Index to Financial Statements

 

 

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, 20112014

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

 

Texas

72-1121985

(State of incorporation)(IRS Employer Identification Number)

(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  þ¨    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 filerþ      Accelerated filer¨      Non-accelerated filer¨      Smaller reporting company¨

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 $910,229,000$571,144,000 based on the closing sale price of $26.12$16.37 per share as reported by the New York Stock Exchange on June 30, 2011.2014.

The number of shares of the registrant’s common stock outstanding on February 23, 2012March 3, 2015 was 74,351,533.75,899,415.

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.

 

 

 


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W&T OFFSHORE, INC.

TABLE OF CONTENTS

 

Page

Page

PART I

Item 1.

Business

1

Item 1A.

Risk Factors

11

10

Item 1B.

Unresolved Staff Comments

31

27

Item 2.

Properties

32

28

Item 3.

Legal Proceedings

44

42

Executive Officers of the Registrant

45

43

Item 4.

Mine Safety Disclosures

45

43

PART II

Item 5.

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

46

44

Item 6.

Selected Financial Data

49

46

Item 7.

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

52

51

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

69

66

Item 8.

Financial Statements and Supplementary Data

70

67

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

117

119

Item 9A.

Controls and Procedures

117

119

Item 9B.

Other Information

117

119

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

118

120

Item 11.

Executive Compensation

118

120

Item 12.

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

118

120

Item 13.

Certain Relationships and Related Transactions, and Director Independence

118

120

Item 14.

Principal Accountant Fees and Services

118

120

PART IV

Item 15.

Exhibits and Financial Statement Schedules

118

121

Signatures

126

127

Index to Consolidated Financial Statements

70

67

Glossary of Oil and Natural Gas Terms

122

124

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.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.

 

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Index to Financial Statements

PART I

 

Item 1.Business

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. 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.  WeOur interest in fields, leases, structures and equipment are an independent oilprimarily owned by the parent company, W&T Offshore, Inc. and natural gas producer, active in the acquisition, exploration and development of oil and natural gas properties primarily in the Gulf of Mexico and Texas.our wholly-own 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.

During 2011,  Over the last several years, we significantly increasedhave shifted our activityfocus more toward the deepwater and to onshore from what was previously a relatively minor presence. In May 2011, we acquired various properties and leasehold interests in four counties in the Permian Basin of West Texas.  In the deepwater, we have completed numerous acquisitions and drilled both exploration and development wells.  Our deepwater acreage has expanded considerably and currently represents almost half of our offshore acreage on a gross acreage basis.

Our onshore activities have been primarily in the Permian Basin in West Texas, (as described below)where most of our leasehold interests were acquired in a single transaction and separately acquired other leasehold interests2011 acquisition.  During 2014, we reassigned most of our interest in another county in the Permian Basin. In East Texas weacreage acquired in 2011 back to the original assignor and currently have acquiredlimited leasehold interestsinterest in two separate prospect areas. We have been actively exploringEast Texas and developing each of these areas and have had up to eight drilling and workover rigs in service in our onshore operating areas during the year. We anticipate being active in both of these areas of Texas in 2012.Louisiana.  

As of December 31, 2011,2014, we have interests in offshore leases covering approximately 0.81.1 million gross acres (0.5(0.7 million net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama. On a gross acreage basis, the conventional shelf constitutes approximately 52% and deepwater constitutes approximately 48% of our offshore acreage.  Onshore, we have leasehold interests in approximately 0.2 million50,000 gross acres (0.2 million(40,000 net acres), substantially all of which are in Texas. Approximately 82%58% of our total net offshore acreage is developed, and approximately 9%62% of our total net onshore acreage is developed. Of the onshore leasehold classified as undeveloped, almost all can be extended by drilling two additional wells in 2012 and further extended by additional operations or production in future years.

Based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum consultant,consultants, our total proved reserves at December 31, 20112014 were 116.9120.0 million barrels of oil equivalent (“MMBoe”) or 701.1720.0 billion cubic feet of gas equivalent (“Bcfe”). Approximately 46%57% of our reserves were classified as proved developed producing, 19%12% as proved developed non-producing and 35%31% as proved undeveloped. Classified by product, our reserves at December 31, 20112014 were 44%52% oil, 15%13% natural gas liquids (“NGLs”) and 41%35% 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 conversionenergy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil, NGLs and natural gas per Mcfe may differ significantly. During 2011, prices for oil were higher than NGLs and natural gas on a million cubic feet equivalent (“Mcfe”) basis, and prices for NGLs were higher than natural gas on a Mcfe basis. Our total proved reserves had an estimated present value of future net revenues discounted at 10% (“PV-10”) of $3.1$2.6 billion. Our PV-10 after considering future cash outflows related to asset retirement obligations (“ARO”) and without deducting future income taxes was $2.8$2.3 billion, and our standardized measure of discounted future cash flows was $2.0$1.7 billion as of December 31, 2011.2014. 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, seeProperties – Proved ReservesReserveunder Part I, Item 2 ofin this Form 10-K.10-K.

We seek to increase our reserves through acquisitions, exploratory and infill drilling, recompletions and workovers. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to

Index to Financial Statements

add reserves, production and cash flow post-acquisition. Our acquisition team continues to work diligentlystrives to find properties that will fit our profile and that we believe will add strategic and financial value to our company.

As previously mentioned,In September 2014, we acquired additional ownership interest in May 2011, we completedthe Mobile Bay blocks 113 and 132 located offshore Alabama (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 24,500 gross acres (21,900 net acres)26% NGLs and 74% natural gas, all of which were classified as proved developed.

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In May 2014, we acquired from Woodside Energy (USA) Inc. (“Woodside”) certain oil and gas leasehold interests in the Permian BasinGulf of West Texas, which we refer to as our “Yellow Rose Properties,” from Opal Resources LLC and Opal Resources Operating Company LLC (collectively, “Opal”Mexico (the “Woodside Properties”).  Based on internalThe 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 theof proved reserves associated with the Yellow RoseWoodside Properties as of the acquisition date were approximately 30.11.6 MMBoe (180.4(9.4 Bcfe), comprised of approximately 69%89% oil, 22%1% NGLs and 9%10% natural gas, and approximately 70%all of which were classified as proved undeveloped. Including adjustments from an effective date of January 1, 2011, the adjusted purchase price was $394.4 million, and we assumed the ARO associated with the Yellow Rose Properties, which we have estimated to be $0.4 million, and recorded a long-term liability of $2.1 million.developed.

In August 2011,November and December 2013, we completedacquired from Callon Petroleum Operating Company (“Callon”) certain oil and gas leasehold interests in the acquisitionGulf of Shell Offshore Inc.’s (“Shell”Mexico (the “Callon Properties”) 64.3%. The Callon Properties consist of a 15% working interest in the Fairway Field along with a likeMedusa field (deepwater Mississippi Canyon blocks 582 and 583), interest in the associated Yellowhammer gas treatment plant (collectively, the “Fairway Properties”). Based on internalproduction facilities and various interests in other non-operated fields. Internal estimates theof proved reserves associated with the FairwayCallon 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 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 8.9approximately 7.0 MMBoe (53.5(42.0 Bcfe), comprised of approximately 72%36% oil, 3% NGLs and 61% natural gas, 27% NGLsall of which were classified as proved developed.

From time to time, as part of 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 less than 1% oil and which are 100% proved developed. Including adjustments from an effective date of September 1, 2010, the adjusted purchase price was $42.9 million and we assumedWest Delta area block 29, all located in the ARO associated with the Fairway Properties which we have estimated to be $7.8 million.

During 2010, we closed on two major acquisitions. In April 2010, we acquired two deepwater Gulf of Mexico fields (the “Matterhorn/Virgo Properties”) from Total E&P USA (“Total”) andMexico. In 2012, we sold our non-operated working interest in November 2010, we acquired three deepwaterthe South Timbalier 41 field located in the Gulf of Mexico fields (the “Tahoe/Droshky Properties”) from Shell.Mexico.

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

Our exploration efforts have historically have been in areas in reasonably close proximity to known proved reserves, which we believe reducesbut in 2013, some of our risks.exploration projects were higher risk deepwater projects with potentially higher returns than our previous risk/reward profile. Historically, we have financed our exploratory drilling capital expenditures with netoperating cash provided by operating activities.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. Certain risks are inherent in our business specifically and in the oil and natural gas industry and our business,generally, any one of which if it occurs, can negatively impact our rate of return on shareholders’ equity.equity 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. During the last three years, we have drilled eight,We completed six, five and 10 successfulfour offshore wells (gross) for the years 2011, 2010 and 2009, respectively33, 40 and drilled 39 successful77 onshore wells (gross) in 2011.

From time to time, as part of our business strategy, we sell various properties that we consider non-core assets. We did not sell any properties in 2011 or 2010. We are currently marketing a package of non-core properties located on the shelf of the Gulf of Mexico.2014, 2013 and 2012, respectively.

We generally sell our 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.

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Index to Financial Statements

Our totalcurrent capital expenditure budget for 20122015 is $425.0$200 million, not including any potential acquisitions. The budget includes $209.0This compares to capital expenditures of $630 million to drill, evaluate and complete ten offshore wells (six exploration and four development wells) and $170.0 million to drill, evaluate and complete 65 onshore wells (19 exploration and 46 development wells). The budget also includes $46.0$636 million for facilities2014 and 2013, respectively.  The capital recompletions, seismicbudget 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 leaseholdless than 1% for other items. Thus far in 2012,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 on any acquisitions, andbut we continue to evaluate and bid on opportunities as they arise. We anticipate funding our 20122015 capital budget and any potential acquisitions with cash flow from operating activities, cash on hand and borrowings under our revolving bank credit facility and by accessing thefacility. The capital markets towe have historically accessed are currently constrained, but we believe we could access other capital markets if the extent necessary. Our 2012need arises.  Hence, our 2015 capital budget is subjecthas been set with these premises in mind.  For the portion of our capital budget related to change asdrilling, our operating policy has been to fund these expenditures with cash flow provided by operations.  We continue to monitor commodity prices and may revise 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. See Risk Factors under Part I, Item 1A in this Form 10-K for additional information.

Business Strategy

We plan to continueOur business strategy is to acquire, explore and develop oil and natural gas reserves on the Outer Continental Shelf (“OCS”), the area of our historical success and technical expertise, which we believe will yieldhas yielded desirable rates of return sufficient to remain competitivecommensurate with our perception of risks. The rapid decline in our industry.oil prices that occurred in the back half of 2014 and continued into the first part of 2015 has created a great deal of uncertainty about future exploration and development. We believe this uncertainty will continue until such time as the costs of goods and services utilized in support of exploration and production become more closely aligned with prevailing commodity prices.  We also believe attractive acquisition opportunities will continue to arisebecome 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, and, more specifically, the significant declinereduction in oil and natural gas prices occurring in the last six months, we also believe thatexpect to find opportunities as other less well-capitalized producers may seek buyers for theirto divest properties both onshore and offshore, which could create opportunities for us.offshore.

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 opportunities in the Gulf of Mexico and onshore opportunities in Texas, when market conditions improve, we also plan to continue to pursueevaluate other areas that arecould be compatible with our technical expertise and could yield desirable rates of return sufficient to remain competitive incommensurate with our industry. As described above, we have acquired interests in various onshore properties in Texasperception of risks. We may acquire or expand our offshore and anticipate acquiring or expanding our onshore holdings through acquisitions or exploration, development and development activities.acquisition activities if attractive opportunities arise.

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 netoperating cash provided by operating activities,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 concerns and individual producers and operators. Many of these competitors are large, well established companies andthat have financial and other resources substantially greater than ours. 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. For a more thorough discussion of how competition could impact our ability to successfully complete our business strategy, seeRisk Factors in under Part I, Item 1A ofin this Form 10-K.

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Oil and Natural Gas Marketing and Delivery Commitments

We sell our oil, NGLs and natural gas to third-party purchasers.customers. We are not dependent upon, or contractually limited to, any one purchasercustomer or small group of purchasers.customers. However, in 2011 we sold over2014, approximately 47% of our sales were to Shell Trading (US) Co. and no other customer comprised greater than 10% of our production to each of Shell Trading (US) Co., Conoco Phillipssales.  See Financial Statements  and JP Morgan Ventures Energy Corp. and these three companies accounted for approximately 62% of our total sales. SeeFinancial StatementsSupplementary Data – Note 1 – Significant Accounting Policies – Concentration of Credit Risk in under Part II, Item 8 ofin this Form 10-K for additional information about our sales to these customers. Due to the nature of 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 purchasercustomer or a few purchaserscustomers would materially affect our ability to sell our production. We do not have any agreements thatwhich obligate us to deliver certainmaterial quantities to third parties.

Regulation

General. General.Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation 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 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 sales 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.

In addition, the 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. With regard to our physical sales of oil or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. 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.

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, the 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 limited non-pipeline natural gas sellers, including producers, from effectively competing 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 be 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

Index to Financial Statements

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 conditionreview during 2013 and proposalswas authorized to operate for certain changes were made, but no legislation was enacted during 2011 and the RRC will be reviewed againan additional four years.  Its next scheduled sunset review is in 2013.2017.

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The Outer Continental Shelf Lands Act (“OCSLA”), which is administered by the Bureau of Ocean Energy Management(1) (“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 market to provide producers and shippers working in the OCS with greater assurance of open access service on pipelines located on the OCS and non-discriminatory rates and conditions of service on such pipelines. On June 18, 2008, the 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 W&T,us, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million British thermal units (“MMBtus”MMBtu”) during a calendar year must annually report, starting May 1, 2009, such sales and purchases to the FERC. 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 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 and Congress will continue.

While the changes by these federal and state regulators 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 natural gas liquidsNGLs transportation rates. Our sales of crude oil, condensate and natural gas liquidsNGLs 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 oil and NGLs is affected by the cost of transporting those products to market. Interstate transportation rates for oil, natural gas liquids,NGLs and other products are regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase.

(1)In June 2010, the Minerals Management Service changed its name to the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”). In October 2011, the BOEMRE was split into three separate entities: the Office of Natural Resources Revenue (“ONRR”), which assumed the functions of the Minerals Revenue Management Program; the Bureau of Ocean Energy Management, which is responsible for managing development of the nation’s offshore resources in an environmentally and economically responsible way; and the Bureau of Safety and Environmental Enforcement (“BSEE”), which is responsible for enforcement of safety and environmental regulations.

Index to Financial Statements

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. As it relates to intrastate crude oil, condensate and natural gas liquids 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 liquids pipelines will affect us in a way that materially differs from the way they affect other crude oil, condensate and natural gas liquids 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 by the BOEM.change. The BOEM hasand 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. SeeRisk Factors under Part I, Item 1A in this Form 10-K for more information on new regulations.regulations and interpretations.

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To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees have substantial net worthdemonstrate 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.  W&T Offshore, Inc. is currently exempt from supplemental bondingIn 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 byfor companies operating in federal waters. If the BOEM. As many BOEM regulations are being reviewed, we may be subjectwere to supplemental bondingincrease its financial assurance requirements in the future.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.  SeeRisk Factors – BP’s Deepwater Horizon explosionIn addition, the BOEM can require supplemental bonding from operators for decommissioning, plugging, and ensuing oil spill couldabandonment 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 broad adverse consequences affectingdemonstrated 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 Gulf of Mexico, some of whichnotice.  We intend to contest the fine to the fullest extent possible. The ultimate resolution may be unforeseeableunder Part I, Item 1Aresult in this Form 10-Kfor more information.

The ONRR administers the collection of royalties under the termsa waiver of the OCSLA and the oil and natural gas leases issued thereunder. The amount of royalties due is based upon the termsfine, a reduction of the oil and natural gas leasesfine, or payment of the full amount plus interest covering several years.  As no amount has been determined as wellmore 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 regulations promulgated by the ONRR and the BOEM.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 andand/or the BSEE for future hurricane seasons. New requirements, if any, could increase our operating costs and/or capital expenditures.

Environmental Regulations

Index to Financial Statements

General. Environmental regulations.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 carry substantial civil and even criminal penalties for failure to comply. 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 remediation, reclamation and abandonment of wells, platforms and other facilities in the Gulf of Mexico aremay require us to incur significant costs to us.costs. 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.

We are currently under investigation by the United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the U.S. Environmental Protection Agency (the “EPA”) for alleged violation of environmental laws6


Hazardous Substances and regulations at certain of our operational sites. The outcome of this investigation could have a material adverse effect upon us. We are not able at this time to estimate our potential exposure, if any, related to this matter. See Legal Proceedings under Part I, Item 3 in this Form 10-K for additional information. At our other operation sites, we believe we are in substantial compliance with current applicable environmental laws and regulations. We believe that compliance with existing requirements will not have a material adverse impact on our operations, but failure to comply could have material consequences. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. As such, there can be no assurance that material cost and liabilities will not be incurred in the future.

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 oil or 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.” 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, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes,” thereby potentially

Index to Financial Statements

subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact 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.  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.  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. On July 28, 2011,For example, the EPA proposed rules that would establish newU.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’s proposed rule package includesEPA established New Source Performance Standards to addressfor emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to addressfor hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal wouldEPA 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 the gas and natural gas liquidsany hydrocarbons that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. EPA is currently considering comments submitted on the proposedThese rules and has indicated that it expects to adopt final rules by April 3, 2012. If finalized, these rules couldmay require a number of modifications to our operations including 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, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

In December 2009, theClimate Change. 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 warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA recentlyhas adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases fromrequires preconstruction and operating permits for certain large stationary sources, effective January 2, 2011.sources. The EPA has also adopted rules requiringrequires the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis effective in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginningbasis. We believe we are in 2012 for emissions occurring in 2011. We expect to be able to complycompliance with this emissionsnew emission reporting requirement foras it applies to our onshore operations in West Texas.operations.  

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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 such as electric power plants, 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.

Index to Financial Statements

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 Cleanfederal Water Act.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 raises OPA’s damages liability cap from $75 million to $133.65 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. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to a maximum of $150 million. 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 there was 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 the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our onshore facilities.  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 and/or oil 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 surrounding 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 (“SDWA”(the “SDWA”) over certain hydraulic fracturing activities involving the use of diesel.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. Effective February 1, 2012,For example, in May 2013, the RRC began requiring all operators to disclose on a public website the chemical ingredientsadopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water volumes used to hydraulically fracture wells in Texas.resources.  We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities.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 a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has

Index to Financial Statements

commencedis 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 groundwater, with initial results expectedproduced water, and wastewater treatment and disposal. The EPA has indicated that it expects to be available by late 2012 and final results by 2014. Moreover, theissue 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 by 2014.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 onin May 26, 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.

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 been classified as “threatened” or “endangered” are protected by the Endangered Species Act. This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area. If endangered species are located in an area where we wish to conduct seismic surveys, development or abandonment operations, the work could be prohibited or delayed or expensive mitigation could be required. The U.S. Fish and Wildlife Service is currently considering whether the dunes sagebrush lizard, which is present in certain areas of the Permian Basin near the Texas-New Mexico border, should be listed as endangered. It is possible that

We own a decision to list the dunes sagebrush lizard as endangered could have an adverse impact on our operations in West Texas.

Our oil and natural gas operations include a production 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. Naturally Occurring Radioactive Materials (“NORM”) may

Index to Financial Statements

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 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.9


We maintain liability insurance and well control insurance for all of 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 over 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.  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.

Seasonality

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

Employees

As of December 31, 2011,2014, we employed 310339 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 and other reports with the SEC. Our reports filed with the SEC are available free of charge to the general public through our website atwww.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 atwww.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

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 our industryus and our Companyindustry 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.

Index to Financial Statements

Risks Relating to the Oil and Natural Gas Industry and Our Business

A substantialSubstantial or extended declinedeclines in oil, NGLs and natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our capital expenditure obligations and financial commitments and to implement our business strategy.

The price we receive for our oil, NGLs and natural gas production directly affects our revenues, profitability, access to capital and future rate of growth. Oil, NGLs and natural gas are commodities and are subject to wide price fluctuations in response to relatively minor changes in supply and demand. Lower prices for our oil, NGLs and natural gas production may not only decrease our revenues on a per unit basis but may also reduce the amount of oil, NGLs and natural gas that we can produce economically. Historically, the markets for 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;

the actions of the Organization of Petroleum Exporting Countries;

·

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;

·

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

·

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;

·

weather conditions;

·

technological advances affecting energy consumption;

·

the price and availability of alternative fuels; and

·

geographic differences in pricing.

The prices of crude oil, domestic natural gas and liquefied natural gas;

actsNGLs have declined substantially since June 2014.  The price of war, terrorism or political instabilityWest Texas Intermediate (“WTI”) crude oil has decreased from $107 per barrel in oil producing countries;

economic conditions;

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

the levelmiddle of globalJune 2014 to as low as $44 per barrel in January 2015.  This decrease in prices has impacted all oil and natural gas exploration and production activity;

the level of global oil and natural gas inventories;

weather conditions;

technological advances affecting energy consumption;

the price and availability of alternative fuels; and

geographic differences in pricing.

Lower oil and natural gas prices may not only decrease our revenuesproducers to varying degrees depending on a per unit basis but may also reduce the amount of oil and natural gas that we can produce economically. For example, the prices of oil and natural gas declined substantially during the second half of 2008 and impacted production volumes.hedging strategies.  Natural gas and NGLs prices have been negatively affected by the domestic economy, excess natural gas production, high levels of stored natural gas and weather conditions affecting demand. In recent months, Henry Hub spot prices for natural gas have declined to prices lower than $3.00 per Mcf compared to average prices during 2014 in excess of $4.00 per Mcf. There have been significant recent 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 resulting from the large-scale development of these unconventional resource reserves could continue to have an adverse impact on the price of natural gas.gas and NGLs. An environment of depressedfurther or continued lower 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.

If oil, NGLs and natural gas prices stay at their current levels or decrease further, we maywill likely be required to 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 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 maywill likely be required to write down the carrying value of our oil and natural gas properties. A write-down constitutesSuch write-downs constitute a non-cash charge to earnings.  Primarily as a resultImpairment of proved properties under our full cost oil and gas accounting method is largely driven by the present values of future net revenues of proved reserves estimated using SEC mandated 12-month unweighted first-day-of-the-month commodity prices. Since oil, gas and NGLs prices did not decline in 2014 until after June 2014, and more prominently in the fourth quarter of 2014, the impact of the significant declinerecent pricing downturns will continue to adversely affect our SEC average pricing as recent and current prices roll into the SEC average prices used in bothevaluating 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 for oil, NGLs and natural gas will likely result in future ceiling test impairments.  You should not assume that the $2.6 billion present value of future net revenues, PV-10, from our proved oil and natural gas prices asreserves shown elsewhere in this document is the current market value of December 31, 2008, we recorded a ceiling test impairment at December 31, 2008 of $1.2 billion. Additionally, we recorded a ceiling test impairment at March 31, 2009 of $218.9 million primarily

Index to Financial Statements

as a result of a further decline in natural gas prices as of March 31, 2009. We did not have any impairment write-downs in 2011 or 2010. Declines inour estimated oil and natural gas 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 afterand 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, 2011 may require us to record additional ceiling test impairments2014 for crude oil was $91.12 per barrel and the average price of WTI crude oil in the future.December 2014 was $59.29 per barrel.   No assurance can be given that we will not experience a ceiling test impairmentimpairments in future periods, which could have a material adverse effect on our results of operations in the periodperiods taken. As a result of lower oil, NGLs and natural gas prices, we may also reduce our estimates of the reservesreserve volumes that may be economically recovered, which would reduce the total value of our proved reserves. SeeManagement’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Impairment of oil and natural gas propertiesin under Part II, Item 7 andFinancial Statements and Supplementary Data – Note 1 – Significant Accounting Policiesinunder Part II, Item 8 ofin this Form 10-K for additional information on the ceiling test.

The Company is responding to a federal grand jury investigation that could result in penalties and additional operating restrictions.

The United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the EPA, is conducting a federal grand jury investigation of environmental compliance matters relating to surface discharges and reporting on four of our offshore platforms in the Gulf of Mexico. We are fully cooperating with the investigation. The United States Attorney’s Office has recently informed us that they are continuing their investigation with the intent to seek a criminal disposition. The outcome of this investigation could have a material adverse effect upon us. We are not able at this time to estimate our potential exposure, if any, related to this matter.

The Company has been sued by certain landowners alleging damages to their properties.

On May 6, 2009, certain Cameron Parish land owners filed suit in the 38th Judicial District Court, Cameron Parish, Louisiana against the Company and Tracy W. Krohn as well as several other defendants unrelated to us. In their lawsuit, plaintiffs are alleging that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and are seeking compensatory and punitive damages. We cannot currently estimate our potential exposure, if any, related to this lawsuit. We are currently, and intend to continue, vigorously defending this litigation.

BP’s Deepwater Horizon explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the Gulf of Mexico, some of which may be unforeseeable.

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. Beginning in May 2010, the BOEM and BSEE issued a series of NTLs imposing a variety of new safety measures and permitting requirements. They also imposed a six-month moratorium on drilling activities in federal offshore waters that stretched into a much longer moratorium resulting in delays in not only deepwater drilling but also in many other types of activities in the Gulf of Mexico that continue to exist currently.

In addition to the drilling restrictions, new safety measures and permitting requirements already issued by the BOEM and BSEE, there have been numerous additional proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and oil spill that could affect our operations and cause us to incur substantial losses or expenditures. Implementation of any one or more of the various proposed responses to the disaster could materially adversely affect operations in the Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory costs, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the Gulf of Mexico more difficult, more time consuming, and more costly. For example, a variety of amendments to the OPA have been

Index to Financial Statements

proposed in response to the Deepwater Horizon incident. OPA and regulations adopted pursuant to OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the OCS, which includes the Gulf of Mexico where we have substantial offshore operations. OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. OPA also requires operators to provide 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. Legislation has been proposed in Congress to amend OPA to increase the minimum level of financial responsibility to $300 million or more. If the minimum level of financial responsibility is increased further, we may experience difficulty in providing financial assurances sufficient to comply with the revised 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 further.

After the moratorium ended in 2010, it was not until March 2011 that deep water drilling permits began to be issued, and even then only sporadically, to continue drilling activities that had commenced prior to the Deepwater Horizon incident. Since March 2011, deepwater drilling permits have been issued at a slower and more measured pace than before the Deepwater Horizon event.

Other significant regulatory changes since the Deepwater Horizon event are regulations related to assessing the potential environmental impact of future spills using worse case discharge scenarios on a well-by-well basis, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. The new regulations and increased review process increases the time it takes to obtain drilling permits and increases the cost of operations. As these new regulations and guidance continue to evolve, the risk to our business may be increased. The permitting process is also slow and inconsistent for shallow water work and even for plug and abandonment activities. This could lead to increased costs and performing work at less than optimal effectiveness. We have not experienced delays in obtaining permits related to our onshore operations.

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

Subsequent to the BP Deepwater Horizon incident in the U.S. Gulf of Mexico, the BOEM and BSEE issued a series of NTLs imposing new requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. These new requirements include 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, which requires operators to have a comprehensive safety and environmental management system in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

As a result of the issuance of these new NTLs and the lack of detail therein, the BOEM has been taking much longer to review and approve permits for new wells. Due to the extremely slow pace of permit review and

Index to Financial Statements

approval, various industry sources have determined that the BOEM may take six months or longer to approve applications for drilling permits that were previously approved in less than 30 days. These NTLs also increase the cost of preparing each permit application and will increase the cost of each new well, particularly for wells drilled in deeper waters on the OCS. The delay in granting permits could also cause some of our leases to lapse as a result of failure to commence drilling or continue production operations.

New requirements imposed by the BOEM and BSEE could significantly impact the cost of operating our business.

In addition 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 producing 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 sulphur zones are appropriately isolated. Similarly, platforms or other facilities that 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 may serve to increase, perhaps materially, 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. For the year 2010, we increased our estimate of ARO by $18.7 million based on our expected acceleration in timing for such obligations as a result of implementing this NTL. (For additional details, refer toFinancial Statements – Note 5 – Asset Retirement Obligationsin Part II, Item 8 of this Form 10-K.) The potential increase in decommissioning activity in the Gulf of Mexico 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.

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

On July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and VOCs and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would 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 the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA is currently considering comments submitted on the proposed rules and has indicated that it expects to adopt final rules by April 3, 2012. If finalized, these rules could require a number of modifications to our operations including 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.

We were adversely affected by a recession in the United States and global economy.

The United States and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. The recession that began in 2008 caused a collapse in oil and natural gas prices resulting in write-downs of the value of our reserves at the end of 2008 and early 2009. These write-downs significantly reduced our stockholders’ equity, increased our financial leverage, reduced the market value of our common

Index to Financial Statements

stock and reduced the market value of our long-term debt. There are likely to be long-term effects resulting from the recession, the credit market crisis and the recent issues concerning the Euro and the debt of certain European countries. These and other factors may cause future economic growth rate to be slower than what was experienced before the recession began. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. A lower future economic growth rate could result in decreased demand growth for our oil and natural gas production as well as lower commodity prices, which could reduce our cash flows from operations and our profitability.

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

As of December 31, 2011, available borrowings under our revolving bank credit facility are currently limited to $575.0 million, less outstanding borrowings and letters of credit. Availability is determined semi-annually by our lenders and is based in part on oil and natural gas prices and in part on our proved reserves. Substantially all of our oil and natural gas properties are pledged as collateral under the credit agreement governing our revolving bank credit facility (the “Credit Agreement”). The Credit Agreement limits our ability to incur additional indebtedness based on specified financial covenants, ratios or other criteria. Lower oil and natural gas prices in the future could result in a reduction in credit availability and also affect our ability to satisfy these covenants, ratios or other criteria and thus could reduce our ability to incur additional indebtedness and our ability to replace reserves.

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

We could be exposed to uninsured losses in the future. 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 2011, we renewed our insurance policies covering well control and hurricane damage at an annual cost of approximately $30.7 million. The amount of properties covered and dollar coverage was increased from 2010, but the retention amount per hurricane occurrence was also increased, which increases our risk. In addition, pollution and environmental risks are generally not fully insurable. 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. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented.

SeeFinancial Statements – Note 3 – Hurricane Remediation and Insurance Claimsunder Part II, Item 8 of this Form 10-K for additional information.

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 with hurricanes in the Gulf of Mexico and global catastrophic losses, property damage and well control insurance coverage has become more limited and the cost of such coverage has become both more costly and more volatile. The insurance market may change dramatically in the future due to the major oil spill that occurred in 2010 at BP’s Macondo well in the deepwater Gulf of Mexico. As of December 31, 2011, approximately 93% of our PV-10 value of proved reserves attributable to our Gulf of Mexico properties are on platforms that are covered under our current insurance policies for named windstorm damage. Our insurers may not continue to offer this type and level of coverage to us, our costs may increase substantially as a result of increased premiums and the losses that may have been previously insured may no longer be insured. The occurrence of any or all of these possibilities 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 a claim, the insurance companies will not pay our claim.

Index to Financial Statements

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. We do not enter into derivative instruments for speculative trading purposes. While these commodity derivative positions are intended to reduce the effects of volatile oil and natural gas prices, they may also limit future income if 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;

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.

SeeFinancial Statements – Note 6 – Derivative Financial Instrumentsunder Part II, Item 8 of this Form 10-K for additional information on derivative transactions.

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

Current SEC guidance requires 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 of the date of booking.  This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.  If current low price conditions persist, we also may be compelled to further postpone the drilling of proved undeveloped reserves until prices recover.  Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped.

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As of December 31, 2011,2014, approximately 35%31% of our total proved reserves were undeveloped and approximately 19%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 expenditures and/or activities to convert these into producing reserves.  We cannot provide assurance these expenditures will be made and that activities will be entirely successful in converting these reserves.  Additionally, we are not the operator with respect tofor approximately 10%17% of our undeveloped proved reserves and approximately 11% of our proved developed non-producing reserves, so we may not be in a position to control the timing of all development activities.  Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reserves 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.

If we are not able to replace reserves, we may not be able to sustain production.

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 development, exploration or acquisition activities, our proved reserves and production will decline over time. By their nature, estimates of undeveloped reserves are less certain. Recovery of undeveloped reserves could require significant capital expenditures and successful drilling operations. Our future oil and natural gas reserves, production, and therefore our cash flow and net income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable 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

Index to Financial Statements

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 majority of our current production is from the Gulf of Mexico.  Production from reservoirsReserves in the Gulf of Mexico generally decline more rapidly than from reservoirsreserves in many other producing regions of the United States.  Our independent petroleum consultant estimates that on average, 43%42% of our total proved reserves arewill 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.  In orderThe 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 finance future capital expenditures, we may need to alter or increasegrow and changes in our capitalization substantially through the issuance of additional debt or equity securities, bank borrowings, reserve-based loans, joint ventures or other means. These changes in capitalizationstructure may significantly affect our financial risk profile.  Furthermore, 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 Related to Financings.”

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 not be ablelimited 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 prices in the future could result in a reduction in credit availability and also affect our ability to satisfy these covenants, ratios or 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 cooperated 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 terms of the agreement could lead to additional requirements and/or operating restrictions.

More stringent regulatory initiatives relating to offshore exploration 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 and production operators in the Gulf of Mexico including 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.

These new regulatory initiatives may serve to effectively slow down the pace of drilling and production operations in the Gulf of Mexico due to adjustments in operating procedures and certification practices as well as increased lead times to obtain exploration 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 deepwater on the OCS.  We could become subject to fines, penalties or orders requiring us to modify or suspend our operations in the Gulf of Mexico if we fail to comply with these requirements.  Moreover, if similar oil spill incidents were to occur in the future in the Gulf of Mexico or elsewhere where we conduct operations, the relevant governmental authorities could elect to again issue directives to temporarily cease drilling activities.  In any event, they may from time to time issue further safety and environmental regulatory initiatives regarding offshore oil and gas exploration and development activities, which any one or more of such events could have a material adverse effect on our production activities as well as our financial position, results of 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 impact the cost of operating our business.

In addition 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 producing 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 frequently 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.

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

We could be exposed to uninsured losses in the future. 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, we renewed our insurance policies covering well control, hurricane damage, general liability and pollution.  These policies reduce, but do not 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.  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. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented.  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 with hurricanes in the Gulf of Mexico and global catastrophic losses, property damage and well control insurance coverage has become more limited and the cost of such coverage has become both more costly and more volatile. The insurance market may change dramatically in the future due to the major oil spill that occurred in 2010 at BP’s Macondo well in the deepwater Gulf of Mexico. As of December 31, 2014, virtually all of 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 current coverage, 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. 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. While these commodity derivative positions are intended to reduce the effects of volatile oil and natural gas prices, they may also limit future income if 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;

·

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.

See Financial Statements and Supplementary Data– Note 6 – 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. 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 ability to acquire additional prospects and 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. 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 may put us at a competitive disadvantage for acquiring properties.  These risks are described above in the risk factor entitled: 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.

Index to Financial Statements
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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/orand investment in infrastructure. 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 obligations 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 more restrictive interpretation, 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 could differ dramatically from what we may ultimately incur as a result of platform damage.

As described above in the risk factor titledNew requirements recently 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,” the BOEM’s NTL 2010-G05 increased our liability for ARO by accelerating the time frame for plugging, abandonment and removal for some of our platforms.platforms and the BOEM further increased our liability after issuing regulation interpretations which affected scope and requirements. In addition, the potential increase in decommissioning activity in the Gulf of Mexico over the next several years as a result of the NTL could likely result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related ARO.

Index to Financial Statements

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 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;

·

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

·

selection of technology; and

·

the rate of production of the reserves.

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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;

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

selection of technology; and

the rate of production of the reserves.

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, (such as hurricanes and tropical storms in the Gulf of Mexico), cost overruns, equipment shortages, geological issues 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;

·

explosions;

·

blow-outs and surface cratering;

·

uncontrollable flows of natural gas, oil and formation water;

·

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

·

inability to obtain insurance at reasonable rates;

·

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

·

pipe, cement, subsea well or pipeline failures;

·

casing collapses or failures;

·

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

·

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.

Index to Financial Statements

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;

·

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

·

pollution and other environmental damage;

·

clean-up responsibilities;

·

regulatory investigation and penalties;

·

suspension of our operations;

·

repairs required to resume operations; and

·

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. 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.

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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 outer continental shelfOCS 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;

·

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;

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

·

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

·

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 relatively greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area. For example, in 2009, net production of approximately 8.7 Bcfe was deferred as a result of damage caused primarily by Hurricane Ike.Ike in 2009 and Hurricane Isaac caused net production deferral of approximately 2.9 Bcfe in 2012.

As we increase our onshore operations, we will be subject to different risk factors that could impact loss of revenues or curtailment of production for these geographies.

Onshore oil 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.

Index to Financial Statements

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 recently acquired Yellow Rose Propertiesproperties 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 has begun the process of draftingissued permitting guidance documents on regulating requirements for companies that plan to conduct hydraulic fracturing using diesel fuel.covering such activities in February 2015. In addition, a number of federal agencies are analyzing a variety of environmental issues associated with hydraulic fracturing. Thethe EPA has commenced a broad study of the potential environmental effects of hydraulic fracturing activities, with initial results expectedand the agency has indicated that it expects to be available by late 2012 and final results by 2014.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. TheseThe results of these studies depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Legislation alsoFrom 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, effective February 1, 2012,in May 2013, the RRC began requiring all operators to disclose on a public website the chemical ingredientsadopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water volumes used to hydraulically fracture wells in Texas.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.

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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.

Our business strategy includes a continuing acquisition program,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;

·

amounts of recoverable reserves;

·

estimates of future oil, NGLs and natural gas prices;

·

estimates of future exploratory, development and operating costs;

·

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

·

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

Index to Financial Statements

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;

·

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;

·

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

·

customer or key employee loss from the acquired business;

·

increased administration of new personnel;

·

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

·

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, 2011.2014. SeeManagement’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 inBusinessin under Part I, Item 1, Properties in under Part I, Item 2 andFinancial Statements and Supplementary Data – Note 2221 – Supplemental Oil and Gas Disclosuresinunder Part II, Item 8 ofin this Form 10-K.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

Index to Financial Statements

can vary and may not be under our control. The process also requires economic assumptions about matters such as 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, 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.estimate, which prices are not reflective of the substantially lower prices realized in December 2014 and January 2015. 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 of land 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 you 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 in oil 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, 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.

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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.

Index to Financial Statements

In some cases, our wells are tied back to platforms owned by 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 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, 2011, four2014, 12 fields, accounting for approximately 2.212.8 Bcfe (or 2%12%) of our 20112014 production, are tied back or are planned to be 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.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 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 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, a third-party pipeline used by our Main Pass 108 field was shutdown between June 2010 and March 2011. We estimate this shutdown caused us to deferin 2013, various pipelines were shut down causing production deferral of approximately 4.9 Bcfe during 20106.3 Bcfe.  Our Mississippi Canyon 506 field (Wrigley) was the field most significantly affected by the shutdowns, as it was shut down for all of 2013 and 3.7 Bcfe during 2011.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 cash flows.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 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;

·

lease permit restrictions;

·

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

·

spacing of wells;

·

unitization and pooling of properties;

·

safety precautions;

·

operational reporting;

·

reporting of natural gas sales for resale; and

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lease permit restrictions;

·

taxation.

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

spacing of wells;

unitization and pooling of properties;

safety precautions;

operational reporting;

reporting of natural gas sales for resale; and

taxation.

Index to Financial Statements

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

·

personal injuries;

·

property and natural resource damages;

·

well site reclamation costs; and

·

governmental sanctions, such as fines and penalties.

property and natural resource damages;

well site reclamation costs; and

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. SeeBusiness – Regulation under Part I,Item 1 ofin this Form 10-K for a more detailed explanation of our regulatory risks.

Our operations may incur substantial liabilities to comply with environmental 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;

·

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

·

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;

·

loss of our leases;

·

incurrence of investigatory or remedial obligations; and

·

the imposition of injunctive relief.

loss of our leases;

incurrence of investigatory or remedial obligations; and

the imposition of injunctive relief.

We are currently under investigation by the United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the EPA for alleged violations of environmental laws and regulations. SeeLegal Proceedingsin Part I, Item 3 in this Form 10-K for additional information. Also, in prior years, we have been subject to investigation with respect to allegations that we did not comply with applicable environmental laws and regulations. Resolution of these matters has required management time and expense.

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. SeeBusiness – Regulation, under Part I, Item 1 ofin this Form 10-Kfor10-K for a more detailed description of our environmental risks.

Index to Financial Statements

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.

In December 2009, theThe 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, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA recentlyhas adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissionsimposes preconstruction and operating permit requirements of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011.sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.basis.

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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, such as electric power plants, 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. If any such affects were to occur, they could have an adverse effect on our financial condition and results of operations. Please see– Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

ImplementationThe enactment of financial reformderivatives legislation and regulationsregulation 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.

TheIn July 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act ( the “Dodd-Frank(the “DF Act”), was adopted in July 2010, which, among other provisions,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 law requiredDF Act requires the Commodity Futures Trading Commission (the “CFTC”) andCFTC, the SEC and other regulators to implementpromulgate rules and regulations within 360 days fromimplementing the date of enactment. 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 DecemberOctober 2011, the CFTC extended temporary exemptive relief from regulations on certain provisions of the Dodd-Frank Act applicable to swaps until no later than July 16, 2012. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents.  Certainbona fidehedging transactions or positions are exempt from theseThe initial position limits. It is not possible at this time to predict whenlimits rule was vacated by the United States District Court for the District of Colombia in September 2012.  However, in November 2013, the CFTC will makeproposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these regulations effective. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, althoughnew position limit rules are not yet final, the applicationimpact of those provisions toon us is uncertain at this time.

The financial

IndexCFTC 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 Financial Statements

reform legislationcomply 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 legislationfull 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, (including through requirements to post collateral which could adversely affect our available liquidity), 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, and increase our exposure to less creditworthy counterparties.counterparties or reduce liquidity. If we reduce our use of derivatives as a result of the legislationDF 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 legislationDF 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 legislation and regulationsDF 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.

23


We operateown a production 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.

Our oil and natural gas operations includeWe own a production platform located in a National Marine Sanctuary in the Gulf of Mexico that is subject to special federal laws and regulations. This production platform is not producing and will be plugged, abandoned and remediated according to regulations. Unique regulations related to operations in the 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, including cyber-security exposure, from unauthorized access to our facilities and computer systems. This exposure includes 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 disruptions of our operations. Cyber-security exposures in particular are fluid and adaptive, and include malicious software, unauthorized access to confidential data and disruptions to operations that use computers and data systems.  Although we utilize various procedures and controls to mitigatereduce these exposures, there can be no assurances that these procedures and controls will be sufficient to prevent such events from occurring. Cyber-security exposures in particular are evolving and include malicious software, unauthorized access to confidential data and disruptions to operations that use computers and data systems. We do not carry business interruption insurance. Any of these security breaches could have a material adverse affecteffect 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 OfficerOfficer; Thomas P. Murphy, our Senior Vice President and Chief AccountingOperations Officer; Stephen L. Schroeder, our Senior Vice President and Chief Operating Officer, Jesus G. Melendrez, our Senior Vice President and Chief Commercial Officer,Technical Officer; and Thomas F. Getten, our Vice President, General Counsel and Corporate Secretary, could have a negative impact on our operations. We do not maintain or plan to obtain for the benefit of the Company any insurance against the loss of any of these individuals. Please readExecutive Officers of the Registrantinunder Part I following Item 3in3 in this Form 10-K for more information regarding our senior management team.

Index to Financial Statements

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 significant shortages in the availability of certain types of drilling rigs as well as significant increasesor experience drilling rigs with high costs in relation to the costrecent change in price of utilizing drilling rigs.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 been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. These changes include, but are not 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 States production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and production, and any such change could have a negative effect on the results of our operations.

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

Substantially all of our accounts receivable result from 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 obtain funding on acceptable terms or obtain funding 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.

ForThe 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, and 2012 to date, world financial markets have beenwere 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.

In recent years, access to financing markets was severely limited. 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. In addition, prices for oil, NGLs and natural gas had decreased from 2008.

Index to Financial Statements

We can offer no assurance that we would be able to access the capital market on terms and conditions that would be acceptable to us, if the need were to arise. Our revolving bank credit facility is subject to a semi-annual borrowing base determination,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; or

·

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


Index to Financial Statements

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 39,206,96239,876,501 shares of our common stock, representing approximately 52.7%52.5% of our voting interests as of February 17, 2012.15, 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;

·

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 stockholders.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 New York Stock Exchange (“NYSE”).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 a majorityall of the other directors on the board who arebeing independent from our principal shareholder.

 

Item 1B.Unresolved Staff Comments

Item 1B. Unresolved Staff Comments

None.

Index to Financial Statements
Item 2.Properties

 

27


Item 2. Properties

Our fields are located in the Gulf of Mexico, Alabama and in Texas.  The offshore fields are found in water depths ranging from less than ten10 feet up to 4,2007,200 feet.  The reservoirs in our offshore fields are generally characterized as having high porosity and permeability, which typically results in high 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 describesmap provides the locations of our ten10 largest fields as of December 31, 2011,2014, based on quantities of proved reserves on a natural gasan energy equivalent basis.  At December 31, 2011,2014, these fields accounted for approximately 84%82% of our proved reserves.

 

Field Name

 Field
Category
 Operator Percent Oil
and NGLs
of Net Reserves (1)
  Percent
Natural Gas
of Net Reserves (1)
  2011 Average Daily
Equivalent Sales Rate
(MMcfe/d) (1)
 
     Gross  Net 

Spraberry (Yellow Rose Properties)

 Onshore W&T  89  11  20.3    14.0  

Ship Shoal 349 (Mahogany)

 Shelf W&T  84  16  11.2    9.1  

Viosca Knoll 783 (Tahoe/SE Tahoe)

 Deepwater W&T  28  72  67.5    37.5  

Main Pass 108

 Shelf W&T  22  78  30.8    20.8  

Fairway (Fairway Properties)

 Shelf W&T  25  75  57.1    26.3  

Miss. Canyon 243 (Matterhorn)

 Deepwater W&T  76  24  27.0    26.5  

Viosca Knoll 823 (Virgo)

 Deepwater W&T  34  66  13.9    7.9  

Main Pass 98

 Shelf W&T  29  71  10.4    7.8  

Brazos A-133

 Shelf Apache  1  99  32.0    6.4  

Main Pass 283

 Shelf W&T  51  49  22.1    15.5  

 


28


The following table provides information for our 10 largest fields in descending order of proved net reserves as of December 31, 2014, based on quantities on an energy equivalent basis.  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” 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)

 

Field Name

Field

Category

 

Net

Reserves (1)

 

 

Gross

 

 

Net

 

 

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

 

Fairway

Shelf

 

 

26

%

 

 

5,253

 

 

 

4,305

 

 

 

31,515

 

 

 

25,830

 

Viosca Knoll 783 (Tahoe/SE Tahoe)

Deepwater

 

 

26

%

 

 

6,292

 

 

 

4,668

 

 

 

37,753

 

 

 

28,007

 

Miss. Canyon 243 (Matterhorn)

Deepwater

 

 

74

%

 

 

4,832

 

 

 

4,832

 

 

 

28,989

 

 

 

28,989

 

Main Pass 108

Shelf

 

 

18

%

 

 

2,862

 

 

 

2,356

 

 

 

17,173

 

 

 

14,133

 

Miss. Canyon 782 (Dantzler) (2)

Deepwater

 

 

73

%

 

 

 

 

 

 

 

 

 

 

 

 

Viosca Knoll 823 (Virgo)

Deepwater

 

 

39

%

 

 

2,094

 

 

 

1,303

 

 

 

12,567

 

 

 

7,820

 

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)

Determined by

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 Bbl of crude oil, condensate or NGLs.NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the prices per Mcfeprice 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.

Index to Financial Statements
Volume measurements:

Bbl – barrels

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, 20112014, we had two fields of major significance (having(which we define as having year-end proved reserves which compriseof 15% or more of the Company’s total proved reserves, calculated on a natural gasan 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 description of these fields.

Spraberry Field (Yellow Rose Properties)Rose).

The Spraberry field is located in the Permian Basin in West Texas. W&TWe acquired a 100% working interest in approximately 21,900 net acres in connection with the acquisition of the Yellow Rose Propertiesproperties (the ‘Opal Properties”) from Opal Resources LLC and Opal Resources Operating LLC (collectively, “Opal”) in May 2011 and2011.  In separate transactions, we acquired approximately 9,500 net acres earlier in 2011.2011 and approximately 2,200 net acres in 2013. We are the operator for these properties.  The Spraberry Fieldfield 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. W&T is currently employing a three rig drilling program to continue developing the field.

From 2006 through 2011, 119 wells were drilled on acreage in which we currently have an ownership interest and 118 were successful, including 29 wellsDuring 2014, we drilled to target depth subsequent to our acquisition of the Yellow Rose Properties.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 during this time was 2through 2014 is approximately 6.4 MMBoe (11(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 28.137.3 MMBoe (168.5(223.6 Bcfe) at December 31, 2011.2014, 38.2 MMBoe (229.3 Bcfe) at December 31, 2013 and 31.6 MMBoe (189.8 Bcfe) at December 31, 2012.

The following presents historical information about our produced oil, NGLs and natural gas volumes (net to our interests) from the Spraberry field fromover the acquisition date of May 11, 2011 through December 31, 2011. As we have had limited history operating the Spraberry field, the amounts below may not be representative of future results.past three years.

 

   May -
December
2011
 

Net sales:

  

Oil (MBbls) (1)

   452.3  

NGLs (MBbls)

   60.3  

Natural gas (MMcf)

   213.5  

Total oil equivalent (MBoe) (2)

   548.2  

Total natural gas equivalent (MMcfe)

   3,289.2  

Total oil equivalent (Boe/day)

   2,333  

Total natural gas equivalent (MMcfe/day)

   14.0  

Average realized sales prices:

  

Oil ($/Bbl)

  $91.09  

NGLs ($/Bbl)

   51.70  

Natural gas ($/Mcf)

   3.05  

Oil equivalent ($/Boe) (3)

   82.03  

Natural gas equivalent ($/Mcfe)

   13.67  

Average production costs (4):

  

Oil equivalent ($/Boe)

  $13.62  

Natural gas equivalent ($/Mcfe)

   2.27  

 

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)

One thousand barrels of oil (“MBbl”).
(2)One thousand barrels of oil equivalent (“MBoe”).

Index to Financial Statements
(3)Barrels of oil equivalent (“Boe”).
(4)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. The field area covers Ship Shoal blocks 349 and 359, with a single production platform on Ship Shoal block 349. 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 and we now own a 100% working interest in this field. Cumulative field production through 20112014 is approximately 3037.3 MMBoe gross (179(223.6 Bcfe gross). This field is a sub-salt development with fiveeight productive horizons below salt at depths up to 17,000 feet. As of December 31, 2011, 24 wells have been drilled, of which 15 have been successful. In 2010, we developed a reservoir simulation model to determine the most optimal future development plan.plan (the “2010 Development Plan”).  As a result, in 2011, we drilled and completed one development well and one exploration well.  In January 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 as partat year end 2014 and, in January 2015, drilling on this well was suspended at an intermediate casing point pending higher crude oil prices. All of an ongoing drilling program.the wells drilled under the 2010 Development Plan have been successful. Total proved reserves associated with our interest in this field were 20.318.8 MMBoe (121.7(112.9 Bcfe) at December 31, 2011.2014, 22.9 MMBoe (137.7 Bcfe) at December 31, 2013 and 22.7 MMBoe (136.3 Bcfe) at December 31, 2012.

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

 

   Year Ended December 31, 
   2011   2010   2009 

Net sales:

      

Oil (MBbls)

   445.2     656.7     675.7  

NGLs (MBbls)

   22.7     37.9     47.7  

Natural gas (MMcf)

   497.8     862.8     772.8  

Total oil equivalent (MBoe)

   550.8     838.4     852.2  

Total natural gas equivalent (MMcfe)

   3,304.9     5,030.3     5,112.9  

Total oil equivalent (Boe/day)

   1,509     2,297     2,335  

Total natural gas equivalent (MMcfe/day)

   9.1     13.8     14.0  

Average realized sales prices:

      

Oil ($/Bbl)

  $101.30    $73.20    $55.75  

NGLs ($/Bbl)

   56.06     43.54     29.43  

Natural gas ($/Mcf)

   4.20     4.88     4.56  

Oil equivalent ($/Boe)

   87.97     64.33     49.99  

Natural gas equivalent ($/Mcfe)

   14.66     10.72     8.33  

Average production costs (1):

      

Oil equivalent ($/Boe)

  $14.30    $13.20    $14.57  

Natural gas equivalent ($/Mcfe)

   2.38     2.20     2.43  

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Net Sales:

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

2,020

 

 

 

1,943

 

 

 

960

 

NGLs (MBbls)

 

104

 

 

 

90

 

 

 

85

 

Natural gas (MMcf)

 

3,433

 

 

 

3,328

 

 

 

2,108

 

Total oil equivalent (MBoe)

 

2,697

 

 

 

2,589

 

 

 

1,397

 

Total natural gas equivalents (MMcfe)

 

16,181

 

 

 

15,533

 

 

 

8,380

 

Average daily equivalent sales (Boe/day)

 

7,388

 

 

 

7,093

 

 

 

3,816

 

Average daily equivalent sales (Mcfe/day)

 

44,330

 

 

 

42,556

 

 

 

22,896

 

Average realized sales prices:

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

$

87.21

 

 

$

98.69

 

 

$

102.55

 

NGLs ($/Bbl)

 

46.46

 

 

 

43.24

 

 

 

41.74

 

Natural gas ($/Mcf)

 

4.40

 

 

 

3.72

 

 

 

2.78

 

Oil equivalent ($/Boe)

 

72.73

 

 

 

80.39

 

 

 

77.24

 

Natural gas equivalent ($/Mcfe)

 

12.12

 

 

 

13.40

 

 

 

12.87

 

Average production costs (1):

 

 

 

 

 

 

 

 

 

 

 

Oil equivalent ($/Boe)

$

4.12

 

 

$

3.68

 

 

$

6.27

 

Natural gas equivalent ($/Mcfe)

 

0.69

 

 

 

0.61

 

 

 

1.05

 

(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 ten10 properties, measured by proved reserves at December 31, 2011,2014, three of which five are located on the conventional shelf and threefive 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 field 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 64.3% working interest, along with operatorship in the Fairway field, from 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, six wells have been drilled, one of which was a replacement well. Cumulative field production through 2014 is approximately 125.4 MMBoe gross (752.3 Bcfe 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 from this field, net to our interest, averaged 47 Bbls 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).

Viosca Knoll 783 Field.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, 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.

Index to Financial Statements

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 for these properties. Cumulative field production through 20112014 is approximately 8896.3 MMBoe gross (526(577.6 Bcfe 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, 2011,2014, 16 wells have been drilled at the Tahoe prospect, eight of which eight have been successful and one successful well has been drilled at the SE Tahoe prospect. During December 2011,2014, production from this field, net to our interest, averaged 260212 Bbls of oil per day, 8601,362 Bbls of NGLs per day and 18.918.8 MMcf of natural gas per day, for total production of 4.3 MBoe4,700 Boe per day (25.6(28.2 MMcfe per day).

FairwayMississippi Canyon 243 Field (Fairway Properties)(Matterhorn).  FairwayMississippi Canyon 243 field is comprisedlocated off the coast of Mobile Area blocks 113 (Alabama State Lease #0531) and 132 (Alabama State Lease #0532) and locatedLouisiana, approximately 100 miles southeast of New Orleans, in 252,552 feet of water, approximately 35 miles south of Mobile, Alabama.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 our 64.3%a 100% working interest along with operatorship in the Fairway field from ShellTotal E&P USA Inc. (“Total E&P”) in August 2011. 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, 2011, six wells have been drilled, all of which were successful.2010.  Cumulative field production through 20112014 is approximately 11731.7 MMBoe gross (704(190.4 Bcfe gross).  This field is a Norphlet sand dune trendsupra-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 producing horizon at an approximatewell, which began production in 2013, and we drilled another well, that had reached target depth of 21,300 feet.but had not yet been completed. During 2014, the well that had reached target depth in 2013 was completed.  During December 2011,2014, production from this field, net to our interest, averaged seven1,553 Bbls of oil per day, 1,365463 Bbls of NGLs per day and 14.612.2 MMcf of natural gas per day, for total production of 3.8 MBoe4,051 Boe per day (22.8(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.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, 2011, 422014, 48 wells have been drilled in this field, 30 of which 34 were successful.  Cumulative field production through 20112014 is approximately 4653.1 MMBoe gross (275(318.7 Bcfe gross).  In early June 2010, a third party pipeline that was used to transport production from the field was shutdown due to damage. AOne new line was installed and the production rerouted at the end of March 2011. During 2010 and 2011, additional wells were successfully drilled, recompleted or workovers were performed which increased production and added reserves. Production from the field resumedwell reached target depth in April 2011 and is currently at a higher daily rate than before the pipeline shutdown.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 2011,2014, production from this field, net to our interest, averaged 444118 Bbls of oil per day, 425178 Bbls of NGLs per day and 19.910.7 MMcf of natural gas per day, for total production of 4.2 MBoe2,086 Boe per day (25.2(12.5 MMcfe per day).

Mississippi Canyon 243 Field. (Matterhorn)782 Field (Dantzler) Mississippi Canyon 243782 field is located off the coast of Louisiana, approximately 100160 miles southeast of New Orleans, in 2,5526,600 feet of water.  The field area covers Mississippi Canyon block 243,782 and 738.  We have a 20% working interest, which is operated by Noble Energy.  We, along with a single production platform on Mississippi Canyon block 243. Société Nationale Elf AquitaineNoble Energy, discovered the field in 2002. We acquired a 100% working interest in the field from Total in 2010. Cumulative field production through 2011 is approximately 21 MMBoe gross (124 Bcfe gross).2013.  This field is currently under development as a supra-salt development with 17 productivesubsea tieback to the Thunderhawk Field approximately 12 miles to the northwest.  The field is a three-way closure trapped against a salt wall.  There are two pay horizons, at depths ranging to 9,850 feet.the upper Miocene U5 and U6 sands.  As of December 31, 2011, 172014, two wells have been drilled, of which eightboth have been successful. During December 2011,successful and are targeted for first production from this field, net to our interest, averaged 3,150 Bblsin the first quarter of oil per day, 288 Bbls of NGLs per day and 11.4 MMcf of natural gas per day, for total production of 5.3 MBoe per day (32.0 MMcfe per day).2016.

32


Viosca Knoll 823 Field.Field (Virgo). Viosca Knoll 823 field is located off the coast of Louisiana, approximately 125 miles southeast of New Orleans, 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 2010.2010 and we are the operator for this property. Cumulative field production through 20112014 is approximately 2021.7 MMBoe gross (117(130.4 Bcfe gross). This field is a supra-salt development with 17 productive horizons at depths ranging to 13,335 feet. As of December 31, 2011, 122014, 14 wells have been drilled, 10 of

Index to Financial Statements

which tenhavehave been successful. During December 2011,2014, production from this field, net to our interest, averaged 153128 Bbls of oil per day, 76145 Bbls of NGLs per day and 5.95.2 MMcf of natural gas per day, for total production of 1.2 MBoe1,137 Boe per day (7.3(6.8 MMcfe per day).

East Cameron 321. Main Pass 98 Field.Main Pass 98 field consists of Main Pass blocks 98 and 180. ThisEast Cameron 321 field is located approximately 97 miles off the coast of Louisiana approximately 55 miles east of Venicecoastline in 91225 feet of water.  We acquired our 100% working interestTwo production facilities, the “A” and “B” platforms, are located on the block.  This field has multiple sands that are productive in these blocks from NCXfaulted, structural traps.  These sands are Pleistocene Ang B in 2009. The field produces from low relief, predominantly stratigraphically trapped sands located between two merging, generally south dipping faults. The productive interval is Middle Miocene Bigenerina Humblei. Cumulative field production through 2011 is approximately four MMBoe gross (21 Bcfe) gross.age.  As of December 31, 2011, 112014, 76 wells have been drilled of which seven58 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 December 2011,January to October 2014, which was prior to the departing gas sales line damage, production from this field, net to our interest, averaged 371890 Bbls of oil per day 113 Bbls of NGLs per day and 5.40.2 MMcf of natural gas per day, for total production of 1.4 MBoe928 Boe per day (8.3(5.6 MMcfe 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 2011 is approximately 144 MMBoe gross (861 Bcfe 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 drilled, of which 17 were successful. We own a 25% working interest that was obtained through a transaction with Kerr-McGee. During December 2011, production from this field, net to our interest, averaged nine Bbls of oil per day and 6.4 MMcf of natural gas per day, for total production of 1.1 MBoe per day (6.4 MMcfe per day).

Main Pass 283 Field. 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 20112014 is approximately 2824.3 MMBoe gross (168(145.8 Bcfe gross).  As of December 31, 2011, 182014, 12 wells have been drilled in this field, of which 1410 were successful.  During December 2011,2014, production from this field, net to our interest, averaged 738398 Bbls of oil per day, 227195 Bbls of NGLs per day and 4.7MMcf3.9 MMcf of natural gas per day, for total production of 1.7 MBoe1,251 Boe per day (10.5(7.5 MMcfe per day).

Proved Reserves

Our estimated proved reserves totaled 116.9 MMBoe (701.1 Bcfe) at December 31, 2011. The mix by product was 44% oil, 15% NGLs and 41% natural gas determined using the conversion ratio noted below. The conversion ratio does not assume price equivalency, and the price per Mcfe for natural gas, oil and NGLs may differ significantly from each other. Our proved reserves were estimated by NSAI, our independent petroleum consultant.

Index to Financial Statements

Our proved reserves are summarized below. These reserveconsultant 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, 2014 are summarized below and the mix by product was 52% oil, 13% NGLs and 35% natural gas determined using the energy-equivalent ratio noted below.  

 

 

 

 

 

 

 

 

 

 

 

 

 

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)

 

Proved developed producing

 

29.8

 

 

 

9.2

 

 

 

177.7

 

 

 

68.7

 

 

 

412.2

 

 

 

57

%

 

$

1,903

 

Proved developed non-producing

 

5.9

 

 

 

1.5

 

 

 

43.4

 

 

 

14.6

 

 

 

87.5

 

 

 

12

%

 

 

304

 

Total proved developed

 

35.7

 

 

 

10.7

 

 

 

221.1

 

 

 

83.3

 

 

 

499.7

 

 

 

69

%

 

 

2,207

 

Proved undeveloped

 

26.0

 

 

 

5.1

 

 

 

33.8

 

 

 

36.7

 

 

 

220.3

 

 

 

31

%

 

 

398

 

Total proved

 

61.7

 

 

 

15.8

 

 

 

254.9

 

 

 

120.0

 

 

 

720.0

 

 

 

100

%

 

$

2,605

 

 

  As of December 31, 2011 
           Total Equivalent
Reserves
       
  Oil  NGLs  Natural
Gas
  Oil
Equivalent
  Natural
Gas
Equivalent
  % of
Total
  PV-10 (3) 

Classification of Proved Reserves (1)

 (MMBbls)  (MMBbls)  (Bcf)  (MMBoe) (2)  (Bcfe) (2)  Proved  (In millions) 

Proved developed producing

  17.8    8.2    169.3    54.3    325.8    46 $1,451.9  

Proved developed non-producing

  5.6    2.8    82.1    22.1    132.4    19  527.1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total proved developed

  23.4    11.0    251.4    76.4    458.2    65  1,979.0  

Proved undeveloped

  28.0    6.1    38.3    40.5    242.9    35  1,112.9  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total proved

  51.4    17.1    289.7    116.9    701.1    100 $3,091.9  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Volume measurements:

 

MMBbls – million barrels for crude oil, condensate or NGLs

Bcf – billion cubic feet

MBoe – 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, 20112014 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, 2011.2014. Prices were adjusted by lease for quality, transportation, fees, energy content and regional price differentials. For oil, the West Texas Intermediate posted price was used in the calculation and, after adjustments, a price of $97.36$91.12 per Bbl was used in computing the amounts above. For NGLs, a ratio was computed for each field of the NGLs realized price compared to the oil realized price. Then, this ratio was applied to the oil price using SEC guidance. The NGLs price of $51.30$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 $4.11$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, development costs and ARO are based on year-end costs with no escalations.

33


(2)

Bcfe and MMBoe

Energy equivalents are determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversionenergy-equivalent ratio does not assume price equivalency, and the energy-equivalent price per Mcfe for oil and NGLs may differ significantly from the price per Mcf for natural gas. Similarly, the price per Bbl for oil may differ significantly from the price per Bbl for NGLs.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 prescribeddefined under generally accepted accounting principles (“GAAP”);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 areis 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.

Index to Financial Statements

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

 

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

$

2,605

 

Present value of estimated ARO, discounted at 10%

 

(301

)

PV-10 after ARO

 

2,304

 

Future income taxes, discounted at 10%

 

(601

)

Standardized measure of discounted future net cash flows

$

1,703

 

 

   As of
December 31,
2011
 

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

  $3,091.9  

Present value of estimated ARO, discounted at 10%

   (339.9
  

 

 

 

PV-10 after ARO

   2,752.0  

Future income taxes, discounted at 10%

   (745.6
  

 

 

 

Standardized measure of discounted future net cash flows

  $2,006.4  
  

 

 

 

Changes in Proved Reserves

Our total proved reserves increased to 116.9more than production, resulting in a net increase, and were 120.0 MMBoe (701.1 Bcfe) at December 31, 2011 from 80.92014 compared to 117.7 MMBoe (485.4 Bcfe) at December 31, 2010, primarily as2013.  The change between periods is a result of acquisitions discussed in Item 1,Business,which added 39.0 MMBoe (234.1 Bcfe) estimated as of the date of acquisition. Estimated proved reserves also increased 5.3 MMBoe (32.0 Bcfe) due to extensions and discoveries resultingof 9.7 MMBoe, acquisitions of 6.1 MMBoe and positive net revisions of 4.1 MMBoe, partially offset by 17.6 MMBoe of production.  Increases for extensions and discoveries were primarily at Mississippi Canyon 782 (Dantzler) related to two wells and the Spraberry field related to 51 wells.  Increases from our participationacquisitions were primarily due to acquiring interests in the drillingWoodside Properties and increasing ownership in the Fairway field.  Revisions 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.  See Development of 19 successful exploratory wells (gross) and increases resulting from well completions, recompletions and workovers. In addition,Proved Undeveloped Reserves below for a table reconciling the change in proved undeveloped reserves increased from revisions of previous estimates by 8.6 MMBoe (51.0 Bcfe). Partially offsetting these increases were declines associated with production of 16.9 MMBoe (101.5 Bcfe).during 2014. SeeFinancial Statements and Supplementary Data– Note 2221 – Supplemental Oil and Gas Disclosuresunder Part II, Item 8 in this Form 10-Kfor10-K for additional information.

Our estimates of proved reserves, PV-10 and standardized measure as of December 31, 2014 are calculated based upon SEC mandated 2014 unweighted average first-day-of-the-month oil and natural gas benchmark prices, which are substantially above prices realized in December 2014 and January 2015.  The prices of crude oil, NGLs and natural gas have declined substantially since June 2014.  The spot 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 per Mcf compared to average prices during 2014 well in excess of $4.00 per Mcf. Sustained lower prices will result in the prices used in our estimates through year-end 2015 being substantially lower, which, absent significant proved reserve additions, will reduce future estimated proved reserve volumes due to lower economic limits and economic return thresholds for undeveloped reserves, as well as impact our quarterly full cost impairment ceiling tests and volume-dependent depletion cost calculations.

34


Qualifications of Technical Persons and Internal Controls Overover Reserves Estimation Process

Our estimated proved reserve information as of December 31, 20112014 included in this Annual Report on Form 10-K was prepared by our independent petroleum consultant,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 Annual Report on 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 Engineering and has been a Registered Professional Engineer in the State of Texas for 2326 years and a member of the Society of Petroleum Engineers for over 2730 years. He has over 3437 years total experience in the oil and gas industry, with over 2023 years of reservoir engineering 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 theStandards 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 Vice President of Reservoir Engineering Director has served in that capacity since 2005, after having served2013, as our Reservoir Engineering Manager since 20032006, and has been withas Staff Reservoir Engineer upon joining the Company since 1998.in 2004. Prior to joining the Company, he served as a Reservoir and Facilities Engineer with Exxonat Shell, then VP of Reservoir Engineering at Freeport-McMoRan Oil & Gas and later as a Reservoir Engineer with CollariniManager Acquisitions Engineering Inc.at Matrix Oil & Gas. He received a Bachelor of Science degree in Civil Engineering Science from the University of Florida in 1977 and a Master of Science degree in Environmental Engineering from TulaneIowa State University in 1995.

1972.

Index to Financial Statements

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;

·

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 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. In our December 31, 2011 reserve report prepared by our independent petroleum consultant, NGLs represented approximately 15% of our total proved reserves compared to 5% as of December 31, 2010. Due to the increase in the percentage for NGLs, we have reported NGLs separately from oil and have changed the presentation of prior periods for comparability. We convert Bbl to Mcfe using aan energy-equivalent ratio of six Mcf to one Bbl of oil, condensate or NGLs. This conversionenergy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices on a volume equivalent basisfor oil, NGLs and natural gas may differ substantially between each other.substantially.

35


Development of Proved Undeveloped Reserves

Our proved undeveloped reserves at December 31, 2011, as(“PUDs”) were estimated by NSAI, our independent petroleum consultant, were 40.5 MMBoe (242.9 Bcfe).consultant. Future development costs associated with our proved undeveloped reservesPUDs at December 31, 20112014 were estimated at $471.4$865.8 million. As of December 31, 2010,

The following table presents our proved undeveloped reserves were 15.7 MMBoe (94.1 Bcfe).

Our proved undeveloped reservesPUDs by field (in MMBoe):

 

As of December 31,

 

 

2014

 

 

2013

 

 

2012

 

Ship Shoal 349 (Mahogany)

 

2.1

 

 

 

1.3

 

 

 

4.8

 

Mississippi Canyon 243 (Matterhorn)

 

1.4

 

 

 

1.3

 

 

 

2.1

 

Viosca Knoll 823 (Virgo)

 

2.0

 

 

 

1.4

 

 

 

1.4

 

Spraberry (Yellow Rose)

 

24.9

 

 

 

25.7

 

 

 

19.6

 

Mississippi Canyon 698 (Big Bend) (1)

 

1.9

 

 

 

1.9

 

 

 

 

Mississippi Canyon 538/582 (Medusa)

 

0.3

 

 

 

 

 

 

 

Mississippi Canyon 782 (Dantzler) (1)

 

4.1

 

 

 

 

 

 

 

High Island 21/22

 

 

 

 

 

 

 

2.7

 

Total

 

36.7

 

 

 

31.6

 

 

 

30.6

 

(1)

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

The following table presents a reconciliation of December 31, 2011 and 2010 are as follows:our PUDs (in MMBoe):

 

   December 31, 2011   December 31, 2010 
       MMBoe           Bcfe           MMBoe           Bcfe     

Main Pass 108

   —       —       2.6     15.8  

Ship Shoal 349 (Mahogany)

   16.6     99.8     9.3     55.8  

Mississippi Canyon 243

   3.1     18.8     2.6     15.5  

Viosca Knoll 823

   1.4     8.2     1.2     7.0  

Spraberry (Yellow Rose Properties)

   19.4     116.1     —       —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

   40.5     242.9     15.7     94.1  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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

Index

36


Activity related to Financial Statements

During 2011, we drilled three development wells at our Main Pass 108 field, only one of which resultedPUDs 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.

·

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 reclassification of proved 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.  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 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 proved developed reserves. As shownPUDs in the table above, all of the proved undeveloped reserves associated with this field as of December 31, 2010 were either reclassified2013:

·

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 proved developed or removed from our proved undeveloped reserves as of December 31, 2011.

During 2011, we drilled one development well and one exploration well at our Ship Shoal 349 (Mahogany) field. Also during the year, we had one well sand up that caused reserves previously classified as proved developed to be reclassified to proved undeveloped reserves. In addition, we decided to accelerate production from another well, which resultedPUDs in the movement of reserves previously classified as proved non-producing reserves to proved undeveloped reserves. We are currently drilling the third well of a potentially six well drilling program at the Mahogany field that commenced in 2011 and is expected to continue through 2013. This program is expected to result in the reclassification of a substantial portion of the proved undeveloped reserves to proved developed producing reserves in this field. Please seeOur Fields above under this Item 2 for a description of our Mahogany field, which is our largest offshore field from a reserve standpoint.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

The proved undeveloped reserves at our Mississippi Canyon 243 field and Viosca Knoll 823 fields were obtained through acquisitions completed in 2010 and development of both of these fields is expected to continue.

In May 2011, we acquired the Yellow Rose Properties, which contributed to a significant increase in proved undeveloped reserves between 2010 and 2011. Reserves for the Yellow Rose Properties as of December 31, 2011 consisted of 28.1 MMBoe (168.5 Bcfe), of which 19.4 MMBoe (116.1 Bcfe) was classified as proved undeveloped. SeeBusiness under Part I, Item 1,Our Fields in Item 2 above andFinancial Statements and Supplementary Data – Note 2 – Acquisitions and Divestituresunder Part II, Item 8 in this Form 10-K for additional information on the Yellow Rose Properties. In the Yellow Rose Properties, we completed 27 development wells and three exploration wells from the acquisition date of May 11, 2011 to December 31, 2011 and plan on drilling approximately 46 development wells in 2012.information.

We believe that we will be able to develop all but 1.4 MMBoe of the reserves classified as proved undevelopedPUDs, or approximately 96%, out of the total of 36.7 MMBoe classified as PUDs at December 31, 20112014, within five years from the date such reserves were initially recorded.  The 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 were originally recorded in our reserves as of December 31, 2010. The development of the 1.4 MMBoe of PUDs 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) PUDs in 2020.  

Our capital budget for 20122015 for development is up 37% from our 2011 capital budget, with 61% dedicated to development activities, split 63% offshore and 37% onshore.approximately $120 million. The capital allocated to our offshore development activities will assist us in converting the proved undeveloped reserves at the Mahogany fieldPUDs to proved developed producing reserves. The expected expenditures for offshorePDPs.  A recovery in crude oil prices could lead to an increase in development represent a significant increase over both 2010 and 2011 expenditures.


38


Acreage

The following summarizes our leasehold at December 31, 2011.2014. 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

   605,083     369,967     61,164     61,164     666,247     431,131  

 

507,102

 

 

 

331,450

 

 

 

77,985

 

 

 

77,985

 

 

 

585,087

 

 

 

409,435

 

Deepwater

   85,952     50,470     40,320     31,680     126,272     82,150  

 

179,331

 

 

 

76,434

 

 

 

359,746

 

 

 

212,603

 

 

 

539,077

 

 

 

289,037

 

  

 

   

 

   

 

   

 

   

 

   

 

 

Total Offshore

   691,035     420,437     101,484     92,844     792,519     513,281  

 

686,433

 

 

 

407,884

 

 

 

437,731

 

 

 

290,588

 

 

 

1,124,164

 

 

 

698,472

 

Onshore

   17,599     16,282    187,631     157,152     205,230     173,434  

 

30,228

 

 

 

25,952

 

 

 

24,500

 

 

 

15,749

 

 

 

54,728

 

 

 

41,701

 

  

 

   

 

   

 

   

 

   

 

   

 

 

Total

   708,634     436,719     289,115     249,996     997,749     686,715  

 

716,661

 

 

 

433,836

 

 

 

462,231

 

 

 

306,337

 

 

 

1,178,892

 

 

 

740,173

 

  

 

   

 

   

 

   

 

   

 

   

 

 

Approximately 82%58% of our total net offshore acreage is developed and approximately 9%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.  We have the right to propose future exploration and development projects on the majority of our acreage.

Index to Financial Statements

For the offshore undeveloped leasehold, none of our rights will expire in 2012, 33,74059,498 net acres (36%(20%) could expire in 2013, 26,841of the total 290,588 net undeveloped offshore acres (29%) could expire in 2014, 26,503 net acres (29%) could expire in 2015, and 5,76035,965 net acres (6%(12%) could expire in 2016, 79,180 net acres (28%) could expire in 2017, 52,121 net acres (18%) could expire in 2018, and 63,824 net acres (22%) could expire in 2019 and beyond. For the onshore undeveloped leasehold, our rights to approximately 143,53110,612 net acres (91%(67%) of the total 15,749 net undeveloped onshore acres could expire in 2015 and 5,088 net acres (33%) could expire in 2012, 9,8392016. Within the onshore net undeveloped acreage, the Spraberry field (Yellow Rose) comprises 2,486 net acres (6%) could expire in 2013, 3,777and the other onshore prospects comprise the remaining 13,263 acres of the total 15,749 net acres (3%) could expire in 2014, and five net acres could expire thereafter. Ofacres.  The expiration of the onshore undeveloped onshore leasehold, there are 140,885 net acres that canacreage may be extended by drilling two additional wells in 2012 and further extended by additional operationsthrough the purchase of new leasehold rights or production in future years.extension of leasehold rights, but these potential arrangements were not contractual rights as of December 31, 2014.  In making decisions regarding drilling and operations activity for 2012,2015 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 35,56039,067 net acres (6%(5%) from December 31, 20102013 and our net onshore acreage increased 168,790decreased 141,170 net acres (77%) from a minor ownership position as of December 31, 2010.2013. The reduction in our net offshore acreage was attributable to certain offshore leases that terminated. This reduction was partially offset by the offshore property interests acquired in the Fairway Properties. The increasedecrease in our net onshore acreage iswas primarily attributabledue to the Yellow Rose Properties acquisition and leasehold interest acquiredreassigning acres back to our original assignor at our Star Project in East Texas.

Production

For the years 2011, 20102014, 2013 and 2009,2012, our net daily production averaged 278.2, 238.448.3 MBoe, 49.3 MBoe and 259.7 MMcfe per 46.8 MBoe, respectively. Production decreased in 2014 from 2013 primarily due to an out of period adjustment of 0.9 MBoe/day respectively.recorded in 2013, natural production declines, production deferrals and divestitures, partially offset by acquisitions and new production.  Production increased in 20112013 from 20102012 primarily due to acquisitions completedand increases in 2010 and 2011the Ship Shoal 349 field attributable to development activities and the resumptionout of operations in certain fields that had been shut down from June 2010 to March 2011 due to pipeline outages. Production decreased in 2010 from 2009 primarily due to the two pipeline outages and divestitures completed in 2009,period adjustment, partially offset by acquisitions completednatural production declines and production deferrals.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations under Part II, Item 7 in 2010.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 fiscal years.

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Net Sales:

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

7,176

 

 

 

7,018

 

 

 

6,033

 

NGLs (MBbls)

 

2,112

 

 

 

2,091

 

 

 

2,129

 

Oil and NGLs (MBbls)

 

9,288

 

 

 

9,110

 

 

 

8,163

 

Natural gas (MMcf)

 

50,088

 

 

 

53,257

 

 

 

53,825

 

Total oil equivalent (MBoe)

 

17,636

 

 

 

17,986

 

 

 

17,133

 

Total natural gas equivalents (MMcfe)

 

105,815

 

 

 

107,915

 

 

 

102,800

 

 

   Year Ended December 31, 
  2011   2010   2009 

Net sales:

      

Oil (MMBbls)

   6.1     5.9     6.1  

NGLs (MMBbls)

   1.9     1.2     1.1  

Natural gas (Bcf)

   53.7     44.7     51.6  

Total oil equivalent (MMBoe)

   16.9     14.5     15.8  

Total natural gas equivalent (Bcfe)

   101.5     87.0     94.8  

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 ten10 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 349349/359 field (Mahogany) over the past three fiscal years, each of which have proved reserves exceeding 15% of our total proved reserves. Also refer toSelected Financial Data – Historical Reserve and Operating Informationunder Part II, Item 6 ofin this Form 10-K for additional historical operating data.

data, including average realized sale prices and production costs.

Index to Financial Statements

Productive Wells

The following presents our ownership interest at December 31, 20112014 in our productive oil and natural gas wells. A net well isrepresents our percentagefractional working interest of a gross well.

Offshore Wellswell in which we own less than all of the working interest.

 

   Oil Wells   Gas Wells   Total Wells 
     Gross       Net       Gross       Net       Gross       Net   

Operated

   92     79     96     77     188     156  

Non-operated

   58     19     65     15     123     34  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   150     98     161     92     311     190  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Onshore Wells

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

 

 

   Oil Wells   Gas Wells   Total Wells 
     Gross       Net       Gross       Net       Gross       Net   

Operated

   111     111     1     1     112     112  

Non-operated

                              
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   111     111     1     1     112     112  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

All Productive Wells

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

 

 

  Oil Wells (1)   Gas Wells (1)   Total Wells 

Total Productive Wells

Oil Wells (1)

 

 

Gas Wells (1)

 

 

Total Wells

 

    Gross       Net       Gross       Net       Gross       Net   

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Operated

   203     190     97     78     300     268  

 

324

 

 

 

312

 

 

 

69

 

 

 

54

 

 

 

393

 

 

 

366

 

Non-operated

   58     19     65     15     123     34  

 

34

 

 

 

10

 

 

 

35

 

 

 

11

 

 

 

69

 

 

 

21

 

  

 

   

 

   

 

   

 

   

 

   

 

 
   261     209     162     93     423     302  
  

 

   

 

   

 

   

 

   

 

   

 

 

Total productive wells

 

358

 

 

 

322

 

 

 

104

 

 

 

65

 

 

 

462

 

 

 

387

 

 

(1)

Includes eight11 gross (5.0(9.0 net) oil wells and sevennine gross (6.2(5.8 net) gas wells with multiple completions.

Drilling Activity

As presented in the tables below, our drilling activity increaseddecreased in 20112014 compared to 2010.2013 in our onshore operations. In 2014, 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.  Our onshore drilling activity increased due tois primarily in the Spraberry field, which was acquired by acquisition of the Yellow Rose Properties andin May 2011, coupled with additional leasehold interests acquired in Texas.2011 and 2013.

40


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

Development Drilling

The following table sets forth information related to our development wells drilled 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

 

Our success rates related to our gross development 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 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 were 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.

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 oil, NGLs and natural gas, acquisition opportunities and the results of our exploration and development activities. For the year ended December 31, 2011, ourSee 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 capital expenditures for oil and natural gas properties and equipment of $719.0 million included $437.2 million for acquisitions, an adjustment for funds received of $5.7 millioninformation.

Item 3. Legal Proceedings

Apache Lawsuit.  In December 2014, Apache Corporation (“Apache”) filed a lawsuit against W&T Offshore, Inc., alleging that W&T breached the joint operating agreement related to a 2010 acquisition, $77.6 millionplugging and abandonment costs for exploration activities, $179.7 million for development activities and $30.2 million for seismic, capitalized interest and other leasehold costs.

In managing and tracking our drilling activity, we use target depth as the criteria to determine when a well is reported as drilled and use this criteria internally,three deepwater wells in the field descriptions reported aboveMississippi Canyon area of the Gulf of Mexico.  We contend that the costs incurred by Apache are excessive and unreasonable.  Apache seeks unspecified actual damages, interest, court costs and attorneys’ fees. See Financial Statements and Supplementary Data - Note 18 – Contingenciesunder Part II, Item 8 in press releases. This differsthis Form 10-K for information on this matter.

Claims against Certain Insurance Underwriters. In June 2014, the United States Fifth Circuit reversed a lower court’s ruling and compelled our insurance underwriters to reimburse costs incurred by us for removal of wreck related 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 to claims, the estimated potential reimbursement of removal-of-wreck costs is approximately $31 million, plus interest, attorney fees and damages, if any.  See Financial Statements and Supplementary Data - Note 18 – Contingenciesunder Part II, Item 8 in this Form 10-K for additional information.  

Monetary Sanctions by Government Authorities.  During 2014, we paid a civil penalty assessment from the SEC’s criteria of using completion to determine when a well is counted as drilled. Historically,BSEE for $30,000 and we also paid the period between reaching target depth and completion has been relatively shortUnited States Coast Guard penalties for us. Using the completion criteria creates minor differences in reported wells drilled. For 2011, using target depth as the criteria, we had 54 total gross wells drilled. Using the SEC criteria of completion, we had 48 gross wells drilled. There was one well difference in 2010 and 2009 between the two criteria. The tables below are based on the SEC’s criteria of completion to determine successful wells drilled.

Index to Financial Statements

Development Drilling

The following table sets forth information relating to our development wells drilled over the past three years.

   Year Ended December 31, 
      2011           2010           2009     

Gross Wells:

      

Productive:

      

Offshore

   5     1     2  

Onshore

   27            

Non-productive:

      

Offshore

             1  

Onshore

               
  

 

 

   

 

 

   

 

 

 
   32     1     3  
  

 

 

   

 

 

   

 

 

 

Net Wells:

      

Productive:

      

Offshore

   4.5     0.1     1.7  

Onshore

   27.0            

Non-productive:

      

Offshore

             0.3  

Onshore

               
  

 

 

   

 

 

   

 

 

 
   31.5     0.1     2.0  
  

 

 

   

 

 

   

 

 

 

Our success rates related to our gross development wells drilled during the years ended December 31, 2011, 2010 and 2009 were 100%, 100% and 67%, respectively.

Exploration Drilling

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

   Year Ended December 31, 
      2011           2010           2009     

Gross Wells:

      

Productive:

      

Offshore

   3     5     8  

Onshore

   12            

Non-productive:

      

Offshore

        1     2  

Onshore

   1     2       
  

 

 

   

 

 

   

 

 

 
   16     8     10  
  

 

 

   

 

 

   

 

 

 

Net Wells:

      

Productive:

      

Offshore

   2.4     3.6     6.4  

Onshore

   7.6            

Non-productive:

      

Offshore

        1.0     1.3  

Onshore

   0.7     0.7       
  

 

 

   

 

 

   

 

 

 
   10.7     5.3     7.7  
  

 

 

   

 

 

   

 

 

 

Index to Financial Statements

Our success rates related to our gross exploration wells drilled during the years ended December 31, 2011, 2010 and 2009 were 94%, 63% and 80%, respectively.

Current Drilling Activity

The following table sets forth current 2012 drilling activity to February 17, 2012.

   January 1, 2012 to February 17, 2012 
       Development           Exploration     

Gross Wells:

    

Productive:

    

Offshore

          

Onshore

   4     8  

Non-productive:

    

Offshore

          

Onshore

          
  

 

 

   

 

 

 
   4     8  
  

 

 

   

 

 

 

Net Wells:

    

Productive:

    

Offshore

          

Onshore

   4     7.9  

Non-productive:

    

Offshore

          

Onshore

          
  

 

 

   

 

 

 
   4     7.9  
  

 

 

   

 

 

 

As of February 17, 2012, we wereinsignificant discharges (less than 0.0017 barrels in the processaggregate) totaling less than $4,000.  In February 2015, the Company received a Notice of drilling and/or completing one offshore development well, seven onshore exploration wells and eight onshore development wells.

Item 3.Legal Proceedings

The United States Attorney’s Office forProposed Civil Penalty Assessment from the Eastern District of Louisiana, along withBSEE affecting the Criminal Investigation Division ofCompany’s operated platform A in the EPA, has been conducting a federal grand jury investigation of environmental compliance matters relating to surface discharges and reporting on four of our offshore platformsEast Cameron 321 field in the Gulf of Mexico.  We are fully cooperating with the investigationThe BSEE proposed civil penalties totaled $990,000, which beganarose from two Incidents of Noncompliance (“INCs”) issued in 2011 and is continuing in 2012. The United States Attorney’s Office has informed us that they are continuing their investigation with the intent to seek a criminal disposition. The outcome of this investigation could have a material adverse effect upon us. We are not able at this time to estimate our potential exposure, if any,2014 during drilling operations.  No injuries or spills occurred related to this matter.

On May 6, 2009, certain Cameron Parish land owners filed suit in the 38th Judicial District Court, Cameron Parish, Louisiana againstthese two issues and the Company and Tracy W. Krohn as well as several other defendants unrelated to us. In their lawsuit, plaintiffs are alleging that property they own has been contaminated or otherwise damaged byis contesting the defendants’ oil and gas exploration and production activities and are seeking compensatory and punitive damages. We cannot currently estimate our potential exposure, if any, related to this lawsuit. We are currently, and intend to continue, vigorously defending this litigation.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.

Index to Financial Statements

Executive Officers of the Registrant

The following lists our executive officers:

Name

Age (1)

 

Name

Age (1)

Position

Tracy W. Krohn

60

57

Founder, Chairman, Director and Chief Executive Officer

Jamie L. Vazquez

54

51

President

John D. Gibbons

61

58

Senior Vice President and Chief Financial Officer

Thomas P. Murphy

52

Senior Vice President and Chief AccountingOperations Officer

Stephen L. Schroeder

52

49

Senior Vice President and Chief OperatingTechnical Officer

Jesus G. Melendrez

53Senior Vice President and Chief Commercial Officer

Thomas F. Getten

67

64

Vice President, General Counsel and Corporate Secretary

(1)

Ages as of February 23, 2012.2015.

Tracy W. Krohnhas 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 and ResourceLand/Business Development Gulf of Mexico.

John D. Gibbons joined the Company in February 2007 as Senior Vice President and Chief Financial Officer. In September 2007, he assumed the additional position of Chief Accounting 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. Schroederjoined 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.

Jesus G. Melendrez joined the Company in January 2011 as Senior Vice President and Chief Commercial Officer. From 2003 to 2010, Mr. Melendrez worked at Mariner Energy, Inc. and served in a variety of positions of increasing responsibility, culminating as Senior Vice President and Chief Commercial Officer and acting Chief Financial Officer and Treasurer. From February 2000 until July 2003, Mr. Melendrez was a Vice President of Enron North America Corp. in the Energy Capital Resources group, where he managed the group’s portfolio of oil and gas investments.

Thomas F. Gettenjoined 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

Item 4. Mine Safety Disclosures

Not applicable.

Index to Financial Statements

PART II

 

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

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 New York Stock ExchangeNYSE under the symbol “WTI.”“WTI”. The following table sets forth the high and low sales price of our common stock as reported on the New York Stock Exchange.NYSE.

 

High

 

 

Low

 

  High   Low 

2011

    

2014:

 

 

 

 

 

 

 

First Quarter

  $26.12    $17.51  

$

17.33

 

 

$

13.52

 

Second Quarter

   28.79     21.09  

 

19.78

 

 

 

14.00

 

Third Quarter

   29.27     13.74  

 

16.75

 

 

 

10.87

 

Fourth Quarter

   22.86     11.87  

 

11.32

 

 

 

5.34

 

2010

    

2013:

 

 

 

 

 

 

 

First Quarter

  $13.27    $8.15  

 

18.45

 

 

 

14.07

 

Second Quarter

   12.00     8.25  

 

15.86

 

 

 

10.68

 

Third Quarter

   10.83     8.41  

 

18.16

 

 

 

14.23

 

Fourth Quarter

   20.00     10.50  

 

20.43

 

 

 

14.77

 

As of February 23, 2012,March 3, 2015, there were 229199 registered holders of our common stock.

Dividends

Under the Credit Agreement, we are allowed to pay annual dividends of up to $60$60.0 million per year if we are not in default. In addition, the indenture governing our 8.5%8.50% Senior Notes due in 2019 (the “8.5%“8.50% Senior Notes”) contains restrictions on the payment of dividends unless we meet certain restricted payment tests.payments test. SeeManagement’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 andFinancial Statementsand Supplementary Data – Note 7 – Long-Term Debtunder Part II, Item 8 ofin this Form 10-Kfor10-K for more information regarding our Credit Agreement and the indenture governing the 8.5%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):

 

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

 

 

   Aggregate
Dividends on
Common
Stock
   Dividends per
Share of
Common
Stock
 

2011

    

First Quarter

  $2,979    $0.04  

Second Quarter

   2,979     0.04  

Third Quarter

   2,979     0.04  

Fourth Quarter (1)

   49,819     0.67  

2010

    

First Quarter

  $2,240    $0.03  

Second Quarter

   2,241     0.03  

Third Quarter

   2,986     0.04  

Fourth Quarter (2)

   52,142     0.70  

(1)

Includes a regular dividend of $3.0$7.5 million ($0.040.10 per common share) and a special cash dividend of $46.9$31.8 million ($0.630.42 per common share).

(2)Includes a regular dividend of $3.0 million ($0.04 per common share) and a special cash dividend of $49.2 million ($0.66 per common share).

Index to Financial Statements

WithOur Board of Directors decides on the exception of special cash dividends, we currently expect that comparable cash dividends will continue to be paid individend for the future,Company.  Dividends are subject to periodic reviewsreview of the Company’s performance by our board of directorsand the current economic environment and applicable debt agreement restrictions. On February 23, 2012, our boardIn light of directors declared a cash dividendcurrent market conditions, the Board of $0.08 per common share, payable on March 30, 2012Directors has elected to shareholders of record on March 14, 2012.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 current peer group Peer Group #2, is comprised of Apache Corporation, ATP Oil & Gas Corp., Bill Barrett Corp., Cabot Oil & Gas Corp., Comstock Resources, Inc., Energy XXI (Bermuda) Limited, Forest Oil Corp., McMoRan Exploration Co., Newfield Exploration Co., SM Energy Co., SandRidge Energy, Inc., Stone Energy Corp., and Swift Energy Company.

OurForest Oil Corp. merged with another company during December 2014.  Its shares were included in the peer group usedsince the transaction did not occur until near the end of 2014.  

Securities Authorized for Issuance Under 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 and Cash-Based Incentive Compensation under Part II, Item 8 in the prior year, Peer Group #1, was comprised of ATP Oil & Gas Corp., Cabot Oil & Gas Corp., Comstock Resources, Inc., Energy XXI (Bermuda) Limited, Forest Oil Corp., McMoRan Exploration Co., Newfield Exploration Co., Noble Energy, Inc., Plains Exploration & Production Co., Quicksilver Resources Inc., SM Energy Co., Stone Energy Corp., Venoco, Inc., and Whiting Petroleum Corp.

this Form 10-K.

Index to Financial Statements

Issuer Purchases of Equity Securities

For the year 2011,2014, we did not purchase any of our equity securities.

The following table sets forth information about sharesrestricted stock units delivered by employees during the quarter ended December 31, 20112014 to satisfy tax withholding obligations on the vesting of restricted shares.stock units.

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
Shares
Delivered
   Average
Price per
Share
   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, 2011 – October 31, 2011

   N/A     N/A     N/A     N/A  

November 1, 2011 – November 30, 2011

   N/A     N/A     N/A     N/A  

December 1, 2011 – December 31, 2011

   108,714    $19.07     N/A     N/A  

Item 6. Selected Financial Data

Index to Financial Statements
Item 6.Selected Financial Data

SELECTED HISTORICAL FINANCIAL INFORMATION

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

 

  Year Ended December 31, 
  2011 (1)  2010 (2)  2009  2008  2007 
  (Dollars in thousands, except per share data) 

Consolidated Statement of Income (Loss) Information:

  

    

Revenues:

     

Oil

 $643,222   $453,435   $365,411   $622,388   $495,545  

NGLs

  105,559    51,931    35,247    65,709    65,395  

Natural gas

  221,194    203,533    204,758    527,352    552,687  

Other (3)

  1,072    (3,116  5,580    160    122  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total revenues (4)

  971,047    705,783    610,996    1,215,609    1,113,749  

Operating costs and expenses:

     

Lease operating expenses (5)

  219,206    169,670    203,922    229,747    234,758  

Production taxes

  4,275    1,194    1,544    8,827    5,921  

Gathering and transportation

  16,920    16,484    13,619    15,957    15,526  

Depreciation, depletion and amortization

  299,015    268,415    308,076    482,464    510,903  

Asset retirement obligation accretion

  29,771    25,685    34,461    39,312    22,007  

Impairment of oil and natural gas properties (6)

  —      —      218,871    1,182,758    —    

General and administrative expenses

  74,296    53,290    42,990    47,225    38,853  

Derivative (gain) loss

  (1,896  4,256    7,372    16,464    36,532  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total costs and expenses

  641,587    538,994    830,855    2,022,754    864,500  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Operating income (loss)

  329,460    166,789    (219,859  (807,145  249,249  

Interest expense, net of amounts capitalized

  42,516    37,706    40,087    34,709    37,088  

Loss on extinguishment of debt (7)

  22,694    —      2,926    —      2,806  

Other income (8)

  84    710    842    13,372    6,404  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Income (loss) before income tax expense (benefit)

  264,334    129,793    (262,030  (828,482  215,759  

Income tax expense (benefit)

  91,517    11,901    (74,111  (269,663  71,459  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net income (loss)

 $172,817   $117,892   $(187,919 $(558,819 $144,300  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Earnings (loss) per common share

     

Basic and diluted

 $2.29   $1.58   $(2.51 $(7.36 $1.89  

Dividends on common stock (9)

  58,756    59,609    9,158    27,713    39,146  

Cash dividends per common share (9)

  0.79    0.80    0.12    0.36    0.51  

Consolidated Cash Flow Information:

     

Net cash provided by operating activities

 $521,478   $464,772   $156,266   $882,496   $688,597  

Capital expenditures – oil and natural gas properties

  719,026    415,653    276,134    774,879    361,235  

Index to Financial Statements

 

Year Ended December 31,

 

 

2014(1)

 

 

2013(2)

 

 

2012(3)

 

 

2011(4)

 

 

2010(5)

 

 

(In thousands, except per share data)

 

Consolidated Statement of Operations Information:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

$

652,776

 

 

$

718,944

 

 

$

629,548

 

 

$

643,222

 

 

$

453,435

 

NGLs

 

72,837

 

 

 

73,345

 

 

 

84,637

 

 

 

105,559

 

 

 

51,931

 

Natural gas

 

217,816

 

 

 

189,290

 

 

 

158,390

 

 

 

221,194

 

 

 

203,533

 

Other (6)

 

5,279

 

 

 

2,509

 

 

 

1,916

 

 

 

1,072

 

 

 

(3,116

)

Total revenues (7)

 

948,708

 

 

 

984,088

 

 

 

874,491

 

 

 

971,047

 

 

 

705,783

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses (8)

 

264,751

 

 

 

270,839

 

 

 

232,260

 

 

 

219,206

 

 

 

169,670

 

Production taxes

 

7,932

 

 

 

7,135

 

 

 

5,840

 

 

 

4,275

 

 

 

1,194

 

Gathering and transportation

 

19,821

 

 

 

17,510

 

 

 

14,878

 

 

 

16,920

 

 

 

16,484

 

Depreciation, depletion and amortization

 

490,469

 

 

 

430,611

 

 

 

336,177

 

 

 

299,015

 

 

 

268,415

 

Asset retirement obligations accretion

 

20,633

 

 

 

20,918

 

 

 

20,055

 

 

 

29,771

 

 

 

25,685

 

General and administrative expenses

 

86,999

 

 

 

81,874

 

 

 

82,017

 

 

 

74,296

 

 

 

53,290

 

Derivative (gain) loss

 

(3,965

)

 

 

8,470

 

 

 

13,954

 

 

 

(1,896

)

 

 

4,256

 

Total costs and expenses

 

886,640

 

 

 

837,357

 

 

 

705,181

 

 

 

641,587

 

 

 

538,994

 

Operating income

 

62,068

 

 

 

146,731

 

 

 

169,310

 

 

 

329,460

 

 

 

166,789

 

Interest expense, net of amounts capitalized

 

78,396

 

 

 

75,581

 

 

 

49,994

 

 

 

42,516

 

 

 

37,706

 

Loss on extinguishment of debt (9)

 

 

 

 

 

 

 

 

 

 

22,694

 

 

 

 

Other income, net (10)

 

208

 

 

 

8,946

 

 

 

215

 

 

 

84

 

 

 

710

 

Income (loss) before income tax expense

   (benefit)

 

(16,120

)

 

 

80,096

 

 

 

119,531

 

 

 

264,334

 

 

 

129,793

 

Income tax expense (benefit)

 

(4,459

)

 

 

28,774

 

 

 

47,547

 

 

 

91,517

 

 

 

11,901

 

Net income (loss)

$

(11,661

)

 

$

51,322

 

 

$

71,984

 

 

$

172,817

 

 

$

117,892

 

 

Basic and diluted earnings (loss) per common share

$

(0.16

)

 

$

0.68

 

 

$

0.95

 

 

$

2.29

 

 

$

1.58

 

Dividends on common stock (11)

 

30,260

 

 

 

58,846

 

 

 

82,832

 

 

 

58,756

 

 

 

59,609

 

Cash dividends per common share

 

0.40

 

 

 

0.78

 

 

 

1.11

 

 

 

0.79

 

 

 

0.80

 

 

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

 

 

   December 31, 
   2011   2010   2009   2008   2007 
   (Dollars in thousands) 

Consolidated Balance Sheet Information:

          

Cash and cash equivalents

  $4,512    $28,655    $38,187    $357,552    $314,050  

Total assets

   1,868,925     1,424,094     1,326,833     2,056,186     2,812,204  

Long-term debt

   717,000     450,000     450,000     653,172     654,764  

Shareholders’ equity

   544,574     421,743     358,950     572,227     1,151,340  

 

 

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)

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 Properties that we did not already own.

(2)

In the fourth quarter of 2013, we acquired the Callon Properties from Callon.

(3)

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

(4)

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

(2)

(5)

In the second quarter of 2010, we acquired the Matterhorn/Virgo Propertiescertain properties from Total E&P and, in the fourth quarter of 2010, we acquired the Tahoe/Droshky Propertiescertain properties from Shell.

(3)

(6)

Included in other revenues for 2010 is a reduction of $4.7 million due to a disallowance by the ONRR of royalty relief for transportation of deepwater production through our subsea pipeline system that was originally recorded in 2009.We2009. We are contesting this ONRR adjustment.

(4)

(7)

Included in total revenues for 2010 is $24.9 million related to the recoupment of royalties paid to the ONRR in prior periods based on price thresholds that were believed to limit the availability of royalty relief on certain properties subject to the OCS Deepwater Relief Act of 1995.

(5)

(8)

Included in lease operating expenses are net charges to expense for hurricane-related repairs netted withnet of insurance reimbursements. For the yearsyear 2010, 2009, 2008 and 2007, the impact to lease operating expenses attributable to net hurricane – related–related expenses/reimbursements werewas an $11.7 million decrease, $18.4 million increase, $17.7 million increase and $18.5 million increase, respectively, and theredecrease. There was no suchminimal impact to lease operating expenses in 2011.

(6)The carrying amount of our oil and natural gas properties was written down by $218.9 million in 2009 and $1.2 billion in 2008 through the application of the full cost ceiling limitation due to lower oil and natural gas prices. No such write downs were required during the other years presented.

(7)

(9)

In 2011, we expensed repurchase premiums, deferred financing costs and other costs totaling $22.0 million related to the repurchase of $450.0 million in aggregate principal amount of our 8.25% Senior Notes due 2014 (the “8.25% Senior Notes”) and expensed $0.7 million of deferred financing costs related to replacement of our revolving bank credit facility. In 2009, we expensed $2.9 million of deferred financing costs related to the early repayment of our previously outstanding term loan facility (“Tranche B”). In 2007, we expensed $2.8 million of deferred financing costs related to the early repayment of our Tranche A term loan.2014.

(8)

(10)

Consists

In 2013, other income consisted primarily of interest income.payments received in conjunction with an option exercised by a counterparty.

(9)

(11)

The years 2013, 2012, 2011 and 2010 2008 and 2007 includeincluded special dividends of $31.8 million ($0.42 per share), $59.0 million ($0.79 per share), $46.9 million ($0.63 per share), and $49.2 million ($0.66 per share), $20.8 million ($0.39 per share) and $30.0 million ($0.27 per share), respectively.  The year 2009 does not include aNo special dividend.dividends were paid in 2014.



Index to Financial Statements

HISTORICAL RESERVE AND OPERATING INFORMATION

The following presents summary information regarding our estimated net proved oil, NGLs and natural gas reserves and our historical operating data for the years shown below. All calculations of estimatedEstimated net proved reserves have been madeare 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 the rules and regulations of the SEC and give no effect to federal or state income taxes.guidelines.  For additional information regarding our estimated proved reserves, please readBusinessunder Part I, Item 1and1 and Propertiesunder Part I, Item 2 of thethis Form 10-K.10-K. The selected historical operating data set forth below should be read in conjunction withManagement’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and withFinancial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K.

 

   December 31, 
   2011  2010  2009  2008  2007 

Reserve Data:

      

Estimated net proved reserves (1) (2):

      

Oil (MMBbls)

   51.4    34.0    31.2    40.0    46.4  

NGLs (MMBbls)

   17.1    4.2    3.0    3.9    4.6  

Natural gas (Bcf)

   289.7    256.3    165.8    227.9    332.8  

Total oil equivalent (MMBoe)

   116.9    80.9    61.8    81.9    106.5  

Total natural gas equivalent (Bcfe)

   701.1    485.4    371.0    491.1    638.8  

Proved developed producing (Bcfe)

   325.8    236.6    162.5    148.6    224.1  

Proved developed non-producing (Bcfe) (3)

   132.4    154.7    121.0    185.5    171.2  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total proved developed (Bcfe)

   458.2    391.3    283.5    334.1    395.3  

Proved undeveloped (Bcfe)

   242.9    94.1    87.5    157.0    243.5  

Proved developed reserves as a percentage of proved reserves

   65.4  80.6  76.4  68.0  61.9

Reserve additions (reductions) (Bcfe):

      

Revisions (4)

   51.1    20.2    (25.4  (157.5  (18.7

Extensions and discoveries

   32.0    29.2    23.4    47.2    48.4  

Purchases of minerals in place

   234.1    152.0    0.7    60.5    1.4  

Sales of minerals in place

   —      —      (24.0  —      (1.0

Production

   (101.5  (87.0  (94.8  (97.9  (126.5
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net reserve additions (reductions)

   215.7    114.4    (120.1  (147.7  (96.4
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 

December 31,

 

 

2014

 

 

2013

 

 

2012

 

 

2011

 

 

2010

 

Reserve Data: (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Estimated net proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MMBbls)

 

61.7

 

 

 

58.5

 

 

 

54.8

 

 

 

51.4

 

 

 

34.0

 

NGLs  (MMBbls)

 

15.8

 

 

 

15.9

 

 

 

15.2

 

 

 

17.1

 

 

 

4.2

 

Natural Gas (Bcf)

 

254.9

 

 

 

259.9

 

 

 

285.1

 

 

 

289.7

 

 

 

256.3

 

Total barrel equivalents (MMBoe)

 

120.0

 

 

 

117.7

 

 

 

117.5

 

 

 

116.9

 

 

 

80.9

 

Total natural gas equivalents (Bcfe)

 

720.0

 

 

 

705.9

 

 

 

705.1

 

 

 

701.1

 

 

 

485.4

 

 

Proved developed producing (MMBoe)

 

68.7

 

 

 

60.6

 

 

 

62.6

 

 

 

54.3

 

 

 

39.4

 

Proved developed non-producing (MMBoe) (2)

 

14.6

 

 

 

25.5

 

 

 

24.3

 

 

 

22.1

 

 

 

25.8

 

Total proved developed (MMBoe)

 

83.3

 

 

 

86.1

 

 

 

86.9

 

 

 

76.4

 

 

 

65.2

 

 

Proved undeveloped (MMBoe)

 

36.7

 

 

 

31.6

 

 

 

30.6

 

 

 

40.5

 

 

 

15.7

 

Proved developed reserves as %

 

69.4

%

 

 

73.2

%

 

 

74.0

%

 

 

65.4

%

 

 

80.6

%

 

Reserve additions (reductions) (MMBoe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revisions

 

4.1

 

 

 

(3.9

)

 

 

(4.7

)

 

 

8.6

 

 

 

3.4

 

Extensions and discoveries

 

9.7

 

 

 

20.2

 

 

 

15.8

 

 

 

5.3

 

 

 

4.9

 

Purchases of minerals in place

 

6.1

 

 

 

2.4

 

 

 

7.0

 

 

 

39.0

 

 

 

25.3

 

Sales of minerals in place

 

 

 

 

(0.5

)

 

 

(0.4

)

 

 

 

 

 

 

Production

 

(17.6

)

 

 

(18.0

)

 

 

(17.1

)

 

 

(16.9

)

 

 

(14.5

)

Net reserve additions

 

2.3

 

 

 

0.2

 

 

 

0.6

 

 

 

36.0

 

 

 

19.1

 

(1)

Estimated reserves as

The conversions to barrels of December 31, 2011, 2010oil equivalent and 2009 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. Estimated reserves as of December 31, 2008 and 2007 are based on end-of-period commodity prices in accordance with the previous SEC guidelines in effect on those respective dates.

(2)Bcfe and MMBoe arecubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding).  The conversion ratio does not assume price equivalency, and the price per Mcfeon an equivalent basis for oil, NGLs and natural gas liquids may differ significantly from the price per Mcf for natural gas. Similarly, the price per Bbl for oil for may differ significantly from the price per Bbl for NGLs..

(3)

(2)

Approximately 29.6 Bcfe1.4 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) due to a platform and pipeline outage.  Approximately 4.9 MMBoe of reserves were shut-inshut in at December 31, 2010 due to two pipeline outages impacting several fields, including our Main Pass 108 field.  Approximately 1.7 Bcfe and 53.9 Bcfe of reserves were shut-in at December 31, 2009 and 2008, respectively, because of damage caused by Hurricane Ike in September 2008.

(4)

Volume measurements:

Revisions for 2009 included decreases attributable

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,

 

 

2014

 

 

2013(1)

 

 

2012

 

 

2011

 

 

2010

 

Operating: (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

7,176

 

 

 

7,018

 

 

 

6,033

 

 

 

6,073

 

 

 

5,863

 

NGLs (MBbls)

 

2,112

 

 

 

2,091

 

 

 

2,129

 

 

 

1,892

 

 

 

1,190

 

Oil and NGLs (MBbls)

 

9,288

 

 

 

9,110

 

 

 

8,163

 

 

 

7,964

 

 

 

7,053

 

Natural gas (MMcf)

 

50,088

 

 

 

53,257

 

 

 

53,825

 

 

 

53,743

 

 

 

44,713

 

Total oil equivalent (MBoe)

 

17,636

 

 

 

17,986

 

 

 

17,133

 

 

 

16,921

 

 

 

14,505

 

Total natural gas equivalents (MMcfe)

 

105,815

 

 

 

107,915

 

 

 

102,800

 

 

 

101,528

 

 

 

87,032

 

 

Average daily equivalent sales (Boe/day)

 

48,317

 

 

 

49,276

 

 

 

46,813

 

 

 

46,360

 

 

 

39,741

 

Average daily equivalent sales (Mcfe/day)

 

289,904

 

 

 

295,657

 

 

 

280,875

 

 

 

278,158

 

 

 

238,445

 

 

Average realized sales prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/Bbl)

$

90.96

 

 

$

102.44

 

 

$

104.35

 

 

$

105.92

 

 

$

77.33

 

NGLs ($/Bbl)

 

34.49

 

 

 

35.07

 

 

 

39.75

 

 

 

55.81

 

 

 

43.65

 

Oil and NGLs ($/Bbl)

 

78.13

 

 

 

86.97

 

 

 

87.50

 

 

 

94.02

 

 

 

71.65

 

Natural gas ($/Mcf)

 

4.35

 

 

 

3.55

 

 

 

2.94

 

 

 

4.12

 

 

 

4.55

 

Oil equivalent ($/Boe)

 

53.49

 

 

 

54.58

 

 

 

50.93

 

 

 

57.32

 

 

 

48.87

 

Natural gas equivalent ($/Mcfe)

 

8.92

 

 

 

9.10

 

 

 

8.49

 

 

 

9.55

 

 

 

8.15

 

 

Average per Boe ($/Boe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

$

15.01

 

 

$

15.06

 

 

$

13.56

 

 

$

12.95

 

 

$

11.70

 

Gathering and transportation

 

1.14

 

 

 

0.95

 

 

 

0.85

 

 

 

1.01

 

 

 

1.16

 

Production costs

 

16.15

 

 

 

16.01

 

 

 

14.41

 

 

 

13.96

 

 

 

12.86

 

Production taxes

 

0.42

 

 

 

0.42

 

 

 

0.36

 

 

 

0.24

 

 

 

0.06

 

DD&A

 

28.98

 

 

 

25.10

 

 

 

20.79

 

 

 

19.43

 

 

 

20.28

 

General and administrative expenses

 

4.93

 

 

 

4.55

 

 

 

4.79

 

 

 

4.39

 

 

 

3.67

 

 

$

50.48

 

 

$

46.08

 

 

$

40.35

 

 

$

38.02

 

 

$

36.87

 

 

Average per Mcfe ($/Mcfe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

$

2.50

 

 

$

2.51

 

 

$

2.26

 

 

$

2.16

 

 

$

1.95

 

Gathering and transportation

 

0.19

 

 

 

0.16

 

 

 

0.14

 

 

 

0.17

 

 

 

0.19

 

Production costs

 

2.69

 

 

 

2.67

 

 

 

2.40

 

 

 

2.33

 

 

 

2.14

 

Production taxes

 

0.07

 

 

 

0.07

 

 

 

0.06

 

 

 

0.04

 

 

 

0.01

 

DD&A

 

4.83

 

 

 

4.18

 

 

 

3.47

 

 

 

3.24

 

 

 

3.38

 

General and administrative expenses

 

0.82

 

 

 

0.76

 

 

 

0.80

 

 

 

0.73

 

 

 

0.61

 

 

$

8.41

 

 

$

7.68

 

 

$

6.73

 

 

$

6.34

 

 

$

6.14

 

Wells drilled (gross):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

6

 

 

 

6

 

 

 

5

 

 

 

8

 

 

 

7

 

Onshore

 

33

 

 

 

40

 

 

 

77

 

 

 

40

 

 

 

2

 

Productive wells drilled (gross)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Offshore

 

6

 

 

 

5

 

 

 

4

 

 

 

8

 

 

 

6

 

Onshore

 

33

 

 

 

40

 

 

 

77

 

 

 

39

 

 

 

 

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 changesfederal 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 reserve reporting requirements2013.  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 Bbl 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 companies enacted by the SEC, which became effectivemay differ significantly.

Volume measurements:

Bbl – barrel

Mcf – thousand cubic feet

Boe – barrel of oil equivalent

MMcf – million cubic feet

MBbls – thousand barrels for us on December 31, 2009. The revised rules resulted in the removalcrude oil, condensate or NGLs

MMcfe – million cubic feet equivalent

MBoe – thousand barrels of 23.2 Bcfe of proved undeveloped reserves associated with two of our fields for which our plan of development was not within five years from when the reserves were initially recorded.oil equivalent

Index to Financial Statements

 

   Year Ended December 31, 
   2011   2010   2009   2008   2007 

Operating Data:

          

Net sales:

          

Oil (MMBbls)

   6.1     5.9     6.1     5.9     6.9  

NGLs (MMBbls)

   1.9     1.2     1.1     1.1     1.4  

Oil and NGLs (MMBbls)

   8.0     7.1     7.2     7.0     8.3  

Natural gas (Bcf)

   53.7     44.7     51.6     56.1     76.7  

Total oil equivalent (MMBoe)

   16.9     14.5     15.8     16.3     21.1  

Total natural gas equivalent (Bcfe)

   101.5     87.0     94.8     97.9     126.5  

Average daily equivalent sales (MBoe/d)

   46.4     39.7     43.3     44.6     57.8  

Average daily equivalent sales (MMcfe/d)

   278.2     238.4     259.7     267.5     346.7  

Average realized sales prices (Unhedged):

          

Oil ($/Bbl)

  $105.92    $77.33    $59.96    $105.74    $71.89  

NGLs ($/Bbl)

   55.81     43.65     31.96     60.62     46.45  

Oil and NGLs ($/Bbl)

   94.02     71.65     55.67     98.72     67.58  

Natural gas ($/Mcf)

   4.12     4.55     3.97     9.40     7.20  

Oil equivalent ($/Boe)

   57.32     48.87     38.32     74.50     52.81  

Natural gas equivalent ($/Mcfe)

   9.55     8.15     6.39     12.42     8.80  

Average realized sales prices (Hedged) (1):

          

Oil ($/Bbl)

  $104.30    $77.05    $59.96    $100.94    $71.20  

NGLs ($/Bbl)

   55.81     43.65     31.96     60.62     46.45  

Oil and NGLs ($/Bbl)

   92.78     71.42     55.67     94.67     67.01  

Natural gas ($/Mcf)

   4.12     4.71     3.96     9.42     7.28  

Oil equivalent ($/Boe)

   56.74     49.25     38.30     72.82     52.87  

Natural gas equivalent ($/Mcfe)

   9.46     8.21     6.38     12.14     8.81  

Average per Mcfe ($/Mcfe):

          

Lease operating expenses

  $2.16    $1.95    $2.15    $2.35    $1.86  

Gathering and transportation costs

   0.17     0.19     0.14     0.16     0.12  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Production costs

   2.33     2.14     2.29     2.51     1.98  

Production taxes

   0.04     0.01     0.02     0.09     0.05  

Depreciation, depletion, amortization and accretion

   3.24     3.38     3.61     5.33     4.21  

General and administrative expenses

   0.73     0.61     0.45     0.48     0.31  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $6.34    $6.14    $6.37    $8.41    $6.55  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total number of wells drilled (gross):

          

Offshore

   8     7     13     25     9  

Onshore

   40     2     —       —       —    

Total number of productive wells drilled (gross):

          

Offshore

   8     6     10     19     8  

Onshore

   39     —       —       —       —    

DD&A - depreciation, depletion, amortization and accretion


 

(1)Data for all years presented includes the effects of realized gains and losses on commodity derivative contracts, none of which qualified for hedge accounting.

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

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

The following discussion and analysis should be read in conjunction withFinancial Statements and Supplementary Data under Part II, Item 8 ofin this Form 10-K.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.10-K, particularly in Risk Factors

under Part I, Item 1A in this Form 10-K

Index to Financial Statements

Overview

We are an independent oil and natural gas producer focused primarilywith operations offshore in the Gulf of Mexico and onshore in the Permian Basin of West Texas.  We have grown through acquisitions, exploration and development and currently hold working interests in approximately 58 producing and two capable of producing63 offshore fields in federal and state waters. During 2011, we expanded onshore into West Texaswaters (61 producing and East Texas through an acquisition and acquiring interests in leasehold acreage.two fields capable of producing).  We currently have interests in offshore leases coveringunder lease approximately 0.81.2 million gross acres, (0.5 million net acres) spanning primarily across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama and 0.2including approximately 0.6 million gross acres (0.2on the Gulf of Mexico Shelf, approximately 0.5 million net acres)gross acres in the deepwater and approximately 50,000 gross acres onshore, primarily in Texas.  A substantial majority of our daily production is derived from wells we operate offshore. We operate wells accounting for approximately 80%87% of our average daily production. We own interests in approximately 253203 offshore structures, 158138 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-own subsidiary, W & T Energy VI, LLC.

In managing our business, we are concerned primarily with maximizing return on shareholders’ equity. To accomplish this primary goal, we focus on increasing production and reserves at a profit. We strive to grow our reserves and production through acquisitions and our drilling programs. 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.

During the year 2011,In September 2014, we closed on two acquisition transactions. On May 11, 2011, we completed the acquisition from Opal of the Yellow Rose Properties, which consists of approximately 24,500 gross acres (21,900 net acres) of oil and gas leasehold interestsacquired an additional ownership interest in the Permian BasinFairway Field (Mobile Bay blocks 113 and 132 located offshore Alabama) and the associated Yellowhammer gas processing plant, which increased our ownership interest from 64.3% to 100%.  Internal estimates of West Texas. Based on internal estimates,additional proved reserves associated with the Yellow Rose Propertiesincreased ownership interest in the Fairway Field as of the acquisition date were approximately 30.14.4 MMBoe (180.4(26.4 Bcfe), comprised of approximately 69% oil, 22%26% NGLs and 9%74% natural gas, and approximately 70%all of which were classified as proved undeveloped. The stated purchase price was $366.3 million, subject to certain adjustments, includingdeveloped.  Including adjustments from an effective date of JanuaryJuly 1, 2011 until the closing date of May 11, 2011. Taking into account such adjustments,2014, the adjusted purchase price was $394.4 million. The increase of $28.1$17.4 million primarily reflects drilling and development costs in excess of cash flow from the effective date of January 1, 2011 to the closing date. Wewe assumed the additional ARO associated with the increased ownership interest in Fairway, which we have estimated to be $0.4 million, and recorded a long-term liability of $2.1 million. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.

On August 10, 2011, we completed the acquisition of the Fairway Properties, which consist of Shell’s 64.3% working interest in the Fairway Field along with a like interest in the associated Yellowhammer gas treatment plant. Based on internal estimates, proved reserves associated with the Fairway field as of the acquisition date were 8.9 MBoe (53.5 Bcfe) comprised of approximately 72% natural gas, 27% NGLs and less than 1% oil and which are 100% proved developed. The stated purchase price was $55.0 million, subject to certain adjustments, including adjustments from an effective date of September 1, 2010 until the closing date. Taking into account such adjustments, as of December 31, 2011, the purchase price was reduced to $42.9 million. The decrease of $12.1 million primarily reflects net production cash flow, partially offset by plugging and abandonment and other operating costs incurred, from the effective date of September 1, 2010 to the closing date. The purchase price is subject to further post-effective date adjustments and final settlement is expected to occur in the first half of 2012. We assumed the ARO associated with the properties and plant, which we have estimated to be $7.8$6.1 million. The acquisition was funded from borrowings under our revolving bank credit facility.facility and cash on hand.

During the year 2010, we closed on two acquisition transactions. The first was on April 30, 2010, whenIn 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 Total’s interest, including production platformswhich were classified as proved developed.   Including adjustments from an effective date of November 1, 2013, the adjusted purchase price was $54.8 million and facilities, in three federal offshore lease blocks locatedwe 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.  EstimatesThe 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.

51


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 10.9 MBoe (65.6approximately 7.0 MMBoe (42.0 Bcfe), comprised of approximately 58%36% oil, 6%3% NGLs and 36%61% natural gas, andall of which are 69%were classified as proved developed. TheIncluding adjustments from an effective date of July 1, 2012, the adjusted purchase price was $121.3$205.8 million inclusive ofand we assumed the ARO associated with the Newfield Properties, which we have estimated at $6.3to be $31.7 million. The acquisition was initially funded withfrom borrowings under our revolving bank credit facility and cash on hand.

Index to Financial Statements

The second acquisition in 2010 was on November 3, 2010, when we acquired all of Shell’s interests, including production platforms and facilities, in three federal offshore lease blocks located Subsequently in the Gulfsame month, the amounts borrowed under our revolving bank credit facility were paid down with funds provided from the issuance of Mexico. Estimatesan additional $300.0 million of proved reserves as of the acquisition date were 13.3 MBoe (80.0 Bcfe) comprised of approximately 8% oil, zero NGLs8.50% Senior Notes.

See Financial Statements and 92% natural gas and which are 100% proved developed. The adjusted purchase price was $134.2 million inclusive of the ARO estimated at $18.0 million. The acquisition was funded with cash on hand.

SeeFinancial StatementsSupplementary Data – Note 2 – Acquisitions and Divestitures under Part II, Item 8 ofin this Form 10-K for additional information on acquisitions.

From time to time, as part of our business strategy, we sell various properties that we consider non-core assets. We did not sell any properties in 2011 and 2010. We are currently marketing a package of non-core properties located on the OCS.

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 20112014 were comprised of approximately 36%41% oil and condensate, 11%12% NGLs and 53%47% natural gas, determined using the energy-equivalent ratio of six Mcf of natural gas to one Bblbarrel of crude oil, condensate or NGLs. The conversionenergy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices per Mcfe for oil, NGLs and natural gas may differ significantly. For 2011,2014, our combined total production of oil, NGLs and natural gas was approximately 16.7% higherconsistent with 2013, as we had new production from recently drilled wells and acquisitions, 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 a Mcfe basis than during the same period in 2010.

line along with production from acquisitions.  The third-party pipeline used by our Main Pass 108 and 98 fieldsyear 2013 was shut down from June 2010 to March 2011. This impacted our production in 2011 and in 2010. By the end of the second quarter of 2011, production had been restored and has been positivelyalso negatively impacted by various workoverpipeline 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.

Our realized 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, WTI and Brent crude oil prices averaged above $100 per barrel.  In fact, crude oil prices have averaged over $90 per barrel for WTI and $100 per barrel for Brent for the last four years.  This in turn has led to significant field work, which included drilling both an exploration wellcost inflation in the oil and three development wells. Ingas services industry.  Crude oil prices have fallen dramatically recently from a peak of $107 per barrel for WTI in June 2014 to the low $50s per barrel in December 2011, these fields produced2014 and the mid $40s per barrel during January 2015.  The current market imbalance is predominantly supply driven caused by a number of issues that are described below:

The U.S. Energy Information Administration’s (“EIA”) data estimates the worldwide supply of crude oil will outpace consumption in 2014 by approximately 33.4 MMcfe800,000 barrels per day.  For 2015 and 2016, EIA forecasts crude oil supply being above consumption by approximately 600,000 and 100,000 barrels per day, made uprespectively, 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 815 BblsOPEC grew at a record high of oil2.0 million barrels per day 538 Bblsover 2013, of NGLswhich the U.S. grew production 1.6 million barrels per day and 25.3 MMcfCanada 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 natural gasthe 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.day, respectively, and estimates Canada’s petroleum and other liquids production for 2014, 2015 and 2016 to be 4.4, 4.5 and 4.7 million barrels per day, respectively.  The increasing strength 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.

52


While the expectations 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 consumption in the next two years due to an economic downturn.  Based on the above, crude oil supply is expected by many commentators to exceed demand over the next two years.  Accordingly, we expect that prices will continue to stay depressed until such time as demand grows to meet supply or depressed prices drive producers to cut back production.

In addition to U.S. crude oil production, another factor affecting 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 built 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.  Both of these events have helped relieve the excess crude oil that built up in Cushing, which in turn allowed WTI pricing to increase relative to Brent. Up to 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 2014 and the average spread for December 2014 was $3.04 per barrel.

During 2011,2014, our average realized oil sales price was 11.2% lower than that realized in 2013.  Our average realized oil sales price percentage decrease for 2014 was lower than the crude oil benchmark WTI due to the reduction in our offshore crude oil premiums 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 2014 and have fallen further thus far in 2015.  In December 2014 and January 2015, WTI average prices were volatile$59.29 and increased significantly compared$47.22, respectively.  WTI is frequently used to 2010. Thevalue domestically produced crude oil, and the majority of our oil production is priced using the posted spot price for West Texas Intermediate (“WTI”)WTI as a base price, plus a premium depending onthen adjusted for the type and quality of crude oil. WTI is frequently usedoil and other factors.  In addition, beginning in the fourth quarter of 2013 and continuing through 2014, the premiums for the Gulf of Mexico crude oil have declined to value domestically producedvirtually be at parity with one another as the crude oil. Mostbeing moved to the U.S. Gulf Coast increased and imports continued.  Over 85% of our oil production is produced from our offshore oil production, whichin the Gulf of Mexico and is comprised of various crudes includingcharacterized as Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”), Poseidon and Poseidon. Starting inothers.  For example, the first quarter of 2011monthly average premiums to WTI for LLS, HLS and continuing through the end of 2011, these various crudes sold atPoseidon for 2014 were $3.88, $3.52 and a significant premium relative to WTI. In 2011negative $1.20 per barrel, respectively, compared to 2010, our realized oil sales price (unhedged) increased 37.0%, compared to a 19.4% increase in the unweighted average daily posted spot price$11.06, $11.02 and $5.58 per barrel, respectively, for WTI. The majority of our crude prices2013.  Permian Basin crudes also have correlated closer to the international oil market prices, as measured using the unweighted average daily posted spot price for Brent crude, which increased 39.8% in 2011.

The premiums received on our offshore oil production have been up to $30.00 per Bbl during times in 2011. In comparison, the average premium spread between Heavy Louisiana Sweet crude and WTI crude was approximately $2.00 per Bbl during 2010 and the average premium spread between Light Louisiana Sweet crude and WTI crude was approximately $3.00 per Bbl during 2010. According to industry sources, the correlation between North Sea Brent crude oil and WTI, the crude that trades on the New York Mercantile Exchange (“NYMEX”), had historically been extremely high. In fact, in the past, Brent crude oil has traded at a discount to WTI (at times the discount has been significant) in much of 2014 as Brent crudesupply 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 the oil is trucked due to lack of pipeline access.  

Our average realized NGLs sales prices decreased 1.7% during 2014 versus 2013.  Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel.  During 2014, average prices for domestic ethane increased 2% and average domestic propane prices increased 4% from the comparable 2013 period.  Average price changes for other domestic NGLs ranged from a lower quality relativedecrease of 13% to WTI. Ina decrease of 7%, which caused the middleaverage realized NGLs sales price to decline.  Colder weather was a major factor for the increase of November of 2011, that correlation between the two crudes had fallen to its lowest level in twenty years. At the beginning of 2011, the price of crude oil at Cushing, Oklahoma,propane during the winter months of 2014; however, propane prices were below 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 whereextracted from natural gas.  Once the NYMEX WTI crude is priced, was pressured by an over supply situation. Oncold weather passed, ethane prices declined to pre-winter pricing and prices for the other hand, Brentbalance of 2014 were below the comparable 2013 period.  Similar to propane, ethane prices for December 2014 fell dramatically and were aided by supply disruptions due to unrest38% below the 2014 average.  The decreases in the Middle East and oil production was halted in Libya. Since that time, the turmoil in Europe reduced oil demand and Libya’s oil production is returning. In addition, the announced reversalprices of the Seaway pipeline that has taken crude oil from the Gulf Coast to Cushing will begin flowing crude oil in Cushing to the Gulf Coast beginning in mid-2012. The

Index to Financial Statements

price spread between Brent crude oil and WTI narrowed significantly onnatural gas have affected the dayprices of this announcement. More recently, both WTI and BrentNGLs.  As long as U.S. crude oil prices have increased with threats by Iran of closing the Strait of Hormuzand natural gas production remain high and the implicationsprice ratio of significantly reducing crude oil supplied fromto natural gas remains wide (as measured on a six to one energy equivalency), the region. If economic growth continuesproduction of NGLs may continue to be high relative to historical norms and would, in China, India, Brazil and Russia, such activity will support strong crude oil prices. Also supporting higher prices is the fact that economic deterioration in the US and other countries has forced countries to adopt potentially inflationary policies which may raiseturn, suggest continued downward price pressure on the price of hard assets like crude oilethane.  Many natural gas processing facilities have been and gold.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.

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According to EIA, prices for natural gas at Henry Hub (the primary U.S. price benchmark) were 17% higher 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.  Natural gas prices are much 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.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 likely to continue according to many commentators. During 2011,2014, our average realized sales price increased 22.5% to $4.35 per Mcf from 2013.  During December 2014, natural gas prices have fallen and the Henry Hub average price was 20% below the average price for 2014.  

Although the average price of natural gas (unhedged) decreased 9.5%increased during 2014 on a percentage basis, it is still weak from 2010 compared to the benchmark Henry Hub unweighted average daily posted spot price, which decreased 8.5% from 2010. Wean overall economic standpoint, and we expect continued weakness in natural gas prices at least through 2012 asfor a number of reasons, including (i) producers continuecontinuing to drill in order to secure and to hold leases,large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas storage levels continue at record highs, winter weather continuescontinuing to be relatively mild,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 a by product of the substantial ramp up of oil drilling continues andexplained below), (iii) production efficiency gains arebeing achieved in the shale gas areas resulting from better fracking techniques. Potential mitigating factors could include an increasehydraulic fracturing, horizontal drilling, pad drilling and production techniques and (iv) 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 demand if the United States experiences a strong economic recovery, a dramatic decrease in drilling activity, including horizontal oil well drilling, (which isn’t likely at current high oil prices) or production shut-ins2014 and forecasts $3.55 and $3.98 per Mcf for 2015 and 2016, respectively.  Many research analysts are projecting that natural gas prices will be lower than this forecast by EIA primarily due to economic factors. growth in natural gas supplies. EIA projects U.S. supply to be higher than consumption for both 2015 and 2016.  

According to Baker Hughes, data,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 2013 and decreased further to 328 at the end of December 2014.  The natural gas rig count was at a 21 year low during 2014.  As of mid-February, 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 drillingsearching for oil has more than tripled sinceincreasing from 1,318 at the beginning of 2009. There2013 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.  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 of the end of December 2014.  EIA estimates the percentage of electricity fueled by natural gas to be 27% for 2014, and forecasts the percentage at 28% for both 2015 and 2016, influenced largely by the expected price of natural gas compared to the expected price 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 also a risk that,expected to continue to increase as a result of successful explorationthe announced petrochemical facilities are constructed and development activities in the shale areas coupled with the availability of increasing amounts ofpower producers convert to consuming natural gas to reduce emissions to ever tighter emission regulations and standards.  Several companies are currently building or are planning to build liquefaction capacity to export liquefied natural gas increased supplies of natural gas will offset or mitigate the impact of any natural gas shut-ins or demand increases resulting from improved economic conditions. Accordingdue to industry sources, use of directed horizontal drilling rigs is at record levels and is up over 20% in January 2012 compared to January 2011, while the total oil rig count is up over 50% in January 2012 compared to January 2011.

In 2011 and 2010, we did not incur an impairment write-down. Due to declines in oil, NGL andsignificantly higher natural gas prices in 2009 we recorded an impairment write-downEurope and Asia.

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 $218.9approximately $630 million as determined throughand $636 million, respectively.  The plan for 2015 reflects the application ofsignificantly 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 ceiling test.

Should pricesrecent price decline forin oil and natural gas in the future,continue, it would negatively impact our future oil, NGL and natural gas revenues, earnings and liquidity, would be negatively impacted, and could result incause impairment write-downs of the carrying value of our oil and natural gas properties. This decline couldproperties, reduce proved reserves, create issues with financial ratio compliance, and could result inlead to a reduction of the borrowing base associated with our credit agreement,Credit Agreement, depending on the longevity and severity of such declines. Ifprice weakness.  As required by the full cost accounting rules, we performed our ceiling test calculation as of December 31, 2014 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 was $91.12 per barrel for crude oil and $4.27 per Mcf for natural gas.  (For reference, the prices at the end of the year 2014 for those factorstwo products were $53.45 per barrel for crude oil and $3.23 per Mcf for natural gas, respectively.)  Based on the results of the SEC required calculation, we were not required to occur and were significant,record a write-down of the willingnesscarrying value of financial institutions and investors to provide capital to us and others in theour oil and natural gas industryproperties at December 31, 2014.  We are required to perform 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, see  Risk Factors - Risks Related to Financing under Part I, Item 1A and in the future could be impacted.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.            

Our operating costs include the expense of operating our wells, platforms and other infrastructure primarily in the Gulf of Mexico and Texas and transporting our production to the pointpoints of sale.  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.

Revenue   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 production is highly dependent on pipelines owned by othersSpraberry field (Yellow Rose) operations more workover activity has been performed due to access markets for our products. To the extent that the transportation price such pipelines charge increases, our revenues from the sales of our products would go down or transportation costs would increase, the result of either would be a reduction in operating income. Certain pipelines have filed tariffs which may increase the amounts charged to us and we believe that we have limited alternatives to use other pipelines. The approval process typically results in approval of fees less than those contained in the filing requests; therefore, at this time, we are unable to determine whether or when the rates may ultimately be increased and are unable to estimate the impact to operating income in 2012.expanded well count.

Index to Financial Statements

In recent years, we acquired and built platforms near the outer edge of the continental shelf and operated wells in the deepwater of the Gulf of Mexico. To the extent we continue our deepwater operations, our operating costs will likely increase.increase, especially as we find and produce more crude oil rather than natural gas. While each field can present operating problems 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 we obtain insurance to reduce, but not totally mitigate, our financial exposure risk.  We incurred substantial costs from 2008 through 2011 for hurricane related damage occurring in 2008 and expect to incur costs through 2013 to complete plugging and abandonment work primarily related to three toppled platforms. We received reimbursements from our insurance carrier in each of the last three years and expect to receive additional reimbursements for covered costs incurred in future periods as covered costs incurred to date have not exceeded policy limits. SeeLiquidity and Capital Resourcesbelow - Hurricane Remediation, Insurance Claims and Insurance Coverage under this Item 7 and Financial Statementsand Supplementary Data – Note 318Hurricane Remediation and Insurance ClaimsContingencies 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. The costs 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. We estimated the present value of our liability related to our ARO at $393.9$390.6 million as of December 31, 2011.2014. 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.

In April 2010, there was a fire and explosion aboard  Over the Deepwater Horizon drilling platform operated by BPlast several years, we have seen upward revisions in the deep water of the Gulf of Mexico which caused loss of life, caused the rigcosts to sink and created a major oil spill that produced economic, environmental and natural resource damage. Subsequently, the BOEM issued a series of NTLs and otherdo 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 crude oil prices are expected to lead to lower service costs and a reduction in the estimated liability.

Many changes in laws, regulations, guidance, interpretations and implemented a six-month moratorium on drilling activities which beganpolicy continue to be proposed and issued in May 2010. After the drilling moratorium ended in November 2010, it was not until March 2011 that deep waterour industry.  The process for obtaining offshore drilling permits, began to be issued, and even then only sporadically, to continue drilling activities that had commenced prior to the Deepwater Horizon incident. Since March 2011,especially deepwater drilling permits, have been issued, albeit at a slowerhas expanded and much more measured pace than beforelengthened in the Deepwater Horizon event.past few years.  The most significant regulatoryregulation changes since the Deepwater Horizon eventin recent years are regulations related to assessing the potential environmental impact of future spills using worse case discharge scenarios on a well-by-well basis,impacts, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system.  The new regulations and increased review process increases the time it takes 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.  The permitting process is also slow and inconsistentSee Regulation under Part I, Item 1 in this Form 10-K for shallow water work and even for plug and abandonment activities. This could lead to increased costs and performing work at less than optimal effectiveness or even at less than desirable times due to weather. We have not experienced delays in obtaining permits related to our onshore operations.additional information.   

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Results of Operations

Year Ended December 31, 20112014 Compared to Year Ended December 31, 20102013

Revenues.  Total revenues decreased $35.4 million, or 3.6%, to $948.7 million in 2014 compared to 2013. Oil revenues decreased $66.2 million, or 9.2%, NGLs revenues decreased $0.5 million, or 0.7%, natural gas revenues increased $28.5 million, or 15.1%, and other revenues increased $2.8 million.  The oil revenue decrease was attributable to an 11.2% Bbl decrease in the average realized sales price to $90.96 per Bbl from $102.44 in 2013, partially offset by a 2.3% increase in sales volumes.  The NGLs revenue decrease was attributable to a 1.7% decrease in the average realized sales price to $34.49 per Bbl in 2014 from $35.07 per Bbl in 2013, partially offset by an increase of 1.0% in sales volumes.  The natural gas revenue increase was attributable to a 22.5% increase in the average realized natural gas sales price to $4.35 per Mcf from $3.55 per Mcf for 2013, partially offset by a decrease in sales volumes by 6.0%.  We experienced increases in production from the A-5 well 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 Fairway 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, production deferrals affecting various fields and the divestitures of certain fields in 2013.  The production deferrals were attributable to third-party pipeline outages, platform maintenance, and various operational issues.  We estimate production deferrals were 2.6 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 due to closure of a pipeline, a rig move and well work and weather was a contributing factor in the first quarter of 2014 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.

Revenues from oil and liquids as a percent of our total revenues were 76.5% for 2014 compared to 80.5% for 2013.  NGLs realized sales prices as a percent of oil realized prices increased to 37.9% for 2014 compared to 34.2% for 2013.

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, decreased $6.1 million to $264.8 million in 2014 compared to 2013.  On a per Boe basis, lease operating expenses decreased to $15.01 per Boe during 2014 compared to $15.06 per Boe during 2013.  On a component basis, workover expense decreased $13.2 million, facilities maintenance expense decreased $4.6 million and insurance premiums decreased $3.3 million, partially offset by increases in base lease operating expenses of $15.4 million.  The decrease in workover costs was primarily due to workovers at Main Pass 69 and Ship Shoal (Mahogany) occurring in 2013,  which were partially offset by workovers at High Island 111 and High Island 129 occurring in 2014 and increased workover costs at Spraberry (Yellow Rose). The decrease in facilities maintenance expense was primarily due to 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 increases related to new wells at Ship Shoal 349 (Mahogany) and Spraberry (Yellow Rose).  

Production taxes.  Production taxes increased to $7.9 million during 2014 compared to $7.1 million in 2013 primarily related to increased production in the state waters 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 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 operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs increased to $19.8 million in 2014 compared to $17.5 million in 2013 primarily due to escalation in third-party transportation fees.

Depreciation, depletion, amortization and accretion.  DD&A, including accretion for ARO, increased to $28.98 per Boe for 2014 from $25.10 per Boe for 2013.  On a nominal basis, DD&A increased to $511.1 million for 2014 from $451.5 million in 2013.  DD&A on a per Boe and nominal basis increased in part due to increases in the full cost pool from capital expenditures and estimated future development costs.  Our focus on expanding deepwater exploration and development necessarily increases costs prior to increasing proved reserves, leading to an increase in the rate.  

General and administrative expenses (“G&A”).  G&A increased to $87.0 million for 2014 from $81.9 million for 2013 primarily due to increases in salaries, share-based compensation, contract labor costs and reductions in charge-outs to third-parties, partially offset by lower cash-based incentive compensation.  G&A on a per BOE basis was $4.93 Boe for 2014 compared to $4.55 per Boe for 2013.  See Financial Statements and Supplementary Data – Note 11 – 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)/loss.  For 2014 and 2013, our derivative positions resulted in a net gain of $4.0 million and a net loss $8.5 million, respectively, and related to the change 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 closed contracts.  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 $86.9 million for 2014 from $85.6 million for 2013 primarily due to higher balances on our revolving bank credit facility.  The aggregate principal amount of our 8.50% Senior Notes outstanding was $900.0 million during both years.  During 2014 and 2013, $8.5 million and $10.1 million, respectively, of interest were capitalized to unevaluated oil and natural gas properties.  The decrease is primarily attributable to reclassifying a portion of our unevaluated properties to the full cost pool during 2014 and 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.

Other income, net.  For 2014, other income 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 benefit was $4.5 million for 2014 compared to income tax expense of $28.8 million for 2013 due to a pre-tax loss in 2014 compared to pre-tax income in 2013.  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 $265.3$109.6 million, or 37.6%12.5%, to $971.0$984.1 million in 20112013 compared to 2010.2012. Oil revenues increased $189.8$89.4 million, or 14.2%, NGLs revenues increased $53.6decreased $11.3 million, or 13.3%, natural gas revenues increased $17.7$30.9 million, or 19.5%, and other revenues increased $4.2$0.6 million. The oil revenue increase was attributable to a 37.0%

Index to Financial Statements

increase in the average realized sales price (unhedged) to $105.92 per Bbl in 2011 from $77.33 per Bbl in 2010, combined with an increase of 3.4% in sales volumes. The NGLs revenue increase was attributable to a 27.9% increase in the average realized sales price (unhedged) to $55.81 per Bbl in 2011 from $43.65 per Bbl in 2010, combined with an increase of 58.3% in sales volumes. The sales volume increase for oil and NGLs is primarily attributable to increases associated with properties acquired in 2011 and 2010. The increase in natural gas revenue resulted from a 20.1%16.3% increase in sales volumes, partially offset by a 9.5%$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 (unhedged). For 2011, the natural gas average realized sales price was $4.12to $3.55 per Mcf compared to $4.55from $2.94 per Mcf for 2010.2012, 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 sales volume increase for natural gas is primarilyproduction deferrals were attributable to increases associated withthird-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 acquisition activities, the Main Pass 108 fields resumingFairway field due to well and maintenance issues and a turnaround at our Yellowhammer plant.  During 2012, we also experienced production and successful exploration efforts. Other revenue changeddeferrals primarily due to a disallowance of $4.7 million byHurricane Isaac and various pipeline outages, but not near the ONRRsame magnitude as in 2010 of royalty relief for transportation of deepwater production through our subsea pipeline system.We arecontesting this ONRR adjustment. For additional information, see Financial Statements – Note 19 – Contingenciesunder Part II, Item 8 of this Form 10-K.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 $49.5$38.6 million to $219.2$270.8 million in 20112013 compared to 2010.2012. On a per McfeBOE basis, lease operating expenses increased to $2.16$15.06 per McfeBoe during 2011compared2013 compared to $1.95$13.56 per McfeBoe during 2010.2012. On a component basis, baseworkover 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 facility 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 remediation costs net of insurance claims and workover costs increased $20.7 million, $14.1 million, $11.7 million and $3.6 million, respectively. As a partial offset, insurance premiums decreased $0.6of $1.5 million. The increase in base lease operating expenses is primarily attributable to expenses associated with the properties acquired in 2011 and 2010, higher costs at our various non-operated properties and increased processing fees associated with our Daniel Boone field production. The increase in facility expenses is primarily attributable to work performed on the tendon tension monitoring system and mechanical repairs at our Matterhorn platform, the pipeline repairs at our Ship Shoal 300 field to remove paraffin and inspection fees at our Main Pass 252 platforms. Hurricane remediation costs net of insurance claims increased primarily due to higher reimbursements received in 2010. Workover costs increased due to work performed at our Yellow Rose Properties and expenses at the Main Pass 108 field, partially offset by projects in 2010 that did not occur in 2011. The decrease in insurance premiums resulted primarily from lower premiums on our insurance policies covering well control and hurricane damage that cover the policy period June 1, 2010 to June 1, 2011. Our premiums increased effective with the June 1, 2011 renewal attributable to a substantial improvement in coverage. For additional information, seeLiquidity and Capital Resources – Hurricane Remediation and Insurance Claims.

Production taxes.taxes. Production taxes increased to $4.3$7.1 million during 20112013 compared to $1.2$5.8 million in 20102012 primarily due to the Yellow Rose Properties and the Fairway Properties’ operationsonshore 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.

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Gathering and transportation costs.Gathering and transportation costs were basically flat for 2011increased to $17.5 million in 2013 compared to the prior year.$14.9 million in 2012 primarily due to escalation in third-party transportation fees.

Depreciation, depletion, amortization and accretion(“DD&A”).accretion. DD&A, including accretion for ARO, decreasedincreased to $3.24$25.10 per McfeBoe for 20112013 from $3.38$20.79 per McfeBoe for 2010.2012. On a nominal basis, DD&A increased to $328.8$451.5 million for 20112013 from $294.1$356.2 million in 2010. The decrease in2012. DD&A on a per McfeBoe 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 proved reserves while DDconsulting services related to drilling operations, higher professional services, supplemental bonding fees and increased incentive compensation expense. G&A on a nominalper Boe basis increased due to higher production volumes.

General and administrative expenses. G&A increased to $74.3 millionwas $4.55 per Boe for 2011 from $53.3 million for 2010 due to a number of factors including higher incentive compensation as a result of improved financial and operational performance, costs related to expanded onshore and offshore activities, acquisitions, surety premiums, transition services fees paid to the sellers of the acquired properties, and litigation related costs. Also, we earned administration fees in 2010 related to an asset disposition, and no such fees were earned in 2011. On a

Index to Financial Statements

per Mcfe basis, G&A was $0.73 per Mcfe for 2011,2013 compared to $0.61$4.79 per McfeBoe for 2010.2012. SeeFinancial Statements and Supplementary Data – Note 11 – Share-Based and Cash-Based Incentive Compensationunder 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. Derivative (gain) loss.For 2011, our derivative gain of $1.9Interest expense incurred increased to $85.6 million was attributable entirely to a change in the fair valuefor 2013 from $63.3 million for 2012. The aggregate principal amount of our commodity derivatives as a result8.50% 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 the changes in crudean 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 prices. For 2010, our derivative loss of $4.3 million wasand natural gas properties. The decrease is primarily attributable to a loss from our commodity derivativesreclassifying unevaluated properties to the full cost pool during the fourth quarter of $4.0 million and a loss of $0.3 million related to our interest rate swap.2012. SeeFinancial Statements and Supplementary Data – Note 67Derivative Financial InstrumentsLong-Term Debt under Part II, Item 8 ofin this Form 10-K for additional information.

Other income, netInterest. 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. InterestIncome tax expense incurred increaseddecreased to $52.4$28.8 million for 2011 from $43.12013 compared to $47.5 million for 2010. During 2011, the amounts outstanding of our senior notes increased to $600.0 million from $450.0 million due to issuing our 8.5% Senior Notes and repurchasing our 8.25% Senior Notes. During 2011 and 2010, $9.9 million and $5.4 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties which increased due to the Yellow Rose Properties acquisition. SeeFinancial Statements – Note 7 – Long-Term Debtunder Part II, Item 8 of this Form 10-K for additional information.

Loss on extinguishment of debt. The loss on extinguishment of debt during 2011 of $22.7 million was attributable primarily to the repurchase of all of the $450.0 million outstanding of our 8.25% Senior Notes. The repurchase of the 8.25% Senior Notes was funded with a portion of the proceeds from the issuance of the 8.5% Senior Notes. The call premiums, unamortized debt issuance costs and other related expenses totaled $22.0 million. In addition, the previous revolving bank credit facility was amended and the termination date extended resulting in the write off of unamortized debt issuance costs of $0.7 million. In 2010, no loss on extinguishment of debt was incurred. SeeFinancial Statements – Note 7 – Long-Term Debt under Part II, Item 8 of this Form 10-K for additional information.

Interest income. Interest income decreased to $0.1 million for 2011 from $0.7 million in 2010 primarily2012 due to lower average daily cash balancespre-tax income and a reduction in market interest rates received on invested cash in 2011.

Incomelower effective tax expense (benefit). Income tax expense increased to $91.5 million for 2011 compared to $11.9 million for 2010.rate. Our effective tax rate for 20112013 was 34.6%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 deductionrecapture of deductions for qualified domestic production activities under Section 199 of the Internal Revenue Code (“IRC”). Our effective tax rate for 2010 was 9.2% and primarily reflects as a reduction in our valuation allowance against our deferred tax assetsfunction of loss carrybacks to prior years and the utilizationimpact of the deduction attributable to qualified domestic production activities under Section 199 of the IRC. Taxablestate income in 2010 allowed us to reverse all of our previously recorded valuation allowance.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Revenues. Revenues increased $94.8 million, or 15.5%, to $705.8 million for 2010 compared to 2009. Oil revenues increased $88.0 million, NGLs revenues increased $16.7 million, natural gas revenues decreased $1.2 million and other revenues decreased $8.7 million. The oil revenue increase was caused by a 29.0% increase in the average realized oil price (unhedged) to $77.33 per Bbl in 2010 from $59.96 per Bbl in 2009, partially offset by a 3.3% decrease in sales volumes to 5.9 MMBbls in 2010 from 6.1 MMBbls in 2009. The sales volume decrease for oil was primarily attributable to property divestitures in 2009, partially offset by increases associated with the Matterhorn field we purchased in the second quarter of 2010. The NGLs revenue increase was attributable to a 36.6% increase in the average realized sales price (unhedged) to $43.65 per Bbl in 2010 from $31.96 per Bbl in 2009, combined with an increase of 9.1% in sales volumes. The sales volume increase for NGLs was primarily attributable to acquisitions. The natural gas revenue decrease resulted from a 13.4% decrease in sales volumes to 44.7 Bcf in 2010 from 51.6 Bcf in 2009, partially offset by a 14.6% increase in the average realized natural gas sales price (unhedged) to $4.55 per Mcf in 2010 from $3.97 per Mcf in 2009. The sales volume decrease for natural gas is primarily attributable to production shut in at our Main Pass 108 field as

Index to Financial Statements

a result of a pipeline outage that began in June 2010 and property divestitures in 2009, partially offset by volumes from the properties acquired from Total and Shell in 2010. The decrease in other revenues was primarily attributable to reversing $4.7 million originally recorded in 2009 as this amount relates to the disallowance by the ONRR of royalty relief for transportation of deepwater production through our subsea pipeline system. We are contesting this ONRR adjustment.

Lease operating expenses.Lease operating expenses decreased $34.3 million to $169.7 million in 2010 compared to the prior year. On a Mcfe basis, lease operating expenses decreased to $1.95 per Mcfe in 2010 from $2.15 per Mcfe in 2009. On a component basis, hurricane remediation costs net of insurance claims, base lease operating expenses and insurance premiums decreased $30.1 million, $17.8 million and $0.8 million, respectively, while workover expenses and facilities expense increased $9.8 million and $4.8 million, respectively. Hurricane remediation costs net of insurance claims decreased due to insurance reimbursements being in excess of cost incurred for 2010. The decrease in base lease operating expenses primarily reflects decreases attributable to property divestitures during 2009, partially offset by increases associated with operating the properties acquired in 2010. The decrease in insurance expense is attributable to lower insurance premiums of our insurance policies covering well control and hurricane damage. The increase in workover expense is related to three separate workover projects that required the use of rigs to perform the activity. The increase in facilities expense is primarily attributable to repairs to newly acquired properties, repairs to pipelines and compressors, and blast and paint work.

Production taxes.Production taxes decreased $0.4 million to $1.2 million in 2010 primarily due to property divestitures in 2009. Most of our production is from federal waters, where there are no production taxes.

Gathering and transportation costs. Gathering and transportation costs increased $2.9 million to $16.5 million in 2010 primarily due to costs associated with operating the properties acquired in 2010, partially offset by property divestitures that occurred in 2009.

Depreciation, depletion, amortization and accretion.DD&A, including accretion for ARO, decreased to $3.38 per Mcfe in 2010 from $3.61 in 2009. On a nominal basis, DD&A decreased to $294.1 million in 2010 from $342.5 million in 2009. The rate per Mcfe is lower primarily due to the reserves acquired and the property divestitures in 2009 while DD&A on a nominal basis decreased primarily due to lower production and the lower rate per Mcfe.

Impairment of oil and natural gas properties. In 2010, we did not have a ceiling test impairment but in the first quarter of 2009, we recorded a ceiling test impairment of our oil and natural gas properties of $218.9 million. This write down resulted from the application of the full cost ceiling limitation as prescribed by the SEC, primarily as a result of a further decline in natural gas prices at March 31, 2009 as compared to December 31, 2008. For a more detailed discussion of the ceiling test, refer toFinancial Statements – Note 1 – Significant Accounting Policiesunder Part II, Item 8 of this Form 10-K.

General and administrative expenses.G&A increased to $53.3 million in 2010 from $43.0 million in 2009, primarily due to higher incentive compensation and reductions in billings to joint-interest parties attributable to certain capital projects. Incentive compensation increased due to the Company’s improved financial and operational performance in 2010 and the implementation of a new performance based incentive compensation plan. In 2009, no awards were granted for 2009 performance. On a per Mcfe basis, G&A was $0.61 per Mcfe for 2010, compared to $0.45 per Mcfe for 2009. SeeFinancial Statements – Note 11 – Share-Based and Cash-Based Incentive Compensationunder Part II, Item 8 of this Form 10-K for additional information.

Derivative loss.For 2010, our derivative loss of $4.3 million consisted of a loss of $4.0 million for our commodity derivatives and a loss of $0.3 million for our interest rate swap. For 2009, our derivative loss of $7.4 million consisted of a loss of $5.6 million for our commodity derivatives and a loss of $1.8 million for our interest rate swap. SeeFinancial Statements – Note 6 – Derivative Financial Instruments under Part II, Item 8 of this Form 10-K for additional information.

Index to Financial Statements

Interest expense. Interest expense incurred decreased to $43.1 million for 2010 from $46.7 million in 2009 primarily due to lower interest rates and lower debt outstanding during 2010. During 2010 and 2009, $5.4 million and $6.7 million, respectively, of interest was capitalized to unevaluated oil and gas properties.

Loss on extinguishment of debt. In 2010, no loss on extinguishment of debt was incurred. In May 2009, we repaid the Tranche B term loan facility in full with borrowings under our revolving loan facility. As a result, in 2009 we recorded a loss of $2.9 million related to the write-off of deferred financing costs and other related incidental costs.

Interest income.Interest income decreased to $0.7 million for 2010 from $0.8 million in 2009 primarily due to lower average daily cash balances and a reduction in market interest rates received on invested cash in 2010.

Income tax expense (benefit).Income tax expense increased to $11.9 million in 2010 from an income tax benefit of $74.1 million for 2009. Our effective tax rate for 2010 was 9.2% and primarily reflects a reduction in our valuation allowance against our deferred tax assets and the utilization of the deduction attributable to qualified domestic production activities under Section 199 of the IRC. Taxable income in 2010 allowed us to reverse all of our previously recorded valuation allowance. For 2009, the income tax benefit resulted from a pre-tax loss. Our effective tax rate for 2009 was 28.3% and primarily reflected the effect of a change in law to increase the carryback period and a valuation allowance for our deferred tax assets.

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. 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 of liquidity have historically been sufficient to fund our ongoing cash requirements.

Cash flow and working capital.Net cash provided by operating activities for 20112014 was $521.5$511.4 million, compared to $464.8$561.4 million for 2010. The 2010 period included income tax refunds of $99.8 million primarily related to the Worker, Homeowner and Business Assistance Act of 2009 that allowed us to carry back losses to previously closed years, while the 2011 period included tax payments of $35.7 million. Otherwise, cash flow2013. Cash flows from operating activities, increased $192.2before 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 substantially improved operating results.lower revenues.  Our combined average realized sales price per Mcfe was 17.2%Boe decreased 2.0%, with lower average realized sales prices of oil being partially offset by higher than the comparable 2010 period and ouraverage realized natural gas sales prices.  Our combined production of oil, NGLs and natural gas on a McfeBoe basis during 20112014 decreased 1.9% from 2013.

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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 16.7%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 2010.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 20112014 and 20102013 was $722.7$630.0 million and $415.0$614.8 million, respectively, which primarily represents our investments in both offshore and onshore oil and natural gas properties. Cash usedThe increase is primarily due to proceeds from properties sales and other items of $21.0 million received in investing activities2013 and no similar transactions occurred in 2011 consisted primarily of2014.  Partially offsetting were decreases in acquisition expenditures, as we paid $72.2 million related to the consideration for the acquisitions of the Yellow Rose Properties ($394.4 million)increased ownership in Fairway and the Fairway Properties ($42.9 million). In 2010, cash used in investing activities primarily consisted of the consideration for the acquisition of the Matterhorn/Virgo properties ($115.0 million) and the Tahoe/S. Tahoe/Droshky properties ($121.9 million). In addition, investmentsWoodside Properties in other oil and natural gas properties and equipment were $281.8 million in 20112014 (two separate transactions) compared to $178.7$82.4 million in 2010 with the increase primarily related to the Yellow Rose Properties. There were minimal proceeds from salesacquisition of assetsthe Callon Properties in 2011 and proceeds from asset sales were $1.4 million for 2010.2013.  

Net cash provided by financing activities was $177.1$126.4 million during 2011. Funds were2014. The net cash provided throughduring 2014 was primarily attributable to net borrowings on theour revolving bank credit facility of $117.0$157.0 million, and issuance of $600.0 million of 8.5% Senior Notes andwhich was partially offset by the repurchasedividend payments of $450.0$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 the 8.25% Senior Notes, repurchase premium$120.0 million, which was partially used for dividend payments of $58.8 million and debt issuance costs of $32.3 million and the payment of dividends of $58.8 million, which includes a special dividend of $46.9$3.9 million. SeeFinancial Statements – Note 7 – Long-Term Debt under Part II, Item 8 of this Form 10-K for additional information on the senior note transactions. Net cash used in financing activities during 2010 was $59.3 million, which reflects dividend payments including a special dividend of $49.2 million.

Index to Financial Statements

At December 31, 2011,2014, we had a cash balance of $4.5$23.7 million and $457.6$302.4 million of undrawn capacity available under the revolving bank credit facility, which had a borrowing base of $575.0$750.0 million as of December 31, 2011.2014.

Credit agreement and long-term debt.At December 31, 2011, $117.02014, $447.0 million was outstanding under our revolving bank credit facility compared to zero$290.0 million at December 31, 2010.2013. At December 31, 2011, $600.02014 and 2013, $900.0 million principal amount of our 8.5%8.50% Senior Notes was outstanding and at December 31, 2010, $450.0 million was outstanding of our 8.25% Senior Notes.were outstanding. We believe that cash provided by operations and borrowings available under our revolving bank credit facility and other external sources of liquidity should beis sufficient to fund our ongoing cash requirements.  See Capital Expenditures below.  

On May 5, 2011,November 8, 2013, we entered into our amendedthe Credit Agreement which provides a revolving bank credit facility with an initial borrowing base of $525.0up 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 borrowing base was re-determined in October 2011 and was increased to $575.0 million. The Credit Agreement terminates on May 5, 2015. FeesNovember 8, 2018 and transactions costs related toreplaced the Prior Credit Agreement were approximately $6.1 million and are included in the repurchase premium and debt issuance costs discussed above.Agreement. Availability under the Credit Agreement is subject to a semi-annual borrowing base redeterminationre-determination set at the discretion of our lenders.lenders, 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 oil and natural gas prices could negatively impact our ability to borrow under Part I, Item 1A in this Form 10-K.   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 size ofavailability under our revolving bank credit facility. During 2014, the borrowing base was re-determined and set at $750.0 million.  Borrowings under the Credit Agreement bear 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%.     

We currently have 1020 lenders within the revolving bank credit facility, with commitments ranging from $35.0$20.0 million to $68.0$58.0 million for the current borrowing base of $575.0 million.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.

Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate or LIBOR, plus applicable margins ranging from 2.00% to 2.75%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, and (c) LIBOR plus 1%, plus applicable margins ranging from 1.00% to 1.75%. The unused portion of the borrowing base is subject to a commitment fee of 0.50%.

The Credit Agreement contains covenants that restrict,limit, among other things, the payment of cash dividends in excess of $60.0 million per year, common stock repurchases and Senior Note repurchases in excessyear. In December 2012, we were granted a one-time waiver which allowed for cash dividends of $100up to $85.0 million in the aggregate, borrowings other than from the revolving bank credit facility, sales of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders.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, as defined in the Credit Agreement.agreements. We were in compliance with all applicable covenants of the Credit Agreement as of December 31, 2011. 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 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 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.

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During 2011,2014, the outstanding borrowings outstanding on the revolving bank credit facility increased to $300.0reached a high of $447.0 million, which was also the outstanding balance at December 31, 2014, primarily to fund the acquisition of the Yellow Rose Properties, which also included funding from cash on hand. These borrowings were subsequently reduced to $117.0 million as of December 31, 2011, primarily by utilizing funds received from the senior note transactions described belowacquisitions, our various deepwater development efforts and net cash from operations, partially offset by capital expenditures and dividends.our ongoing onshore operations. Letters of credit outstanding as of December 31, 20112014 were $0.4$0.6 million.

On June 10, 2011, we issued $600.0 million of 8.5% Senior Notes and used a portion of the net proceeds to repurchase the $450.0 million outstanding of our 8.25% Senior Notes. The net cash provided by these senior notes transactions, which includes initial purchaser fees, redemption premiums and other transactions costs, was $123.8 million. These transactions extended the maturity date of our long-term debt and we used the net proceeds to pay down a portion of amounts outstanding under the revolving bank credit facility. The 8.5%8.50% Senior Notes mature on June 15, 2019. Interest2019 and interest is payable semi-annually in arrears on June 15 and December 15 of each year beginning on December 15, 2011.year. SeeFinancial Statements and Supplementary Data – Note 7 – Long-Term Debt under Part II, Item 8 ofin this Form 10-K for additional information about our Credit Agreement and long-term debt.

We were in compliance with all applicable covenants related to the 8.50% Senior Notes as of December 31, 2014.

Index to Financial Statements

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, 2011, our2014, we did not have any outstanding derivative instruments consisted of commodity swapopen derivatives. See Financial Statements and option contracts relating to approximately 2.2 MMBbls, 1.3 MMBbls and 0.7 MMBbls of our anticipated oil production for 2012, 2013 and 2104, respectively. SeeFinancial StatementsSupplementary Data – Note 6 – Derivative Financial Instrumentsunder Part II, Item 8 ofin this Form 10-K for additional information about our derivatives.

Hurricane Remediationremediation, insurance claims and Insurance Claimsinsurance coverage. During the third quarter of 2008, Hurricane Ike and to a much lesser extent Hurricane Gustav, caused substantial property damage and disruptions to our exploration and production activities. Our insurance coverage policy limits atdamage.  Substantially all the time of Hurricane Ike were $150 million for property damage due to named windstorms (excluding certain damage incurred at our facilities we chose not to insure) and $250 million for, among other things, removal of wreckage if mandated by any governmental authority. The policies in effect on the occurrence dates of Hurricanes Ike and Gustav had a retention requirement of $10 million per occurrence. In 2008, we satisfied our $10 million retention requirement for Hurricane Ike in connection with two platforms that were toppled and were deemed total losses. The damage we incurred as a result of Hurricane Gustav was below our retention amount.

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’ adjuster reviews and approves such costs for payment by the underwriters. Claims that have been processed in this manner have customarily been paid on a timely basis.

In 2011, 2010, 2009 and 2008 we have received cash of $20.9 million, $65.5 million, $47.1 million and $5.8 million, respectively, from our insurance carrier related to Hurricane Ike have been incurred and we submitted claims (totaling $139.3 million) and have recorded $0.7under our insurance policies effective at that time, of which $161.2 million of insurance receivables as ofhas been collected through December 31, 20112014.  In June 2014, the United States Fifth Circuit reversed a lower court’s ruling and compelled our insurance underwriters to reimburse costs incurred by us for removal of wreck related 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 to claims, that have been submittedthe estimated potential reimbursement of removal-of-wreck costs is approximately $31 million, plus interest, attorney fees and approved for payment. As of December 31, 2011,damages, if any.  Given the Fifth Circuit’s ruling, we have recorded in ARO an estimate of $56.9 million for additional costsexpect to be incurred related to Hurricane Ikereimbursed and we have estimated that this work will be completed by the end of 2013. We expect to receive reimbursementcompensated for a portion ofall these costs, from our insurance carrier once the costs are incurred, claims are processedinterest, fees and payments are approved, but cannot estimate the amount of reimbursement to be received at this time. Should necessary expenditures exceed our insurance coverage for damages incurred as a result of Hurricane Ike, or claims are denied by our insurance carrier for other reasons, we expect that our available cash on hand, cash flow from operations and the availability under our revolving bank credit facility will be sufficient to meet these future cash needs.

For a discussion of our hurricane remediation costs related to lease operating expenses incurred during 2011, 2010 and 2009, refer todamages.  See Financial Statements and Supplementary Data - Note 18 Note 3 – Hurricane Remediation and Insurance ClaimsContingencies under Part II, Item 8 ofin this Form 10-K. Lease operating expenses will be offset in future periods to the extent that these costs incurred are approved for payment under our insurance policies. We expect that the majority of insurance reimbursements subsequent to December 31, 2011 will be attributable to plugging and abandonment activities.additional information.                  

We currently carry threemultiple layers of insurance coverage forin our Energy Package covering our operating activities, in the Gulfwith higher limits of Mexico.coverage for higher valued properties and wells.  The current policy limits for well control range from $30.0 million to $500.0 million depending on the risk profile and hurricane damage (defined as contractual 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 of named windstorm coverage for our lower value offshore properties for the cost of removal in our policies) are up to $100.0 millionexcess of scheduled ARO amounts.  The well control, named windstorm and $120.0 million, respectively, and the policies arephysical damage coverage is effective until June 1, 2012. We carry an additional $100.0 million of well control coverage effective until June 1, 2012 on certain wells at our Mahogany, Matterhorn, Virgo, Tahoe and SE Tahoe fields.2015.  A per-occurrence retention amount of $5.0$30.0 million for well controlnamed windstorm events and $37.5 million per hurricane occurrence must be satisfied by us before our insurers will indemnify us for losses and we are indemnified for losses. Certain properties we have deemed as non-core are not covered for hurricane damage. As of December 31, 2011, approximately 93%co-insure 15% of our PV-10 valuenamed windstorm coverage. We also have other smaller per-occurrence retention amounts for various other events. Coverage for pollution causing a negative environmental impact is provided under the well control and named windstorm sections of proved reserves attributable tothe policy.

All of our Gulf of Mexico properties are on platforms thatwith estimated future net revenues are covered under our current insurance policies for named windstorm damage.  Pollution causing a negative environmental impact is characterized as a covered component of each of the well controlThe risk exposure varies per property and hurricane sections of the policy.we have exposure for applicable retentions, co-insurance amounts and coverage limits.

Index to Financial Statements

Our general and excess liability policy, which ispolicies are effective until May 1, 2012, provides2015 and provide for $250.0$300.0 million of liability 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 (“OSFR”) requirement under the OPA,Oil Pollution Act of 1990, we are required to evidence $150.0 million of financial responsibility to the BSEE.  We qualify to self-insure for $35$54.0 million of this amount and the remaining $115.0$96.0 million is covered by insurance.

The premiums for the aboveAlthough we were able to renew our Energy Package and our general and excess liability policies were $30.7 million for the May/June 2011 policy renewals compared to $22.6 million for the expiring policies. The increase in our premiums effective with the June 1, 2011 renewal was primarily attributable to an increase in the policy limit for hurricane damagesecond quarter of 2014 and increases in covered property. Although we have not been informed otherwise, in the future, our insurers may not continue to offer this type and level of coverage to us, 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 insurance companiesinsurers will not pay our claim.claims.  However, we are not aware of any financial issues related to any of our insurance underwriters 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 million for the May/June 2014 policy renewals compared to $24.1 million for the expiring policies. The increase in our premiums effective with the June 1, 2014 renewal was primarily attributable to the addition of the builder’s risk policy and partially offset by lower premiums due to an improved insurance market.

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 oil and natural gas, acquisition opportunities, and the results of our exploration and development activities. The following table presents our capital expenditures for acquisitions, exploration, development 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, 
   2011  2010   2009 
   (in thousands) 

Acquisition of Yellow Rose Properties

  $394,377   $—      $—    

Acquisition of Fairway Properties

   42,870    —       —    

Acquisition of (adjustments to) Tahoe/Droshky Properties

   (5,700  121,933     —    

Acquisition of Matterhorn/Virgo Properties

   —      115,012    —    

Exploration (1)

   77,606    60,164     90,636  

Development (1)

   179,705    77,230     162,111  

Seismic, capitalized interest, other leasehold costs

   30,168    41,314     23,387  
  

 

 

  

 

 

   

 

 

 

Acquisitions and investments in oil and gas property/equipment

  $719,026   $415,653    $276,134  
  

 

 

  

 

 

   

 

 

 

(1)

Reported by geographygeographically in the subsequent table.

The following table presents our exploration and development capital expenditures by geography:geographically:

 

 

Year Ended December 31,

 

 

 

2014

 

 

2013

 

 

2012

 

 

 

(In thousands)

 

Conventional shelf

 

$

131,215

 

 

$

143,151

 

 

$

104,401

 

Deepwater

 

 

216,539

 

 

 

143,745

 

 

 

65,856

 

Deep shelf

 

 

23,615

 

 

 

61,953

 

 

 

11,961

 

Onshore

 

 

154,215

 

 

 

158,218

 

 

 

265,042

 

Exploration and development capital expenditures

 

$

525,584

 

 

$

507,067

 

 

$

447,260

 

 

   Year Ended December 31, 
   2011   2010   2009 
   (in thousands) 

Conventional shelf

  $132,680    $115,503    $200,699  

Deepwater

   4,826     9,358     45,911  

Deep shelf

   5,833     3,382     4,573  

Onshore

   113,972     9,151     1,564  
  

 

 

   

 

 

   

 

 

 

Exploration and development capital expenditures

  $257,311    $137,394    $252,747  
  

 

 

   

 

 

   

 

 

 

Index to Financial Statements

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

Completed

 

 

Non-commercial

 

  Successful   Unsuccessful 

2014

 

 

2013

 

 

2012

 

 

2014

 

 

2013

 

 

2012

 

      2011           2010           2009           2011           2010           2009     

Offshore – gross wells drilled:

            

Offshore - gross wells drills:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Conventional shelf

   7     6     8     —       1     3  

 

3

 

 

 

4

 

 

 

3

 

 

 

 

 

 

1

 

 

 

1

 

Deepwater

 

3

 

 

 

1

 

 

 

1

 

 

 

 

 

 

 

 

 

 

Deep shelf

   1     —       2     —       —       —    

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Wells operated by W&T

   7     3     7     n/a     n/a     n/a  

 

4

 

 

 

5

 

 

 

3

 

 

n/a

 

 

n/a

 

 

n/a

 

Onshore:

            

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross wells drilled

   40     —       —       1     2     —    

 

33

 

 

 

40

 

 

 

77

 

 

 

 

 

 

 

 

 

 

Wells operated by W&T

   33     —       —       n/a     n/a     n/a  

 

32

 

 

 

40

 

 

 

73

 

 

n/a

 

 

n/a

 

 

n/a

 

As of December 31, 2011,2014, we were in the process of drilling and/or completing sevenfive offshore exploration wells, six onshore development wells in Texas 13and seven onshore exploration wells in Texas and no offshore wells.Texas.

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

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

In 2011, we did not participate in bidding for any Gulf of MexicoWe acquired the following leases on the OCS. Due to the government mandated moratorium that began in April 2010, Gulf of Mexico lease sales conducted by the U.S. government through the BOEM were suspended until December 2011. Leases acquired from the BOEM in the March 2010 lease sale totaledBOEM:  five leases ($2.4 million), two leases ($0.5 million) and 11 leases ($2.5 million) for $8.7 millionthe years 2014, 2013 and in 2009 we acquired three leases for $0.7 million.2012, respectively.

Periodically, as part of our business strategy,61


From time to time, we sell various oil and gas properties that we identify as non-core, which we define as either having limited exploration or development potential or are expectedfor a variety of reasons including, change of focus, perception of value and to yield less than our desired return on equity when abandonment costs are considered.reduce debt, among other reasons. In 2011 and 2010,2014, there were no significant property sales.sales of significance. In 2009,2013, we sold oneour 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 our fields$10.2 million and reduced ARO by $19.6 million. Also in Louisiana state waters and2013, we received $9.1 million in conjunction with a payment to us for an option exercised by a counterparty.  In 2012, we sold 36 non-core oil and natural gas fieldsour 40% non-operated working interest in the Gulf of Mexico. In connection with these transactions, weSouth Timbalier 41 field for $30.5 million and reduced our ARO by $128.5 million$4.0 million.  See Financial Statements and we received proceeds of $32.2 million.Supplementary Data – Note 2 – Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K for additional information on divestitures.

Our totalcurrent capital expenditure budget for 20122015 is $425.0$200 million, not including any potential acquisitions.  The 2015 budget includes $209.0 millionis 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 drill,the deepwater.  Through February 2015, we have not closed any acquisitions, but we continue to evaluate and complete ten offshore wells (six explorationbid on opportunities as they arise.  We anticipate funding our 2015 capital budget, any potential acquisitions and four development wells)other expenditures with cash flow from operating activities, cash on hand and $170.0 millionborrowings under our revolving bank credit facility.  For the portion of our capital budget related to drill, evaluate and complete 65 onshore wells (19 exploration and 46 development wells). The budget also includes $46.0 milliondrilling, our operating policy has been to fund these expenditures with cash flow provided by operations.  See below for facilitiesinformation on capital recompletions, seismic and leasehold items.markets.  Our 20122015 capital budget is subject to change as conditions warrant and wewarrant.  We strive to be as flexible as possible.possible and believe this strategy holds the best promise for value creation, growth and managing the volatility inherent in our business.

Income taxes.  During 2014, we did not make any income tax payments and received $3.0 million of refunds.  The refund was attributable to 2013 estimated federal tax payments.  During 2013, we made income tax payments of $3.0 million and received $59.1 million of refunds.  The refunds were primarily attributable 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.  As of December 31, 2014, $9.5 million of the refunds received in 2013 have been accounted for as unrecognized tax benefits.  We intendhave $516.4 million of Federal net operating loss carryforwards (tax basis) available to continueoffset future taxable income in 2015 and forward.  We also have $12.1 million of alternative minimum tax credit carryforwards (tax basis) available to pursue acquisitionsbe utilized in 2015 and joint venture opportunities during 2012 should attractive opportunities arise. We are actively evaluating opportunities and expect to complement our drilling and development projects with acquisitions providing acceptable rates of return. We anticipate funding our 2012 capital budget and acquisitions with internally generated cash flow, cash on hand, borrowings under our revolving loan facility, and accessing the capital markets to the extent necessary.forward.

Dividends. Dividends.In 2011,2014, we paid $30.3 million in dividends.  In 2013, we paid $58.8 million in dividends, which includesincluded a special dividend of $46.9totaling $31.8 million and regular dividends of $11.9$27.0 million. In 2010,2012, we paid $59.6$82.8 million in dividends, which includes aincluded two special dividend of $49.2dividends totaling $59.0 million and regular dividends of $10.4$23.8 million.  In 2009, we paid $9.2 million of regular dividends. Future special dividends cannot be predicted andDividends are subject to approvalperiodic review of the board of directors, which will consider theCompany’s performance of the Company, its financial condition, future investment opportunities and other factors as our majority shareholder and the boardcurrent economic environment and applicable debt agreement restrictions.  In light of directors deems appropriate.current market conditions, the Board of Directors has elected to suspend the regular quarterly dividend.  

Index to Financial Statements

Capital Marketsmarkets and Impact on Liquidity. During 2011, we accessed the capital markets for our 8.5% Senior Notes and renewed our revolving bank credit facility arrangement as described above. For 2012 to date, the U.S. financial markets have not as of yet been adversely affected by the events in the international markets, including the financial crisis that has threatened the various countries in the Euro zone. Such crisis is having an impact on European banks that have exposure to these countries which could ultimately impact borrowers in the United States. The longer-term outlook could be impacted from these or other international events.liquidity. At this time, we do not have current plans to obtain additional financing in 2012,2015, but this situation could change depending on a number of factors, such as acquisition opportunities and prices of oil and natural gas.

A fairly recent example of scarce financing availability occurred in 2009 when  The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the globalneed 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 economic conditions were severely distressed. There were concernsoptions given different scenarios of bank failurescommodity 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 concerns whether our banks would be able to meet their commitments under credit arrangements in place during that time. In addition, prices for oil and natural gas had decreased from 2008. These conditions contributed to fewer financing transactions being completed.levels.

Asset retirement obligations. Each year (or(and often more often if conditions warrant)frequently) we review and to the extent necessary, revise our ARO estimates. Our ARO at December 31, 20112014 and 20102013 were $393.9$390.6 million and $391.3$354.4 million, respectively. In 2014 and 2013, we revised our estimates to account for the increased cost to comply with new and revised regulations including an increase in work scope and interpretation of work scope. SeeFinancial Statements and Supplementary Data – Note 5 – Asset Retirement Obligationsunder Part II, Item 8 ofin this 10-Kfor10-K for additional information regarding our estimation of our ARO.

62


Contractual obligations. The following table summarizes our significant contractual obligations by maturity as of December 31, 2011.2014. At December 31, 2011,2014, we did not have any capital leases.

 

   Payments Due by Period at December 31, 2011 
  Total   Less Than
One Year
   One to
Three Years
   Three to
Five Years
   More Than
Five Years
 
  (Dollars in millions) 

Long-term debt – principal

  $717.0    $—      $—      $117.0    $600.0 

Long-term debt – interest (1)

   389.2     53.7     107.3     103.0     125.2 

Drilling rigs

   33.8     32.1     1.7     —       —    

Operating leases

   12.6     0.3     2.3     2.2     7.8 

Asset retirement obligations

   393.9     138.2     94.7     47.3     113.7  

Derivatives (2)

   7.2     7.2     —       —       —    

Other liabilities

   4.6     —       4.6     —       —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $1,558.3    $231.5    $210.6    $269.5    $846.7  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

Payments Due by Period as of December 31, 2014

 

 

Total

 

 

Less than

One Year

 

 

One to

Three Years

 

 

Three to

Five Years

 

 

More Than

Five Years

 

Long-term debt - principal

$

1,347.0

 

 

$

 

 

$

 

 

$

1,347.0

 

 

$

 

Long-term debt - interest (1)

 

390.6

 

 

 

89.4

 

 

 

178.8

 

 

 

122.4

 

 

 

 

Drilling rigs

 

12.6

 

 

 

12.6

 

 

 

 

 

 

 

 

 

 

Operating leases

 

13.9

 

 

 

1.5

 

 

 

3.2

 

 

 

3.5

 

 

 

5.7

 

Asset retirement obligations (2)

 

390.6

 

 

 

36.0

 

 

 

179.4

 

 

 

19.0

 

 

 

156.2

 

Other liabilities and commitments (3)

 

61.7

 

 

 

7.9

 

 

 

15.7

 

 

 

9.7

 

 

 

28.4

 

Total

$

2,216.4

 

 

$

147.4

 

 

$

377.1

 

 

$

1,501.6

 

 

$

190.3

 

 

(1)

Interest on long-term debt is comprised of: (a) interest on our 8.5%8.50% Senior Notes, which bear interest at a fixed rate of 8.5%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 effective atof 2.6%, which was the interest rate as of December 31, 20112014, and the commitment fee of 2.3%.0.375% on the unused balance as of December 31, 2014. Interest was calculated through the stated maturity date of the related debt.

(2)

Derivatives contracts that had fair values of assets of $4.1 million were excluded as these did not represent future payments

ARO in the above table is presented on a discounted basis, consistent with the amounts reported on the Consolidated Balance as of December 31, 2011. Future price changes2014.  All other amounts in the above table are presented on an undiscounted basis.  

(3)

Other liabilities and commitments primarily consist of estimated fees for obtaining bonds related to obligations under certain purchase and sale agreements and 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 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 cause some or all of these derivative contracts to become liabilities resulting in paymentsbe offset by our interest in future periods. In addition,revenue from these non-operated properties.  These joint interest obligations for future commitments cannot be determined due to the derivative contracts that had fair valuesvariability of liabilities reported above could have greater payments upon realization depending on the underlying commodity price of oil.factors involved.  See Financial Statements and Supplementary Data – Note 16 – Commitments under Part II, Item 8 in this 10-K for additional information.

Inflation and Seasonality

InflationInflation. For 2011,2014, our realized prices for oil increased 37.0%decreased 11.2%, NGLs increased 27.9%decreased 1.7% and natural gas decreased 9.5%increased 22.5% from 2010.2013. These are discussed in theOverview section above. Costs measured on a $/McfeBoe basis increased by 3.3%9.5% in 20112014 compared to 2010.2013. The cost per McfeBoe 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 oil, NGLNGLs and natural gas, as

Index to Financial Statements

these commodities affect the demand for these goods and services. In the last threerecent years, other factors have influenced the cost of goods and services. For example, in 2009, some offshore third-party contractors were in high demand associated with remediation work related to Hurricane Ike which increased the price for these types of contractors. In 2010, pricesDemand for offshore third-party contractors were relatively stable as drilling activity was curtailed due tocan be affected by hurricanes, oil spills and changes in regulations which are outside of the moratorium, but boat prices and other services escalated due to contract work for BP in connection with the clean up effortinfluences from the oil spill at the Macondo well.commodity price changes. Other costs, such as insurance premiums, have fluctuated with changes in hurricane activity, the oil spill at the Macondo wellspills and other factors besides production volumes. More recently,Also, many commodity prices, including oil, copper, steel and other types of metals, have fluctuated wildly with various world events. Some of this fluctuation is due to strongchanges in economic activity in certain parts of the world, while other changes appear to be driven by political events around the world, as well as the weakchanges in the value of the US dollar (both up and down) and other foreign currencies and the prospect ofcurrencies. In addition, inflation in the futureour industry is impacted as a result of record federal deficits.deficits and expectations that large deficits will continue.

SeasonalitySeasonality. 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. 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-inshut 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 inFinancial Statements and Supplementary Data – Note 1 – Significant Accounting Policiesunder Part II, Item 8 in this Form 10-K.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 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

Index to Financial Statements

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 judgments 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 these estimates, which would affect the timing of when these expenses would be recognized in DD&A. SeeOil and natural gas reserve quantitiesandAsset retirement obligationsbelow for more information.

64


Impairment of oil and natural gas properties.Under the full cost method of accounting, we are required to periodically perform a “ceiling test,” which determines a limit on the book value of our oil and natural gas properties. Any write downs occurring as a result of athe ceiling test impairment are not recoverable or reversible in future periods. We did not have a ceiling test impairment in 2011 or 2010, but we did haveany ceiling test impairments in 2009 as2014 or 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 recognize a resultnon-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 significant decline in both oileffect of lower commodity prices on liquidity, see  Risk Factors - Risks Related to Financing under Part I, Item 1A and natural gas prices that began in the second halfLiquidity and Capital Resources section of 2008. Declinesthis Item in oilthis Form 10-K for additional information about our Credit Agreement and natural gasfinancing.  For the effect of lower commodity prices after December 31, 2011 may require us to recordon revenues and earnings, see Quantitative and Qualitative Disclosures on Market Risks under Part II, Item 7A in this Form 10-K for additional ceiling test impairments in the future.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, 20112014 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;

·

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

·

the judgment of the persons preparing the estimates.

Index to Financial Statements

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.

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 clean up.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 theAsset Retirement and Environmental Obligations topic of the FASB Accounting Standards Codification (the “Codification”),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 these derivatives,our derivatives; therefore, the change in fair value for all outstanding derivatives, which include derivatives that are hedges againstentered into in anticipation of future production, are reflected currently in our statementstatements of income.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.


65


Income taxes.We provide for income taxes in accordance with theIncome Taxestopic of the Codification,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 required by GAAP.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 theCompensation – Stock Compensation topic of the Codification,GAAP, we 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. 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.

Index to Financial Statements

Item 7A. Accounting PoliciesQuantitative and PronouncementsQualitative Disclosures About Market Risk

Effective for our annual reporting period ended December 31, 2009, we adopted certain amendments to theExtractive Activities – Oil and Gas topic of the Codification that updated and aligned the FASB’s reserve estimation and disclosure requirements for oil and natural gas companies with the reserve estimation and disclosure requirements that were adopted by the SEC in December 2008. Periods reported prior to 2009 were not adjusted retrospectively. The amendments revised prices used and revised the definition of proved undeveloped reserves along with other changes. These amendments impacted our financial position and the results of operations as they affected our determination of DD&A expense and the calculations used in determining impairment assessment under the ceiling test rules. The amendments did not have an impact on our cash flows.

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 derivativesderivative contracts to reduce the risk of fluctuations in commodity prices and expect to use these instruments in the future. We dodid not enter intohave any open derivative contracts for speculative purposes. We are currently a party to commodity swap and option 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 2011,2014 and assuming no other items had changed, our incomeloss before income taxestax would have decreasedincreased by approximately 37%$94 million in 2011.2014. If costs and expenses of operating our properties had increased by 10% in 2011,2014, our incomeloss before income taxestax would have decreasedincreased by 9%approximately $29 million in 2011.2014.

During 2011 and 2010, we entered into commodity swap and option contracts to manage a portion of our exposure to commodity price risk from sales of oil during the years ended December 31, 2012, 2013 and 2014. As of December 31, 2011,2014, we did not have derivatives with a notional quantity of 4.2 MMBbl.any open derivative contracts. We do not designate our commodity derivativesderivative contracts as hedging instruments. While theseprevious derivative contracts arewere intended to reduce the effects of volatile oil prices, they may also limit futurehave limited income from favorable price movements. For additional details about our commodity derivatives,derivative contracts, refer toFinancial Statements and Supplementary Data – Note 6 – Derivative Financial Instrumentsunder Part II, Item 8 ofin this Form 10-K.10-K.

Interest rate risk.As of December 31, 2011,2014, we had $117.0$447.0 million outstanding on our revolving bank credit facility and during 20112014 we had amounts outstanding that ranged from zero$242.0 million to $300.0$447.0 million. The revolving bank credit facility has a variable interest rate which is primarily impacted by the rates for the London Interbank Offered Rate (“LIBOR”)LIBOR and the margin ranges from 2.0%1.75% to 2.75% depending on the amount outstanding. In 2011,2014, if interest rates would have been 100 basis points higher (an additional 1%); our interest expense would have been approximately $0.8$3.3 million higher. We did not have any derivativesderivative contracts related to interest rates as of December 31, 2011.2014.

66


Item 8. Index to Financial Statements

Item 8.Financial Statements and Supplementary Data
and Supplementary Data

W&T OFFSHORE, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

67


Index to Financial Statements

MANAGEMENT’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 framework inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.Commission (2013 framework).  

Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 20112014 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, 20112014 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

Index to Financial Statements

68


REPORT 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, 2011,2014, 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 overOver 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, 2011,2014, 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, 20112014 and 2010,2013, and the related consolidated statements of income (loss), changes inoperations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011 of W&T Offshore, Inc. and subsidiaries2014 and our report dated February 27, 2012March 6, 2015 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG

/s/ Ernst & Young, LLP

Houston, Texas

February 27, 2012

March 6, 2015

Index to Financial Statements

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, 20112014 and 2010,2013, and the related consolidated statements of income (loss),operations, changes in shareholders’shareholders' equity and cash flows for each of the three years in the period ended December 31, 2011.2014. These financial statements are the responsibility of the Company’sCompany'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, 20112014 and 2010,2013, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011,2014, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, in 2009 the Company changed its reserve estimates and related disclosures as a result of adopting new oil and natural gas reserve estimation and disclosure requirements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), W&T Offshore, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2011,2014, 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 February 27, 2012,March 6, 2015 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG

/s/ Ernst & Young, LLP

Houston, Texas

February 27, 2012

March 6, 2015

Index to Financial Statements

70


W&T OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

 

December 31,

 

 

2014

 

 

2013

 

Assets

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

$

23,666

 

 

$

15,800

 

Receivables:

 

 

 

 

 

 

 

Oil and natural gas sales

 

67,242

 

 

 

96,752

 

Joint interest and other

 

43,645

 

 

 

31,104

 

Total receivables

 

110,887

 

 

 

127,856

 

Deferred income taxes

 

11,662

 

 

 

584

 

Prepaid expenses and other assets

 

36,347

 

 

 

29,362

 

Total current assets

 

182,562

 

 

 

173,602

 

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

 

Furniture, fixtures and other

 

23,269

 

 

 

21,431

 

Total property and equipment

 

8,068,935

 

 

 

7,360,528

 

Less accumulated depreciation, depletion and amortization

 

5,575,078

 

 

 

5,084,704

 

Net property and equipment

 

2,493,857

 

 

 

2,275,824

 

Restricted deposits for asset retirement obligations

 

15,444

 

 

 

37,421

 

Other assets

 

17,244

 

 

 

20,455

 

Total assets

$

2,709,107

 

 

$

2,507,302

 

Liabilities and Shareholders' Equity

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accounts payable

$

194,109

 

 

$

145,212

 

Undistributed oil and natural gas proceeds

 

37,009

 

 

 

42,107

 

Asset retirement obligations

 

36,003

 

 

 

77,785

 

Accrued liabilities

 

17,377

 

 

 

28,000

 

Total current liabilities

 

284,498

 

 

 

293,104

 

Long-term debt, less current maturities

 

1,360,057

 

 

 

1,205,421

 

Asset retirement obligations, less current portion

 

354,565

 

 

 

276,637

 

Deferred income taxes

 

186,988

 

 

 

178,142

 

Other liabilities

 

13,691

 

 

 

13,388

 

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

 

Additional paid-in capital

 

414,580

 

 

 

403,564

 

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

 

 

   December 31, 
   2011  2010 
   (In thousands, except
share data)
 

Assets

   

Current assets:

   

Cash and cash equivalents

  $4,512   $28,655  

Receivables:

   

Oil and natural gas sales

   98,550    79,911  

Joint interest and other

   25,089    25,415  

Insurance

   715    1,014  
  

 

 

  

 

 

 

Total receivables

   124,354    106,340  

Deferred income taxes

   2,007    5,784  

Prepaid expenses and other assets

   30,315    23,426  
  

 

 

  

 

 

 

Total current assets

   161,188    164,205  

Property and equipment – at cost:

   

Oil and natural gas properties and equipment (full cost method, of which $154,516 at December 31, 2011 and $65,419 at December 31, 2010 were excluded from amortization)

   5,959,016    5,225,582  

Furniture, fixtures and other

   19,500    15,841  
  

 

 

  

 

 

 

Total property and equipment

   5,978,516    5,241,423  

Less accumulated depreciation, depletion and amortization

   4,320,410    4,021,395  
  

 

 

  

 

 

 

Net property and equipment

   1,658,106    1,220,028  

Restricted deposits for asset retirement obligations

   33,462    30,636  

Deferred income taxes

   —      2,819  

Other assets

   16,169    6,406  
  

 

 

  

 

 

 

Total assets

  $1,868,925   $1,424,094  
  

 

 

  

 

 

 

Liabilities and Shareholders’ Equity

   

Current liabilities:

   

Accounts payable

  $75,871   $80,442  

Undistributed oil and natural gas proceeds

   33,732    25,240  

Asset retirement obligations

   138,185    92,575  

Accrued liabilities

   29,705    25,827  

Income taxes payable

   10,392    17,552  
  

 

 

  

 

 

 

Total current liabilities

   287,885    241,636  

Long-term debt, less current maturities

   717,000    450,000  

Asset retirement obligations, less current portion

   255,695    298,741  

Deferred income taxes

   58,881    —    

Other liabilities

   4,890    11,974  

Commitments and contingencies

   —      —    

Shareholders’ equity:

   

Preferred stock, $0.00001 par value, 2,000,000 shares authorized and 0 issued at December 31, 2011 and at December 31, 2010

   —      —    

Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,220,706 issued and 74,351,533 outstanding at December 31, 2011; 77,343,520 issued and 74,474,347 outstanding at December 31, 2010;

   1    1  

Additional paid-in capital

   386,920    377,529  

Retained earnings

   181,820    68,380  

Treasury stock, at cost

   (24,167  (24,167
  

 

 

  

 

 

 

Total shareholders’ equity

   544,574    421,743  
  

 

 

  

 

 

 

Total liabilities and shareholders’ equity

  $1,868,925   $1,424,094  
  

 

 

  

 

 

 

See accompanying notes.

Index to Financial Statements

71


W&T OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)OPERATIONS

 

  Year Ended December 31, 
2011 2010 2009 

Year Ended December 31,

 

(In thousands, except per share data) 

2014

 

 

2013

 

 

2012

 

(In thousands except per share data)

 

Revenues

  $971,047   $705,783   $610,996  

$

948,708

 

 

$

984,088

 

 

$

874,491

 

  

 

  

 

  

 

 

Operating costs and expenses:

    

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

   219,206    169,670    203,922  

 

264,751

 

 

 

270,839

 

 

 

232,260

 

Production taxes

   4,275    1,194    1,544  

 

7,932

 

 

 

7,135

 

 

 

5,840

 

Gathering and transportation

   16,920    16,484    13,619  

 

19,821

 

 

 

17,510

 

 

 

14,878

 

Depreciation, depletion and amortization

   299,015    268,415    308,076  

 

490,469

 

 

 

430,611

 

 

 

336,177

 

Asset retirement obligation accretion

   29,771    25,685    34,461  

Impairment of oil and natural gas properties

   —      —      218,871  

Asset retirement obligations accretion

 

20,633

 

 

 

20,918

 

 

 

20,055

 

General and administrative expenses

   74,296    53,290    42,990  

 

86,999

 

 

 

81,874

 

 

 

82,017

 

Derivative (gain) loss

   (1,896  4,256    7,372  

 

(3,965

)

 

 

8,470

 

 

 

13,954

 

  

 

  

 

  

 

 

Total costs and expenses

   641,587    538,994    830,855  

 

886,640

 

 

 

837,357

 

 

 

705,181

 

  

 

  

 

  

 

 

Operating income (loss)

   329,460    166,789    (219,859

Operating income

 

62,068

 

 

 

146,731

 

 

 

169,310

 

Interest expense:

    

 

 

 

 

 

 

 

 

 

 

 

Incurred

   52,393    43,101    46,749  

 

86,922

 

 

 

85,639

 

 

 

63,268

 

Capitalized

   (9,877  (5,395  (6,662

 

(8,526

)

 

 

(10,058

)

 

 

(13,274

)

Loss on extinguishment of debt

   22,694    —      2,926  

Interest income

   84    710    842  
  

 

  

 

  

 

 

Other income, net

 

208

 

 

 

8,946

 

 

 

215

 

Income (loss) before income tax expense (benefit)

   264,334    129,793    (262,030

 

(16,120

)

 

 

80,096

 

 

 

119,531

 

Income tax expense (benefit)

   91,517    11,901    (74,111

 

(4,459

)

 

 

28,774

 

 

 

47,547

 

  

 

  

 

  

 

 

Net income (loss)

  $172,817   $117,892   $(187,919

$

(11,661

)

 

$

51,322

 

 

$

71,984

 

  

 

  

 

  

 

 

Basic and diluted earnings (loss) per common share

  $2.29   $1.58   $(2.51

$

(0.16

)

 

$

0.68

 

 

$

0.95

 

Weighted average common shares outstanding

   74,033    73,685    74,852  

See accompanying notes.

Index to Financial Statements

72


W&T OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

 

  Common Stock
Outstanding
  Additional
Paid-In
Capital
  Retained
Earnings
  Treasury Stock  Accumulated
Other
Comprehensive
Income (Loss)
  Total
Shareholders’
Equity
 
 Shares  Value    Shares  Value   
 (In thousands) 

Balances at December 31, 2008

  76,291   $1   $372,595   $200,274    —     $—     $(643 $572,227  

Cash dividends:

        

Common stock ($0.12 per share)

  —      —      (6,861  (2,289  —      —      —      (9,150

Share-based compensation

  —      —      6,380    —      —      —      —      6,380  

Restricted stock issued, net of forfeitures

  1,471    —      3,014    —      —      —      —      3,014  

Shares surrendered for payroll taxes

  (182  —      (2,078  —      —      —      —      (2,078

Repurchase of common stock

  (2,869  —      —      —      2,869    (24,167  —      (24,167

Other comprehensive income, net of tax

  —      —      —      —      —      —      643    643  

Net loss

  —      —      —      (187,919  —      —      —      (187,919
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balances at December 31, 2009

  74,711   $1   $373,050   $10,066    2,869   $(24,167 $—     $358,950  

Cash dividends:

        

Common stock regular ($0.14 per share)

  —      —      —      (10,446  —      —      —      (10,446

Common stock special ($0.66 per share)

  —      —      —      (49,132  —      —      —      (49,132

Share-based compensation

  —      —      5,533    —      —      —      —      5,533  

Restricted stock issued, net of forfeitures

  (95  —      1,357    —      —      —      —      1,357  

Shares surrendered for payroll taxes

  (142  —      (2,411  —      —      —      —      (2,411

Net income

  —      —      —      117,892    —      —      —      117,892  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balances at December 31, 2010

  74,474   $1   $377,529   $68,380    2,869   $(24,167 $—     $421,743  

Cash dividends:

        

Common stock regular ($0.16 per share)

  —      —      —      (11,913  —      —      —      (11,913

Common stock special ($0.63 per share)

  —      —      —      (46,842  —      —      —      (46,842

Share-based compensation

  —      —      9,710    —      —      —      —      9,710  

Restricted stock issued, net of forfeitures

  (13  —      —      —      —      —      —      —    

Shares surrendered for payroll taxes

  (109  —      (2,073  —      —      —      —      (2,073

Other

  —      —      1,754    (622  —      —      —      1,132  

Net income

  —      —      —      172,817    —      —      —      172,817  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balances at December 31, 2011

  74,352   $1   $386,920   $181,820    2,869   $(24,167 $—     $544,574  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 

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

 

See accompanying notes.

Index to Financial Statements

73


W&T OFFSHORE, INC. AND SUBSIDIARIESOffshore, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

  Year Ended December 31, 

Year Ended December 31,

 

  2011 2010 2009 

2014

 

 

2013

 

 

2012

 

  (In thousands) 

(In thousands)

 

Operating activities:

    

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

  $172,817   $117,892   $(187,919

$

(11,661

)

 

$

51,322

 

 

$

71,984

 

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

    

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

   328,786    294,100    345,637  

 

511,102

 

 

 

451,529

 

 

 

356,232

 

Impairment of oil and natural gas properties

   —      —      218,871  

Amortization of debt issuance costs and discount on indebtedness

   2,010    1,338    1,838  

Loss on extinguishment of debt

   22,694    —      2,817  

Amortization of debt issuance costs and premium

 

701

 

 

 

1,645

 

 

 

2,575

 

Share-based compensation

   9,710    5,533    6,380  

 

14,744

 

 

 

11,525

 

 

 

12,398

 

Derivative (gain) loss

   (1,896  4,256    7,372  

 

(3,965

)

 

 

8,470

 

 

 

13,954

 

Cash payments on derivative settlements

   (9,873  874    (6,679

Cash payments on derivative settlements, net

 

(5,318

)

 

 

(8,589

)

 

 

(7,664

)

Deferred income taxes

   61,835    (8,266  (346

 

(4,760

)

 

 

30,920

 

 

 

88,109

 

Other

   —      —      998  

Changes in operating assets and liabilities:

    

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas receivables

   (18,639  (24,933  (18,509

 

29,510

 

 

 

980

 

 

 

818

 

Joint interest and other receivables

   375    25,897    31,866  

 

(4,255

)

 

 

34,257

 

 

 

(28,823

)

Insurance receivables

   20,771    54,873    23,235  

Income taxes

   (7,124  104,067    (52,100

 

3,143

 

 

 

44,328

 

 

 

(58,011

)

Prepaid expenses and other assets

   (7,809  4,536    (749

 

15,012

 

 

 

(10,044

)

 

 

7,440

 

Asset retirement obligations

   (59,958  (87,166  (99,069

Accounts payable and accrued liabilities

   7,881    (31,885  (117,230

Other liabilities

   (102  3,656    (147
  

 

  

 

  

 

 

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

   521,478    464,772    156,266  

 

511,423

 

 

 

561,358

 

 

 

385,137

 

  

 

  

 

  

 

 

Investing activities:

    

 

 

 

 

 

 

 

 

 

 

 

Acquisition of property interest in oil and natural gas properties

   (437,247  (236,944  (2,421

 

(72,234

)

 

 

(82,424

)

 

 

(205,550

)

Investment in oil and natural gas properties and equipment

   (281,779  (178,709  (273,713

 

(554,378

)

 

 

(551,954

)

 

 

(479,313

)

Proceeds from sales of oil and natural gas properties and equipment

   15    1,420    32,226  

Proceeds from insurance

   —      —      6,916  

Purchases of furniture, fixtures and other, net

   (3,660  (760  (705
  

 

  

 

  

 

 

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

   (722,671  (414,993  (237,697

 

(629,952

)

 

 

(614,805

)

 

 

(657,441

)

  

 

  

 

  

 

 

Financing activities:

    

 

 

 

 

 

 

 

 

 

 

 

Issuance of 8.5% Senior Notes

   600,000    —      —    

Repurchase of 8.25% Senior Notes

   (450,000  —      —    

Borrowings of long-term debt – revolving bank credit facility

   623,000    627,500    205,441  

Repayments of long-term debt – revolving bank credit facility

   (506,000  (627,500  (410,941

Repurchase premium and debt issuance costs

   (32,288  —      —    

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

   (58,756  (59,609  (9,158

 

(30,260

)

 

 

(58,846

)

 

 

(82,832

)

Repurchases of common stock

   —      —      (24,167

Other

   1,094    298    891  

 

(345

)

 

 

(260

)

 

 

379

 

  

 

  

 

  

 

 

Net cash provided by (used in) financing activities

   177,050    (59,311  (237,934
  

 

  

 

  

 

 

Decrease in cash and cash equivalents

   (24,143  (9,532  (319,365

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

   28,655    38,187    357,552  

 

15,800

 

 

 

12,245

 

 

 

4,512

 

  

 

  

 

  

 

 

Cash and cash equivalents, end of period

  $4,512   $28,655   $38,187  

$

23,666

 

 

$

15,800

 

 

$

12,245

 

  

 

  

 

  

 

 

See accompanying notes.

Index to Financial Statements


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”&T,” “we,”, “us,” “our,” or the “Company,”“Company”, is an independent oil and natural gas producer focused primarily in the Gulf of Mexico and more recently, onshore Texas.  The Company is active in the acquisition, exploration, development and developmentacquisition 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-own 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 ownedmajority-owned subsidiaries.  All significant intercompany transactions and amounts have been eliminated for all years presented.

Reclassifications

Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation. In Note 13, certain state incomepresentation as follows:   Income tax items were previously reported separately and are now– receivables was combined with Joint interest and other items due to being immaterial. In Note 22, reserve information related to oil– receivables on 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 interest and natural gas liquids (“NGLs”) is reported separately due toother receivables and changes in Other – operating assets and liabilities was combined with the increasechanges in NGLs as a percentAccounts payable, accrued liabilities and other on the Consolidated Statements of total reserves and these had been combined in prior periods. The historical information was modified to report oil and NGLs separately for comparability to the current year’s information.Cash Flows.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“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.

Fiscal YearRecent Events

Our fiscal year endsThe price we receive for our 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 June 2014 and were significantly lower in January and February of 2015 compared to the last few years.  

We have taken several steps to mitigate the effects of these lower prices including: (i) significantly reducing the 2015 capital budget from the previous year; (ii) suspending our drilling and completion activities at several locations; (iii) suspending the regular quarterly common stock dividend and (iv) implementing numerous cost reduction projects to reduce our operating costs.  

Assuming continuing oil and gas prices are 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 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, and we may have to reduce our cash outlays further for capital expenditures and other activities until such time as market conditions recover.  

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.

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 December 31.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 has taken less than its ownership share of production.  At both December 31, 20112014 and 2010, $6.52013, $6.4 million and $6.5 million, respectively, werewas included in current liabilities related to natural gas imbalances.

Index to Financial Statements

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.  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 except in rare circumstances.  Accordingly, we do not maintain an allowance for doubtful accounts.accounts of any material amounts.

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

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Customer

 

 

 

 

 

 

 

 

 

 

 

Shell Trading (US) Co.

 

47

%

 

 

48

%

 

 

35

%

ConocoPhillips (1)

**

 

 

**

 

 

 

16

%

 

   Year Ended December 31, 
  2011  2010  2009 

Customer

    

Shell Trading (US) Co.

   36  40  34

ConocoPhillips

   16  17  *

J.P. Morgan Ventures Energy Corp.

   10  *  15

Chevron Corp.

   *  *  13

**

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’ adjuster reviews and approves such costs for payment by the underwriters.  Claims that have been processed in this manner have customarily been paid on a timely basis.  See Note 18 for information related to unpaid claims by certain underwriters.

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 property.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 has 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 expenditures made in connection with the exploration and developmentamount 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.  We capitalized $9.9 million, $5.4 million and $6.7 millionCapitalization of interest expense duringceases when the years 2011, 2010,property is moved into the amortization base.  All capitalized interest is recorded within Oil and 2009, respectively.

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIESnatural gas property and equipment

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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.  These additionalFuture development costs related to developing proved reserves are not recorded as liabilities on the balance sheet.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.

Under the full cost method of accounting, we are required to periodically perform a “ceiling test,” 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: (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,amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base, net ofbase; and (iv) less related tax effects, the excess is charged to expense and reflected as additional accumulated depreciation, depletion and amortization. Any such write downs are not recoverable or reversible in future periods.effects.  Estimated future net revenues used in the ceiling test as of December 31, 2011, 2010 and 2009for each year are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for that yearyear.  All prices are adjusted by field for quality, transportation fees, energy content and exclude future cash outflows related to capitalized ARO and include future development costs and ARO related to wells to be drilled.regional price differentials.

For77


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Declines in the ceiling test asunweighted rolling average of March 31, 2009,first-day-of-the-month commodity prices were based on the end-of-the-period prices using guidance effective for that reporting period. We recorded a ceiling test impairment in 2009 of $218.9 million primarily as a result of a decline in natural gas prices as of March 31, 2009. Declines in oil and natural gas prices after December 31, 20112014 may require us to record additional ceiling testceiling-test impairments in the future.  We did not have a ceiling test impairmentany write-downs related to ceiling-test impairments during the years 20112014, 2013 and 2010,2012, 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.

Asset Retirement Obligations

Pursuant to theAsset Retirement and Environmental Obligations topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (the “Codification”),GAAP, 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 clean up.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.

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Oil and Natural Gas Reserve Information

In January 2010, the FASB issued certain amendmentsPursuant to theExtractive Activities – Oil and Gas topic of the Codification that updated and aligned the FASB’s reserve estimation and disclosure requirements for oil and natural gas companies with the reserve estimation and disclosure requirements that were adopted by the Securities and Exchange Commission (“SEC”) in December 2008. The FASB’s amendments and the SEC’s new requirements became effective for annual reporting periods ending on or after December 31, 2009. Collectively, the new rules permit the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Other definitions and terms were revised, including the definition ofproved reserves which was changed to indicate, among other things, that commencing with year-end 2009 entities mustGAAP, we use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period rather than end-of-period commodity prices, 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 have been changed from end-of-period commodity prices toare the 12-month average commodity prices.  Also, because it is our policy to use end-of-period reserves in the determination of quarterly depletion, our depreciation, depletion, amortization and accretion expense for the fourth quarter of 2009, each of the quarters of 2010 and each of the quarters of 2011 were calculated using proved reserves that were determined in accordance with the new rules. Additionally, entities must separately disclose information about reserve quantities and certain financial statement amounts for geographic areas that represent 15% or more of proved reserves, and equity-method investees should be included in determining whether an entity has significant oil and gas producing activities. Another significant provision of the new rulesguidance is a general requirement that, subject to limited exceptions, 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.  Refer to Note 2221 for additional information about our proved reserves and the impact of the new reserve estimation and disclosure requirements.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.  Our derivative instruments currently consist of commodity swap and option contracts for oil.  We do not enter into derivative instruments for speculative trading purposes.

We account for derivative contracts inIn accordance with theDerivatives and Hedging topic of the Codification, which requires eachGAAP, a derivative to beis 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.  We have elected 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.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 facility approximates fair value because the interest rates are variable and reflective of market rates.

Index to Financial Statements
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

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 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.

Deferred FinancingDebt Issuance Costs

Debt issuance costs associated with our revolving loan 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.

Premiums Received on Debt Issuance

Premiums are recorded in long-term liabilities and are amortized over the term of the related debt using the effective interest method.

Share-Based Compensation

In accordance with theCompensation – Stock Compensation topic of the Codification,GAAP, 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.  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 11 for more information.

Earnings (Loss) Per Share

In accordance with theEarnings Per Share topic of the Codification,GAAP, unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall beare included in the computation of earnings per share under the two-class method.  For additional information, refer to Note 14.

Recent Accounting DevelopmentsOther Income, Net

In addition toFor 2013, the amendments toamount reported consisted primarily of $9.2 million received in conjunction with a payment for an option exercised by a counterparty.  Partially offsetting theExtractive Activities – Oil proceeds were related third-party expenses of $0.1 million.  The net amount was included in net cash flows from investing activities within the line, Proceeds from sales of assets and Gas topicother, net in the consolidated statements of the Codification that were previously discussed, the following recent accounting developments are applicable to the Company.

In December 2010, the FASB issued certain amendments to theBusiness Combinationstopic of the Codification. The amendments specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual period only. In addition, the supplemental pro forma disclosures were expanded related to pro forma adjustments. The amendments are effective for our fiscal year ended December 31, 2011. Early adoption was permitted and we elected to apply the amendments for the year 2010. These amendments only change disclosure requirements and not accounting practices; therefore, the adoption of these amendments did not have any impact on our financial position, results of operations or cash flows.

Previously issued amendments to theBusiness Combination topic became effective January 1, 2009, that require the acquiring entity in a business combination to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their respective fair values at the acquisition date. These amendments require the acquirer to record the fair value of contingent consideration (if any) at the acquisition date. Acquisition-related costs incurred prior to an acquisition are required to be expensed rather than included in79


Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

Recent Accounting Developments

In May 2014, the purchase-price determination. Also includedFinancial 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 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.  Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the amendments areinitial period of application.  We have not determined the effect 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 in the first quarter of 2017.

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 recognizingthe annual period ending after December 15, 2016, and measuringfor annual and interim periods thereafter.  We do not expect the goodwill acquired inrevised guidance to materially affect our evaluation as to being a business combination and guidance for determining what information to disclose to enable users of thegoing concern, or have an effect on our financial statements to evaluate the natureor related disclosures.

2. Acquisitions and financial effects of a business combination. These amendments apply prospectively to business combinations occurring on or after January 1, 2009. The adoption of these amendments did not have a material impact on the Company’s financial statements.Divestitures

2.2014 Acquisitions

2011 AcquisitionsFairway

On May 11, 2011, we completedSeptember 15, 2014, the acquisition of approximately 24,500 gross acres (21,900 net acres) of oil and gas leasehold interestsParent Company entered into an asset purchase agreement with a third party to increase its ownership interest from 64.3% to 100% in the West Texas Permian BasinMobile Bay blocks 113 and 132 located offshore Alabama (the “Yellow Rose Properties”“Fairway Field”) from Opal Resources LLC and Opal Resources Operating Company LLC (collectively, “Opal”). The cash component of the stated purchase price was $366.3 million, subject to certain adjustments, including adjustments from an effective date of January 1, 2011 until the closing date of May 11, 2011. Taking into account such adjustments, the adjusted cash component of the purchase price was $394.4 million. The increase of $28.1 million primarily reflects drilling costs in excess of cash flow from the effective date of January 1, 2011 to the closing date. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.

The following table presents the purchase price allocation for the acquisition of the Yellow Rose Properties (in thousands):

Oil and natural gas properties and equipment (1)

  $396,902  

Asset retirement obligations – non-current

   (382

Long-term liability

   (2,143
  

 

 

 

Total cash paid

  $394,377  
  

 

 

 

(1)At the acquisition date, $84.7 million was recorded as unproved properties. During 2011, this amount was increased by $4.5 million due to capitalized interest and decreased by $3.5 million due to reclassifications to proved properties resulting in $85.7 million in unproved properties as of December 31, 2011 for the Yellow Rose Properties. Amounts recorded as unproved properties are excluded from the full cost pool and amortization base.

On August 10, 2011, we completed the acquisition of Shell Offshore Inc.’s (“Shell”) 64.3% interest in the Fairway Field along with a like interest in the associated Yellowhammer gas treatmentprocessing plant (collectively, the “Fairway Properties”“Fairway”).  The cash componentFairway 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 statedtransaction 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 $55.0 million, subject to certain adjustments, including adjustments from an effective datefinalized during the fourth quarter of September 1, 2010 until the closing date of August 10, 2011. Taking into account such adjustments, as of December 31, 2011, the cash component of the purchase price was $42.9 million. The decrease of $12.1 million primarily reflects net production cash flow, partially offset by plugging and abandonment costs incurred, from the effective date of September 1, 2010 to the closing date. The purchase price is subject to further post-effective date adjustments and final settlement is expected to occur in the first half of 2012. We assumed the asset retirement obligations associated with the properties, which we have estimated to be $7.8 million.2014.  The acquisition was funded from borrowings under our revolving bank credit facility.facility and cash on hand.

IndexThe 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 Financial Statements

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

The following table presents the purchase price allocation, including estimated adjustments, for the acquisition of the FairwayWoodside 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

 

 

Oil and natural gas properties and equipment

  $50,682  

Asset retirement obligations – non-current

   (7,812
  

 

 

 

Total cash paid

  $42,870  
  

 

 

 

Expenses associatedThe 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 acquisition activities and transition activities related to the Yellow Rose and Fairway acquisitions for the year 2011 were $1.6 million and are included in general and administrative expenses.Woodside Properties acquisition.

Revenue,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 year 2011,period of May 20, 2014 to December 31, 2014, the Yellow Rose Properties and the FairwayWoodside Properties accounted for $64.0$28.4 million of revenue, $25.5revenues, $5.5 million of direct operating expenses, $20.5$11.0 million of depreciation, depletion, amortizationDD&A and accretion (“DD&A”) and $6.3$4.2 million of income taxes, resulting in $11.7$7.7 million of net income. Such amounts are for the period from each respective close date to December 31, 2011.  The net income attributable to these propertiesthe 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 Yellow RoseWoodside 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 FairwayWoodside 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, natural gas liquids (“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)

 

 

 

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

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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)

 

 

 

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

 

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 $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.

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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 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.

Pro forma financial information has been prepared since the Yellow Rose Properties constitute a significant acquisition. The Fairway Properties acquisition, which was not significant, was combined with the Yellow Rose Properties to disclose the effect of both acquisitions upon our results of operations. The unaudited pro forma financial information presented below was computed as if these two acquisitionsthe acquisition of the Callon Properties had been completed on January 1, 2010.2012.  The historical financial information iswas derived from theW&T’s audited historical consolidated financial statements, of W&Tthe Callon Properties’ audited historical financial statement, and the Callon Properties’ unaudited historical statements offinancial statement for the sellers.periods presented.

The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Yellow Rose Properties and the FairwayCallon Properties.  The pro forma financial information is not necessarily indicative of the results of operations had the respective purchasespurchase occurred on January 1, 2010.2012.  If the transactionstransaction 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 sellers, realized sales prices for oil, NGLs and natural gas sales prices may have been differentdifferent; and the costs of operating the propertiesCallon 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

 

 

   (unaudited)
Year Ended December 31,
 
   2011   2010 

Revenue

  $1,023,430    $784,964  

Net income (loss)

   180,779     113,783  

Basic and diluted earnings (loss) per common share

   2.39     1.52  

The purchase price of both acquisitions may be subject to further adjustments.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the pro forma financial information, we assumedcertain information was derived from financial records and certain information was estimated.  The following table presents incremental items included in the transactions were financed with borrowings from the revolving bank credit facility because the cash and cash equivalents balancespro forma information reported above for the assumed acquisition date was less than the cashCallon 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 cashsignificant assumptions are described below:

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

equivalents on hand used on the actual closing dates of the two acquisitions. Also, we assumed that the revolving bank credit facility capacity would have been increased due to the increase in reserves.

The following adjustments were made in the preparation of the financial information:

(a)

(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)

Revenues and direct operating expenses for the Yellow Rose Properties and the FairwayCallon Properties were derived from the historical financial records of the sellers up to the respective closing dates.Callon.

(c)

(b)

DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Yellow Rose Properties and FairwayCallon Properties’ costs, reserves and production into our currently existing full cost pool in order to compute such amounts.  The purchase price allocation included $81.2 million that was allocated to the pool of unevaluated properties for oil and natural gas interests. Accordingly, nointerests was excluded from the DD&A expense estimation.  ARO was estimated for the unevaluated properties.

(c)Asset retirement obligations and related accretion were estimated by W&T management.

(d)

(d)Incremental

G&A adjustments related to incremental transaction expenses, related to the acquisitions completed during 2011 were $1.6 million andwhich were assumed to be funded from cash on hand.hand, and were adjusted from the 2013 results.

(e)

(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 that were in effect during the applicable time period and we assumed that six-month London Interbank Offered Rate (“LIBOR”)applied to incremental borrowings were made as allowed underon 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 interest rates rangedborrowings.  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, we sold our working interests in the West Delta area block 29 with an effective date of January 1, 2013.  The property is located in the Gulf of Mexico.  Including adjustments 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 structured as a like-kind exchange under 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.

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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 acquisition 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 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 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 3.1%January 1, 2012 to 3.5%. A reductionOctober 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 revolving bank credit facility commitment feeDD&A expense estimation.  ARO was estimated by W&T management.

(e)

G&A adjustments related to theincremental 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 was netted againstof $205.8 million, which equates to the computed incrementalcash component of the transaction, and an interest expense.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)

(f)

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)

(g)

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

2010 AcquisitionsThe pro forma adjustments do not included adjustments related to any other acquisitions or divestitures.

During 2010, we closed on two acquisition transactions. The first acquisition closed on April 30, 2010. Through our wholly-owned subsidiary, 86


W&T Energy VI, LLC (“Energy VI”)OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2012 Divestiture

On May 15, 2012, we sold our 40%, we acquired all of Total E&P USA’s (“Total”)non-operated working interest including production platforms and facilities, in three federal offshore lease blocksthe 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 assumedother 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 ARO for plugging and abandonment ofreplacement periods as defined under the acquired interests. The adjusted purchase price was $121.3IRC.  In connection with this sale, we reversed $4.0 million inclusive of ARO. There were no adjustments to the purchase price in 2011. The properties acquired from Total (the “Matterhorn/Virgo Properties”) are producing interests and include a 100% working interest in the Matterhorn field (Mississippi Canyon block 243) and a 64% working interest in the Virgo field (Viosca Knoll blocks 822 and 823). The second acquisition closed on November 4, 2010. Through Energy VI, we acquired all of Shell’s interests, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico and assumed the ARO for plugging and abandonment of the acquired interests. The adjusted purchase price recorded in 2010 was $139.9 million inclusive of ARO. In 2011, the adjusted purchase price inclusive of ARO was subsequently reduced to $134.2 million due to settlement adjustments of $5.7 million determined and received in 2011. The properties acquired from Shell (the “Tahoe/Droshky Properties”) are producing interests and include a 70% working interest in the Tahoe field (Viosca Knoll 783), 100% working interest in the Southeast Tahoe field (Viosca Knoll 784) and a 6.25% of 8/8ths overriding royalty interest in the Droshky field (Green Canyon 244).

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table presents the purchase price allocation for the acquisition of the Matterhorn/Virgo Properties (in thousands):

Oil and natural gas properties and equipment

  $121,301  

Asset retirement obligations – non-current

   (6,289
  

 

 

 

Total cash paid

  $115,012  
  

 

 

 

The following table presents the purchase price allocation for the acquisition of the Tahoe/Droshky Properties (in thousands):

Oil and natural gas properties and equipment

  $134,189  

Asset retirement obligations – non-current

   (17,956
  

 

 

 

Total cash paid

  $116,233  
  

 

 

 

3. Hurricane Remediation and Insurance Claims

During the third quarter of 2008, Hurricane Ike and,caused substantial damage to a much lesser extent, Hurricane Gustav caused property damage and disruptions tocertain of our exploration and production activities.properties.  Our insurance policies in effect on the occurrence datesdate of HurricanesHurricane Ike and Gustav had a retention requirement of $10.0 million per occurrence, to bewhich has been satisfied, by us before we could be indemnified for losses. In the fourth quarter of 2008, we satisfied our $10.0 million retention requirement for Hurricane Ike in connection with two platforms that were toppled and were deemed total losses. Our insurance coverage policy limits at the time of Hurricane Ike were $150.0 million for property damage due to named windstorms (excluding damage at certain damage incurred at our facilities of marginal significance)facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority. The damage

For 2014, 2013 and 2012, we incurredhave 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 a resultreductions in Oil and natural gas properties and equipment on the Consolidated Balance Sheets, with minor amounts recorded as reductions in Lease operating expense in the Consolidated Statements of Hurricane Gustav was below our retention amount.

Below is a summary of remediation costs and amounts approved for payments related to Hurricanes Ike and Gustav that were included in lease operating expense (in thousands), with bracketed amounts representing credits to expense:

   Year Ended December 31, 
   2011  2010  2009 

Incurred and reversals of accruals

  $132   $(1,380 $37,062  

Plus amounts returned to insurers

   1,241    —      —    

Less amounts approved for payment by insurers

   (1,334  (10,350  (18,683
  

 

 

  

 

 

  

 

 

 

Included in lease operating expenses

  $39   $(11,730 $18,379  
  

 

 

  

 

 

  

 

 

 

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’ adjuster reviews and approves such costs for payment by the underwriters. Claims that have been processed in this manner have customarily been paid on a timely basis. Incurred expenses included revisions of previous estimates. Amounts in 2011 include return of reimbursements that were previously received by us related to prepayments based on preliminary estimates. In 2010, incurred expenses were a credit due to revisions of previous estimates. See Note 5 for additional information about the impact of hurricane related items on our asset retirement obligations.

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Below is a reconciliation of our insurance receivables (in thousands):

Balance, December 31, 2010

  $1,014  

Costs approved under our insurance policies, net

   20,566  

Payments received, net

   (20,865
  

 

 

 

Balance, December 31, 2011

  $715  
  

 

 

 

At December 31, 2011 and December 31, 2010, substantially all of the amounts in insurance receivables relate to the plugging and abandonment of wells and dismantlement of facilities damaged by Hurricane Ike.

Operations.  From the third quarter of 2008 through December 31, 2011,2014, we have received $139.3$161.2 million cumulative from our insurance carrierunderwriters related to Hurricane Ike.  To the extent that additional remediation cost or plug and abandonment costs are incurred that are not covered by insurance, we expect that our available cash and cash equivalents, cash flow from operationsSee Note 18 for information regarding legal actions involving certain insurers and the availability under our revolving bank credit facility will be sufficientCompany concerning claims related to meet necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricane Ike.Ike damages.

4. Restricted Deposits

Restricted deposits as of December 31, 20112014 and 20102013 consisted of funds escrowed for the future plugging and abandonment of certain oil and natural gas properties. We are not obligated

Pursuant to contribute additional amounts to these escrowed accounts, except for an arrangementthe Purchase and Sale Agreement with Total where we areE&P USA Inc. (“Total E&P”), security for future plugging and abandonment of certain oil and natural gas properties is required to make annual increases in the security amount.

The arrangement with Total requires security either through bonds or payments to an escrow account in accordance with the Purchase and Sale Agreement. Pursuant to the Purchase and Sale Agreement, monthlyor a combination thereof.  Monthly payments are made to an escrow account for our overriding royalty interests related to the Droshky field and these funds are returned to us once verification is made as to fulfillingthat the security requirements. In addition, funds are returned as asset retirement obligations are fulfilled.amount requirements have been met.  We were in compliance with the security requirements as of December 31, 2011 and have provided funds to fulfill our security requirement for December 31, 2012.2014.  See Note 1716 for potential future security requirements.

5. Asset Retirement Obligations

Pursuant to theAsset Retirement and Environmental Obligations topic of the Codification,GAAP, an asset retirement obligation associated with the retirement of a tangible long-lived asset is 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.

Index to Financial Statements
87


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

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

 

 

   2011  2010 

Asset retirement obligation, beginning of period

  $391,316   $348,800  

Liabilities settled

   (59,958  (87,166

Accretion of discount

   29,771    25,685  

Disposition of properties

   —      (2,070

Liabilities assumed through acquisition

   8,194    24,477  

Liabilities incurred

   565    503  

Revisions of estimated liabilities due to Hurricane Ike

   4,744    41,952  

Revisions of estimated liabilities due to NTL 2010-G05 (1)

   —      18,725  

Revisions of estimated liabilities – all other

   19,248    20,410  
  

 

 

  

 

 

 

Asset retirement obligation, end of period

   393,880    391,316  

Less current portion

   138,185    92,575  
  

 

 

  

 

 

 

Long-term

  $255,695   $298,741  
  

 

 

  

 

 

 

(1)NTL No. 2010-G05,“Decommissioning Guidance for Wells and Platforms” issued by the Bureau of Ocean Energy Management (“BOEM”) (a) on September 15, 2010 and effective as of October 15, 2010, requires us to decommission any wells and platforms that have not been used during the past five years for exploration or production on active leases and are no longer capable of producing in paying quantities within three years. The accelerated time frame causes our estimated liabilities for ARO to be incurred in earlier periods, resulting in a higher present value of such liabilities.

(a)In June 2010, the Minerals Management Service changed its name to the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”). In October 2011, the BOEMRE was split into three separate entities: the Office of Natural Resources Revenue (“ONRR”), which assumed the functions of the Minerals Revenue Management Program; the BOEM, which is responsible for managing development of the nation’s offshore resources in an environmentally and economically responsible way; and the Bureau of Safety and Environmental Enforcement (“BSEE”), which is responsible for enforcement of safety and environmental regulations.

Each year (or more often if conditions warrant)During 2014, we review and, to the extent necessary, reviseincreased our ARO estimates. During 2011, we reducedon an overall basis primarily due 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.  Increases related to acquisitions include the increase in our ARO by $60.0 millionownership interest at Fairway, 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 (including $23.0 million to plug and abandon wells and facilities damaged by Hurricane Ike). Offsetting this decrease were the acquisitions of properties, including the Yellow Rose Properties and the Fairway Properties, which increased our obligations by $8.2 million. In addition, revisions were made related to Hurricane Ike, which increased the liability by $4.7 million. Other estimates were increased by $19.2 million primarily attributable to changes in estimates for non-operated properties and accelerating the expected timingdisposition of performing the work.certain properties.  

During 2010,2013, we reduced our ARO by $87.2 million foron an overall basis primarily due to the plug and abandonment work performed during the year (including $62.9 million to plug and abandon wells and facilities damaged by Hurricane Ike). Offsetting this decrease were the acquisitions of properties, including the properties from Total and Shell, which increased our obligations by $24.5 million.year.  In addition, revisions were made relatedthe disposition of certain properties, as described in Note 2, reduced our ARO.  The acquisition of the Callon Properties and drilling activity caused ARO to Hurricane Ikeincrease.  Revisions that increased ARO on a net basis primarily attributable to: a) regulation interpretations issued by the BSEE, which increased the liability by $42.0 million and there was an $18.7 million increase relatedamount of work involved, b) revisions to a change in regulation, which accelerated the decommissioning ofthird-party contractor estimated prices for certain work on wells and platforms. Other estimates were increased by $20.4 million primarily due to an increase instructures, c) revisions accelerating the scopetiming of planned work for certain wells and time requiredd) 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 and operated properties and changes to estimates in useful lives.

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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.  We do not enter intoAll of the derivative instruments for speculative trading purposes. Our derivative instruments currently consistcounterparties are also lenders or affiliates of commodity swap and option contracts.lenders participating in our revolving bank credit facility.  We are exposed to credit loss in the event of nonperformance by the counterparties (Natixis; ING Capital Markets, LLC-EDP; the Toronto Dominion Bank; and BNP Paribas Corporate and Investment Banking);derivative counterparties; however, we do not currently anticipate anythat each of our derivative counterparties being unablewill 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 is recordedcontract on the balance sheet as an asset or a liability at its fair value.  Changes in a derivative’s fair value are requiredWe have elected not to be recognized currently in earnings unless specific hedge accounting criteria are met at the time we enter into adesignate our commodity derivative contract. We do not attempt to qualify our derivatives for hedge accounting under GAAP;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 additional 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 2011the years ended December 31, 2014, 2013 and 2010,2012, we entered into commodity optionderivative contracts and these contracts consisted entirely of crude oil swap contracts to manage a portion of our exposure to commodity price risk from sales of oil through December 31, 2014.contracts.  While these contracts arewere intended to reduce the effects of price volatility, they may also limit futurehave limited income from favorable price movements.  AsThe crude oil swap contracts were comprised of December 31, 2011, our open commodity derivatives were as follows:

Zero Cost Collars – Oil

 

Termination Period

  Notional
Quantity (Bbls)
   Weighted Average
Contract Price
   Fair Value
Liability
(in thousands)
 
    Floor   Ceiling   

2012:                 1st quarter

   364,000    $75.00    $97.88    $1,735  

                           2nd quarter

   364,000     75.00     97.88     2,707  

                           3rd quarter

   124,000     75.00     97.88     972  

                           4th quarter

   251,000     75.00     98.99     1,785  
    

 

 

       

 

 

 
     1,103,000    $75.00    $98.13    $7,199  
    

 

 

       

 

 

 

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Swaps – Oil

 


Termination Period

  Notional
Quantity (Bbls)
   Weighted
Average

Contract  Price
   Fair Value
Net Asset
(in thousands)
 

2012:                1st quarter

   236,600    $107.28    $124  

                          2nd quarter

   200,200     107.28     294  

                          3rd quarter

   414,000     107.28     1,023  

                          4th quarter

   257,600     107.28     901  

2013:                1st quarter

   351,000     101.97     (171

                          2nd quarter

   336,700     101.97     217  

                          3rd quarter

   312,800     101.98     543  

                          4th quarter

   294,400     101.98     820  

2014:                1st quarter

   180,000     97.38     (125

                          2nd quarter

   172,900     97.38     39  

                          3rd quarter

   165,600     97.38     161  

                          4th quarter

   156,400     97.37     261  
    

 

 

     

 

 

 
     3,078,200    $102.87    $4,087  
    

 

 

     

 

 

 

At December 31, 2011, $7.2 million was included inAccrued liabilities, $2.3 million was included inPrepaid and other assets and $1.8 million was included inOther assets related to the fair value of our commodity derivative contracts. At December 31, 2010, $9.5 million was included inAccrued liabilities and $5.4 million was included inOther long-term liabilities related to the fair value of our commodity derivative contracts. The zero cost collars are priced off thea portion based on Brent crude oil prices, a portion based on West Texas Intermediate (“WTI”) crude oil price quotedprices and a portion based on the New York Mercantile Exchange and the swaps areLight Louisiana Sweet (“LLS”) crude oil prices.  The Brent based swap contracts were priced off the Brent crude oil price quoted on the IntercontinentalExchange,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. Ourearnings 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 gainsettlements, 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 year 2011 includes a realized lossterms of $9.9 millionthe agreements provided for offsetting of amounts payable or receivable between us and an unrealized gainthe counterparty, at the election of $11.8 million, related to our commodity derivatives. Our derivative lossboth parties, for transactions that occur on the year 2010 includes a realized gain of $5.5 millionsame date and an unrealized loss of $9.5 million, related to our commodity derivatives. Our derivative loss for the year 2009 includes realized and unrealized losses of $0.2 million and $5.4 million, respectively, related to our commodity derivatives.

Interest Rate Swap

Changes in the fair valuesame 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 settlement of our interest derivative instruments.  If we were required to settle all of our open derivative instruments, we would have been able to net payments 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 are also recognized currently in earnings. Our interest rate swap contract with a fixed interest rate of 5.21% expired in August 2010. During 2010, we recognizedas either an unrealized gain of $4.4 million and a realized loss of $4.7 million for this contract. During 2009, we recognized an unrealized gain of $4.7 million and a realized loss of $6.5 million for this contract.asset or liability.

Index to Financial Statements
89


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

There were no open derivative contracts as of December 31, 2014.  The following table provides a reconciliation of the gross assets and liabilities 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, 20112014 and 20102013, our long-term debt was as follows (in thousands):

   December 31, 
   2011   2010 

8.5% Senior Notes, due June 2019

  $600,000    $—    

8.25% Senior Notes, due June 2014

   —       450,000  

Revolving bank credit facility due May 2015

   117,000     —    
  

 

 

   

 

 

 

Total long-term debt

   717,000     450,000  

Current maturities of long-term debt

   —       —    
  

 

 

   

 

 

 

Long-term debt, less current maturities

  $717,000    $450,000  
  

 

 

   

 

 

 

 

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 long-term debt asSenior Notes at a premium of December 31,106% 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 are as follows (in millions): 2012–$0.0; 2013 – $0.0; 2014 – $0.0; 2015 – $117.0; thereafter – $600.0.

See Note 8 for(collectively, the estimated fair value“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 acquisition of the Newfield Properties described in Note 2, and for general corporate purposes.  In February 2013, holders of the 8.50% Senior Notes and additional details about fair value measurements.

issued in October 2012 exchanged their 8.50% Senior Notes for registered notes with the same terms.

On June 10, 2011, we issued $600.0 million of our senior notesSenior Notes at par with an interest rate of 8.5%8.50% and maturity date of June 15, 2019 (the “8.5%2019.  The net proceeds after fees and expenses were approximately $593.5 million.  In January 2012, holders of the Senior Notes”). 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.year and all of the 8.50% Senior Notes are subject to the same indenture.  The 8.5%8.50% Senior Notes are unsecured and are fully and unconditionally guaranteed by certain of our subsidiaries.  At December 31, 2011,2014 and 2013, the outstanding balance of our 8.5%8.50% Senior Notes was $600.0 million and was classified at their carrying value as long-term debt.  The estimated annual effective interest rate on the 8.5%8.50% Senior Notes is 8.7%8.4% for 2014, which includes amortization of debt issuance costs.costs and premiums.  At December 31, 2011,2014 and 2013, the estimated fair value of the 8.5%8.50% Senior Notes was approximately $612.0 million. In January 2012, holders of the 8.5% Senior Notes exchanged their senior notes for registered notes with the same terms.

In June and July of 2011, we used a portion of the net proceeds from the issuance of the 8.5% Senior Notes to repurchase all of our 8.25% Senior Notes due 2014 (the “8.25% Senior Notes”), which had a principal amount of $450.0 million. Costs of $22.0 million related to repurchasing the 8.25% Senior Notes, which included repurchase premiums and the unamortized debt issuance costs, are included in the statement of income within the line item classification,Loss on extinguishment of debt.

At December 31, 2010, the outstanding balance of our 8.25% Senior Notes was $450.0$594.0 million and was classified at their carrying value as long-term debt. At December 31, 2010, the estimated fair value of the 8.25% Senior Notes was approximately $441.0 million.

During 2009, we repaid the Tranche B term loan facility in full with borrowings under our revolving loan facility. As a result, in 2009 we recorded a loss of $2.9$962.5 million, related to the write-off of deferred financing costs and other related incidental costs.respectively.

We and our restricted subsidiaries are subject to certain covenants under the indenture governing the 8.5%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

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

substantially all of itsour 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 8.5%8.50% Senior Notes as of December 31, 2011.2014.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Credit Agreement

On May 5, 2011,November 8, 2013, we entered into the FourthFifth Amended and Restated Credit Agreement (the “Credit Agreement”), which provides a revolving bank credit facility with an initial borrowing base of $525.0 million. In October 2011, the borrowing base was re-determined by our lenders and increasedup to $575.0 million. This is a secured facility that is collateralized by our oil and natural gas properties. The Credit Agreement terminates on May 5, 2015 and replaces the prior Third Amended and Restated Credit Agreement (the “Prior Credit Agreement”).$1.2 billion. Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders.lenders, and the Company and the lenders may each request one additional determination per year.  The borrowing base as of December 31, 2014 was $750.0 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.  Letters of credit may be issued in amounts up to $300.0 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”).  

The Credit Agreement contains covenants that restrict,limit, among other things, the payment ofour ability to: (i) pay cash dividends in excess of up to $60.0 million per year,year; (ii) repurchase our common stock repurchases and Senior Note repurchasesor outstanding senior notes in excess of up to $100.0 million borrowings other than fromin the revolving bank credit facility, salesaggregate, provided that such limitation will not apply to the repurchase of assets,our existing senior notes in an aggregate principal amount equal to the aggregate principal amount of any new issuance of notes; (iii) sell our assets; (iv) make certain loans to others, investments, merger activity,or investments; (v) merge or consolidate; (vi) eliminate certain hedging contracts liensor 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.  Letters of credit may be issued up to $90.0 million, provided availability under the revolving bank credit facility exists. We are permitted to issue additional unsecured indebtedness above our current level of $900.0 million as long as no event of default occurs, we are in compliance with the financial covenants after giving pro forma effect to the additional unsecured indebtedness, and such additional unsecured indebtedness matures after the maturity date of the Credit Agreement and is not subject to various financialrestrictive covenants calculated as of the last day of each fiscal quarter including a minimum current ratio and a maximum leverage ratio as such ratios are definedmaterially more onerous than those provided for in the Credit Agreement.  We wereIf we issue additional unsecured indebtedness in compliance with all applicable covenantsexcess of the Credit Agreement ascurrent $900.0 million in aggregate principal amount, the borrowing base then in effect will be reduced by $0.25 for each dollar of December 31, 2011.such excess until the borrowing base is redetermined by our lenders.

Borrowings under the revolving bank credit facility bear interest at the applicable LIBORLondon Interbank Offered Rate (“LIBOR”) plus a margin that varies from 2.00%1.75% to 2.75% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the applicable margin ranging from 1.00% to 1.75% plus the highestgreater of the (a) Prime Rate, (b) Federal Funds Rate plus 0.50%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 of 0.50%ranging from 0.375% to 0.5%.  The estimated annual effective interest rate was 3.7%2.9% for 20112014 for borrowings under the Credit Agreement and the Prior Credit Agreement.  The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs.

UnamortizedThe Credit Agreement contains various customary covenants, customary events of default and certain financial tests, as of the end of each quarter, including a maximum consolidated leverage ratio, as defined in the Credit Agreement, of 3.5 to 1.0, and a minimum current ratio, as defined in the Credit Agreement, of 1.0 to 1.0.  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.  We were in compliance with all applicable covenants of the Credit Agreement as of December 31, 2014.

As it applies to 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 to the borrowing base under the Prior Credit Agreement.  One of $0.7 millionthe 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 were written off and are includedexpensed the portion related to the bank whose debt was extinguished and did not participate in the statementCredit Agreement.  The remaining unamortized debt issuance costs related to the Prior Credit Agreement was combined with the debt issuance costs related to the Credit Agreement and is being amortized over the term of income within the Credit Agreement on a straight line item classification,Loss on extinguishment of debt.basis.    

At December 31, 2011,2014, we had $117.0$447.0 million in borrowings and $0.6 million in letters of credit outstanding under the revolving bank credit facility.  At December 31, 2013, we had $290.0 million in borrowings and $0.4 million in letters of credit outstanding under the revolving bank credit facility.  The carrying amount of our revolving bank credit facility debt approximates

For information about fair value because the interest rates are variable and reflective of market rates. At December 31, 2010, we had no borrowings and $0.4 million in letters of credit outstanding under the revolving bank credit facility provided by the Prior Credit Agreement.measurements, refer to Note 8.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Fair Value Measurements

Under theFair Value Measurements and Disclosures topic of the Codification,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.

Index to Financial Statements

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 the Company’s own 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 derivativesderivative financial instruments, and our 8.50% Senior Notes (in thousands).

        December 31, 
        2011   2010 
    Hierarchy   Assets   Liabilities   Assets   Liabilities 

Derivatives

   Level 2    $ 4,087    $7,199    $ —      $14,882  

Senior Notes

   Level 2     —       612,000     —       441,000  

Revolving bank credit facility

   Level 2     —       117,000     —       —    

Derivatives are reported in the statement of financial position at fair value. The Senior Notes are reported in the statement of financial position at their carrying value which was $600.0 million and $450.0 million at December 31, 2011 and 2010, respectively. Theour revolving bank credit facility debt is reported in the statement of financial position at its carrying value which was $117.0 million and nil at December 31, 2011 and 2010, respectively.(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

 

We measure the fair value of our derivative financial instruments by applying the income approach, and 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 fair value measurement 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 fair 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 facility debt is reported 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.

For additional information about our derivative financial instruments refer to Note 6 and for additional information on our 8.50% Senior Notes and revolving bank credit facility refer to Note 7.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Equity Structure and Transactions

As of December 31, 20112014 and 2010,2013, the Company was authorized to issue two20 million shares of preferred stock with a par value of $0.00001 per share; however, no preferred shares have been issued or were outstanding as of the respective dates.

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In March 2009, we announced a $25.0 million stock repurchase program, which expired on December 31, 2009. In 2009, we purchased 2,869,173 shares of our common stock for approximately $24.2 million in the open market in accordance with the repurchase program. Repurchases were funded with cash on hand.

During the years 2011, 20102014, 2013 and 2009,2012, we paid regular cash dividends of $0.16, $0.14$0.40, $0.36 and $0.12 per$0.32 common share per year, respectively.  In December 2011,2013, we paid a special dividend of $0.63$0.42 per share or $46.9$31.8 million.  In December 2010,2012, we paid atwo special dividend of $0.66dividends totaling $0.79 per share or $49.2$59.0 million.  No special dividend was paid in 2009. On February 23, 2012, our boardDividends are subject to periodic review of directors declared a cash dividendthe Company’s performance and the current economic environment and applicable debt agreement restrictions.  In light of $0.08 per common share, payable on March 30, 2012current market conditions, the Board of Directors has elected to shareholders of record on March 14, 2012.suspend the regular quarterly dividend.

10. Incentive Compensation Plan and Directors Compensation Plan

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.  The Plan is an amended and restated version of the Company’s previous Long-term Incentive Compensation Plan (the “Previous Plan”). In addition to other cash and equity-basedshare-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 Internal Revenue Code (“IRC”).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”). The administrative authority includes setting the terms and provisions of each award granted and modifications to previously granted awards with certain restrictions.

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 aremay be established by the Committee for certain individuals.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 ten10 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 2011,2014, 2013 and 2012, performance awards under the Plan were granted in the form of restricted stock units (“RSUs”) and cash awards..  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.   The sole businessVesting 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, establishedwhich 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 2011 RSU awardsapplicable 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 anapproximately 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.

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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 target. The Company exceeded(“EPS”) for 2012; and (ii) the top-tier target; thereforeCompany’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 RSUpre-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 will bewere granted under the Plan to substantially all eligible for vesting on December 15, 2013.employees.  The cash-based awards, which are a short-term component of the Plan, were determined based on multiple performance measures, such as earnings per share,Adjusted EBITDA, reserve and production growth, cost containment and individual performance measures.  With respect to the 20112014 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 individualwere combined with the individual’s performance was estimated atto determine the mid-pointcash-based award.  With respect to the 2012 cash-based awards, some of the eligible range. Employees will beperformance 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 2011.end.

For 2010, performance awards under the Plan were granted in the form of RSUs and cash awards. Share-based Awards: Common Stock

The sole business performance criteria established2014 annual incentive plan award for the 2010 RSU awardsChief Executive Officer (“CEO”) was an earningssettled in shares of common stock based on a pre-determined price of $14.66 per share, target. The Company exceeded the top-tier target; therefore 100%subject to pre-defined performance measures and approval of the RSU awards will be eligible for vesting on

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 15, 2012. The cash based awards were determined based on multiple performance measures. With respect to the 2010 cash-based awards, most of the performance criteria targets were achieved.

In 2009, the Previous Plan was effective. Awards consisted of a general award and an extraordinary performance award. For 2009, the Company’s performance did not achieve any of the targets; therefore no awards were granted that were related to Company performance.

In 2009, the Compensation Committee approved a modification to the restricted stock portion of the 2008 award. Due to a decline in the market price of the Company’s common stock, the Compensation Committee determined thatCommittee.  As the number of shares availablecould not be determined until the full-year 2014 results were determined and approved by the Committee, the CEO’s 2014 award was accounted for issuance underas a liability award during 2014 and adjusted to fair value using the Previous PlanCompany’s closing price at the end of each reporting period.  The grant was insufficient to cover 100%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 restricted stock portionimmediately 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 2008 award. Accordingly, in March 2009,CEO’s awards were the same as the cash-based-awards performance measures established for the other eligible Company granted to its eligible employees on a pro-rata basis, substantially all offor 2014 and 2013, respectively.

Directors Compensation Plan Share-Based Awards

Under the Directors Compensation Plan, shares of restricted stock available to be(“Restricted Shares”) were issued under the Previous Plan. In May 2009, the Company’s shareholders approved an increase in the number of shares available for issuance under the Previous Plan of 2,000,000 shares. Subsequent to the increase in the number of shares available, the Company granted to its employees restricted stock to satisfy the remainder of the 2008 award.

For information concerning grants awarded2014, 2013 and amounts recognized in lease operating expense and general and administrative expense, see Note 11.

11. Share-Based and Cash-Based Incentive Compensation

In accordance with theCompensation – Stock Compensation topic of the Codification, we recognize compensation cost on a straight line basis 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 grant. We are also required to estimate forfeitures, resulting in the recognition of compensation cost only for those awards that actually vest.

As allowed by the Plan, in August 2011 and August 2010, the Company granted RSUs to certain of its employees and in January 2011, the Company granted restricted stock to one of its employees. Prior to 2010, the Company granted only restricted stock to its employees. In 2011 and in prior years, restricted stock was granted2012 to the Company’s non-employee directors underas a component of their compensation arrangement.  Vesting occurs upon completion of the Director Compensation Plan. In addition to share-based compensation, the Company granted its employees cash-based incentive awards in 2011specified vesting period and in 2010.

At December 31, 2011, there were 2,269,745 sharesone-third of common stock available for award under the Plan and 568,783 shares of common stock available for award under the Directors Compensation Plan.

Restricted Stock

Under the Company’s share-based payment plans, restricted shares were issued to only one employee in 2011 and no restricted shares were issued to employees in 2010. Restricted shares were issued to employees in 2009. In 2011, 2010 and 2009, restricted shares were issued to the Company’s non-employee directors. Restricted shares are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restrictedeach grant vests each year over a three-year period.  The holders of restricted sharesRestricted 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.

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A summary of share activity related to restricted stock is as follows:

  2011  2010  2009 
  Restricted
Shares
  Weighted Average
Grant  Date Price
Per Share
  Restricted
Shares
  Weighted Average
Grant  Date Price
Per Share
  Restricted
Shares
  Weighted Average
Grant  Date Price
Per Share
 

Nonvested, beginning of period

  470,392   $7.42    1,050,506   $8.48    233,703   $30.33  

Granted

  20,433    25.45    35,000    10.00    1,570,436    6.91  

Vested

  (404,422  7.31    (485,934  9.69    (653,676  12.18  

Forfeited

  (34,533  6.83    (129,180  8.15    (99,957  10.77  
 

 

 

   

 

 

   

 

 

  

Nonvested, end of period

  51,870    15.81    470,392    7.42    1,050,506    8.48  
 

 

 

   

 

 

   

 

 

  

At December 31, 2011, the composition of our restricted stock awards outstanding, by year granted, was as follows:

   Shares 

Employees – granted in:

  

2011

   2,662(1) 

Non-employee directors – granted in:

  

2011

   15,108(2) 

2010

   23,330(3) 

2009

   10,770(4) 
  

 

 

 

Total

   51,870  
  

 

 

 

Subject to employment conditions and less any forfeitures, vesting of restricted stock will occur as follows:

(1)December 2012.
(2)Equal installments in May 2012, 2013 and 2014.
(3)Equal installments in May 2012 and 2013.
(4)May 2012.

The grant date fair value of restricted stock granted during the years 2011, 2010 and 2009 was $0.5 million, $0.4 million and $10.9 million, respectively. The fair value of the restricted stock that vested during the years ended 2011, 2010 and 2009 was $7.9 million, $8.1 million and $7.4 million, respectively, based on the closing prices on the dates of vesting.

Restricted Stock Units

During 2011 and 2010, the Company awarded to certain employees RSUs that were 100% contingent upon meeting specified performance requirements. The specific performance requirements were achieved in 2011 and 2010. Vesting occurs upon completion of the specified vesting period applicable to each award. Effective January 2012, the RSUs awarded in 2011 and 2010 will earn dividend equivalents at the same rate as dividends paid on our common stock. During 2011, RSUs awarded in 2010 earned dividend equivalents at the same rate as dividends paid on our common stock. RSUs awarded in both yearsShares 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 period.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.

Index to Financial Statements
94


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

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

 

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 share activity related to RSUs is as follows:

 

  2011   2010 

2014

 

 

2013

 

 

2012

 

  RSUs Weighted Average
Grant Date Price
Per Unit
   RSUs Weighted Average
Grant Date Price
Per Unit
 

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

   1,266,617   $9.36     —     $—    

 

1,331,753

 

 

$

14.96

 

 

 

969,820

 

 

$

22.70

 

 

 

1,732,703

 

 

$

14.67

 

Granted

   534,375    26.93     1,280,501    9.36  

 

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

   (68,289  12.03     (13,884  9.36  

 

(195,114

)

 

 

16.53

 

 

 

(139,061

)

 

 

16.50

 

 

 

(329,329

)

 

 

19.56

 

  

 

    

 

  

Nonvested, end of period (1)

   1,732,703    14.67     1,266,617    9.36  
  

 

    

 

  

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:

(1)

Subject

Restricted Stock Units

2015 - subject to employment conditionsservice requirements

759,234

2015 - subject to service and less any forfeitures, 1,208,714 and 523,989 RSUs will vest in December 2012 and 2013, respectively.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.

RSUs fair value at grant date:During the years 20112014, 2013 and 2010,2012, the grant date fair value of RSUs granted was $14.4$20.1 million, $12.8 million and $12.0$14.3 million, respectively.

RSUs fair value 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.

96


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Common Stock

A grant 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 deductions for withholding and payroll taxes 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.

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, 

Year Ended December 31,

 

  2011   2010   2009 

2014

 

 

2013

 

 

2012

 

Share-based compensation expense from:

      

 

 

 

 

 

 

 

 

 

 

 

Restricted stock

  $2,377    $3,469    $7,730  

$

369

 

 

$

397

 

 

$

399

 

Restricted stock units

   7,333     2,064     —    

 

13,150

 

 

 

11,128

 

 

 

11,999

 

  

 

   

 

   

 

 

Common shares

 

1,225

 

 

 

 

 

 

 

Total

  $9,710    $5,533    $7,730  

$

14,744

 

 

$

11,525

 

 

$

12,398

 

  

 

   

 

   

 

 

Share-based compensation tax benefit:

      

 

 

 

 

 

 

 

 

 

 

 

Tax benefit computed at the statutory rate

  $3,399    $1,937    $2,706  

$

5,160

 

 

$

4,034

 

 

$

4,339

 

  

 

   

 

   

 

 

As of December 31, 2011,2014, unrecognized share-based compensation expense related to our issued restricted sharesawards of Restricted Shares, RSUs and RSUscommon stock was $0.6$0.5 million, $16.5 million and $15.7$0.1 million, respectively.  Unrecognized compensation expense will be recognized through April 20142017 for restricted shares, November 2016 for RSUs and November 2013February 2015 for RSUs.common stock.

Cash-based Incentive Compensation

As defined by the Plan, annual incentive awards payable in cash may be granted to eligible employees payable in cash.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 quarter of the following year.

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Share-Based Compensation and Cash-Based Incentive Compensation Expense

A summary of incentive compensation expense is as follows (in thousands):

 

   Year Ended December 31, 
   2011   2010   2009 

Share-based compensation expense included in:

      

Lease operating expense

  $466    $748    $2,242  

General and administrative

   9,244     4,785     5,488  
  

 

 

   

 

 

   

 

 

 

Total charged to operating income (loss)

   9,710     5,533     7,730  
  

 

 

   

 

 

   

 

 

 

Cash-based incentive compensation included in:

      

Lease operating expense

   3,700     2,067     1,472  

General and administrative

   12,213     8,539     1,525  
  

 

 

   

 

 

   

 

 

 

Total charged to operating income (loss)

   15,913     10,606     2,997  
  

 

 

   

 

 

   

 

 

 

Total incentive compensation charged to operating income (loss)

  $25,623    $16,139    $10,727  
  

 

 

   

 

 

   

 

 

 

 

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.

97


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”), which covers those employees who meet the 401(k) Plan’s eligibility requirements.  During 2011, 20102014, 2013 and 2009,2012, the Company’s matching contribution was 100% of each participant’s contribution up to a maximum of 5%6% for 2014, 2013 and 2012 of the participant’s eligible compensation, subject to limitations imposed by the Internal Revenue Service.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 $1.8$2.4 million, $1.4$2.1 million and $1.5$2.1 million for the years 2011, 20102014, 2013 and 2009,2012, respectively.

13. Income Taxes

Income Tax Expense (Benefit)

Components of income tax expense (benefit) were as follows (in thousands):

 

   Year Ended December 31, 
   2011   2010  2009 

Current

  $29,682    $20,167   $(74,111

Deferred

   61,835     (8,266  —    
  

 

 

   

 

 

  

 

 

 
  $91,517    $11,901   $(74,111
  

 

 

   

 

 

  

 

 

 

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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 taxes computed at the U.S. federal statutory tax rate to our income tax expense (benefit) is as follows (in thousands):

 

  Year Ended December 31, 
  2011  2010  2009 

Income tax expense (benefit) at the federal statutory rate

 $92,517    35.0 $45,427    35.0 $(91,710  35.0

Valuation allowance

  —      —      (31,985  (24.6  14,594    (5.6

Domestic production activities deduction

  (1,823  (0.7  (2,623  (2.0  3,167    (1.2

Share-based compensation

  —      —      —      —      208    —    

State income taxes

  603    0.2    32    —      (73  —    

Other

  220    0.1    1,050    0.8    (297  0.1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 
 $91,517    34.6 $11,901    9.2 $(74,111  28.3
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 

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

%

Our effective tax rate for the year 2011 consists primarily of2014 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 with an adjustmentprimarily as a result of state income taxes.  Our effective tax rate for the utilizationyear 2012 differed from the federal statutory rate primarily as a result of the deduction attributable torecapture of deductions for qualified domestic production activities under Section 199 of the IRC. Our effective tax rate for the year 2010 primarily reflectsIRC as a reduction in our valuation allowance against our deferred tax assetsfunction of loss carrybacks to prior years and the Section 199 deduction described above. Taxableimpact of state income in 2010 allowed us to reverse all of the previously recorded valuation allowance. Our effective tax rate for the year 2009 primarily reflects recapture of the Section 199 deduction related to net operating loss carrybacks for tax purposes as well as the incremental current period effect of a change in our valuation allowance for our deferred tax assets. In 2009, the Company experienced a net operating loss for tax purposes and as a result, the Section 199 deduction was not available to us. In 2009, a portion of the qualified domestic production activities deduction for 2005 and 2007 was recaptured due to carrybacks of a net operating loss from 2009 to 2005 and 2007.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, 
   2011  2010 

Deferred tax liabilities:

   

Property and equipment

  $63,328   $2,370  

Other

   4,707    3,274  
  

 

 

  

 

 

 

Total deferred tax liabilities

   68,035    5,644  
  

 

 

  

 

 

 

Deferred tax assets:

   

Minimum tax credit

   —      3,558  

State net operating losses

   4,626    4,176  

Derivatives

   1,096    4,622  

Valuation allowance

   (4,626  (4,176

Accrued cash-based bonus

   5,390    4,022  

Stock-based compensation

   3,971    1,581  

Other

   704    464  
  

 

 

  

 

 

 

Total deferred tax assets

   11,161    14,247  
  

 

 

  

 

 

 

Net deferred tax (liabilities) assets

  $(56,874 $8,603  
  

 

 

  

 

 

 

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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 the year 2011,2014, 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 $35.7$3.0 million.  WeDuring 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 $0.4$0.5 million.

During the year 2010,At December 31, 2014, we received refunds ofdid 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 in prior years totaling $99.8 million, consisting primarily of carrybacks of net operating losses generated in 2009 and 2008 and made payments of $12.0 million for federal and state income taxes. On November 6, 2009, the Worker, Homeownership and Business Assistance Act of 2009 was signed into law. A provision of this act provides an election to increase the carryback period for applicable net operating losses up to five years from two years.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, 20112014 (in thousands):

 

   Amount   Expiration Year 

State net operating loss

  $88,963     2020-2025  

 

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

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.

99


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Valuation Allowance

As of December 31, 20112014 and December 31, 2010,2013, we had a valuation allowance related to Louisiana state net operating losses.  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, we consider future reversals of existing taxable temporary differences.

Uncertain Tax Positions

The table below sets forth the reconciliation of the beginning and ending balances 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.  We recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2011, we had zero accrued interest related to uncertain tax positions. During 2011, we recognized $0.3 million of income tax benefit for the reversal of accrued interest and penalties.

Balances and changes in the uncertain tax positions are as follows (in thousands):

 

   December 31, 
   2011  2010 

Balance at beginning of period

  $3,558   $—    

Increase related to current-year tax positions

   —      3,558  

(Decreases) related to prior-year tax positions

   (3,558  —    
  

 

 

  

 

 

 

Balance at end of period

  $—     $3,558  
  

 

 

  

 

 

 

 

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

 

We recognize interest and penalties related to uncertain tax positions in income tax expense.  For 2014, 2013 and 2012, the amounts recognized in income tax expense were immaterial.

Years open to examination

The tax years from 20082010 through 20112014 remain open to examination by the tax jurisdictions to which we are subject.

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

14. Earnings (Loss) Per Share

In accordance with theEarnings Per Share topic of the Codification,GAAP, the 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.

The following table presents the calculation of basic and diluted earnings (loss) per common share (in thousands, except per share amounts):

 

  Year Ended December 31, 

Year Ended December 31,

 

  2011   2010   2009 

2014

 

 

2013

 

 

2012

 

Net income (loss)

  $172,817    $117,892    $(187,919

$

(11,661

)

 

$

51,322

 

 

$

71,984

 

Less portion allocated to nonvested shares

   3,211     1,178     —    

 

269

 

 

 

303

 

 

 

983

 

  

 

   

 

   

 

 

Net income (loss) allocated to common shares

  $169,606    $116,714    $(187,919

$

(11,930

)

 

$

51,019

 

 

$

71,001

 

  

 

   

 

   

 

 

Weighted average common shares outstanding

   74,033     73,685     74,852  

 

75,609

 

 

 

75,239

 

 

 

74,354

 

  

 

   

 

   

 

 

Basic and diluted earnings (loss) per common share

  $2.29    $1.58    $(2.51

$

(0.16

)

 

$

0.68

 

 

$

0.95

 

Shares excluded due to being anti-dilutive

   1,873     1,540     1,347  

Shares excluded due to being anti-dilutive (weighted-average)

 

29

 

 

 

 

 

 

1,923

 

15. Comprehensive Income (Loss)

Our comprehensive income (loss) for the periods indicated is as follows (in thousands):

 

   Year Ended December 31, 
   2011   2010   2009 

Net income (loss)

  $172,817    $117,892    $(187,919

Amounts reclassified to income, net of income tax of $0 in 2011, $0 in 2010 and $346 in 2009 (1)

   —       —       643  
  

 

 

   

 

 

   

 

 

 

Comprehensive income (loss)

  $172,817    $117,892    $(187,276
  

 

 

   

 

 

   

 

 

 

100


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

(1)Includes the amortization of amounts recorded in other comprehensive income upon the de-designation of our interest rate swap as a cash flow hedge in 2007.

16.

15. Supplemental Cash Flow Information

The following reflects our supplemental cash flow information (in thousands):

   Year Ended December 31, 
   2011   2010   2009 

Cash paid for interest, net of interest capitalized of $9,877 in 2011, $5,395 in 2010 and $6,662 in 2009

  $39,772    $36,362    $37,286  

Cash paid for income taxes

   35,655     12,000     100  

Cash paid for share-based compensation (1)

   1,062     452     162  

Cash tax benefit related to share-based compensation (2)

   3,125     6,871     —    

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Year Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

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

 

Cash paid for income taxes

 

 

 

 

3,000

 

 

 

16,056

 

Cash refunds received for income taxes

 

3,000

 

 

 

59,126

 

 

 

479

 

Cash paid for share-based compensation (1)

 

431

 

 

 

466

 

 

 

1,531

 

Cash tax benefit related to share-based compensation (2)

 

 

 

 

 

 

 

5,962

 

(1)

The cash paid for share-based compensation 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-baseshare-based compensation arrangements.

(2)

The cash tax benefit for share-based compensation is attributable to tax deductions for vested restricted shares, tax deductions forvested RSUs, dividends paid on unvested restricted stock and tax deductions related to dividend equivalents paid on RSUs.  Tax refunds were received in 2010For 2014 and 2013, no cash tax benefit was realized as the Company had a tax loss for that includedyear and all carrybacks of net operating losses for the years 2009 and 2008 to prior years, therefore the tax cash benefits from share-based compensation in those years was determined to be received in 2010. In addition, refunds related to the carryback of 2008 net operating loss to prior years were also received in 2009. As refunds could not be specifically determined as to which related to share-based compensation, it was assumed these cash flows were received in 2010 as most refunds were received in that year.had previously been utilized.

During the years 2011, 2010 and 2009, we received refunds of federal income taxes paid in prior years totaling $0.4 million, $99.8 million and $22.3 million, respectively.

17.16. 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, 20112014 are as follows (in millions): 2012 – $0.3; 2013 – $1.2; 2014 – $1.1; thereafter – $10.0.

follows: 2015–$1.5 million; 2016–$1.6 million; 2017–$1.6 million; 2018–$1.7 million thereafter–$7.5 million.  Total rent expense was approximately $1.9$3.2 million, $2.0$2.6 million and $2.2$1.7 million during the years 2011, 20102014, 2013 and 2009,2012, respectively.

Pursuant to the Purchase and Sale Agreement with Total E&P, we are required to fulfill security requirements related to ARO for certain properties through bonds or making payments to an escrow account.account or a combination.  As of December 31, 2014, we were in compliance with the security amount requirement of $64.0 million.  Additional security requirements are nil in 2012, $9.0 million in 2013, $9.0 million in 2014, $9.0 million in 2015, $6.0 million in 2016, $4.0 million in 2017, $5.0 million in 2018 and $30.0$15.0 million in the 20162019 to 2023 time period.period to a total security requirement of $103.0 million by 2023.

Pursuant to the Purchase and Sale agreement with Shell Offshore Inc. (“Shell”) related to ARO for certain properties, we have bonds that are subject to re-appraisal in the 2015.  The current security requirement of $74.0 million could be increased up to $94.0 million depending on certain conditions and circumstances.

We have onebonding requirements 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.

Total expenses related to bonds, inclusive of the bonds in connection with Total E&P and Shell described above, were $4.1 million, $5.0 million 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 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–$5.4 million; 2018–$5.2 million; thereafter–$32.9 million.  

Pursuant to an agreement with the Helix Well Containment Group, we are required to make payments 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, future payments due are $2.1 million in 2015 and $2.1 million in 2016.  These payments may increase or decrease depending on whether the number of companies participating in the consortium changes.

We have no drilling rig commitmentcommitments with a term that exceeded one year as of December 31, 20112014 and our drilling rig commitments meet the criteria of an operating lease.  Future payments of all drilling rig commitments as of December 31, 20112014 were $32.1 million in 2012, $1.7 million in$12.6 million.

101


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. Related Parties

During 2014, 2013 and none beyond 2013.

18. Related Parties

During 2011, 2010, and 2009,2012, there were certain transactions between us and other companies that were controlled by our majority shareholder. Theshareholder either controlled or in which he had an ownership interest.  In addition, there were transactions were primarily for usewith a company that employs the spouse of jet services and transactions related to insurance.our majority shareholder.  Our majority shareholder owns a certainan aircraft that the Company used and reimbursed him for such use and for his use.  JetAirplane services were charged to us at rates that were either equal to or below rates chargescharged by non-related, third-party companies.  JetAirplane services transactions were approximately $1.1 million, $0.9 million, $1.2 million and $0.1$1.0 million for the years 2011, 20102014, 2013 and 2009,2012, respectively.  In addition, ourOur majority shareholder 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 shareholder owns a minority ownership interest and serves on its board of directors, and W&T paid $0.2 million, $0.2 million and $0.7 million for drilling related services during 2014, 2013 and 2012, respectively.  A company that provides marine transportation and logistics services to W&T employs the spouse of our majority shareholder.  The spouse received commissions partially based on services rendered to W&T which totaled less than $0.2 million per year for 2014, 2013 and 2012.  All these transactions were determined to be priced at competitive rates and were reviewed by the Audit Committee for compliance with our policies and procedures.

Index

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, we received notice from the ONRR of a statutory fine of $2.3 million relative to Financial Statements

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.     

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”) related to deepwater wells in the Mississippi Canyon area of the Gulf of Mexico.  That lawsuit, styled Apache Corporation v. W&T Offshore, Inc., is currently pending 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 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. 

102


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

19. Contingencies

The United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the EPA, has been conducting a federal grand jury investigation of environmental compliance matters relating to surface discharges and reporting on four of our offshore platforms in the Gulf of Mexico. We are fully cooperating with the investigation which began in 2011 and is continuing in 2012. The United States Attorney’s Office has informed us that they are continuing their investigation with the intent to seek a criminal disposition. The outcome of this investigation could have a material adverse effect upon us. We are not able at this time to estimate our potential exposure, if any, related to this matter.Insurance Claims

On May 6, 2009, certain Cameron Parish land owners filed suit in the 38th Judicial District Court, Cameron Parish, Louisiana against the Company and Tracy W. Krohn as well as several other defendants unrelated to us. In their lawsuit, plaintiffs are alleging that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and are seeking compensatory and punitive damages. We cannot currently estimate our potential exposure, if any, related to this lawsuit. We are currently, and intend to continue, vigorously defending this litigation.

We have recorded a liability of $2.0 million inDuring the fourth quarter of 2011,2012, 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 Court 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 favor of the underwriters, adopting their position that 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 Court 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.  One 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 includedunder discussion.  The other underwriters have not paid inOther liabilities accordance 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 balance sheetConsolidated Balance Sheets and charged toGeneral and administrative expenses (“G&A”)recoveries from claims made on these Excess Policies will be recorded as reductions in the statement of income (loss), for the loss contingencies of environmental matters that include the events described above and other minor environmental matters we are addressing.this line item, which will reduce our future DD&A rate.

Royalties

In 2009, the Company recognized $5.3 million in 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 the third quarter of 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken.  We recorded a reduction to other revenue of $4.7 million in the third quarter of 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”) under the Department of the Interior.  W&T’s brief was filed in November 2014 and planwe expect the briefing before BLA to pursue our claim, including taking legal action, if necessary, to resolvebe completed in the matter.first half of 2015.

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.  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 believes 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.

IndexContingent Liability Recorded

We recognized expenses related to Financial Statements

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.

103


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

20.

19. Selected Quarterly Financial Data – 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, 2011

        

Revenues

  $210,855    $252,922    $245,371    $261,899  

Operating income

   37,548     115,643     95,333     80,936  

Net income

   18,649     55,175     52,928     46,065  

Basic and diluted earnings per common share (1)

   0.25     0.73     0.70     0.61  

Year Ended December 31, 2010

        

Revenues

  $169,585    $179,667    $169,575    $186,956  

Operating income

   55,711     40,178     36,847     34,053  

Net income

   42,315     27,870     27,188     20,519  

Basic and diluted earnings per common share (1)

   0.57     0.37     0.36     0.27  

 

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

)

(1)

The sum of the individual quarterly earnings per share may not agree with year-to-date earnings 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.

21.


104


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. Supplemental Guarantor Information

Our payment obligations under the 8.50% Senior Notes and the Credit Agreement (see Note 7) are fully and unconditionally guaranteed by certain of our wholly-owned100%-owned subsidiaries, W & T Energy VI, which includes the operations of the acquisitions closed in 2010 as described in Note 2,LLC and W&T & T Energy VII, LLC which(together, the “Guarantor Subsidiaries”).  W & T Energy VII, LLC does not currently have any active operations (together,or contain any assets.  Guarantees of the “Guarantor Subsidiaries”).8.50% Senior Notes will be released under certain circumstances, including:

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(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” provisions of the indenture;

(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” 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;

(4)

upon Legal Defeasance or Covenant Defeasance (as such terms are defined in the indenture) or upon satisfaction and discharge of the indenture;

(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, provided no event of default has occurred and is continuing.

 

The following unaudited condensed consolidating financial information presents the financial condition, results of operations and cash flows of W&T Offshore, Inc. (the “Parent Company”)the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis.  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 transfers were transactions between entities under common control, the prior period financial information has been 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


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet as of December 31, 20112014

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

  Parent
Company
 Guarantor
Subsidiaries
   Eliminations Consolidated
W&T
Offshore, Inc.
 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

  (In thousands) 

(In thousands)

 

Assets

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

  $4,512   $—      $—     $4,512  

$

23,666

 

 

$

 

 

$

 

 

$

23,666

 

Receivables:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

   78,131    20,419     —      98,550  

 

41,820

 

 

 

25,422

 

 

 

 

 

 

67,242

 

Joint interest and other

   25,089    —       —      25,089  

 

142,885

 

 

 

 

 

 

(99,240

)

 

 

43,645

 

Insurance

   715    —       —      715  

Income taxes

   74,183    —       (74,183  —    
  

 

  

 

   

 

  

 

 

Total receivables

   178,118    20,419     (74,183  124,354  

 

184,705

 

 

 

25,422

 

 

 

(99,240

)

 

 

110,887

 

Deferred income taxes

   2,007    —       —      2,007  

 

9,797

 

 

 

1,865

 

 

 

 

 

 

11,662

 

Prepaid expenses and other assets

   30,315    —       —      30,315  

 

28,728

 

 

 

7,619

 

 

 

 

 

 

36,347

 

  

 

  

 

   

 

  

 

 

Total current assets

   214,952    20,419     (74,183  161,188  

 

246,896

 

 

 

34,906

 

 

 

(99,240

)

 

 

182,562

 

Property and equipment – at cost:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas properties and equipment

   5,689,535    269,481     —      5,959,016  

 

6,038,915

 

 

 

2,006,751

 

 

 

 

 

 

8,045,666

 

Furniture, fixtures and other

   19,500    —       —      19,500  

 

23,269

 

 

 

 

 

 

 

 

 

23,269

 

  

 

  

 

   

 

  

 

 

Total property and equipment

   5,709,035    269,481     —      5,978,516  

 

6,062,184

 

 

 

2,006,751

 

 

 

 

 

 

8,068,935

 

Less accumulated depreciation, depletion and amortization

   4,208,825    111,585     —      4,320,410  

 

4,442,899

 

 

 

1,132,179

 

 

 

 

 

 

5,575,078

 

  

 

  

 

   

 

  

 

 

Net property and equipment

   1,500,210    157,896     —      1,658,106  

 

1,619,285

 

 

 

874,572

 

 

 

 

 

 

2,493,857

 

Restricted deposits for asset retirement obligations

   33,462    —       —      33,462  

 

15,444

 

 

 

 

 

 

 

 

 

15,444

 

Deferred income taxes

   —      17,637     (17,637)  —    

Other assets

   372,572    275,181     (631,584  16,169  

 

974,049

 

 

 

349,912

 

 

 

(1,306,717

)

 

 

17,244

 

  

 

  

 

   

 

  

 

 

Total assets

  $2,121,196   $471,133    $(723,404 $1,868,925  

$

2,855,674

 

 

$

1,259,390

 

 

$

(1,405,957

)

 

$

2,709,107

 

  

 

  

 

   

 

  

 

 

Liabilities and Shareholders’ Equity

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payable

  $73,333   $2,538    $—     $75,871  

$

188,654

 

 

$

5,455

 

 

$

 

 

$

194,109

 

Undistributed oil and natural gas proceeds

   33,391    341     —      33,732  

 

36,130

 

 

 

879

 

 

 

 

 

 

37,009

 

Asset retirement obligations

   138,185    —       —      138,185  

 

30,711

 

 

 

5,292

 

 

 

 

 

 

36,003

 

Accrued liabilities

   29,705    —       —      29,705  

 

17,437

 

 

 

99,180

 

 

 

(99,240

)

 

 

17,377

 

Income taxes

   —      84,575     (74,183  10,392  
  

 

  

 

   

 

  

 

 

Total current liabilities

   274,614    87,454     (74,183  287,885  

 

272,932

 

 

 

110,806

 

 

 

(99,240

)

 

 

284,498

 

Long-term debt

   717,000    —       —      717,000  

Long-term debt, less current maturities

 

1,360,057

 

 

 

 

 

 

 

 

 

1,360,057

 

Asset retirement obligations, less current portion

   228,419    27,276     —      255,695  

 

235,876

 

 

 

118,689

 

 

 

 

 

 

354,565

 

Deferred income taxes

   76,518    —       (17,637  58,881  

 

59,616

 

 

 

127,372

 

 

 

 

 

 

186,988

 

Other liabilities

   280,071    —       (275,181  4,890  

 

417,885

 

 

 

 

 

 

(404,194

)

 

 

13,691

 

Commitments and contingencies

      

Shareholders’ equity:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock

   1    —       —      1  

 

1

 

 

 

 

 

 

 

 

 

1

 

Additional paid-in capital

   386,920    231,759     (231,759  386,920  

 

414,580

 

 

 

703,440

 

 

 

(703,440

)

 

 

414,580

 

Retained earnings

   181,820    124,644     (124,644  181,820  

 

118,894

 

 

 

199,083

 

 

 

(199,083

)

 

 

118,894

 

Treasury stock, at cost

   (24,167  —       —      (24,167

 

(24,167

)

 

 

 

 

 

 

 

 

(24,167

)

  

 

  

 

   

 

  

 

 

Total shareholders’ equity

   544,574    356,403     (356,403  544,574  

 

509,308

 

 

 

902,523

 

 

 

(902,523

)

 

 

509,308

 

  

 

  

 

   

 

  

 

 

Total liabilities and shareholders’ equity

  $2,121,196   $471,133    $(723,404 $1,868,925  

$

2,855,674

 

 

$

1,259,390

 

 

$

(1,405,957

)

 

$

2,709,107

 

  

 

  

 

   

 

  

 

 

Index to Financial Statements

106


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

Condensed Consolidating Balance Sheet as of December 31, 20102013

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

  Parent
Company
 Guarantor
Subsidiaries (1)
   Eliminations Consolidated
W&T
Offshore, Inc.
 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

  (In thousands) 

(In thousands)

 

Assets

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

  $28,655   $—      $—     $28,655  

$

15,800

 

 

$

 

 

$

 

 

$

15,800

 

Receivables:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

   50,421    29,490     —      79,911  

 

61,373

 

 

 

35,379

 

 

 

 

 

 

96,752

 

Joint interest and other

   25,415    —       —      25,415  

 

123,595

 

 

 

 

 

 

(92,491

)

 

 

31,104

 

Insurance

   1,014    —       —      1,014  

Income taxes

   2,492    —       (2,492  —    
  

 

  

 

   

 

  

 

 

Total receivables

   79,342    29,490     (2,492  106,340  

 

184,968

 

 

 

35,379

 

 

 

(92,491

)

 

 

127,856

 

Deferred income taxes

   5,784    2,755     (2,755  5,784  

 

584

 

 

 

-

 

 

 

 

 

 

584

 

Prepaid expenses and other assets

   23,426    —       —      23,426  

 

23,090

 

 

 

6,272

 

 

 

 

 

 

29,362

 

  

 

  

 

   

 

  

 

 

Total current assets

   137,207    32,245     (5,247  164,205  

 

224,442

 

 

 

41,651

 

 

 

(92,491

)

 

 

173,602

 

Property and equipment – at cost:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas properties and equipment

   4,955,460    270,122     —      5,225,582  

 

5,667,389

 

 

 

1,671,708

 

 

 

 

 

 

7,339,097

 

Furniture, fixtures and other

   15,841    —       —      15,841  

 

21,431

 

 

 

 

 

 

 

 

 

21,431

 

  

 

  

 

   

 

  

 

 

Total property and equipment

   4,971,301    270,122     —      5,241,423  

 

5,688,820

 

 

 

1,671,708

 

 

 

 

 

 

7,360,528

 

Less accumulated depreciation, depletion and amortization

   3,994,085    27,310     —      4,021,395  

 

4,166,359

 

 

 

918,345

 

 

 

 

 

 

5,084,704

 

  

 

  

 

   

 

  

 

 

Net property and equipment

   977,216    242,812     —      1,220,028  

 

1,522,461

 

 

 

753,363

 

 

 

 

 

 

2,275,824

 

Restricted deposits for asset retirement obligations

   30,636    —       —      30,636  

 

37,421

 

 

 

 

 

 

 

 

 

37,421

 

Deferred income taxes

   2,819    —       —      2,819  

Other assets

   275,461    47,160     (316,215  6,406  

 

951,203

 

 

 

479,820

 

 

 

(1,410,568

)

 

 

20,455

 

  

 

  

 

   

 

  

 

 

Total assets

  $1,423,339   $322,217    $(321,462 $1,424,094  

$

2,735,527

 

 

$

1,274,834

 

 

$

(1,503,059

)

 

$

2,507,302

 

  

 

  

 

   

 

  

 

 

Liabilities and Shareholders’ Equity

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payable

  $77,422   $3,020    $—     $80,442  

$

144,492

 

 

$

720

 

 

$

 

 

$

145,212

 

Undistributed oil and natural gas proceeds

   24,866    374     —      25,240  

 

41,735

 

 

 

372

 

 

 

 

 

 

42,107

 

Asset retirement obligations

   92,575    —       —      92,575  

 

65,329

 

 

 

12,456

 

 

 

 

 

 

77,785

 

Accrued liabilities

   25,827    —       —      25,827  

 

28,000

 

 

 

92,491

 

 

 

(92,491

)

 

 

28,000

 

Income taxes

   —      20,044     (2,492  17,552  
  

 

  

 

   

 

  

 

 

Total current liabilities

   220,690    23,438     (2,492  241,636  

 

279,556

 

 

 

106,039

 

 

 

(92,491

)

 

 

293,104

 

Long-term debt

   450,000    —       —      450,000  

Long-term debt, less current maturities

 

1,205,421

 

 

 

 

 

 

 

 

 

1,205,421

 

Asset retirement obligations, less current portion

   269,016    29,725     —      298,741  

 

189,507

 

 

 

87,130

 

 

 

 

 

 

276,637

 

Deferred income taxes

   2,755    —       (2,755  —    

 

79,424

 

 

 

98,718

 

 

 

 

 

 

178,142

 

Other liabilities

   59,135    —       (47,161  11,974  

 

441,009

 

 

 

 

 

 

(427,621

)

 

 

13,388

 

Commitments and contingencies

      

Shareholders’ equity:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock

   1    —       —      1  

 

1

 

 

 

 

 

 

 

 

 

1

 

Additional paid-in capital

   377,529    236,944     (236,944  377,529  

 

403,564

 

 

 

784,104

 

 

 

(784,104

)

 

 

403,564

 

Retained earnings

   68,380    32,110     (32,110  68,380  

 

161,212

 

 

 

198,843

 

 

 

(198,843

)

 

 

161,212

 

Treasury stock, at cost

   (24,167  —       —      (24,167

 

(24,167

)

 

 

 

 

 

 

 

 

(24,167

)

  

 

  

 

   

 

  

 

 

Total shareholders’ equity

   421,743    269,054     (269,054  421,743  

 

540,610

 

 

 

982,947

 

 

 

(982,947

)

 

 

540,610

 

  

 

  

 

   

 

  

 

 

Total liabilities and shareholders’ equity

  $1,423,339   $322,217    $(321,462 $1,424,094  

$

2,735,527

 

 

$

1,274,834

 

 

$

(1,503,059

)

 

$

2,507,302

 

  

 

  

 

   

 

  

 

 

 

(1)Began operations on May 1, 2010.

Index to Financial Statements

107


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

Condensed Consolidating Statement of IncomeOperations for the Twelve MonthsYear Ended December 31, 20112014

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

  Parent
Company
 Guarantor
Subsidiaries
   Eliminations Consolidated
W&T
Offshore, Inc.
 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

  (In thousands) 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

(In thousands)

 

Revenues

  $697,899   $273,148    $—     $971,047  

$

592,460

 

 

$

356,248

 

 

$

 

 

$

948,708

 

  

 

  

 

   

 

  

 

 

Operating costs and expenses:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

   182,165    37,041     —      219,206  

 

179,344

 

 

 

85,407

 

 

 

 

 

 

264,751

 

Production taxes

   4,275    —       —      4,275  

 

7,932

 

 

 

 

 

 

 

 

 

7,932

 

Gathering and transportation

   12,676    4,244     —      16,920  

 

11,712

 

 

 

8,109

 

 

 

 

 

 

19,821

 

Depreciation, depletion and amortization

   214,740    84,275     —      299,015  

Asset retirement obligation accretion

   26,947    2,824     —      29,771  

Depreciation, depletion, amortization and accretion

 

276,636

 

 

 

213,833

 

 

 

 

 

 

490,469

 

Asset retirement obligations accretion

 

10,981

 

 

 

9,652

 

 

 

 

 

 

20,633

 

General and administrative expenses

   71,714    2,582     —      74,296  

 

48,084

 

 

 

38,915

 

 

 

 

 

 

86,999

 

Derivative (gain) loss

   (1,896  —       —      (1,896
  

 

  

 

   

 

  

 

 

Derivative gain

 

(3,965

)

 

 

 

 

 

 

 

 

(3,965

)

Total costs and expenses

   510,621    130,966     —      641,587  

 

530,724

 

 

 

355,916

 

 

 

 

 

 

886,640

 

  

 

  

 

   

 

  

 

 

Operating income

   187,278    142,182     —      329,460  

 

61,736

 

 

 

332

 

 

 

 

 

 

62,068

 

Earnings of affiliates

   92,533    —       (92,533  —    

 

240

 

 

 

 

 

 

(240

)

 

 

 

Interest expense:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Incurred

   52,393    —       —      52,393  

 

84,460

 

 

 

2,462

 

 

 

 

 

 

86,922

 

Capitalized

   (9,877  —       —      (9,877

 

(6,064

)

 

 

(2,462

)

 

 

 

 

 

(8,526

)

Loss on extinguishment of debt

   22,694    —       —      22,694  

Interest income

   84    —       —      84  
  

 

  

 

   

 

  

 

 

Income before income tax expense

   214,685    142,182     (92,533  264,334  

Other income, net

 

208

 

 

 

 

 

 

 

 

 

208

 

Income (loss) before income tax expense (benefit)

 

(16,212

)

 

 

332

 

 

 

(240

)

 

 

(16,120

)

Income tax expense (benefit)

   41,868    49,649     —      91,517  

 

(4,551

)

 

 

92

 

 

 

 

 

 

(4,459

)

  

 

  

 

   

 

  

 

 

Net income

  $172,817   $92,533    $(92,533 $172,817  
  

 

  

 

   

 

  

 

 

Net income (loss)

$

(11,661

)

 

$

240

 

 

$

(240

)

 

$

(11,661

)

Index to Financial Statements

108


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

Condensed Consolidating Statement of IncomeOperations for the Twelve MonthsYear Ended December 31, 20102013

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

  Parent
Company
 Guarantor
Subsidiaries (1)
   Eliminations Consolidated
W&T
Offshore, Inc.
 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

  (In thousands) 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

(In thousands)

 

Revenues

  $608,600   $97,183    $—     $705,783  

$

631,267

 

 

$

352,821

 

 

$

 

 

$

984,088

 

  

 

  

 

   

 

  

 

 

Operating costs and expenses:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

   152,534    17,136     —      169,670  

 

202,096

 

 

 

68,743

 

 

 

 

 

 

270,839

 

Production taxes

   1,194    —       —      1,194  

 

7,135

 

 

 

 

 

 

 

 

 

7,135

 

Gathering and transportation

   15,338    1,146     —      16,484  

 

9,248

 

 

 

8,262

 

 

 

 

 

 

17,510

 

Depreciation, depletion and amortization

   241,105    27,310     —      268,415  

Asset retirement obligation accretion

   25,122    563     —      25,685  

Depreciation, depletion, amortization and accretion

 

236,600

 

 

 

194,011

 

 

 

 

 

 

430,611

 

Asset retirement obligations accretion

 

14,218

 

 

 

6,700

 

 

 

 

 

 

 

20,918

 

General and administrative expenses

   51,662    1,628     —      53,290  

 

44,040

 

 

 

37,834

 

 

 

 

 

 

81,874

 

Derivative (gain) loss

   4,256    —       —      4,256  
  

 

  

 

   

 

  

 

 

Derivative loss

 

8,470

 

 

 

 

 

 

 

 

 

8,470

 

Total costs and expenses

   491,211    47,783     —      538,994  

 

521,807

 

 

 

315,550

 

 

 

 

 

 

837,357

 

  

 

  

 

   

 

  

 

 

Operating income

   117,389    49,400     —      166,789  

 

109,460

 

 

 

37,271

 

 

 

 

 

 

146,731

 

Earnings of affiliates

   32,110    —       (32,110  —    

 

24,400

 

 

 

 

 

 

(24,400

)

 

 

 

Interest expense:

      

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Incurred

   43,101    —       —      43,101  

 

82,570

 

 

 

3,069

 

 

 

 

 

 

85,639

 

Capitalized

   (5,395  —       —      (5,395

 

(6,989

)

 

 

(3,069

)

 

 

 

 

 

(10,058

)

Interest income

   710    —       —      710  
  

 

  

 

   

 

  

 

 

Other income, net

 

8,946

 

 

 

 

 

 

 

 

 

8,946

 

Income before income tax expense

   112,503    49,400     (32,110  129,793  

 

67,225

 

 

 

37,271

 

 

 

(24,400

)

 

 

80,096

 

Income tax expense (benefit)

   (5,389  17,290     —      11,901  
  

 

  

 

   

 

  

 

 

Income tax expense

 

15,903

 

 

 

12,871

 

 

 

 

 

 

28,774

 

Net income

  $117,892   $32,110    $(32,110 $117,892  

$

51,322

 

 

$

24,400

 

 

$

(24,400

)

 

$

51,322

 

  

 

  

 

   

 

  

 

 

 

(1)Began operations on May 1, 2010.

Index to Financial Statements

109


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

Condensed Consolidating Statement of Operations for the Year Ended December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

 

(In thousands)

 

Revenues

$

539,958

 

 

$

334,533

 

 

$

 

 

$

874,491

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

168,033

 

 

 

64,227

 

 

 

 

 

 

232,260

 

Production taxes

 

5,840

 

 

 

 

 

 

 

 

 

5,840

 

Gathering and transportation

 

10,197

 

 

 

4,681

 

 

 

 

 

 

14,878

 

Depreciation, depletion, amortization and accretion

 

187,039

 

 

 

149,138

 

 

 

 

 

 

336,177

 

Asset retirement obligations accretion

 

14,979

 

 

 

5,076

 

 

 

 

 

 

 

20,055

 

General and administrative expenses

 

45,260

 

 

 

36,757

 

 

 

 

 

 

82,017

 

Derivative loss

 

13,954

 

 

 

 

 

 

 

 

 

13,954

 

Total costs and expenses

 

445,302

 

 

 

259,879

 

 

 

 

 

 

705,181

 

Operating income

 

94,656

 

 

 

74,654

 

 

 

 

 

 

169,310

 

Earnings of affiliates

 

49,799

 

 

 

 

 

 

(49,799

)

 

 

 

Interest expense:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Incurred

 

60,778

 

 

 

2,490

 

 

 

 

 

 

63,268

 

Capitalized

 

(10,784

)

 

 

(2,490

)

 

 

 

 

 

(13,274

)

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

 

110


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows for the Twelve MonthsYear Ended December 31, 20112014

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

  Parent
Company
 Guarantor
Subsidiaries
 Eliminations Consolidated
W&T
Offshore, Inc.
 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

  (In thousands) 

(In thousands)

 

Operating activities:

     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

  $172,817   $92,533   $(92,533 $172,817  

$

(11,661

)

 

$

240

 

 

$

(240

)

 

$

(11,661

)

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

     

Adjustments to reconcile net income (loss) to net cash

provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

   241,687    87,099    —      328,786  

 

287,617

 

 

 

223,485

 

 

 

 

 

 

511,102

 

Amortization of debt issuance costs

   2,010    —      —      2,010  

Loss on extinguishment of debt

   22,694    —      —      22,694  

Amortization of debt issuance costs and premium

 

701

 

 

 

 

 

 

 

 

 

701

 

Share-based compensation

   9,710    —      —      9,710  

 

14,744

 

 

 

 

 

 

 

 

 

14,744

 

Derivative (gain) loss

   (1,896  —      —      (1,896)

Cash payments on derivative settlements

   (9,873  —      —      (9,873

Derivative gain

 

(3,965

)

 

 

 

 

 

 

 

 

(3,965

)

Cash payments on derivative settlements, net

 

(5,318

)

 

 

 

 

 

 

 

 

(5,318

)

Deferred income taxes

   76,717    (14,882  —      61,835  

 

(32,456

)

 

 

27,696

 

 

 

 

 

 

(4,760

)

Earnings of affiliates

   (92,533  —      92,533    —    

 

(240

)

 

 

 

 

 

240

 

 

 

 

Changes in operating assets and liabilities:

     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas receivables

   (27,709  9,070    —      (18,639

 

19,553

 

 

 

9,957

 

 

 

 

 

 

29,510

 

Joint interest and other receivables

   375    —      —      375  

 

(4,255

)

 

 

 

 

 

 

 

 

(4,255

)

Insurance receivables

   20,771    —      —      20,771  

Income taxes

   (71,655  64,531    —      (7,124

 

30,747

 

 

 

(27,604

)

 

 

 

 

 

3,143

 

Prepaid expenses and other assets

   (8,003  (228,020  228,214    (7,809

 

25,555

 

 

 

12,882

 

 

 

(23,425

)

 

 

15,012

 

Asset retirement obligations

   (59,958  —      —      (59,958

Accounts payable and accrued liabilities

   8,589    (514  (194  7,881  

Other liabilities

   227,918    —      (228,020  (102
  

 

  

 

  

 

  

 

 

Asset retirement obligation settlements

 

(57,253

)

 

 

(17,060

)

 

 

 

 

 

(74,313

)

Accounts payable, accrued liabilities and other

 

12,816

 

 

 

5,242

 

 

 

23,425

 

 

 

41,483

 

Net cash provided by operating activities

   511,661    9,817    —      521,478  

 

276,585

 

 

 

234,838

 

 

 

 

 

 

511,423

 

  

 

  

 

  

 

  

 

 

Investing activities:

     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acquisition of property interest in oil and natural gas properties

   (437,247)  —      —      (437,247

 

(17,407

)

 

 

(54,827

)

 

 

 

 

 

(72,234

)

Investment in oil and natural gas properties and equipment

   (277,147  (4,632  —      (281,779

 

(312,044

)

 

 

(242,334

)

 

 

 

 

 

(554,378

)

Investment in subsidiary

   5,185    —      (5,185)  —    

 

(62,323

)

 

 

 

 

 

62,323

 

 

 

 

Purchases of furniture, fixtures, misc. sales and other

   (3,645  —      —      (3,645
  

 

  

 

  

 

  

 

 

Purchases of furniture, fixtures and other

 

(3,340

)

 

 

 

 

 

 

 

 

(3,340

)

Net cash used in investing activities

   (712,854  (4,632  (5,185  (722,671

 

(395,114

)

 

 

(297,161

)

 

 

62,323

 

 

 

(629,952

)

  

 

  

 

  

 

  

 

 

Financing activities:

     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of 8.5% Senior Notes

   600,000    —      —      600,000  

Repurchase of 8.25% Senior Notes

   (450,000  —      —      (450,000

Borrowings of long-term debt – revolving bank credit facility

   623,000    —      —      623,000  

 

556,000

 

 

 

 

 

 

 

 

 

556,000

 

Repayments of long-term debt – revolving bank credit facility

   (506,000  —      —      (506,000

 

(399,000

)

 

 

 

 

 

 

 

 

(399,000

)

Repurchase premium and debt issuance costs

   (32,288  —      —      (32,288

Dividends to shareholders

   (58,756  —      —      (58,756

 

(30,260

)

 

 

 

 

 

 

 

 

(30,260

)

Other

   1,094    —      —      1,094  

 

(345

)

 

 

 

 

 

 

 

 

(345

)

Investment from parent

   —      (5,185  5,185    —    

 

 

 

 

62,323

 

 

 

(62,323

)

 

 

 

  

 

  

 

  

 

  

 

 

Net cash provided by (used in) financing activities

   177,050    (5,185  5,185    177,050  
  

 

  

 

  

 

  

 

 

Decrease in cash and cash equivalents

   (24,143  —      —      (24,143

Net cash provided in financing activities

 

126,395

 

 

 

62,323

 

 

 

(62,323

)

 

 

126,395

 

Increase in cash and cash equivalents

 

7,866

 

 

 

 

 

 

 

 

 

7,866

 

Cash and cash equivalents, beginning of period

   28,655    —      —      28,655  

 

15,800

 

 

 

 

 

 

 

 

 

15,800

 

  

 

  

 

  

 

  

 

 

Cash and cash equivalents, end of period

  $4,512   $—     $—     $4,512  

$

23,666

 

 

$

 

 

$

 

 

$

23,666

 

  

 

  

 

  

 

  

 

 

Index to Financial Statements

111


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

Condensed Consolidating Statement of Cash Flows for the Twelve MonthsYear Ended December 31, 20102013

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

  Parent
Company
 Guarantor
Subsidiaries (1)
 Eliminations Consolidated
W&T
Offshore, Inc.
 

Company

 

 

Subsidiaries

 

 

Eliminations

 

 

Offshore, Inc.

 

  (In thousands) 

(In thousands)

 

Operating activities:

     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

  $117,892   $32,110   $(32,110 $117,892  

Net income

$

51,322

 

 

$

24,400

 

 

$

(24,400

)

 

$

51,322

 

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

     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

   266,227    27,873    —      294,100  

 

250,818

 

 

 

200,711

 

 

 

 

 

 

451,529

 

Amortization of debt issuance costs

   1,338    —      —      1,338  

Amortization of debt issuance costs and premium

 

1,645

 

 

 

 

 

 

 

 

 

1,645

 

Share-based compensation

   5,533    —      —      5,533  

 

11,525

 

 

 

 

 

 

 

 

 

11,525

 

Derivative (gain) loss

   4,256    —      —      4,256  

Derivative loss

 

8,470

 

 

 

 

 

 

 

 

 

8,470

 

Cash payments on derivative settlements

   874    —      —      874  

 

(8,589

)

 

 

 

 

 

 

 

 

(8,589

)

Deferred income taxes

   (5,511  (2,755  —      (8,266

 

7,564

 

 

 

23,356

 

 

 

 

 

 

30,920

 

Earnings of affiliates

   (32,110  —      32,110    —    

 

(24,400

)

 

 

 

 

 

24,400

 

 

 

 

Changes in operating assets and liabilities:

     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas receivables

   4,556    (29,489  —      (24,933

 

6,182

 

 

 

(5,202

)

 

 

 

 

 

980

 

Joint interest and other receivables

   25,897    —      —      25,897  

 

34,257

 

 

 

 

 

 

 

 

 

34,257

 

Insurance receivables

   54,873    —      —      54,873  

Income taxes

   84,023    20,044    —      104,067  

 

54,813

 

 

 

(10,485

)

 

 

 

 

 

44,328

 

Prepaid expenses and other assets

   4,536    (47,160  47,160    4,536  

 

(25,329

)

 

 

(18,835

)

 

 

34,120

 

 

 

(10,044

)

Asset retirement obligations

   (87,166  —      —      (87,166

 

(65,438

)

 

 

(16,105

)

 

 

 

 

 

(81,543

)

Accounts payable and accrued liabilities

   (35,278  3,393    —      (31,885

Other liabilities

   50,816    —      (47,160  3,656  
  

 

  

 

  

 

  

 

 

Accounts payable, accrued liabilities and other

 

59,961

 

 

 

717

 

 

 

(34,120

)

 

 

26,558

 

Net cash provided by operating activities

   460,756    4,016    —      464,772  

 

362,801

 

 

 

198,557

 

 

 

 

 

 

561,358

 

  

 

  

 

  

 

  

 

 

Investing activities:

     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acquisition of property interest in oil and natural gas properties

   —      (236,944  —      (236,944

 

 

 

 

(82,424

)

 

 

 

 

 

(82,424

)

Investment in oil and natural gas properties and equipment

   (174,693  (4,016  —      (178,709

 

(349,804

)

 

 

(202,150

)

 

 

 

 

 

(551,954

)

Proceeds from sales of oil and natural gas properties and equipment

   1,420    —      —      1,420  

Investment in subsidiary

   (236,944  —      236,944    —    

 

(86,017

)

 

 

 

 

 

86,017

 

 

 

 

Proceeds from sales of assets and other, net

 

21,008

 

 

 

 

 

 

 

 

 

21,008

 

Purchases of furniture, fixtures and other

   (760  —      —      (760

 

(1,435

)

 

 

 

 

 

 

 

 

(1,435

)

  

 

  

 

  

 

  

 

 

Net cash used in investing activities

   (410,977  (240,960  236,944    (414,993

 

(416,248

)

 

 

(284,574

)

 

 

86,017

 

 

 

(614,805

)

  

 

  

 

  

 

  

 

 

Financing activities:

     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Borrowings of revolving bank credit facility

   627,500    —      —      627,500  

Repayments of revolving bank credit facility

   (627,500  —      —      (627,500

Borrowings of long-term debt – revolving bank credit facility

 

563,000

 

 

 

 

 

 

 

 

 

563,000

 

Repayments of long-term debt – revolving bank credit facility

 

(443,000

)

 

 

 

 

 

 

 

 

(443,000

)

Debt issuance costs

 

(3,892

)

 

 

 

 

 

 

 

 

(3,892

)

Dividends to shareholders

   (59,609  —      —      (59,609

 

(58,846

)

 

 

 

 

 

 

 

 

(58,846

)

Investment from parent

 

 

 

 

86,017

 

 

 

(86,017

)

 

 

 

Other

   298    —      —      298  

 

(260

)

 

 

 

 

 

 

 

 

(260

)

Investment from parent

   —      236,944    (236,944  —    
  

 

  

 

  

 

  

 

 

Net cash provided by (used in) financing activities

   (59,311  236,944    (236,944  (59,311
  

 

  

 

  

 

  

 

 

Decrease in cash and cash equivalents

   (9,532  —      —      (9,532

Net cash used in financing activities

 

57,002

 

 

 

86,017

 

 

 

(86,017

)

 

 

57,002

 

Increase in cash and cash equivalents

 

3,555

 

 

 

 

 

 

 

 

 

3,555

 

Cash and cash equivalents, beginning of period

   38,187    —      —      38,187  

 

12,245

 

 

 

 

 

 

 

 

 

12,245

 

  

 

  

 

  

 

  

 

 

Cash and cash equivalents, end of period

  $28,655   $—     $—     $28,655  

$

15,800

 

 

$

 

 

$

 

 

$

15,800

 

  

 

  

 

  

 

  

 

 

 

(1)Began operations on May 1, 2010.

Index to Financial Statements

112


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

22.

Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

 

Parent

 

 

Guarantor

 

 

 

 

 

 

W&T

 

 

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:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

202,018

 

 

 

154,214

 

 

 

 

 

 

356,232

 

Amortization of debt issuance costs and premium

 

2,575

 

 

 

 

 

 

 

 

 

2,575

 

Share-based compensation

 

12,398

 

 

 

 

 

 

 

 

 

12,398

 

Derivative loss

 

13,954

 

 

 

 

 

 

 

 

 

13,954

 

Cash payments on derivative settlements

 

(7,664

)

 

 

 

 

 

 

 

 

(7,664

)

Deferred income taxes

 

81,653

 

 

 

6,456

 

 

 

 

 

 

88,109

 

Earnings of affiliates

 

(49,799

)

 

 

 

 

 

49,799

 

 

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas receivables

 

(3,783

)

 

 

4,601

 

 

 

 

 

 

818

 

Joint interest and other receivables

 

(28,823

)

 

 

 

 

 

 

 

 

(28,823

)

Income taxes

 

(76,411

)

 

 

18,400

 

 

 

 

 

 

(58,011

)

Prepaid expenses and other assets

 

9,017

 

 

 

(119,895

)

 

 

118,318

 

 

 

7,440

 

Asset retirement obligations

 

(105,773

)

 

 

(7,054

)

 

 

 

 

 

(112,827

)

Accounts payable, accrued liabilities  and other

 

159,774

 

 

 

(2,504

)

 

 

(118,318

)

 

 

38,952

 

Net cash provided by operating activities

 

281,120

 

 

 

104,017

 

 

 

 

 

 

385,137

 

Investing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acquisition of property interest in oil and natural gas properties

 

(151,429

)

 

 

(54,121

)

 

 

 

 

 

(205,550

)

Investment in oil and natural gas properties and equipment

 

(375,296

)

 

 

(104,017

)

 

 

 

 

 

(479,313

)

Investment in subsidiary

 

(54,121

)

 

 

 

 

 

54,121

 

 

 

 

Proceeds from sales of assets and other, net

 

30,453

 

 

 

 

 

 

 

 

 

30,453

 

Purchases of furniture, fixtures and other

 

(3,031

)

 

 

 

 

 

 

 

 

(3,031

)

Net cash used in investing activities

 

(553,424

)

 

 

(158,138

)

 

 

54,121

 

 

 

(657,441

)

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

 

Repayments of long-term debt – revolving bank credit facility

 

(679,000

)

 

 

 

 

 

 

 

 

(679,000

)

Debt issuance costs

 

(8,510

)

 

 

 

 

 

 

 

 

(8,510

)

Dividends to shareholders

 

(82,832

)

 

 

 

 

 

 

 

 

(82,832

)

Investment from parent

 

 

 

 

54,121

 

 

 

(54,121

)

 

 

 

Other

 

379

 

 

 

 

 

 

 

 

 

379

 

Net cash used in financing activities

 

280,037

 

 

 

54,121

 

 

 

(54,121

)

 

 

280,037

 

Increase in cash and cash equivalents

 

7,733

 

 

 

 

 

 

 

 

 

7,733

 

Cash and cash equivalents, beginning of period

 

4,512

 

 

 

 

 

 

 

 

 

4,512

 

Cash and cash equivalents, end of period

$

12,245

 

 

$

 

 

$

 

 

$

12,245

 

113


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

21. Supplemental Oil and Gas Disclosures – 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.  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,

 

  2011 2010 2009 

2014

 

 

2013

 

 

2012

 

Net capitalized cost:

    

 

 

 

 

 

 

 

 

 

 

 

Proved oil and natural gas properties and equipment

  $5,775.4   $5,130.9   $4,637.2  

$

7,924.2

 

 

$

7,207.1

 

 

$

6,551.5

 

Unproved oil and natural gas properties and equipment

   183.6    94.7    95.5  

 

121.5

 

 

 

132.0

 

 

 

143.0

 

Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities

   (4,307.1  (4,009.9  (3,743.3

 

(5,557.6

)

 

 

(5,069.2

)

 

 

(4,640.8

)

  

 

  

 

  

 

 

Net capitalized costs related to producing activities

  $1,651.9   $1,215.7   $989.4  

$

2,488.1

 

 

$

2,269.9

 

 

$

2,053.7

 

  

 

  

 

  

 

 

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, 2011,2014, by the year in which the costs were incurred (in millions):

 

  Total   2011   2010   2009   Prior to
2009
 

Total

 

 

2014

 

 

2013

 

 

2012

 

 

Prior to

2012

 

Costs excluded by year incurred:

          

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acquisition costs

  $125.7    $81.3    $ —      $ —      $44.4  

$

75.5

 

 

$

2.6

 

 

$

5.7

 

 

$

7.0

 

 

$

60.2

 

Capitalized interest not subject to amortization

   28.8     9.6     4.8     4.2     10.2  

 

34.3

 

 

 

7.5

 

 

 

7.3

 

 

 

6.4

 

 

 

13.1

 

  

 

   

 

   

 

   

 

   

 

 

Total costs not subject to amortization

  $154.5    $90.9    $4.8    $4.2    $54.6  

$

109.8

 

 

$

10.1

 

 

$

13.0

 

 

$

13.4

 

 

$

73.3

 

  

 

   

 

   

 

   

 

   

 

 

Index to Financial Statements


114


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—STATEMENTS (Continued)

 

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):

 

   Year Ended December 31, 
   2011   2010   2009 

Costs incurred (1):

      

Proved property acquisitions

  $369.9    $277.3    $17.5  

Development

   203.7     158.3     142.9  

Exploration (2) (3)

   92.7     70.8     101.6  

Unproved property acquisitions (4)

   95.1     19.7     12.2  
  

 

 

   

 

 

   

 

 

 

Total costs incurred in oil and gas property acquisition, exploration and development activities

  $761.4    $526.1    $274.2  
  

 

 

   

 

 

   

 

 

 

 

December 31,

 

 

2014

 

 

2013

 

 

2012

 

Costs incurred: (1)

 

 

 

 

 

 

 

 

 

 

 

Proved properties acquisitions

$

111.5

 

 

$

96.9

 

 

$

239.8

 

Exploration (2) (3)

 

411.1

 

 

 

215.3

 

 

 

151.3

 

Development

 

198.7

 

 

 

352.9

 

 

 

363.7

 

Unproved properties acquisitions (4)

 

3.1

 

 

 

26.3

 

 

 

26.5

 

Total costs incurred in oil and gas property acquisition,

      exploration and development activities

$

724.4

 

 

$

691.4

 

 

$

781.3

 

(1)

Includes net additions (reductions) to ourfrom capitalized ARO of $32.8$88.0 million, $106.1$50.6 million and ($6.0)$86.9 million during the years 2011, 20102014, 2013 and 2009,2012, respectively, associated with acquisitions, liabilities incurred and revisions of estimates.  Refer to Note 5.

(2)

Includes seismic costs of $8.0$9.0 million, $5.8$8.9 million and $6.6$6.2 million incurred during the years 2011, 20102014, 2013 and 2009,2012, respectively.

(3)

Includes geological and geophysical costs charged to expense of $6.8$7.3 million, $4.3$5.9 million and $4.1$6.2 million during the years 2011, 20102014, 2013 and 2009,2012, respectively.

(4)

The amounts for 2011, 2010 and 2009unproved property acquisitions include capitalized interest associated with unproved properties classified as unproved at December 31, 2011, 2010 and 2009, respectively.acquired during the period.

Depreciation, depletion, amortization and accretion expense

The following table presents our depreciation, depletion, amortization and accretion expense per million cubic feetbarrel equivalent (“Mcfe”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, 
   2011   2010   2009 

Depreciation, depletion, amortization and accretion per Mcfe

  $3.24    $3.38    $3.61  

Oil and Natural Gas Reserve Information

Effective for our annual reporting period ended December 31, 2009, we adopted certain amendments to theExtractive Activities – Oil and Gas topic of the Codification that updated and aligned the FASB’s reserve estimation and disclosure requirements for oil and natural gas companies with the reserve estimation and disclosure requirements that were adopted by the SEC in December 2008. In accordance with the new rules, we use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period, rather than end-of-period commodity prices, 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 impairment were changed from end-of-period commodity prices to the 12-month average commodity prices. Another significant provision of the new rules is a general requirement that, subject to limited exceptions, 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. As the rules are effective for December 31, 2009 and were not applied retroactively, the data for 2008 may not be comparable to the data for 2009, 2010 and 2011. In addition to the oil and gas reserve information, the amendments impacted our financial position and the results of

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

operations as they affected our determination of DD&A expense and the calculations used in determining impairment under the ceiling test rules. The amendments did not have an impact to our cash flows.

For the year 2009, the following items were affected by the change in the rules. The initial application of these rules resulted in the removal of 3.9 million barrels of oil equivalent (“MMBoe”) (23.2 billion cubic feet equivalent (“Bcfe”)) in the year 2009 of proved undeveloped reserves associated with two of our fields for which our plan of development was not within five years from when the reserves were initially recorded, as required. The impact on our DD&A expense for 2009 related to the adoption of these amendments to the Codification was an approximate $7.6 million ($0.08 per Mcfe) increase in DD&A.

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 datainformation represent 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 10%11% of our proved developed non-producing reserves, so we may not be in a position to control the timing of all development activities.

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, (including natural gas liquids)NGLs and natural gas reserves, virtually allreserves.  All of whichthe reserves are located offshorein the Unites States with 69% located in the Gulf of Mexico.Mexico and the remainder located in the West Texas Permian Basin.  These 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 economically 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”.

 

            Total Equivalent Reserves 
   Oil
(MMBbls) (1)
  NGLs
(MMBbls) (1)
  Natural Gas
(Bcf) (1)
  Oil
Equivalent
(MMBoe) (2)
  Natural Gas
Equivalent
(Bcfe) (2)
 

Proved reserves as of December 31, 2008

   40.0    3.9    227.9    81.9    491.1  

Revisions of previous estimates (3)

   (2.1  —      (13.0  (4.3  (25.4

Extensions and discoveries (4)

   1.2    0.3    14.5    3.9    23.4  

Purchase of minerals in place

   —      —      0.4    0.1    0.7  

Sales of reserves (5)

   (1.8  (0.1  (12.4  (4.0  (24.0

Production

   (6.1  (1.1  (51.6  (15.8  (94.8
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Proved reserves as of December 31, 2009

   31.2    3.0    165.8    61.8    371.0  

Revisions of previous estimates (6)

   (0.2  1.2    14.6    3.4    20.2  

Extensions and discoveries (7)

   1.2    0.5    19.1    4.9    29.2  

Purchase of minerals in place (8)

   7.7    0.7    101.5    25.3    152.0  

Production

   (5.9  (1.2  (44.7  (14.5  (87.0
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Proved reserves as of December 31, 2010

   34.0    4.2    256.3    80.9    485.4  

Revisions of previous estimates (9)

   0.8    5.5    13.5    8.6    51.1  

Extensions and discoveries (10)

   2.0    0.4    17.7    5.3    32.0  

Purchase of minerals in place (11)

   20.7    8.9    55.9    39.0    234.1  

Production

   (6.1  (1.9  (53.7  (16.9  (101.5
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Proved reserves as of December 31, 2011

   51.4    17.1    289.7    116.9    701.1  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Year-end proved developed reserves:

      

2011

   23.4    11.0    251.4    76.4    458.2  

2010

   23.6    3.4    229.1    65.2    391.3  

2009

   21.3    2.4    141.3    47.3    283.5  

Year-end proved undeveloped reserves:

      

2011

   28.0    6.1    38.3    40.5    242.9  

2010

   10.4    0.8    27.2    15.7    94.1  

2009

   9.9    0.6    24.5    14.5    87.5  

 

115


W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Energy Equivalent Reserves (1)

 

 

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

 

Revisions of previous estimates (2)

 

(1.1

)

 

 

(2.6

)

 

 

(4.8

)

 

 

(4.6

)

 

 

(27.5

)

Extensions and discoveries (3)

 

8.2

 

 

 

2.6

 

 

 

29.6

 

 

 

15.7

 

 

 

94.5

 

Purchase of minerals in place (4)

 

2.5

 

 

 

0.2

 

 

 

25.5

 

 

 

7.0

 

 

 

42.0

 

Sales of reserves (5)

 

(0.2

)

 

 

 

 

 

(1.1

)

 

 

(0.4

)

 

 

(2.2

)

Production

 

(6.0

)

 

 

(2.1

)

 

 

(53.8

)

 

 

(17.1

)

 

 

(102.8

)

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

)

Extensions and discoveries (7)

 

13.9

 

 

 

2.6

 

 

 

22.0

 

 

 

20.2

 

 

 

121.0

 

Purchase of minerals in place (8)

 

1.5

 

 

 

 

 

 

4.4

 

 

 

2.3

 

 

 

13.7

 

Sales of reserves (9)

 

(0.4

)

 

 

 

 

 

(0.4

)

 

 

(0.5

)

 

 

(3.2

)

Production

 

(7.0

)

 

 

(2.1

)

 

 

(53.3

)

 

 

(18.0

)

 

 

(107.9

)

Proved reserves as of Dec. 31, 2013

 

58.5

 

 

 

15.9

 

 

 

259.9

 

 

 

117.7

 

 

 

705.9

 

Revisions of previous estimates (10)

 

1.6

 

 

 

0.1

 

 

 

14.3

 

 

 

4.1

 

 

 

25.3

 

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

)

Proved reserves as of Dec. 31, 2014

 

61.7

 

 

 

15.8

 

 

 

254.9

 

 

 

120.0

 

 

 

720.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year-end proved developed reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

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

 

(1)

Volume measurements:

Estimated reserves as

Bbl – barrel

Mcf – thousand cubic feet

MMBbls – million barrels for crude oil, condensate or NGLs

Bcf – billion cubic feet

MMBoe – million barrels of December 31, 2011, 2010 and 2009 are based on the unweighted averageoil equivalent

Bcfe – billion cubic feet of first-day-of-the-month commodity prices over the period January through December for those years in accordance with current definitions and guidelines set forth by the SEC and the FASB. Estimated of reserves as of December 31, 2008 were based on end-of-year prices.gas equivalent


116


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(2)

(1)

Bcfe

The conversion to barrels of oil equivalent and MMBoe arecubic feet equivalent were determined using the energy-equivalent ratio of six thousand cubic feet (“Mcf”)Mcf of natural gas to one barrel (“Bbl”)Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding).  The conversionenergy-equivalent ratio does not assume price equivalency, and the price per Mcfeenergy-equivalent prices for oil, and NGLs may differ significantly from the price per Mcf for natural gas. Similarly, the price per Bbl for oil for may differ significantly from the price per Bbl for NGLs.

(3)

Revisions for 2009 included decreases attributable to revised reserve reporting requirements for oil and natural gas companies enacted by the SEC and the FASB, which became effective for annual reporting periods ending on or after December 31, 2009. The initial application of these rules resulted in the removalmay differ significantly.

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(2)

of 23.2 Bcfe of proved undeveloped reserves associated with two of our fields for which our plan of development was not within five years from when the reserves were initially recorded, as required. Also included in the revisions of previous estimates for 2009 are negative revisions of 4.7 Bcfe due to performance.
(4)The majority of these volumes are attributable to extensions and discoveries resulting from our participation in the drilling of eight successful exploratory wells in 2009, all of which were on the conventional shelf.
(5)In the second quarter of 2009, we sold one of our fields in Louisiana state waters, and in the fourth quarter of 2009, we sold 36 non-core oil and natural gas fields in the Gulf of Mexico, subject to the terms of the purchase and sale agreements.
(6)

Includes downward revisions due to price of 17.5 Bcfe.1.3 MMBoe and negative performance revisions of 3.0 MMBoe at our Spraberry field.

(7)

(3)

Includes extensions and discoveries of 21.9 Bcfe primarily11.6 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 Main Pass 98field and Main Pass 283 fields0.5 MMBoe our South Timbalier 176 field.  

(7)

Includes extensions and extensionsdiscoveries of 7.2 Bcfe primarily in the Main Pass 28312.6 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 properties acquired from Total (Matterhorn and Virgo fields) andacquisition of the properties acquired from Shell (Tahoe, Southeast Tahoe and Droshky fields).Callon Properties.

(9)

Includes revision of 6.3 Bcfe due to an increase in average prices, 16.5 Bcfe for a change in NGLs marketing arrangements that allow us to recover a greater percentage of our NGLs from the gas stream, 11.3 Bcfe increase due to additional compression at our Tahoe field that allows us to reduce the drawdown pressure that increases production and ultimate recoveries, and 10.6 Bcfe at Fairway for revisions to reserve estimates from the acquisition date to year end.
(10)Includes discoveries of 13.9 Bcfe at Main Pass 98 and 8.0 Bcfe at Ship Shoal 349/359 and extensions of 3.7 Bcfe at Main Pass 108.
(11)

Primarily due to the properties acquired from Opal (the Yellow Rose Properties)sales of our non-working interests in the Green Canyon 60 field, the Green Canyon 19 field and the properties acquiredWest 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, 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 Spraberry field and 2.4 MMBoe at various other fields.

(11)

Includes extensions and discoveries of 4.1 MMBoe at our Spraberry field and 4.1 MMBoe at our Mississippi Canyon 782 field.

(12)

Primarily due to acquiring additional ownership in the Fairway field and acquisition of the Woodside Properties.

(13)

We believe that we will be able to develop all but 1.4 MMBoe of the reserves classified as proved undeveloped (“PUDs”), or approximately 96%, out of the total of 36.7 MMBoe classified as PUDs at December 31, 2014, within five years from Shell (the Fairway Properties).the date such reserves were initially recorded.  The 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 were originally recorded in our reserves as of December 31, 2010.  The development of the 1.4 MMBoe of PUDs 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) PUDs in 2020.

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, as defined by the FASB.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 December 31, 2011, 2010 and 2009 and period-end commodity prices for December 31, 2008 (beginning of 2009).the periods presented.  All prices are adjusted by leasefield 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:

 

   December 31, 
   2011   2010   2009   2008 

Oil – per barrel

  $97.36    $76.28    $55.87    $38.85  

NGLs – per barrel

   51.30     44.92     33.36     25.90  

Natural gas – per Mcf

   4.11     4.57     3.80     6.17  

 

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


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 of future income taxes, have been discounted to their present values based on a 10% annual discount rate.

Index to Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 20122014 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 thousands)millions):

 

   Year Ended December 31, 
   2011  2010  2009 

Standardized Measure of Discounted Future Net Cash Flows

    

Future cash inflows

  $7,077,206   $3,953,655   $2,474,260  

Future costs:

    

Production

   (1,862,488  (1,011,552  (604,794

Development

   (543,017  (243,570  (212,835

Dismantlement and abandonment

   (513,620  (520,490  (496,540

Income taxes

   (1,126,573  (495,696  (186,101
  

 

 

  

 

 

  

 

 

 

Future net cash inflows before 10% discount

   3,031,508    1,682,347    973,990  

10% annual discount factor

   (1,025,131  (503,275  (313,594
  

 

 

  

 

 

  

 

 

 
  $2,006,377   $1,179,072   $660,396  
  

 

 

  

 

 

  

 

 

 
   Year Ended December 31, 
   2011  2010  2009 

Changes in Standardized Measure

    

Standardized measure, beginning of year

  $1,179,072   $660,396   $761,682  

Increases (decreases):

    

Sales and transfers of oil and gas produced, net of production costs

   (729,574  (521,551  (386,331

Net changes in price, net of future production costs

   634,174    367,575    (34,841

Extensions and discoveries, net of future production and development costs

   219,924    143,612    98,087  

Changes in estimated future development costs

   (4,572  (59,124  144,590  

Previously estimated development costs incurred

   173,911    97,188    224,802  

Revisions of quantity estimates

   204,988    94,735    (86,600

Accretion of discount

   135,791    68,862    78,789  

Net change in income taxes

   (398,204  (221,226  (32,394

Purchases of reserves in-place

   483,286    624,302    (9,927

Sales of reserves in-place

   —      —      (205,691

Changes in production rates due to timing and other

   107,581    (75,697  108,230  
  

 

 

  

 

 

  

 

 

 

Net increase (decrease) in standardized measure

   827,305    518,676    (101,286
  

 

 

  

 

 

  

 

 

 

Standardized measure, end of year

  $2,006,377   $1,179,072   $660,396  
  

 

 

  

 

 

  

 

 

 

 

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. Index toChanges in and Disagreements With Accountants on Accounting and Financial Statements

Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Disclosure

None.

 

Item 9A.Controls and Procedures

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that material 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 SECSEC’s rules and forms and that any material 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, 20112014 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, 2011,2014, is set forth inManagement’s Report on Internal Control over Financial Reporting”Reporting included inunder Part II, Item 8 ofin 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, 2011,2014, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included inunder Part II, Item 8 ofin 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, 20112014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

Item 9B.Other Information

Item 9B. Other Information

None.

Index to Financial Statements

PART III

 

Item 10.Directors, Executive Officers and Corporate Governance


PART 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

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

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

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

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.

PART IV

 

Item 15.Exhibits and Financial Statement Schedules


PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Documents filed as a part of this report:

1.

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

  

2.Exhibits:

Description

Exhibit

Number2.1

Description

2.1Agreement and Plan of Merger, effective October 1, 2005, among Kerr-McGee Oil & Gas Corporation, Kerr-McGee Oil & Gas (Shelf) LLC, W&T Offshore, Inc., and W&T Energy V, LLC. (Incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K, filed January 27, 2006)
2.2Purchase and Sale Agreement, effective January 1, 2010, between Total E&P USA Inc. and W&T Offshore, Inc. (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed on May 3, 2010)

Index to Financial Statements

Exhibit

Number

Description

  2.3Asset Purchase Agreement, dated November 3, 2010, between Shell Offshore, Inc., as Seller, and W&T Offshore, Inc. and W&T Energy VI, LLC, as Purchasers. (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed November 9, 2010)
  2.4Purchase and Sale Agreement, dated April 21, 2011September 17, 2012, between Opal Resources,Newfield Exploration Company, Newfield Exploration Gulf Coast LLC, Opal Resources Operating Company LLCas Sellers, and W&T Offshore, Inc. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed May 13, 2011)October 12, 2012 (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))

  3.1

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)2006 (File No. 001-32414))

3.2

  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))

4.1

Specimen Common Stock 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

  4.4

Purchase Agreement, dated June 3, 2011, by and among W&T Offshore, Inc., W&T Energy VI, LLC and W&T Energy VII, LLC, and Morgan Stanley & Co. LLC, as representative of the Initial Purchasers. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed June 8, 2011)
  4.5

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.  (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed June 16, 2011)15, 2011 (File No. 001-32414))

4.3

  4.6

Form

First Supplemental Indenture, dated as of 8.5% Senior Notes due 2019. (included in Exhibit 4.4)

  4.7Registration Rights Agreement, dated June 10, 2011, by and among W&T Offshore, Inc., the Guarantors named therein and Morgan Stanley & Co. LLC,Wells Fargo Bank, National Association, as representative of the Initial Purchasers.trustee.  (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed June 15, 2011)2011 (File No. 001-32414))

4.4

Form of 8.50% Senior Notes due 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**

Form of Indemnification and Hold Harmless Agreement between W&T Offshore, Inc. and each of its directors.
10.2*

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*

10.3*

Indemnification and Hold Harmless Agreement by and between W&T Offshore, Inc. and Stephen L. Schroeder, dated July 5, 2006.  (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed July 12, 2006)2006 (File No. 001-32414))

10.3*

10.4*

Indemnification and Hold Harmless Agreement by and between W&T Offshore, Inc. and John D. Gibbons, dated as of February 26, 2007.  (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed February 26, 2007)2007 (File No. 001-32414))


Exhibit
Number

Description

10.4*

10.5*

Indemnification and Hold Harmless Agreement, dated September 24, 2008, by and between W&T Offshore, Inc. and Jamie L. Vazquez.  (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K, filed September 26, 2008)2008 (File No. 001-32414))

10.5*

10.6*

W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan.  (Incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A, filed April 2, 2010)

2010 (File No. 001-32414))

Index to Financial Statements

Exhibit

Number10.6*

Description

  10.7*Resignation Agreement dated as of July 1, 2010 between W. Reid Lea and

First Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.1 ofAppendix A to the Company’s Current ReportDefinitive Proxy Statement on Form 8-K,Schedule 14A filed July 8, 2010)April 3, 2013)

10.7*

Second 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 April 3, 2013)

10.8*

Form of Employment Agreement for Executive Officers other than the Chief Executive Officer.  (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed August 6, 2010)2010 (File No. 001-32414))

10.9*

  10.9*

Form of the Executive Annual Incentive Award Agreement for Fiscal Year 2010. (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
  10.10*Form of the Executive Restricted Stock Unit Agreement. (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
  10.11*

Employment Agreement forbetween W&T Offshore, Inc. and Tracy W. Krohn.Krohn dated as of November 1, 2010.  (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on November 5, 2010)2010 (File No. 001-32414))

10.10*

Form of Indemnification and Hold Harmless Agreement between W&T Offshore, Inc. and each of its 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))

  10.12*

10.11*

Form of Employment Agreement by and between W&T Offshore, Inc. and Jesus G. Melendrez.Thomas P. Murphy.  (Incorporated by reference to Exhibit 10.1 ofto the Company’s Current Report on Form 8-K, filed January 19, 2011)August 6, 2010 (File No. 001-32414))

10.12*

  10.13*

Indemnification and Hold Harmless Agreement by and between W&T Offshore, Inc. and Jesus G. Melendrez.Thomas P. Murphy, dated as of June 19, 2012.  (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed January 19, 2011)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

10.14*

Fourth

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.  (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

Fifth Amended and Restated Credit Agreement, dated May 5, 2011,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. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed May 6, 2011)November 13, 2013 (File No. 001-32414))

10.18*

  10.15*

Form of the Executive Annual Incentive Award Agreement for Fiscal Year 2011.2014.  (Incorporated by reference to Exhibit 10.2 to10.1 of the Company’s Quarterly Report on Form 10-Q, for the quarter ended September 30, 2011)filed May 8, 2014 (File No. 001-32414))

10.19*

Form of 2014 Executive Restricted Stock Unit 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*

Tracy W. Krohn Executive Annual Incentive Agreement for Fiscal 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**

Ratio of Earnings to Fixed Charges


Exhibit
Number

Description

14.1

  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**

  21.1**

Subsidiaries of the Registrant.

23.1**

  23.1**

Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.

23.2**

  23.2**

Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.

31.1**

  31.1**

Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

31.2**

  31.2**

Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

32.1**

  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**

  99.1**

Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.

101.INS**

101.INS**

XBRL Instance Document.

Index to Financial Statements

Exhibit

Number101.SCH**

Description

XBRL Schema Document.

101.SCH*

101.CAL**

XBRL Schema Document.
101.CAL**

XBRL Calculation Linkbase Document

101.DEF**

101.DEF**

XBRL Definition Linkbase Document.

101.LAB**

101.LAB**

XBRL Label Linkbase Document.

101.PRE**

101.PRE**

XBRL Presentation Linkbase Document.

 

*

Management Contract or Compensatory Plan or Arrangement.

**

Filed or furnished herewith.

Index to Financial Statements


GLOSSARY OF OIL AND NATURAL 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.

AcquisitionsAcquisitions. Refers to acquisitions, mergers or exercise of preferential rights of purchase.

BblBbl. One stock tank barrel or 42 U.S. gallons liquid volume.

BcfBcf. Billion cubic feet.

BcfeBcfe. One billion cubic feet equivalent, determined using aan energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

BoeBoe. 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.

BOEMREBOEMRE.. 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.

BSEEBSEE. 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.

DeepwaterDeepwater. 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.

Index to Financial Statements

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.

FieldField. 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.


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

MBoeMBoe. One thousand barrels of oil equivalent.

McfMcf. One thousand cubic feet.

McfeMcfe. One thousand cubic feet equivalent, determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl 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.

MMBoeMMBoe. One million barrels of oil equivalent.

MMBtuMMBtu. One million British thermal units.

MMcfMMcf. One million cubic feet.

MMcfeMMcfe. One million cubic feet equivalent, determined using aan energy-equivalent ratio of six Mcf of natural gas to one Bbl 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.

NGLsNGLs. 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. OCS.Outer continental shelf.shelf

OCS block. A unit of defined area for purposes of management of offshore petroleum exploration and production by the BOEM.

ONRRONRR.. 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.

Index to Financial Statements

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 – producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – 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 producibility 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.

RecompletionRecompletion. 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.

ReservesReserves. 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.

ReservoirReservoir. 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.

Index to Financial Statements

Supra-saltSupra-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 producibility 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.

Index to Financial Statements


SIGNATURES

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 February 27, 2012.March 6, 2015.

 

W&T OFFSHORE, INC.

By:

/S/    JOHN D. GIBBONS        

By:

/s/ John D. Gibbons

John D. Gibbons

Senior Vice President and Chief Financial Officer and

Chief Accounting 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 February 27, 2012.March 6, 2015.

 

/S/    TRACY W. KROHN        

s/ Tracy W. Krohn

Chairman, Chief Executive Officer and Director (Principal

Tracy W. Krohn

(Principal Executive Officer)

/S/    JOHN D. GIBBONS        

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 (Principal Financial and

Karen S. Acree

(Principal Accounting Officer)

/S/    VIRGINIA BOULET        

s/ Virginia Boulet

Director

Virginia Boulet

/S/    SAMIR G. GIBARA        

Samir G. Gibaras/ Robert I. Israel

Director

Robert I. Israel

/S/    ROBERT I. ISRAEL        

Robert I. Israels/ Stuart B. Katz

Director

Stuart B. Katz

/S/    STUART B. KATZ        

Stuart B. Katzs/ S. James Nelson, Jr 

Director

/S/    S. JAMES NELSON, JR        

S. James Nelson, Jr.

/s/ B. Frank Stanley

Director

/S/    B. FRANK STANLEY        

B. Frank Stanley

Director

 

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