing with both sole and non-sole liability properties.

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, ordering suspension of operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our Credit Agreementbusiness, properties, results of operations and long-term debt.financial condition.  See “Risk Factors — We may be unable to provide the financial assurances demanded by the BOEM to cover our decommissioning obligations in the amounts and under the time periods required by the BOEM, either under the current rules or new rules that may be proposed.  If extensions and modifications to the BOEM’s current or future 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” under Part I, Item 1A of this Form 10-K.

Surety Bond Collateral.  Some of the sureties under our existing supplemental surety bonds have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and could impact our liquidity.  In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion.

The issuance of any additional surety bonds or other security to satisfy the BOEM orders, any future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third-parties may require the posting of cash collateral, which may be significant, and the creation of escrow accounts.  

Cash flow and working capital.  Net cash provided by operating activities for 2016 was $14.2 million, compared to $133.2 million for 2015.  Cash flows from operating activities, before changes in working capital and ARO settlements, were $103.1 million in compliance2016 compared to $140.3 million in 2015.  The reduction in cash flows was primarily due to lower realized prices for all our commodities - oil, NGLs and natural gas and lower production volumes, partially offset by lower operating expenses.  Our combined average realized sales price per Boe decreased 12.2%, which lowered revenues $61.5 million (57.3% of the total change in revenues).  Combined volumes on a Boe basis decreased 9.9%, which lowered revenues by $43.1 million.  Partially offsetting were decreases in lease operating expenses of $40.4 million and lower G&A expenses of $13.4 million.  

Other items affecting operating cash flows for 2016 were ARO settlements of $72.3 million and collateral deposits of $16.9 million.  


Net cash used in investing activities of oil and gas properties and equipment during 2016 was $82.4 million, which represents our investments in oil and gas properties and equipment.  For 2015, we had net cash provided by investing activities of $86.1 million due to the proceeds from the sale of all our onshore interest in the Yellow Rose field, partially offset by investments in oil and gas properties and equipment in the Gulf of Mexico.  There were no acquisitions of significance during either period.  Investments in oil and natural gas properties on an accrual basis during 2016were $48.6 million compared to $230.2 million for 2015.  In addition, adjustments from working capital changes associated with all applicable covenantsinvesting activities used net cash of $35.2 million in 2016 compared to net cash usage of $55.4 million for 2015.  Both of these amounts represent cash expenditures in the year following the work, and accrual of the cost for accounting purposes occurred in the period the work was performed.      

Net cash provided by financing activities for 2016 was $53.0 million and net cash used in financing activities for 2015 was $157.6 million.  The net cash provided by financing activities for 2016 was attributable to the 1.5 Lien Term Loan, partially offset by costs related to the 8.50% Senior Notes asExchange Transaction and interest payments related to the 1.5 Lien Term Loan.  Interest related to debt meeting the definition of December 31, 2014.troubled debt restructuring under ASC 470-60, of which the 1.5 Lien Term Loan meets the definition of troubled debt restructuring, is included in net cash provided by financing activities.  The net cash used in financing activities for 2015 was attributable to net repayments on the revolving bank credit facility, partially offset by the issuance of the Second Lien Term Loan.  

Derivative financial instruments.  From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility.  As of December 31, 2014,2016, we did not have any outstanding open derivatives. See Financial Statementsderivatives for crude oil and Supplementary Data – Note 6 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information about our derivatives.natural gas.  

Hurricane remediation, insurance claims and insurance coverage. During 2008, Hurricane Ike caused substantial property damage.  Substantially all the costs related to Hurricane Ike have been incurred and we submitted claims under our insurance policies effective at that time, of which $161.2$171.4 million has been collected through December 31, 2014.2016.  In June 2014, the United States Fifth Circuit reversed a lower court’s ruling and compelledDecember 2016, we reached settlements with certain insurance companies related to claims under our insurance underwritersexcess liability policies arising from Hurricane Ike which had been made subject to reimburse costs incurredadjustment or request for reimbursement by us, for removal of wreck relatedin which these companies agreed to damages we incurred during Hurricane Ike.  Several of the underwriters have not paid in accordance with the Fifth Circuit ruling.  We filed a lawsuit in September 2014 against certain underwriters for amounts owed, interest, attorney fees and damages.  After receiving reimbursements applied against our remaining Energy Package limits, reimbursement from certain underwriters of the Excess Policies of approximately $10 million and adjustments topay such claims the estimated potential reimbursement of removal-of-wreck costs is approximately $31totaling $30.2 million, plus interest and attorney fees, which were received in December 2016 and damages, if any.  Given the Fifth Circuit’s ruling, we expectJanuary 2017.   This settlement did not include claims arising from Hurricane Ike that have not yet been made subject to be reimbursed and compensatedadjustment or requested for all these costs, interest, fees and damages.reimbursement by us.  See Financial Statements and Supplementary Data - Note 1817 – Contingencies and Note 19 – Subsequent Eventsunder Part II, Item 8 in this Form 10-K for additional information.

We currently carry multiple layers of insurance coverage in our Energy Package 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$30.0 million to $500.0 million depending on the risk profile and contractual requirements. requirements.  We have $75.0 million of named windstorm (hurricane and tropical storm) coverage for certain of our offshore properties and wells and an additional $75.0 million for certain properties and wells at our higher value fields.  We have $50.0 million ofcarry named windstorm coverage of $150.0 million for TLO on our lower value offshore properties for the cost of removal in excess of scheduled ARO amounts.  The well control,Mahogany platform (Ship Shoal 349) and do not have named windstorm coverage on any other of our properties.  The operational and physical damage coverage isnamed windstorm coverages described above are effective until June 1, 2015.  A per-occurrence retention amount of $30.0 million for named windstorm events must be satisfied by us before our insurers will indemnify us for losses and we co-insure 15% of our named windstorm coverage. We also have other smaller per-occurrence retention amounts for various other events.2017.  Coverage for pollution causing a negative environmental impact is provided under the well control and named windstormother sections ofwithin the policy.

All of our Gulf of Mexico properties with estimated future net revenues are covered under our current insurance policies for named windstorm damage.  The risk exposure varies per property and we have exposure for applicable retentions, co-insurance amounts and coverage limits.

Our general and excess liability policies are effective until May 1, 20152017 and provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination.  We have a builder’s risk and separate liability policy for certain non-operated properties for platforms and drilling operations under construction, which has coverage net to our interest of  $137 million and $50 million, respectively, with retentions ranging from $0.1 to $0.3 million for different events and is effective until the estimated completion date of December 31, 2015.  With respect to the Oil Spill Financial Responsibility requirement under the Oil Pollution Act of 1990,OPA, we are required to evidence $150.0 million of financial responsibility to the BSEE.  We qualify to self-insure for $54.0 millionBSEE and we have insurance coverage of this amount and the remaining $96.0 million is covered by insurance.such amount.  

Although we were able to renew our Energy Package and our general and excess liability policies in the second quarter of 2014May 2016, and have not been informed otherwise,our Energy Package in the future,June 2016, our insurers may not continue to offer this type and level of coverage to us in the future, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations.  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 insurers will not pay our claims.  However, we are not aware of any financial issues related to any of our insurance underwriterscompanies that would affect their ability to pay claims.  We do not carry business interruption insurance.


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The premiums for the above policies including brokerage fees were $25.6$8.5 million for the May/June 20142016 policy renewals compared to $24.1$16.3 million for the expiring policies.  The increasedecrease in our premiums effective with the May/June 1, 20142016 renewal was primarily attributable to reductions in properties covered and the additiontype of the builder’s risk policy and partially offset by lower premiums due to an improved insurance market.coverage for named windstorm damage.

Capital expenditures. The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors including the prices of crude oil, NGLs and natural gas,gas; acquisition opportunities,opportunities; liquidity and financing options; and the results of our exploration and development activities.  The following table presents our capital expenditures on an accrual basis for acquisitions, exploration, development, acquisitions and other leasehold costs:

 

 

Year Ended December 31,

 

 

 

2014

 

 

2013

 

 

2012

 

 

 

(In thousands)

 

Acquisition of additional interest in Fairway

 

$

17,407

 

 

$

 

 

$

 

Acquisition of Woodside Properties

 

 

54,827

 

 

 

 

 

 

 

Acquisition of Callon Properties

 

 

576

 

 

 

82,424

 

 

 

 

Acquisition of Newfield Properties

 

 

 

 

 

238

 

 

 

205,550

 

Exploration (1)

 

 

179,196

 

 

 

198,740

 

 

 

137,055

 

Development (1)

 

 

346,388

 

 

 

308,327

 

 

 

310,205

 

Seismic, capitalized interest, other leasehold costs

 

 

28,218

 

 

 

44,649

 

 

 

32,053

 

Acquisitions and investments in oil and gas property/equipment

 

$

626,612

 

 

$

634,378

 

 

$

684,863

 

 

 

Year Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

 

 

(In thousands)

 

Exploration (1)

 

$

1,541

 

 

$

51,768

 

 

$

179,196

 

Development (1)

 

 

45,183

 

 

 

160,500

 

 

 

346,388

 

Acquisition of additional interest in Fairway (2)

 

 

 

 

 

1,285

 

 

 

17,407

 

Acquisition of Woodside Properties (2)

 

 

 

 

 

214

 

 

 

54,827

 

Seismic, capitalized interest, other

 

 

1,882

 

 

 

16,394

 

 

 

28,794

 

Acquisitions and investments in oil and gas property/equipment

 

$

48,606

 

 

$

230,161

 

 

$

626,612

 

(1)

Reported geographically in the subsequent table.

(2)

The amounts in 2015 represent adjustments to the purchase price for post-effective adjustments.

The following table presents our exploration and development capital expenditures on an accrual basis geographically:

 

Year Ended December 31,

 

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

 

2016

 

 

2015

 

 

2014

 

 

(In thousands)

 

 

(In thousands)

 

Conventional shelf

 

$

131,215

 

 

$

143,151

 

 

$

104,401

 

 

$

38,631

 

 

$

13,933

 

 

$

131,215

 

Deepwater

 

 

216,539

 

 

 

143,745

 

 

 

65,856

 

 

 

8,093

 

 

 

186,579

 

 

 

216,539

 

Deep shelf

 

 

23,615

 

 

 

61,953

 

 

 

11,961

 

 

 

 

 

 

195

 

 

 

23,615

 

Onshore

 

 

154,215

 

 

 

158,218

 

 

 

265,042

 

 

 

 

 

 

11,561

 

 

 

154,215

 

Exploration and development capital expenditures

 

$

525,584

 

 

$

507,067

 

 

$

447,260

 

 

$

46,724

 

 

$

212,268

 

 

$

525,584

 

 

The following table sets forth our drilling activity on a gross basis.

Completed

 

 

Non-commercial

 

Completed

 

2014

 

 

2013

 

 

2012

 

 

2014

 

 

2013

 

 

2012

 

2016

 

 

2015

 

 

2014

 

Offshore - gross wells drills:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Conventional shelf

 

3

 

 

 

4

 

 

 

3

 

 

 

 

 

 

1

 

 

 

1

 

 

 

 

 

 

 

 

3

 

Deepwater

 

3

 

 

 

1

 

 

 

1

 

 

 

 

 

 

 

 

 

 

 

1

 

 

 

5

 

 

 

3

 

Deep shelf

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Wells operated by W&T

 

4

 

 

 

5

 

 

 

3

 

 

n/a

 

 

n/a

 

 

n/a

 

 

 

 

 

 

 

 

4

 

Onshore:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross wells drilled

 

33

 

 

 

40

 

 

 

77

 

 

 

 

 

 

 

 

 

 

Wells operated by W&T

 

32

 

 

 

40

 

 

 

73

 

 

n/a

 

 

n/a

 

 

n/a

 

We had a 100% success rate in each of the years presented.  

During 2015, we sold our interest in the onshore Yellow Rose field.  Therefore, the historical information for onshore wells was excluded from the table above.

As of December 31, 2014,2016, we were in the process of completing one offshore development well at the Mahogany field (the A-18 well).  This well was spud in 2014 and drilling and/or completing five offshore exploration wells, six onshore development wellswas suspended in Texasearly 2015.  Subsequently in August 2016, drilling was resumed and seven onshore exploration wells in Texas.the well reached target depth during 2016.  In January 2017, the A-18 well was completed and was brought on production.  

See Properties –Drilling Activity under Part I, Item 2 of this Form 10-K for a breakdown of exploration and development wells and additional drilling activity information.


See Properties –Development of Proved Undeveloped Reserves under Part I, Item 2 of this Form 10-K for a discussion on activity related to proved undeveloped reserves.

We acquired the following leases from the BOEM:  one lease ($0.1 million), two leases ($0.3 million) and five leases ($2.4 million), two leases ($0.5 million) and 11 leases ($2.5 million) for the years 2016, 2015 and 2014, 2013 and 2012, respectively.

61


From time to time, we sell various oil and gas properties for a variety of reasons including, change of focus, perception of value and to reduce debt, among other reasons.  As previously discussed, in 2015 we sold our interest in the Yellow Rose field for $370.9 million after adjustments and reduced related ARO for $6.9 million.  In 2014, there were no property sales of significance. In 2013, we sold our working interests in the Green Canyon 60 field, the Green Canyon 19 field, the West Delta area block 29 and, combined with various other transactions and adjustments, produced net cash receipts of $10.2 million and reduced ARO by $19.6 million. Also in 2013, we received $9.1 million in conjunction with a payment to us for an option exercised by a counterparty.  In 2012, we sold our 40% non-operated working interest in the South Timbalier 41 field for $30.5 million and reduced ARO by $4.0 million.  See Financial Statements and Supplementary Data – Note 27 – Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K for additional information on divestitures.

Capital expenditures.Our currentinitial capital expenditure budget for 20152017 is $200$125 million, not including any potential acquisitions.  The 2015 budget is being allotted as follows: 38% for exploration, 61% for development and less than 1% for other items.  Geographically, the budget is split 92% for offshore and 8% for onshore, with the substantial majority of offshore dedicated to the deepwater.  Through February 2015, we have not closed any acquisitions, but we continue to evaluate and bid on opportunities as they arise.  We anticipate funding our 2015 capital budget, anywhich excludes potential acquisitions, with over 50% allocated to development.  Because of the level of commodity prices and other expenditures with cash flow from operating activities, cash on hand and borrowings underthe outlook for the remainder of 2017, we believe this level will maintain our revolving bank credit facility.  For the portion of our capital budget related to drilling, our operating policy has been to fund these expenditures with cash flow provided by operations.  See below for information on capital markets.  Our 2015 capital budget is subject to change as conditions warrant.liquidity capacity throughout 2017.  We strive to be as flexible as possible and believe this strategy holds the best promise for value creation, growth and managing the volatility inherentmaintain flexibility in our business.capital expenditure projects and if prices improve, we may increase our investments.  See the Overview section in this Item for additional information.

Income taxes.  During 2014,2016, we made income tax payments of $0.3 million and received $7.8 million of refunds.  A portion of the refund in the amount of $5.8 million related to an NOL claim for 2015 carried back to 2005 filed on Form 1139, Corporation Application for Tentative Refund.  During 2015, we did not make any income tax payments and received $3.0 millionnor receive any refunds of refunds.  The refund was attributable to 2013 estimated federal tax payments.  During 2013,significance.  For 2017, we madeexpect that a substantial portion of our income tax will be deferred and payments, of $3.0 million and received $59.1 million of refunds.  The refunds wereif any, will be primarily attributablerelated to tax loss carrybacks to 2010 and 2011, and refunds of 2012 estimated federal tax payments.  During 2012, we made income tax payments of $16.1 million and received refunds of $0.5 million.  state taxes.  

As of December 31, 2014, $9.52016, we have recorded current income tax receivables of $11.9 million and non-current income tax receivables of the refunds received in 2013 have been accounted for as unrecognized$52.1 million.  The current income tax benefits.  We have $516.4 million of Federalreceivables relates primarily to a net operating loss carryforwards (tax basis) availableclaim for 2016 carried back to offset future taxable2006 and is included in receivable line Joint interest, insurance reimbursement and other on the Consolidated Balance Sheet.  The non-current income in 2015taxes receivables relates to our NOL claims for the years 2012, 2013 and forward.  We also have $12.1 million of alternative minimum tax credit carryforwards (tax basis) available2014 that were carried back to the years 2003, 2004, 2007, 2010 and 2011 filed on Form 1120X, U.S. Corporation Income Tax Return.  These carryback claims are made pursuant to IRC Section 172(f), which permits certain platform dismantlement, well abandonment and site clearance costs to be utilized in 2015carried back 10 years.  The refund claims filed on Form 1120X will require a review by the Congressional Joint Committee on Taxation and forward.are accordingly classified as non-current.

Dividends.  During 2016 and 2015, we did not pay any dividends and a suspension of dividends remains in effect.  In 2014, we paid $30.3 million in dividends.  In 2013, we paid $58.8 million in dividends, which included a special dividend totaling $31.8 million and regular dividends of $27.0 million. In 2012, we paid $82.8 million in dividends, which included two special dividends totaling $59.0 million and regular dividends of $23.8 million.  Dividends are subject to periodic review of the Company’s performance and the current economic environment and applicable debt agreement restrictions.  In light of current market conditions, the Board of Directors has elected to suspend the regular quarterly dividend.  

Capital markets and impact on liquidity. At this time, we do not have current plans to obtain additional financing in 2015, but this situation could change depending on a number of factors, such as acquisition opportunities and prices of oil and natural gas.  The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises.  Additionally, we may be restricted on accessing certain capital markets due to terms within our Credit Agreement and Senior Note Indenture if certain covenants, primarily certain financial ratios, are not achieved on a current and pro forma basis as defined within the agreements.  We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations through December 31, 2015; however, we cannot predict how an extended period of low commodity prices will affect our operations and liquidity levels.

  Asset retirement obligations.  Each year (and often more frequently) we review and revise our ARO estimates.  Our ARO at December 31, 20142016 and 20132015 were $390.6$334.4 million and $354.4$378.3 million, respectively.  In 2014Our estimate of ARO spending in 2017 is $78.3 million.  During 2016 and 2013,2015, we revised our estimates of costs anticipated to be charged by service providers for plug and abandonment projects.  As these estimates are for work to be performed in the future, and in many case, several years in the future, actual expenditures could be substantially different than our estimates.  Additionally, we revise our estimates to account for the increased cost to comply with new and revised regulations, including an increaseincreases in work scope and cost changes from interpretation of work scope.  See Risk Factors  –  Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are concentrated in the Gulf of Mexico under Part I, Item 1A and Financial Statements and Supplementary Data – Note 54 – Asset Retirement Obligations under Part II, Item 8 in this 10-K for additional information regarding our estimation of our ARO.


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Contractual obligations.  At December 31, 2016, we did not have any capital leases or open derivative contracts.  The following table summarizes our significant contractual obligations by maturity as of December 31, 2014. At December 31, 2014, we did not have any capital leases.2016:

Payments Due by Period as of December 31, 2014

 

Payments Due by Period as of December 31, 2016

 

Total

 

 

Less than

One Year

 

 

One to

Three Years

 

 

Three to

Five Years

 

 

More Than

Five Years

 

Total

 

 

Less than

One Year

 

 

One to

Three Years

 

 

Three to

Five Years

 

 

More Than

Five Years

 

Long-term debt - principal(1)

$

1,347.0

 

 

$

 

 

$

 

 

$

1,347.0

 

 

$

 

$

924.6

 

 

$

 

 

$

264.8

 

 

$

659.8

 

 

$

 

Long-term debt - interest (1)(2)

 

390.6

 

 

 

89.4

 

 

 

178.8

 

 

 

122.4

 

 

 

 

 

237.3

 

 

 

52.1

 

 

 

141.4

 

 

 

43.8

 

 

 

 

Drilling rigs

 

12.6

 

 

 

12.6

 

 

 

 

 

 

 

 

 

 

 

4.4

 

 

 

4.4

 

 

 

 

 

 

 

 

 

 

Operating leases

 

13.9

 

 

 

1.5

 

 

 

3.2

 

 

 

3.5

 

 

 

5.7

 

 

10.6

 

 

 

1.6

 

 

 

3.5

 

 

 

3.6

 

 

 

1.9

 

Asset retirement obligations (2)(3)

 

390.6

 

 

 

36.0

 

 

 

179.4

 

 

 

19.0

 

 

 

156.2

 

 

334.4

 

 

 

78.3

 

 

 

89.4

 

 

 

51.1

 

 

 

115.6

 

Other liabilities and commitments (3)(4)

 

61.7

 

 

 

7.9

 

 

 

15.7

 

 

 

9.7

 

 

 

28.4

 

 

66.6

 

 

 

7.8

 

 

 

15.2

 

 

 

9.9

 

 

 

33.7

 

Total

$

2,216.4

 

 

$

147.4

 

 

$

377.1

 

 

$

1,501.6

 

 

$

190.3

 

$

1,577.9

 

 

$

144.2

 

 

$

514.3

 

 

$

768.2

 

 

$

151.2

 

(1)

InterestPrincipal on long-term debt assumes the PIK option is comprised of: (a) interestfully utilized on our 8.50% Seniorthe Second Lien PIK Toggle Notes which bear interest at a fixed rate of 8.50% and (b) interest on our revolving bank credit facility, which has a variable interest rate, estimated using the borrowings outstanding as of December 31, 2014, an annual interest rate of 2.6%, which was the interest rate as of December 31, 2014, and the commitment fee of 0.375% on the unused balance as of December 31, 2014. Third Lien PIK Toggle Notes.

(2)

Interest waspayments were calculated through the stated maturity date of the related debt.debt:  (a) Interest on long-term debt assumes full utilization of the PIK option for the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes.  (b) As no amounts were outstanding on the revolving bank credit facility as of December 31, 2016 and minimal letters of credit were outstanding, interest for the revolving bank credit facility was calculated using the commitment fee of 0.50% on the current borrowing base through the maturity date.    

(2)(3)

ARO in the above table is presented on a discounted basis, consistent with the amounts reported on the Consolidated Balance as of December 31, 2014.2016 and are estimates of future payments.  Actual payments and the timing of the payments may be significantly different than our estimates.  All other amounts in the above table are presented on an undiscounted basis.  

(3)(4)

Other liabilities and commitments primarily consist of estimated fees for obtainingsurety bonds related to obligations under certain purchase and sale agreements and for supplemental bonding for plugging and abandonment on behalf of the BOEM.  The amounts are based on current market rates and conditions for these types of bonds and are subject to change.  Excluded are potential increases in surety bond requirements which have not yet been determined.  Also excluded are obligations under joint interest arrangements related to commitments that have not yet been incurred.  In these instances, we are obligated to pay, according to our interest ownership, a portion of exploration and development costs, operating costs and potentially could be offset by our interest in future revenue from these non-operated properties.  These joint interest obligations for future commitments cannot be determined due to the variability of factors involved.  See Financial Statements and Supplementary Data – Note 1615 – Commitments under Part II, Item 8 in this 10-K for additional information.


Inflation and Seasonality

Inflation.  For 2014,2016, our realized prices for crude oil decreased 11.2%17.1%, NGLs decreased 1.7%0.6% and natural gas increased 22.5%decreased 5.2% from 2013.2015.  These are discussed in the Overview section above.  Costs measured on a $/Boe basis increased(excluding DD&A and ceiling test write-downs) decreased by 9.5%8.1% in 20142016 compared to 2013.2015.  The cost per Boe is impacted by factors other than cost changes, such as work activity including workovers, production levels and insurance reimbursements.  Historically, costs for goods and services have moved directionally with the price of crude oil, NGLs and natural gas, as these commodities affect the demand for these goods and services.  In recent years, other factors have influenced the cost of goods and services.  Demand for offshore third-party contractors can be affected by hurricanes, oil spills and changes in regulations which are outside of the influences from commodity price changes.  Other costs, such as insurance premiums, have fluctuated with changes in hurricane activity, the oil spills and other factors besides production volumes.  Also, many commodity prices, including crude oil, copper, steel and other types of metals, have fluctuated wildly with various world events.  Some of this fluctuation is due to changes in economic activity in certain parts of the world, while other changes appear to be driven by political events around the world, the changes in the value of the US dollar (both up and down) and other foreign currencies.  In addition, inflation in our industry is impacted as a result of record federal deficits and expectations that large deficits will continue.

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 may be 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 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.

63


Critical Accounting Policies

This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with GAAP in the United States.  The preparation of our financial statements requires us to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements.  We base our estimates on historical experience and other sources that we believe to be reasonable at the time.  Changes in the facts and circumstances or the discovery of new information may result in revised estimates and actual results may vary from our estimates.  Our significant accounting policies are detailed in Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K.  We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management.

Revenue recognition.  We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured.  We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership.  Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production.  These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production.  If crude oil and natural gas prices decrease, we may need to increase this liability.  Also, disputes may arise as to volume measurements and allocation of production components between parties.  These disputes could cause us to increase our liability for such potential exposure.  We do not record receivables for those properties in which the Company has taken less than its ownership share of production which could cause us to delay recognition of amounts due us.


Full-cost accounting.  We account for our investments in oil and natural gas properties using the full-cost method of accounting.  Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and gas properties are capitalized.  Capitalization of geological and geophysical costs, certain employee costs and G&A expenses related to these activities is permitted.  We amortize our investment in oil and natural gas properties, capitalized ARO and future development costs (including ARO of wells to be drilled) through DD&A, using the units-of-production method.  The units-of-production method uses reserve information in its calculations.  The cost of unproved properties related to acquisitions are excluded from the amortization base until it is determined that proved reserves exist or until such time that impairment has occurred.  We capitalize interest on unproved properties that are excluded from the amortization base.  The costs of drilling non-commercial exploratory wells are included in the amortization base immediately upon determination that such wells are non-commercial.  Under the full-cost method, sales of oil and natural gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized unless an adjustment would significantly alter the relationship between capitalized costs and the value of proved reserves.

Our financial position and results of operations may have been significantly different had we used the successful-efforts method of accounting for our oil and natural gas investments.  GAAP allows successful-efforts accounting as an alternative method to full-cost accounting.  The primary difference between the two methods is in the treatment of exploration costs, including geological and geophysical costs, and in the resulting computation of DD&A.  Under the full-cost method, which we follow, exploratory costs are capitalized, while under successful-efforts, the cost associated with unsuccessful exploration activities and all geological and geophysical costs are expensed.  In following the full-cost method, we calculate DD&A based on a single pool for all of our oil and natural gas properties, while the successful-efforts method utilizes cost centers represented by individual properties, fields or reserves.  Typically, the application of the full-cost method of accounting for oil and natural gas properties results in higher capitalized costs and higher DD&A rates, compared to similar companies applying the successful efforts method of accounting.

DD&A can be affected by several factors other than production.  The rate computation includes estimates of reserves which requires significant judgmentsjudgment and is subject to change at each assessment.  The determination of when proved reserves exist for our unproved properties requires judgment, which can affect our DD&A rate.  Also, estimates of our ARO and estimates of future development costs require significant judgment.  Actual results may be significantly different from thesesuch estimates, which would affect the timing of when these expenses would be recognized in DD&A.  See Oil and natural gas reserve quantities and Asset retirement obligations below for more information.

64


Impairment of oil and natural gas properties.  Under the full costfull-cost method of accounting, we are required to periodically perform a “ceiling test,”test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties.  Any write downs occurring as a result of the ceiling test impairment are not recoverable or reversible in future periods.  We incurred significant ceiling test write-downs during 2016 and 2015.  We did not have any ceiling test impairments in 2014 or2014.  Ceiling test impairments in future periods are highly dependent on commodity prices, and also are impacted by other factors and events.   See the previous four years.  If WTI and Brent prices remain at levels occurring during December 2014 and January 2015, we estimate that we will likely recognizeOverview section for a non-cashdiscussion on the price sensitivity of the ceiling test write-down during 2015, and could have a non-cash ceiling test write-down in more than one quarter of 2015.under certain assumptions.  For the effect of lower commodity prices on liquidity, see  Risk Factors - Risks Related to Financing under Part I, Item 1A and in the Liquidity and Capital Resources section of this Item in this Form 10-K for additional information about our Credit Agreement and financing.  For the effect of lower commodity prices on revenues and earnings, see Quantitative and Qualitative Disclosures on Market Risks under Part II, Item 7A in this Form 10-K for additional information.

Oil and natural gas reserve quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of DD&A and impairment assessment of our oil and natural gas properties.  We make changes to DD&A rates and impairment calculations in the same period that changes to our reserve estimates are made.  Our proved reserve information as of December 31, 20142016 included in this Form 10-K was estimated by our independent petroleum consultant, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.  The accuracy of our reserve estimates is a function of:


·

the quality and quantity of available data and the engineering and geological interpretation of that data;

·

estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results;

estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results;

·

the accuracy of various mandated economic assumptions such as the future prices of oil and natural gas; and

the accuracy of various mandated economic assumptions such as the future prices of crude oil and natural gas; and

·

the judgment of the persons preparing the estimates.

the judgment of the persons preparing the estimates.

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered.  See the Overview section for a discussion on the price sensitivity of the ceiling test under certain assumptions and the resulting sensitivity to reserve quantities.

Asset retirement obligations.  We have significant obligations to plug and abandon all well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations.  These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup.  Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal.  Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period.  Pursuant to GAAP, we are required to record a separate liability for the discounted present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet.

Inherent in the present value calculation of our liability are numerous estimates and judgments, including the ultimate settlement amounts, inflation factors, changes to our credit-adjusted risk-free rate, timing of settlement and changes in the legal, regulatory, environmental and political environments.  Revisions to these estimates impact the value of our abandonment liability, our oil and natural gas property balance and our DD&A rates.

Fair value measurements.  We measure the fair value of our derivative financial instruments by applying the income approach and using inputs that are derived principally from observable market data.  Changes in the underlying commodity prices of the derivatives impact the unrealized and realized gain or loss recognized.  We do not apply hedge accounting to our derivatives; therefore, the change in fair value for all outstanding derivatives, which include derivatives that are entered into in anticipation of future production, are reflected currently in our statements of operations.  This can create timing differences between when the production is recognized and when the gain or loss on the derivative is recognized in the income statement.  We estimate the fair value of our debt based on trades when such information is available.  The market for our debt has low volumes of activity and has experienced high volatility in the past; therefore, the fair values presented may not represent the fair value of our debt in future periods.  


65


Income taxes. We provide for income taxes in accordance with GAAP, which requires the use of the liability method of computing deferred income taxes, whereby deferred income taxes are recognized for the future tax consequences of the differences between the tax basis of assets and liabilities and the carrying amount in our financial statements.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  Because our tax returns are filed after the financial statements are prepared, estimates are required in recording tax assets and liabilities.  We record adjustments to reflect actual taxes paid in the period we complete our tax returns.  In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.

We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken.  When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense.  The final settlement of these tax positions may occur several years after the tax return is filed and may result in significant adjustments depending on the outcome of these settlements.


Share-based compensation.  In accordance with GAAP, weWe recognize compensation cost for share-based payments to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of the grant.grant, which may be significantly different than on the date of vesting.  We estimate forfeitures during the service period and make adjustments depending on actual experience.  These adjustments can create timing differences on when expense is recognized.

Troubled Debt Restructuring.   We accounted for the Exchange Transaction as a troubled debt restructuring pursuant to the guidance under ASC 470-60.  Under ASC 470-60, the carrying value of the New Debt is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Consolidated Statements of Operations for the period from September 7, 2016 to December 31, 2016.  Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt.  The amounts recorded for the carrying value of the New Debt were determined using certain assumptions, which primarily were: (i) the PIK options, when available, would be fully utilized and (ii) the maturity of 1.5 Lien Term Loan and the Third Lien PIK Toggle Notes would not be accelerated, which implies the Unsecured Senior Notes will be refinanced prior to February 28, 2019.  These assumptions may prove to be incorrect, which would change the carrying value of the New Debt.    

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks arising from fluctuating prices of crude oil, NGLs, natural gas and interest rates as discussed below.  We have utilized derivative contracts to reduce the risk of fluctuations in commodity prices and expect to use these instruments in the future.  We did not have anyentered into derivative contracts for crude oil and natural gas during 2015 and had no open derivative contracts as of December 31, 2014.

Commodity price risk. Our revenues, profitability and future rate of growth substantially depend upon market prices for oil, NGLs and natural gas, which fluctuate widely. Oil, NGLs and natural gas price declines and volatility could adversely affect our revenues, net cash provided by operating activities and profitability. For example, assuming a 10% decline in our average realized oil, NGLs and natural gas sales prices in 2014 and assuming no other items had changed, our loss before income tax would have increased by approximately $94 million in 2014. If costs and expenses of operating our properties had increased by 10% in 2014, our loss before income tax would have increased by approximately $29 million in 2014.

As of December 31, 2014, we did not have any open derivative contracts.2016.  We do not designate our commodity derivative contracts as hedging instruments.  While previous derivative contracts were intended to reduce the effects of volatile oil prices, they may also have limited income from favorable price movements.  For additional details about our derivative contracts, refer to Financial Statements and Supplementary Data – Note 6 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K.

Commodity price risk. Our revenues, profitability and future rate of growth substantially depend upon market prices for crude oil, NGLs and natural gas, which fluctuate widely.  Crude oil, NGLs and natural gas price declines and volatility could adversely affect our revenues, net cash provided by operating activities and profitability.  For example, assuming a 10% decline in our average realized oil, NGLs and natural gas sales prices in 2016 and assuming no other items had changed, our loss before income tax would have increased by approximately $40 million in 2016.  If costs and expenses of operating our properties had increased by 10% in 2016, our loss before income tax would have increased by approximately $18 million in 2016.  These estimates exclude the potential increase to the ceiling test write-down resulting in further net losses, as a full reserve and PV-10 analysis would be required for such pro forma calculations.  The amounts above would be representative of the effect on operating cash flows under the price and cost change assumptions.

Interest rate risk. As of December 31, 2014,2016, we had $447.0 millionno borrowings outstanding on our revolving bank credit facility and during 20142016 we had amounts outstanding that ranged from $242.0 millionzero to $447.0$340.0 million.  The revolving bank credit facility has a variable interest rate which is primarily impacted by the rates for the LIBORLondon Interbank Offered Rate and the current margin ranges from 1.75%3.00% to 2.75%4.00% depending on the amount outstanding.  In 2014,2016, if interest rates would have been 100 basis points higher (an additional 1%); our interest expense would have been approximately $3.3$1.3 million higher.  We did not have any derivative contracts related to interest rates as of December 31, 2014.2016.  

 

 


66


Item 8. FinancialFinancial Statements and Supplementary Data

W&T OFFSHORE, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

  

Page

Management’s Report on Internal Control over Financial Reporting

  

6883

Report of Independent Registered Public Accounting Firm

  

6984

Report of Independent Registered Public Accounting Firm

  

7085

 

Consolidated Financial Statements:

  

 

Consolidated Balance Sheets as of December 31, 20142016 and 20132015

  

7186

Consolidated Statements of Operations for the years ended December 31, 2014, 20132016, 2015 and 20122014

  

7287

Consolidated Statements of Changes in Shareholders’ Equity (Deficit) for the years ended December 31, 2014, 20132016, 2015 and 20122014

  

7388

Consolidated Statements of Cash Flows for the years ended December 31, 2014, 20132016, 2015 and 20122014

  

7489

Notes to Consolidated Financial Statements

  

7590

 

 

 

67



MANAGEMENT’SMANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f).  Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States (GAAP).  Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.  Accordingly, even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework).  

Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 20142016 in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  The effectiveness of our internal control over financial reporting as of December 31, 20142016 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

 

 

 

68



REPORTREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of W&T Offshore, Inc. and Subsidiaries

We have audited W&T Offshore, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2014,2016, based on criteria established in the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the “COSO criteria”)COSO criteria).  W&T Offshore, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, W&T Offshore, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014,2016, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of W&T Offshore, Inc. and subsidiaries as of December 31, 20142016 and 2013,2015, and the related consolidated statements of operations, changes in shareholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 20142016 and our report dated March 6, 20152, 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

March 6, 20152, 2017

 

 

 


69


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of W&T Offshore, Inc. and Subsidiaries

We have audited the accompanying consolidated balance sheets of W&T Offshore, Inc. and subsidiaries as of December 31, 20142016 and 2013,2015, and the related consolidated statements of operations, changes in shareholders' equity (deficit) and cash flows for each of the three years in the period ended December 31, 2014.2016.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.   An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of W&T Offshore, Inc. and subsidiaries at December 31, 20142016 and 2013,2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2014,2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), W&T Offshore, Inc. and subsidiaries’’s internal control over financial reporting as of December 31, 2014,2016, based on criteria established in the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 6, 20152, 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

March 6, 20152, 2017

 

 

 


70


W&T OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

December 31,

 

December 31,

 

2014

 

 

2013

 

2016

 

 

2015

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

23,666

 

 

$

15,800

 

$

70,236

 

 

$

85,414

 

Receivables:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

 

67,242

 

 

 

96,752

 

 

43,073

 

 

 

35,005

 

Joint interest and other

 

43,645

 

 

 

31,104

 

Joint interest

 

21,885

 

 

 

22,000

 

Insurance reimbusrements

 

30,100

 

 

 

12

 

Income tax

 

11,943

 

 

 

 

Total receivables

 

110,887

 

 

 

127,856

 

 

107,001

 

 

 

57,017

 

Deferred income taxes

 

11,662

 

 

 

584

 

Prepaid expenses and other assets

 

36,347

 

 

 

29,362

 

 

14,504

 

 

 

26,879

 

Total current assets

 

182,562

 

 

 

173,602

 

 

191,741

 

 

 

169,310

 

Property and equipment - at cost:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas properties and equipment (full cost method, of which $109,824 at

December 31, 2014 and $116,612 at December 31, 2013 were excluded from amortization)

 

8,045,666

 

 

 

7,339,097

 

Oil and natural gas properties and equipment (full cost method, of which $0 at

December 31, 2016 and $18,595 at December 31, 2015 were excluded from amortization)

 

7,932,504

 

 

 

7,902,494

 

Furniture, fixtures and other

 

23,269

 

 

 

21,431

 

 

20,898

 

 

 

20,802

 

Total property and equipment

 

8,068,935

 

 

 

7,360,528

 

 

7,953,402

 

 

 

7,923,296

 

Less accumulated depreciation, depletion and amortization

 

5,575,078

 

 

 

5,084,704

 

 

7,406,349

 

 

 

6,933,247

 

Net property and equipment

 

2,493,857

 

 

 

2,275,824

 

 

547,053

 

 

 

990,049

 

Deferred income taxes

 

 

 

 

27,595

 

Restricted deposits for asset retirement obligations

 

15,444

 

 

 

37,421

 

 

27,371

 

 

 

15,606

 

Income tax receivables

 

52,097

 

 

 

 

Other assets

 

17,244

 

 

 

20,455

 

 

11,464

 

 

 

5,462

 

Total assets

$

2,709,107

 

 

$

2,507,302

 

$

829,726

 

 

$

1,208,022

 

Liabilities and Shareholders' Equity

 

 

 

 

 

 

 

Liabilities and Shareholders’ Deficit

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payable

$

194,109

 

 

$

145,212

 

$

81,039

 

 

$

109,797

 

Undistributed oil and natural gas proceeds

 

37,009

 

 

 

42,107

 

 

26,254

 

 

 

21,439

 

Asset retirement obligations

 

36,003

 

 

 

77,785

 

 

78,264

 

 

 

84,335

 

Long-term debt

 

8,272

 

 

 

 

Accrued liabilities

 

17,377

 

 

 

28,000

 

 

9,200

 

 

 

11,922

 

Total current liabilities

 

284,498

 

 

 

293,104

 

 

203,029

 

 

 

227,493

 

Long-term debt, less current maturities

 

1,360,057

 

 

 

1,205,421

 

Long-term debt, less current portion

 

1,012,455

 

 

 

1,196,855

 

Asset retirement obligations, less current portion

 

354,565

 

 

 

276,637

 

 

256,174

 

 

 

293,987

 

Deferred income taxes

 

186,988

 

 

 

178,142

 

Other liabilities

 

13,691

 

 

 

13,388

 

 

17,105

 

 

 

16,178

 

Commitments and contingencies

 

 

 

 

 

Shareholders' equity:

 

 

 

 

 

 

 

Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at

December 31, 2014 and 2013

 

 

 

 

 

Common stock, $0.00001 par value; 118,330,000 shares authorized;

78,768,588 issued and 75,899,415 outstanding at December 31, 2014;

78,460,872 issued and 75,591,699 outstanding at December 31, 2013

 

1

 

 

 

1

 

Commitments and contingencies (Notes 15 and 17)

 

 

 

 

 

 

 

Shareholders’ deficit:

 

 

 

 

 

 

 

Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at

December 31, 2016 and 2015

 

 

 

 

 

Common stock, $0.00001 par value; 200,000,000 shares authorized;

140,543,545 issued and 137,674,372 outstanding at December 31, 2016;

79,375,662 issued and 76,506,489 outstanding at December 31, 2015

 

1

 

 

 

1

 

Additional paid-in capital

 

414,580

 

 

 

403,564

 

 

539,973

 

 

 

423,499

 

Retained earnings

 

118,894

 

 

 

161,212

 

Treasury stock, at cost

 

(24,167

)

 

 

(24,167

)

Total shareholders' equity

 

509,308

 

 

 

540,610

 

Total liabilities and shareholders' equity

$

2,709,107

 

 

$

2,507,302

 

Retained earnings (deficit)

 

(1,174,844

)

 

 

(925,824

)

Treasury stock, at cost; 2,869,173 shares at December 31, 2016 and 2015

 

(24,167

)

 

 

(24,167

)

Total shareholders’ deficit

 

(659,037

)

 

 

(526,491

)

Total liabilities and shareholders’ deficit

$

829,726

 

 

$

1,208,022

 

 

 

See accompanying notes.


 

 

71


W&T OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

 

(In thousands except per share data)

 

Revenues

$

948,708

 

 

$

984,088

 

 

$

874,491

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

264,751

 

 

 

270,839

 

 

 

232,260

 

Production taxes

 

7,932

 

 

 

7,135

 

 

 

5,840

 

Gathering and transportation

 

19,821

 

 

 

17,510

 

 

 

14,878

 

Depreciation, depletion and amortization

 

490,469

 

 

 

430,611

 

 

 

336,177

 

Asset retirement obligations accretion

 

20,633

 

 

 

20,918

 

 

 

20,055

 

General and administrative expenses

 

86,999

 

 

 

81,874

 

 

 

82,017

 

Derivative (gain) loss

 

(3,965

)

 

 

8,470

 

 

 

13,954

 

Total costs and expenses

 

886,640

 

 

 

837,357

 

 

 

705,181

 

Operating income

 

62,068

 

 

 

146,731

 

 

 

169,310

 

Interest expense:

 

 

 

 

 

 

 

 

 

 

 

Incurred

 

86,922

 

 

 

85,639

 

 

 

63,268

 

Capitalized

 

(8,526

)

 

 

(10,058

)

 

 

(13,274

)

Other income, net

 

208

 

 

 

8,946

 

 

 

215

 

Income (loss)  before income tax expense (benefit)

 

(16,120

)

 

 

80,096

 

 

 

119,531

 

Income tax expense (benefit)

 

(4,459

)

 

 

28,774

 

 

 

47,547

 

Net income (loss)

$

(11,661

)

 

$

51,322

 

 

$

71,984

 

 

Basic and diluted earnings (loss) per common share

$

(0.16

)

 

$

0.68

 

 

$

0.95

 

See accompanying notes.

72


W&T OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY(In thousands except per share data)

 

 

Common Stock

 

 

Additional

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

Outstanding

 

 

Paid-In

 

 

Retained

 

 

Treasury Stock

 

 

Shareholders’

 

 

Shares

 

 

Value

 

 

Capital

 

 

Earnings

 

 

Shares

 

 

Value

 

 

Equity

 

 

(In thousands)

 

Balances at December 31, 2011

 

74,352

 

 

$

1

 

 

$

386,920

 

 

$

181,820

 

 

 

2,869

 

 

$

(24,167

)

 

$

544,574

 

Cash dividends:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock regular

   ($0.32 per share)

 

 

 

 

 

 

 

 

 

 

(23,798

)

 

 

 

 

 

 

 

 

(23,798

)

Common stock special

   ($0.79 per share)

 

 

 

 

 

 

 

 

 

 

(59,034

)

 

 

 

 

 

 

 

 

(59,034

)

Share-based compensation

 

 

 

 

 

 

 

12,398

 

 

 

 

 

 

 

 

 

 

 

 

12,398

 

Stock issued, net of forfeitures

 

898

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

RSUs surrendered for payroll

   taxes

 

 

 

 

 

 

 

(5,329

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(5,329

)

Other

 

 

 

 

 

 

 

2,197

 

 

 

(1,805

)

 

 

 

 

 

 

 

 

392

 

Net income

 

 

 

 

 

 

 

 

 

 

71,984

 

 

 

 

 

 

 

 

 

71,984

 

Balances at December 31, 2012

 

75,250

 

 

 

1

 

 

 

396,186

 

 

 

169,167

 

 

 

2,869

 

 

 

(24,167

)

 

 

541,187

 

Cash dividends:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock regular

   ($0.36 per share)

 

 

 

 

 

 

 

 

 

 

(27,098

)

 

 

 

 

 

 

 

 

(27,098

)

Common stock special

   ($0.42 per share)

 

 

 

 

 

 

 

 

 

 

(31,748

)

 

 

 

 

 

 

 

 

(31,748

)

Share-based compensation

 

 

 

 

 

 

 

11,525

 

 

 

 

 

 

 

 

 

 

 

 

11,525

 

Stock issued, net of forfeitures

 

342

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

RSUs surrendered for payroll

   taxes

 

 

 

 

 

 

 

(2,370

)

 

 

 

 

 

 

 

 

 

 

 

(2,370

)

Other

 

 

 

 

 

 

 

(1,777

)

 

 

(431

)

 

 

 

 

 

 

 

 

(2,208

)

Net income

 

 

 

 

 

 

 

 

 

 

51,322

 

 

 

 

 

 

 

 

 

51,322

 

Balances at December 31, 2013

 

75,592

 

 

 

1

 

 

 

403,564

 

 

 

161,212

 

 

 

2,869

 

 

 

(24,167

)

 

 

540,610

 

Cash dividends:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock regular

   ($0.40 per share)

 

 

 

 

 

 

 

 

 

 

(30,260

)

 

 

 

 

 

 

 

 

(30,260

)

Share-based compensation

 

 

 

 

 

 

 

14,744

 

 

 

 

 

 

 

 

 

 

 

 

14,744

 

Stock issued, net of forfeitures

 

307

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

RSUs surrendered for payroll

   taxes

 

 

 

 

 

 

 

 

 

(848

)

 

 

 

 

 

 

 

 

 

 

 

(848

)

Other

 

 

 

 

 

 

 

(2,880

)

 

 

(397

)

 

 

 

 

 

 

 

 

(3,277

)

Net income

 

 

 

 

 

 

 

 

 

 

(11,661

)

 

 

 

 

 

 

 

 

(11,661

)

Balances at December 31, 2014

 

75,899

 

 

$

1

 

 

$

414,580

 

 

$

118,894

 

 

 

2,869

 

 

$

(24,167

)

 

$

509,308

 

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

 

 

Revenues

$

399,986

 

 

$

507,265

 

 

$

948,708

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

152,399

 

 

 

192,765

 

 

 

264,751

 

Production taxes

 

1,889

 

 

 

3,002

 

 

 

7,932

 

Gathering and transportation

 

22,928

 

 

 

17,157

 

 

 

19,821

 

Depreciation, depletion and amortization

 

194,038

 

 

 

373,368

 

 

 

490,469

 

Asset retirement obligations accretion

 

17,571

 

 

 

20,703

 

 

 

20,633

 

Ceiling test write-down of oil and natural gas properties

 

279,063

 

 

 

987,238

 

 

 

 

General and administrative expenses

 

59,740

 

 

 

73,110

 

 

 

86,999

 

Derivative (gain) loss

 

2,926

 

 

 

(14,375

)

 

 

(3,965

)

Total costs and expenses

 

730,554

 

 

 

1,652,968

 

 

 

886,640

 

Operating income (loss)

 

(330,568

)

 

 

(1,145,703

)

 

 

62,068

 

Interest expense:

 

 

 

 

 

 

 

 

 

 

 

Incurred

 

92,791

 

 

 

104,592

 

 

 

86,922

 

Capitalized

 

(520

)

 

 

(7,256

)

 

 

(8,526

)

Gain on exchange of debt

 

123,923

 

 

 

 

 

 

 

Other (income) expense, net

 

(6,520

)

 

 

4,663

 

 

 

(208

)

Loss  before income tax benefit

 

(292,396

)

 

 

(1,247,702

)

 

 

(16,120

)

Income tax benefit

 

(43,376

)

 

 

(202,984

)

 

 

(4,459

)

Net loss

$

(249,020

)

 

$

(1,044,718

)

 

$

(11,661

)

 

Basic and diluted loss per common share

$

(2.60

)

 

$

(13.76

)

 

$

(0.16

)

See accompanying notes.

73


W&T Offshore, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

 

(In thousands)

 

Operating activities:

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

$

(11,661

)

 

$

51,322

 

 

$

71,984

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

511,102

 

 

 

451,529

 

 

 

356,232

 

Amortization of debt issuance costs and premium

 

701

 

 

 

1,645

 

 

 

2,575

 

Share-based compensation

 

14,744

 

 

 

11,525

 

 

 

12,398

 

Derivative (gain) loss

 

(3,965

)

 

 

8,470

 

 

 

13,954

 

Cash payments on derivative settlements, net

 

(5,318

)

 

 

(8,589

)

 

 

(7,664

)

Deferred income taxes

 

(4,760

)

 

 

30,920

 

 

 

88,109

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas receivables

 

29,510

 

 

 

980

 

 

 

818

 

Joint interest and other receivables

 

(4,255

)

 

 

34,257

 

 

 

(28,823

)

Income taxes

 

3,143

 

 

 

44,328

 

 

 

(58,011

)

Prepaid expenses and other assets

 

15,012

 

 

 

(10,044

)

 

 

7,440

 

Asset retirement obligation settlements

 

(74,313

)

 

 

(81,543

)

 

 

(112,827

)

Accounts payable, accrued liabilities and other

 

41,483

 

 

 

26,558

 

 

 

38,952

 

Net cash provided by operating activities

 

511,423

 

 

 

561,358

 

 

 

385,137

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

Acquisition of property interest in oil and natural gas properties

 

(72,234

)

 

 

(82,424

)

 

 

(205,550

)

Investment in oil and natural gas properties and equipment

 

(554,378

)

 

 

(551,954

)

 

 

(479,313

)

Proceeds from sales of assets and other, net

 

 

 

 

21,008

 

 

 

30,453

 

Purchases of furniture, fixtures and other

 

(3,340

)

 

 

(1,435

)

 

 

(3,031

)

Net cash used in investing activities

 

(629,952

)

 

 

(614,805

)

 

 

(657,441

)

Financing activities:

 

 

 

 

 

 

 

 

 

 

 

Issuance of 8.50% Senior Notes

 

 

 

 

 

 

 

318,000

 

Borrowings of long-term debt - revolving bank credit facility

 

556,000

 

 

 

563,000

 

 

 

732,000

 

Repayments of long-term debt - revolving bank credit facility

 

(399,000

)

 

 

(443,000

)

 

 

(679,000

)

Debt issuance costs

 

 

 

 

(3,892

)

 

 

(8,510

)

Dividends to shareholders

 

(30,260

)

 

 

(58,846

)

 

 

(82,832

)

Other

 

(345

)

 

 

(260

)

 

 

379

 

Net cash provided by financing activities

 

126,395

 

 

 

57,002

 

 

 

280,037

 

Increase in cash and cash equivalents

 

7,866

 

 

 

3,555

 

 

 

7,733

 

Cash and cash equivalents, beginning of period

 

15,800

 

 

 

12,245

 

 

 

4,512

 

Cash and cash equivalents, end of period

$

23,666

 

 

$

15,800

 

 

$

12,245

 

 

 

See accompanying notes.

 

 

 


W&T OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (DEFICIT)

(In thousands)

 

Common Stock

 

 

Additional

 

 

Retained

 

 

 

 

 

 

 

 

 

 

Total

 

 

Outstanding

 

 

Paid-In

 

 

Earnings

 

 

Treasury Stock

 

 

Shareholders’

 

 

Shares

 

 

Value

 

 

Capital

 

 

(Deficit)

 

 

Shares

 

 

Value

 

 

Equity (Deficit)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balances at December 31, 2013

 

75,592

 

 

$

1

 

 

$

403,564

 

 

$

161,212

 

 

 

2,869

 

 

$

(24,167

)

 

$

540,610

 

Cash dividends

 

 

 

 

 

 

 

 

 

 

(30,260

)

 

 

 

 

 

 

 

 

(30,260

)

Share-based compensation

 

 

 

 

 

 

 

14,744

 

 

 

 

 

 

 

 

 

 

 

 

14,744

 

Stock issued

 

307

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

RSUs and shares surrendered

  for payroll taxes

 

 

 

 

 

 

 

(848

)

 

 

 

 

 

 

 

 

 

 

 

(848

)

Other

 

 

 

 

 

 

 

(2,880

)

 

 

(397

)

 

 

 

 

 

 

 

 

(3,277

)

Net loss

 

 

 

 

 

 

 

 

 

 

(11,661

)

 

 

 

 

 

 

 

 

(11,661

)

Balances at December 31, 2014

 

75,899

 

 

 

1

 

 

 

414,580

 

 

 

118,894

 

 

 

2,869

 

 

 

(24,167

)

 

 

509,308

 

Share-based compensation

 

 

 

 

 

 

 

10,242

 

 

 

 

 

 

 

 

 

 

 

 

10,242

 

Stock issued

 

607

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

RSUs and shares surrendered

  for payroll taxes

 

 

 

 

 

 

 

(674

)

 

 

 

 

 

 

 

 

 

 

 

(674

)

Other

 

 

 

 

 

 

 

(649

)

 

 

 

 

 

 

 

 

 

 

 

(649

)

Net loss

 

 

 

 

 

 

 

 

 

 

(1,044,718

)

 

 

 

 

 

 

 

 

(1,044,718

)

Balances at December 31, 2015

 

76,506

 

 

 

1

 

 

 

423,499

 

 

 

(925,824

)

 

 

2,869

 

 

 

(24,167

)

 

 

(526,491

)

Share-based compensation

 

 

 

 

 

 

 

11,013

 

 

 

 

 

 

 

 

 

 

 

 

11,013

 

Stock issued

 

61,168

 

 

 

 

 

 

106,366

 

 

 

 

 

 

 

 

 

 

 

 

106,366

 

RSUs surrendered

   for payroll taxes

 

 

 

 

 

 

 

(905

)

 

 

 

 

 

 

 

 

 

 

 

(905

)

Net loss

 

 

 

 

 

 

 

 

 

 

(249,020

)

 

 

 

 

 

 

 

 

(249,020

)

Balances at December 31, 2016

 

137,674

 

 

$

1

 

 

$

539,973

 

 

$

(1,174,844

)

 

 

2,869

 

 

$

(24,167

)

 

$

(659,037

)

See accompanying notes.


W&T Offshore, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities:

 

 

 

 

 

 

 

 

 

 

 

Net loss

$

(249,020

)

 

$

(1,044,718

)

 

$

(11,661

)

Adjustments to reconcile net loss to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

211,609

 

 

 

394,071

 

 

 

511,102

 

Ceiling test write-down of oil and gas properties

 

279,063

 

 

 

987,238

 

 

 

 

Gain on exchange of debt

 

(123,923

)

 

 

 

 

 

 

Debt issuance costs write-down/amortization of debt items

 

2,548

 

 

 

4,411

 

 

 

701

 

Share-based compensation

 

11,013

 

 

 

10,242

 

 

 

14,744

 

Derivative (gain) loss

 

2,926

 

 

 

(14,375

)

 

 

(3,965

)

Cash receipts (payments) on derivative settlements, net

 

4,746

 

 

 

6,703

 

 

 

(5,318

)

Deferred income taxes

 

28,392

 

 

 

(203,272

)

 

 

(4,760

)

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas receivables

 

(7,005

)

 

 

32,236

 

 

 

29,510

 

Joint interest receivables and insurance

 

(1,126

)

 

 

21,633

 

 

 

(4,255

)

Income taxes

 

(64,274

)

 

 

(7

)

 

 

3,143

 

Prepaid expenses and other assets

 

(14,946

)

 

 

17,816

 

 

 

15,012

 

Asset retirement obligation settlements

 

(72,320

)

 

 

(32,555

)

 

 

(74,313

)

Accounts payable, accrued liabilities and other

 

6,497

 

 

 

(46,195

)

 

 

4,881

 

Net cash provided by operating activities

 

14,180

 

 

 

133,228

 

 

 

474,821

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

Acquisition of property interest in oil and natural gas properties

 

 

 

 

 

 

 

(72,234

)

Investment in oil and natural gas properties and equipment

 

(48,606

)

 

 

(230,161

)

 

 

(554,378

)

Changes in operating assets and liabilities associated with investing activities

 

(35,194

)

 

 

(55,425

)

 

 

37,450

 

Net proceeds from sales of assets

 

1,500

 

 

 

372,939

 

 

 

 

Purchases of furniture, fixtures and other

 

(96

)

 

 

(1,278

)

 

 

(3,340

)

Net cash provided by (used in) investing activities

 

(82,396

)

 

 

86,075

 

 

 

(592,502

)

Financing activities:

 

 

 

 

 

 

 

 

 

 

 

Borrowings of long-term debt - revolving bank credit facility

 

340,000

 

 

 

263,000

 

 

 

556,000

 

Repayments of long-term debt - revolving bank credit facility

 

(340,000

)

 

 

(710,000

)

 

 

(399,000

)

Issuance of 1.5 Lien Term Loan

 

75,000

 

 

 

 

 

 

 

Issuance of Second Lien Term Loan

 

 

 

 

297,000

 

 

 

 

Payment of interest on 1.5 Lien Term Loan

 

(2,570

)

 

 

 

 

 

 

Debt exchange/issuance costs

 

(18,464

)

 

 

(6,669

)

 

 

 

Dividends to shareholders

 

 

 

 

 

 

 

(30,260

)

Other

 

(928

)

 

 

(886

)

 

 

(1,193

)

Net cash provided by (used in) financing activities

 

53,038

 

 

 

(157,555

)

 

 

125,547

 

Increase (decrease) in cash and cash equivalents

 

(15,178

)

 

 

61,748

 

 

 

7,866

 

Cash and cash equivalents, beginning of period

 

85,414

 

 

 

23,666

 

 

 

15,800

 

Cash and cash equivalents, end of period

$

70,236

 

 

$

85,414

 

 

$

23,666

 

See accompanying notes.


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1. Significant Accounting Policies

Operations

W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,”, “us,” “our,” or the “Company”, is an independent oil and natural gas producer focused primarily in the Gulf of Mexico andMexico.  On October 15, 2015, a substantial amount of our interest in onshore Texas.  The Companyacreage was sold, which is described in Note 7.  We are active in the exploration, development and acquisition of oil and natural gas properties.  Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our wholly-ownwholly-owned subsidiary, W & T Energy VI, LLC (“Energy VI”).  

Basis of Presentation

Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries.  All significant intercompany transactions and amounts have been eliminated for all years presented.

Reclassifications

Certain reclassifications  Our consolidated financial statements have been made to prior periods’ financial statements to conform toprepared in accordance with United States generally accepted accounting principles (“GAAP”) and the current presentation as follows:   Income tax – receivables was combined with Joint interestappropriate rules and other – receivables onregulations of the Consolidated Balance Sheets.  Loss on extinguishment of debt was combined with Other income, net on the Consolidated Statements of Operations.  Insurance proceeds was combined with the changes in Joint interestSecurities and other receivables and changes in Other – operating assets and liabilities was combined with the changes in Accounts payable, accrued liabilities and other on the Consolidated Statements of Cash Flows.Exchange Commission (���SEC”).

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”)GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves.  Actual results could differ from those estimates.

Early Adoption of Accounting Standard Amendments

Accounting Standards Update No. 2016-09 (“ASU 2016-09”), Compensation – Stock Compensation (Subtopic 718) was early adopted as of December 31, 2016.  The amendment’s objective is simplification of several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the Consolidated Statements of Cash Flows.  The early adoption affected the statements of cash flows as to the classification of cash paid for employee income taxes and payroll taxes, which were funded through the forfeiture of vested restricted stock units (“RSUs”).  Previously, these cash payments were classified as operating activities.  The updated standard requires such cash transactions be classified as financing activities. The reclassification was applied retrospectively on the statements of cash flows for the years 2014 and 2015 and resulted in reclassification of $0.8 million and $0.7 million, respectively.  None of the other amendments under ASU 2016-09 had an effect on our financial statements and the early adoption of ASU 2016-09 did not affect the Consolidated Balance Sheets, Consolidated Statements of Operations or the Consolidated Statements of Changes in Shareholders’ Equity (Deficit).  

90


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Recent Events

The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital and future rate of growth.  The prices of these commodities began falling in Junethe second half of 2014, and were significantly lower during 2015 and lower still in January and February of 20152016 compared to the last fewprior years.  

We have taken severaltook a number of  steps during 2015 and 2016 to mitigate the effects of these lower prices including: (i) significantly reducing the 2015 capital budgetspending from the previous year;year levels and budgeting conservative capital spending for 2017 (exclusive of acquisitions); (ii) restructuring our debt and issuing our common stock through an exchange transaction, which is described in Note 2, (iii) receiving funds through two debt issuances, which are described in Note 2 (iv) suspending our drilling and completion activities at several locations; (iii) suspending the regular quarterly common stock dividend anddividend; (iv) implementing numerous cost reduction projects to reduce our operating costs.  costs; and (v) selling our interest in the Yellow Rose onshore field, which is described in Note 7.

Assuming continuing oilDuring 2016, the Bureau of Ocean Energy Management (“BOEM”) issued orders to us concerning financial assurances related to plug and gas prices are near levels realizedabandonment (decommissioning) obligations for Federal offshore leases, including an order issued to us in December 20142016 regarding additional security required for sole liability properties.  In July 2016, effective September 2016, the BOEM issued Notice to Lessees #2016-N01 (“NTL #2016-N01”), related to obligations for decommissioning activities on the Outer Continental Shelf (“OCS”) for leases, rights-of-way (“ROWs”) or rights of use and easement (“RUEs”).  In January 2015, we likely will be out2017, the BOEM extended the implementation timeline by an additional six months of complianceNTL #2016-N01 as to leases, ROWs and RUEs for which there are co-lessees and/or predecessors in interest (non-sole liability properties), with certain of ourexceptions.  In February 2017, the BOEM withdrew the sole liability orders it had issued in December 2016 to allow time for the new President’s administration to review the complex financial ratio maintenance covenants under our Credit Agreement sometime during 2015.  We intend to engage the lenders under the Credit Agreement in discussions regarding amending our financial ratio covenants at such time as our borrowing base is redetermined in April 2015, but we can provide no assurance that we will be successful in obtaining such an amendment.  While we believe we will obtain the appropriate covenant relief, if we are unable to obtain such an amendment from our lenders, we believe that we can find alternative financing,program.  See Note 17 and we may have to reduce our cash outlays further19 for capital expenditures and other activities until such time as market conditions recover.additional information.      

We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations through December 31, 2015;for at least 12 months from the date of issuance of this Form 10-K, which is the threshold of a going concern under GAAP; however, we cannot predict how an extended period of lowwith any certainty future commodity prices willor the actions of the BOEM concerning financial assurance requirements, either of which could affect our operations and liquidity levels.

75


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Adjustment Related to Additional Volumes

In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtu”) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe).  The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011.  The effect of using this incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense.  We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in 2013.  The 2013 period reflects a one-time increase in natural gas production volumes of 1.9 billion cubic feet (“Bcf”) (with no corresponding increase in revenue) for the annual periods of 2011 and 2012, which increased depreciation, depletion, amortization and accretion (“DD&A”) by $5.0 million and decreased net income by $3.2 million.  

Cash Equivalents

We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents.

Revenue Recognition

We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured.  We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership.  Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production.  These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production.  We do not record receivables for those properties in which the Company haswe have taken less than itsour ownership share of production.  At both December 31, 20142016 and 2013, $6.42015, $5.3 million wasand $6.9 million, respectively, were included in current liabilities related to natural gas imbalances.

91


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Concentration of Credit Risk

Our customers are primarily large integrated oil and natural gas companies and large financial institutions.  OurThe majority of our production is sold utilizing month-to-month contracts that are based on bid prices.  We also have receivables from joint interest owners on properties we operate and we may have the ability to withhold future revenue disbursements to recover amounts due us.  We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guaranties when considered necessary.  We historically have not had any significant problems collecting our receivables, exceptbut with the decline in rare circumstances.  Accordingly, we do not maintaincommodity prices, several oil and gas companies have filed for bankruptcy, including some of our joint interest partners.  We use the specific identification method of determining if an allowance for doubtful accounts is needed.  As of any material amounts.December 31, 2016 and 2015, $7.6 million and $2.5 million, respectively, were recorded as an allowance for doubtful accounts.  During 2016 and 2015, there were no reductions recorded in the allowance for doubtful accounts (no collections of accounts previously reserved and no permanent write-off of receivable accounts).  

The following identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas.

Year Ended December 31,

 

Year Ended December 31,

 

2014

 

 

2013

 

 

2012

 

2016

 

 

2015

 

 

2014

 

Customer

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Shell Trading (US) Co.

 

47

%

 

 

48

%

 

 

35

%

 

43

%

 

 

50

%

 

 

47

%

ConocoPhillips (1)

**

 

 

**

 

 

 

16

%

Vitol Inc.

 

20

%

 

**

 

 

**

 

J. P. Morgan

**

 

 

 

14

%

 

**

 

**

less** Less than 10%

(1)

ConocoPhillips split into two separate companies during 2012 and individually were approximately 8% each.

We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing.

76


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Insurance Receivables

We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance underwriters’company’s adjuster reviews and approves such costs for payment byor when the underwriters.insurance company has agreed to reimbursement amounts.  Claims that have been processed in this manner have customarily been paid on a timely basis.  See Note 185, 17 and 19 for information related to settlement of previously unpaid claims by certain underwriters.insurance companies.

Prepaid expenses and other

Amounts recorded in Prepaid expenses and other on the Consolidated Balance Sheets are expected to be realized within one year.  Items representing 5% or more of total current assets in either period presented are disclosed in the following table:  

92


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Year Ended December 31,

 

 

2016

 

 

2015

 

Derivative assets - current (1)

$

 

 

$

10,036

 

Prepaid/accrued  insurance and surety bonds

 

5,386

 

 

 

7,475

 

Prepaid deposits related to royalties

 

6,237

 

 

 

5,943

 

Other (2)

 

2,881

 

 

 

3,425

 

Prepaid expenses and other

$

14,504

 

 

$

26,879

 

(1)

Includes open and closed (and not yet collected) derivative commodity contracts recorded at fair value as of December 31, 2015.

(2)

Individual items were less than 5% of total current assets for either period presented.

Properties and Equipment

We use the full-cost method of accounting for oil and natural gas properties and equipment.  Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized.  Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties.  Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs.  Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines.  Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred.

Oil and natural gas properties and equipment include costs of unproved properties.  The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as the Company haswe have made an evaluation that impairment has occurred.  The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial.

We capitalize interest on the amount of unproved properties that are excluded from the amortization base.  Interest is capitalized only for the period that exploration and development activities are in progress.  Capitalization of interest ceases when the property is moved into the amortization base.  All capitalized interest is recorded within Oil and natural gas property and equipment on the Consolidated Balance Sheets.

Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities.  In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves.  Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense.

Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years.  Leasehold improvements are amortized over the shorter of their economic lives or the lease term.  Repairs and maintenance costs are expensed in the period incurred.

93


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Ceiling Test Write-Down

Under the full costfull-cost method of accounting, we are required to periodically perform a “ceiling test,”test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties.  If the net capitalized cost of oil and natural gas properties (including capitalized ARO), net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed.  Any such write downs are not recoverable or reversible in future periods.  The ceiling test limit is comprised of:calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects.  Estimated future net revenues used in the ceiling test for each yearperiod are based on current prices for each product, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the period January through Decemberprior twelve months for that year.period.  All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials.

77


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DeclinesDue primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas, we recorded ceiling test write-downs in 2015 and 2016, which are reported as a separate line in the Statements of Operations.  The average price using the SEC required methodology at December 31, 2016 was $39.25 per barrel for West Texas Intermediate (“WTI”) crude oil and $2.48 per million British Thermal Unit  (“MMBtu”) for Henry Hub natural gas.  These prices are before adjustments for quality, transportation, fees, energy content and regional price differentials.   The ceiling test write-downs of the carrying value of our oil and natural gas properties were $279.1 million and $987.2 million for 2016 and 2015, respectively.  There was no ceiling test write-down in the fourth quarter of 2016.  We did not record a ceiling test write-down during 2014.  If average crude oil and natural gas prices after December 31, 2014 may require us to record ceiling-test impairments in the future.  We did not have any write-downs related to ceiling-test impairmentsdecrease from 2016 levels, it is possible that a ceiling test write-down will be recorded during 2014, 2013 and 2012, respectively.

Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years.  Leasehold improvements are amortized over the shorter of their economic lives or the lease term.  Repairs and maintenance costs are expensed in the period incurred.2017.  

Asset Retirement Obligations

Pursuant to GAAP, weWe are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet.  We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations.  These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup.  Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal.  Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period.  For additional information, refer to Note 5.4.

Oil and Natural Gas Reserve Information

Pursuant to GAAP, weWe use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves.  Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices.  Another provision of the guidance is a general requirement that, subject to limited exceptions, provedProved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.years, with some limited exceptions allowed.  Refer to Note 21 for additional information about our proved reserves.

Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and interest rates.  From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our credit facility.  OurAs of December 31, 2016, we did not have any open derivative instruments currently consist of commodity swap contracts for oil.financial instruments.  We do not enter into derivative instruments for speculative trading purposes.

In accordance with GAAP, a derivative is94


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Derivative instruments are recorded on the balance sheet as an asset or a liability at its fair value.  Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into.  WeWhenever we have electedentered into derivative contracts, we did not to designate our commodity derivatives as hedging instruments, therefore, all changes in fair value are recognized in earnings.

Fair Value of Financial Instruments

We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance.  We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments.  We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments.  We believe the carrying amount of debt under our revolving bank credit facility11.00% 1.5 Lien Term Loan, due November 2019, (the “1.5 Lien Term Loan”) approximates fair value because the interest rates are variabledebt was recently executed and reflective of market rates.

78


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

rates and conditions.

Fair Value of Acquisitions

Acquisitions are recorded on the closing date of the transaction at their fair value, which is determined by applying the market and income approaches using Level 3 inputs.  The Level 3 inputs are: (i) analysis of comparable transactions obtained from various third-parties, (ii) estimates of ultimate recoveries of reserves, and (iii) estimates of discounted cash flows based on estimated reserve quantities, reserve categories, timing of production, costs to produce and develop reserves, future prices, ARO and discount rates.  The estimates and assumptions are determined by management and third-parties.  The fair value is based on subjective estimates and assumptions, which are inherently imprecise, and the actual realized values can vary significantly from estimates that are made.  No goodwill was recorded for the acquisitions completed in 2014, 2013 or 2012.

Income Taxes

We use the liability method of accounting for income taxes in accordance with the Income Taxes topic of the Accounting Standard Codification.  Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements.  In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.  We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken.  When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense.  See Note 12 for additional information.

Troubled Debt Restructuring  

We accounted for an exchange transaction, which is described in Note 2, as a troubled debt restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”).  Under ASC 470-60, the carrying value of the newly issued debt, as described in Note 2, is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the newly issued debt in the Consolidated Statements of Operations for the period from September 7, 2016 to December 31, 2016.  Additionally, no interest expense related to the newly issued debt will be recorded in future periods as payments of interest on the newly issued debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the newly issued debt.  See Note 2 for additional information.    

95


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Debt Issuance Costs

Debt issuance costs associated with our revolving loanbank credit facility are amortized using the straight-line method over the scheduled maturity of the debt.  Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method.  Unamortized debt issuance costs associated with our revolving bank credit facility is reported within Other Assets (noncurrent) and unamortized debt issuance costs associated with our other debt is reported as a reduction in Long-Term Debt, less current maturities in the Consolidated Balance Sheets.  See Note 2 for additional information.  

Premiums Received and Discounts Provided on Debt Issuance

Premiums and discounts are recorded in long-term liabilitiesLong-Term Debt, less current maturities in the Consolidated Balance Sheets and are amortized over the term of the related debt using the effective interest method.

Share-Based Compensation

In accordance with GAAP, compensationCompensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award.  The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant.  The fair value of equity instruments subject to market-based performance measurements was determined using a Monte Carlo simulation probabilistic model.  We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award.  Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests.  See Note 1110 for moreadditional information.

EarningsLoss Per Share

In accordance with GAAP, unvestedUnvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earningsloss per share under the two-class method.method when the effect is dilutive.  For additional information, refer to Note 14.13.

Other Income,(Income) Expense, Net

For 2013,2016, the amount reported consisted primarilyincludes $7.7 million of $9.2income related to the settlement of certain insurance claims.  In 2016 and 2015, the amount includes write-offs of debt issuance costs of $1.4 million receivedand $3.2 million, respectively, related to a reduction in conjunction with a payment forthe borrowing base of the revolving bank credit facility under the Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”).  The write-offs of debt issuance costs in both 2016 and 2015 are included as an option exercisedadjustment to net income in determining Net cash provided by a counterparty.  Partially offsetting the proceeds were related third-party expenses of $0.1 million.  The net amount was included in net cash flows from investingoperating activities within the line, Proceeds from sales of assets and other, net in the consolidated statementsConsolidated Statements of cash flows.

79


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Cash Flows as the write-offs were non-cash transactions.  

Recent Accounting Developments

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Topic(Subtopic 606).  ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance.  The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016.2017.  Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application.  Our current intention is to adopt the standard utilizing the modified retrospective approach.  Our evaluation to date is the adoption of ASU 2014-09 is not expected to have a material impact on our consolidated financial statements.  We have not determinedfully completed our analysis and subsequent guidance may change this assessment.  Our disclosures related to revenue will be modified when the effectnew guidance is effective.  ASU 2014-09 will have on the recognition of our revenue, if any, nor have we determined the method we will utilize upon adoption, which would be effective for us in the first quarter of 2017.2018.

In August 2014, the FASB issued Accounting Standards Update No. 2014-15 (“ASU 2014-15”), Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40).  The guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures.  ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter.  We do not expect the revised guidance to materially affect our evaluation as to being a going concern, or have an effect on our financial statements or related disclosures.

2. Acquisitions and Divestitures

2014 Acquisitions

Fairway

On September 15, 2014, the Parent Company entered into an asset purchase agreement with a third party to increase its ownership interest from 64.3% to 100% in the Mobile Bay blocks 113 and 132 located offshore Alabama (the “Fairway Field”) and the associated Yellowhammer gas processing plant (collectively, “Fairway”).  The Fairway Field is located in the state waters of Alabama and the Yellowhammer gas processing plant is located in the state of Alabama.  The effective date of the transaction was July 1, 2014.  The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO.  The purchase price was finalized during the fourth quarter of 2014.  The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

The following table presents the preliminary purchase price allocation, including estimated adjustments, for the increased ownership interest in Fairway (in thousands):  

Cash consideration:

 

 

 

Evaluated properties including equipment

$

17,407

 

Non-cash consideration:

 

 

 

Asset retirement obligations - non-current

 

6,124

 

Total consideration

$

23,531

 

The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value.  See Note 1 for a description of the Level 3 inputs.  No goodwill was recorded in connection with the acquisition of this additional working interest in Fairway.

Woodside Properties  

On May 20, 2014, Energy VI entered into a purchase and sale agreement to acquire certain oil and natural gas property interests from Woodside Energy (USA) Inc. (“Woodside”).  The properties acquired from Woodside (the “Woodside Properties”) consisted of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks.  All of the Woodside Properties are located in the Gulf of Mexico.  The effective date of the transaction was November 1, 2013.  The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO.  The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

8096


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

The following table presentsIn February 2016, the purchase price allocation, including estimated adjustments,FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases (Subtopic 842).  Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Consistent with current GAAP, the acquisitionrecognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease.  However, unlike current GAAP, which requires only capital leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet.  ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases.  These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements.  ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources.  Our current operating leases that will be impacted by ASU 2016-02 when it is effective are leases for office space in Houston and New Orleans, although ASU 2016-02 may impact the accounting for leases related to operations equipment depending on the term of the Woodside Properties (in thousands):  

Cash consideration:

 

 

 

Evaluated properties including equipment

$

52,167

 

Unevaluated properties

 

2,660

 

Sub-total cash consideration

 

54,827

 

Non-cash consideration:

 

 

 

Asset retirement obligations - current

 

782

 

Asset retirement obligations - non-current

 

10,543

 

Sub-total non-cash consideration

 

11,325

 

Total consideration

$

66,152

 

The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value.  See Note 1lease.  We currently do not have any leases classified as financing leases.  ASU 2016-02 is effective for a description of the Level 3 inputs.  No goodwill was recorded in connection with the Woodside Properties acquisition.

2014 Acquisitions — Revenues, Net Income and Pro Forma Financial Information - Unaudited  

The increase in working interest ownership for Fairway was not included in our consolidated results until the property transfer date, which occurred in September 2014 and the incremental revenue and operating expenses were immaterial for 2014.  Unaudited pro forma information is not presented as the pro forma information is not materially different from the reported results for 2014 and 2013.  

The Woodside Properties were not included in our consolidated results until the property transfer date, which occurred on May 20 2014.  For the period of May 20, 2014 to December 31, 2014, the Woodside Properties accounted for $28.4 million of revenues, $5.5 million of direct operating expenses, $11.0 million of DD&A and $4.2 million of income taxes, resulting in $7.7 million of net income.  The net income attributable to the Woodside Properties does not reflect certain expenses, such as general and administrative expenses (“G&A”) and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis.  In addition, the Woodside Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate.    

In accordance with the applicable accounting guidance, the unaudited pro forma financial information was computed as if the acquisition of the Woodside Properties had been completed on January 1, 2013.  The financial information was derived from W&T’s audited historical consolidated financial statements for annual periods, W&T’s unaudited historical condensed consolidated financial statements for interim periods, and the Woodside Properties’ unaudited historical financial statements for the annual and interim periods.

The pro forma adjustments were based on estimates by managementperiods beginning after December 15, 2018 and information believedis to be directly relatedapplied using the modified retrospective approach.  We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.  

In June 2016, the FASB issued Accounting Standards Update No. 2016-13, (“ASU 2016-13”), Financial Instruments – Credit Losses (Subtopic 326).  The new guidance eliminates the probable recognition threshold and broadens the information to consider past events, current conditions and forecasted information in estimating credit losses.  ASU 2016-13 is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted for fiscal years beginning after December 15, 2018.  We have not yet fully determined or quantified the purchaseeffect ASU 2016-13 will have on our financial statements.

In August 2016, the FASB issued Accounting Standards Update No. 2016-15, (“ASU 2016-15”), Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments.  ASU 2016-15 addresses the classification of several items that previously had diversity in practice.  Items identified in the new standard which were incurred by us in the past are: (a) debt prepayment or extinguishment costs; (b) contingent consideration made after a business acquisition; and (c) proceeds from settlement of insurance claims.  The item described in clause (b) would be the only such item changed under our historical classification in the Statement of Cash Flows (financing vs. investing) and the amount of such change would not be material; therefore, we do not anticipate the new standard will have a material effect on our Statement of Cash Flows.  ASU 2016-15 is effective for fiscal years beginning after December 15, 2017 and early adoption is permitted.  

In November 2016, the FASB issued Accounting Standards Update No. 2016-18, (“ASU 2016-18”), Statement of Cash Flows (Topic 230) – Restricted Cash.  ASU 2016-18 addresses diversity in practice and requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.  ASU 2016-18 is expected to change some of the Woodside Properties.  The pro forma financial informationpresentation in our statement of cash flows, but not materially impact total cash flows from operating, investing or financing activities.  ASU 2016-18 is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2013.  Had we owned the Woodside Properties during theeffective for fiscal years beginning after December 15, 2017 and interim periods indicated, the results may have been substantially different.  For example, we may have operated the assets differently than Woodside; the realized sales prices for oil, natural gas liquids (“NGLs”) and natural gas may have been different; and the costs of operating the Woodside Properties may have been different.within those fiscal years.  Early adoption is permitted, including adoption in an interim period.

The following table presents a summary of our pro forma financial information (in thousands, except earnings per share):

 

 

(unaudited)

 

 

 

Year Ended December 31,

 

 

 

2014

 

 

2013

 

Revenue

 

$

971,595

 

 

$

1,047,037

 

Net income (loss)

 

 

(5,495

)

 

 

71,432

 

Basic and diluted earnings (loss) per common share

 

 

(0.08

)

 

 

0.94

 

 

8197


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

2. Long-Term Debt

For the pro forma financial information, certain informationAs of December 31, 2016 and 2015, our long-term debt was derived from our financial records, Woodside’s financial records and certain information was estimated.  

The following table presents incremental items included in the pro forma information reported above for the Woodside Propertiesas follows (in thousands):

 

 

(unaudited)

 

 

 

Year Ended December 31,

 

 

 

2014 (a)

 

 

2013

 

Revenues (b)

 

$

22,887

 

 

$

62,949

 

Direct operating expenses (b)

 

 

4,417

 

 

 

9,583

 

DD&A (c)

 

 

8,374

 

 

 

20,476

 

G&A (d)

 

 

300

 

 

 

800

 

Interest expense (e)

 

 

329

 

 

 

987

 

Capitalized interest (f)

 

 

(19

)

 

 

164

 

Income tax expense (g)

 

 

3,320

 

 

 

10,829

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

December 31, 2016

 

 

2015

 

 

 

 

 

 

PIK Payable/

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Payable/

 

 

Carrying

 

 

Principal/

 

 

Principal

 

 

Other

 

 

Value

 

 

Other*

 

11.00% 1.5 Lien Term Loan,

     due November 2019

$

75,000

 

 

$

23,823

 

 

$

98,823

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9.00 % Second Lien Term Loan,

    due May 2020

 

300,000

 

 

 

 

 

 

300,000

 

 

 

300,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9.00%/10.75% Second Lien PIK Toggle Notes,

    due May 2020

 

163,007

 

 

 

60,898

 

 

 

223,905

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8.50%/10.00% Third Lien PIK Toggle Notes,

   due June 2021

 

145,897

 

 

 

67,549

 

 

 

213,446

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8.50% Unsecured Senior Notes,

    due June 2019

 

189,829

 

 

 

 

 

 

189,829

 

 

 

900,000

 

Subtotal

 

873,733

 

 

 

152,270

 

 

 

1,026,003

 

 

 

1,200,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt premium, discount, issuance costs,

     net of amortization

 

 

 

 

(5,276

)

 

 

(5,276

)

 

 

(3,145

)

Total long-term debt

 

873,733

 

 

 

146,994

 

 

 

1,020,727

 

 

 

1,196,855

 

Current maturities of long-term debt

 

 

 

 

8,272

 

 

 

8,272

 

 

 

 

Long term debt, less current maturities

$

873,733

 

 

$

138,722

 

 

$

1,012,455

 

 

$

1,196,855

 

 

The sources* Amounts also equal carrying value

Aggregate annual maturities of information and significant assumptionsamounts recorded for long-term debt as of December 31, 2016 are described below:as follows (in millions): 2017–$8.2; 2018–$23.8; 2019–$303.7; 2020–$510.1; thereafter–$180.1.  See below for discussion on the determination of recorded amounts.    

(a)

The adjustments for 2014 are for the period from January 1, 2014 to May 20, 2014.

(b)

Revenues and direct operating expenses for the Woodside Properties were derived from the historical financial records of Woodside.

(c)

DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Woodside Properties’ costs, reserves and production into our full cost pool in order to compute such amounts.  The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation.  ARO was estimated by W&T management.

(d)

Estimated insurance costs related to the Woodside Properties.

(e)

The acquisition was assumed to be funded entirely with borrowed funds.  Interest expense was computed using assumed borrowings of $54.8 million, which equates to the cash component of the acquisition purchase price, and an interest rate of 1.8%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility.

(f)

The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings.  The negative amount represents a decrease to net expenses.

(g)

Income tax expense was computed using the 35% federal statutory rate.

The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures.

2013 Acquisition

On October 17, 2013, W&T Offshore, Inc. entered into a purchase and sale agreement to acquire certain oil and natural gas property interests from Callon Petroleum Operating Company (“Callon”).  Pursuant to the purchase and sale agreement, transfers of certain properties that had no preferential rights were consummated on November 5, 2013 and transfers of certain properties subject to preferential rights, of which third-parties declined to exercise their preferential rights, were consummated on December 4, 2013.  The properties acquired from Callon (the “Callon Properties”) consist of a 15% working interest in the Medusa field (deepwater Mississippi Canyon blocks 582 and 583), interest in associated production facilities and various interests in other non-operated fields.  All of the Callon Properties are located in the Gulf of Mexico.  The effective date of the transaction was July 1, 2013.  The transaction included customary adjustments for the effective date, certain closing adjustments and we assumed the related ARO.  An upward net purchase price adjustment of $0.6 million was recorded during 2014.  The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

8298


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

The following table presents the purchase price allocation, including estimated adjustments, for the acquisition of the Callon Properties (in thousands):

Cash consideration:

 

 

 

Evaluated properties including equipment

$

73,752

 

Unevaluated properties

 

9,248

 

Sub-total cash consideration

 

83,000

 

Non-cash consideration:

 

 

 

Asset retirement obligations - current

 

90

 

Asset retirement obligations - non-current

 

4,143

 

Sub-total non-cash consideration

 

4,233

 

Total consideration

$

87,233

 

The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value.  See Note 1 for a description of the Level 3 inputs.  No goodwill was recorded in connection with the acquisition of the Callon Properties.

2013 Acquisition — Revenues, Net Income and Pro Forma Financial Information — Unaudited

The Callon Properties were not included in our consolidated results until the respective property transfer dates, which occurred during the fourth quarter of 2013.  In 2014, the Callon Properties accounted for $32.5 million of revenue, $6.6 million of direct operating expenses, $16.4 million of DD&A and $3.3 million of income taxes, resulting in $6.2 million of net income.  In the fourth quarter of 2013, the Callon Properties accounted for $5.8 million of revenues, $1.3 million of direct operating expenses, $2.4 million of DD&A and $0.7 million of income taxes, resulting in $1.4 million of net income.  The net income attributable to these properties does not reflect certain expenses, such as G&A and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis.  In addition, the Callon Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate.

The unaudited pro forma financial information presented below was computed as if the acquisition of the Callon Properties had been completed on January 1, 2012.  The financial information was derived from W&T’s audited historical consolidated financial statements, the Callon Properties’ audited historical financial statement, and the Callon Properties’ unaudited historical financial statement for the periods presented.

The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Callon Properties.  The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2012.  If the transaction had been in effect for the periods indicated, the results may have been substantially different.  For example, we may have operated the assets differently than Callon; the realized sales prices for oil, NGLs and natural gas may have been different; and the costs of operating the Callon Properties may have been different.    

The following table presents a summary of our pro forma financial information (in thousands except earnings per share):

 

(unaudited)

 

 

Year Ended December 31,

 

 

2013

 

 

2012

 

Revenue

$

1,018,118

 

 

$

923,050

 

Net income

 

59,015

 

 

 

85,310

 

Basic and diluted earnings per common share

 

0.78

 

 

 

1.12

 

83


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the pro forma financial information, certain information was derived from financial records and certain information was estimated.  The following table presents incremental items included in the pro forma information reported above for the Callon Properties (in thousands):

 

(unaudited)

 

 

Year Ended December 31,

 

 

2013 (a)

 

 

2012

 

Revenues (b)

$

34,030

 

 

$

48,559

 

Direct operating expenses (b)

 

6,405

 

 

 

8,525

 

DD&A (c)

 

14,931

 

 

 

17,578

 

G&A (d)

 

(361

)

 

 

 

Interest expense (e)

 

1,383

 

 

 

1,660

 

Capitalized interest (f)

 

(164

)

 

 

295

 

Income tax expense (g)

 

4,143

 

 

 

7,175

 

The sources of information and significant assumptions are described below:

(a)

The adjustments for 2013 are for the period from January 1, 2013 to the respective property transfer date, all of which occurred in the fourth quarter of 2013.

(b)Exchange Transaction

Revenues and direct operating expenses for the Callon Properties were derived from the historical financial records of Callon.

(c)

DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Callon Properties’ costs, reserves and production into our currently existing full cost pool in order to compute such amounts.  The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation.  ARO was estimated by W&T management.

(d)

G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from the 2013 results.

(e)

The acquisition was assumed to be funded entirely with borrowed funds.  Interest expense was computed using assumed borrowings of $83.0 million, which equates to the cash component of the transaction, and an interest rate of 2.0%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility.

(f)

The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings.  A positive amount represents an increase to net expenses and a negative amount represents a decrease to net expenses.

(g)

Income tax expense was computed using the 35% federal statutory rate.

The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures.

2013 Divestitures

On July 11, 2013, we sold our non-operated working interest in two offshore fields located in the Gulf of Mexico; the Green Canyon 60 field and the Green Canyon 19 field.  The effective date was October 1, 2011 and we retained the deep rights in both fields.  Due to the length of time from the effective date, we paid $4.3 million to sell the properties as revenues exceeded operating expenses and the purchase price for the period between the effective date and the close date.  In connection with the sale, we reversed $15.6 million of our ARO.

On September 26, 2013,7, 2016, we soldconsummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our working interests8.500% Senior Notes (the “Unsecured Senior Notes”), due June 15, 2019, for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Senior Second Lien PIK Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); (ii) $142.0 million in aggregate principal amount of 8.50%/10.00% Senior Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”); and (iii) 60.4 million shares of our common stock (collectively, the West Delta area block 29“Debt Exchange”).  At the same time on closing on the Debt Exchange, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 2019, with an effective datethe then largest holder of January 1, 2013.  The property is located inour Unsecured Senior Notes (collectively with the Gulf of Mexico.  Including adjustmentsDebt Exchange, the “Exchange Transaction”).  We accounted for the effective date, the net proceeds were $14.7 million, which includes a $1.7 million post-effective-date repayment that occurred during 2014.  The transaction was structuredExchange Transaction as a like-kind exchangeTroubled Debt Restructuring pursuant to the guidance under ASC 470-60.  Under ASC 470-60, the Internal Revenue Service Code (“IRC”) Section 1031 and other applicable regulations, with funds held by a qualified intermediary until replacement purchases are made.  Replacement purchases were made in 2013, which were within the replacement periods as defined under the IRC.  In connection with this sale, we reversed $3.9 million of ARO.

84


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2012 Acquisitions

On October 5, 2012, we acquired from Newfield Exploration Company and its subsidiary, Newfield Exploration Gulf Coast LLC (together, “Newfield”) certain oil and gas leasehold interests in the Gulf of Mexico (the “Newfield Properties”).  The Newfield Properties consist of leases covering 78 offshore blocks on approximately 416,000 gross acres (268,000 net acres) predominantly in the deepwater.  The effective date was July 1, 2012.  The transaction included customary adjustments for the effective date, certain closing adjustments and we assumed the related ARO.  The consideration and the purchase price allocation are set forth in the table below.  The purchase price was finalized during 2013.  A net purchase price increase of $0.2 million was recorded during 2013.  The acquisition was initially funded from borrowings under our revolving bank credit facility and cash on hand.  Subsequently in the same month, the amounts borrowed under our revolving bank credit facility were paid down with funds provided from the issuance of long-term debt in October 2012.  See Note 7 for information on long-term debt.

The following table presents the purchase price allocation, including adjustments, for the acquisitioncarrying value of the Newfield Properties (in thousands):

Cash consideration:

 

 

 

Evaluated properties including equipment

$

192,723

 

Unevaluated properties

 

13,065

 

Sub-total cash consideration

 

205,788

 

Non-cash consideration:

 

 

 

Asset retirement obligations – current

 

7,250

 

Asset retirement obligations - non-current

 

24,414

 

Sub-total non-cash consideration

 

31,664

 

Total consideration

$

237,452

 

The acquisition was recorded at fair value, which was determinednewly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) is measured using both the marketall future undiscounted payments (principal and income approaches, and Level 3 inputs were used to determine fair value.  See Note 1 for a description of the Level 3 inputs.  No goodwillinterest); therefore, no interest expense was recorded for the Newfield Properties.

2012 Acquisitions — Revenue, Net Income and Pro Forma Financial Information — Unaudited

The Newfield Properties were not included in our consolidated results until the closing date of October 5, 2012.  In 2014, the Newfield Properties accounted for $121.1 million of revenue, $23.5 million of direct operating expenses, $60.5 million of DD&A and $13.0 million of income taxes, resulting in $24.1 million of net income.  In 2013, the Newfield Properties accounted for $127.1 million of revenue, $26.7 million of direct operating expenses, $57.6 million of DD&A and $15.0 million of income taxes, resulting in $27.8 million of net income.  In the fourth quarter of 2012, the Newfield Properties accounted for $29.6 million of revenue, $5.4 million of direct operating expenses, $11.9 million of DD&A and $4.3 million of income taxes, resulting in $8.0 million of net income.  The net income attributable to these properties does not reflect certain expenses, such as G&A expense and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis.  In addition, the Newfield Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate.

Consistent with the computation of pro forma financial information presented in Item 8, Financial Statements and Supplementary Data, in the Annual Report on Form 10-K for the year end December 31, 2012, the unaudited pro forma financial information was computed as if the acquisition of the Newfield Properties had been completed on January 1, 2011.  The financial information was derived from W&T’s audited historical consolidated financial statements, the Newfield Properties’ audited historical financial statement for 2011 and the Newfield Properties’ unaudited historical financial statements for the 2012 interim period.

The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Newfield Properties.  The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2011.  If the transaction had been in effect for the periods indicated, the results may have been substantially different.  For example, we may have operated the assets differently than Newfield; the realized sales prices for oil, NGLs and natural gas may have been different; and the costs of operating the Newfield Properties may have been different.

85


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table presents a summary of our pro forma financial information (in thousands except earnings per share):

 

 

(unaudited)

 

 

 

Year Ended

December 31, 2012

 

Revenue

 

$

980,196

 

Net income

 

 

77,036

 

Basic and diluted earnings per common share

 

 

1.01

 

For the pro forma financial information, certain information was derived from financial records and certain information was estimated.  The following table presents incremental items included in the pro forma information reported above for the Newfield Properties (in thousands):

 

 

(unaudited)

 

 

 

Year Ended

December 31, 2012 (a)

 

Revenues (b)

 

$

105,705

 

Direct operating expenses (b)

 

 

33,186

 

Insurance costs (c)

 

 

475

 

DD&A (d)

 

 

53,408

 

G&A (e)

 

 

(553

)

Interest expense (f)

 

 

12,060

 

Capitalized interest (g)

 

 

(643

)

Income tax expense (h)

 

 

2,720

 

The sources of information and significant assumptions are described below:

(a)

The adjustments are for the period from January 1, 2012 to October 5, 2012.

(b)

Revenues and direct operating expenses for the Newfield Properties were derived from the historical financial records of Newfield.

(c)

Incremental costs for insurance were estimated from the incremental costs to add the Newfield Properties to W&T’s insurance programs.  The direct operating costs for the Newfield Properties described above excluded insurance costs.

(d)

DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Newfield Properties’ costs, reserves and production into our currently existing full cost pool in order to compute such amounts.  The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation.  ARO was estimated by W&T management.

(e)

G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from 2012 results.  

(f)

The acquisition was assumed to be funded entirely with borrowed funds.  Interest expense was computed using assumed borrowings of $205.8 million, which equates to the cash component of the transaction, and an interest rate of 7.7%, which equates to the effective yield on net proceeds for the additional senior notes issued shortly after the acquisition closed.

(g)

Incremental capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings.  The negative amount represents a decrease to net expenses.

(h)

Income tax expense was computed using the 35% federal statutory rate.

The pro forma adjustments do not included adjustments related to any other acquisitions or divestitures.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2012 Divestiture

On May 15, 2012, we sold our 40%, non-operated working interest in the South Timbalier 41 field located in the Gulf of Mexico for $30.5 million, net, with an effective date of April 1, 2012.  The transaction was structured as a like-kind exchange under the IRC Section 1031 and other applicable regulations, with funds held by a qualified intermediary until replacement purchases could be executed.  Replacement purchases were consummated during 2012, which were within the replacement periods as defined under the IRC.  In connection with this sale, we reversed $4.0 million of ARO.

3. Hurricane Remediation and Insurance Claims

During the third quarter of 2008, Hurricane Ike caused substantial damage to certain of our properties.  Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.

For 2014, 2013 and 2012, we have received insurance proceeds of $12.2 million, $6.7 million and $2.9 million, respectively.  These amounts are included within Net cash provided by operating activities in the Consolidated Statement of Cash Flows and are primarily recorded as reductions in Oil and natural gas properties and equipment on the Consolidated Balance Sheets, with minor amounts recorded as reductions in Lease operating expenseNew Debt in the Consolidated Statements of Operations.  FromOperations for the third quarter of 2008 throughperiod from September 7, 2016 to December 31, 2014, we have received $161.2 million cumulative from our insurance underwriters2016.  Additionally, no interest expense related to Hurricane Ike.  See Note 18 for information regarding legal actions involving certain insurers and the Company concerning claims related to Hurricane Ike damages.

4. Restricted Deposits

Restricted depositsNew Debt will be recorded in future periods as payments of December 31, 2014 and 2013 consisted of funds escrowed forinterest on the future plugging and abandonment of certain oil and natural gas properties.

Pursuant to the Purchase and Sale Agreement with Total E&P USA Inc. (“Total E&P”), security for future plugging and abandonment of certain oil and natural gas properties is required either through bonds or payments to an escrow account or a combination thereof.  Monthly payments are made to an escrow account and these funds are returned to us once verification is made that the security amount requirements have been met.  We were in compliance with the security requirements as of December 31, 2014.  See Note 16 for potential future security requirements.

5. Asset Retirement Obligations

Pursuant to GAAP, an asset retirement obligation associated with the retirement of a tangible long-lived asset is required toNew Debt will be recognizedrecorded as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increasereduction in the carrying amountamount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the associated asset.  The costNew Debt.    

A gain of $123.9 million was recognized related to the tangible asset, includingExchange Transaction.  Under ASC 470-60, a gain was recognized as the initially recognized ARO, is depleted such thatsum of (i) the cost offuture undiscounted payments (principal and interest) related to the ARO is recognized overNew Debt, (ii) the useful life of the asset.  The fair value of the ARO is measured using expected cash outflows associated withcommon stock issued and (iii) deal transaction costs of $18.9 million was less than the ARO, discountedsum of (iv) the carrying value of the Unsecured Senior Notes exchanged and (v) the funds received from the 1.5 Lien Term Loan.  The shares of common stock issued were valued at our credit-adjusted risk-free rate when$1.76 per share, which was the liability is initially recorded.  Accretion expense is recognized over time asclosing price on September 7, 2016.  The effect on basic and diluted earnings per share for 2016 was a $1.30 per share, which assumes the discounted liability is accreted to its expected settlement value.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

gain would not affect income tax benefit for 2016.  

The following is a reconciliation of our ARO liability (in thousands):

 

2014

 

 

2013

 

Asset retirement obligations, beginning of period

$

354,422

 

 

$

384,053

 

Liabilities settled

 

(74,313

)

 

 

(81,543

)

Accretion of discount

 

20,633

 

 

 

20,918

 

Disposition of properties

 

 

 

 

(19,564

)

Liabilities assumed through acquisition

 

21,820

 

 

 

4,233

 

Liabilities incurred

 

3,258

 

 

 

1,745

 

Revisions of estimated liabilities

 

64,748

 

 

 

44,580

 

Asset retirement obligations, end of period

 

390,568

 

 

 

354,422

 

Less current portion

 

36,003

 

 

 

77,785

 

Long-term

$

354,565

 

 

$

276,637

 

During 2014, we increased our ARO on an overall basis primarily duefunds received from the 1.5 Lien Term Loan were used to revisions, acquisitions and accretion of discount.  Revisions increased ARO on a net basis primarily attributable to: a) increases at certain non-operated properties, b) regulation interpretations issued by the Bureau of Safety and Environmental Enforcement (“BSEE”), which increased the amount of work involved, c) revisions to third-party contractor estimated prices for certain work on wells and structures, d) revisions accelerating the timing of planned work for certain wells and e) revisions for certain wells that are taking longer to complete the plugging and abandonment work than previously estimated due to operational issues.  Increasespay transaction costs related to acquisitions include the increase in our ownership interest at Fairway,Exchange Transaction and to pay down borrowings on the acquisition of the Woodside Properties and other minor acquisitions.  Partially offsetting these were decreases for the plug and abandonment work performed during the year and the disposition of certain properties.  

During 2013, we reduced our ARO on an overall basis primarily due to the plug and abandonment work performed during the year.  In addition, the disposition of certain properties, as described in Note 2, reduced our ARO.  The acquisition of the Callon Properties and drilling activity caused ARO to increase.  Revisions that increased ARO on a net basis primarily attributable to: a) regulation interpretations issued by the BSEE, which increased the amount of work involved, b) revisions to third-party contractor estimated prices for certain work on wells and structures, c) revisions accelerating the timing of planned work for certain wells and d) revisions for certain wells that took longer to complete the plugging and abandonment work than previously estimated due to operational issues.  In addition, increases were made for certain locations affected by Hurricane Ike and increases in estimates were made for certain non-operated properties.

6. Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and interest rates.  From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of our oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility.  AllThe balance of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility.  We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations.  Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders and we do not require collateral from our derivative counterparties.

In accordance with GAAP, we record each derivative contractborrowings on the balance sheet as an asset or a liability at its fair value.  We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all changes in the fair value of derivative contracts are recognized currently in earnings.  The cash flows of all of our commodity derivative contracts are included in Net cash provided by operating activities on the Consolidated Statements of Cash Flows.

For information about fair value measurements, refer to Note 8.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Commodity Derivatives

As of December 31, 2014, we did not have any open commodity contracts.  During the years ended December 31, 2014, 2013 and 2012, we entered into derivative contracts and these contracts consisted entirely of crude oil swap contracts.  While these contracts were intended to reduce the effects of price volatility, they may have limited income from favorable price movements.  The crude oil swap contracts were comprised of a portion based on Brent crude oil prices, a portion based on West Texas Intermediate (“WTI”) crude oil prices and a portion based on Light Louisiana Sweet (“LLS”) crude oil prices.  The Brent based swap contracts were priced off the Brent crude oil price quoted on the Intercontinental Exchange, known as ICE.  The WTI based swap contracts were priced off the New York Mercantile Exchange, known as NYMEX.  The LLS based swap contracts were priced from data provided by Argus, an independent media organization.  Although our Gulf of Mexico crude oil price is based off the WTI crude oil price plus a premium, the realized prices received for our Gulf of Mexico crude oil, up until October 2013, had been closer to the Brent crude oil price because of competition with foreign supplied crude oil, which was based off the Brent crude oil price.  Therefore, a portion of the swap oil contracts were priced off the Brent crude oil price to mitigate a portion of the price risk associated with our Gulf of Mexico crude oil production.

The following balance sheet line items included amounts related to the estimated fair value of our open derivative contracts as indicated in the following table (in thousands):

 

December 31,

 

 

2014

 

 

2013

 

Prepaid and other assets

$

 

 

$

141

 

Accrued liabilities

 

 

 

 

9,423

 

Changes in the fair value of our commodity derivative contracts are recognized currently in earnings and were as follows (in thousands):

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Derivative (gain) loss:

$

(3,965

)

 

$

8,470

 

 

$

13,954

 

Cash payments on derivative settlements, net, are included within Net cash provided by operating activities on the Consolidated Statements of Cash Flows and were as follows (in thousands):

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Cash payments on derivative settlements, net

$

5,318

 

 

$

8,589

 

 

$

7,664

 

Offsetting Commodity Derivatives

During 2014, 2013 and 2012, all of our derivative agreements allowed for netting of derivative gains and losses upon settlement.  In general, the terms of the agreements provided for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.  If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility that event may also trigger an acceleration of settlementwas paid down from available cash.

In conjunction with the Exchange Transactions, certain terms of our derivative instruments.  If weCredit Agreement were required to settle all of our open derivative instruments, we would have been able to net paymentsmodified and receipts per counterparty pursuant to the derivative agreements.  Although our derivative agreements allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

There were no open derivative contracts as of December 31, 2014.  The following table provides a reconciliation of the gross assets and liabilitiesare reflected in the balance sheet and the potential effects of master netting agreements on the fair value of open derivative contracts as of December 31, 2013 (in thousands):

 

December 31, 2013

 

 

Derivative

 

 

Derivative

 

 

Assets

 

 

Liabilities

 

Gross amounts presented in the balance sheet

$

141

 

 

$

9,423

 

Amounts not offset in the balance sheet

 

(141

)

 

 

(141

)

Net Amounts

$

 

 

$

9,282

 

7. Long-Term Debt

As of December 31, 2014 and 2013, our long-term debt was as follows (in thousands):

 

December 31,

 

 

2014

 

 

2013

 

8.50% Senior Notes

$

900,000

 

 

$

900,000

 

Debt premiums, net of amortization

 

13,057

 

 

 

15,421

 

Revolving bank credit facility

 

447,000

 

 

 

290,000

 

Total long-term debt

 

1,360,057

 

 

 

1,205,421

 

Current maturities of long-term debt

 

 

 

 

 

Long term debt, less current maturities

$

1,360,057

 

 

$

1,205,421

 

(1)

Aggregate annual maturities of long-term debt as of December 31, 2014 are as follows (in millions): 2015–$0.0; 2016–$0.0; 2017–$0.0; 2018–$447.0; thereafter–$900.0.

Senior Notes

On October 24, 2012, we issued $300.0 million of Senior Notes at a premium of 106% par value with an interest rate of 8.50% (7.7% effective interest rate) and maturity date of June 15, 2019, which have identical terms to the Senior Notes issued in June 2011 (collectively, the “8.50% Senior Notes”).  The net proceeds after fees and expenses were approximately $312.0 million.  The funds were used to repay all of our outstanding indebtedness under our revolving bank credit facility, a portion of which was incurred to partially fund our acquisitiondescription of the Newfield Properties described in Note 2, and for general corporate purposes.  In February 2013, holders of the 8.50% Senior Notes issued in October 2012 exchanged their 8.50% Senior Notes for registered notes with the same terms.Credit Agreement below.

On June 10, 2011, we issued $600.0 million of Senior Notes at par with an interest rate of 8.50% and maturity date of June 15, 2019.  The net proceeds after fees and expenses were approximately $593.5 million.  In January 2012, holders of the Senior Notes issued in June 2011 exchanged their Senior Notes for registered notes with the same terms.

Interest on the 8.50% Senior Notes is payable semi-annually in arrears on June 15 and December 15 of each year and all of the 8.50% Senior Notes are subject to the same indenture.  The 8.50% Senior Notes are unsecured and are fully and unconditionally guaranteed by certain of our subsidiaries.  At December 31, 2014 and 2013, the outstanding balance of our 8.50% Senior Notes was classified at their carrying value as long-term debt.  The estimated annual effective interest rate on the 8.50% Senior Notes is 8.4% for 2014, which includes amortization of debt issuance costs and premiums.  At December 31, 2014 and 2013, the estimated fair value of the 8.50% Senior Notes was approximately $594.0 million and $962.5 million, respectively.

We and our restricted subsidiaries are subject to certain covenants under the indenture governing the 8.50% Senior Notes, which limit our and our restricted subsidiaries’ ability to, among other things, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of our assets, engage in transactions with affiliates, pay dividends or make other distributions on capital stock or subordinated indebtedness and create unrestricted subsidiaries.  We were in compliance with all applicable covenants of the indenture governing the 8.50% Senior Notes as of December 31, 2014.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Credit Agreement

On November 8, 2013, we entered into the Fifth Amended and RestatedThe Credit Agreement (the “Credit Agreement”), which provides a revolving bank credit facility of up to $1.2 billion.facility.  Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders (historically in the spring and the Companyfall), and thewe and our lenders may each request one additional determination per year.  The borrowing base as of December 31, 20142016 was $750.0$150.0 million.  The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.  To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base, such excess or deficiency is required to be repaid within 90 days in three equal monthly payments.  Letters of credit may be issued in amounts up to $300.0$150.0 million, provided availability under the revolving bank credit facility exists.  The revolving bank credit facility is secured and is collateralized by our oil and natural gas properties.  The Credit Agreement terminates on November 8, 2018 and replaced the prior Fourth Amended and Restated Credit Agreement (the “Prior Credit Agreement”).2018.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Credit Agreement contains covenants that limit, among other things, our ability to: (i) pay cash dividends in excess of $60.0 million per year;dividends; (ii) repurchase our common stock or outstanding senior notes in excess of $100.0 million in the aggregate, provided that such limitation will not apply to the repurchase of our existing senior notes in an aggregate principal amount equal to the aggregate principal amount of any new issuance of notes;debt; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) eliminate certain hedging contracts or enter into certain hedging contacts in excess of 75% of projected oil and gas  production on a monthly basis; (vii) enter into certain liens; and (viii) enter into certain other transactions, without the prior consent of the lenders.  We are permitted to issue additional unsecured indebtedness above our current levelif certain conditions are met including: (i) the additional debt is subordinate in security and right of $900.0 million as long as no eventpayment; (ii) the borrowers enter into an intercreditor agreement with terms acceptable to the Administrative Agent of default occurs,the Credit Agreement; (iii) we are in compliance with the financial covenants after giving pro forma effect to the additional unsecured indebtedness,indebtedness; and (iv) such additional unsecured indebtedness matures at least six months after the maturity date of the Credit Agreement and is not subject to restrictive covenants materially more onerous than those provided for in the Credit Agreement.  If we issue additional unsecured indebtedness in excessWith consent of the current $900.0 millionlenders, such limitation will not apply to the repurchase of our existing debt in an aggregate principal amount equal to or less than the borrowing base then in effect will be reduced by $0.25 for each dollaraggregate principal amount of any new issuance of such excess until the borrowing base is redetermined bydebt.  We are permitted to redeem, repurchase, prepay or defease up to $35 million of our lenders.

Borrowings underUnsecured Senior Notes if after giving effect to such redemption, repayment, prepayment or defeasance: (i) no amounts are outstanding on the revolving bank credit facility bear interestfacility; (ii) letters of credit outstanding do not exceed $5 million; (iii) the Consolidated Cash balance is at least $35 million after the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 1.75% to 2.75% depending on the levelredemption or repayment; and (iv) no event of total borrowings under the Credit Agreement, or an alternative base rate equal to the greater of (a) Prime Rate, (b) Federal Funds Rate plus 0.5%,default shall have occurred and (c) LIBOR plus 1.0%, plus applicable margin ranging from 0.75% to 1.75%.  The unused portion of thebe continuing, and no borrowing base is subject to a commitment fee ranging from 0.375% to 0.5%.  The estimated annual effective interest rate was 2.9% for 2014 for borrowings under the Credit Agreement.  The estimated annual effective interest rate includes amortization of debt issuance costsdeficiency shall have occurred and excludes commitment fees and other costs.be continuing or result therefrom.

The Credit Agreement also contains various customary covenants customary events of default andfor certain financial tests, as defined in the Credit Agreement and measured as of the end of each quarter, including a maximum consolidated leverage ratio,and for customary events of default.  These financial test ratios and limits as defined inof December 31, 2016 and thereafter are: (i) the Credit Agreement,First Lien Leverage Ratio must be less than 2.50 to 1.00 through June 30, 2017, then 2.00 to 1.00 thereafter; (ii) the Asset Coverage Ratio must be not less than 1.25 to 1.00 as of 3.5December 31, 2016, then is suspended thereafter; and (ii) the Current Ratio must be greater than 1.00 to 1.0, and a minimum1.00.  As of December 31, 2016, the current ratio was 2.93 to 1.00.  As of December 31, 2016, the First Lien Leverage Ratio and the Asset Coverage Ratio were in compliance, but not meaningful as defined inno borrowings were outstanding on the Credit Agreement,revolving bank credit facility and only minor amounts of 1.0 to 1.0.letters of credit were outstanding.  The customary events of default include: (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Company or any of its subsidiaries guaranteeing borrowings under the revolving bank credit facility; or (iii) a change of control.  The Credit Agreement contains cross-default clauses with the other debt agreements, and these agreements contain similar cross-default clauses with the Credit Agreement.  We were in compliance with all applicable covenants of the Credit Agreement as of December 31, 2014.2016.

As it appliesWe are required to have deposit accounts only with banks party to the Credit Agreement with certain exceptions.  We may not have unrestricted cash balances above $35 million if outstanding balances on the revolving bank credit agreement (including letters of credit) are greater than $5 million.

Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 3.00% to 4.00% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the greater of (a) Prime Rate, (b) Federal Funds Rate plus 0.50%, or (c) LIBOR plus 1.0%, plus applicable margin ranging from 2.00% to 3.00%.  The unused portion of the borrowing base is subject to a commitment fee of 0.50%.  The estimated annual effective interest rate was 3.3% for 2016 for borrowings under the Credit Agreement.  The estimated annual effective interest rate includes amortization of debt issuance costs we applied accounting guidance under the FASB codification 470-50-40-21 that relates to line-of-credit arrangements.  The Credit Agreement had an initial borrowing base equal toand excludes commitment fees and other costs.

During 2016 and 2015, the borrowing base under the Prior Credit Agreement.  One of the 20 banks in the syndication under the Prior Credit Agreement was replaced with a different bank under the Credit Agreement and the other 19 banks were unchanged.  Accordingly, we apportioned the unamortized debt issuance cost related to the Prior Credit Agreement and expensed the portion related to the bank whose debt was extinguished and did not participatereduced.  The reductions in the Credit Agreement.  The remainingborrowing base resulted in proportional reductions in the unamortized debt issuance costs related to the Prior Credit Agreement was combined with the debt issuance costs related to the Credit Agreement of $1.4 million and $3.2 million in 2016 and 2015, respectively, which is being amortized overincluded in the termline Other (income)/expense, net on the Consolidated Statements of the Credit Agreement on a straight line basis.Operations.  

At December 31, 2014,2016 and 2015, we had $447.0 million inno borrowings and $0.6 million in letters of credit outstanding under the revolving bank credit facility.  At December 31, 2013,2016 and 2015, we had $290.0$0.5 million in borrowings and $0.4$0.9 million, respectively, outstanding in letters of credit outstanding under the revolving bank credit facility.  

For information about fair value measurements, refer to Note 8.

91100


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

1.5 Lien Term Loan

8.As part of the Exchange Transaction, we entered into the 1.5 Lien Term Loan on September 7, 2016 with a maturity date of November 15, 2019.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  Interest accrues at 11.00% per annum and is payable quarterly in cash.  The holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction.  The 1.5 Lien Term Loan is secured by a 1.5 priority lien on all of our assets pledged under the Credit Agreement.  The lien securing the 1.5 Lien Term Loan is subordinate to the liens securing the Credit Agreement and has priority above the liens securing the Second Lien Term Loan (defined below), the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes.  All future undiscounted cash flows have been included in the carrying value under ASC 470-60.  Current maturities of our long-term debt represent the cash interest payable for the 1.5 Lien Term Loan payable in the next 12 months.  The 1.5 Lien Term Loan contains various covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) enter into certain liens; and (vii) enter into transactions with affiliates.  We were in compliance with those covenants as of December 31, 2016.

Second Lien Term Loan

In May 2015, we entered into the 9.00% Term Loan (the “Second Lien Term Loan”), which bears an annual interest rate of 9.00%, was issued at a 1.0% discount to par and matures on May 15, 2020 and is recorded at its carrying value consisting of principal, unamortized discount and unamortized debt issuance costs.  Interest on the Second Lien Term Loan is payable in arrears semi-annually on May 15 and November 15.  The estimated annual effective interest rate on the Second Lien Term Loan is 9.7%, which includes amortization of debt issuance costs and discounts.  The Second Lien Term Loan is secured by a second-priority lien on all of our assets that are secured under the Credit Agreement.  The Second Lien Term Loan is effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien PIK Toggle Notes (discussed below).  We are subject to various covenants under the terms governing the Second Lien Term Loan including, without limitation, covenants that limit our ability to incur other debt, pay dividends or distributions on our equity, merge or consolidate with other entities and make certain investments in other entities.  We were in compliance with those covenants as of December 31, 2016.  

Second Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Second Lien PIK Toggle Notes on September 7, 2016, with a maturity date of May 15, 2020.  Cash interest accrues at 9.00% per annum and is payable on May 15 and November 15 of each year.  The Second Lien PIK Toggle Notes contain payment-in-kind (“PIK”) interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period.  We have the option for the first 18 months to pay all or a portion of interest in kind at a rate of 10.75% per annum, except that the initial interest payment on November 15, 2016 had to be paid solely using PIK.  The Second Lien PIK Toggle Notes are secured by a second-priority lien on all of our assets that are pledged under the Credit Agreement.  The Second Lien PIK Toggle Notes are effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien Term Loan.  For purposes of determining the gain from the Exchange Transaction under ASC 470-60, we assumed we will elect full use of the PIK option and these amounts will increase the principal amount.  This assumption for PIK utilization was also used in calculating the maturity amounts disclosed above.  All future undiscounted cash flows have been included in the carrying value under ASC 470-60.  The Second Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with those covenants as of December 31, 2016.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Third Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Third Lien PIK Toggle Notes on September 7, 2016, with a maturity date of June 15, 2021.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  Cash interest accrues at 8.50% per annum and is payable on June 15 and December 15 of each year.  The Third Lien PIK Toggle Notes contain PIK interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period.  We have the option for the first 24 months to pay all or a portion of interest in kind at a rate of 10.00% per annum, except that the initial interest payment on December 15, 2016 had to be paid solely using PIK.  The Third Lien PIK Toggle Notes are secured by a third-priority lien on all of our assets that are secured under the Credit Agreement.  The Third Lien PIK Toggle Notes are effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes.  For purposes of determining the gain from the Exchange Transaction under ASC 470-60, we assumed we will elect full use of the PIK option and these amounts will increase the principal amount.  All future undiscounted cash flows have been included in the carrying value under ASC 470-60.  The Third Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with those covenants as of December 31, 2016.

Unsecured Senior Notes

At December 31, 2016 and 2015, our outstanding Unsecured Senior Notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019, were classified as long-term at their carrying value.  Interest on the Unsecured Senior Notes is payable semi-annually in arrears on June 15 and December 15.  The estimated annual effective interest rate on the Unsecured Senior Notes is 8.4%, which includes amortization of debt issuance costs and premiums.  We and our restricted subsidiaries are subject to certain covenants under the indenture governing the Unsecured Senior Notes, which limit our and our restricted subsidiaries’ ability to, among other things, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of our assets, engage in transactions with affiliates, pay dividends or make other distributions on capital stock or subordinated indebtedness and create unrestricted subsidiaries.  We were in compliance with those covenants as of December 31, 2016.

For information about fair value measurements of our long-term debt, refer to Note 3.

3. Fair Value Measurements

Under GAAP, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  The fair value of an asset should reflect its highest and best use by market participants, whether using an in-use or an in-exchange valuation premise.  The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach.  The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs.  Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

·

Level 1 – quoted prices in active markets for identical assets or liabilities.

Level 1 – quoted prices in active markets for identical assets or liabilities.

·

Level 2 – inputs other than quoted prices that are observable for an asset or liability.  These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

Level 2 – inputs other than quoted prices that are observable for an asset or liability.  These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

·

Level 3 – unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

Level 3 – unobservable inputs that reflect our expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

The following table presents the fair value of our long-term debt (in thousands):

 

 

 

December 31,

 

 

Hierarchy

 

2016

 

 

2015

 

11.00% 1.5 Lien Term Loan, due November 2019

Level 2

 

$

75,000

 

 

$

 

9.00 % Second Lien Term Loan, due May 2020

Level 2

 

 

255,000

 

 

 

217,500

 

9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020

Level 2

 

 

122,255

 

 

 

 

8.50%/10.00% Third Lien PIK Toggle Notes due June 2021

Level 2

 

 

80,243

 

 

 

 

8.50% Unsecured Senior Notes, due June 2019

Level 2

 

 

123,389

 

 

 

324,000

 

The fair value of long-term debt is based on quoted prices, although the market is not an active market; therefore, the fair value is classified within Level 2.  An exception is the fair value of the 1.5 Lien Term Loan, which is held by one entity, and was not traded since its inception in September 2016.  As the 1.5 Lien Term Loan was recently executed, the fair value was assumed to be the carrying value, excluding amounts recorded for future interest payments.  

As of December 31, 2016, there were no open derivatives financial instruments.  As of December 31, 2015, the carrying value of our open derivative financial instruments our 8.50% Senior Notes and our revolving bank credit facility (in thousands):

 

 

 

December 31, 2014

 

 

December 31, 2013

 

 

Hierarchy

 

Assets

 

 

Liabilities

 

 

Assets

 

 

Liabilities

 

Derivatives

Level 2

 

$

 

 

$

 

 

$

141

 

 

$

9,423

 

8.50% Senior Notes

Level 2

 

 

 

 

 

594,000

 

 

 

 

 

 

962,460

 

Revolving bank credit facility

Level 2

 

 

 

 

 

447,000

 

 

 

 

 

 

290,000

 

equaled the estimated fair value.  We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy.  The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity futures prices.  

The faircarrying value of our 8.50% Senior Notes is based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.  The carrying amount of debt under our revolving bank credit facility approximates fair value because the interest rates are variable and reflective of market rates.

Derivatives are reported in the statement of financial position at fair value.  The 8.50% Senior Notes are reported in the statement of financial position at their carrying value, which was $900.0 million at December 31, 2014 and 2013.  The revolving bank credit facilitylong-term debt is reporteddisclosed in the statement of financial position at its carrying value, which was $447.0 million and $290.0 million at December 31, 2014 and 2013, respectively.

Note 2 above.  For additional information about our derivative financial instruments, refer to Note 68.

4. Asset Retirement Obligations  

Asset retirement obligations associated with the retirement of tangible long-lived assets are required to be recognized as a liability in the period in which a legal obligation is incurred and for additional information onbecomes determinable, with an offsetting increase in the carrying amount of the associated asset.  The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset.  The fair value of the ARO is measured using expected cash outflows associated with the ARO, discounted at our 8.50% Senior Notes and revolving bank credit facility refercredit-adjusted risk-free rate when the liability is initially recorded.  Accretion expense is recognized over time as the discounted liability is accreted to Note 7.its expected settlement value.


92103


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

The following is a reconciliation of our ARO liability (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

Asset retirement obligations, beginning of period

$

378,322

 

 

$

390,568

 

Liabilities settled

 

(72,320

)

 

 

(32,555

)

Accretion of discount

 

17,571

 

 

 

20,703

 

Disposition of properties

 

 

 

 

(8,581

)

Liabilities assumed through acquisition

 

 

 

 

2,944

 

Liabilities incurred

 

398

 

 

 

4,780

 

Revisions of estimated liabilities

 

10,467

 

 

 

463

 

Asset retirement obligations, end of period

 

334,438

 

 

 

378,322

 

Less current portion

 

78,264

 

 

 

84,335

 

Long-term

$

256,174

 

 

$

293,987

 

During 2016, we decreased our ARO on an overall basis primarily due to plug and abandonment work performed during 2016, partially offset by increases from accretion and revisions of previous estimates.  Upward revisions were primarily related to sustained casing pressure issues for idle iron at our West Cameron fields identified while performing preliminary plug and abandonment work at these fields.  In addition, increases were attributable to non-operated properties.  Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations.

During 2015, we decreased our ARO on an overall basis primarily due to plug and abandonment work performed during 2015, partially offset by increases from accretion.  Revisions were basically flat as some service providers reduced their costs of goods and services, some service provider costs remained flat and some service provider costs estimates were increased, all of which were incorporated into our estimates.  In addition, revisions were made for scope changes and on the estimates of timing of when the work will be performed.  Liability increases from acquisitions and wells drilled were basically offset by reductions from dispositions.    

5. Insurance Claims

During the third quarter of 2008, Hurricane Ike caused substantial damage to certain of our properties.  Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.

For 2016, 2015 and 2014, we received insurance reimbursements of $10.2 million, $0.2 million and $12.2 million, respectively, primarily related to hurricane damage.  In addition, we recorded receivables of $30.1 million as of December 31, 2016 for recent settlements with certain insurance companies related to Hurricane Ike claims within Receivables – Joint interest, insurance reimbursements and other on the Consolidated Balance Sheets.  Cash receipts from insurance proceeds are included within Net cash provided by operating activities in the Consolidated Statements of Cash Flows and are primarily recorded as reductions in Oil and natural gas properties and equipment on the Consolidated Balance Sheets, with some amounts recorded as reductions in Lease operating expense, General and administrative expenses and Other income (expense), net in the Consolidated Statements of Operations.  From the third quarter of 2008 through December 31, 2016, we have received $171.4 million cumulative reimbursements from insurance companies related to hurricane reimbursements.    

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

9. Equity Structure6. Restricted Deposits

Restricted deposits as of December 31, 2016 and Transactions2015 consisted of funds escrowed for collateral related to the future plugging and abandonment obligations of certain oil and natural gas properties.

Pursuant to the Purchase and Sale Agreement with Total E&P USA Inc. (“Total E&P”), security for future plugging and abandonment of certain oil and natural gas properties is required either through surety bonds or payments to an escrow account or a combination thereof.  Monthly payments are made to an escrow account and these funds are returned to us once verification is made that the security amount requirements have been met.  See Note 15 for potential future security requirements.

7. Acquisitions and Divestitures

2015 Divestiture

On October 15, 2015, we sold certain onshore oil and natural gas property interests to Ajax Resources, LLC (“Ajax”) for approximately $370.9 million in cash, which includes certain customary price adjustments, and Ajax assumed responsibility for the related ARO.  The effective date of the sale was January 1, 2015.  A net purchase price adjustment of $0.9 million for final customary effective date adjustments was recorded during 2016.  Ajax acquired all of our interest in the Yellow Rose field in the Permian Basin, covering approximately 25,800 net acres in Andrews, Martin, Gaines and Dawson counties in West Texas.  We retained a non-expense bearing overriding royalty interest (“ORRI”) equal to a variable percentage in production from the working interests assigned to Ajax, which percentage varies on a sliding scale from one percent for each month that the prompt month New York Mercantile Exchange (“NYMEX”) trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than $90.00 per barrel.  We used a portion of the proceeds of the sale to repay all outstanding borrowings under the revolving bank credit facility, while the remaining balance of approximately $100.0 million was added to available cash.

Under the full-cost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the cost center.  The sale to Ajax did not represent greater than 25% of our proved reserves of oil and natural gas attributable to the full cost pool.  As a result, alteration in the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool was not deemed significant and no gain or loss was recognized from the sale.        

2014 Acquisitions

Fairway

On September 15, 2014, the Parent Company entered into an asset purchase agreement with a third party to increase its ownership interest from 64.3% to 100% in the Mobile Bay blocks 113 and 132 (the “Fairway Field”) and the associated Yellowhammer gas processing plant (collectively, “Fairway”).  The Fairway Field is located in the state waters of Alabama and the Yellowhammer gas processing plant is located in the state of Alabama.  The effective date of the transaction was July 1, 2014.  The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO.  A net purchase price increase of $1.3 million for customary final closing adjustments was recorded in 2015.  The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table presents the purchase price allocation, including estimated adjustments, for the increased ownership interest in Fairway (in thousands):  

Cash consideration:

 

 

 

Evaluated properties including equipment

$

18,693

 

Non-cash consideration:

 

 

 

Asset retirement obligations - non-current

 

6,124

 

Total consideration

$

24,817

 

The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value.  See Note 1 for a description of the Level 3 inputs.  No goodwill was recorded in connection with the acquisition of this additional working interest in Fairway.

Woodside Properties  

On May 20, 2014, Energy VI entered into a purchase and sale agreement to acquire certain oil and natural gas property interests from Woodside Energy (USA) Inc. (“Woodside”).  The properties acquired from Woodside (the “Woodside Properties”) consisted of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks.  All of the Woodside Properties are located in the Gulf of Mexico.  The effective date of the transaction was November 1, 2013.  The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO.  A net purchase price increase of $0.2 million for customary final closing adjustments was recorded in 2015.  The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

The following table presents the purchase price allocation, including estimated adjustments, for the acquisition of the Woodside Properties (in thousands):  

Cash consideration:

 

 

 

Evaluated properties including equipment

$

52,347

 

Unevaluated properties

 

2,660

 

Sub-total cash consideration

 

55,007

 

Non-cash consideration:

 

 

 

Asset retirement obligations - current

 

782

 

Asset retirement obligations - non-current

 

10,543

 

Sub-total non-cash consideration

 

11,325

 

Total consideration

$

66,332

 

The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value.  See Note 1 for a description of the Level 3 inputs.  No goodwill was recorded in connection with the Woodside Properties acquisition.

2014 Acquisitions — Revenues, Net Income and Pro Forma Financial Information - Unaudited  

The increase in working interest ownership for Fairway was not included in our consolidated results until the property transfer date, which occurred in September 2014 and the incremental revenue and operating expenses were immaterial for 2014.  Unaudited pro forma information is not presented as the pro forma information is not materially different from the reported results for 2014 and 2013.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Woodside Properties were not included in our consolidated results until the property transfer date, which occurred on May 20 2014.  For 2015, the Woodside Properties accounted for $24.4 million of revenues, $9.5 million of direct operating expenses, $14.4 million of depreciation, depletion, amortization and accretion (“DD&A”) and no income tax expense, resulting in $0.5 million of net income.  For the period of May 20, 2014 to December 31, 2014, the Woodside Properties accounted for $28.4 million of revenues, $5.5 million of direct operating expenses, $11.0 million of DD&A and $4.2 million of income taxes, resulting in $7.7 million of net income.  The net income attributable to the Woodside Properties does not reflect certain expenses, such as general and administrative expenses (“G&A”) and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis.  In addition, the Woodside Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate.    

In accordance with the applicable accounting guidance, the unaudited pro forma financial information was computed as if the acquisition of the Woodside Properties had been completed on January 1, 2013.  The financial information was derived from W&T’s audited historical consolidated financial statements for annual periods, W&T’s unaudited historical condensed consolidated financial statements for interim periods, and the Woodside Properties’ unaudited historical financial statements for the annual and interim periods.

The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Woodside Properties.  The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2013.  Had we owned the Woodside Properties during the periods indicated, the results may have been substantially different.  For example, we may have operated the assets differently than Woodside; the realized sales prices for oil, NGLs and natural gas may have been different; and the costs of operating the Woodside Properties may have been different.

The following table presents a summary of our pro forma financial information (in thousands, except earnings per share):

 

 

(unaudited)

 

 

 

December 31, 2014 (a)

 

Revenue

 

$

971,595

 

Net loss

 

 

(5,504

)

Basic and diluted loss per common share

 

 

(0.08

)

For the pro forma financial information, certain information was derived from our financial records, Woodside’s financial records and certain information was estimated.  

The following table presents incremental items included in the pro forma information reported above for the Woodside Properties (in thousands):

 

 

(unaudited)

 

 

 

December 31, 2014 (a)

 

Revenues (b)

 

$

22,887

 

Direct operating expenses (b)

 

 

4,417

 

DD&A (c)

 

 

8,385

 

G&A (d)

 

 

300

 

Interest expense (e)

 

 

330

 

Capitalized interest (f)

 

 

(19

)

Income tax expense (g)

 

 

3,316

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The sources of information and significant assumptions are described below:

(a)

The adjustments for 2014 are for the period from January 1, 2014 to May 20, 2014.

(b)

Revenues and direct operating expenses for the Woodside Properties were derived from the historical financial records of Woodside.

(c)

DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Woodside Properties’ costs, reserves and production into our full cost pool in order to compute such amounts.  The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation.  ARO was estimated by W&T management.

(d)

Estimated insurance costs related to the Woodside Properties.

(e)

The acquisition was assumed to be funded entirely with borrowed funds.  Interest expense was computed using assumed borrowings of $55.0 million, which equates to the cash component of the acquisition purchase price, and an interest rate of 1.8%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility.

(f)

The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings.  The negative amount represents a decrease to net expenses.

(g)

Income tax expense was computed using the 35% federal statutory rate.

The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures.

8.  Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our oil and natural gas.  All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility.  We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations.  Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders, and we do not require collateral from our derivative counterparties.

Each derivative contract is recorded on the balance sheet as an asset or liability at fair value as of the respective period.  We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all changes in the fair value of derivative contracts were recognized currently in earnings during the periods presented.  The cash flows of all of our commodity derivative contracts are included in Net cash provided by operating activities on the Consolidated Statements of Cash Flows. While these contracts are intended to reduce the effects of price volatility, they may have limited incremental income from favorable price movements.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Commodity Derivatives

As of December 31, 2016, we did not have any open derivative contracts.  During 2015, we entered into crude oil and natural gas derivative contracts for a portion of our anticipated future production.  Some of the commodity derivative contracts are known as “three-way collars” consisting of a purchased put option, a sold call option and a purchased call option, each at varying strike prices.  The strike prices of the contracts were set so that the contracts were premium neutral (“costless”), which means no net premium was paid to or received from a counterparty.  The three-way collar contracts are structured to provide price risk protection if the commodity price falls below the strike price of the put option and provides us the opportunity to benefit if the commodity price rises above the strike price of the purchased call option.  In addition, we entered into oil derivative contracts known as “two-way”, “costless” collars, which consist of a purchased put option and a sold call option.  These two-way collars provide price risk protection if crude oil prices fall below certain levels, but have the potential to limit incremental income from favorable price movements above certain limits.  The oil contracts are based on WTI crude oil prices as quoted off the NYMEX.  The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX.  During 2014, we used crude oil swap contracts and 2013,have used various derivative instruments in prior years to manage our exposure to commodity price risk from sales of our oil and natural gas.  

The following balance sheet line items included amounts related to the estimated fair value of our open commodity derivative contracts as reported in the following table (in thousands):

 

December 31,

 

 

2016

 

 

2015

 

Prepaid and other assets - current

$

 

 

$

7,672

 

Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Derivative (gain) loss

$

2,926

 

 

$

(14,375

)

 

$

(3,965

)

Cash receipts (payments), net, on commodity derivative contract settlements are included within Net cash provided by operating activities on the Consolidated Statements of Cash Flows and were as follows (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Cash receipts (payments) on derivative settlements, net

$

4,746

 

 

$

6,703

 

 

$

(5,318

)

Offsetting Commodity Derivatives

During 2016 and 2015, all our commodity derivative contracts permit netting of derivative gains and losses upon settlement.  In general, the terms of the contracts provide for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same commodity.  If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our derivative instruments.  If we were required to settle all of our open derivative contracts, we would be able to net payments and receipts per counterparty pursuant to the derivative contracts.  Although our derivative contracts allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability.   For the open derivative contracts as of December 31, 2015, there would have been no difference if the contracts were presented on net basis.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Equity Transactions

During 2016, after receiving shareholder approval, the Company wasincreased the amount of common stock authorized to issue 20from 118.3 million shares to 200.0 million shares, which allowed for the issuance of preferred stock60.4 million additional shares in conjunction with a par value of $0.00001 per share; however, no preferred shares have been issued or were outstanding as of the respective dates.Exchange Transaction.  

During 2014, 20132016 and 2012,2015, we did not pay any dividends and dividends are currently suspended.  During 2014, we paid regular cash dividends of $0.40 $0.36 and $0.32per common share per year, respectively.  In December 2013, we paid a special dividend of $0.42 per share or $31.8 million.  In December 2012, we paid two special dividends totaling $0.79 per share or $59.0 million.  Dividends are subject to periodic review of the Company’s performance and the current economic environment and applicable debt agreement restrictions.  In light of current market conditions, the Board of Directors has elected to suspend the regular quarterly dividend.

share.    

10.  Incentive Compensation PlanShare-Based Awards and Directors Compensation PlanCash-Based Awards

Incentive Compensation Plan

In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders and amendments to the Plan were approved by our shareholders in 2013.  The Plan covers the Company’s eligible employees and consultants.  In addition to other cash and share-based compensation awards, the Plan is designed to grant awards that qualify as performance-based compensation within the meaning of section 162(m) of the IRC.  The Plan grants the Compensation Committee of the Board of Directors administrative authority over all participants, and grants the President and Chief Executive Officer with authority over the administration of awards granted to participants that are not subject to section 16 of the Exchange Act (as applicable, the “Committee”).

Pursuant to the terms of the Plan, the Committee establishes the performance criteria and may use a single measure or combination of business measures as described in the Plan.  Also, individual goals may be established by the Committee.  Performance awards may be granted in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, or other awards related to stock, and awards may be paid in cash, stock, or any combination of cash and stock, as determined by the Committee.  The performance awards granted under the Plan can be measured over a performance period of up to 10 years and annual incentive awards (a type of performance award) will be paid within 90 days following the applicable year end.

Share-based Awards: Restricted Stock Units

For 2014, 2013 and 2012, performance awards under the Plan were granted in the form of restricted stock units (“RSUs”).  As defined by the Plan, RSUs are rights to receive stock, cash or a combination thereof at the end of a specified vesting period, subject to certain terms and conditions as determined by the Committee.  RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period using a predefined scale based on the Company achieving certain predetermined performance criteria.   Vesting occurs upon completion of the specified vesting period applicable to each grant.  Subsequent to the determination of the performance achievement and prior to vesting, the RSUs earn dividend equivalents at the same rate as dividends paid on our common stock.  RSUs are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period.  

During 2014, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which is comprised of: (i) net income before income tax expense, net interest expense, depreciation, depletion, amortization, accretion and certain other items (“Adjusted EBITDA”) for 2014 and (ii) Adjusted EBITDA as a percent of total revenue (“Adjusted EBITDA Margin”) for 2014.  Adjustments range from 0% to 100% dependent upon actual results compared against pre-defined performance levels.  For 2014, the Company was above target for Adjusted EBITDA and was slightly below target for Adjusted EBITDA Margin.

During 2013, RSUs granted were subject to a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2013; (ii) Adjusted EBITDA Margin for 2013; and (iii) the Company’s total shareholder return (“TSR”) ranking against peer companies’ TSR for 2013, 2014 and January 1, 2015 to October 31, 2015.  TSR is determined based upon the change in the entity’s stock price plus dividends for the applicable performance period.  Adjustments range from 0% to 150% for portions subject to Adjusted EBITDA and Adjusted EBITDA Margin measurements and adjustments range from 0% to 200% for the portion subject to TSR measurement.  For 2013, the Company exceeded the target for Adjusted EBITDA and was approximately at target for 2013 Adjusted EBITDA Margin.  For 2014 and 2013, the Company was below target for the TSR rankings for each period.  In addition, RSUs were granted during 2013 which were not subject to performance criteria and were less than 3% of total grants.

93


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2012, RSUs granted were subject to a combination of performance criteria, which was comprised of: (i) earnings per share (“EPS”) for 2012; and (ii) the Company’s TSR ranking against peer companies’ TSR for 2012, 2013 and January 1, 2014 to October 31, 2014.  Adjustments range from 0% to 100% for the portion subject to EPS measurement and adjustments range from 0% to 150% for the portion subject to TSR measurement.  Pursuant to the Plan, discretionary authority was exercised for certain non-executive employees, which reduced the forfeitures that would have occurred through application of the pre-defined performance measurement.

All RSUs granted to date are subject to employment-based criteria in addition to performance criteria.  Vesting occurs in December of the third year after the grant.  For example, the RSUs granted during 2012 (after adjustment for performance) vested in December 2014 to eligible employees.

Cash-based Awards

For 2014, 2013 and 2012, cash-based awards were granted under the Plan to substantially all eligible employees.  The cash-based awards, which are a short-term component of the Plan, were determined based on multiple performance measures, such as Adjusted EBITDA, reserve and production growth, cost containment and individual performance measures.  With respect to the 2014 cash-based awards, some of the performance criteria targets were achieved and were combined with estimates of personal performance measurements to record potential payments.  With respect to the 2013 cash-based awards, most of the performance criteria targets were achieved and were combined with the individual’s performance to determine the cash-based award.  With respect to the 2012 cash-based awards, some of the performance criteria targets were achieved and were combined with the individual’s performance to determine the cash-based award.  In addition, pursuant to the Plan, discretionary authority was exercised for certain non-executive employees, which increased cash-based award amounts in 2012.  Eligible employees are paid their cash-based awards within 75 days following year end.

Share-based Awards: Common Stock

The 2014 annual incentive plan award for the Chief Executive Officer (“CEO”) was settled in shares of common stock based on a pre-determined price of $14.66 per share, subject to pre-defined performance measures and approval of the Compensation Committee.  As the number of shares could not be determined until the full-year 2014 results were determined and approved by the Committee, the CEO’s 2014 award was accounted for as a liability award during 2014 and adjusted to fair value using the Company’s closing price at the end of each reporting period.  The grant was made in the first quarter of 2015 once the number of shares could be determined and approved by the Committee.  The 2013 annual incentive plan award for the CEO was settled in shares of common stock based using the price of the stock immediately preceding the day the award was settled and the grant was made in the first quarter of 2014.  Adjustments were made to both grants to satisfy withholding tax requirements.  The performance measures for the CEO’s awards were the same as the cash-based-awards performance measures established for the other eligible Company employees for 2014 and 2013, respectively.

Directors Compensation Plan Share-Based Awards

Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2014, 2013 and 2012 to the Company’s non-employee directors as a component of their compensation arrangement.  Vesting occurs upon completion of the specified vesting period and one-third of each grant vests each year over a three-year period.  The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares.  Restricted Shares are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restriction period.  

For additional information concerning share-based awards and cash-based awards, including expense recognition, see Note 11.

 

11. Share-Based and Cash-Based Incentive Compensation

As allowed by the Plan, in 2014, 2013 and 2012, the Company granted RSUs to certain of its employees.  In 2014, 2013 and 2012, restricted stock was granted to the Company’s non-employee directors under the Directors Compensation Plan.  In addition to share-based compensation, the Company granted cash-based incentive awards to substantially all eligible employees in 2014, 2013 and 2012.

94


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Additional

 

On May 7, 2013, after receiving shareholder approval, 4,000,000 shares of common stock were added to the amount available for issuance under the Plan.  As of December 31, 2014, there were 4,790,082 shares of common stock available for issuance in satisfaction of awards under the Plan and 500,564 shares of common stock available for issuance in satisfaction of awards under the Directors Compensation Plan.  The shares available for both plans are reduced when restricted stock is granted.  RSUs reduce the shares available in the Plan only when RSUs are settled in shares of common stock, net of withholding tax.  Although the Company has the option to settle RSUs in stock or cash at vesting, only common stock has been used to settle vested RSUs to date.

Restricted Stock

Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2014, 2013 and 2012 to the Company’s non-employee directors.  See Note 10 for additional information concerning Restricted Shares.  A summary of activity related to Restricted Shares is as follows:

 

 

2014

 

 

2013

 

 

2012

 

 

Restricted Shares

 

 

Weighted Average Grant Date Fair Value Per Share

 

 

Restricted Shares

 

 

Weighted Average Grant Date Fair Value Per Share

 

 

Restricted Shares

 

 

Weighted Average Grant Date Fair Value Per Share

 

Nonvested, beginning of period

 

43,840

 

 

$

15.96

 

 

 

43,687

 

 

$

18.69

 

 

 

51,870

 

 

$

15.81

 

Granted

 

18,815

 

 

 

18.60

 

 

 

27,450

 

 

 

12.75

 

 

 

21,954

 

 

 

19.13

 

Vested

 

(19,445

)

 

 

18.00

 

 

 

(27,297

)

 

 

17.09

 

 

 

(27,475

)

 

 

13.59

 

Forfeited

 

 

 

 

 

 

 

 

 

 

 

 

 

(2,662

)

 

 

18.78

 

Nonvested, end of period

 

43,210

 

 

$

16.20

 

 

 

43,840

 

 

$

15.96

 

 

 

43,687

 

 

$

18.69

 

Retained

 

Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2014 are expected to vest as follows:

 

 

Restricted Shares

 

2015

 

21,520

 

2016

 

15,420

 

2017

 

6,270

 

Total

 

43,210

 

Restricted stock fair value at grant date and vested date: The grant date fair value of restricted stock granted during 2014, 2013 and 2012 was $0.3 million, $0.3 million and $0.4 million, respectively, based on the Company’s closing price on the date of grant.  The fair value of the restricted stock that vested during 2014, 2013 and 2012 was $0.3 million, $0.4 million and $0.5 million, respectively, based on the Company’s closing price on the date of vesting.

Restricted Stock Units

During 2014, 2013 and 2012, the Company granted RSUs to certain employees, with nearly all grants being contingent upon meeting specified performance requirements.  The grants are subject to adjustments at the end of the applicable performance period using a predefined scale based on the Company achieving certain predetermined performance criteria.  See Note 10 for additional information concerning RSUs.

The fair value of the RSUs granted in 2014 was determined using the Company’s closing price on the grant dates as the performance measures were all company-specific performance measures comprised of Adjusted EBITDA and Adjusted EBITDA Margin.  

95


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

 

The fair value of the RSUs granted in 2013 was determined separately for each component.  For the components related to the company-specific performance measures (Adjusted EBITDA and Adjusted EBITDA Margin), the fair value was determined using the Company’s closing price on the grant date.  The components related to Adjusted EBITDA and Adjusted EBITDA Margin comprised 40% and 30%, respectively, of the amount granted.  For the component related to TSR ranking, the fair value was determined using a Monte Carlo simulation probabilistic model.  The component related to TSR ranking totaled 30% of the amount granted, with 10% for each of the three-year performance periods.  The inputs used in the model for the Company and the peer companies were: average closing stock prices during January 2013; risk-free interest rates using the LIBOR ranging from 0.27% to 0.91% over the service period; expected volatilities ranging from 30% to 63%; expected dividend yields ranging from 0.0% to 3.1%; and correlation factors ranging from a negative 84% to a positive 95%.  The expected volatilities, expected dividends and correlation factors were developed using historical data.  For the RSUs granted in 2013 that were not subject to performance measures, the fair value was determined using the closing price on the date of grant.

The fair value of the RSUs granted in 2012 was determined separately for the two components.  For the component related to the company-specific performance measure, which was comprised of only EPS, the fair value was determined using the Company’s closing price on the grant date.  The component related to EPS comprised 70% of the amount granted.  For the component related to TSR ranking, the fair value was determined by using a Monte Carlo simulation probabilistic model.  The component related to TSR ranking totaled 30% of the amount granted, with 10% for each of the three-year performance periods.  The inputs used in the model for the Company and the peer companies were: average closing stock prices during January 2012; risk-free interest rates using the LIBOR ranging from 0.15% to 0.72% over the service period; expected volatilities ranging from 33% to 74%; expected dividend yields ranging from 0.0% to 2.5%; and correlation factors ranging from a negative 67% to a positive 94%.  The expected volatilities, expected dividends and correlation factors were developed using historical data.

A summary of activity related to RSUs is as follows:

 

 

2014

 

 

2013

 

 

2012

 

 

Restricted Stock Units

 

 

Weighted Average Grant Date Fair Value Per Share

 

 

Restricted Stock Units

 

 

Weighted Average Grant Date Fair Value Per Share

 

 

Restricted Stock Units

 

 

Weighted Average Grant Date Fair Value Per Share

 

Nonvested, beginning of period

 

1,331,753

 

 

$

14.96

 

 

 

969,820

 

 

$

22.70

 

 

 

1,732,703

 

 

$

14.67

 

Granted

 

1,195,388

 

 

 

16.84

 

 

 

969,919

 

 

 

13.23

 

 

 

764,654

 

 

 

18.64

 

Vested

 

(354,692

)

 

 

18.59

 

 

 

(468,925

)

 

 

26.93

 

 

 

(1,198,208

)

 

 

9.36

 

Forfeited

 

(195,114

)

 

 

16.53

 

 

 

(139,061

)

 

 

16.50

 

 

 

(329,329

)

 

 

19.56

 

Nonvested, end of period

 

1,977,335

 

 

$

15.29

 

 

 

1,331,753

 

 

$

14.96

 

 

 

969,820

 

 

$

22.70

 

 

Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2014 are eligible to vest in the year indicated in the table below:

 

 

Restricted Stock Units

 

2015 - subject to service requirements

759,234

2015 - subject to service and other requirements (1)

90,105

2016 - subject to service requirements

1,127,996

Total

1,977,335

 

(1)

In addition to service requirements, these RSUs are also subject to TSR performance requirements not yet measureable, with awards ranging from 0% to 200% of amounts granted.

Outstanding

Paid-In

Earnings

Treasury Stock

Shareholders’

Shares

Value

Capital

(Deficit)

Shares

Value

Equity (Deficit)

Balances at December 31, 2013

75,592

$

1

$

403,564

$

161,212

2,869

$

(24,167

)

$

540,610

Cash dividends

(30,260

)

(30,260

)

Share-based compensation

14,744

14,744

Stock issued

307

RSUs fair valueand shares surrendered

  for payroll taxes

(848

)

(848

)

Other

(2,880

)

(397

)

(3,277

)

Net loss

(11,661

)

(11,661

)

Balances at grant date: DuringDecember 31, 2014 2013

75,899

1

414,580

118,894

2,869

(24,167

)

509,308

Share-based compensation

10,242

10,242

Stock issued

607

RSUs and 2012, the grant date fair value of shares surrendered

  for payroll taxes

(674

)

(674

)

Other

(649

)

(649

)

Net loss

(1,044,718

)

(1,044,718

)

Balances at December 31, 2015

76,506

1

423,499

(925,824

)

2,869

(24,167

)

(526,491

)

Share-based compensation

11,013

11,013

Stock issued

61,168

106,366

106,366

RSUs granted was $20.1 million, $12.8 million and $14.3 million, respectively.surrendered

RSUs fair value   for payroll taxes

(905

)

(905

)

Net loss

(249,020

)

(249,020

)

Balances at vested date: The fair value of the RSUs that vested during 2014, 2013 and 2012 was $2.0 million, $7.2 million and $20.0 million, respectively, based on the Company’s closing price on the vesting date.December 31, 2016

96

137,674

$

1

$

539,973

$

(1,174,844

)

2,869

$

(24,167

)

$

(659,037

)

See accompanying notes.


W&T Offshore, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities:

 

 

 

 

 

 

 

 

 

 

 

Net loss

$

(249,020

)

 

$

(1,044,718

)

 

$

(11,661

)

Adjustments to reconcile net loss to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

211,609

 

 

 

394,071

 

 

 

511,102

 

Ceiling test write-down of oil and gas properties

 

279,063

 

 

 

987,238

 

 

 

 

Gain on exchange of debt

 

(123,923

)

 

 

 

 

 

 

Debt issuance costs write-down/amortization of debt items

 

2,548

 

 

 

4,411

 

 

 

701

 

Share-based compensation

 

11,013

 

 

 

10,242

 

 

 

14,744

 

Derivative (gain) loss

 

2,926

 

 

 

(14,375

)

 

 

(3,965

)

Cash receipts (payments) on derivative settlements, net

 

4,746

 

 

 

6,703

 

 

 

(5,318

)

Deferred income taxes

 

28,392

 

 

 

(203,272

)

 

 

(4,760

)

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas receivables

 

(7,005

)

 

 

32,236

 

 

 

29,510

 

Joint interest receivables and insurance

 

(1,126

)

 

 

21,633

 

 

 

(4,255

)

Income taxes

 

(64,274

)

 

 

(7

)

 

 

3,143

 

Prepaid expenses and other assets

 

(14,946

)

 

 

17,816

 

 

 

15,012

 

Asset retirement obligation settlements

 

(72,320

)

 

 

(32,555

)

 

 

(74,313

)

Accounts payable, accrued liabilities and other

 

6,497

 

 

 

(46,195

)

 

 

4,881

 

Net cash provided by operating activities

 

14,180

 

 

 

133,228

 

 

 

474,821

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

Acquisition of property interest in oil and natural gas properties

 

 

 

 

 

 

 

(72,234

)

Investment in oil and natural gas properties and equipment

 

(48,606

)

 

 

(230,161

)

 

 

(554,378

)

Changes in operating assets and liabilities associated with investing activities

 

(35,194

)

 

 

(55,425

)

 

 

37,450

 

Net proceeds from sales of assets

 

1,500

 

 

 

372,939

 

 

 

 

Purchases of furniture, fixtures and other

 

(96

)

 

 

(1,278

)

 

 

(3,340

)

Net cash provided by (used in) investing activities

 

(82,396

)

 

 

86,075

 

 

 

(592,502

)

Financing activities:

 

 

 

 

 

 

 

 

 

 

 

Borrowings of long-term debt - revolving bank credit facility

 

340,000

 

 

 

263,000

 

 

 

556,000

 

Repayments of long-term debt - revolving bank credit facility

 

(340,000

)

 

 

(710,000

)

 

 

(399,000

)

Issuance of 1.5 Lien Term Loan

 

75,000

 

 

 

 

 

 

 

Issuance of Second Lien Term Loan

 

 

 

 

297,000

 

 

 

 

Payment of interest on 1.5 Lien Term Loan

 

(2,570

)

 

 

 

 

 

 

Debt exchange/issuance costs

 

(18,464

)

 

 

(6,669

)

 

 

 

Dividends to shareholders

 

 

 

 

 

 

 

(30,260

)

Other

 

(928

)

 

 

(886

)

 

 

(1,193

)

Net cash provided by (used in) financing activities

 

53,038

 

 

 

(157,555

)

 

 

125,547

 

Increase (decrease) in cash and cash equivalents

 

(15,178

)

 

 

61,748

 

 

 

7,866

 

Cash and cash equivalents, beginning of period

 

85,414

 

 

 

23,666

 

 

 

15,800

 

Cash and cash equivalents, end of period

$

70,236

 

 

$

85,414

 

 

$

23,666

 

See accompanying notes.


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Significant Accounting Policies

Operations

W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”, is an independent oil and natural gas producer focused primarily in the Gulf of Mexico.  On October 15, 2015, a substantial amount of our interest in onshore acreage was sold, which is described in Note 7.  We are active in the exploration, development and acquisition of oil and natural gas properties.  Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our wholly-owned subsidiary, W & T Energy VI, LLC (“Energy VI”).  

Basis of Presentation

Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries.  All significant intercompany transactions and amounts have been eliminated for all years presented.  Our consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) and the appropriate rules and regulations of the Securities and Exchange Commission (���SEC”).

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves.  Actual results could differ from those estimates.

Early Adoption of Accounting Standard Amendments

Accounting Standards Update No. 2016-09 (“ASU 2016-09”), Compensation – Stock Compensation (Subtopic 718) was early adopted as of December 31, 2016.  The amendment’s objective is simplification of several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the Consolidated Statements of Cash Flows.  The early adoption affected the statements of cash flows as to the classification of cash paid for employee income taxes and payroll taxes, which were funded through the forfeiture of vested restricted stock units (“RSUs”).  Previously, these cash payments were classified as operating activities.  The updated standard requires such cash transactions be classified as financing activities. The reclassification was applied retrospectively on the statements of cash flows for the years 2014 and 2015 and resulted in reclassification of $0.8 million and $0.7 million, respectively.  None of the other amendments under ASU 2016-09 had an effect on our financial statements and the early adoption of ASU 2016-09 did not affect the Consolidated Balance Sheets, Consolidated Statements of Operations or the Consolidated Statements of Changes in Shareholders’ Equity (Deficit).  

90


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

 

Recent Events

The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital and future rate of growth.  The prices of these commodities began falling in the second half of 2014, were significantly lower during 2015 and lower still in 2016 compared to prior years.  

We took a number of  steps during 2015 and 2016 to mitigate the effects of these lower prices including: (i) significantly reducing capital spending from previous year levels and budgeting conservative capital spending for 2017 (exclusive of acquisitions); (ii) restructuring our debt and issuing our common stock through an exchange transaction, which is described in Note 2, (iii) receiving funds through two debt issuances, which are described in Note 2 (iv) suspending our quarterly common stock dividend; (iv) implementing numerous cost reduction projects to reduce our operating costs; and (v) selling our interest in the Yellow Rose onshore field, which is described in Note 7.

During 2016, the Bureau of Ocean Energy Management (“BOEM”) issued orders to us concerning financial assurances related to plug and abandonment (decommissioning) obligations for Federal offshore leases, including an order issued to us in December 2016 regarding additional security required for sole liability properties.  In July 2016, effective September 2016, the BOEM issued Notice to Lessees #2016-N01 (“NTL #2016-N01”), related to obligations for decommissioning activities on the Outer Continental Shelf (“OCS”) for leases, rights-of-way (“ROWs”) or rights of use and easement (“RUEs”).  In January 2017, the BOEM extended the implementation timeline by an additional six months of NTL #2016-N01 as to leases, ROWs and RUEs for which there are co-lessees and/or predecessors in interest (non-sole liability properties), with certain exceptions.  In February 2017, the BOEM withdrew the sole liability orders it had issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program.  See Note 17 and 19 for additional information.      

We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations for at least 12 months from the date of issuance of this Form 10-K, which is the threshold of a going concern under GAAP; however, we cannot predict with any certainty future commodity prices or the actions of the BOEM concerning financial assurance requirements, either of which could affect our operations and liquidity levels.

Cash Equivalents

We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents.

Revenue Recognition

We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured.  We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership.  Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production.  These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production.  We do not record receivables for those properties in which we have taken less than our ownership share of production.  At December 31, 2016 and 2015, $5.3 million and $6.9 million, respectively, were included in current liabilities related to natural gas imbalances.

91


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Concentration of Credit Risk

Our customers are primarily large integrated oil and natural gas companies and large financial institutions.  The majority of our production is sold utilizing month-to-month contracts that are based on bid prices.  We also have receivables from joint interest owners on properties we operate and we may have the ability to withhold future revenue disbursements to recover amounts due us.  We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guaranties when considered necessary.  We historically have not had any significant problems collecting our receivables, but with the decline in commodity prices, several oil and gas companies have filed for bankruptcy, including some of our joint interest partners.  We use the specific identification method of determining if an allowance for doubtful accounts is needed.  As of December 31, 2016 and 2015, $7.6 million and $2.5 million, respectively, were recorded as an allowance for doubtful accounts.  During 2016 and 2015, there were no reductions recorded in the allowance for doubtful accounts (no collections of accounts previously reserved and no permanent write-off of receivable accounts).  

The following identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas.

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Customer

 

 

 

 

 

 

 

 

 

 

 

Shell Trading (US) Co.

 

43

%

 

 

50

%

 

 

47

%

Vitol Inc.

 

20

%

 

**

 

 

**

 

J. P. Morgan

**

 

 

 

14

%

 

**

 

** Less than 10%

We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing.

Insurance Receivables

We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance company’s adjuster reviews and approves such costs for payment or when the insurance company has agreed to reimbursement amounts.  Claims that have been processed in this manner have customarily been paid on a timely basis.  See Note 5, 17 and 19 for information related to settlement of previously unpaid claims by certain insurance companies.

Prepaid expenses and other

Amounts recorded in Prepaid expenses and other on the Consolidated Balance Sheets are expected to be realized within one year.  Items representing 5% or more of total current assets in either period presented are disclosed in the following table:  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Year Ended December 31,

 

 

2016

 

 

2015

 

Derivative assets - current (1)

$

 

 

$

10,036

 

Prepaid/accrued  insurance and surety bonds

 

5,386

 

 

 

7,475

 

Prepaid deposits related to royalties

 

6,237

 

 

 

5,943

 

Other (2)

 

2,881

 

 

 

3,425

 

Prepaid expenses and other

$

14,504

 

 

$

26,879

 

(1)

Includes open and closed (and not yet collected) derivative commodity contracts recorded at fair value as of December 31, 2015.

(2)

Individual items were less than 5% of total current assets for either period presented.

Properties and Equipment

We use the full-cost method of accounting for oil and natural gas properties and equipment.  Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized.  Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties.  Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs.  Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines.  Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred.

Oil and natural gas properties and equipment include costs of unproved properties.  The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as we have made an evaluation that impairment has occurred.  The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial.

We capitalize interest on the amount of unproved properties that are excluded from the amortization base.  Interest is capitalized only for the period that exploration and development activities are in progress.  Capitalization of interest ceases when the property is moved into the amortization base.  All capitalized interest is recorded within Oil and natural gas property and equipment on the Consolidated Balance Sheets.

Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities.  In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves.  Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense.

Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years.  Leasehold improvements are amortized over the shorter of their economic lives or the lease term.  Repairs and maintenance costs are expensed in the period incurred.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Ceiling Test Write-Down

Under the full-cost method of accounting, we are required to perform a “ceiling test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties.  If the net capitalized cost of oil and natural gas properties (including capitalized ARO) net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed.  Any such write downs are not recoverable or reversible in future periods.  The ceiling test limit is calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects.  Estimated future net revenues used in the ceiling test for each period are based on current prices for each product, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the prior twelve months for that period.  All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials.

Due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas, we recorded ceiling test write-downs in 2015 and 2016, which are reported as a separate line in the Statements of Operations.  The average price using the SEC required methodology at December 31, 2016 was $39.25 per barrel for West Texas Intermediate (“WTI”) crude oil and $2.48 per million British Thermal Unit  (“MMBtu”) for Henry Hub natural gas.  These prices are before adjustments for quality, transportation, fees, energy content and regional price differentials.   The ceiling test write-downs of the carrying value of our oil and natural gas properties were $279.1 million and $987.2 million for 2016 and 2015, respectively.  There was no ceiling test write-down in the fourth quarter of 2016.  We did not record a ceiling test write-down during 2014.  If average crude oil and natural gas prices decrease from 2016 levels, it is possible that a ceiling test write-down will be recorded during 2017.  

Asset Retirement Obligations

We are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet.  We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations.  These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup.  Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal.  Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period.  For additional information, refer to Note 4.

Oil and Natural Gas Reserve Information

We use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves.  Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices.  Proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years, with some limited exceptions allowed.  Refer to Note 21 for additional information about our proved reserves.

Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and interest rates.  From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our credit facility.  As of December 31, 2016, we did not have any open derivative financial instruments.  We do not enter into derivative instruments for speculative trading purposes.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value.  Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into.  Whenever we have entered into derivative contracts, we did not designate our commodity derivatives as hedging instruments, therefore, all changes in fair value are recognized in earnings.

Fair Value of Financial Instruments

We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance.  We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments.  We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments.  We believe the carrying amount of debt under our 11.00% 1.5 Lien Term Loan, due November 2019, (the “1.5 Lien Term Loan”) approximates fair value because the debt was recently executed and reflective of market rates and conditions.

Fair Value of Acquisitions

Acquisitions are recorded on the closing date of the transaction at their fair value, which is determined by applying the market and income approaches using Level 3 inputs.  The Level 3 inputs are: (i) analysis of comparable transactions obtained from various third-parties, (ii) estimates of ultimate recoveries of reserves, and (iii) estimates of discounted cash flows based on estimated reserve quantities, reserve categories, timing of production, costs to produce and develop reserves, future prices, ARO and discount rates.  The estimates and assumptions are determined by management and third-parties.  The fair value is based on subjective estimates and assumptions, which are inherently imprecise, and the actual realized values can vary significantly from estimates that are made.

Income Taxes

We use the liability method of accounting for income taxes in accordance with the Income Taxes topic of the Accounting Standard Codification.  Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements.  In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.  We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken.  When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense.  See Note 12 for additional information.

Troubled Debt Restructuring  

We accounted for an exchange transaction, which is described in Note 2, as a troubled debt restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”).  Under ASC 470-60, the carrying value of the newly issued debt, as described in Note 2, is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the newly issued debt in the Consolidated Statements of Operations for the period from September 7, 2016 to December 31, 2016.  Additionally, no interest expense related to the newly issued debt will be recorded in future periods as payments of interest on the newly issued debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the newly issued debt.  See Note 2 for additional information.    

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Debt Issuance Costs

Debt issuance costs associated with our revolving bank credit facility are amortized using the straight-line method over the scheduled maturity of the debt.  Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method.  Unamortized debt issuance costs associated with our revolving bank credit facility is reported within Other Assets (noncurrent) and unamortized debt issuance costs associated with our other debt is reported as a reduction in Long-Term Debt, less current maturities in the Consolidated Balance Sheets.  See Note 2 for additional information.  

Premiums Received and Discounts Provided on Debt Issuance

Premiums and discounts are recorded in Long-Term Debt, less current maturities in the Consolidated Balance Sheets and are amortized over the term of the related debt using the effective interest method.

Share-Based Compensation

Compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award.  The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant.  We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award.  Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests.  See Note 10 for additional information.

Loss Per Share

Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of loss per share under the two-class method when the effect is dilutive.  For additional information, refer to Note 13.

Other (Income) Expense, Net  

For 2016, the amount includes $7.7 million of income related to the settlement of certain insurance claims.  In 2016 and 2015, the amount includes write-offs of debt issuance costs of $1.4 million and $3.2 million, respectively, related to a reduction in the borrowing base of the revolving bank credit facility under the Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”).  The write-offs of debt issuance costs in both 2016 and 2015 are included as an adjustment to net income in determining Net cash provided by operating activities in the Consolidated Statements of Cash Flows as the write-offs were non-cash transactions.  

Recent Accounting Developments

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Subtopic 606).  ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance.  The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017.  Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application.  Our current intention is to adopt the standard utilizing the modified retrospective approach.  Our evaluation to date is the adoption of ASU 2014-09 is not expected to have a material impact on our consolidated financial statements.  We have not fully completed our analysis and subsequent guidance may change this assessment.  Our disclosures related to revenue will be modified when the new guidance is effective.  ASU 2014-09 will be effective for us in the first quarter of 2018.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases (Subtopic 842).  Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Consistent with current GAAP, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease.  However, unlike current GAAP, which requires only capital leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet.  ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases.  These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements.  ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources.  Our current operating leases that will be impacted by ASU 2016-02 when it is effective are leases for office space in Houston and New Orleans, although ASU 2016-02 may impact the accounting for leases related to operations equipment depending on the term of the lease.  We currently do not have any leases classified as financing leases.  ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach.  We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.  

In June 2016, the FASB issued Accounting Standards Update No. 2016-13, (“ASU 2016-13”), Financial Instruments – Credit Losses (Subtopic 326).  The new guidance eliminates the probable recognition threshold and broadens the information to consider past events, current conditions and forecasted information in estimating credit losses.  ASU 2016-13 is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted for fiscal years beginning after December 15, 2018.  We have not yet fully determined or quantified the effect ASU 2016-13 will have on our financial statements.

In August 2016, the FASB issued Accounting Standards Update No. 2016-15, (“ASU 2016-15”), Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments.  ASU 2016-15 addresses the classification of several items that previously had diversity in practice.  Items identified in the new standard which were incurred by us in the past are: (a) debt prepayment or extinguishment costs; (b) contingent consideration made after a business acquisition; and (c) proceeds from settlement of insurance claims.  The item described in clause (b) would be the only such item changed under our historical classification in the Statement of Cash Flows (financing vs. investing) and the amount of such change would not be material; therefore, we do not anticipate the new standard will have a material effect on our Statement of Cash Flows.  ASU 2016-15 is effective for fiscal years beginning after December 15, 2017 and early adoption is permitted.  

In November 2016, the FASB issued Accounting Standards Update No. 2016-18, (“ASU 2016-18”), Statement of Cash Flows (Topic 230) – Restricted Cash.  ASU 2016-18 addresses diversity in practice and requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.  ASU 2016-18 is expected to change some of the presentation in our statement of cash flows, but not materially impact total cash flows from operating, investing or financing activities.  ASU 2016-18 is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years.  Early adoption is permitted, including adoption in an interim period.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Long-Term Debt

As of December 31, 2016 and 2015, our long-term debt was as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

December 31, 2016

 

 

2015

 

 

 

 

 

 

PIK Payable/

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Payable/

 

 

Carrying

 

 

Principal/

 

 

Principal

 

 

Other

 

 

Value

 

 

Other*

 

11.00% 1.5 Lien Term Loan,

     due November 2019

$

75,000

 

 

$

23,823

 

 

$

98,823

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9.00 % Second Lien Term Loan,

    due May 2020

 

300,000

 

 

 

 

 

 

300,000

 

 

 

300,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9.00%/10.75% Second Lien PIK Toggle Notes,

    due May 2020

 

163,007

 

 

 

60,898

 

 

 

223,905

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8.50%/10.00% Third Lien PIK Toggle Notes,

   due June 2021

 

145,897

 

 

 

67,549

 

 

 

213,446

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8.50% Unsecured Senior Notes,

    due June 2019

 

189,829

 

 

 

 

 

 

189,829

 

 

 

900,000

 

Subtotal

 

873,733

 

 

 

152,270

 

 

 

1,026,003

 

 

 

1,200,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt premium, discount, issuance costs,

     net of amortization

 

 

 

 

(5,276

)

 

 

(5,276

)

 

 

(3,145

)

Total long-term debt

 

873,733

 

 

 

146,994

 

 

 

1,020,727

 

 

 

1,196,855

 

Current maturities of long-term debt

 

 

 

 

8,272

 

 

 

8,272

 

 

 

 

Long term debt, less current maturities

$

873,733

 

 

$

138,722

 

 

$

1,012,455

 

 

$

1,196,855

 

* Amounts also equal carrying value

Aggregate annual maturities of amounts recorded for long-term debt as of December 31, 2016 are as follows (in millions): 2017–$8.2; 2018–$23.8; 2019–$303.7; 2020–$510.1; thereafter–$180.1.  See below for discussion on the determination of recorded amounts.    

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Exchange Transaction

On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our 8.500% Senior Notes (the “Unsecured Senior Notes”), due June 15, 2019, for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Senior Second Lien PIK Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); (ii) $142.0 million in aggregate principal amount of 8.50%/10.00% Senior Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”); and (iii) 60.4 million shares of our common stock (collectively, the “Debt Exchange”).  At the same time on closing on the Debt Exchange, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 2019, with the then largest holder of our Unsecured Senior Notes (collectively with the Debt Exchange, the “Exchange Transaction”).  We accounted for the Exchange Transaction as a Troubled Debt Restructuring pursuant to the guidance under ASC 470-60.  Under ASC 470-60, the carrying value of the newly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Consolidated Statements of Operations for the period from September 7, 2016 to December 31, 2016.  Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt.    

A gain of $123.9 million was recognized related to the Exchange Transaction.  Under ASC 470-60, a gain was recognized as the sum of (i) the future undiscounted payments (principal and interest) related to the New Debt, (ii) the fair value of the common stock issued and (iii) deal transaction costs of $18.9 million was less than the sum of (iv) the carrying value of the Unsecured Senior Notes exchanged and (v) the funds received from the 1.5 Lien Term Loan.  The shares of common stock issued were valued at $1.76 per share, which was the closing price on September 7, 2016.  The effect on basic and diluted earnings per share for 2016 was a $1.30 per share, which assumes the gain would not affect income tax benefit for 2016.  

The funds received from the 1.5 Lien Term Loan were used to pay transaction costs related to the Exchange Transaction and to pay down borrowings on the revolving bank credit facility.  The balance of the borrowings on the revolving bank credit facility was paid down from available cash.

In conjunction with the Exchange Transactions, certain terms of our Credit Agreement were modified and are reflected in the description of the Credit Agreement below.

Credit Agreement

The Credit Agreement provides a revolving bank credit facility.  Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders (historically in the spring and fall), and we and our lenders may each request one additional determination per year.  The borrowing base as of December 31, 2016 was $150.0 million.  The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.  To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base, such excess or deficiency is required to be repaid within 90 days in three equal monthly payments.  Letters of credit may be issued in amounts up to $150.0 million, provided availability under the revolving bank credit facility exists.  The revolving bank credit facility is secured and is collateralized by our oil and natural gas properties.  The Credit Agreement terminates on November 8, 2018.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Credit Agreement contains covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock or outstanding debt; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) eliminate certain hedging contracts or enter into certain hedging contacts in excess of 75% of projected oil and gas  production on a monthly basis; (vii) enter into certain liens; and (viii) enter into certain other transactions, without the prior consent of the lenders.  We are permitted to issue additional indebtedness if certain conditions are met including: (i) the additional debt is subordinate in security and right of payment; (ii) the borrowers enter into an intercreditor agreement with terms acceptable to the Administrative Agent of the Credit Agreement; (iii) we are in compliance with the financial covenants after giving pro forma effect to the additional indebtedness; and (iv) such additional unsecured indebtedness matures at least six months after the maturity date of the Credit Agreement and is not subject to restrictive covenants materially more onerous than those provided for in the Credit Agreement.  With consent of the lenders, such limitation will not apply to the repurchase of our existing debt in an aggregate principal amount equal to or less than the aggregate principal amount of any new issuance of such debt.  We are permitted to redeem, repurchase, prepay or defease up to $35 million of our Unsecured Senior Notes if after giving effect to such redemption, repayment, prepayment or defeasance: (i) no amounts are outstanding on the revolving bank credit facility; (ii) letters of credit outstanding do not exceed $5 million; (iii) the Consolidated Cash balance is at least $35 million after the redemption or repayment; and (iv) no event of default shall have occurred and be continuing, and no borrowing base deficiency shall have occurred and be continuing or result therefrom.

The Credit Agreement also contains various customary covenants for certain financial tests, as defined in the Credit Agreement and measured as of the end of each quarter, and for customary events of default.  These financial test ratios and limits as of December 31, 2016 and thereafter are: (i) the First Lien Leverage Ratio must be less than 2.50 to 1.00 through June 30, 2017, then 2.00 to 1.00 thereafter; (ii) the Asset Coverage Ratio must be not less than 1.25 to 1.00 as of December 31, 2016, then is suspended thereafter; and (ii) the Current Ratio must be greater than 1.00 to 1.00.  As of December 31, 2016, the current ratio was 2.93 to 1.00.  As of December 31, 2016, the First Lien Leverage Ratio and the Asset Coverage Ratio were in compliance, but not meaningful as no borrowings were outstanding on the revolving bank credit facility and only minor amounts of letters of credit were outstanding.  The customary events of default include: (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Company or any of its subsidiaries guaranteeing borrowings under the revolving bank credit facility; or (iii) a change of control.  The Credit Agreement contains cross-default clauses with the other debt agreements, and these agreements contain similar cross-default clauses with the Credit Agreement.  We were in compliance with all applicable covenants of the Credit Agreement as of December 31, 2016.

We are required to have deposit accounts only with banks party to the Credit Agreement with certain exceptions.  We may not have unrestricted cash balances above $35 million if outstanding balances on the revolving bank credit agreement (including letters of credit) are greater than $5 million.

Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 3.00% to 4.00% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the greater of (a) Prime Rate, (b) Federal Funds Rate plus 0.50%, or (c) LIBOR plus 1.0%, plus applicable margin ranging from 2.00% to 3.00%.  The unused portion of the borrowing base is subject to a commitment fee of 0.50%.  The estimated annual effective interest rate was 3.3% for 2016 for borrowings under the Credit Agreement.  The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs.

During 2016 and 2015, the borrowing base under the Credit Agreement was reduced.  The reductions in the borrowing base resulted in proportional reductions in the unamortized costs related to the Credit Agreement of $1.4 million and $3.2 million in 2016 and 2015, respectively, which is included in the line Other (income)/expense, net on the Consolidated Statements of Operations.  

At December 31, 2016 and 2015, we had no borrowings outstanding under the revolving bank credit facility.  At December 31, 2016 and 2015, we had $0.5 million and $0.9 million, respectively, outstanding in letters of credit under the revolving bank credit facility.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1.5 Lien Term Loan

As part of the Exchange Transaction, we entered into the 1.5 Lien Term Loan on September 7, 2016 with a maturity date of November 15, 2019.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  Interest accrues at 11.00% per annum and is payable quarterly in cash.  The holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction.  The 1.5 Lien Term Loan is secured by a 1.5 priority lien on all of our assets pledged under the Credit Agreement.  The lien securing the 1.5 Lien Term Loan is subordinate to the liens securing the Credit Agreement and has priority above the liens securing the Second Lien Term Loan (defined below), the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes.  All future undiscounted cash flows have been included in the carrying value under ASC 470-60.  Current maturities of our long-term debt represent the cash interest payable for the 1.5 Lien Term Loan payable in the next 12 months.  The 1.5 Lien Term Loan contains various covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) enter into certain liens; and (vii) enter into transactions with affiliates.  We were in compliance with those covenants as of December 31, 2016.

Second Lien Term Loan

In May 2015, we entered into the 9.00% Term Loan (the “Second Lien Term Loan”), which bears an annual interest rate of 9.00%, was issued at a 1.0% discount to par and matures on May 15, 2020 and is recorded at its carrying value consisting of principal, unamortized discount and unamortized debt issuance costs.  Interest on the Second Lien Term Loan is payable in arrears semi-annually on May 15 and November 15.  The estimated annual effective interest rate on the Second Lien Term Loan is 9.7%, which includes amortization of debt issuance costs and discounts.  The Second Lien Term Loan is secured by a second-priority lien on all of our assets that are secured under the Credit Agreement.  The Second Lien Term Loan is effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien PIK Toggle Notes (discussed below).  We are subject to various covenants under the terms governing the Second Lien Term Loan including, without limitation, covenants that limit our ability to incur other debt, pay dividends or distributions on our equity, merge or consolidate with other entities and make certain investments in other entities.  We were in compliance with those covenants as of December 31, 2016.  

Second Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Second Lien PIK Toggle Notes on September 7, 2016, with a maturity date of May 15, 2020.  Cash interest accrues at 9.00% per annum and is payable on May 15 and November 15 of each year.  The Second Lien PIK Toggle Notes contain payment-in-kind (“PIK”) interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period.  We have the option for the first 18 months to pay all or a portion of interest in kind at a rate of 10.75% per annum, except that the initial interest payment on November 15, 2016 had to be paid solely using PIK.  The Second Lien PIK Toggle Notes are secured by a second-priority lien on all of our assets that are pledged under the Credit Agreement.  The Second Lien PIK Toggle Notes are effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien Term Loan.  For purposes of determining the gain from the Exchange Transaction under ASC 470-60, we assumed we will elect full use of the PIK option and these amounts will increase the principal amount.  This assumption for PIK utilization was also used in calculating the maturity amounts disclosed above.  All future undiscounted cash flows have been included in the carrying value under ASC 470-60.  The Second Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with those covenants as of December 31, 2016.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Third Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Third Lien PIK Toggle Notes on September 7, 2016, with a maturity date of June 15, 2021.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  Cash interest accrues at 8.50% per annum and is payable on June 15 and December 15 of each year.  The Third Lien PIK Toggle Notes contain PIK interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period.  We have the option for the first 24 months to pay all or a portion of interest in kind at a rate of 10.00% per annum, except that the initial interest payment on December 15, 2016 had to be paid solely using PIK.  The Third Lien PIK Toggle Notes are secured by a third-priority lien on all of our assets that are secured under the Credit Agreement.  The Third Lien PIK Toggle Notes are effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes.  For purposes of determining the gain from the Exchange Transaction under ASC 470-60, we assumed we will elect full use of the PIK option and these amounts will increase the principal amount.  All future undiscounted cash flows have been included in the carrying value under ASC 470-60.  The Third Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with those covenants as of December 31, 2016.

Unsecured Senior Notes

At December 31, 2016 and 2015, our outstanding Unsecured Senior Notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019, were classified as long-term at their carrying value.  Interest on the Unsecured Senior Notes is payable semi-annually in arrears on June 15 and December 15.  The estimated annual effective interest rate on the Unsecured Senior Notes is 8.4%, which includes amortization of debt issuance costs and premiums.  We and our restricted subsidiaries are subject to certain covenants under the indenture governing the Unsecured Senior Notes, which limit our and our restricted subsidiaries’ ability to, among other things, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of our assets, engage in transactions with affiliates, pay dividends or make other distributions on capital stock or subordinated indebtedness and create unrestricted subsidiaries.  We were in compliance with those covenants as of December 31, 2016.

For information about fair value measurements of our long-term debt, refer to Note 3.

3. Fair Value Measurements

Under GAAP, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  The fair value of an asset should reflect its highest and best use by market participants, whether using an in-use or an in-exchange valuation premise.  The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach.  The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs.  Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

Level 1 – quoted prices in active markets for identical assets or liabilities.

Level 2 – inputs other than quoted prices that are observable for an asset or liability.  These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

Level 3 – unobservable inputs that reflect our expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

The following table presents the fair value of our long-term debt (in thousands):

 

 

 

December 31,

 

 

Hierarchy

 

2016

 

 

2015

 

11.00% 1.5 Lien Term Loan, due November 2019

Level 2

 

$

75,000

 

 

$

 

9.00 % Second Lien Term Loan, due May 2020

Level 2

 

 

255,000

 

 

 

217,500

 

9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020

Level 2

 

 

122,255

 

 

 

 

8.50%/10.00% Third Lien PIK Toggle Notes due June 2021

Level 2

 

 

80,243

 

 

 

 

8.50% Unsecured Senior Notes, due June 2019

Level 2

 

 

123,389

 

 

 

324,000

 

The fair value of long-term debt is based on quoted prices, although the market is not an active market; therefore, the fair value is classified within Level 2.  An exception is the fair value of the 1.5 Lien Term Loan, which is held by one entity, and was not traded since its inception in September 2016.  As the 1.5 Lien Term Loan was recently executed, the fair value was assumed to be the carrying value, excluding amounts recorded for future interest payments.  

As of December 31, 2016, there were no open derivatives financial instruments.  As of December 31, 2015, the carrying value of our open derivative financial instruments equaled the estimated fair value.  We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy.  The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity futures prices.  

The carrying value of our long-term debt is disclosed in Note 2 above.  For additional information about our derivative financial instruments, refer to Note 8.

4. Asset Retirement Obligations  

Asset retirement obligations associated with the retirement of tangible long-lived assets are required to be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset.  The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset.  The fair value of the ARO is measured using expected cash outflows associated with the ARO, discounted at our credit-adjusted risk-free rate when the liability is initially recorded.  Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a reconciliation of our ARO liability (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

Asset retirement obligations, beginning of period

$

378,322

 

 

$

390,568

 

Liabilities settled

 

(72,320

)

 

 

(32,555

)

Accretion of discount

 

17,571

 

 

 

20,703

 

Disposition of properties

 

 

 

 

(8,581

)

Liabilities assumed through acquisition

 

 

 

 

2,944

 

Liabilities incurred

 

398

 

 

 

4,780

 

Revisions of estimated liabilities

 

10,467

 

 

 

463

 

Asset retirement obligations, end of period

 

334,438

 

 

 

378,322

 

Less current portion

 

78,264

 

 

 

84,335

 

Long-term

$

256,174

 

 

$

293,987

 

During 2016, we decreased our ARO on an overall basis primarily due to plug and abandonment work performed during 2016, partially offset by increases from accretion and revisions of previous estimates.  Upward revisions were primarily related to sustained casing pressure issues for idle iron at our West Cameron fields identified while performing preliminary plug and abandonment work at these fields.  In addition, increases were attributable to non-operated properties.  Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations.

During 2015, we decreased our ARO on an overall basis primarily due to plug and abandonment work performed during 2015, partially offset by increases from accretion.  Revisions were basically flat as some service providers reduced their costs of goods and services, some service provider costs remained flat and some service provider costs estimates were increased, all of which were incorporated into our estimates.  In addition, revisions were made for scope changes and on the estimates of timing of when the work will be performed.  Liability increases from acquisitions and wells drilled were basically offset by reductions from dispositions.    

5. Insurance Claims

During the third quarter of 2008, Hurricane Ike caused substantial damage to certain of our properties.  Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.

For 2016, 2015 and 2014, we received insurance reimbursements of $10.2 million, $0.2 million and $12.2 million, respectively, primarily related to hurricane damage.  In addition, we recorded receivables of $30.1 million as of December 31, 2016 for recent settlements with certain insurance companies related to Hurricane Ike claims within Receivables – Joint interest, insurance reimbursements and other on the Consolidated Balance Sheets.  Cash receipts from insurance proceeds are included within Net cash provided by operating activities in the Consolidated Statements of Cash Flows and are primarily recorded as reductions in Oil and natural gas properties and equipment on the Consolidated Balance Sheets, with some amounts recorded as reductions in Lease operating expense, General and administrative expenses and Other income (expense), net in the Consolidated Statements of Operations.  From the third quarter of 2008 through December 31, 2016, we have received $171.4 million cumulative reimbursements from insurance companies related to hurricane reimbursements.    

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Restricted Deposits

Restricted deposits as of December 31, 2016 and 2015 consisted of funds escrowed for collateral related to the future plugging and abandonment obligations of certain oil and natural gas properties.

Pursuant to the Purchase and Sale Agreement with Total E&P USA Inc. (“Total E&P”), security for future plugging and abandonment of certain oil and natural gas properties is required either through surety bonds or payments to an escrow account or a combination thereof.  Monthly payments are made to an escrow account and these funds are returned to us once verification is made that the security amount requirements have been met.  See Note 15 for potential future security requirements.

7. Acquisitions and Divestitures

2015 Divestiture

On October 15, 2015, we sold certain onshore oil and natural gas property interests to Ajax Resources, LLC (“Ajax”) for approximately $370.9 million in cash, which includes certain customary price adjustments, and Ajax assumed responsibility for the related ARO.  The effective date of the sale was January 1, 2015.  A net purchase price adjustment of $0.9 million for final customary effective date adjustments was recorded during 2016.  Ajax acquired all of our interest in the Yellow Rose field in the Permian Basin, covering approximately 25,800 net acres in Andrews, Martin, Gaines and Dawson counties in West Texas.  We retained a non-expense bearing overriding royalty interest (“ORRI”) equal to a variable percentage in production from the working interests assigned to Ajax, which percentage varies on a sliding scale from one percent for each month that the prompt month New York Mercantile Exchange (“NYMEX”) trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than $90.00 per barrel.  We used a portion of the proceeds of the sale to repay all outstanding borrowings under the revolving bank credit facility, while the remaining balance of approximately $100.0 million was added to available cash.

Under the full-cost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the cost center.  The sale to Ajax did not represent greater than 25% of our proved reserves of oil and natural gas attributable to the full cost pool.  As a result, alteration in the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool was not deemed significant and no gain or loss was recognized from the sale.        

2014 Acquisitions

Fairway

On September 15, 2014, the Parent Company entered into an asset purchase agreement with a third party to increase its ownership interest from 64.3% to 100% in the Mobile Bay blocks 113 and 132 (the “Fairway Field”) and the associated Yellowhammer gas processing plant (collectively, “Fairway”).  The Fairway Field is located in the state waters of Alabama and the Yellowhammer gas processing plant is located in the state of Alabama.  The effective date of the transaction was July 1, 2014.  The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO.  A net purchase price increase of $1.3 million for customary final closing adjustments was recorded in 2015.  The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table presents the purchase price allocation, including estimated adjustments, for the increased ownership interest in Fairway (in thousands):  

Cash consideration:

 

 

 

Evaluated properties including equipment

$

18,693

 

Non-cash consideration:

 

 

 

Asset retirement obligations - non-current

 

6,124

 

Total consideration

$

24,817

 

The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value.  See Note 1 for a description of the Level 3 inputs.  No goodwill was recorded in connection with the acquisition of this additional working interest in Fairway.

Woodside Properties  

On May 20, 2014, Energy VI entered into a purchase and sale agreement to acquire certain oil and natural gas property interests from Woodside Energy (USA) Inc. (“Woodside”).  The properties acquired from Woodside (the “Woodside Properties”) consisted of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks.  All of the Woodside Properties are located in the Gulf of Mexico.  The effective date of the transaction was November 1, 2013.  The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO.  A net purchase price increase of $0.2 million for customary final closing adjustments was recorded in 2015.  The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

The following table presents the purchase price allocation, including estimated adjustments, for the acquisition of the Woodside Properties (in thousands):  

Cash consideration:

 

 

 

Evaluated properties including equipment

$

52,347

 

Unevaluated properties

 

2,660

 

Sub-total cash consideration

 

55,007

 

Non-cash consideration:

 

 

 

Asset retirement obligations - current

 

782

 

Asset retirement obligations - non-current

 

10,543

 

Sub-total non-cash consideration

 

11,325

 

Total consideration

$

66,332

 

The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value.  See Note 1 for a description of the Level 3 inputs.  No goodwill was recorded in connection with the Woodside Properties acquisition.

2014 Acquisitions — Revenues, Net Income and Pro Forma Financial Information - Unaudited  

The increase in working interest ownership for Fairway was not included in our consolidated results until the property transfer date, which occurred in September 2014 and the incremental revenue and operating expenses were immaterial for 2014.  Unaudited pro forma information is not presented as the pro forma information is not materially different from the reported results for 2014 and 2013.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Woodside Properties were not included in our consolidated results until the property transfer date, which occurred on May 20 2014.  For 2015, the Woodside Properties accounted for $24.4 million of revenues, $9.5 million of direct operating expenses, $14.4 million of depreciation, depletion, amortization and accretion (“DD&A”) and no income tax expense, resulting in $0.5 million of net income.  For the period of May 20, 2014 to December 31, 2014, the Woodside Properties accounted for $28.4 million of revenues, $5.5 million of direct operating expenses, $11.0 million of DD&A and $4.2 million of income taxes, resulting in $7.7 million of net income.  The net income attributable to the Woodside Properties does not reflect certain expenses, such as general and administrative expenses (“G&A”) and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis.  In addition, the Woodside Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate.    

In accordance with the applicable accounting guidance, the unaudited pro forma financial information was computed as if the acquisition of the Woodside Properties had been completed on January 1, 2013.  The financial information was derived from W&T’s audited historical consolidated financial statements for annual periods, W&T’s unaudited historical condensed consolidated financial statements for interim periods, and the Woodside Properties’ unaudited historical financial statements for the annual and interim periods.

The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Woodside Properties.  The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2013.  Had we owned the Woodside Properties during the periods indicated, the results may have been substantially different.  For example, we may have operated the assets differently than Woodside; the realized sales prices for oil, NGLs and natural gas may have been different; and the costs of operating the Woodside Properties may have been different.

The following table presents a summary of our pro forma financial information (in thousands, except earnings per share):

 

 

(unaudited)

 

 

 

December 31, 2014 (a)

 

Revenue

 

$

971,595

 

Net loss

 

 

(5,504

)

Basic and diluted loss per common share

 

 

(0.08

)

For the pro forma financial information, certain information was derived from our financial records, Woodside’s financial records and certain information was estimated.  

The following table presents incremental items included in the pro forma information reported above for the Woodside Properties (in thousands):

 

 

(unaudited)

 

 

 

December 31, 2014 (a)

 

Revenues (b)

 

$

22,887

 

Direct operating expenses (b)

 

 

4,417

 

DD&A (c)

 

 

8,385

 

G&A (d)

 

 

300

 

Interest expense (e)

 

 

330

 

Capitalized interest (f)

 

 

(19

)

Income tax expense (g)

 

 

3,316

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The sources of information and significant assumptions are described below:

(a)

The adjustments for 2014 are for the period from January 1, 2014 to May 20, 2014.

(b)

Revenues and direct operating expenses for the Woodside Properties were derived from the historical financial records of Woodside.

(c)

DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Woodside Properties’ costs, reserves and production into our full cost pool in order to compute such amounts.  The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation.  ARO was estimated by W&T management.

(d)

Estimated insurance costs related to the Woodside Properties.

(e)

The acquisition was assumed to be funded entirely with borrowed funds.  Interest expense was computed using assumed borrowings of $55.0 million, which equates to the cash component of the acquisition purchase price, and an interest rate of 1.8%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility.

(f)

The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings.  The negative amount represents a decrease to net expenses.

(g)

Income tax expense was computed using the 35% federal statutory rate.

The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures.

8.  Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our oil and natural gas.  All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility.  We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations.  Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders, and we do not require collateral from our derivative counterparties.

Each derivative contract is recorded on the balance sheet as an asset or liability at fair value as of the respective period.  We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all changes in the fair value of derivative contracts were recognized currently in earnings during the periods presented.  The cash flows of all of our commodity derivative contracts are included in Net cash provided by operating activities on the Consolidated Statements of Cash Flows. While these contracts are intended to reduce the effects of price volatility, they may have limited incremental income from favorable price movements.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Commodity Derivatives

As of December 31, 2016, we did not have any open derivative contracts.  During 2015, we entered into crude oil and natural gas derivative contracts for a portion of our anticipated future production.  Some of the commodity derivative contracts are known as “three-way collars” consisting of a purchased put option, a sold call option and a purchased call option, each at varying strike prices.  The strike prices of the contracts were set so that the contracts were premium neutral (“costless”), which means no net premium was paid to or received from a counterparty.  The three-way collar contracts are structured to provide price risk protection if the commodity price falls below the strike price of the put option and provides us the opportunity to benefit if the commodity price rises above the strike price of the purchased call option.  In addition, we entered into oil derivative contracts known as “two-way”, “costless” collars, which consist of a purchased put option and a sold call option.  These two-way collars provide price risk protection if crude oil prices fall below certain levels, but have the potential to limit incremental income from favorable price movements above certain limits.  The oil contracts are based on WTI crude oil prices as quoted off the NYMEX.  The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX.  During 2014, we used crude oil swap contracts and have used various derivative instruments in prior years to manage our exposure to commodity price risk from sales of our oil and natural gas.  

The following balance sheet line items included amounts related to the estimated fair value of our open commodity derivative contracts as reported in the following table (in thousands):

 

December 31,

 

 

2016

 

 

2015

 

Prepaid and other assets - current

$

 

 

$

7,672

 

Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Derivative (gain) loss

$

2,926

 

 

$

(14,375

)

 

$

(3,965

)

Cash receipts (payments), net, on commodity derivative contract settlements are included within Net cash provided by operating activities on the Consolidated Statements of Cash Flows and were as follows (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Cash receipts (payments) on derivative settlements, net

$

4,746

 

 

$

6,703

 

 

$

(5,318

)

Offsetting Commodity Derivatives

During 2016 and 2015, all our commodity derivative contracts permit netting of derivative gains and losses upon settlement.  In general, the terms of the contracts provide for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same commodity.  If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our derivative instruments.  If we were required to settle all of our open derivative contracts, we would be able to net payments and receipts per counterparty pursuant to the derivative contracts.  Although our derivative contracts allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability.   For the open derivative contracts as of December 31, 2015, there would have been no difference if the contracts were presented on net basis.  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Equity Transactions

During 2016, after receiving shareholder approval, the Company increased the amount of common stock authorized from 118.3 million shares to 200.0 million shares, which allowed for the issuance of 60.4 million additional shares in conjunction with the Exchange Transaction.  

During 2016 and 2015, we did not pay any dividends and dividends are currently suspended.  During 2014, we paid regular cash dividends of $0.40 per common share.    

10.  Share-Based Awards and Cash-Based Awards

Common Stock

A grant

Additional

Retained

Total

Outstanding

Paid-In

Earnings

Treasury Stock

Shareholders’

Shares

Value

Capital

(Deficit)

Shares

Value

Equity (Deficit)

Balances at December 31, 2013

75,592

$

1

$

403,564

$

161,212

2,869

$

(24,167

)

$

540,610

Cash dividends

(30,260

)

(30,260

)

Share-based compensation

14,744

14,744

Stock issued

307

RSUs and issuance of 42,547 shares of common stock was made in March 2014 to the CEO pursuant to the terms of his 2013 annual incentive compensation award.  The number of shares was determined after deductionssurrendered

  for withholding and payroll taxes

(848

)

(848

)

Other

(2,880

)

(397

)

(3,277

)

Net loss

(11,661

)

(11,661

)

Balances at December 31, 2014

75,899

1

414,580

118,894

2,869

(24,167

)

509,308

Share-based compensation

10,242

10,242

Stock issued

607

RSUs and the shares were valued at the Company’s closing price as of the date of grant.  The grant and issuance of shares of common stock pursuant to the terms of the CEO’s 2014 annual incentive compensation award will be made during the first quarter of 2015.  See Note 10 for additional information concerning the CEO annual incentive compensation award.surrendered

  Share-Based Compensationfor payroll taxes

A summary of

(674

)

(674

)

Other

(649

)

(649

)

Net loss

(1,044,718

)

(1,044,718

)

Balances at December 31, 2015

76,506

1

423,499

(925,824

)

2,869

(24,167

)

(526,491

)

Share-based compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):

11,013

11,013

Stock issued

61,168

106,366

106,366

RSUs surrendered

   for payroll taxes

(905

)

(905

)

Net loss

(249,020

)

(249,020

)

Balances at December 31, 2016

137,674

$

1

$

539,973

$

(1,174,844

)

2,869

$

(24,167

)

$

(659,037

)

See accompanying notes.


W&T Offshore, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities:

 

 

 

 

 

 

 

 

 

 

 

Net loss

$

(249,020

)

 

$

(1,044,718

)

 

$

(11,661

)

Adjustments to reconcile net loss to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

211,609

 

 

 

394,071

 

 

 

511,102

 

Ceiling test write-down of oil and gas properties

 

279,063

 

 

 

987,238

 

 

 

 

Gain on exchange of debt

 

(123,923

)

 

 

 

 

 

 

Debt issuance costs write-down/amortization of debt items

 

2,548

 

 

 

4,411

 

 

 

701

 

Share-based compensation

 

11,013

 

 

 

10,242

 

 

 

14,744

 

Derivative (gain) loss

 

2,926

 

 

 

(14,375

)

 

 

(3,965

)

Cash receipts (payments) on derivative settlements, net

 

4,746

 

 

 

6,703

 

 

 

(5,318

)

Deferred income taxes

 

28,392

 

 

 

(203,272

)

 

 

(4,760

)

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas receivables

 

(7,005

)

 

 

32,236

 

 

 

29,510

 

Joint interest receivables and insurance

 

(1,126

)

 

 

21,633

 

 

 

(4,255

)

Income taxes

 

(64,274

)

 

 

(7

)

 

 

3,143

 

Prepaid expenses and other assets

 

(14,946

)

 

 

17,816

 

 

 

15,012

 

Asset retirement obligation settlements

 

(72,320

)

 

 

(32,555

)

 

 

(74,313

)

Accounts payable, accrued liabilities and other

 

6,497

 

 

 

(46,195

)

 

 

4,881

 

Net cash provided by operating activities

 

14,180

 

 

 

133,228

 

 

 

474,821

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

Acquisition of property interest in oil and natural gas properties

 

 

 

 

 

 

 

(72,234

)

Investment in oil and natural gas properties and equipment

 

(48,606

)

 

 

(230,161

)

 

 

(554,378

)

Changes in operating assets and liabilities associated with investing activities

 

(35,194

)

 

 

(55,425

)

 

 

37,450

 

Net proceeds from sales of assets

 

1,500

 

 

 

372,939

 

 

 

 

Purchases of furniture, fixtures and other

 

(96

)

 

 

(1,278

)

 

 

(3,340

)

Net cash provided by (used in) investing activities

 

(82,396

)

 

 

86,075

 

 

 

(592,502

)

Financing activities:

 

 

 

 

 

 

 

 

 

 

 

Borrowings of long-term debt - revolving bank credit facility

 

340,000

 

 

 

263,000

 

 

 

556,000

 

Repayments of long-term debt - revolving bank credit facility

 

(340,000

)

 

 

(710,000

)

 

 

(399,000

)

Issuance of 1.5 Lien Term Loan

 

75,000

 

 

 

 

 

 

 

Issuance of Second Lien Term Loan

 

 

 

 

297,000

 

 

 

 

Payment of interest on 1.5 Lien Term Loan

 

(2,570

)

 

 

 

 

 

 

Debt exchange/issuance costs

 

(18,464

)

 

 

(6,669

)

 

 

 

Dividends to shareholders

 

 

 

 

 

 

 

(30,260

)

Other

 

(928

)

 

 

(886

)

 

 

(1,193

)

Net cash provided by (used in) financing activities

 

53,038

 

 

 

(157,555

)

 

 

125,547

 

Increase (decrease) in cash and cash equivalents

 

(15,178

)

 

 

61,748

 

 

 

7,866

 

Cash and cash equivalents, beginning of period

 

85,414

 

 

 

23,666

 

 

 

15,800

 

Cash and cash equivalents, end of period

$

70,236

 

 

$

85,414

 

 

$

23,666

 

See accompanying notes.


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Significant Accounting Policies

Operations

W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”, is an independent oil and natural gas producer focused primarily in the Gulf of Mexico.  On October 15, 2015, a substantial amount of our interest in onshore acreage was sold, which is described in Note 7.  We are active in the exploration, development and acquisition of oil and natural gas properties.  Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our wholly-owned subsidiary, W & T Energy VI, LLC (“Energy VI”).  

Basis of Presentation

Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries.  All significant intercompany transactions and amounts have been eliminated for all years presented.  Our consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) and the appropriate rules and regulations of the Securities and Exchange Commission (���SEC”).

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves.  Actual results could differ from those estimates.

Early Adoption of Accounting Standard Amendments

Accounting Standards Update No. 2016-09 (“ASU 2016-09”), Compensation – Stock Compensation (Subtopic 718) was early adopted as of December 31, 2016.  The amendment’s objective is simplification of several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the Consolidated Statements of Cash Flows.  The early adoption affected the statements of cash flows as to the classification of cash paid for employee income taxes and payroll taxes, which were funded through the forfeiture of vested restricted stock units (“RSUs”).  Previously, these cash payments were classified as operating activities.  The updated standard requires such cash transactions be classified as financing activities. The reclassification was applied retrospectively on the statements of cash flows for the years 2014 and 2015 and resulted in reclassification of $0.8 million and $0.7 million, respectively.  None of the other amendments under ASU 2016-09 had an effect on our financial statements and the early adoption of ASU 2016-09 did not affect the Consolidated Balance Sheets, Consolidated Statements of Operations or the Consolidated Statements of Changes in Shareholders’ Equity (Deficit).  

90


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Recent Events

The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital and future rate of growth.  The prices of these commodities began falling in the second half of 2014, were significantly lower during 2015 and lower still in 2016 compared to prior years.  

We took a number of  steps during 2015 and 2016 to mitigate the effects of these lower prices including: (i) significantly reducing capital spending from previous year levels and budgeting conservative capital spending for 2017 (exclusive of acquisitions); (ii) restructuring our debt and issuing our common stock through an exchange transaction, which is described in Note 2, (iii) receiving funds through two debt issuances, which are described in Note 2 (iv) suspending our quarterly common stock dividend; (iv) implementing numerous cost reduction projects to reduce our operating costs; and (v) selling our interest in the Yellow Rose onshore field, which is described in Note 7.

During 2016, the Bureau of Ocean Energy Management (“BOEM”) issued orders to us concerning financial assurances related to plug and abandonment (decommissioning) obligations for Federal offshore leases, including an order issued to us in December 2016 regarding additional security required for sole liability properties.  In July 2016, effective September 2016, the BOEM issued Notice to Lessees #2016-N01 (“NTL #2016-N01”), related to obligations for decommissioning activities on the Outer Continental Shelf (“OCS”) for leases, rights-of-way (“ROWs”) or rights of use and easement (“RUEs”).  In January 2017, the BOEM extended the implementation timeline by an additional six months of NTL #2016-N01 as to leases, ROWs and RUEs for which there are co-lessees and/or predecessors in interest (non-sole liability properties), with certain exceptions.  In February 2017, the BOEM withdrew the sole liability orders it had issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program.  See Note 17 and 19 for additional information.      

We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations for at least 12 months from the date of issuance of this Form 10-K, which is the threshold of a going concern under GAAP; however, we cannot predict with any certainty future commodity prices or the actions of the BOEM concerning financial assurance requirements, either of which could affect our operations and liquidity levels.

Cash Equivalents

We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents.

Revenue Recognition

We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured.  We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership.  Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production.  These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production.  We do not record receivables for those properties in which we have taken less than our ownership share of production.  At December 31, 2016 and 2015, $5.3 million and $6.9 million, respectively, were included in current liabilities related to natural gas imbalances.

91


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Concentration of Credit Risk

Our customers are primarily large integrated oil and natural gas companies and large financial institutions.  The majority of our production is sold utilizing month-to-month contracts that are based on bid prices.  We also have receivables from joint interest owners on properties we operate and we may have the ability to withhold future revenue disbursements to recover amounts due us.  We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guaranties when considered necessary.  We historically have not had any significant problems collecting our receivables, but with the decline in commodity prices, several oil and gas companies have filed for bankruptcy, including some of our joint interest partners.  We use the specific identification method of determining if an allowance for doubtful accounts is needed.  As of December 31, 2016 and 2015, $7.6 million and $2.5 million, respectively, were recorded as an allowance for doubtful accounts.  During 2016 and 2015, there were no reductions recorded in the allowance for doubtful accounts (no collections of accounts previously reserved and no permanent write-off of receivable accounts).  

The following identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas.

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Customer

 

 

 

 

 

 

 

 

 

 

 

Shell Trading (US) Co.

 

43

%

 

 

50

%

 

 

47

%

Vitol Inc.

 

20

%

 

**

 

 

**

 

J. P. Morgan

**

 

 

 

14

%

 

**

 

** Less than 10%

We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing.

Insurance Receivables

We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance company’s adjuster reviews and approves such costs for payment or when the insurance company has agreed to reimbursement amounts.  Claims that have been processed in this manner have customarily been paid on a timely basis.  See Note 5, 17 and 19 for information related to settlement of previously unpaid claims by certain insurance companies.

Prepaid expenses and other

Amounts recorded in Prepaid expenses and other on the Consolidated Balance Sheets are expected to be realized within one year.  Items representing 5% or more of total current assets in either period presented are disclosed in the following table:  

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Share-based compensation expense from:

 

 

 

 

 

 

 

 

 

 

 

Restricted stock

$

369

 

 

$

397

 

 

$

399

 

Restricted stock units

 

13,150

 

 

 

11,128

 

 

 

11,999

 

Common shares

 

1,225

 

 

 

 

 

 

 

Total

$

14,744

 

 

$

11,525

 

 

$

12,398

 

Share-based compensation tax benefit:

 

 

 

 

 

 

 

 

 

 

 

Tax benefit computed at the statutory rate

$

5,160

 

 

$

4,034

 

 

$

4,339

 

92


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Year Ended December 31,

 

 

2016

 

 

2015

 

Derivative assets - current (1)

$

 

 

$

10,036

 

Prepaid/accrued  insurance and surety bonds

 

5,386

 

 

 

7,475

 

Prepaid deposits related to royalties

 

6,237

 

 

 

5,943

 

Other (2)

 

2,881

 

 

 

3,425

 

Prepaid expenses and other

$

14,504

 

 

$

26,879

 

As

(1)

Includes open and closed (and not yet collected) derivative commodity contracts recorded at fair value as of December 31, 2014, unrecognized2015.

(2)

Individual items were less than 5% of total current assets for either period presented.

Properties and Equipment

We use the full-cost method of accounting for oil and natural gas properties and equipment.  Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized.  Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties.  Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs.  Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines.  Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred.

Oil and natural gas properties and equipment include costs of unproved properties.  The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as we have made an evaluation that impairment has occurred.  The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial.

We capitalize interest on the amount of unproved properties that are excluded from the amortization base.  Interest is capitalized only for the period that exploration and development activities are in progress.  Capitalization of interest ceases when the property is moved into the amortization base.  All capitalized interest is recorded within Oil and natural gas property and equipment on the Consolidated Balance Sheets.

Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities.  In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves.  Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense.

Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years.  Leasehold improvements are amortized over the shorter of their economic lives or the lease term.  Repairs and maintenance costs are expensed in the period incurred.

93


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Ceiling Test Write-Down

Under the full-cost method of accounting, we are required to perform a “ceiling test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties.  If the net capitalized cost of oil and natural gas properties (including capitalized ARO) net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed.  Any such write downs are not recoverable or reversible in future periods.  The ceiling test limit is calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects.  Estimated future net revenues used in the ceiling test for each period are based on current prices for each product, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the prior twelve months for that period.  All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials.

Due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas, we recorded ceiling test write-downs in 2015 and 2016, which are reported as a separate line in the Statements of Operations.  The average price using the SEC required methodology at December 31, 2016 was $39.25 per barrel for West Texas Intermediate (“WTI”) crude oil and $2.48 per million British Thermal Unit  (“MMBtu”) for Henry Hub natural gas.  These prices are before adjustments for quality, transportation, fees, energy content and regional price differentials.   The ceiling test write-downs of the carrying value of our oil and natural gas properties were $279.1 million and $987.2 million for 2016 and 2015, respectively.  There was no ceiling test write-down in the fourth quarter of 2016.  We did not record a ceiling test write-down during 2014.  If average crude oil and natural gas prices decrease from 2016 levels, it is possible that a ceiling test write-down will be recorded during 2017.  

Asset Retirement Obligations

We are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet.  We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations.  These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup.  Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal.  Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period.  For additional information, refer to Note 4.

Oil and Natural Gas Reserve Information

We use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves.  Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices.  Proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years, with some limited exceptions allowed.  Refer to Note 21 for additional information about our proved reserves.

Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and interest rates.  From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our credit facility.  As of December 31, 2016, we did not have any open derivative financial instruments.  We do not enter into derivative instruments for speculative trading purposes.

94


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value.  Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into.  Whenever we have entered into derivative contracts, we did not designate our commodity derivatives as hedging instruments, therefore, all changes in fair value are recognized in earnings.

Fair Value of Financial Instruments

We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance.  We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments.  We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments.  We believe the carrying amount of debt under our 11.00% 1.5 Lien Term Loan, due November 2019, (the “1.5 Lien Term Loan”) approximates fair value because the debt was recently executed and reflective of market rates and conditions.

Fair Value of Acquisitions

Acquisitions are recorded on the closing date of the transaction at their fair value, which is determined by applying the market and income approaches using Level 3 inputs.  The Level 3 inputs are: (i) analysis of comparable transactions obtained from various third-parties, (ii) estimates of ultimate recoveries of reserves, and (iii) estimates of discounted cash flows based on estimated reserve quantities, reserve categories, timing of production, costs to produce and develop reserves, future prices, ARO and discount rates.  The estimates and assumptions are determined by management and third-parties.  The fair value is based on subjective estimates and assumptions, which are inherently imprecise, and the actual realized values can vary significantly from estimates that are made.

Income Taxes

We use the liability method of accounting for income taxes in accordance with the Income Taxes topic of the Accounting Standard Codification.  Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements.  In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.  We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken.  When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense.  See Note 12 for additional information.

Troubled Debt Restructuring  

We accounted for an exchange transaction, which is described in Note 2, as a troubled debt restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”).  Under ASC 470-60, the carrying value of the newly issued debt, as described in Note 2, is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the newly issued debt in the Consolidated Statements of Operations for the period from September 7, 2016 to December 31, 2016.  Additionally, no interest expense related to the newly issued debt will be recorded in future periods as payments of interest on the newly issued debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the newly issued debt.  See Note 2 for additional information.    

95


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Debt Issuance Costs

Debt issuance costs associated with our revolving bank credit facility are amortized using the straight-line method over the scheduled maturity of the debt.  Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method.  Unamortized debt issuance costs associated with our revolving bank credit facility is reported within Other Assets (noncurrent) and unamortized debt issuance costs associated with our other debt is reported as a reduction in Long-Term Debt, less current maturities in the Consolidated Balance Sheets.  See Note 2 for additional information.  

Premiums Received and Discounts Provided on Debt Issuance

Premiums and discounts are recorded in Long-Term Debt, less current maturities in the Consolidated Balance Sheets and are amortized over the term of the related debt using the effective interest method.

Share-Based Compensation

Compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award.  The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant.  We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award.  Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests.  See Note 10 for additional information.

Loss Per Share

Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of loss per share under the two-class method when the effect is dilutive.  For additional information, refer to Note 13.

Other (Income) Expense, Net  

For 2016, the amount includes $7.7 million of income related to the settlement of certain insurance claims.  In 2016 and 2015, the amount includes write-offs of debt issuance costs of $1.4 million and $3.2 million, respectively, related to a reduction in the borrowing base of the revolving bank credit facility under the Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”).  The write-offs of debt issuance costs in both 2016 and 2015 are included as an adjustment to net income in determining Net cash provided by operating activities in the Consolidated Statements of Cash Flows as the write-offs were non-cash transactions.  

Recent Accounting Developments

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Subtopic 606).  ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance.  The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017.  Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application.  Our current intention is to adopt the standard utilizing the modified retrospective approach.  Our evaluation to date is the adoption of ASU 2014-09 is not expected to have a material impact on our consolidated financial statements.  We have not fully completed our analysis and subsequent guidance may change this assessment.  Our disclosures related to revenue will be modified when the new guidance is effective.  ASU 2014-09 will be effective for us in the first quarter of 2018.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases (Subtopic 842).  Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Consistent with current GAAP, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease.  However, unlike current GAAP, which requires only capital leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet.  ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases.  These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements.  ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources.  Our current operating leases that will be impacted by ASU 2016-02 when it is effective are leases for office space in Houston and New Orleans, although ASU 2016-02 may impact the accounting for leases related to operations equipment depending on the term of the lease.  We currently do not have any leases classified as financing leases.  ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach.  We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.  

In June 2016, the FASB issued Accounting Standards Update No. 2016-13, (“ASU 2016-13”), Financial Instruments – Credit Losses (Subtopic 326).  The new guidance eliminates the probable recognition threshold and broadens the information to consider past events, current conditions and forecasted information in estimating credit losses.  ASU 2016-13 is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted for fiscal years beginning after December 15, 2018.  We have not yet fully determined or quantified the effect ASU 2016-13 will have on our financial statements.

In August 2016, the FASB issued Accounting Standards Update No. 2016-15, (“ASU 2016-15”), Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments.  ASU 2016-15 addresses the classification of several items that previously had diversity in practice.  Items identified in the new standard which were incurred by us in the past are: (a) debt prepayment or extinguishment costs; (b) contingent consideration made after a business acquisition; and (c) proceeds from settlement of insurance claims.  The item described in clause (b) would be the only such item changed under our historical classification in the Statement of Cash Flows (financing vs. investing) and the amount of such change would not be material; therefore, we do not anticipate the new standard will have a material effect on our Statement of Cash Flows.  ASU 2016-15 is effective for fiscal years beginning after December 15, 2017 and early adoption is permitted.  

In November 2016, the FASB issued Accounting Standards Update No. 2016-18, (“ASU 2016-18”), Statement of Cash Flows (Topic 230) – Restricted Cash.  ASU 2016-18 addresses diversity in practice and requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.  ASU 2016-18 is expected to change some of the presentation in our statement of cash flows, but not materially impact total cash flows from operating, investing or financing activities.  ASU 2016-18 is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years.  Early adoption is permitted, including adoption in an interim period.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Long-Term Debt

As of December 31, 2016 and 2015, our long-term debt was as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

December 31, 2016

 

 

2015

 

 

 

 

 

 

PIK Payable/

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Payable/

 

 

Carrying

 

 

Principal/

 

 

Principal

 

 

Other

 

 

Value

 

 

Other*

 

11.00% 1.5 Lien Term Loan,

     due November 2019

$

75,000

 

 

$

23,823

 

 

$

98,823

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9.00 % Second Lien Term Loan,

    due May 2020

 

300,000

 

 

 

 

 

 

300,000

 

 

 

300,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9.00%/10.75% Second Lien PIK Toggle Notes,

    due May 2020

 

163,007

 

 

 

60,898

 

 

 

223,905

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8.50%/10.00% Third Lien PIK Toggle Notes,

   due June 2021

 

145,897

 

 

 

67,549

 

 

 

213,446

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8.50% Unsecured Senior Notes,

    due June 2019

 

189,829

 

 

 

 

 

 

189,829

 

 

 

900,000

 

Subtotal

 

873,733

 

 

 

152,270

 

 

 

1,026,003

 

 

 

1,200,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt premium, discount, issuance costs,

     net of amortization

 

 

 

 

(5,276

)

 

 

(5,276

)

 

 

(3,145

)

Total long-term debt

 

873,733

 

 

 

146,994

 

 

 

1,020,727

 

 

 

1,196,855

 

Current maturities of long-term debt

 

 

 

 

8,272

 

 

 

8,272

 

 

 

 

Long term debt, less current maturities

$

873,733

 

 

$

138,722

 

 

$

1,012,455

 

 

$

1,196,855

 

* Amounts also equal carrying value

Aggregate annual maturities of amounts recorded for long-term debt as of December 31, 2016 are as follows (in millions): 2017–$8.2; 2018–$23.8; 2019–$303.7; 2020–$510.1; thereafter–$180.1.  See below for discussion on the determination of recorded amounts.    

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Exchange Transaction

On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our 8.500% Senior Notes (the “Unsecured Senior Notes”), due June 15, 2019, for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Senior Second Lien PIK Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); (ii) $142.0 million in aggregate principal amount of 8.50%/10.00% Senior Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”); and (iii) 60.4 million shares of our common stock (collectively, the “Debt Exchange”).  At the same time on closing on the Debt Exchange, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 2019, with the then largest holder of our Unsecured Senior Notes (collectively with the Debt Exchange, the “Exchange Transaction”).  We accounted for the Exchange Transaction as a Troubled Debt Restructuring pursuant to the guidance under ASC 470-60.  Under ASC 470-60, the carrying value of the newly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Consolidated Statements of Operations for the period from September 7, 2016 to December 31, 2016.  Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt.    

A gain of $123.9 million was recognized related to the Exchange Transaction.  Under ASC 470-60, a gain was recognized as the sum of (i) the future undiscounted payments (principal and interest) related to the New Debt, (ii) the fair value of the common stock issued and (iii) deal transaction costs of $18.9 million was less than the sum of (iv) the carrying value of the Unsecured Senior Notes exchanged and (v) the funds received from the 1.5 Lien Term Loan.  The shares of common stock issued were valued at $1.76 per share, which was the closing price on September 7, 2016.  The effect on basic and diluted earnings per share for 2016 was a $1.30 per share, which assumes the gain would not affect income tax benefit for 2016.  

The funds received from the 1.5 Lien Term Loan were used to pay transaction costs related to the Exchange Transaction and to pay down borrowings on the revolving bank credit facility.  The balance of the borrowings on the revolving bank credit facility was paid down from available cash.

In conjunction with the Exchange Transactions, certain terms of our Credit Agreement were modified and are reflected in the description of the Credit Agreement below.

Credit Agreement

The Credit Agreement provides a revolving bank credit facility.  Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders (historically in the spring and fall), and we and our lenders may each request one additional determination per year.  The borrowing base as of December 31, 2016 was $150.0 million.  The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.  To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base, such excess or deficiency is required to be repaid within 90 days in three equal monthly payments.  Letters of credit may be issued in amounts up to $150.0 million, provided availability under the revolving bank credit facility exists.  The revolving bank credit facility is secured and is collateralized by our oil and natural gas properties.  The Credit Agreement terminates on November 8, 2018.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Credit Agreement contains covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock or outstanding debt; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) eliminate certain hedging contracts or enter into certain hedging contacts in excess of 75% of projected oil and gas  production on a monthly basis; (vii) enter into certain liens; and (viii) enter into certain other transactions, without the prior consent of the lenders.  We are permitted to issue additional indebtedness if certain conditions are met including: (i) the additional debt is subordinate in security and right of payment; (ii) the borrowers enter into an intercreditor agreement with terms acceptable to the Administrative Agent of the Credit Agreement; (iii) we are in compliance with the financial covenants after giving pro forma effect to the additional indebtedness; and (iv) such additional unsecured indebtedness matures at least six months after the maturity date of the Credit Agreement and is not subject to restrictive covenants materially more onerous than those provided for in the Credit Agreement.  With consent of the lenders, such limitation will not apply to the repurchase of our existing debt in an aggregate principal amount equal to or less than the aggregate principal amount of any new issuance of such debt.  We are permitted to redeem, repurchase, prepay or defease up to $35 million of our Unsecured Senior Notes if after giving effect to such redemption, repayment, prepayment or defeasance: (i) no amounts are outstanding on the revolving bank credit facility; (ii) letters of credit outstanding do not exceed $5 million; (iii) the Consolidated Cash balance is at least $35 million after the redemption or repayment; and (iv) no event of default shall have occurred and be continuing, and no borrowing base deficiency shall have occurred and be continuing or result therefrom.

The Credit Agreement also contains various customary covenants for certain financial tests, as defined in the Credit Agreement and measured as of the end of each quarter, and for customary events of default.  These financial test ratios and limits as of December 31, 2016 and thereafter are: (i) the First Lien Leverage Ratio must be less than 2.50 to 1.00 through June 30, 2017, then 2.00 to 1.00 thereafter; (ii) the Asset Coverage Ratio must be not less than 1.25 to 1.00 as of December 31, 2016, then is suspended thereafter; and (ii) the Current Ratio must be greater than 1.00 to 1.00.  As of December 31, 2016, the current ratio was 2.93 to 1.00.  As of December 31, 2016, the First Lien Leverage Ratio and the Asset Coverage Ratio were in compliance, but not meaningful as no borrowings were outstanding on the revolving bank credit facility and only minor amounts of letters of credit were outstanding.  The customary events of default include: (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Company or any of its subsidiaries guaranteeing borrowings under the revolving bank credit facility; or (iii) a change of control.  The Credit Agreement contains cross-default clauses with the other debt agreements, and these agreements contain similar cross-default clauses with the Credit Agreement.  We were in compliance with all applicable covenants of the Credit Agreement as of December 31, 2016.

We are required to have deposit accounts only with banks party to the Credit Agreement with certain exceptions.  We may not have unrestricted cash balances above $35 million if outstanding balances on the revolving bank credit agreement (including letters of credit) are greater than $5 million.

Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 3.00% to 4.00% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the greater of (a) Prime Rate, (b) Federal Funds Rate plus 0.50%, or (c) LIBOR plus 1.0%, plus applicable margin ranging from 2.00% to 3.00%.  The unused portion of the borrowing base is subject to a commitment fee of 0.50%.  The estimated annual effective interest rate was 3.3% for 2016 for borrowings under the Credit Agreement.  The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs.

During 2016 and 2015, the borrowing base under the Credit Agreement was reduced.  The reductions in the borrowing base resulted in proportional reductions in the unamortized costs related to the Credit Agreement of $1.4 million and $3.2 million in 2016 and 2015, respectively, which is included in the line Other (income)/expense, net on the Consolidated Statements of Operations.  

At December 31, 2016 and 2015, we had no borrowings outstanding under the revolving bank credit facility.  At December 31, 2016 and 2015, we had $0.5 million and $0.9 million, respectively, outstanding in letters of credit under the revolving bank credit facility.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1.5 Lien Term Loan

As part of the Exchange Transaction, we entered into the 1.5 Lien Term Loan on September 7, 2016 with a maturity date of November 15, 2019.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  Interest accrues at 11.00% per annum and is payable quarterly in cash.  The holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction.  The 1.5 Lien Term Loan is secured by a 1.5 priority lien on all of our assets pledged under the Credit Agreement.  The lien securing the 1.5 Lien Term Loan is subordinate to the liens securing the Credit Agreement and has priority above the liens securing the Second Lien Term Loan (defined below), the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes.  All future undiscounted cash flows have been included in the carrying value under ASC 470-60.  Current maturities of our long-term debt represent the cash interest payable for the 1.5 Lien Term Loan payable in the next 12 months.  The 1.5 Lien Term Loan contains various covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) enter into certain liens; and (vii) enter into transactions with affiliates.  We were in compliance with those covenants as of December 31, 2016.

Second Lien Term Loan

In May 2015, we entered into the 9.00% Term Loan (the “Second Lien Term Loan”), which bears an annual interest rate of 9.00%, was issued at a 1.0% discount to par and matures on May 15, 2020 and is recorded at its carrying value consisting of principal, unamortized discount and unamortized debt issuance costs.  Interest on the Second Lien Term Loan is payable in arrears semi-annually on May 15 and November 15.  The estimated annual effective interest rate on the Second Lien Term Loan is 9.7%, which includes amortization of debt issuance costs and discounts.  The Second Lien Term Loan is secured by a second-priority lien on all of our assets that are secured under the Credit Agreement.  The Second Lien Term Loan is effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien PIK Toggle Notes (discussed below).  We are subject to various covenants under the terms governing the Second Lien Term Loan including, without limitation, covenants that limit our ability to incur other debt, pay dividends or distributions on our equity, merge or consolidate with other entities and make certain investments in other entities.  We were in compliance with those covenants as of December 31, 2016.  

Second Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Second Lien PIK Toggle Notes on September 7, 2016, with a maturity date of May 15, 2020.  Cash interest accrues at 9.00% per annum and is payable on May 15 and November 15 of each year.  The Second Lien PIK Toggle Notes contain payment-in-kind (“PIK”) interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period.  We have the option for the first 18 months to pay all or a portion of interest in kind at a rate of 10.75% per annum, except that the initial interest payment on November 15, 2016 had to be paid solely using PIK.  The Second Lien PIK Toggle Notes are secured by a second-priority lien on all of our assets that are pledged under the Credit Agreement.  The Second Lien PIK Toggle Notes are effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien Term Loan.  For purposes of determining the gain from the Exchange Transaction under ASC 470-60, we assumed we will elect full use of the PIK option and these amounts will increase the principal amount.  This assumption for PIK utilization was also used in calculating the maturity amounts disclosed above.  All future undiscounted cash flows have been included in the carrying value under ASC 470-60.  The Second Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with those covenants as of December 31, 2016.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Third Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Third Lien PIK Toggle Notes on September 7, 2016, with a maturity date of June 15, 2021.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  Cash interest accrues at 8.50% per annum and is payable on June 15 and December 15 of each year.  The Third Lien PIK Toggle Notes contain PIK interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period.  We have the option for the first 24 months to pay all or a portion of interest in kind at a rate of 10.00% per annum, except that the initial interest payment on December 15, 2016 had to be paid solely using PIK.  The Third Lien PIK Toggle Notes are secured by a third-priority lien on all of our assets that are secured under the Credit Agreement.  The Third Lien PIK Toggle Notes are effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes.  For purposes of determining the gain from the Exchange Transaction under ASC 470-60, we assumed we will elect full use of the PIK option and these amounts will increase the principal amount.  All future undiscounted cash flows have been included in the carrying value under ASC 470-60.  The Third Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with those covenants as of December 31, 2016.

Unsecured Senior Notes

At December 31, 2016 and 2015, our outstanding Unsecured Senior Notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019, were classified as long-term at their carrying value.  Interest on the Unsecured Senior Notes is payable semi-annually in arrears on June 15 and December 15.  The estimated annual effective interest rate on the Unsecured Senior Notes is 8.4%, which includes amortization of debt issuance costs and premiums.  We and our restricted subsidiaries are subject to certain covenants under the indenture governing the Unsecured Senior Notes, which limit our and our restricted subsidiaries’ ability to, among other things, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of our assets, engage in transactions with affiliates, pay dividends or make other distributions on capital stock or subordinated indebtedness and create unrestricted subsidiaries.  We were in compliance with those covenants as of December 31, 2016.

For information about fair value measurements of our long-term debt, refer to Note 3.

3. Fair Value Measurements

Under GAAP, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  The fair value of an asset should reflect its highest and best use by market participants, whether using an in-use or an in-exchange valuation premise.  The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach.  The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs.  Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

Level 1 – quoted prices in active markets for identical assets or liabilities.

Level 2 – inputs other than quoted prices that are observable for an asset or liability.  These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

Level 3 – unobservable inputs that reflect our expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

The following table presents the fair value of our long-term debt (in thousands):

 

 

 

December 31,

 

 

Hierarchy

 

2016

 

 

2015

 

11.00% 1.5 Lien Term Loan, due November 2019

Level 2

 

$

75,000

 

 

$

 

9.00 % Second Lien Term Loan, due May 2020

Level 2

 

 

255,000

 

 

 

217,500

 

9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020

Level 2

 

 

122,255

 

 

 

 

8.50%/10.00% Third Lien PIK Toggle Notes due June 2021

Level 2

 

 

80,243

 

 

 

 

8.50% Unsecured Senior Notes, due June 2019

Level 2

 

 

123,389

 

 

 

324,000

 

The fair value of long-term debt is based on quoted prices, although the market is not an active market; therefore, the fair value is classified within Level 2.  An exception is the fair value of the 1.5 Lien Term Loan, which is held by one entity, and was not traded since its inception in September 2016.  As the 1.5 Lien Term Loan was recently executed, the fair value was assumed to be the carrying value, excluding amounts recorded for future interest payments.  

As of December 31, 2016, there were no open derivatives financial instruments.  As of December 31, 2015, the carrying value of our open derivative financial instruments equaled the estimated fair value.  We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy.  The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity futures prices.  

The carrying value of our long-term debt is disclosed in Note 2 above.  For additional information about our derivative financial instruments, refer to Note 8.

4. Asset Retirement Obligations  

Asset retirement obligations associated with the retirement of tangible long-lived assets are required to be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset.  The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset.  The fair value of the ARO is measured using expected cash outflows associated with the ARO, discounted at our credit-adjusted risk-free rate when the liability is initially recorded.  Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a reconciliation of our ARO liability (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

Asset retirement obligations, beginning of period

$

378,322

 

 

$

390,568

 

Liabilities settled

 

(72,320

)

 

 

(32,555

)

Accretion of discount

 

17,571

 

 

 

20,703

 

Disposition of properties

 

 

 

 

(8,581

)

Liabilities assumed through acquisition

 

 

 

 

2,944

 

Liabilities incurred

 

398

 

 

 

4,780

 

Revisions of estimated liabilities

 

10,467

 

 

 

463

 

Asset retirement obligations, end of period

 

334,438

 

 

 

378,322

 

Less current portion

 

78,264

 

 

 

84,335

 

Long-term

$

256,174

 

 

$

293,987

 

During 2016, we decreased our ARO on an overall basis primarily due to plug and abandonment work performed during 2016, partially offset by increases from accretion and revisions of previous estimates.  Upward revisions were primarily related to sustained casing pressure issues for idle iron at our West Cameron fields identified while performing preliminary plug and abandonment work at these fields.  In addition, increases were attributable to non-operated properties.  Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations.

During 2015, we decreased our ARO on an overall basis primarily due to plug and abandonment work performed during 2015, partially offset by increases from accretion.  Revisions were basically flat as some service providers reduced their costs of goods and services, some service provider costs remained flat and some service provider costs estimates were increased, all of which were incorporated into our estimates.  In addition, revisions were made for scope changes and on the estimates of timing of when the work will be performed.  Liability increases from acquisitions and wells drilled were basically offset by reductions from dispositions.    

5. Insurance Claims

During the third quarter of 2008, Hurricane Ike caused substantial damage to certain of our properties.  Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.

For 2016, 2015 and 2014, we received insurance reimbursements of $10.2 million, $0.2 million and $12.2 million, respectively, primarily related to hurricane damage.  In addition, we recorded receivables of $30.1 million as of December 31, 2016 for recent settlements with certain insurance companies related to Hurricane Ike claims within Receivables – Joint interest, insurance reimbursements and other on the Consolidated Balance Sheets.  Cash receipts from insurance proceeds are included within Net cash provided by operating activities in the Consolidated Statements of Cash Flows and are primarily recorded as reductions in Oil and natural gas properties and equipment on the Consolidated Balance Sheets, with some amounts recorded as reductions in Lease operating expense, General and administrative expenses and Other income (expense), net in the Consolidated Statements of Operations.  From the third quarter of 2008 through December 31, 2016, we have received $171.4 million cumulative reimbursements from insurance companies related to hurricane reimbursements.    

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Restricted Deposits

Restricted deposits as of December 31, 2016 and 2015 consisted of funds escrowed for collateral related to the future plugging and abandonment obligations of certain oil and natural gas properties.

Pursuant to the Purchase and Sale Agreement with Total E&P USA Inc. (“Total E&P”), security for future plugging and abandonment of certain oil and natural gas properties is required either through surety bonds or payments to an escrow account or a combination thereof.  Monthly payments are made to an escrow account and these funds are returned to us once verification is made that the security amount requirements have been met.  See Note 15 for potential future security requirements.

7. Acquisitions and Divestitures

2015 Divestiture

On October 15, 2015, we sold certain onshore oil and natural gas property interests to Ajax Resources, LLC (“Ajax”) for approximately $370.9 million in cash, which includes certain customary price adjustments, and Ajax assumed responsibility for the related ARO.  The effective date of the sale was January 1, 2015.  A net purchase price adjustment of $0.9 million for final customary effective date adjustments was recorded during 2016.  Ajax acquired all of our interest in the Yellow Rose field in the Permian Basin, covering approximately 25,800 net acres in Andrews, Martin, Gaines and Dawson counties in West Texas.  We retained a non-expense bearing overriding royalty interest (“ORRI”) equal to a variable percentage in production from the working interests assigned to Ajax, which percentage varies on a sliding scale from one percent for each month that the prompt month New York Mercantile Exchange (“NYMEX”) trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than $90.00 per barrel.  We used a portion of the proceeds of the sale to repay all outstanding borrowings under the revolving bank credit facility, while the remaining balance of approximately $100.0 million was added to available cash.

Under the full-cost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the cost center.  The sale to Ajax did not represent greater than 25% of our proved reserves of oil and natural gas attributable to the full cost pool.  As a result, alteration in the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool was not deemed significant and no gain or loss was recognized from the sale.        

2014 Acquisitions

Fairway

On September 15, 2014, the Parent Company entered into an asset purchase agreement with a third party to increase its ownership interest from 64.3% to 100% in the Mobile Bay blocks 113 and 132 (the “Fairway Field”) and the associated Yellowhammer gas processing plant (collectively, “Fairway”).  The Fairway Field is located in the state waters of Alabama and the Yellowhammer gas processing plant is located in the state of Alabama.  The effective date of the transaction was July 1, 2014.  The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO.  A net purchase price increase of $1.3 million for customary final closing adjustments was recorded in 2015.  The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table presents the purchase price allocation, including estimated adjustments, for the increased ownership interest in Fairway (in thousands):  

Cash consideration:

 

 

 

Evaluated properties including equipment

$

18,693

 

Non-cash consideration:

 

 

 

Asset retirement obligations - non-current

 

6,124

 

Total consideration

$

24,817

 

The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value.  See Note 1 for a description of the Level 3 inputs.  No goodwill was recorded in connection with the acquisition of this additional working interest in Fairway.

Woodside Properties  

On May 20, 2014, Energy VI entered into a purchase and sale agreement to acquire certain oil and natural gas property interests from Woodside Energy (USA) Inc. (“Woodside”).  The properties acquired from Woodside (the “Woodside Properties”) consisted of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks.  All of the Woodside Properties are located in the Gulf of Mexico.  The effective date of the transaction was November 1, 2013.  The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO.  A net purchase price increase of $0.2 million for customary final closing adjustments was recorded in 2015.  The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

The following table presents the purchase price allocation, including estimated adjustments, for the acquisition of the Woodside Properties (in thousands):  

Cash consideration:

 

 

 

Evaluated properties including equipment

$

52,347

 

Unevaluated properties

 

2,660

 

Sub-total cash consideration

 

55,007

 

Non-cash consideration:

 

 

 

Asset retirement obligations - current

 

782

 

Asset retirement obligations - non-current

 

10,543

 

Sub-total non-cash consideration

 

11,325

 

Total consideration

$

66,332

 

The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value.  See Note 1 for a description of the Level 3 inputs.  No goodwill was recorded in connection with the Woodside Properties acquisition.

2014 Acquisitions — Revenues, Net Income and Pro Forma Financial Information - Unaudited  

The increase in working interest ownership for Fairway was not included in our consolidated results until the property transfer date, which occurred in September 2014 and the incremental revenue and operating expenses were immaterial for 2014.  Unaudited pro forma information is not presented as the pro forma information is not materially different from the reported results for 2014 and 2013.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Woodside Properties were not included in our consolidated results until the property transfer date, which occurred on May 20 2014.  For 2015, the Woodside Properties accounted for $24.4 million of revenues, $9.5 million of direct operating expenses, $14.4 million of depreciation, depletion, amortization and accretion (“DD&A”) and no income tax expense, resulting in $0.5 million of net income.  For the period of May 20, 2014 to December 31, 2014, the Woodside Properties accounted for $28.4 million of revenues, $5.5 million of direct operating expenses, $11.0 million of DD&A and $4.2 million of income taxes, resulting in $7.7 million of net income.  The net income attributable to the Woodside Properties does not reflect certain expenses, such as general and administrative expenses (“G&A”) and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis.  In addition, the Woodside Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate.    

In accordance with the applicable accounting guidance, the unaudited pro forma financial information was computed as if the acquisition of the Woodside Properties had been completed on January 1, 2013.  The financial information was derived from W&T’s audited historical consolidated financial statements for annual periods, W&T’s unaudited historical condensed consolidated financial statements for interim periods, and the Woodside Properties’ unaudited historical financial statements for the annual and interim periods.

The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Woodside Properties.  The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2013.  Had we owned the Woodside Properties during the periods indicated, the results may have been substantially different.  For example, we may have operated the assets differently than Woodside; the realized sales prices for oil, NGLs and natural gas may have been different; and the costs of operating the Woodside Properties may have been different.

The following table presents a summary of our pro forma financial information (in thousands, except earnings per share):

 

 

(unaudited)

 

 

 

December 31, 2014 (a)

 

Revenue

 

$

971,595

 

Net loss

 

 

(5,504

)

Basic and diluted loss per common share

 

 

(0.08

)

For the pro forma financial information, certain information was derived from our financial records, Woodside’s financial records and certain information was estimated.  

The following table presents incremental items included in the pro forma information reported above for the Woodside Properties (in thousands):

 

 

(unaudited)

 

 

 

December 31, 2014 (a)

 

Revenues (b)

 

$

22,887

 

Direct operating expenses (b)

 

 

4,417

 

DD&A (c)

 

 

8,385

 

G&A (d)

 

 

300

 

Interest expense (e)

 

 

330

 

Capitalized interest (f)

 

 

(19

)

Income tax expense (g)

 

 

3,316

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The sources of information and significant assumptions are described below:

(a)

The adjustments for 2014 are for the period from January 1, 2014 to May 20, 2014.

(b)

Revenues and direct operating expenses for the Woodside Properties were derived from the historical financial records of Woodside.

(c)

DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Woodside Properties’ costs, reserves and production into our full cost pool in order to compute such amounts.  The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation.  ARO was estimated by W&T management.

(d)

Estimated insurance costs related to our awardsthe Woodside Properties.

(e)

The acquisition was assumed to be funded entirely with borrowed funds.  Interest expense was computed using assumed borrowings of Restricted Shares, RSUs and common stock was $0.5$55.0 million, $16.5 million and $0.1 million, respectively.  Unrecognized compensation expense will be recognized through April 2017 for restricted shares, November 2016 for RSUs and February 2015 for common stock.

Cash-based Incentive Compensation

As defined bywhich equates to the Plan, annual incentive awards payable in cash may be granted to eligible employees.  These awards are performance-based awards consisting of one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each of such criteria.  Generally, the performance period is the calendar year and determination and payment is made in cash in the first quartercomponent of the following year.

Share-Based Compensationacquisition purchase price, and Cash-Based Incentive Compensation Expense

A summaryan interest rate of incentive compensation expense is as follows (in thousands):

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Share-based compensation included in:

 

 

 

 

 

 

 

 

 

 

 

General and administrative (1)

$

14,744

 

 

$

11,525

 

 

$

12,398

 

Cash-based incentive compensation included in:

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

3,285

 

 

 

3,482

 

 

 

3,787

 

General and administrative (1)

 

6,950

 

 

 

8,817

 

 

 

6,558

 

Total charged to operating income

$

24,979

 

 

$

23,824

 

 

$

22,743

 

(1)

Reclassified $0.7 million from cash-based incentive compensation expense to share-based compensation expense in 2014 related to the CEO’s 2013 award.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Employee Benefit Plan

We maintain a defined contribution benefit plan in compliance with Section 401(k) of the IRC (the “401(k) Plan”)1.8%, which covers those employees who meet the 401(k) Plan’s eligibility requirements.  During 2014, 2013 and 2012, the Company’s matching contribution was 100% of each participant’s contribution up to a maximum of 6% for 2014, 2013 and 2012 of the participant’s eligible compensation, subject to limitations imposed by the IRC.  The 401(k) Plan provides 100% vesting in Company match contributions on a pro rata basis over five years of service (20% per year).  Our expenses relatingequates to the 401(k) Plan were $2.4 million, $2.1 millionrates applied to incremental borrowings on the revolving bank credit facility.

(f)

The change to capitalized interest was computed for the addition to the pool of unevaluated properties and $2.1 millionthe capitalization interest rate was adjusted for 2014, 2013 and 2012, respectively.the assumed borrowings.  The negative amount represents a decrease to net expenses.

 

13. Income Taxes(g)

Income Tax Expense (Benefit)

Components of income tax expense (benefit) were as follows (in thousands):

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Current

$

301

 

 

$

(2,146

)

 

$

(40,562

)

Deferred

 

(4,760

)

 

 

30,920

 

 

 

88,109

 

 

$

(4,459

)

 

$

28,774

 

 

$

47,547

 

Effective Tax Rate Reconciliation

The reconciliation of income taxeswas computed atusing the U.S.35% federal statutory taxrate.

The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures.

8.  Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our oil and natural gas.  All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility.  We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations.  Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders, and we do not require collateral from our derivative counterparties.

Each derivative contract is recorded on the balance sheet as an asset or liability at fair value as of the respective period.  We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all changes in the fair value of derivative contracts were recognized currently in earnings during the periods presented.  The cash flows of all of our commodity derivative contracts are included in Net cash provided by operating activities on the Consolidated Statements of Cash Flows. While these contracts are intended to reduce the effects of price volatility, they may have limited incremental income from favorable price movements.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Commodity Derivatives

As of December 31, 2016, we did not have any open derivative contracts.  During 2015, we entered into crude oil and natural gas derivative contracts for a portion of our anticipated future production.  Some of the commodity derivative contracts are known as “three-way collars” consisting of a purchased put option, a sold call option and a purchased call option, each at varying strike prices.  The strike prices of the contracts were set so that the contracts were premium neutral (“costless”), which means no net premium was paid to or received from a counterparty.  The three-way collar contracts are structured to provide price risk protection if the commodity price falls below the strike price of the put option and provides us the opportunity to benefit if the commodity price rises above the strike price of the purchased call option.  In addition, we entered into oil derivative contracts known as “two-way”, “costless” collars, which consist of a purchased put option and a sold call option.  These two-way collars provide price risk protection if crude oil prices fall below certain levels, but have the potential to limit incremental income from favorable price movements above certain limits.  The oil contracts are based on WTI crude oil prices as quoted off the NYMEX.  The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX.  During 2014, we used crude oil swap contracts and have used various derivative instruments in prior years to manage our exposure to commodity price risk from sales of our oil and natural gas.  

The following balance sheet line items included amounts related to the estimated fair value of our open commodity derivative contracts as reported in the following table (in thousands):

 

December 31,

 

 

2016

 

 

2015

 

Prepaid and other assets - current

$

 

 

$

7,672

 

Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Derivative (gain) loss

$

2,926

 

 

$

(14,375

)

 

$

(3,965

)

Cash receipts (payments), net, on commodity derivative contract settlements are included within Net cash provided by operating activities on the Consolidated Statements of Cash Flows and were as follows (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Cash receipts (payments) on derivative settlements, net

$

4,746

 

 

$

6,703

 

 

$

(5,318

)

Offsetting Commodity Derivatives

During 2016 and 2015, all our commodity derivative contracts permit netting of derivative gains and losses upon settlement.  In general, the terms of the contracts provide for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same commodity.  If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our derivative instruments.  If we were required to settle all of our open derivative contracts, we would be able to net payments and receipts per counterparty pursuant to the derivative contracts.  Although our derivative contracts allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability.   For the open derivative contracts as of December 31, 2015, there would have been no difference if the contracts were presented on net basis.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Equity Transactions

During 2016, after receiving shareholder approval, the Company increased the amount of common stock authorized from 118.3 million shares to 200.0 million shares, which allowed for the issuance of 60.4 million additional shares in conjunction with the Exchange Transaction.  

During 2016 and 2015, we did not pay any dividends and dividends are currently suspended.  During 2014, we paid regular cash dividends of $0.40 per common share.    

10.  Share-Based Awards and Cash-Based Awards

Incentive Compensation Plan

In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders and amendments to the Plan were approved by our shareholders in 2016.  The Plan covers the Company’s eligible employees and consultants.  In addition to other cash and share-based compensation awards, the Plan is designed to grant awards that qualify as performance-based compensation within the meaning of section 162(m) of the IRC.  The Plan grants the Compensation Committee of the Board of Directors administrative authority over all participants, and grants the President and the Chief Executive Officer (“CEO”) with authority over the administration of awards granted to participants that are not subject to section 16 of the Exchange Act (as applicable, the “Committee”).

Pursuant to the terms of the Plan, the Committee establishes the performance criteria and may use a single measure or combination of business measures as described in the Plan.  Also, individual goals may be established by the Committee.  Performance awards may be granted in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, or other awards related to stock, and awards may be paid in cash, stock, or any combination of cash and stock, as determined by the Committee.  The performance awards granted under the Plan can be measured over a performance period of up to 10 years and annual incentive awards (a type of performance award) will generally be paid within 90 days following the applicable year end.

On May 4, 2016, after receiving shareholder approval, 3,300,000 shares of common stock were added to the amount available for issuance under the Plan.  As of December 31, 2016, there were 6,933,337 shares of common stock available for issuance in satisfaction of awards under the Plan.  RSUs reduce the shares available in the Plan when settled in shares of common stock, net of withholding tax.  

Share-based Awards: Restricted Stock Units

For 2016, 2015 and 2014, performance awards under the Plan were granted in the form of RSUs.  As defined by the Plan, RSUs are rights to receive stock, cash or a combination thereof at the end of a specified vesting period, subject to certain terms and conditions as determined by the Committee.  RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period using a predefined scale based on the Company achieving certain predetermined performance criteria.   Vesting occurs upon completion of the specified vesting period applicable to each grant.  Subsequent to the determination of the performance achievement and prior to vesting, the RSUs earn dividend equivalents at the same rate as dividends paid on our common stock.  RSUs are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period.

During 2016, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) net income before income tax expense, net interest expense, depreciation, depletion, amortization, accretion and certain other items (“Adjusted EBITDA”) for 2016 and (ii) Adjusted EBITDA as a percent of total revenue (“Adjusted EBITDA Margin”) for 2016.  Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels.  For 2016, the Company was below target for Adjusted EBITDA and achieved target for Adjusted EBITDA Margin.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

  During 2015, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2015 and (ii)  Adjusted EBITDA Margin for 2015.  Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels.  For 2015, the Company was below target for Adjusted EBITDA and achieved target for Adjusted EBITDA Margin.

During 2014, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2014 and (ii) Adjusted EBITDA Margin for 2014.  Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels.  For 2014, the Company achieved target for Adjusted EBITDA and was slightly below target for Adjusted EBITDA Margin.

All RSUs granted to date are subject to employment-based criteria in addition to performance criteria.  Vesting occurs in December of the second calendar year following the date of grant.  For example, the RSUs granted during 2014 (after adjustment for performance) vested in December 2016 to eligible employees.  Although the Company has the option to settle RSUs in stock or cash at vesting, only common stock has been used to settle vested RSUs to date.

During 2016, 2015 and 2014, the Company granted RSUs to certain employees, with nearly all grants being contingent upon meeting specified performance requirements described above.  The fair value of the RSUs granted in 2016, 2015 and 2014 was determined using the Company’s closing price on the grant dates.  

A summary of activity related to RSUs is as follows:

 

2016

 

 

2015

 

 

2014

 

 

Restricted Stock Units

 

 

Weighted Average Grant Date Fair Value Per Share

 

 

Restricted Stock Units

 

 

Weighted Average Grant Date Fair Value Per Share

 

 

Restricted Stock Units

 

 

Weighted Average Grant Date Fair Value Per Share

 

Nonvested, beginning of period

 

3,474,079

 

 

$

7.42

 

 

 

1,977,335

 

 

$

15.29

 

 

 

1,331,753

 

 

$

14.96

 

Granted

 

4,213,964

 

 

 

2.21

 

 

 

2,626,930

 

 

 

3.59

 

 

 

1,195,388

 

 

 

16.84

 

Vested

 

(968,652

)

 

 

16.69

 

 

 

(721,038

)

 

 

13.23

 

 

 

(354,692

)

 

 

18.59

 

Forfeited

 

(612,143

)

 

 

3.64

 

 

 

(409,148

)

 

 

10.63

 

 

 

(195,114

)

 

 

16.53

 

Nonvested, end of period

 

6,107,248

 

 

$

2.73

 

 

 

3,474,079

 

 

$

7.42

 

 

 

1,977,335

 

 

$

15.29

 

Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2016 are eligible to vest in the year indicated in the table below:

 

Restricted Stock Units

 

2017

 

2,311,434

 

2018

 

3,795,814

 

Total

 

6,107,248

 

RSUs fair value at grant date: During 2016, 2015 and 2014, the grant date fair value of RSUs granted was $9.3 million, $9.4 million and $20.1 million, respectively.

RSUs fair value at vested date: The fair value of the RSUs that vested during 2016, 2015 and 2014 was $2.4 million, $2.1 million and $2.0 million, respectively, based on the Company’s closing price on the vesting date.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Share-based Awards: Common Stock

The 2014 annual incentive plan award for the CEO was settled in shares of common stock based on a pre-determined price of $14.66 per share, pursuant to the terms of his award.  As the number of shares could not be determined until the full-year 2014 results were determined and approved by the Compensation Committee, the CEO’s 2014 award was accounted for as a liability award and adjusted to fair value using the Company’s closing price at the end of each reporting period.  The CEO award for 2014 was 100% performance based and was subject to pre-defined performance measures and employment-based criteria, which were the same pre-defined performance measures and employment-based criteria established for the other eligible employees, and were subject to approval of the Compensation Committee.  An issuance of 37,316 shares of common stock was made in March 2015 to the CEO for his 2014 annual incentive compensation award.  The number of shares was determined after deductions for withholding and payroll taxes and the shares were valued at the Company’s closing price as of the date of issuance.  

Share-Based Awards:  Restricted Stock

Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2016, 2015 and 2014 to the Company’s non-employee directors as a component of their compensation arrangement.  Vesting occurs upon completion of the specified vesting period and one-third of each grant vests each year over a three-year period.  The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares.  Restricted Shares are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restriction period.  

As of December 31, 2016, there were 317,896 shares of common stock available for issuance in satisfaction of awards under the Directors Compensation Plan.  Reductions in shares available are made when Restricted Shares are granted.  

A summary of activity related to Restricted Shares is as follows:

 

2016

 

 

2015

 

 

2014

 

 

Restricted Shares

 

 

Weighted Average Grant Date Fair Value Per Share

 

 

Restricted Shares

 

 

Weighted Average Grant Date Fair Value Per Share

 

 

Restricted Shares

 

 

Weighted Average Grant Date Fair Value Per Share

 

Nonvested, beginning of period

 

78,230

 

 

$

8.95

 

 

 

43,210

 

 

$

16.20

 

 

 

43,840

 

 

$

15.96

 

Granted

 

126,128

 

 

 

2.22

 

 

 

56,540

 

 

 

6.19

 

 

 

18,815

 

 

 

18.60

 

Vested

 

(43,062

)

 

 

9.75

 

 

 

(21,520

)

 

 

16.26

 

 

 

(19,445

)

 

 

18.00

 

Nonvested, end of period

 

161,296

 

 

$

3.47

 

 

 

78,230

 

 

$

8.95

 

 

 

43,210

 

 

$

16.20

 

Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2016 are expected to vest as follows:

 

Restricted Shares

 

2017

 

62,136

 

2018

 

57,120

 

2019

 

42,040

 

Total

 

161,296

 

Restricted stock fair value at grant date:  The grant date fair value of restricted stock granted during 2016, 2015 and 2014 was $0.3 million for all periods based on the Company’s closing price on the date of grant.

Restricted stock fair value at vested date: The fair value of the restricted stock that vested during 2016, 2015 and 2014 was $0.1 million, $0.1 million and $0.3 million, respectively, based on the Company’s closing price on the date of vesting.

112


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Share-Based Compensation

A summary of compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Share-based compensation expense from:

 

 

 

 

 

 

 

 

 

 

 

Restricted stock units

$

10,640

 

 

$

9,978

 

 

$

13,150

 

Restricted stock

 

373

 

 

 

358

 

 

 

369

 

Common shares

 

 

 

 

(94

)

 

 

1,225

 

Total

$

11,013

 

 

$

10,242

 

 

$

14,744

 

Share-based compensation tax benefit:

 

 

 

 

 

 

 

 

 

 

 

Tax benefit computed at the statutory rate

$

3,855

 

 

$

3,585

 

 

$

5,160

 

As of December 31, 2016, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $9.7 million and $0.4 million, respectively.  Unrecognized compensation expense will be recognized through November 2018 for RSUs and April 2019 for Restricted Shares.

Cash-based Awards

In addition to share-based compensation, cash-based awards were granted under the Plan to substantially all eligible employees in 2016, 2015 and 2014.  The cash-based awards, which are a short-term component of the Plan, are performance-based awards consisting of one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each of such criteria.  In addition, for the 2016 and 2015 cash-based awards, which includes the 2016/2015 incentive plan for the CEO, the Company designed the awards with an additional financial condition that must be achieved on or before December 31, 2018 for the 2016 awards, and on or before December 31, 2017 for the 2015 awards:  Adjusted EBITDA less Interest Expense Incurred, as reporting by the Company in its announced Earning Release with respect to the end of any fiscal quarter plus three preceding quarters, exceeds $300.0 million.  As this additional financial condition was not achieved as of December 31, 2016, no amounts were accrued or subsequently paid.  If this additional financial condition is achieved, payment is to be made within 30 days following the achievement of the financial condition, but subject to all the terms of the 2016 and 2015 Annual Incentive Award Agreement (the 2016 and 2015 cash-based awards).  

With respect to the 2014 cash-based awards, some of the performance criteria targets were achieved and were combined with estimates of personal performance measurements to record potential payments.  Eligible employees were paid their cash-based awards within 75 days following year end 2014.

Share-Based Awards and Cash-Based Awards Compensation Expense

A summary of compensation expense related to share-based awards and cash-based awards is as follows (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Share-based compensation included in:

 

 

 

 

 

 

 

 

 

 

 

General and administrative

$

11,013

 

 

$

10,242

 

 

$

14,744

 

Cash-based incentive compensation included in:

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

 

 

 

364

 

 

 

3,285

 

General and administrative (1)

 

 

 

 

(233

)

 

 

6,950

 

Total charged to operating income

$

11,013

 

 

$

10,373

 

 

$

24,979

 

(1)

Adjustments to our income taxtrue up estimates to actual payments resulted in net credit balances to expense (benefit) is as follows (in thousands):for 2015.

 

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Income tax expense (benefit) at the federal

    statutory rate

$

(5,642

)

 

 

35.0

%

 

$

28,033

 

 

 

35.0

%

 

$

41,836

 

 

 

35.0

%

Qualified domestic production activities

 

 

 

 

 

 

 

 

 

 

 

 

 

4,256

 

 

 

3.5

 

State income taxes

 

263

 

 

 

(1.6

)

 

 

343

 

 

 

0.4

 

 

 

750

 

 

 

0.7

 

Other

 

920

 

 

 

(5.7

)

 

 

398

 

 

 

0.5

 

 

 

705

 

 

 

0.6

 

 

$

(4,459

)

 

 

27.7

%

 

$

28,774

 

 

 

35.9

%

 

$

47,547

 

 

 

39.8

%

113


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Employee Benefit Plan

We maintain a defined contribution benefit plan in compliance with Section 401(k) of the IRC (the “401(k) Plan”), which covers those employees who meet the 401(k) Plan’s eligibility requirements.  As of March 5, 2016, the Company suspended matching contributions.  From January 1, 2016 to March 5, 2016, and during 2015 and 2014, the Company’s matching contribution was 100% of each participant’s contribution up to a maximum of 6% of the participant’s eligible compensation, subject to limitations imposed by the IRC.  The 401(k) Plan provides 100% vesting in Company match contributions on a pro rata basis over five years of service (20% per year).  Our expenses relating to the 401(k) Plan were $0.4 million, $2.3 million and $2.4 million for 2016, 2015 and 2014, respectively.

12. Income Taxes

Income Tax Expense (Benefit)

Components of income tax expense (benefit) were as follows (in thousands):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Current

$

(71,768

)

 

$

288

 

 

$

301

 

Deferred

 

28,392

 

 

 

(203,272

)

 

 

(4,760

)

Total income tax( benefit)

$

(43,376

)

 

$

(202,984

)

 

$

(4,459

)

 

Effective Tax Rate Reconciliation

The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax benefit is as follows (in thousands, except percentages):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Income tax (benefit) at the federal statutory rate

$

(102,339

)

 

 

35.0

%

 

$

(436,696

)

 

 

35.0

%

 

$

(5,642

)

 

 

35.0

%

Share-based compensation

 

4,920

 

 

 

(1.7

)

 

 

2,940

 

 

 

(0.2

)

 

 

 

 

 

 

State income taxes

 

(755

)

 

 

0.2

 

 

 

(2,343

)

 

 

0.2

 

 

 

263

 

 

 

(1.6

)

Valuation allowance

 

52,915

 

 

 

(18.1

)

 

 

232,925

 

 

 

(18.7

)

 

 

 

 

 

 

Debt restructuring cost

 

1,463

 

 

 

(0.5

)

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

420

 

 

 

(0.1

)

 

 

190

 

 

 

 

 

 

920

 

 

 

(5.7

)

 

$

(43,376

)

 

 

14.8

%

 

$

(202,984

)

 

 

16.3

%

 

$

(4,459

)

 

 

27.7

%

Our effective tax rate for the years 2016 and 2015 differed from the federal statutory rate of 35.0% primarily due to recording and adjusting a valuation allowance for our deferred tax assets, which is discussed below.  Our effective tax rate for the year 2014 is distorted due to a small pre-tax loss; consequently, our permanent differences have a larger impact on our effective tax rate.    

114


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Deferred Tax Assets and Liabilities

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.  Significant components of our deferred tax assets and liabilities were as follows (in thousands):

 

December 31,

 

 

2016

 

 

2015

 

Deferred tax liabilities:

 

 

 

 

 

 

 

Property and equipment

$

 

 

$

40,287

 

Derivatives

 

 

 

 

2,697

 

Other

 

1,423

 

 

 

3,000

 

Total deferred tax liabilities

 

1,423

 

 

 

45,984

 

Deferred tax assets:

 

 

 

 

 

 

 

Alternative minimum tax credit

 

 

 

 

20,486

 

Property and equipment

 

42,385

 

 

 

 

Asset retirement obligations

 

117,588

 

 

 

133,018

 

Federal net operating losses

 

 

 

 

145,733

 

State net operating losses

 

5,615

 

 

 

5,068

 

Valuation allowance

 

(290,190

)

 

 

(237,275

)

Exchange transaction

 

118,467

 

 

 

 

Share-based compensation

 

2,353

 

 

 

4,245

 

Other

 

4,798

 

 

 

2,304

 

Total deferred tax assets

 

1,016

 

 

 

73,579

 

Net deferred tax asset (liabilities)

$

(407

)

 

$

27,595

 

During 2016, we made income tax payments of $0.3 million and received $7.8 million of refunds, which includes an income tax refund of $5.8 million related to an NOL claim for 2015 carried back to 2005 filed on Form 1139, Corporation Application for Tentative Refund.  During 2015, we did not make any payments for federal or state income taxes or receive any refunds of significance.  During 2014, we did not make any payments for federal and state income taxes and we received refunds of $3.0 million.

Income Tax Receivables

As of December 31, 2016, we have recorded current income tax receivables of $11.9 million and non-current income tax receivables of $52.1 million.  The current income tax receivables primarily relates to a net operating loss claim for 2016 carried back to 2006 and is included in the receivable line Joint interest, insurance reimbursement and other on the Consolidated Balance Sheet.  The non-current income tax receivables relates to our NOL claims for the years 2012, 2013 and 2014 that were carried back to the years 2003, 2004, 2007, 2010 and 2011 filed on Form 1120X, U.S. Corporation Income Tax Return.  These carryback claims are made pursuant to IRC Section 172(f), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.  The refund claims filed on Form 1120X will require a review by the Congressional Joint Committee on Taxation and are accordingly classified as non-current.

Our effective tax rate for the year 2014 is distorted due to a small pre-tax loss; consequently, our permanent differences have a larger impact on our effective tax rate.  Our effective tax rate for the year 2013 differed from the federal statutory rate primarily as a result of state income taxes.  Our effective tax rate for the year 2012 differed from the federal statutory rate primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a function of loss carrybacks to prior years and the impact of state income taxes.  

98


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Deferred Tax Assets and Liabilities

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.  Significant components of our deferred tax assets and liabilities were as follows (in thousands):

 

December 31,

 

 

2014

 

 

2013

 

Deferred tax liabilities:

 

 

 

 

 

 

 

Property and equipment

$

518,566

 

 

$

422,805

 

Other

 

5,019

 

 

 

3,602

 

Total deferred tax liabilities

 

523,585

 

 

 

426,407

 

Deferred tax assets:

 

 

 

 

 

 

 

Alternative minimum tax credit

 

20,486

 

 

 

20,486

 

Asset retirement obligations

 

137,597

 

 

 

124,863

 

Federal net operating losses

 

180,024

 

 

 

91,472

 

State net operating losses

 

5,008

 

 

 

5,028

 

Derivatives

 

 

 

 

3,270

 

Valuation allowance (state)

 

(4,255

)

 

 

(4,490

)

Accrued cash-based bonus

 

3,559

 

 

 

3,873

 

Stock-based compensation

 

5,042

 

 

 

3,703

 

Other

 

798

 

 

 

643

 

Total deferred tax assets

 

348,259

 

 

 

248,848

 

Net deferred tax liabilities

$

175,326

 

 

$

177,559

 

During 2014, we made did not make any payments for federal and state income taxes and we received refunds of $3.0 million.  During 2013, we made payments primarily for federal and state income taxes of approximately $3.0 million.  During 2013, we received refunds of $59.1 million, of which $9.5 million have been accounted for as unrecognized tax benefits.  The refunds were primarily attributable to tax loss carrybacks to 2010 and 2011, and refunds of estimated tax payments.  During 2012, we made payments primarily for federal and state income taxes of $16.1 million and we received refunds related to prior years of $0.5 million.  

At December 31, 2014, we did not have a federal income tax receivable.  At December 31, 2013, we had a federal income tax receivable of $3.1 million.  This amount is comprised principally of refunds related to estimated taxes paid during 2013.  

Net Operating Loss and Tax Credit Carryovers

The table below presents the details of our net operating loss and tax credit carryovers as of December 31, 20142016 (in thousands):

 

Amount

 

 

Expiration Year

Federal net operating loss

$

516,393

 

 

2032-2034

State net operating losses

 

99,656

 

 

2021-2029

Alternative minimum tax credit

 

12,091

 

 

Indefinite

General business credit

 

406

 

 

2027-2028

Amount

Expiration Year

Federal net operating loss

$

N/A

State net operating losses

112,512

2021-2030

Alternative minimum tax credit

N/A

General business credit

N/A

The federal net operating loss and alternative minimum tax credit amounts presented in the table, Deferred Tax Assets and Liabilities, reflect adjustments for unrecognized excess tax benefits and uncertain tax positions, as applicable, to the amounts presented above.

99115


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

 

Exchange Transaction Tax Gain

The tax gain on the Exchange Transaction associated with the cancellation of a portion of our debt was not recognized pursuant to Internal Revenue Code Section 108.  Certain tax attributes including net operating losses, alternative minimum tax credit, general business credit carryovers and the tax basis of assets are required to be reduced, as reflected in the table above.  No carryovers will be available to 2017.

Valuation Allowance

As of December 31, 2014 During 2016 and 2013,2015, we had arecorded increases in the valuation allowance of $52.9 million and $232.9 million, respectively, related to Louisianafederal and state deferred tax assets.  Deferred tax assets are recorded related to net operating losses.losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods.  The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions during periods in which those temporary differences or net operating losses are deductible.  In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.  As part of our assessment,December 31, 2016 and 2015, we consider future reversals of existing taxable temporary differences.had a valuation allowance related to Federal and state deferred tax assets.  

Uncertain Tax Positions

The table below sets forth the reconciliation of the beginning and ending balancesbalance of the total amount of unrecognized tax benefits.  There are no unrecognized benefits that would impact the effective tax rate if recognized.  While amounts could change in the next 12 months, we do not anticipate it having a material impact on our financial statements.  

Balances and changes in the uncertain tax positions are as follows (in thousands):

 

December 31,

 

 

2014

 

 

2013

 

Balance, beginning of period

$

9,482

 

 

$

 

Increases related to carryback positions

 

 

 

 

9,482

 

Balance, end of period

$

9,482

 

 

$

9,482

 

 

December 31,

 

 

2016

 

 

2015

 

Balance, beginning and end of period

$

9,482

 

 

$

9,482

 

 

We recognize interest and penalties related to uncertain tax positions in income tax expense.  For 2014, 20132016, 2015 and 2012,2014, the amounts recognized in income tax expense were immaterial.

Years open to examination

The tax years from 20102013 through 20142016 remain open to examination by the tax jurisdictions to which we are subject.

116


W&T OFFSHORE, INC. AND SUBSIDIARIES

14. EarningsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Loss Per Share

In accordance with GAAP, theThe Company’s unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are deemed participating securities and are included in the computation of earnings per share under the two-class method.method when the effect is dilutive.

The following table presents the calculation of basic and diluted earningsloss per common share (in thousands, except per share amounts):

Year Ended December 31,

 

Year Ended December 31,

 

2014

 

 

2013

 

 

2012

 

2016

 

 

2015

 

 

2014

 

Net income (loss)

$

(11,661

)

 

$

51,322

 

 

$

71,984

 

Net loss

$

(249,020

)

 

$

(1,044,718

)

 

$

(11,661

)

Less portion allocated to nonvested shares

 

269

 

 

 

303

 

 

 

983

 

 

 

 

 

 

 

 

269

 

Net income (loss) allocated to common shares

$

(11,930

)

 

$

51,019

 

 

$

71,001

 

Net loss allocated to common shares

$

(249,020

)

 

$

(1,044,718

)

 

$

(11,930

)

Weighted average common shares outstanding

 

75,609

 

 

 

75,239

 

 

 

74,354

 

 

95,644

 

 

 

75,931

 

 

 

75,609

 

Basic and diluted earnings (loss) per common share

$

(0.16

)

 

$

0.68

 

 

$

0.95

 

Basic and diluted loss per common share

$

(2.60

)

 

$

(13.76

)

 

$

(0.16

)

Shares excluded due to being anti-dilutive (weighted-average)

 

29

 

 

 

 

 

 

1,923

 

 

5,269

 

 

 

2,195

 

 

 

2,097

 

 

100


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15.14. Supplemental Cash Flow Information

The following reflects our supplemental cash flow information (in thousands):

Year Ended December 31,

 

Year Ended December 31,

 

2014

 

 

2013

 

 

2012

 

2016

 

 

2015

 

 

2014

 

Cash paid for interest, net of interest capitalized of $8,526 in 2014,

$10,058 in 2013 and $13,274 in 2012

$

77,607

 

 

$

73,909

 

 

$

46,247

 

Supplemental cash items:

 

 

 

 

 

 

 

 

 

 

 

Cash paid for interest, net of interest capitalized of $520 in 2016,

$7,256 in 2015 and $8,526 in 2014

$

96,501

 

 

$

92,622

 

 

$

77,607

 

Cash paid for income taxes

 

 

 

 

3,000

 

 

 

16,056

 

 

310

 

 

 

390

 

 

 

 

Cash refunds received for income taxes

 

3,000

 

 

 

59,126

 

 

 

479

 

 

7,796

 

 

 

90

 

 

 

3,000

 

Cash paid for share-based compensation (1)

 

431

 

 

 

466

 

 

 

1,531

 

 

 

 

 

 

 

 

431

 

Cash tax benefit related to share-based compensation (2)

 

 

 

 

 

 

 

5,962

 

 

 

 

 

 

 

 

 

 

 

 

Non-cash investing activities:

 

 

 

 

 

 

 

 

 

 

 

Accruals for property and equipment

 

9,129

 

 

 

44,324

 

 

 

99,750

 

ARO - additions, dispositions and revisions, net

 

10,865

 

 

 

(394

)

 

 

89,826

 

 

 

 

 

 

 

 

 

 

 

 

Non-cash financing activities:

 

 

 

 

 

 

 

 

 

 

 

Exchange transaction — non-cash securities issued:

 

 

 

 

 

 

 

 

 

 

 

11.00% 1.5 Lien Term Loan - interest payable

 

23,823

 

 

 

 

 

 

 

9.00%/10.75% Second Lien PIK Toggle Notes - carrying value

 

223,905

 

 

 

 

 

 

 

8.50%/10.00% Third Lien PIK Toggle Notes - carrying value

 

213,446

 

 

 

 

 

 

 

Common stock issued - fair value at issuance date

 

106,366

 

 

 

 

 

 

 

 

 

��

 

 

 

 

 

 

 

 

Exchange transaction — non-cash securities exchanged:

 

 

 

 

 

 

 

 

 

 

 

8.50% Unsecured Senior Notes - carrying value

 

(712,967

)

 

 

 

 

 

 

(1)

The cash paid for share-based compensation in 2014 is for dividends on unvested restricted stock and for dividend equivalents paid on RSUs.  No cash was received from employees or directors related to share-based compensation and no cash was used to settle any equity instruments granted under share-based compensation arrangements.

(2)

117


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The cash tax benefit for share-based compensation is attributable to tax deductions for vested restricted shares, vested RSUs, dividends paid on unvested restricted stock and dividend equivalents paid on RSUs.  For 2014 and 2013, no cash tax benefit was realized as the Company had a tax loss for that year and all carrybacks had previously been utilized.

 

16.15. Commitments

We have operating lease agreements for office space and office equipment.  The lease for the majority of our office space terminates in December 2022.  Minimum future lease payments due under noncancelable operating leases with terms in excess of one year as of December 31, 20142016 are as follows: 2015–$1.5 million; 2016–$1.6 million; 2017–$1.6 million; 2018–$1.7 million; 2019–$1.8 million; 2020–$1.8 million thereafter–$7.53.7 million.  Total rent expense was approximately $3.2 million, $2.6$3.3 million and $1.7$3.2 million during 2014, 20132016, 2015 and 2012,2014, respectively.

Pursuant to the Purchase and Sale Agreement with Total E&P, we are required tomay fulfill security requirements related to ARO for certain properties through securing bonds, or through making payments to an escrow account under a formula pursuant to the agreement, or a combination.combination thereof, until certain prescribed thresholds are met.  Once the threshold is met for that year, excess funds in the escrow account are returned to us.  As of December 31, 2014,2016, we were in compliance with the security amount requirement of $64.0 million.  Additional security requirements are $9.0had bonds totaling $75.0 million and had $1.9 million in 2015, $6.0an escrow account.  The threshold is $83.0 million in 2016, $4.0for 2017, $88.0 million in 2017, $5.0 million infor 2018 and $15.0 million in the 2019escalates to 2023 time period to a total security requirement of $103.0 million by 2023.for 2023 in $3.0 million per year increments.

Pursuant to the Purchase and Sale agreementAgreement with Shell Offshore Inc. (“Shell”) related to ARO for certain properties, we have bonds that are subject to re-appraisal in theby either party after November 2015.  As of December 31, 2016, neither party had requested a re-appraisal to be made.  The current security requirement of $74.0$64.0 million could be increased up to $94.0 million depending on certain conditions and circumstances.

We have bonding requirementsDuring 2016, 2015 and 2014, we had surety bonds related to properties owned by our subsidiary, W & T Energy VI, LLC, which require bonds in compliance with requirements set by the Bureau of Ocean Energy Management (“BOEM”).  These bonds are required as long as W & T Energy VI, LLC owns the properties, including completion of plugging and abandonment activities.

decommissioning obligations or ARO.  Total expenses related to surety bonds, inclusive of the surety bonds in connection with the Total E&P and Shell agreements described above, were $4.3 million, $5.5 million and $4.1 million $5.0 millionduring 2016, 2015 and $2.9 million during 2014, 2013 and 2012, respectively.  The amount of future commitments is dependent on rates charged in the market place and when asset retirements are completed.  Estimated future expenses related to surety bonds were based on current market prices and estimates of the timing of asset retirements, of which some wells and structures are estimated to extend to 2030.  Future costs are estimated as follows: 2015–$5.8 million; 2016–$5.8 million; 2017–$5.46.1 million; 2018–$5.9 million; 2019–$5.2 million; 2020–$5.0 million; thereafter–$32.938.6 million.  See Notes 17 and 19 for information concerning financial assurances per the BOEM regulations, which could impact future cost estimates related to surety bonds.    

As of December 31, 2016, we had $16.9 million of collateral deposits for certain sureties related to certain surety bonds for decommissioning obligations and appeals submitted to the Interior Board of Land Appeals (the “IBLA”).

Pursuant to an agreement with the Helix Well Containment Group, we are required to make payments quarterly in advance to have access to certain equipment to respond to a subsea spill should a spill occur at a property we operate.  As of December 31, 2014,2016, future payments due are $2.1$1.7 million in 20152017 and $2.1$1.7 million in 2016.2018.  These payments may increase or decrease depending on whether the number of companies participating in the consortium changes.

We have no drilling rig commitments with a term that exceeded one year as of December 31, 20142016 and our drilling rig commitments meet the criteria of an operating lease.  Future payments of all drilling rig commitments as of December 31, 20142016 were $12.6 million.$7.4 million, of which $2.9 million relates to ARO projects.

101118


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

17.16. Related Parties

During 2014, 20132016, 2015 and 2012,2014, there were certain transactions between us and other companies our majority shareholderCEO either controlled or in which he had an ownership interest.  In addition, there were transactions with a company that employs the spouse of our majority shareholder.CEO.  Our majority shareholderCEO owns an aircraft that the Company used and reimbursed him for such use and for his use.  Airplane services were charged to us at rates that were either equal to or below rates charged by non-related, third-party companies.  Airplane services transactions were approximately $0.9$1.1 million, $1.2$1.1 million and $1.0$0.9 million for the years 2014, 20132016, 2015 and 2012,2014, respectively.  Our majority shareholderCEO has ownership interests in certain wells operated by us (such ownership interests pre-date our initial public offering).  Revenues are disbursed and expenses are collected in accordance with ownership interest.  Proportionate insurance premiums were paid to us and proportionate collections of insurance reimbursements attributable to damage on certain wells were disbursed.  W&T hired the services of a directional drilling services company, in which our majority shareholderCEO owns a minority ownership interest and serves on its board of directors,directors. We paid no amounts in 2016 and W&T2015 and paid $0.2 million, $0.2 million and $0.7 million for drilling related services during 2014, 2013 and 2012, respectively.2014.  A company that provides marine transportation and logistics services to W&T employs the spouse of our majority shareholder.CEO.  The spouse received commissions partially based on services rendered to W&T which totaled less than $0.2 million per year for 2014, 20132016, 2015 and 2012.  All these transactions were determined to be priced at competitive rates and were reviewed2014.  During 2015, an entity controlled by our CEO participated in the Second Lien Term Loan for a $5.0 million principal commitment on the same terms as the other lenders.        

17. Contingencies

Financial Assurance Requirements by the Audit CommitteeBOEM

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 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 complianceOCS leases, ROWs or RUEs.  This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07.        

In the first quarter of 2016, we received several orders from the BOEM pursuant to NTL #2008-N07 demanding the Company to secure financial assurances in the aggregate of $260.8 million, with amounts specified with respect to certain designated leases, ROWs and RUEs.  We filed various appeals to the Interior Board of Land Appeals (the “IBLA”) concerning these orders.  The IBLA, acknowledging the BOEM and the Company were seeking to resolve the BOEM demands through settlement discussions, stayed the effectiveness of these orders several times, with the current stay effective to May 31, 2017.  

In September 2016, we received notice from the BOEM confirming that we do not qualify to self-insure a portion of any additional financial assurance under NTL #2016-N01.

In October 2016, we received from the BOEM proposal letters outlining what additional security the BOEM proposes to require for leases, ROWs and RUEs in which we are designated operator.

See Note 19 for a BOEM order issued in December 2016 related to additional financial assurance for sole liability properties, which was subsequently withdrawn in February 2017 by the BOEM.  See Note 19 regarding a notice issued in January 2017 by the BOEM extending the implementation timeline by an additional six months of the new regulations as to non-sole liability leases, ROWs and RUEs.  

Surety Bond Issuers’ Collateral Requirements

The issuers of surety bonds in some cases have requested and received additional collateral related to surety bonds for plugging and abandonment activities.  Pursuant to the terms of our policies and procedures.agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

18. Contingencies

Notification by ONRR of Fine for Non-compliance  

In December 2013 and January 2014, we were notified by the Office of Natural Resources Revenue (“ONRR”) of an underpayment of royalties on certain Federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment.  In March 2014, weWe received notice from the ONRR of a statutory fine of $2.3 million (subsequently reduced to $1.1 million) relative to such underpayment.  We believe the fine is excessive and extreme considering the circumstances and in relation to the amount of underpayment.  On April 23, 2014, we filed a request for aA hearing on this matter was held with an Administrative Law Judge in August 2016.  A decision on this case has been deferred until March 2017 at the record and a general denial of the ONRR’s allegations contained in the notice.  We intend to contest the fine to the fullest extent possible.earliest.  The ultimate resolution may result in a waiver of the fine, a reduction of the fine, or payment of the full amount plus interest covering several years.  As no amount has been determined as more likely than any other within the range of possible resolutions, no amount has been accrued as of December 31, 2014 per authoritative guidance.  However, we cannot state with certainty that our estimate of the exposure is accurate concerning this matter.2016 or 2015.      

Apache Lawsuit

  On December 15, 2014, Apache Corporation (“Apache”) filed a lawsuit against W&T Offshore, Inc., alleging that W&T breached the joint operating agreement (“JOA”(the “JOA”) related to, among other things, the abandonment of deepwater wells in the Mississippi Canyon area of the Gulf of Mexico.  That lawsuit, styled On October 28, 2016, the jury made the following findings:

1.

W&T failed to comply with the contract by failing to pay its proportionate share of the costs to plug and abandon the MC 674 wells.

2.

The amount of money to compensate Apache for W&T’s failure to pay its proportionate share of the costs to plug and abandon the MC 674 wells was $43.2 million.

3.

The $43.2 million referred to in #2 should be offset by $17.0 million.

4.

Apache acted in bad faith thereby causing W&T to not comply with the contract.

In November 2016 we filed a motion with the trial court requesting a judgment consistent with the jury’s finding that Apache Corporation v.acted in bad faith thereby causing W&T Offshore, Inc., is currently pendingnot to comply with the contract, which W&T asserted bars Apache from recovery for damages under applicable law, and if damages are not barred in their entirety, that any judgment for monetary damages should be offset by $17.0 million as determined by the United States District Court forjury. After Apache filed its opposing motion, a hearing was held by the Southern District of Texas.  Apache contends that W&T has failed to pay its proportional sharetrial court in December 2016.  As of the costs associated with plugging and abandoning three wells that are subject tofiling date of this Form 10-K, no judgment has been entered by the JOA.  We contend that the costs incurred by Apache are excessive and unreasonable.  Apache seeks an award of unspecified actual damages, interest, court costs, and attorneys’ fees. In February 2015, we made a payment to Apache for our net share of the amounts that we believe are reasonable to plug and abandon the three wells, all of which was originally recorded as an asset retirement obligation and was accrued on our balance sheet as of December 31, 2014.  Our estimate of the potential exposure ranges from zero to $32 million related to this matter. 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

court.  

Insurance Claims

DuringThe matter concerning certain claims with certain insurance companies was settled during the fourth quarter of 2012, underwriters of W&T’s excess liability policies (“Excess Policies”) (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company, XL Specialty Insurance Company, National Liability & Fire Insurance Company (“Starr Marine”)  and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court2016.  See Note 5 for the Southern District of Texas (the “District Court”) seeking a determination that our Excess Policies do not cover removal-of-wreck and debris claims arising from Hurricane Ike except to the extent we have first exhausted the limits of our Energy Package (defined as certain insurance policies relating to our oil and gas properties which includes named windstorm coverage) with only removal-of-wreck and debris claims.  The court consolidated the various suits filed by the underwriters.  In January 2013, we filed a motion for summary judgment seeking the court’s determination that such Excess Policies do not require us to exhaust the limits of our Energy Package policies with only removal-of-wreck and debris claims.  In July 2013, the District Court ruled in favordescription of the underwriters, adopting their position thatsettlement and the Excess Policies cover removal-of-wreck and debris claims only to the extent the limits of our Energy Package policies have been exhausted with removal-of-wreck and debris claims.  We appealed the decision in the United States Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) and, in June 2014, the Fifth Circuit reversed the District Court’s ruling and ruled in our favor.  The underwriters filed three separate briefs requesting a rehearing or a certification to the Texas Supreme Court, all of which the Court denied.  A brief was subsequently filed by one underwriter requesting a rehearing to the District Courtaccounting of the Fifth Circuit’s decision, which the District Court denied.  Claims of approximately $43 million were filed, of which approximately $1 million was paid under the Energy Package and of which approximately $1 million was paid under our Comprehensive General Liability policy.  Onefunds received.  The settlement does not include claims that have not yet been made subject to adjustment or requested for reimbursement by us as of the underwriters, Liberty Mutual Insurance Co., has paid their portion of the first excess liability policy (approximately $5 million), including interest, although the commencement date of the interest calculation is under discussion.  The other underwriters have not paid in accordancesettlement.        

Appeal with the Fifth Circuit ruling, and we filed a lawsuit in September 2014 against these underwriters for amounts owed, interest, attorney fees and damages.  Subsequent to the filing of that lawsuit, Starr Marine has paid their portion ($5 million) of the first excess liability policy without interest.  The revised estimate of potential reimbursement is approximately $31 million, plus interest, attorney fees and damages, if any.  Removal-of-wreck costs are recorded in Oil and natural gas properties and equipment on the Consolidated Balance Sheets and recoveries from claims made on these Excess Policies will be recorded as reductions in this line item, which will reduce our future DD&A rate.

RoyaltiesONRR

In 2009, the Companywe recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems.  In 2010, the ONRR audited the calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken.  We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR.  We filed an appeal with the ONRR, which was denied in May 2014.  On June 17, 2014, we filed an appeal with the Board of Land Appeals (the “BLA”)IBLA under the Department of the Interior.  See Note 19 regarding the denial of our appeal subsequent to December 31, 2016.  

120


W&T’s brief was filed&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Royalties – “Unbundling” Initiative

The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in November 2014determining the appropriate allowances for transportation and we expect the briefing before BLAprocessing costs that are permitted to be completeddeducted in determining royalties under Federal 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, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production that was processed through a specific processing plant.  We also received a preliminary determination notice from the ONRR asserting its preliminary determination that our allocation of certain processing costs and plant fuel use at another processing plant were impermissibly allowed as deductions in the first halfdetermination of 2015.royalties owed under Federal oil and gas leases.  We submitted revised calculations covering certain plants and certain time periods and has not yet received official 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 our Federal oil and gas leases for current and prior periods.  We have paid $0.5 million during 2016 based on our revised calculations for one plant covering part of the 84 month period.  We are not able to determine the range of any additional royalties or, if and when assessed, whether such amounts would be material.

Notices of Proposed Civil Penalty Assessment

During 2016 and 2015, we paid $0.1 million and $0.2 million of civil penalties issued by the BSEE related to Incidents of Noncompliance (“INCs”) issued by the BSEE at various offshore locations.  We currently have four open civil penalties issued by the BSEE arising from INCs, which have not been settled as of the filing of this Form 10-K.  The INC’s underlying the civil penalties were issued during 2015, with one re-issued during 2016, and relate to four separate offshore locations with occurrence dates ranging from July 2012 to June 2014.  The proposed civil penalties for these INCs total $8.1 million.  We have accrued approximately $1.5 million, which is our best estimate of the final settlement once all appeals have been exhausted.  Our position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs.

Iberville School Board Lawsuit

In August, 2013, a citation was issued on behalf of plaintiffs, the State of Louisiana and the Iberville Parish School Board in their suit against the Company (among others) in the 18th Judicial District Court for the Parish of Iberville, State of Louisiana.  This case involves claims by the Iberville Parish School Board that certain property in Louisiana had allegedly been contaminated or otherwise damaged by certain defendants’ oil and gas exploration and production activities.  The plaintiff’s claims include assessment costs, restoration costs, diminution of property value, punitive damages, and attorney fees and expenses, of which were not quantified in the claim.  We cannot currently estimate our potential exposure, if any, related to this lawsuit.  We are currently, and intend to continue, vigorously defending this litigation.

Other Claims

We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business.  In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties.  In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold.  We are also subject to federal and state administrative proceedings conducted in the ordinary course of business.business including matters related to alleged royalty underpayments on certain federal-owned properties.  Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, management believeswe believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

Contingent Liability Recorded

We recognized expenses related to accrued and settled claims, complaints and fines of $0.4 million, $0.5 million and $9.3 million for the years 2014, 2013 and 2012, respectively.  These expenses are reported within Operating costs and expenses on the statements of operations and reflect the items noted above and other various claims, complaints and fines.  As of December 31, 2014 and 2013, we have recorded a liability of $0.1 million and $0.2 million, respectively, which is included in Accrued liabilities on the Consolidated Balance Sheets, for the loss contingencies matters that include the events described above and other minor environmental and litigation matters which we are addressing in the normal course of business.

103121


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

  

19.18. Selected Quarterly Financial Data—UNAUDITED

Unaudited quarterly financial data are as follows (in thousands, except per share amounts):

 

1st

Quarter

 

 

2nd

Quarter

 

 

3rd

Quarter

 

 

4th

Quarter

 

Year Ended December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

254,516

 

 

$

262,994

 

 

$

234,521

 

 

$

196,677

 

Operating income (loss)

 

37,225

 

 

 

34,403

 

 

 

20,983

 

 

 

(30,543

)

Net income (loss)

 

11,189

 

 

 

9,837

 

 

 

684

 

 

 

(33,371

)

Basic and diluted earnings (loss) per common share (1)

 

0.15

 

 

 

0.13

 

 

 

0.01

 

 

 

(0.44

)

Year Ended December 31, 2013 (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

259,222

 

 

$

235,383

 

 

$

244,555

 

 

$

244,928

 

Operating income

 

60,321

 

 

 

53,823

 

 

 

31,965

 

 

 

622

 

Net income (loss)

 

26,618

 

 

 

22,396

 

 

 

14,194

 

 

 

(11,886

)

Basic and diluted earnings (loss) per common share (1)

 

0.35

 

 

 

0.29

 

 

 

0.19

 

 

 

(0.16

)

 

1st

Quarter

 

 

2nd

Quarter

 

 

3rd

Quarter

 

 

4th

Quarter

 

Year Ended December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

77,715

 

 

$

99,655

 

 

$

107,403

 

 

$

115,213

 

Operating  income (loss) (1)

 

(166,614

)

 

 

(126,997

)

 

 

(58,276

)

 

 

21,319

 

Net income (loss) (1)

 

(190,509

)

 

 

(120,922

)

 

 

45,928

 

 

 

16,483

 

Basic and diluted income (loss) per common share (1) (2)

 

(2.49

)

 

 

(1.58

)

 

 

0.48

 

 

 

0.12

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

127,907

 

 

$

149,066

 

 

$

126,228

 

 

$

104,064

 

Operating  loss (1)

 

(337,508

)

 

 

(278,806

)

 

 

(468,573

)

 

 

(60,816

)

Net loss (1)

 

(255,095

)

 

 

(260,449

)

 

 

(477,568

)

 

 

(51,606

)

Basic and diluted loss per common share (1) (2)

 

(3.36

)

 

 

(3.43

)

 

 

(6.29

)

 

 

(0.68

)

(1)

During 2016, we recorded in first, second and third quarter ceiling test write-downs of oil and natural gas properties of $116.6 million, $104.6 million and $57.9 million, respectively.  In the third quarter of 2016, we recorded a gain on exchange of debt of $123.9 million.  During 2015, we recorded in first, second, third and fourth quarter ceiling test write-downs of oil and natural gas properties of $260.4 million, $252.8 million, $441.6 million and $32.4 million, respectively.  See Note 1 for additional information.

(2)

The sum of the individual quarterly earnings (loss) per share maydoes not agree with year-to-date earningsthe year loss per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

(2)

In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtu”) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe).  The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011.  The use of the incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense.  We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in the fourth quarter of 2013.  

The fourth quarter of 2013 reflects a one-time increase in natural gas production volumes of 2.6 Bcf (with no corresponding increase in revenue) by using the correct conversion factor for the annual periods of 2011 and 2012, and the first three quarters of 2013, which increased DD&A by $7.1 million and decreased net income by $4.6 million.



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W&T OFFSHORE, INC. AND SUBSIDIARIES

104NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. Subsequent Events

Financial Assurance Requirements by the BOEM   

In January 2017, the IBLA stay related to our appeal of the BOEM orders issued during the first quarter of 2016 was extended to May 31, 2017.  

In January 2017, the BOEM, in a notice to stakeholders, extended the implementation timeline for NTL #2016-N01 by an additional six months with respect to non-sole liability properties, except in circumstances in which the BOEM determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  The extension did not affect the demand to provide financial assurance for leases, ROWs and RUEs constituting sole liability properties.  

  In February 2017, the BOEM withdrew the orders it issued in December 2016 affecting so called “sole liability properties” to allow time for the new President’s administration to review the complex financial assurance program.  Sole liability properties are leases, ROWs or RUEs for which the holder is the only liable party, i.e., there are no co-lessees, operating rights owners and/or other grant holders, and no prior interest holders liable to meet the lease and/or grant obligations.  This withdrawal rescinded the Order to Provide Additional Security issued to us in December 2016.  However, the BOEM may re-issue sole liability orders before the end of the six-month period if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.

As suggested by the BOEM in its January and February notices, we intend to use the six month extension granted by the BOEM as an opportunity to propose and negotiate acceptable plans dealing with both sole and non-sole liability properties.

Appeal with ONRR

On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties, which is described in Note 17.  We are reviewing the decision with counsel to determine an appropriate course of action.


123


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

 

20. Supplemental Guarantor Information

Our payment obligations under the 8.50% SeniorCredit Agreement, the 1.5 Lien Term Loan, the Second Lien Term Loan, the Second Lien PIK Toggle Notes, the Third Lien PIK Toggle Notes and the Credit AgreementUnsecured Senior Notes (see Note 7)2) are fully and unconditionally guaranteed by our 100%-owned subsidiaries, W & T Energy VI, LLC and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”).  W & T Energy VII, LLC does not currently have any active operations or contain any assets.  Guarantees of the 8.50% Senior Notes will be released under certain circumstances, including:

(1)

in connection with any sale or other disposition of all or substantially all of the assets of a Guarantor Subsidiary (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary, (as such term is defined in the indenture governing the 8.50% Senior Notes) of the Company, if the sale or other disposition does not violate the “Asset Sales”Asset Sales provisions of the indenture;(as such terms are defined in certain debt documents);

(2)

in connection with any sale or other disposition of the capital stock of such Guarantor Subsidiary to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the “Asset Sales”Asset Sales provisions of the indenture and the Guarantor Subsidiary ceases to be a subsidiary of the Company as a result of such sales or disposition;

(3)

if such Guarantor Subsidiary is a Restricted Subsidiary and the Company designates such Guarantor Subsidiary as an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture;certain debt documents;

(4)

upon Legal Defeasance or Covenant Defeasance (as such terms are defined in the indenture)certain debt documents) or upon satisfaction and discharge of the indenture;certain debt documents;

(5)

upon the liquidation or dissolution of such Guarantor Subsidiary, provided no event of default has occurred and is continuing; or

(6)

at such time as such Guarantor Subsidiary is no longer required to be a Guarantor Subsidiary of the 8.50% Senior Notes as described in the indenture,certain debt documents, provided no event of default has occurred and is continuing.

The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis.  TransfersIncluded in the consolidating adjustments was an adjustment related to the ceiling test write-down, as the computation is performed for each subsidiary on a stand-alone basis and also for the consolidated Company.  This resulted in write-downs for the combined subsidiaries to be greater than or less than computed on a total Company basis, which required a contra ceiling test write-down adjustment to present the consolidated results appropriately.  

When transfers of property including related ARO and deferred income tax liabilities, were made from the Parent Company to the Guarantor Subsidiaries, to assist the Parent Company to continue to qualify for a waiver of certain supplemental bonding requirements from the BOEM.  As these transferswhich were transactions between entities under common control, the prior period financial information has beenwas retrospectively adjusted for comparability purposes, as prescribed under authoritative guidance.  The condensed consolidating financial information for current and prior periods was adjusted as if all transfers occurred at the beginning of the period presented.  None of the above adjustments had any effect on the consolidated results for the current or prior periods presented.

 

 

 

105

124


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Condensed Consolidating Balance Sheet as of December 31, 20142016

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

23,666

 

 

$

 

 

$

 

 

$

23,666

 

$

70,236

 

 

$

 

 

$

 

 

$

70,236

 

Receivables:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

 

41,820

 

 

 

25,422

 

 

 

 

 

 

67,242

 

 

2,173

 

 

 

40,900

 

 

 

 

 

 

43,073

 

Joint interest and other

 

142,885

 

 

 

 

 

 

(99,240

)

 

 

43,645

 

 

163,200

 

 

 

 

 

 

(99,272

)

 

 

63,928

 

Total receivables

 

184,705

 

 

 

25,422

 

 

 

(99,240

)

 

 

110,887

 

 

165,373

 

 

 

40,900

 

 

 

(99,272

)

 

 

107,001

 

Deferred income taxes

 

9,797

 

 

 

1,865

 

 

 

 

 

 

11,662

 

Prepaid expenses and other assets

 

28,728

 

 

 

7,619

 

 

 

 

 

 

36,347

 

 

12,448

 

 

 

2,056

 

 

 

 

 

 

14,504

 

Total current assets

 

246,896

 

 

 

34,906

 

 

 

(99,240

)

 

 

182,562

 

 

248,057

 

 

 

42,956

 

 

 

(99,272

)

 

 

191,741

 

Property and equipment – at cost:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas properties and equipment

 

6,038,915

 

 

 

2,006,751

 

 

 

 

 

 

8,045,666

 

 

5,700,205

 

 

 

2,232,299

 

 

 

 

 

 

7,932,504

 

Furniture, fixtures and other

 

23,269

 

 

 

 

 

 

 

 

 

23,269

 

 

20,898

 

 

 

 

 

 

 

 

 

20,898

 

Total property and equipment

 

6,062,184

 

 

 

2,006,751

 

 

 

 

 

 

8,068,935

 

 

5,721,103

 

 

 

2,232,299

 

 

 

 

 

 

7,953,402

 

Less accumulated depreciation, depletion and amortization

 

4,442,899

 

 

 

1,132,179

 

 

 

 

 

 

5,575,078

 

 

5,360,137

 

 

 

2,045,259

 

 

 

953

 

 

 

7,406,349

 

Net property and equipment

 

1,619,285

 

 

 

874,572

 

 

 

 

 

 

2,493,857

 

 

360,966

 

 

 

187,040

 

 

 

(953

)

 

 

547,053

 

Restricted deposits for asset retirement obligations

 

15,444

 

 

 

 

 

 

 

 

 

15,444

 

 

27,371

 

 

 

 

 

 

 

 

 

27,371

 

Income tax receivables

 

52,097

 

 

 

 

 

 

 

 

 

52,097

 

Other assets

 

974,049

 

 

 

349,912

 

 

 

(1,306,717

)

 

 

17,244

 

 

394,931

 

 

 

344,742

 

 

 

(728,209

)

 

 

11,464

 

Total assets

$

2,855,674

 

 

$

1,259,390

 

 

$

(1,405,957

)

 

$

2,709,107

 

$

1,083,422

 

 

$

574,738

 

 

$

(828,434

)

 

$

829,726

 

Liabilities and Shareholders’ Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and Shareholders’ Equity (Deficit)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payable

$

188,654

 

 

$

5,455

 

 

$

 

 

$

194,109

 

$

74,306

 

 

$

6,733

 

 

$

 

 

$

81,039

 

Undistributed oil and natural gas proceeds

 

36,130

 

 

 

879

 

 

 

 

 

 

37,009

 

 

24,493

 

 

 

1,761

 

 

 

 

 

 

26,254

 

Asset retirement obligations

 

30,711

 

 

 

5,292

 

 

 

 

 

 

36,003

 

 

62,261

 

 

 

16,003

 

 

 

 

 

 

78,264

 

Long-term debt

 

8,272

 

 

 

 

 

 

 

 

 

8,272

 

Accrued liabilities

 

17,437

 

 

 

99,180

 

 

 

(99,240

)

 

 

17,377

 

 

9,293

 

 

 

99,179

 

 

 

(99,272

)

 

 

9,200

 

Total current liabilities

 

272,932

 

 

 

110,806

 

 

 

(99,240

)

 

 

284,498

 

 

178,625

 

 

 

123,676

 

 

 

(99,272

)

 

 

203,029

 

Long-term debt, less current maturities

 

1,360,057

 

 

 

 

 

 

 

 

 

1,360,057

 

 

1,012,455

 

 

 

 

 

 

 

 

 

1,012,455

 

Asset retirement obligations, less current portion

 

235,876

 

 

 

118,689

 

 

 

 

 

 

354,565

 

 

142,376

 

 

 

113,798

 

 

 

 

 

 

256,174

 

Deferred income taxes

 

59,616

 

 

 

127,372

 

 

 

 

 

 

186,988

 

Other liabilities

 

417,885

 

 

 

 

 

 

(404,194

)

 

 

13,691

 

 

408,050

 

 

 

 

 

 

(390,945

)

 

 

17,105

 

Shareholders’ equity:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Shareholders’ equity (deficit):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock

 

1

 

 

 

 

 

 

 

 

 

1

 

 

1

 

 

 

 

 

 

 

 

 

1

 

Additional paid-in capital

 

414,580

 

 

 

703,440

 

 

 

(703,440

)

 

 

414,580

 

 

539,973

 

 

 

704,885

 

 

 

(704,885

)

 

 

539,973

 

Retained earnings

 

118,894

 

 

 

199,083

 

 

 

(199,083

)

 

 

118,894

 

Retained earnings (deficit)

 

(1,173,891

)

 

 

(367,621

)

 

 

366,668

 

 

 

(1,174,844

)

Treasury stock, at cost

 

(24,167

)

 

 

 

 

 

 

 

 

(24,167

)

 

(24,167

)

 

 

 

 

 

 

 

 

(24,167

)

Total shareholders’ equity

 

509,308

 

 

 

902,523

 

 

 

(902,523

)

 

 

509,308

 

Total liabilities and shareholders’ equity

$

2,855,674

 

 

$

1,259,390

 

 

$

(1,405,957

)

 

$

2,709,107

 

Total shareholders’ equity (deficit)

 

(658,084

)

 

 

337,264

 

 

 

(338,217

)

 

 

(659,037

)

Total liabilities and shareholders’ equity (deficit)

$

1,083,422

 

 

$

574,738

 

 

$

(828,434

)

 

$

829,726

 

 

 

106125


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Condensed Consolidating Balance Sheet as of December 31, 20132015

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

(In thousands)

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

15,800

 

 

$

 

 

$

 

 

$

15,800

 

$

85,414

 

 

$

 

 

$

 

 

$

85,414

 

Receivables:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

 

61,373

 

 

 

35,379

 

 

 

 

 

 

96,752

 

 

2,742

 

 

 

32,263

 

 

 

 

 

 

35,005

 

Joint interest and other

 

123,595

 

 

 

 

 

 

(92,491

)

 

 

31,104

 

 

121,190

 

 

 

 

 

 

(99,178

)

 

 

22,012

 

Total receivables

 

184,968

 

 

 

35,379

 

 

 

(92,491

)

 

 

127,856

 

 

123,932

 

 

 

32,263

 

 

 

(99,178

)

 

 

57,017

 

Deferred income taxes

 

584

 

 

 

-

 

 

 

 

 

 

584

 

Prepaid expenses and other assets

 

23,090

 

 

 

6,272

 

 

 

 

 

 

29,362

 

 

25,375

 

 

 

1,504

 

 

 

 

 

 

26,879

 

Total current assets

 

224,442

 

 

 

41,651

 

 

 

(92,491

)

 

 

173,602

 

 

234,721

 

 

 

33,767

 

 

 

(99,178

)

 

 

169,310

 

Property and equipment – at cost:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas properties and equipment

 

5,667,389

 

 

 

1,671,708

 

 

 

 

 

 

7,339,097

 

 

5,682,793

 

 

 

2,219,701

 

 

 

 

 

 

7,902,494

 

Furniture, fixtures and other

 

21,431

 

 

 

 

 

 

 

 

 

21,431

 

 

20,802

 

 

 

 

 

 

 

 

 

20,802

 

Total property and equipment

 

5,688,820

 

 

 

1,671,708

 

 

 

 

 

 

7,360,528

 

 

5,703,595

 

 

 

2,219,701

 

 

 

 

 

 

7,923,296

 

Less accumulated depreciation, depletion and amortization

 

4,166,359

 

 

 

918,345

 

 

 

 

 

 

5,084,704

 

 

5,258,563

 

 

 

1,822,273

 

 

 

(147,589

)

 

 

6,933,247

 

Net property and equipment

 

1,522,461

 

 

 

753,363

 

 

 

 

 

 

2,275,824

 

 

445,032

 

 

 

397,428

 

 

 

147,589

 

 

 

990,049

 

Deferred income taxes

 

27,251

 

 

 

344

 

 

 

 

 

 

27,595

 

Restricted deposits for asset retirement obligations

 

37,421

 

 

 

 

 

 

 

 

 

37,421

 

 

15,606

 

 

 

 

 

 

 

 

 

15,606

 

Other assets

 

951,203

 

 

 

479,820

 

 

 

(1,410,568

)

 

 

20,455

 

 

498,782

 

 

 

266,748

 

 

 

(760,068

)

 

 

5,462

 

Total assets

$

2,735,527

 

 

$

1,274,834

 

 

$

(1,503,059

)

 

$

2,507,302

 

$

1,221,392

 

 

$

698,287

 

 

$

(711,657

)

 

$

1,208,022

 

Liabilities and Shareholders’ Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and Shareholders’ Equity (Deficit)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payable

$

144,492

 

 

$

720

 

 

$

 

 

$

145,212

 

$

100,282

 

 

$

9,515

 

 

$

 

 

$

109,797

 

Undistributed oil and natural gas proceeds

 

41,735

 

 

 

372

 

 

 

 

 

 

42,107

 

 

20,463

 

 

 

976

 

 

 

 

 

 

21,439

 

Asset retirement obligations

 

65,329

 

 

 

12,456

 

 

 

 

 

 

77,785

 

 

63,716

 

 

 

20,619

 

 

 

 

 

 

84,335

 

Accrued liabilities

 

28,000

 

 

 

92,491

 

 

 

(92,491

)

 

 

28,000

 

 

11,922

 

 

 

99,178

 

 

 

(99,178

)

 

 

11,922

 

Total current liabilities

 

279,556

 

 

 

106,039

 

 

 

(92,491

)

 

 

293,104

 

 

196,383

 

 

 

130,288

 

 

 

(99,178

)

 

 

227,493

 

Long-term debt, less current maturities

 

1,205,421

 

 

 

 

 

 

 

 

 

1,205,421

 

 

1,196,855

 

 

 

 

 

 

 

 

 

1,196,855

 

Asset retirement obligations, less current portion

 

189,507

 

 

 

87,130

 

 

 

 

 

 

276,637

 

 

173,105

 

 

 

120,882

 

 

 

 

 

 

293,987

 

Deferred income taxes

 

79,424

 

 

 

98,718

 

 

 

 

 

 

178,142

 

 

 

 

 

 

 

 

 

 

 

 

Other liabilities

 

441,009

 

 

 

 

 

 

(427,621

)

 

 

13,388

 

 

329,129

 

 

 

 

 

 

(312,951

)

 

 

16,178

 

Shareholders’ equity:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Shareholders’ equity (deficit):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock

 

1

 

 

 

 

 

 

 

 

 

1

 

 

1

 

 

 

 

 

 

 

 

 

1

 

Additional paid-in capital

 

403,564

 

 

 

784,104

 

 

 

(784,104

)

 

 

403,564

 

 

423,499

 

 

 

704,885

 

 

 

(704,885

)

 

 

423,499

 

Retained earnings

 

161,212

 

 

 

198,843

 

 

 

(198,843

)

 

 

161,212

 

 

(1,073,413

)

 

 

(257,768

)

 

 

405,357

 

 

 

(925,824

)

Treasury stock, at cost

 

(24,167

)

 

 

 

 

 

 

 

 

(24,167

)

 

(24,167

)

 

 

 

 

 

 

 

 

(24,167

)

Total shareholders’ equity

 

540,610

 

 

 

982,947

 

 

 

(982,947

)

 

 

540,610

 

Total liabilities and shareholders’ equity

$

2,735,527

 

 

$

1,274,834

 

 

$

(1,503,059

)

 

$

2,507,302

 

Total shareholders’ equity (deficit)

 

(674,080

)

 

 

447,117

 

 

 

(299,528

)

 

 

(526,491

)

Total liabilities and shareholders’ equity (deficit)

$

1,221,392

 

 

$

698,287

 

 

$

(711,657

)

 

$

1,208,022

 

 

 

107126


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Condensed Consolidating Statement of Operations for the Year Ended December 31, 20142016

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

592,460

 

 

$

356,248

 

 

$

 

 

$

948,708

 

$

161,063

 

 

$

238,923

 

 

$

 

 

$

399,986

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

179,344

 

 

 

85,407

 

 

 

 

 

 

264,751

 

 

84,415

 

 

 

67,984

 

 

 

 

 

 

152,399

 

Production taxes

 

7,932

 

 

 

 

 

 

 

 

 

7,932

 

 

1,889

 

 

 

 

 

 

 

 

 

1,889

 

Gathering and transportation

 

11,712

 

 

 

8,109

 

 

 

 

 

 

19,821

 

 

9,795

 

 

 

13,133

 

 

 

 

 

 

22,928

 

Depreciation, depletion, amortization and accretion

 

276,636

 

 

 

213,833

 

 

 

 

 

 

490,469

 

Depreciation, depletion and amortization

 

73,268

 

 

 

112,277

 

 

 

8,493

 

 

 

194,038

 

Asset retirement obligations accretion

 

10,981

 

 

 

9,652

 

 

 

 

 

 

20,633

 

 

8,165

 

 

 

9,406

 

 

 

 

 

 

17,571

 

Ceiling test write-down of oil and natural gas properties

 

28,305

 

 

 

110,709

 

 

 

140,049

 

 

 

279,063

 

General and administrative expenses

 

48,084

 

 

 

38,915

 

 

 

 

 

 

86,999

 

 

24,817

 

 

 

34,923

 

 

 

 

 

 

59,740

 

Derivative gain

 

(3,965

)

 

 

 

 

 

 

 

 

(3,965

)

Derivative loss

 

2,926

 

 

 

 

 

 

 

 

 

2,926

 

Total costs and expenses

 

530,724

 

 

 

355,916

 

 

 

 

 

 

886,640

 

 

233,580

 

 

 

348,432

 

 

 

148,542

 

 

 

730,554

 

Operating income

 

61,736

 

 

 

332

 

 

 

 

 

 

62,068

 

Earnings of affiliates

 

240

 

 

 

 

 

 

(240

)

 

 

 

Operating loss

 

(72,517

)

 

 

(109,509

)

 

 

(148,542

)

 

 

(330,568

)

Loss of affiliates

 

(109,853

)

 

 

 

 

 

109,853

 

 

 

 

Interest expense:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Incurred

 

84,460

 

 

 

2,462

 

 

 

 

 

 

86,922

 

 

92,607

 

 

 

184

 

 

 

 

 

 

92,791

 

Capitalized

 

(6,064

)

 

 

(2,462

)

 

 

 

 

 

(8,526

)

 

(336

)

 

 

(184

)

 

 

 

 

 

(520

)

Other income, net

 

208

 

 

 

 

 

 

 

 

 

208

 

Income (loss) before income tax expense (benefit)

 

(16,212

)

 

 

332

 

 

 

(240

)

 

 

(16,120

)

Gain on exchange of debt

 

123,923

 

 

 

 

 

 

 

 

 

123,923

 

Other (income) expense, net

 

(6,520

)

 

 

 

 

 

 

 

 

(6,520

)

Loss before income tax expense (benefit)

 

(144,198

)

 

 

(109,509

)

 

 

(38,689

)

 

 

(292,396

)

Income tax expense (benefit)

 

(4,551

)

 

 

92

 

 

 

 

 

 

(4,459

)

 

(43,720

)

 

 

344

 

 

 

 

 

 

(43,376

)

Net income (loss)

$

(11,661

)

 

$

240

 

 

$

(240

)

 

$

(11,661

)

Net loss

$

(100,478

)

 

$

(109,853

)

 

$

(38,689

)

 

$

(249,020

)

 

 

108127


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Condensed Consolidating Statement of Operations for the Year Ended December 31, 20132015

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

631,267

 

 

$

352,821

 

 

$

 

 

$

984,088

 

$

290,212

 

 

$

217,053

 

 

$

 

 

$

507,265

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

202,096

 

 

 

68,743

 

 

 

 

 

 

270,839

 

 

126,189

 

 

 

66,576

 

 

 

 

 

 

192,765

 

Production taxes

 

7,135

 

 

 

 

 

 

 

 

 

7,135

 

 

3,002

 

 

 

 

 

 

 

 

 

3,002

 

Gathering and transportation

 

9,248

 

 

 

8,262

 

 

 

 

 

 

17,510

 

 

9,209

 

 

 

7,948

 

 

 

 

 

 

17,157

 

Depreciation, depletion, amortization and accretion

 

236,600

 

 

 

194,011

 

 

 

 

 

 

430,611

 

Depreciation, depletion and amortization

 

201,154

 

 

 

172,214

 

 

 

 

 

 

373,368

 

Asset retirement obligations accretion

 

14,218

 

 

 

6,700

 

 

 

 

 

 

 

20,918

 

 

11,587

 

 

 

9,116

 

 

 

 

 

 

20,703

 

Ceiling test write-down of oil and natural gas properties

 

616,947

 

 

 

517,880

 

 

 

(147,589

)

 

 

987,238

 

General and administrative expenses

 

44,040

 

 

 

37,834

 

 

 

 

 

 

81,874

 

 

39,009

 

 

 

34,101

 

 

 

 

 

 

73,110

 

Derivative loss

 

8,470

 

 

 

 

 

 

 

 

 

8,470

 

 

(14,375

)

 

 

 

 

 

 

 

 

(14,375

)

Total costs and expenses

 

521,807

 

 

 

315,550

 

 

 

 

 

 

837,357

 

 

992,722

 

 

 

807,835

 

 

 

(147,589

)

 

 

1,652,968

 

Operating income

 

109,460

 

 

 

37,271

 

 

 

 

 

 

146,731

 

Operating loss

 

(702,510

)

 

 

(590,782

)

 

 

147,589

 

 

 

(1,145,703

)

Earnings of affiliates

 

24,400

 

 

 

 

 

 

(24,400

)

 

 

 

 

(464,931

)

 

 

 

 

 

464,931

 

 

 

 

Interest expense:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Incurred

 

82,570

 

 

 

3,069

 

 

 

 

 

 

85,639

 

 

101,542

 

 

 

3,050

 

 

 

 

 

 

104,592

 

Capitalized

 

(6,989

)

 

 

(3,069

)

 

 

 

 

 

(10,058

)

 

(4,206

)

 

 

(3,050

)

 

 

 

 

 

(7,256

)

Other income, net

 

8,946

 

 

 

 

 

 

 

 

 

8,946

 

Income before income tax expense

 

67,225

 

 

 

37,271

 

 

 

(24,400

)

 

 

80,096

 

Income tax expense

 

15,903

 

 

 

12,871

 

 

 

 

 

 

28,774

 

Net income

$

51,322

 

 

$

24,400

 

 

$

(24,400

)

 

$

51,322

 

Other (income) expense, net

 

4,663

 

 

 

 

 

 

 

 

 

4,663

 

Loss before income tax expense

 

(1,269,440

)

 

 

(590,782

)

 

 

612,520

 

 

 

(1,247,702

)

Income tax benefit

 

(77,133

)

 

 

(125,851

)

 

 

 

 

 

(202,984

)

Net loss

$

(1,192,307

)

 

$

(464,931

)

 

$

612,520

 

 

$

(1,044,718

)

 

109128


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Condensed Consolidating Statement of Operations for the Year Ended December 31, 20122014

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

539,958

 

 

$

334,533

 

 

$

 

 

$

874,491

 

$

571,365

 

 

$

377,343

 

 

$

 

 

$

948,708

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

168,033

 

 

 

64,227

 

 

 

 

 

 

232,260

 

 

180,149

 

 

 

84,602

 

 

 

 

 

 

264,751

 

Production taxes

 

5,840

 

 

 

 

 

 

 

 

 

5,840

 

 

7,932

 

 

 

 

 

 

 

 

 

7,932

 

Gathering and transportation

 

10,197

 

 

 

4,681

 

 

 

 

 

 

14,878

 

 

11,790

 

 

 

8,031

 

 

 

 

 

 

19,821

 

Depreciation, depletion, amortization and accretion

 

187,039

 

 

 

149,138

 

 

 

 

 

 

336,177

 

Depreciation, depletion and amortization

 

267,406

 

 

 

223,063

 

 

 

 

 

 

490,469

 

Asset retirement obligations accretion

 

14,979

 

 

 

5,076

 

 

 

 

 

 

 

20,055

 

 

10,981

 

 

 

9,652

 

 

 

 

 

 

20,633

 

General and administrative expenses

 

45,260

 

 

 

36,757

 

 

 

 

 

 

82,017

 

 

46,513

 

 

 

40,486

 

 

 

 

 

 

86,999

 

Derivative loss

 

13,954

 

 

 

 

 

 

 

 

 

13,954

 

Derivative gain

 

(3,965

)

 

 

 

 

 

 

 

 

(3,965

)

Total costs and expenses

 

445,302

 

 

 

259,879

 

 

 

 

 

 

705,181

 

 

520,806

 

 

 

365,834

 

 

 

 

 

 

886,640

 

Operating income

 

94,656

 

 

 

74,654

 

 

 

 

 

 

169,310

 

 

50,559

 

 

 

11,509

 

 

 

 

 

 

62,068

 

Earnings of affiliates

 

49,799

 

 

 

 

 

 

(49,799

)

 

 

 

 

8,320

 

 

 

 

 

 

(8,320

)

 

 

 

Interest expense:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Incurred

 

60,778

 

 

 

2,490

 

 

 

 

 

 

63,268

 

 

84,460

 

 

 

2,462

 

 

 

 

 

 

86,922

 

Capitalized

 

(10,784

)

 

 

(2,490

)

 

 

 

 

 

(13,274

)

 

(6,064

)

 

 

(2,462

)

 

 

 

 

 

(8,526

)

Other income, net

 

215

 

 

 

 

 

 

 

 

 

215

 

Income before income tax expense

 

94,676

 

 

 

74,654

 

 

 

(49,799

)

 

 

119,531

 

Income tax expense

 

22,692

 

 

 

24,855

 

 

 

 

 

 

47,547

 

Net income

$

71,984

 

 

$

49,799

 

 

$

(49,799

)

 

$

71,984

 

Other (income) expense, net

 

(208

)

 

 

 

 

 

 

 

 

(208

)

Income (loss) before income tax expense (benefit)

 

(19,309

)

 

 

11,509

 

 

 

(8,320

)

 

 

(16,120

)

Income tax expense (benefit)

 

(7,648

)

 

 

3,189

 

 

 

 

 

 

(4,459

)

Net income (loss)

$

(11,661

)

 

$

8,320

 

 

$

(8,320

)

 

$

(11,661

)

 

 

110129


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 20142016

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

$

(11,661

)

 

$

240

 

 

$

(240

)

 

$

(11,661

)

Adjustments to reconcile net income (loss) to net cash

provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

$

(100,478

)

 

$

(109,853

)

 

$

(38,689

)

 

$

(249,020

)

Adjustments to reconcile net loss to net cash provided by

(used in) operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

287,617

 

 

 

223,485

 

 

 

 

 

 

511,102

 

 

81,433

 

 

 

121,683

 

 

 

8,493

 

 

 

211,609

 

Amortization of debt issuance costs and premium

 

701

 

 

 

 

 

 

 

 

 

701

 

Ceiling test write-down of oil and gas properties

 

28,305

 

 

 

110,709

 

 

 

140,049

 

 

 

279,063

 

Gain on exchange of debt

 

(123,923

)

 

 

 

 

 

 

 

 

(123,923

)

Debt issuance costs write-off/amortization of debt items

 

2,548

 

 

 

 

 

 

 

 

 

2,548

 

Share-based compensation

 

14,744

 

 

 

 

 

 

 

 

 

14,744

 

 

11,013

 

 

 

 

 

 

 

 

 

11,013

 

Derivative gain

 

(3,965

)

 

 

 

 

 

 

 

 

(3,965

)

 

2,926

 

 

 

 

 

 

 

 

 

2,926

 

Cash payments on derivative settlements, net

 

(5,318

)

 

 

 

 

 

 

 

 

(5,318

)

Cash receipts on derivative settlements, net

 

4,746

 

 

 

 

 

 

 

 

 

4,746

 

Deferred income taxes

 

(32,456

)

 

 

27,696

 

 

 

 

 

 

(4,760

)

 

28,048

 

 

 

344

 

 

 

 

 

 

28,392

 

Earnings of affiliates

 

(240

)

 

 

 

 

 

240

 

 

 

 

Loss of affiliates

 

109,853

 

 

 

 

 

 

(109,853

)

 

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas receivables

 

19,553

 

 

 

9,957

 

 

 

 

 

 

29,510

 

 

1,630

 

 

 

(8,635

)

 

 

 

 

 

(7,005

)

Joint interest and other receivables

 

(4,255

)

 

 

 

 

 

 

 

 

(4,255

)

 

(1,126

)

 

 

 

 

 

 

 

 

(1,126

)

Income taxes

 

30,747

 

 

 

(27,604

)

 

 

 

 

 

3,143

 

 

(64,274

)

 

 

 

 

 

 

 

 

(64,274

)

Prepaid expenses and other assets

 

25,555

 

 

 

12,882

 

 

 

(23,425

)

 

 

15,012

 

 

(14,395

)

 

 

(78,547

)

 

 

77,996

 

 

 

(14,946

)

Asset retirement obligation settlements

 

(57,253

)

 

 

(17,060

)

 

 

 

 

 

(74,313

)

 

(49,303

)

 

 

(23,017

)

 

 

 

 

 

(72,320

)

Accounts payable, accrued liabilities and other

 

12,816

 

 

 

5,242

 

 

 

23,425

 

 

 

41,483

 

 

46,955

 

 

 

37,538

 

 

 

(77,996

)

 

 

6,497

 

Net cash provided by operating activities

 

276,585

 

 

 

234,838

 

 

 

 

 

 

511,423

 

Net cash provided by (used in) operating activities

 

(36,042

)

 

 

50,222

 

 

 

 

 

 

14,180

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acquisition of property interest in oil and natural gas properties

 

(17,407

)

 

 

(54,827

)

 

 

 

 

 

(72,234

)

Investment in oil and natural gas properties and equipment

 

(312,044

)

 

 

(242,334

)

 

 

 

 

 

(554,378

)

 

(37,418

)

 

 

(11,188

)

 

 

 

 

 

(48,606

)

Investment in subsidiary

 

(62,323

)

 

 

 

 

 

62,323

 

 

 

 

Changes in operating assets and liabilities associated with

investing activities

 

4,340

 

 

 

(39,534

)

 

 

 

 

 

(35,194

)

Proceeds from sales of assets and other, net

 

1,000

 

 

 

500

 

 

 

 

 

 

1,500

 

Purchases of furniture, fixtures and other

 

(3,340

)

 

 

 

 

 

 

 

 

(3,340

)

 

(96

)

 

 

 

 

 

 

 

 

(96

)

Net cash used in investing activities

 

(395,114

)

 

 

(297,161

)

 

 

62,323

 

 

 

(629,952

)

 

(32,174

)

 

 

(50,222

)

 

 

 

 

 

(82,396

)

Financing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Borrowings of long-term debt – revolving bank credit facility

 

556,000

 

 

 

 

 

 

 

 

 

556,000

 

 

340,000

 

 

 

 

 

 

 

 

 

340,000

 

Repayments of long-term debt – revolving bank credit facility

 

(399,000

)

 

 

 

 

 

 

 

 

(399,000

)

 

(340,000

)

 

 

 

 

 

 

 

 

(340,000

)

Dividends to shareholders

 

(30,260

)

 

 

 

 

 

 

 

 

(30,260

)

Issuance of 1.5 Lien Term Loan

 

75,000

 

 

 

 

 

 

 

 

 

75,000

 

Payment of interest on 1.5 Lien Term Loan

 

(2,570

)

 

 

 

 

 

 

 

 

(2,570

)

Debt exchange costs

 

(18,464

)

 

 

 

 

 

 

 

 

(18,464

)

Other

 

(345

)

 

 

 

 

 

 

 

 

(345

)

 

(928

)

 

 

 

 

 

 

 

 

(928

)

Investment from parent

 

 

 

 

62,323

 

 

 

(62,323

)

 

 

 

Net cash provided in financing activities

 

126,395

 

 

 

62,323

 

 

 

(62,323

)

 

 

126,395

 

Increase in cash and cash equivalents

 

7,866

 

 

 

 

 

 

 

 

 

7,866

 

Net cash provided by financing activities

 

53,038

 

 

 

 

 

 

 

 

 

53,038

 

Decrease in cash and cash equivalents

 

(15,178

)

 

 

 

 

 

 

 

 

(15,178

)

Cash and cash equivalents, beginning of period

 

15,800

 

 

 

 

 

 

 

 

 

15,800

 

 

85,414

 

 

 

 

 

 

 

 

 

85,414

 

Cash and cash equivalents, end of period

$

23,666

 

 

$

 

 

$

 

 

$

23,666

 

$

70,236

 

 

$

 

 

$

 

 

$

70,236

 

 

 

111130


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 20132015

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

$

51,322

 

 

$

24,400

 

 

$

(24,400

)

 

$

51,322

 

Adjustments to reconcile net income to net cash

provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

$

(1,192,307

)

 

$

(464,931

)

 

$

612,520

 

 

$

(1,044,718

)

Adjustments to reconcile net loss to net cash

provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

250,818

 

 

 

200,711

 

 

 

 

 

 

451,529

 

 

212,741

 

 

 

181,330

 

 

 

 

 

 

394,071

 

Ceiling test write-down of oil and gas properties

 

616,947

 

 

 

517,880

 

 

 

(147,589

)

 

 

987,238

 

Amortization of debt issuance costs and premium

 

1,645

 

 

 

 

 

 

 

 

 

1,645

 

 

4,411

 

 

 

 

 

 

 

 

 

4,411

 

Share-based compensation

 

11,525

 

 

 

 

 

 

 

 

 

11,525

 

 

10,242

 

 

 

 

 

 

 

 

 

10,242

 

Derivative loss

 

8,470

 

 

 

 

 

 

 

 

 

8,470

 

Derivative gain

 

(14,375

)

 

 

 

 

 

 

 

 

(14,375

)

Cash payments on derivative settlements

 

(8,589

)

 

 

 

 

 

 

 

 

(8,589

)

 

6,703

 

 

 

 

 

 

 

 

 

6,703

 

Deferred income taxes

 

7,564

 

 

 

23,356

 

 

 

 

 

 

30,920

 

 

(77,421

)

 

 

(125,851

)

 

 

 

 

 

(203,272

)

Earnings of affiliates

 

(24,400

)

 

 

 

 

 

24,400

 

 

 

 

Loss of affiliates

 

464,931

 

 

 

 

 

 

(464,931

)

 

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas receivables

 

6,182

 

 

 

(5,202

)

 

 

 

 

 

980

 

 

39,078

 

 

 

(6,842

)

 

 

 

 

 

32,236

 

Joint interest and other receivables

 

34,257

 

 

 

 

 

 

 

 

 

34,257

 

 

21,633

 

 

 

 

 

 

 

 

 

21,633

 

Income taxes

 

54,813

 

 

 

(10,485

)

 

 

 

 

 

44,328

 

 

(7

)

 

 

 

 

 

 

 

 

(7

)

Prepaid expenses and other assets

 

(25,329

)

 

 

(18,835

)

 

 

34,120

 

 

 

(10,044

)

 

(13,916

)

 

 

122,977

 

 

 

(91,245

)

 

 

17,816

 

Asset retirement obligations

 

(65,438

)

 

 

(16,105

)

 

 

 

 

 

(81,543

)

 

(26,637

)

 

 

(5,918

)

 

 

 

 

 

(32,555

)

Accounts payable, accrued liabilities and other

 

59,961

 

 

 

717

 

 

 

(34,120

)

 

 

26,558

 

 

(141,596

)

 

 

4,156

 

 

 

91,245

 

 

 

(46,195

)

Net cash provided by operating activities

 

362,801

 

 

 

198,557

 

 

 

 

 

 

561,358

 

Net cash provided by (used in) operating activities

 

(89,573

)

 

 

222,801

 

 

 

 

 

 

133,228

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acquisition of property interest in oil and natural gas properties

 

 

 

 

(82,424

)

 

 

 

 

 

(82,424

)

Investment in oil and natural gas properties and equipment

 

(349,804

)

 

 

(202,150

)

 

 

 

 

 

(551,954

)

 

(31,534

)

 

 

(198,627

)

 

 

 

 

 

(230,161

)

Changes in operating assets and liabilities associated with

investing activities

 

(29,806

)

 

 

(25,619

)

 

 

 

 

 

(55,425

)

Proceeds from sales of assets and other, net

 

372,939

 

 

 

 

 

 

 

 

 

372,939

 

Investment in subsidiary

 

(86,017

)

 

 

 

 

 

86,017

 

 

 

 

 

(1,445

)

 

 

 

 

 

1,445

 

 

 

 

Proceeds from sales of assets and other, net

 

21,008

 

 

 

 

 

 

 

 

 

21,008

 

Purchases of furniture, fixtures and other

 

(1,435

)

 

 

 

 

 

 

 

 

(1,435

)

 

(1,278

)

 

 

 

 

 

 

 

 

(1,278

)

Net cash used in investing activities

 

(416,248

)

 

 

(284,574

)

 

 

86,017

 

 

 

(614,805

)

Net cash provided by (used) in investing activities

 

308,876

 

 

 

(224,246

)

 

 

1,445

 

 

 

86,075

 

Financing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Borrowings of long-term debt – revolving bank credit facility

 

563,000

 

 

 

 

 

 

 

 

 

563,000

 

 

263,000

 

 

 

 

 

 

 

 

 

263,000

 

Repayments of long-term debt – revolving bank credit facility

 

(443,000

)

 

 

 

 

 

 

 

 

(443,000

)

 

(710,000

)

 

 

 

 

 

 

 

 

(710,000

)

Issuance of 9.00% Second Lien Term Loan

 

297,000

 

 

 

 

 

 

 

 

 

297,000

 

Debt issuance costs

 

(3,892

)

 

 

 

 

 

 

 

 

(3,892

)

 

(6,669

)

 

 

 

 

 

 

 

 

(6,669

)

Dividends to shareholders

 

(58,846

)

 

 

 

 

 

 

 

 

(58,846

)

Other

 

(886

)

 

 

 

 

 

 

 

 

(886

)

Investment from parent

 

 

 

 

86,017

 

 

 

(86,017

)

 

 

 

 

 

 

 

1,445

 

 

 

(1,445

)

 

 

 

Other

 

(260

)

 

 

 

 

 

 

 

 

(260

)

Net cash used in financing activities

 

57,002

 

 

 

86,017

 

 

 

(86,017

)

 

 

57,002

 

Net cash provided by (used in) financing activities

 

(157,555

)

 

 

1,445

 

 

 

(1,445

)

 

 

(157,555

)

Increase in cash and cash equivalents

 

3,555

 

 

 

 

 

 

 

 

 

3,555

 

 

61,748

 

 

 

 

 

 

 

 

 

61,748

 

Cash and cash equivalents, beginning of period

 

12,245

 

 

 

 

 

 

 

 

 

12,245

 

 

23,666

 

 

 

 

 

 

 

 

 

23,666

 

Cash and cash equivalents, end of period

$

15,800

 

 

$

 

 

$

 

 

$

15,800

 

$

85,414

 

 

$

 

 

$

 

 

$

85,414

 

 

 

112131


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 20122014

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

(In thousands)

 

 

 

Operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

$

71,984

 

 

$

49,799

 

 

$

(49,799

)

 

$

71,984

 

Adjustments to reconcile net income to net cash

provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

$

(11,661

)

 

$

8,320

 

 

$

(8,320

)

 

$

(11,661

)

Adjustments to reconcile net income (loss) to net cash

provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

202,018

 

 

 

154,214

 

 

 

 

 

 

356,232

 

 

278,387

 

 

 

232,715

 

 

 

 

 

 

511,102

 

Amortization of debt issuance costs and premium

 

2,575

 

 

 

 

 

 

 

 

 

2,575

 

 

701

 

 

 

 

 

 

 

 

 

701

 

Share-based compensation

 

12,398

 

 

 

 

 

 

 

 

 

12,398

 

 

14,744

 

 

 

 

 

 

 

 

 

14,744

 

Derivative loss

 

13,954

 

 

 

 

 

 

 

 

 

13,954

 

 

(3,965

)

 

 

 

 

 

 

 

 

(3,965

)

Cash payments on derivative settlements

 

(7,664

)

 

 

 

 

 

 

 

 

(7,664

)

 

(5,318

)

 

 

 

 

 

 

 

 

(5,318

)

Deferred income taxes

 

81,653

 

 

 

6,456

 

 

 

 

 

 

88,109

 

 

(32,456

)

 

 

27,696

 

 

 

 

 

 

(4,760

)

Earnings of affiliates

 

(49,799

)

 

 

 

 

 

49,799

 

 

 

 

 

(8,320

)

 

 

 

 

 

8,320

 

 

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas receivables

 

(3,783

)

 

 

4,601

 

 

 

 

 

 

818

 

 

19,553

 

 

 

9,957

 

 

 

 

 

 

29,510

 

Joint interest and other receivables

 

(28,823

)

 

 

 

 

 

 

 

 

(28,823

)

 

(4,255

)

 

 

 

 

 

 

 

 

(4,255

)

Income taxes

 

(76,411

)

 

 

18,400

 

 

 

 

 

 

(58,011

)

 

27,650

 

 

 

(24,507

)

 

 

 

 

 

3,143

 

Prepaid expenses and other assets

 

9,017

 

 

 

(119,895

)

 

 

118,318

 

 

 

7,440

 

 

45,962

 

 

 

(7,525

)

 

 

(23,425

)

 

 

15,012

 

Asset retirement obligations

 

(105,773

)

 

 

(7,054

)

 

 

 

 

 

(112,827

)

 

(57,253

)

 

 

(17,060

)

 

 

 

 

 

(74,313

)

Accounts payable, accrued liabilities and other

 

159,774

 

 

 

(2,504

)

 

 

(118,318

)

 

 

38,952

 

 

11,931

 

 

 

(30,475

)

 

 

23,425

 

 

 

4,881

 

Net cash provided by operating activities

 

281,120

 

 

 

104,017

 

 

 

 

 

 

385,137

 

 

275,700

 

 

 

199,121

 

 

 

 

 

 

474,821

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acquisition of property interest in oil and natural gas properties

 

(151,429

)

 

 

(54,121

)

 

 

 

 

 

(205,550

)

 

(17,407

)

 

 

(54,827

)

 

 

 

 

 

(72,234

)

Investment in oil and natural gas properties and equipment

 

(375,296

)

 

 

(104,017

)

 

 

 

 

 

(479,313

)

 

(312,044

)

 

 

(242,334

)

 

 

 

 

 

(554,378

)

Changes in operating assets and liabilities associated with

investing activities

 

1,733

 

 

 

35,717

 

 

 

 

 

 

37,450

 

Investment in subsidiary

 

(54,121

)

 

 

 

 

 

54,121

 

 

 

 

 

(62,323

)

 

 

 

 

 

62,323

 

 

 

 

Proceeds from sales of assets and other, net

 

30,453

 

 

 

 

 

 

 

 

 

30,453

 

Purchases of furniture, fixtures and other

 

(3,031

)

 

 

 

 

 

 

 

 

(3,031

)

 

(3,340

)

 

 

 

 

 

 

 

 

(3,340

)

Net cash used in investing activities

 

(553,424

)

 

 

(158,138

)

 

 

54,121

 

 

 

(657,441

)

 

(393,381

)

 

 

(261,444

)

 

 

62,323

 

 

 

(592,502

)

Financing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of 8.50% Senior Notes

 

318,000

 

 

 

 

 

 

 

 

 

318,000

 

Borrowings of long-term debt – revolving bank credit facility

 

732,000

 

 

 

 

 

 

 

 

 

732,000

 

 

556,000

 

 

 

 

 

 

 

 

 

556,000

 

Repayments of long-term debt – revolving bank credit facility

 

(679,000

)

 

 

 

 

 

 

 

 

(679,000

)

 

(399,000

)

 

 

 

 

 

 

 

 

(399,000

)

Debt issuance costs

 

(8,510

)

 

 

 

 

 

 

 

 

(8,510

)

Dividends to shareholders

 

(82,832

)

 

 

 

 

 

 

 

 

(82,832

)

 

(30,260

)

 

 

 

 

 

 

 

 

(30,260

)

Other

 

(1,193

)

 

 

 

 

 

 

 

 

(1,193

)

Investment from parent

 

 

 

 

54,121

 

 

 

(54,121

)

 

 

 

 

 

 

 

62,323

 

 

 

(62,323

)

 

 

 

Other

 

379

 

 

 

 

 

 

 

 

 

379

 

Net cash used in financing activities

 

280,037

 

 

 

54,121

 

 

 

(54,121

)

 

 

280,037

 

Net cash provided by financing activities

 

125,547

 

 

 

62,323

 

 

 

(62,323

)

 

 

125,547

 

Increase in cash and cash equivalents

 

7,733

 

 

 

 

 

 

 

 

 

7,733

 

 

7,866

 

 

 

 

 

 

 

 

 

7,866

 

Cash and cash equivalents, beginning of period

 

4,512

 

 

 

 

 

 

 

 

 

4,512

 

 

15,800

 

 

 

 

 

 

 

 

 

15,800

 

Cash and cash equivalents, end of period

$

12,245

 

 

$

 

 

$

 

 

$

12,245

 

$

23,666

 

 

$

 

 

$

 

 

$

23,666

 

 

 

 

113132


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

21. Supplemental Oil and Gas Disclosures—UNAUDITED

Geographic Area of Operation

All of our proved reserves are located within the United States with a majority of those reserves located in the Gulf of Mexico and a minority located in Texas.Mexico.  Therefore, the following disclosures about our costs incurred, results of operations and proved reserves are on a total-company basis.

Capitalized Costs

Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions):

December 31,

 

December 31,

 

2014

 

 

2013

 

 

2012

 

2016

 

 

2015

 

 

2014

 

Net capitalized cost:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved oil and natural gas properties and equipment

$

7,924.2

 

 

$

7,207.1

 

 

$

6,551.5

 

$

7,932.5

 

 

$

7,882.3

 

 

$

7,924.2

 

Unproved oil and natural gas properties and equipment

 

121.5

 

 

 

132.0

 

 

 

143.0

 

 

 

 

 

20.2

 

 

 

121.5

 

Accumulated depreciation, depletion and amortization

related to oil, NGLs and natural gas activities

 

(5,557.6

)

 

 

(5,069.2

)

 

 

(4,640.8

)

Accumulated depreciation, depletion and amortization (1)

related to oil, NGLs and natural gas activities

 

(7,387.8

)

 

 

(6,916.2

)

 

 

(5,557.6

)

Net capitalized costs related to producing activities

$

2,488.1

 

 

$

2,269.9

 

 

$

2,053.7

 

$

544.7

 

 

$

986.3

 

 

$

2,488.1

 

Costs Not Subject To Amortization

Costs not subject to amortization relate to unproved properties which are excluded from amortizable capital costs until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred.  Subject to industry conditions, evaluation of most of these properties is expected to be completed within one to five years.  The following table provides a summary of costs that are not being amortized as of December 31, 2014, by the year in which the costs were incurred (in millions):

 

Total

 

 

2014

 

 

2013

 

 

2012

 

 

Prior to

2012

 

Costs excluded by year incurred:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acquisition costs

$

75.5

 

 

$

2.6

 

 

$

5.7

 

 

$

7.0

 

 

$

60.2

 

Capitalized interest not subject to amortization

 

34.3

 

 

 

7.5

 

 

 

7.3

 

 

 

6.4

 

 

 

13.1

 

Total costs not subject to amortization

$

109.8

 

 

$

10.1

 

 

$

13.0

 

 

$

13.4

 

 

$

73.3

 


114


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

(1)

Includes ceiling test write-down in 2016 and 2015.

Costs Incurred In Oil and Gas Property Acquisition, Exploration and Development Activities

The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions):

 

December 31,

 

Year Ended December 31,

 

2014

 

 

2013

 

 

2012

 

2016

 

 

2015

 

 

2014

 

Costs incurred: (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved properties acquisitions

$

111.5

 

 

$

96.9

 

 

$

239.8

 

$

1.3

 

 

$

15.6

 

 

$

111.5

 

Exploration (2) (3)

 

411.1

 

 

 

215.3

 

 

 

151.3

 

 

4.8

 

 

 

152.4

 

 

 

411.1

 

Development

 

198.7

 

 

 

352.9

 

 

 

363.7

 

 

56.9

 

 

 

65.5

 

 

 

198.7

 

Unproved properties acquisitions (4)

 

3.1

 

 

 

26.3

 

 

 

26.5

 

 

0.5

 

 

 

0.1

 

 

 

3.1

 

Total costs incurred in oil and gas property acquisition,

exploration and development activities

$

724.4

 

 

$

691.4

 

 

$

781.3

 

$

63.5

 

 

$

233.6

 

 

$

724.4

 

(1)

Includes net addition from capitalized ARO of $10.8 million in 2016, net reductions from capitalized ARO of $0.4 million in 2015, and net additions from capitalized ARO of $88.0 million $50.6 million and $86.9 million during 2014, 2013 and 2012, respectively,2014.  These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates.  

(2)

Includes seismic costs of $9.0$0.2 million, $8.9$3.2 million and $6.2$9.0 million incurred during 2014, 20132016, 2015 and 2012,2014, respectively.

(3)

Includes geological and geophysical costs charged to expense of $4.1 million, $5.7 million and $7.3 million $5.9 millionduring 2016, 2015 and $6.2 million during 2014, 2013 and 2012, respectively.

(4)

The amounts for unproved property acquisitions include capitalized interest associated with unproved properties acquired during the period.

133


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Depreciation, depletion, amortization and accretion expense

The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent (“Boe”) of products sold.

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Depreciation, depletion, amortization and accretion per Boe

$

28.98

 

 

$

25.10

 

 

$

20.79

 

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Depreciation, depletion, amortization and accretion per Boe

$

13.77

 

 

$

23.11

 

 

$

28.98

 

Oil and Natural Gas Reserve Information

There are numerous uncertainties in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures.  The following reserve information representrepresents estimates only and are inherently imprecise and may be subject to substantial revisions as additional information such as reservoir performance, additional drilling, technological advancements and other factors become available.  Decreases in the prices of oil, NGLs and natural gas could have an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow.  We are not the operator with respect to approximately 11%19% of our proved developed non-producing reserves as of December 31, 2016 so we may not be in a position to control the timing of all development activities.  We are the operator for all of our proved undeveloped reserves as of December 31, 2016.  In prior years, we were not the operator of all proved undeveloped reserves.

The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves.  All of the reserves are located in the Unites States with 69%all located in state and federal waters in the Gulf of Mexico and the remainder located in the West Texas Permian Basin.  TheseMexico.  The reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information.  In addition to other criteria, estimated reserves are assessed for economicallyeconomic viability based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB.  The prices used do not purport, nor should it be interpreted, to present the current market prices related to our estimated oil and natural gas reserves.  Actual future prices and costs may differ materially from those used in determining our proved reserves for the periods presented.  The prices used are presented in the section below entitled “Standardized Measure of Discounted Future Net Cash Flows”.

 

115134


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Energy Equivalent Reserves (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Energy Equivalent Reserves (1)

 

Oil

(MMBbls)

 

 

NGLs

(MMBbls)

 

 

Natural Gas

(Bcf)

 

 

Oil

Equivalent

(MMBoe)

 

 

Natural Gas

Equivalent

(Bcfe)

 

Oil

(MMBbls)

 

 

NGLs

(MMBbls)

 

 

Natural Gas

(Bcf)

 

 

Oil

Equivalent

(MMBoe)

 

 

Natural Gas

Equivalent

(Bcfe)

 

Proved reserves as of Dec. 31, 2011

 

51.4

 

 

 

17.1

 

 

 

289.7

 

 

 

116.9

 

 

 

701.1

 

Proved reserves as of Dec. 31, 2013

 

58.5

 

 

 

15.9

 

 

 

259.9

 

 

 

117.7

 

 

 

705.9

 

Revisions of previous estimates (2)

 

(1.1

)

 

 

(2.6

)

 

 

(4.8

)

 

 

(4.6

)

 

 

(27.5

)

 

1.6

 

 

 

0.1

 

 

 

14.3

 

 

 

4.1

 

 

 

25.3

 

Extensions and discoveries (3)

 

8.2

 

 

 

2.6

 

 

 

29.6

 

 

 

15.7

 

 

 

94.5

 

 

7.3

 

 

 

0.7

 

 

 

10.1

 

 

 

9.7

 

 

 

58.1

 

Purchase of minerals in place (4)

 

2.5

 

 

 

0.2

 

 

 

25.5

 

 

 

7.0

 

 

 

42.0

 

 

1.5

 

 

 

1.2

 

 

 

20.7

 

 

 

6.1

 

 

 

36.5

 

Sales of reserves (5)

 

(0.2

)

 

 

 

 

 

(1.1

)

 

 

(0.4

)

 

 

(2.2

)

Production

 

(6.0

)

 

 

(2.1

)

 

 

(53.8

)

 

 

(17.1

)

 

 

(102.8

)

 

(7.2

)

 

 

(2.1

)

 

 

(50.1

)

 

 

(17.6

)

 

 

(105.8

)

Proved reserves as of Dec. 31, 2012

 

54.8

 

 

 

15.2

 

 

 

285.1

 

 

 

117.5

 

 

 

705.1

 

Revisions of previous estimates (6)

 

(4.3

)

 

 

0.2

 

 

 

2.1

 

 

 

(3.8

)

 

 

(22.8

)

Proved reserves as of Dec. 31, 2014

 

61.7

 

 

 

15.8

 

 

 

254.9

 

 

 

120.0

 

 

 

720.0

 

Revisions of previous estimates (5)

 

4.8

 

 

 

(0.9

)

 

 

4.9

 

 

 

4.7

 

 

 

28.0

 

Revisions related to sold properties (6)

 

(12.1

)

 

 

(4.8

)

 

 

(2.9

)

 

 

(17.4

)

 

 

(104.3

)

Extensions and discoveries (7)

 

13.9

 

 

 

2.6

 

 

 

22.0

 

 

 

20.2

 

 

 

121.0

 

 

2.4

 

 

 

0.2

 

 

 

8.8

 

 

 

4.1

 

 

 

24.4

 

Purchase of minerals in place (8)

 

1.5

 

 

 

 

 

 

4.4

 

 

 

2.3

 

 

 

13.7

 

 

 

 

 

 

 

 

6.1

 

 

 

1.0

 

 

 

6.1

 

Sales of reserves (9)

 

(0.4

)

 

 

 

 

 

(0.4

)

 

 

(0.5

)

 

 

(3.2

)

 

(13.5

)

 

 

(2.1

)

 

 

(20.2

)

 

 

(19.0

)

 

 

(113.8

)

Production

 

(7.0

)

 

 

(2.1

)

 

 

(53.3

)

 

 

(18.0

)

 

 

(107.9

)

 

(7.8

)

 

 

(1.6

)

 

 

(46.2

)

 

 

(17.0

)

 

 

(102.3

)

Proved reserves as of Dec. 31, 2013

 

58.5

 

 

 

15.9

 

 

 

259.9

 

 

 

117.7

 

 

 

705.9

 

Proved reserves as of Dec. 31, 2015

 

35.5

 

 

 

6.6

 

 

 

205.4

 

 

 

76.4

 

 

 

458.1

 

Revisions of previous estimates (10)

 

1.6

 

 

 

0.1

 

 

 

14.3

 

 

 

4.1

 

 

 

25.3

 

 

4.6

 

 

 

3.1

 

 

 

32.1

 

 

 

13.0

 

 

 

78.1

 

Extensions and discoveries (11)

 

7.3

 

 

 

0.7

 

 

 

10.1

 

 

 

9.7

 

 

 

58.1

 

Purchase of minerals in place (12)

 

1.5

 

 

 

1.2

 

 

 

20.7

 

 

 

6.1

 

 

 

36.5

 

Production

 

(7.2

)

 

 

(2.1

)

 

 

(50.1

)

 

 

(17.6

)

 

 

(105.8

)

 

(7.2

)

 

 

(1.5

)

 

 

(39.7

)

 

 

(15.4

)

 

 

(92.2

)

Proved reserves as of Dec. 31, 2014

 

61.7

 

 

 

15.8

 

 

 

254.9

 

 

 

120.0

 

 

 

720.0

 

Proved reserves as of Dec. 31, 2016

 

32.9

 

 

 

8.2

 

 

 

197.8

 

 

 

74.0

 

 

 

444.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year-end proved developed reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2016

 

26.6

 

 

 

7.6

 

 

 

183.1

 

 

 

64.7

 

 

 

388.2

 

2015

 

29.4

 

 

 

6.4

 

 

 

198.5

 

 

 

69.0

 

 

 

413.5

 

2014

 

35.7

 

 

 

10.7

 

 

 

221.1

 

 

 

83.3

 

 

 

499.7

 

 

35.7

 

 

 

10.7

 

 

 

221.1

 

 

 

83.3

 

 

 

499.7

 

2013

 

36.2

 

 

 

11.1

 

 

 

232.7

 

 

 

86.1

 

 

 

516.1

 

2012

 

35.3

 

 

 

11.0

 

 

 

243.5

 

 

 

86.9

 

 

 

521.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year-end proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 (13)

 

26.0

 

 

 

5.1

 

 

 

33.8

 

 

 

36.7

 

 

 

220.3

 

2013

 

22.3

 

 

 

4.8

 

 

 

27.2

 

 

 

31.6

 

 

 

189.8

 

2012

 

19.5

 

 

 

4.2

 

 

 

41.6

 

 

 

30.6

 

 

 

183.9

 

2016 (11)

 

6.3

 

 

 

0.6

 

 

 

14.7

 

 

 

9.3

 

 

 

55.8

 

2015

 

6.1

 

 

 

0.2

 

 

 

6.9

 

 

 

7.4

 

 

 

44.6

 

2014

 

26.0

 

 

 

5.1

 

 

 

33.8

 

 

 

36.7

 

 

 

220.3

 

 

Volume measurements:

 

 

Bbl – barrel

 

Mcf – thousand cubic feet

MMBbls – million barrels for crude oil, condensate or NGLs

 

Bcf – billion cubic feet

MMBoe – million barrels of oil equivalent

 

Bcfe – billion cubic feet of gas equivalent

 

116135


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

 

(1)

The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one Bblbarrel of crude oil, condensate or NGLs (totals may not compute due to rounding).  The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly.

(2)

Includes downward revisions due to price of 1.3 MMBoe and negative performance revisions of 3.0 MMBoe at our Spraberry field.

(3)

Includes extensions and discoveries of 11.6 MMBoe at our Spraberry field and extensions and discoveries of 2.7 MMBoe at our High Island 21/22 field.

(4)

Due to the acquisition of the Newfield Properties.

(5)

Due to the sale of our interest in the South Timbalier 41 field.

(6)

Includes upward revision due to price of 1.9 MMBoe; negative revisions of 4.9 MMBoe at our Spraberry field for performance and technical changes, 2.3 MMBoe at our High Island 21/22 field for performance, 1.3 MMBoe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 0.7 MMBoe at our Main Pass 98 field, 0.7 MMBoe at our South Timbalier 314, 0.6 MMBoe at our Main Pass 108 field and 0.5 MMBoe our South Timbalier 176 field.  

(7)

Includes extensions and discoveries of 12.6 MMBoe at our Spraberry field, 4.2 MMBoe at our Ship Shoal 349 field and 1.9 MMBoe at our Mississippi Canyon 698 field.

(8)

Primarily due to the acquisition of the Callon Properties.

(9)

Primarily due to the sales of our non-working interests in the Green Canyon 60 field, the Green Canyon 19 field and the West Delta area block 29.

(10)

Includes upwards revisions due to price of 0.3 MMBoe; positive revisions of 2.4 MMBoe at our Fairway field,Field, 1.2 MMBoe at our Mississippi Canyon 800 field and 6.4 MMBoe at various fields; and negative revisions of 3.9 MMBoe at our SpraberryYellow Rose field and 2.4 MMBoe at various other fields.

(11)(3)

Includes extensions and discoveries of 4.1 MMBoe at our SpraberryYellow Rose field and 4.1 MMBoe at our Mississippi Canyon 782 field.

(12)(4)

Primarily due to acquiring additional ownership in the Fairway fieldField and acquisition of the Woodside Properties.

(13)(5)

Includes upwards revisions of 7.4 MMBoe at the Ship Shoal 349 field (Mahogany), 1.9 MMBoe at our Brazo A-133 field, 1.3 MMBoe at out Atwater 575 field, 1.3 MMBoe at out Mississippi Canyon 243 field (Matterhorn), 1.1 MMBoe at our Fairway Field, partially offset by downward revisions due to price of 10.7 MMBoe.  The revision for price excludes the Yellow Rose field sold during 2015.

(6)

Revisions related to the Yellow Rose field during 2015, which were primarily due to price reductions, up to the date of the sale in October 2015.

(7)

Primarily due to increases at our Ewing Bank 910 field.

(8)

Primarily due to purchase of additional interest at our Brazos A-133 field.

(9)

Related primarily to the sale of the Yellow Rose field in October 2015, which had estimated reserves at the date of sale of 19.0 MMBoe.  

(10)

Primarily related to upward revisions of 14.2 MMBoe, which included upward revisions of 3.8 MMBoe at our Viosca Knoll 823 (Tahoe/SE Tahoe) field, 1.5 MMBoe at our Fairway field, 1.3 MMBoe at our Mississippi Canyon 782 (Dantzler) field, and 1.2 MMBoe at our Main Pass 108 field.  Partially offsetting were decreases for price revisions of 1.2 MMBoe.

(11)

We believe that we will be able to develop all but 1.41.3 MMBoe, or approximately 14%, of the total of 9.3 MMBoe reserves classified as proved undeveloped (“PUDs”), or approximately 96%, out of the total of 36.7 MMBoe classified as PUDs at December 31, 2014,2016, within five years from the date such reserves were initially recorded.  The lone exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan.  The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells.  These PUDs wereOne of the sidetrack PUD locations in this field was originally recorded in our proved reserves as of December 31, 2010.  The development of the 1.4 MMBoe of PUDsthis PUD will be delayed until an existing well is depleted and available to sidetrack.  Based on the latest reserve report, a well is expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDsthis PUD location in 2020.2023.

136


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Standardized Measure of Discounted Future Net Cash Flows

The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein.  Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented.  All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials.  Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the crude oil realized price.  Then, this ratio is applied to the crude oil price using FASB/SEC guidance.  The average commodity prices weighted by field production and after adjustments related to the proved reserves are as follows:

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

2013

 

Oil - per barrel

$

36.28

 

 

$

46.94

 

 

$

91.12

 

 

$

99.65

 

NGLs per barrel

 

16.82

 

 

 

17.60

 

 

 

34.63

 

 

 

35.21

 

Natural gas per Mcf

 

2.47

 

 

 

2.50

 

 

 

4.27

 

 

 

3.80

 

Future production, development costs and ARO are based on costs in effect at the end of each of the respective years with no escalations.  Estimated future net cash flows, net of future income taxes, have been discounted to their present values based on a 10% annual discount rate.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of our oil and natural gas reserves.  These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2016 or later years and the risks inherent in reserve estimates.  The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Standardized Measure of Discounted Future Net Cash Flows

The following presents the standardized measure of discounted future

Future cash inflows

$

1,818.4

$

2,296.7

$

7,258.5

Future costs:

Production

(691.5

)

(840.1

)

(2,224.5

)

Development

(141.1

)

(161.4

)

(922.0

)

Dismantlement and abandonment

(427.7

)

(471.8

)

(475.4

)

Income taxes (1)

(948.4

)

Future net cash flows related to our proved oil and natural gas reserves together with changes therein.  Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented.  All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials.  Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the oil realized price.  Then, this ratio is applied to the oil price using FASB/SEC guidance.  The average commodity prices weighted by field production related to the proved reserves are as follows:before 10% discount

558.1

823.4

2,688.2

10% annual discount factor

(79.8

)

(209.5

)

(985.4

)

Total

$

478.3

$

613.9

$

1,702.8

 

 

December 31,

 

 

2014

 

 

2013

 

 

2012

 

 

2011

 

Oil - per barrel

$

91.12

 

 

$

99.65

 

 

$

98.13

 

 

$

97.36

 

NGLs per barrel

 

34.63

 

 

 

35.21

 

 

 

47.30

 

 

 

51.30

 

Natural gas - per Mcf

 

4.27

 

 

 

3.80

 

 

 

2.77

 

 

 

4.11

 

 

117(1)


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Future production, development costs and ARO are based on costs in effect at the end of each of the respective years with no escalations.  Estimated future net cash flows, net ofNo future income taxes have been discountedwere estimated to their present values based on a 10% annual discount rate.

The standardized measure of discountedbe paid in 2016 and 2015 as our tax position has sufficient tax basis to offset estimated future net cash flows does not purport, nor should it be interpreted,taxes.  State income taxes were disregarded due to present the fair market value of our oil and natural gas reserves.  These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2014 or later years and the risks inherent in reserve estimates.  The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions):immateriality.

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Standardized Measure of Discounted Future Net Cash Flows

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows

$

7,258.5

 

 

$

7,376.7

 

 

$

6,888.4

 

Future costs:

 

 

 

 

 

 

 

 

 

 

 

Production

 

(2,224.5

)

 

 

(2,142.8

)

 

 

(1,858.3

)

Development

 

(922.0

)

 

 

(1,001.4

)

 

 

(655.4

)

Dismantlement and abandonment

 

(475.4

)

 

 

(441.6

)

 

 

(508.0

)

Income taxes

 

(948.4

)

 

 

(986.9

)

 

 

(1,002.1

)

Future net cash inflows before 10% discount

 

2,688.2

 

 

 

2,804.0

 

 

 

2,864.6

 

10% annual discount factor

 

(985.4

)

 

 

(1,129.4

)

 

 

(1,018.2

)

Total

$

1,702.8

 

 

$

1,674.6

 

 

$

1,846.4

 

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Changes in Standardized Measure

 

 

 

 

 

 

 

 

 

 

 

Standardized measure, beginning of year

$

1,674.6

 

 

$

1,846.4

 

 

$

2,006.4

 

Increases (decreases):

 

 

 

 

 

 

 

 

 

 

 

Sales and transfers of oil and gas produced, net of production

       costs

 

(650.9

)

 

 

(686.1

)

 

 

(620.4

)

Net changes in price, net of future production costs

 

(278.6

)

 

 

(65.2

)

 

 

(224.3

)

Extensions and discoveries, net of future production and

        development costs

 

309.6

 

 

 

393.8

 

 

 

181.9

 

Changes in estimated future development costs

 

(56.4

)

 

 

(91.1

)

 

 

(103.3

)

Previously estimated development costs incurred

 

263.1

 

 

 

262.1

 

 

 

332.9

 

Revisions of quantity estimates

 

118.6

 

 

 

(91.6

)

 

 

(128.1

)

Accretion of discount

 

180.6

 

 

 

202.2

 

 

 

231.1

 

Net change in income taxes

 

(11.4

)

 

 

56.6

 

 

 

99.7

 

Purchases of reserves in-place

 

86.7

 

 

 

79.6

 

 

 

270.2

 

Sales of reserves in-place

 

 

 

 

(53.1

)

 

 

(16.1

)

Changes in production rates due to timing and other

 

66.9

 

 

 

(179.0

)

 

 

(183.6

)

Net increase (decrease) in standardized measure

 

28.2

 

 

 

(171.8

)

 

 

(160.0

)

Standardized measure, end of year

$

1,702.8

 

 

$

1,674.6

 

 

$

1,846.4

 


Item 9. Changes

137


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The change in the standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions):

 

Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Changes in Standardized Measure

 

 

 

 

 

 

 

 

 

 

 

Standardized measure, beginning of year

$

613.9

 

 

$

1,702.8

 

 

$

1,674.6

 

Increases (decreases):

 

 

 

 

 

 

 

 

 

 

 

Sales and transfers of oil and gas produced, net of production

       costs

 

(218.6

)

 

 

(289.1

)

 

 

(650.9

)

Net changes in price, net of future production costs

 

(275.2

)

 

 

(1,455.6

)

 

 

(278.6

)

Extensions and discoveries, net of future production and

        development costs

 

 

 

 

65.3

 

 

 

309.6

 

Changes in estimated future development costs

 

(32.5

)

 

 

(8.5

)

 

 

(56.4

)

Previously estimated development costs incurred

 

114.5

 

 

 

158.9

 

 

 

263.1

 

Revisions of quantity estimates

 

190.1

 

 

 

137.9

 

 

 

118.6

 

Accretion of discount

 

52.6

 

 

 

150.6

 

 

 

180.6

 

Net change in income taxes

 

 

 

 

600.8

 

 

 

(11.4

)

Purchases of reserves in-place

 

 

 

 

6.0

 

 

 

86.7

 

Sales of reserves in-place

 

 

 

 

(401.4

)

 

 

 

Changes in production rates due to timing and other

 

33.5

 

 

 

(53.8

)

 

 

66.9

 

Net increase (decrease) in standardized measure

 

(135.6

)

 

 

(1,088.9

)

 

 

28.2

 

Standardized measure, end of year

$

478.3

 

 

$

613.9

 

 

$

1,702.8

 


Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

 

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that any information relating to us is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have each concluded that as of December 31, 20142016 our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2014,2016, is set forth in “Management’s Report on Internal Control over Financial Reporting” included under Part II, Item 8 in this Form 10-K.

Attestation Report of the Registered Public Accounting Firm

The effectiveness of our internal control over financial reporting as of December 31, 2014,2016, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included under Part II, Item 8 in this Form 10-K.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting that occurred during the quarterly period ended December 31, 20142016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

Item 9B. Other Information

None.

 


PARTPART III

 

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K and to the information set forth following Item 3 of this report.

 

Item 11. Executive Compensation

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

 

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

 

Item 14. Principal Accountant Fees and Services

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

 

 

 


PARTPART IV

 

Item 15. Exhibits and Financial Statement Schedules

(a) Documents filed as a part of this report:

1.

Financial Statements.  See “Index to Consolidated Financial Statements” in Part II, Item 8 of this Form 10-K.

All schedules are omitted because they are not applicable, not required or the required information is included in the consolidated financial statements or related notes.

2.

Exhibits:

Exhibit

Number

  

Description

 

2.1

 

Purchase and Sale Agreement, dated September 17, 2012, between Newfield Exploration Company, Newfield Exploration Gulf Coastas of August 31, 2015, by and among Ajax Resources, LLC, as Sellers,Buyer, and W&T Offshore, Inc., as Seller (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed October 12, 201221, 2015 (File No. 001-32414))

 

2.2

 

 

First Amendment to Purchase and Sale Agreement, dated October 5, 2012, between Newfield Exploration Company, Newfield Exploration Gulf Coast LLC, as Sellers, and W&T Offshore, Inc. (Incorporated by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-K, filed October 12, 2012 (File No. 001-32414))

2.3

Purchase and Sale Agreement, dated as of October 17, 2013, by and among Callon Petroleum Operating Company, as Seller, and W&T Offshore, Inc., as Buyer (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed November 7, 2013 (File No. 001-32414))

3.1

  

Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed February 24, 2006 (File No. 001-32414))

 

3.2

  

Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

 

3.3

  

Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q, filed July 31, 2012 (File No. 001-32414))

 

3.4

Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc., dated as of September 6, 2016 (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed September 6, 2016 (File No. 001-32414))

4.1

  

Specimen Common Stock Certificate.Certificate (Incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

 

4.2

  

Indenture, dated as of June 10, 2011, by and among W&T Offshore, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee.trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed June 15, 2011 (File No. 001-32414))

 

4.3

  

First Supplemental Indenture, dated as of June 10, 2011, by and among W&T Offshore, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee.trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed June 15, 2011 (File No. 001-32414))

 

4.4

  

Form of 8.50% Senior Notes due 2019.2019 (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K, filed June 15, 2011 (File No. 001-32414))

 

10.1*

4.5

First Supplemental Indenture, dated as of September 7, 2016, by and among W&T Offshore, Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

 

 


Exhibit
Number

Description

4.6

9.00% / 10.75% Senior Second Lien PIK Toggle Notes due 2020 Indenture, dated as of September 7, 2016, by and among W&T Offshore, Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

4.7

Form of 9.00% / 10.75% Senior Second Lien PIK Toggle Notes due 2020 (included in Exhibit 4.2) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

4.8

8.50% / 10.00% Senior Third Lien PIK Toggle Notes due 2021 Indenture, dated as of September 7, 2016, by and among W&T Offshore, Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

4.9

Form of 8.50% / 10.00% Senior Third Lien PIK Toggle Notes due 2021 (included in Exhibit 4.4) (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

4.10

Registration Rights Agreement, dated as of September 7, 2016, by and among W&T Offshore, Inc. and the initial holders named therein (Incorporated by reference to Exhibit 4.6 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

10.1*

2004 Directors Compensation Plan of W&T Offshore, Inc. (Incorporated by reference to Exhibit 10.11 of the Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

 

10.2*

  

Indemnification and Hold Harmless Agreement by and between W&T Offshore, Inc. and Stephen L. Schroeder, dated July 5, 2006.2006 (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed July 12, 2006 (File No. 001-32414))

 

10.3*

  

Indemnification and Hold Harmless Agreement by and between W&T Offshore, Inc. and John D. Gibbons, dated as of February 26, 2007.2007 (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed February 26, 2007 (File No. 001-32414))


Exhibit
Number

Description

 

10.4*

 

 

10.4*

Indemnification and Hold Harmless Agreement, dated September 24, 2008, by and between W&T Offshore, Inc. and Jamie L. Vazquez.Vazquez (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K, filed September 26, 2008 (File No. 001-32414))

 

10.5*

  

W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan.Plan (Incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A, filed April 2, 2010 (File No. 001-32414))

10.6*

 

 

10.6*

First Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan.Plan (Incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed April 3, 2013)

10.7*

 

 

10.7*

Second Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan.Plan (Incorporated by reference to Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed April 3, 2013)

 


Exhibit
Number

Description

10.8*

Third Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (Incorporated by reference to Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed March 24, 2016)

 

 

10.9*

Form of Employment Agreement for Executive Officers other than the Chief Executive Officer.Officer (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed August 6, 2010 (File No. 001-32414))

 

10.9*

 

 

10.10*

Employment Agreement between W&T Offshore, Inc. and Tracy W. Krohn dated as of November 1, 2010.2010 (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on November 5, 2010 (File No. 001-32414))

 

10.10*

 

 

10.11*

Form of Indemnification and Hold Harmless Agreement between W&T Offshore, Inc. and each of its directors.directors (Incorporated by reference to Exhibit 10.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 001-32414))

 

10.11*

 

 

10.12*

Form of Employment Agreement by and between W&T Offshore, Inc. and Thomas P. Murphy.Murphy (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed August 6, 2010 (File No. 001-32414))

 

10.12*

 

 

10.13*

Indemnification and Hold Harmless Agreement by and between W&T Offshore, Inc. and Thomas P. Murphy, dated as of June 19, 2012.2012  (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed June 22, 2012 (File No. 001-32414))

10.13*

 

 

Form of 2013 Executive Annual Incentive Award Agreement.  (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q, filed August 8, 2013 (File No. 001-32414))

10.14*

 

Form of 2013 Executive Restricted Stock Unit Agreement.  (Incorporated by reference to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q, filed August 8, 2013 (File No. 001-32414))

10.15*

Form of 2013 Executive Time Based Restricted Stock Unit Agreement.  (Incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q, filed August 8, 2013 (File No. 001-32414))

10.16*

Tracy W. Krohn  Executive Annual Incentive Award Agreement for Fiscal 2013.2013  (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q, filed August 8, 2013 (File No. 001-32414))

 

10.17

 

 

10.15

Fifth Amended and Restated Credit Agreement, dated as of November 8, 2013, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto.thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed November 13, 2013 (File No. 001-32414))

10.18*

10.16*

 

Form of Executive Annual Incentive Agreement for Fiscal 2014.2014 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q, filed May 8, 2014 (File No. 001-32414))

10.19*

10.17*

 

Form of 2014 Executive Restricted Stock Unit Agreement.Agreement (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q, filed May 8, 2014 (File No. 001-32414))

10.20*

10.18*

 

Tracy W. Krohn Executive Annual Incentive Agreement for Fiscal 2014.2014 (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q, filed May 8, 2014 (File No. 001-32414))

 

12.1**

10.19

First Amendment to Fifth Amended and Restated Credit Agreement, dated as of April 23, 2015, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent, and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed April 27, 2015 (File No. 001-32414))

 

 

Ratio10.20

Second Amendment to Fifth Amended and Restated Credit Agreement, dated as of EarningsMay 8, 2015, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by reference to Fixed ChargesExhibit 10.1 of the Company’s Current Report on Form 8-K, filed May 14, 2015 (File No. 001-32414))


Exhibit

Number

  

Description

10.21

14.1

Third Amendment to Fifth Amended and Restated Credit Agreement, dated as of October 30, 2015, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed November 5, 2015 (File No. 001-32414))

 

 

10.22

Fourth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of July 28, 2016, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed August 3, 2016 (File No. 001-32414))

10.23

Fifth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of August 25, 2016, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as administrative agent and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed August 31, 2016 (File No. 001-32414))

10.24  

$300,000,000 Term Loan Agreement, dated May 11, 2015, by and among W&T Offshore, Inc., Morgan Stanley Senior Funding, Inc., as administrative agent and collateral trustee, and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed May 14, 2015 (File No. 001-32414))

10.25  

Intercreditor Agreement, dated May 11, 2015, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as priority lien agent, Morgan Stanley Senior Funding, Inc., as second lien collateral trustee, and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed May 14, 2015 (File No. 001-32414))

10.26

Form of Support Agreement, effective July 25, 2016, by and among W&T Offshore, Inc. and certain Supporting Noteholders (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed July 25, 2016 (File No. 001-32414))

10.27

Form of Amendment to Support Agreement by and among the Company and the Supporting Noteholders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed August 16, 2016 (File No. 001-32414))

10.28

1.5 Lien Term Loan Credit Agreement, dated as of September 7, 2016, by and among W&T Offshore, Inc., Cortland Capital Market Services LLC, as Administrative Agent and 1.5 Lien Collateral Agent, and the various lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

10.29

Priority Confirmation Joinder, dated as of September 7, 2016, by and between Toronto Dominion (Texas) LLC, as Priority Lien Agent, Cortland Capital Market Services LLC, as Administrative Agent and 1.5 Lien Collateral Agent, and Morgan Stanley Senior Funding, Inc., as Second Lien Collateral Trustee (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

10.30

Priority Confirmation Joinder, dated as of September 7, 2016, by and between Toronto Dominion (Texas) LLC, as Priority Lien Agent, Wilmington Trust, National Association, as Second Lien Trustee, and Morgan Stanley Senior Funding, Inc., as Second Lien Collateral Trustee (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))


Exhibit
Number

Description

10.31

Priority Confirmation Joinder, dated as of September 7, 2016, by and between Toronto Dominion (Texas) LLC, as Priority Lien Agent, Morgan Stanley Senior Funding, Inc., as Second Lien Collateral Trustee, and Wilmington Trust, National Association, as Third Lien Trustee and Third Lien Collateral Trustee (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K, filed September 13, 2016 (File No. 001-32414))

10.32*

Form of Executive Annual Incentive Agreement for Fiscal 2015 (Incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q, filed November 6, 2015 (File No. 001-32414))

10.33*

Form of 2015 Executive Restricted Stock Unit Agreement (Incorporated by reference to Exhibit 10.23 of the Company’s Annual Report on Form 10-K, filed March 9, 2016 (File No. 001-32414))

10.34*

Form of Executive Annual Incentive Agreement for Fiscal 2016 (Incorporated by reference to Exhibit 10.9 of the Company’s Quarterly Report on Form 10-Q, filed November 3, 2016 (File No. 001-32414))

10.35*

Form of 2016 Executive Restricted Stock Unit Agreement (Incorporated by reference to Exhibit 10.10 of the Company’s Quarterly Report on Form 10-Q, filed November 3, 2016 (File No. 001-32414))

12.1**

Ratio of Earnings to Fixed Charges

14.1

W&T Offshore, Inc. Code of Business Conduct and Ethics (as amended).  (Incorporated by reference to Exhibit 14.1 of the Company’s Current Report on Form 8-K, filed November 17, 2005)

 

21.1**

 

Subsidiaries of the Registrant.

 

23.1**

 

Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.

 

23.2**

 

Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.

 

31.1**

 

Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

 

31.2**

 

Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

 

32.1**

 

Certification of Chief Executive Officer and Chief Financial Officer of W&T Offshore, Inc. pursuant to 18 U.S.C. § 1350.

 

99.1**

 

Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.

 

101.INS**

 

XBRL Instance Document.

 

101.SCH**

 

XBRL Schema Document.

 

101.CAL**

 

XBRL Calculation Linkbase Document

 

101.DEF**

 

XBRL Definition Linkbase Document.

 

101.LAB**

 

XBRL Label Linkbase Document.

 

101.PRE**

 

XBRL Presentation Linkbase Document.

*

Management Contract or Compensatory Plan or Arrangement.

**

Filed or furnished herewith.

 


GLOSSARY OF OIL AND NATURALNATURAL GAS TERMS

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry that are used in this report.

Acquisitions.  Refers to acquisitions, mergers or exercise of preferential rights of purchase.

Bbl.  One stock tank barrel or 42 U.S. gallons liquid volume.

Bcf.  Billion cubic feet.

Bcfe.  One billion cubic feet equivalent, determined using an energy-equivalent ratio of six Mcf of natural gas to one Bblbarrel of crude oil, condensate or natural gas liquids.

Boe.  Barrel of oil equivalent.

Boe/d. Barrel of oil equivalent per day.

BOEM.  Bureau of Ocean Energy Management.  The agency is responsible for managing development of the nation’s offshore resources in an environmentally and economically responsible way.  Previously, this function was managed by the Bureau of Ocean Energy Management, Regulation and Enforcement.

BOEMRE.  Bureau of Ocean Energy Management, Regulation and Enforcement (formerly the Minerals Management Service), was the federal agency that manages the nation’s natural gas, oil and other mineral resources on the outer continental shelf.  The BOEMRE was split into three separate entities: the Office of Natural Resources Revenue; the Bureau of Ocean Energy Management; and the Bureau of Safety and Environmental Enforcement.

BSEE.  Bureau of Safety and Environmental Enforcement.  The agency is responsible for enforcement of safety and environmental regulations.  Previously, this function was managed by the Bureau of Ocean Energy Management, Regulation and Enforcement.

Conventional shelf well.  A well drilled in water depths less than 500 feet.

Deep shelf well.  A well drilled on the outer continental shelf to subsurface depths greater than 15,000 feet and water depths of less than 500 feet.

Deepwater.  Water depths greater than 500 feet in the Gulf of Mexico.

Deterministic estimate.  Refers to a method of estimation whereby a single value for each parameter in the reserves calculation is used in the reserves estimation procedure.

Developed reserves.  Oil and natural gas reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development project.  A project by which petroleum resources are brought to the status of economically producible.  As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Development well.  A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well.  A well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Economically producible.  Refers to a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.


Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

Extension well.  A well drilled to extend the limits of a known reservoir.

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

Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.


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

MBoe.  One thousand barrels of oil equivalent.

Mcf.  One thousand cubic feet.

Mcfe.  One thousand cubic feet equivalent, determined using the energy-equivalent ratio of six Mcf of natural gas to one Bblbarrel of crude oil or other hydrocarbon.

Mcfe/d.  One thousand cubic feet equivalent per day.

MMBbls.  One million barrels of crude oil or other liquid hydrocarbons.

MMBoe.  One million barrels of oil equivalent.

MMBtu.  One million British thermal units.

MMcf.  One million cubic feet.

MMcfe.  One million cubic feet equivalent, determined using an energy-equivalent ratio of six Mcf of natural gas to one Bblbarrel of crude oil condensate or natural gas liquids.

Net acres or net wells.  The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGLs.  Natural gas liquids.  These are created during the processing of natural gas.

Non-productive well.  A well that is found not to have economically producible hydrocarbons.

Oil.  Crude oil and condensate.

OCS.  Outer continental shelf

OCS block.  A unit of defined area for purposes of management of offshore petroleum exploration and production by the BOEM.

ONRR.  Office of Natural Resources Revenue.  The agency assumed the functions of the former Minerals Revenue Management Program, which had been renamed to the Bureau of Ocean Energy Management, Regulation and Enforcement.

Probabilistic estimate.  Refers to a method of estimation whereby the full range of values that could reasonably occur for each unknown parameter in the reserves estimation procedure is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

Productive well.  A well that is found to have economically producible hydrocarbons.

Proved properties.  Properties with proved reserves.

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


this definition, “existing economic conditions” include prices and costs at which economic producibilityproduction from a reservoir is to be determined.  The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.  The SEC provides a complete definition of proved reserves in Rule 4-10(a)(22) of Regulation S-X.

Proved undeveloped drilling location.  A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

PV-10 value.  A term used in the industry that is not a defined term in generally accepted accounting principles.  We define PV-10 as the present value of estimated future net revenues of estimated proved reserves as calculated by our independent petroleum consultant using a discount rate of 10%.  This amount includes projected revenues, estimated production costs and estimated future development costs.  PV-10 excludes cash flows for asset retirement obligations, general and administrative expenses, derivatives, debt service and income taxes.

Reasonable certainty.  When deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities of hydrocarbons will be recovered.  When probabilistic methods are used, reasonable certainty means at least a 90% probability that the quantities of hydrocarbons actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of


geoscience, engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

Recompletion.  The completion for production of an existing well bore in another formation from that which the well has been previously completed.

Reliable technology.  A grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves.  Estimated remaining quantities of oil, natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering the oil, natural gas or related substances to market, and all permits and financing required to implement the project.

Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Supra-salt.  A geological layer lying above the salt layer.

Undeveloped reserves.  Oil and natural gas reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibilityproduction at greater distances.  Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.  Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Unproved properties.  Properties with no proved reserves.

 

 

 


SIGNATURESSIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 6, 2015.2, 2017.

 

W&T OFFSHORE, INC.

By:

 

 

/s/ John D. Gibbons

 

 

John D. Gibbons

 

 

Senior Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 6, 2015.2, 2017.

 

/s/ Tracy W. Krohn

  

Chairman, Chief Executive Officer and Director

Tracy W. Krohn

 

(Principal Executive Officer)

/s/ John D. Gibbons

  

 

Senior Vice President and Chief Financial Officer

John D. Gibbons

 

(Principal Financial Officer)

/s/  KAREN S. ACREE

Vice President, Controller and Chief Accounting Officer

Karen S. Acree

(Principal Accounting Officer)

/s/ Virginia Boulet

  

 

Director

Virginia Boulet

/s/ Robert I. Israel

Director

Robert I. Israel

 

 

/s/ Stuart B. Katz

  

 

Director

Stuart B. Katz

 

 

/s/ S. James Nelson, Jr 

  

 

Director

S. James Nelson, Jr.

 

 

/s/ B. Frank Stanley

  

 

Director

B. Frank Stanley

 

 

 

 

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