UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-K
| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20142017
or
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number 1-32414
W&T OFFSHORE, INC.
(Exact name of registrant as specified in its charter)
Texas |
| 72-1121985 |
(State or other jurisdiction of incorporation or organization) |
| (I.R.S. Employer |
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Nine Greenway Plaza, Suite 300 Houston, Texas |
| 77046-0908 |
(Address of principal executive offices) |
| (Zip Code) |
(713) 626-8525
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class |
| Name of Each Exchange on Which Registered |
Common Stock, par value $0.00001 |
| New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨☐ No þ☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨☐ No þ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ☑ No ¨☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every interactive data file required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ☑ No ¨☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ☑
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer |
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Non-accelerated filer |
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(Do not check if a smaller reporting company) | Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨☐ No þ☑
The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $571,144,000$182,243,000 based on the closing sale price of $16.37$1.96 per share as reported by the New York Stock Exchange on June 30, 2014.2017.
The number of shares of the registrant’s common stock outstanding on March 3, 2015February 28, 2018 was 75,899,415.139,091,289.
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.
TABLE OF CONTENTS
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Item 1. |
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Item 1A. |
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Item 1B. |
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Item 2. |
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Item 5. |
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Item 6. |
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Item 7. |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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Item 9. |
| Changes in and Disagreements With Accountants on Accounting and Financial Disclosure |
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Item 10. |
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Item 11. |
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Item 12. |
| Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
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Item 13. |
| Certain Relationships and Related Transactions, and Director Independence |
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Item 14. |
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i
This Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors, and market risks are discussed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of this Annual Report on Form 10-K and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission (“SEC”). Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We assume no obligation, nor do we intend, to update these forward-looking statements, unless required by law. Unless the context requires otherwise, references in this Annual Report on Form 10-K to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.
iii
W&T Offshore, Inc. is an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties primarily in the Gulf of Mexico and the Permian Basin in West Texas.Mexico. W&T Offshore, Inc. is a Texas corporation originally organized as a Nevada corporation in 1988, and successor by merger to W&T Oil Properties, Inc., a Louisiana corporation organized in 1983.
We have grown through acquisitions, exploration and development and currently hold working interests in 49 offshore fields in federal and state waters (47 producing and two fields capable of producing). We currently have under lease approximately 700,000 gross acres (370,000 net acres) spanning across the Outer Continental Shelf (“OCS”) off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 470,000 gross acres on the conventional shelf and approximately 230,000 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. We currently own interests in approximately 135 offshore structures, 87 of which are located in fields that we operate. Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. and our wholly-ownwholly-owned subsidiary, W & T Energy VI, LLC, a Delaware limited liability company.
The Gulf of Mexico is an area where we have developed significant technical expertise and where high production rates associated with hydrocarbon deposits have historically provided us the best opportunity to achieve a rapid return on our invested capital. We have leveraged our historic experience in the conventional shelf (water depths of less than 500 feet) to develop higher impact capital projects in the Gulf of Mexico in both the deepwater (water depths in excess of 500 feet) and the deep shelf (well depths in excess of 15,000 feet and water depths of less than 500 feet). We have acquired rights to explore and develop new prospects and acquired existing oil and natural gas properties in both the deepwater and the deep shelf, while at the same time continuing our focus on the conventional shelf. Over the last severalOur drilling efforts in recent years we have shifted our focus more towardincluded the deepwater of the Gulf of Mexico. During 2017 and to onshore in the Permian Basin2016, a portion of West Texas. Inour production was from the deepwater we have completed numerous acquisitionsfields, Big Bend and drilledDantzler, which commenced production in late 2015. The reserves of both explorationof these are comprised of over 75% oil and development wells. Our deepwater acreage has expanded considerably and currently represents almost half of our offshore acreagenatural gas liquids (“NGLs”) on a gross acreageBoe basis.
Our onshore activities have been primarily in the Permian Basin in West Texas, where most of our leasehold interests were acquired in a single 2011 acquisition. During 2014, we reassigned most of our interest in East Texas acreage acquired in 2011 back to the original assignor and currently have limited leasehold interest in East Texas and Louisiana.
As of December 31, 2014,2017, the Big Bend field was in our top ten fields based on reserves, net to our interest, on a Boe basis.
In managing our business, we are focused on optimizing production and growing reserves in a profitable and prudent manner, while managing cash flows to meet our obligations and investment needs. Our cash flows are materially impacted by the prices of our commodities produced (crude oil and natural gas, and the NGLs extracted from the natural gas). In addition, the prices of goods and services used in our business impact our cash flows and margins. During 2017, commodity prices improved from the lower price levels experienced during 2016 and 2015, but were nonetheless below the levels realized in years prior to 2015. Our margins in 2017 have improved from 2016 and 2015 levels, and are approaching the margin levels achieved prior to 2015. Although we have interestshistorically grown our reserves and production through both acquisitions and our drilling programs, for the last three years we have focused on increasing reserves and production through drilling and through projects to optimize production from existing wells. While our production decreased 5.2% in offshore leases covering approximately 1.1 million gross acres (0.7 million2017 from the prior year, our reserves increased more than production and resulted in a net acres) spanning acrossincrease in reserves year-over-year. The increase in proved reserves is a result of drilling, recompletion and workover effects, and improved commodity prices. During 2017, we drilled five wells on 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 50,000 gross acres (40,000 net acres), substantially allfour of which are in Texas. Approximately 58% of our total net offshore acreage is developed,were successful and approximately 62% of our total net onshore acreage is developed.began producing during 2017.
Based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum consultants, our total proved reserves at December 31, 20142017 were 120.074.2 million barrels of oil equivalent (“MMBoe”) or 720.0445.3 billion cubic feet of gas equivalent (“Bcfe”). compared to 74.0 MMBoe as of December 31, 2016. Approximately 57%74% of our proved reserves as of December 31, 2017 were classified as proved developed producing, 12%10% as proved developed non-producing and 31%16% as proved undeveloped. Classified by product, our proved reserves at December 31, 20142017 were 52%46% crude oil, 13% natural gas liquids (“NGLs”)11% NGLs and 35%43% natural gas. These percentages were determined using the energy-equivalent ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs. This energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly. Our total proved reserves had an estimated present value of future net revenues discounted at 10% (“PV-10”) of $2.6 billion.$992.9 million before consideration of cash outflows related to asset retirement obligations (“ARO”). Our PV-10 after considering future cash outflows related to asset retirement obligations (“ARO”) and without deducting future income taxesARO was $2.3 billion,$800.7 million, and our standardized measure of discounted future cash flows was $1.7 billion$740.6 million as of December 31, 2014.2017. Neither PV-10 nor PV-10 after ARO is a financial measure defined under generally accepted accounting principles (“GAAP”). For additional information about our proved reserves and a reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows, see Properties – Proved ReserveReserves under Part I, Item 2 in this Form 10-K.
Under current commodity pricing conditions, we expect to continue to focus on conserving capital and maintaining liquidity. We seekexpect our 2018 production to increasebe lower compared to 2017 before considering any potential acquisition opportunities. Factors such as drilling results, time required to bring successful wells to completion, natural production declines, unplanned downtime and well performance could lead to results different from our reserves through acquisitions, exploratoryproduction expectations for 2018. Our capital expenditure budget for 2018 of approximately $130 million is composed of select lower-risk, high-return, oil-focused projects combined with higher-risk, higher return, oil-focused projects that, assuming success, would be placed on production fairly quickly.
To provide additional financial flexibility, as we have previously reported, throughout 2017 and infillnow into 2018 we have been working to establish a drilling recompletionsjoint venture with private investors. We are in final stages of establishing a drilling joint venture to be formed with private investors that will allow us to drill and workovers.exploit assets on a promoted basis and with reduced capital outlay. We have focusedcompleted negotiations with an initial group of investors, the terms of which are subject to funding at an initial closing expected to occur by mid-March. It is expected that entities owned and controlled by Tracy W. Krohn, Chairman and Chief Executive Officer of the Company, and his family will invest on acquiring properties where we can developthe same terms as are negotiated with the unaffiliated investors to acquire an inventory of drilling prospects that will enable us to add reserves, production and cash flow post-acquisition. Our acquisition team strives to find properties that will fit our profile and that we believe will add strategic and financial value to our company.
In September 2014, we acquired additional ownershipapproximate 4% interest in the Mobile Bay blocks 113 and 132 located offshore Alabama (the “Fairway Field”) anddrilling joint venture. More investors may join the associated Yellowhammer gas processing plant (collectively “Fairway”), which increased our ownership interest from 64.3% to 100%. Internal estimatesjoint venture before or after the initial closing. If completed, this joint venture arrangement should reduce cash commitments for capital expenditures depending on the level of additional proved reserves associated with the increased ownership interestoutside investor participation. We believe other arrangements on a promoted basis are available in the Fairway Field as ofcurrent market environment. We believe financing arrangements exist for the right acquisition date were approximately 4.4 MMBoe (26.4 Bcfe), comprised of approximately 26% NGLs and 74% natural gas, all of which were classified as proved developed.opportunity, although these financing arrangements may be structured differently than past arrangements.
1
In May 2014, we acquired from Woodside Energy (USA) Inc. (“Woodside”) certain oil and gas leasehold interests inWe also expect to reduce or extend the Gulf of Mexico (the “Woodside Properties”). The Woodside Properties consistedmaturities 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 date were approximately 1.6 MMBoe (9.4 Bcfe), comprised of approximately 89% oil, 1% NGLs and 10% natural gas, all of which were classified as proved developed.
In November and December 2013, we acquired from Callon Petroleum Operating Company (“Callon”) certain oil and gas leasehold interests in the Gulf of Mexico (the “Callon Properties”). The Callon Properties consist of a 15% working interest in the Medusa field (deepwater Mississippi Canyon blocks 582 and 583), interest in associated production facilities and various interests in other non-operated fields. Internal estimates of proved reserves associated with the Callon Properties as of the acquisition dates were approximately 2.1 MMBoe (12.7 Bcfe), comprised of approximately 67% oil and 33% natural gas, all of which were classified as proved developed.
In October 2012, we acquired from Newfield Exploration Company and its subsidiary, Newfield Exploration Gulf Coast LLC (together, “Newfield”), certain oil and gas leasehold interests in the Gulf of Mexico (the “Newfield Properties”). The Newfield Properties consisted of leases covering 78 federal offshore blocks on approximately 416,000 gross acres (268,000 net acres) predominantly in the deepwater. Internal estimates of proved reserves associated with the Newfield Properties as of the acquisition date were approximately 7.0 MMBoe (42.0 Bcfe), comprised of approximately 36% oil, 3% NGLs and 61% natural gas, all of which were classified as proved developed.
From time to time, as partsignificant amount of our business strategy, we sell various properties. In 2014, we had no significant property sales. In 2013, we soldexisting indebtedness within the next 12 months assuming reasonably stable market conditions to provide greater financial flexibility. Our 2018 plans include spending $24 million for ARO, compared to $72 million spent on ARO in 2017. We continue to closely monitor current and forecasted commodity prices to assess what changes, if any, should be made to our non-operated working interests in the Green Canyon 60 field, the Green Canyon 19 field and the West Delta area block 29, all located in the Gulf of Mexico. In 2012, we sold our non-operated working interest in the South Timbalier 41 field located in the Gulf of Mexico.
Additional information on these acquisitions and divestitures can be found under Properties in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7, and in Financial Statements and Supplementary Data - Note 2 – Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K.2018 plans.
Our exploration efforts have historically been in areas in reasonably close proximity to known proved reserves, but starting in 2013,2012, some of our exploration projects were higher risk deepwater projects with potentially higher returns than our previous risk/reward profile. Historically, we have financed our drilling capital expenditures with operating cash flow. The investment associated with drilling an offshore well and future development of an offshore project principally depends upon water depth, the depth of the well, the complexity of the geological formations involved and whether the well or project can be connected to existing infrastructure or will require additional investment in infrastructure. Deepwater and deep shelf drilling projects can be substantially more capital intensive than those on the conventional shelfshelf. During 2017, we did not drill or participate in any deepwater projects, and onshore.in 2016, we participated in one deepwater project. Certain risks are inherent in our business specifically and in the oil and natural gas industry generally, any one of which can negatively impact our rate of return on shareholders’ equityinvested capital if it occurs. When projects are extremely capital intensive and involve substantial risk, we often seek participants to share the risk. Onshore wells are less capital intensive than offshore wells, but the amount of reserves discovered and developed on a per well basis has historically been less from onshore wells than from offshore wells. We completed six, five and four offshore wells (gross) and 33, 40 and 77 onshore wells (gross) in 2014, 2013 and 2012, respectively.
We generally sell our crude oil, NGLs and natural gas at the wellhead at current market prices or transport our production to “pooling points” where it is sold. We are required to pay gathering and transportation costs with respect to a majority of our products. Our products are marketed several different ways depending upon a number of factors including the availability of purchasers at the wellhead, the availability and cost of pipelines near the well or related production platforms, the availability of third-party processing capacity, market prices, pipeline constraints and operational flexibility.
2
Our current capital expenditure budget for 2015 is $200 million, not including any potential acquisitions. This compares to capital expenditures of $630 million and $636 million for 2014 and 2013, respectively. The capital budget for 2015 is significantly lower than recent annual expenditures primarily due to the dramatic decline in crude oil prices. The 2015 budget is being allotted as follows: 38% for exploration, 61% for development and less than 1% for other items. Geographically, the budget is split 92% for offshore and 8% for onshore, with the substantial majority of offshore dedicated to the deepwater. Through February 2015, we have not closed any acquisitions, but we continue to evaluate and bid on opportunities as they arise. We anticipate funding our 2015 capital budget and any potential acquisitions with cash flow from operating activities, cash on hand and borrowings under our revolving bank credit facility. The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises. Hence, our 2015 capital budget has been set with these premises in mind. For the portion of our capital budget related to drilling, 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
Our business strategy is to acquire, explore and develop oil and natural gas reserves on the Outer Continental Shelf (“OCS”),OCS, the area of our historical success and technical expertise, which we believe has yieldedwill yield desirable rates of return commensurate with our perception of risks. The rapid decline in 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 goodsattractive drilling 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 become available in the Gulf of Mexico as the major integrated oil companies and other large independent oil and gas exploration and production companies continue to divest properties to focus on larger and more capital-intensive projects that better match their long-term strategic goals. Because of ongoing market volatility, more specifically, the reduction in oil and natural gas prices occurring in the last six months,Also, we expect to find opportunities will arise as other less well-capitalized producers may seek to divest their properties both onshorefor short-term cash flow needs. Our plans for the short-term include operating within cash flow, maintaining liquidity, meeting our financial obligations, establishing a drilling joint venture to provide drilling capital on a promoted basis (as discussed above) and offshore.pursuing acquisitions meeting our criteria.
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 plan to continue to evaluate other areas that could be compatible with our technical expertise and could yield desirable rates of return commensurate with our perception of risks. We may acquire or expand our offshore and onshore holdings through exploration, development and acquisition activities if attractive opportunities arise.
We believe our business approach has contributed to our success and has positioned us to capitalize on new opportunities. Historically, we have limited our annual capital spending for drilling activities to operating cash flow, and we have used capacity under our revolving bank credit facility and the capital markets for acquisitions, development and to balance working capital fluctuations. The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises.
Competition
The oil and natural gas industry is highly competitive. We currently operate in the Gulf of Mexico and onshore in Texas and compete for the acquisition of oil and natural gas properties primarily on the basis of price for such properties. We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas concernscompanies and individual producers and operators. Many of these competitors are large, well established companies that have financial and other resources substantially greater than ours.ours and greater ability to provide the extensive regulatory financial assurances required for offshore properties. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties, finance investments 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, see Risk Factors under Part I, Item 1A in this Form 10-K.
3
Oil and Natural Gas Marketing and Delivery Commitments
We sell our crude oil, NGLs and natural gas to third-party customers. We are not dependent upon, or contractually limited to, any one customer or small group of customers. However, in 2014,2017, approximately 47%46% of our sales were to Shell Trading (US) Co. and 15% were to Vitol Inc., with no other customer comprisedcomprising greater than 10% of our sales. See Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies – Concentration of Credit Risk under Part II, Item 8 in this Form 10-K for additional information about our sales to customers.2017 revenues. Due to the free trading nature of the oil and natural gas markets and because oil and natural gas are freely traded commodities with numerous purchasers in the Gulf of Mexico, and Texas, we do not believe the loss of a single customer or a few customers would materially affect our ability to sell our production. We do not have any agreements which obligate us to deliver material quantities to third parties.
Exchange Transaction in 2016
In September 2016, we consummated a transaction whereby we exchanged approximately $710.2 million principal amount, or 79%, of our 8.500% Senior Notes due 2019 (the “Unsecured Senior Notes”) for $301.8 million principal amount of new secured notes and 60.4 million shares of our common stock. In conjunction with the transaction, we closed on a new $75.0 million, 11.00%, 1.5 Lien Term Loan (the “1.5 Lien Term Loan”), and two amendments were made effective under our Fifth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”) (collectively, the “Exchange Transaction”). See Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7, and in Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for a full description of the transaction, the new debt instruments and the accounting for the transaction.
Regulation
General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulationregulations as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) regulations, pursuant to the Outer Continental Shelf Lands Act (“OCSLA”), apply to our operations on federal leases in the Gulf of Mexico.
The Federal Energy Regulatory Commission (“FERC”) regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting wellhead sales of natural gas, effective January 1, 1993. While salesSales by producers of natural gas and all sales of crude oil, condensate and NGLs can currently be made at uncontrolled market prices, Congress could reenact price controls inprices. The FERC also regulates rates and service conditions for the future.interstate transportation of liquids, including crude oil, condensate and NGLs, under various statues.
In addition, theThe Federal Trade Commission (“FTC”), the FERC and the Commodity Futures Trading Commission (“CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. WithWe are required to observe the market-related regulations enforced by these agencies with regard to our physical sales of crude oil or other energy commodities, and any related hedging activities that we undertake, we are requiredundertake. Any violation of the FTC, FERC, and CFTC prohibitions on market manipulation can result in substantial civil penalties amounting to observe the market-related regulations enforced by theseover $1 million per violation per day.
These departments and agencies which holdhave substantial enforcement authority.authority and the ability to grant and suspend operations, and to levy substantial penalties for non-compliance. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.
Federal leases. Most of our offshore operations are conducted on federal oil and natural gas leases. These leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require compliance with BOEM, BSEE, and other government agency regulations and orders that are subject to interpretation and change. The BOEM and BSEE also regulate the plugging and abandonment of wells located on the OCS and, following cessation of operations, the removal or appropriate abandonment of all production facilities, structures and pipelines on the OCS (collectively, these activities are referred to as “decommissioning”).
Decommissioning and financial assurance requirements. The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS. In July 2016, the BOEM issued Notice to Lessees and Operators (“NTL”) #2016-N01 (“NTL #2016-N01”) to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, rights of way (“ROWs”) and rights of use and easement (“RUEs”). NTL #2016-N01 became effective in September 2016, but the BOEM has since extended indefinitely the start date for implementation. In December 2016, we received an Order to Provide Additional Security from the BOEM totaling approximately $29.5 million for our sole liability properties (the “December 2016 Order”). However, following the BOEM’s action in January 2017 to extend the implementation date of NTL #2016-N01 for a period of six months, the BOEM elected to include sole liability properties as being covered under the extension and thus issued us a letter on February 21, 2017 rescinding the December 2016 Order while the BOEM reviewed its financial assurance program. In June 2017, the BOEM further extended the start date for implementing NTL #2016-N01 indefinitely beyond June 30, 2017. This extension currently remains in effect; however, the BOEM reserved the right to re-issue sole liability orders in the future, including in the event that it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning sole liabilities. See Risk Factors under Part I, Item 1A, Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 and Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for more discussion on decommissioning and financial assurance requirements.
Reporting of decommissioning expenditures. During December 2015, the BSEE issued a final rule requiring lessees to submit summaries of actual expenditures for decommissioning of wells, platforms, and other facilities required under the BSEE’s existing regulations. The BSEE has reported that it will use this summary information to better estimate future decommissioning costs, and the BOEM typically relies upon the BSEE’s estimates to set the amount of required bonds or other forms of financial security in order to minimize the government’s perceived risk of potential decommissioning liability.
“Unbundling.” The Office of Natural Resources Revenue (the “ONRR”) has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases. The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant utilized during that period. Through December 31, 2017, we have paid $ 2.1 million in additional royalties as a result of this initiative.
Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, theThe FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limitedallows non-pipeline natural gas sellers, including producers, fromto effectively competingcompete with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. The rates for such storage and transportation services are subject to FERC ratemaking authority, and FERC exercises its authority either by applying cost-of-service principles or granting market based rates.
Similarly, the natural gas pipeline industry may also beis subject to state regulations, which may change from time to time. During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (“Competition Bill”) and H.B. 1920 (“LUG Bill”). The Competition Bill gives the Railroad Commission of Texas (“RRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and intrastate transportation pipelines in formal rate proceedings. It also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation, or gathering of natural gas. The LUG Bill modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested, provides producers with an annual audit right, and provides the RRC with the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. The RRC was subject to a sunset review during 2013 and was authorized to operate for an additional four years. Its next scheduled sunset review is in 2017.
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The Outer Continental Shelf Lands Act (“OCSLA”),OCSLA, which is administered by the Bureau of Ocean Energy Management (“BOEM”)BOEM and the FERC, requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. One of the FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the OCS market, to provide producers and shippers working in the OCS with greater assurance of open access service on pipelines located on the OCS, and to provide non-discriminatory rates and conditions of service on such pipelines. On June 18, 2008, theThe BOEM issued a final rule, effective August 18, 2008 that implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines on the OCS.
In December 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as us, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million British thermal units (“MMBtu”) during a calendar year must annually report starting May 1, 2009, such sales and purchases to the FERC.FERC to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state legislatures, state commissions and the courts. The natural gas industry historically has been very heavily regulated. As a result, there is no assurance that the less stringent regulatory approach recently pursued by the FERC, Congress and Congressthe states will continue.
While the changes by these federal and state regulatorsregulations for the most part affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC, the BOEM or state regulators will take on these matters; however, we do not believe that any such action taken will affect us differently, in any material way, than other natural gas producers with which we compete.
Oil and NGLs transportation rates. Our sales of liquids, which include crude oil, condensate and NGLs are not currently regulated and are transacted at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act.jurisdiction. The price we receive from the sale of crude oil and NGLs is affected by the cost of transporting those products to market. Interstate transportation rates for crude oil, condensate, NGLs and other products are regulated by the FERC. In general, interstate crude oil, condensate and NGL pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. The FERC has established an indexing system for such transportation, which generally allows such pipelines to take an annual inflation-based rate increase.
In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.statutes and regulations. As it relates to intrastate crude oil, condensate and natural gas liquidsNGL pipelines, state regulation is generally less rigorous than the federal regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests, which are infrequent and are usually resolved informally.
We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate or natural gas liquidsNGL pipelines will affect us in a way that materially differs from the way they affect other crude oil, condensate and natural gas liquidsNGL producers or marketers.
Regulation of oil and natural gas exploration and production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the location of wells, the method of drilling, casing, operating, plugging and abandoning wells, and governing the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation of oil and gas resources, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing of such wells.
Federal leases. Most of our offshore operations are conducted on federal oil and natural gas leases, which are administered by the BOEM pursuant to the OCSLA. These leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require compliance with detailed BOEM, Bureau of Safety and Environmental Enforcement (“BSEE”), and other government agency regulations and orders that are subject to interpretation and change. The BOEM and BSEE have promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities, structures and pipelines. See Risk Factors under Part I, Item 1A in this Form 10-K for more information on new regulations and interpretations.
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To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees demonstrate financial strength and reliability according to regulations or post bonds or other acceptable assurances that such obligations will be satisfied. The significant reductions in oil and natural gas pricing since the middle of 2014 may also adversely impact the BOEM’s financial assurance determinations with respect to the Company. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. In August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements for companies operating in federal waters. If the BOEM were to increase its financial assurance requirements substantially, such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations. In addition, the BOEM can require supplemental bonding from operators for decommissioning, plugging, and abandonment liabilities. According to federal regulations, the BOEM will waive its supplemental bonding requirements when a lessee or its guarantor can demonstrate the financial capability and reliability to meet these obligations. We have demonstrated our financial capability and reliability to the satisfaction of the BOEM and the agency does not require that the Parent Company post any supplemental bonds to cover our operations on the OCS.
In December 2013 and January 2014, we were notified by the Office of Natural Resources Revenue (“ONRR”) of an underpayment of royalties on certain Federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment. In March 2014, we received notice from the ONRR of a statutory fine of $2.3 million relative to such underpayment. We believe the fine is excessive and extreme considering the circumstances and in relation to the amount of underpayment. On April 23, 2014, we filed a request for a hearing on the record and a general denial of the ONRR’s allegations contained in the notice. We intend to contest the fine to the fullest extent possible. The ultimate resolution may result in a waiver of the fine, a reduction of the fine, or payment of the full amount plus interest covering several years. As no amount has been determined as more likely than any other within the range of possible resolutions, no amount has been accrued as of December 31, 2014 per authoritative guidance. However, we cannot state with certainty that our estimate of the exposure is accurate concerning this matter.
Hurricanes in the Gulf of Mexico can have a significant impact on oil and gas operations on the OCS. The effects from past hurricanes have included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs. The BOEM and the BSEE continue to be concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the potential for future damage, the BOEM and the BSEE have periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not more stringent, requirements will be issued by the BOEM and/or the BSEE for future hurricane seasons. New requirements, if any, could increase our operating costs and/or capital expenditures.
Environmental Regulations
General. We are subject to complex and stringent federal, state and local environmental laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and producing operations, the amounts and types of materials that may be released into the environment, the discharge and disposal of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with, and which carrya failure to comply may result in substantial administrative, civil and even criminal penalties for failure to comply.or the suspension or cessation of operations in affected areas. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent and address pollution, such as the closure of inactive oil and gas waste pits and the plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. The cost of remediation, reclamation and decommissioning, including abandonment of wells, platforms and other facilities in the Gulf of Mexico may require us to incur significant costs.is significant. These costs are considered a normal, recurring cost of our on-going operations. Our domestic competitors are generally subject to the same laws and regulations.
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Hazardous Substances and Wastes. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, such persons are subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies. In addition, companies that incur liability frequently also confront third-party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.
The Federalfederal 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 non-hazardous and hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and certain other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste.waste,” Disposaland the disposal of such non-hazardous oil and natural gas exploration, development and production wastes is regulated under less onerous non-hazardous waste requirements, usually regulated byunder state law. Other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, however, various environmental groups have challenged the Environmental Protection Agency’s (“EPA”) exemption of certain oil and gas wastes from RCRA. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA must propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. In addition, legislation ishas been proposed from time to time in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes,wastes.” therebyA loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could potentially subjectingsubject such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impactOther wastes handled at exploration and production sites or generated in the course of providing well services may not fall within the RCRA exclusion. Moreover, stricter standards for waste handling, disposal and cleanup may be imposed on our operating costs as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.the future. Additionally, Naturally Occurring Radioactive Materials (“NORM”) may contaminate minerals extraction and processing equipment used in the oil and natural gas industry. The waste resulting from such contamination is regulated by federal and state laws. Standards have been developed for: worker protection; treatment, storage, and disposal of NORM and NORM waste; management of NORM-contaminated waste piles, containers and tanks; and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. We do not anticipate any material expenditures in connection with our compliance with existing RCRA and applicable state laws related to NORM waste.
Air Emissions and Climate Change. Air emissions from our operations are subject to the Federalfederal Clean Air Act (“CAA”) and comparable state and local requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For example, the U.S. Environmental Protection Agency (“EPA”) has established air emission controls requirements for oil and natural gas production and natural gas processing operations. Specifically,in October 2015, the EPA established New Source Performance Standardsissued a final rule under the Clean Air Act lowering the National Ambient Air Quality Standard for emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards for hazardous air pollutants frequently associated with oil and natural gas production and processing activities.ground level ozone from 75 to 70 parts per billion. The EPA rules require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions”published a final rule in November 2017 establishing attainment area designations for hydraulic fracturing, which requires the operator to recover rather than vent any hydrocarbons that come to the surface during completioncertain areas of the fracturing process. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanksUS and other production equipment.is expected to issue nonattainment designations for additional areas of the US in the first half of 2018, which areas may include regions where we conduct operations. In addition, the rules establish new leak detection requirements for natural gas processing plants. These rules may require a numberEPA has developed, and continues to develop, stringent regulations governing emissions of modifications to our operations includingtoxic air pollutants at specified sources. Moreover, the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our operating results. However, we believe our operations will not be materially adversely affected by any such requirements,U.S. Congress and the requirements are not expectedEPA, in addition to be any more burdensomesome state and regional efforts, have in recent years considered legislation or regulations to us than to other similarly situated companies involved in oilreduce emissions of greenhouse gases (“GHG”). These efforts have included consideration of cap-and-trade programs, carbon taxes, and natural gas explorationGHG monitoring and production activities.reporting programs.
Climate Change. TheIn the absence of federal GHG limitations, the EPA has determined that GHG emissions of carbon dioxide, methane and other “greenhouse gases” present an endangermenta danger to public health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and it has adopted regulations that, among other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations tothings, restrict emissions of greenhouse gasesGHG under existing provisions of the CAA. The EPA has adopted two setsCAA and may require the installation of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction incontrol technologies to limit emissions of greenhouse gases from motor vehicles andGHG. For example, in June 2016, the other of which requires preconstruction and operating permits for certain large stationary sources. The EPA also requires the reporting of greenhouse gas emissions from specified large greenhouse gas emission sourcespublished a final rule establishing new source performance standards that require new, modified, or reconstructed facilities in the United States, including certain onshore oil and natural gas production facilities, on an annual basis. We believe we are in compliance with this new emission reporting requirement as it applies to our operations.
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In addition, the United States Congress has from time to time considered adopting legislationsector to reduce emissionsmethane gas and volatile organic compound emissions. The 2016 rule would apply to any new or significantly modified facilities that we construct in the future that would otherwise emit large volumes of greenhouse gases, and almost one-halfGHG together with other criteria pollutants. However, in June 2017, the EPA published a proposed rule to stay certain portions of the states have already taken legal measures2016 rule for two years and reconsider the entirety of the 2016 rule but the agency has not yet published a final rule and, as a result, the 2016 rule is currently in effect but future implementation of the 2016 rule is uncertain at this time. Also, certain of our operations are subject to reduceEPA rules requiring the monitoring and annual reporting of GHG emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.from specified offshore production sources.
Water Discharges. The primary federal law for oil spill liability is the Oil Pollution Act (the “OPA”) which amends and augments oil spill provisions of the federal Water Pollution Control Act (the “Clean Water Act”). OPA imposes certain duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters, including the OCS or adjoining shorelines. A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several, strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil and natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. In addition, in December 2014,January 2018, the BOEM issued a final rule, effective January 12, 2015, which raisesraised OPA’s damages liability cap from $75 million to $133.65$137.7 million. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill, and to prepare and submit for approval oil spill response plans. These oil spill response plans must detail the action to be taken in the event of a spill; identify contracted spill response equipment, materials, and trained personnel; and identify the time necessary to deploy these resources in the event of a spill. In addition, OPA currently requires a minimum financial responsibility demonstration of between $35 million and $150 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to a maximum of $150 million.OCS. We are currently required to demonstrate, on an annual basis, that we have ready access to $150 million that can be used to respond to an oil spill from our facilities on the OCS. As a result of the BP Deepwater Horizon incident, legislation has been proposed in Congress to increase the minimum level of financial responsibility to $300 million or more. If OPA is amended to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.
The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the monitoring and discharge of pollutants, including produced waters and other natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The EPA has also adopted regulations requiring certain onshore oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with theThe treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our onshore facilities.gas processing plant may have significant costs. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. We currently maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.
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Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand or other proppants and chemicals under pressure into the formation to fracture the rock formation and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (the “SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance covering such activities in February 2014. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. We follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities including disclosure requirements. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells that require hydraulic fracturing.
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA is performing a study of the potential environmental effects of hydraulic fracturing on drinking water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal. The EPA has indicated that it expects to issue its study report in 2015. The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards in 2015. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.
Protected and Endangered Species. Executive Order 13158, issued in May 2000, directs federal agencies to safeguard existing Marine Protected Areas (“MPAs”) in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future development and exploration projects and/or causing us to incur increased operating expenses.
In addition, Federal Lease Stipulations include regulations regarding the taking of protected marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species). The BSEE also issues numerous regulations under the nomenclature Notice to Lessees (“NTL”) that provide formal guidelines on implementation of OCS regulations and standards. We believe we are in compliance in all material respects with the requirements regarding protection of marine species.
Certain flora and fauna that have been officially classified as “threatened” or “endangered” are protected by the Endangered Species Act.Act (“ESA”). This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area. IfWe conduct operations on leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species are located in an area where we wish to conduct seismic surveys, development or abandonment operations, the workthat potentially could be prohibitedlisted as threatened or delayed or expensive mitigation could be required.
endangered under the ESA may exist. We own a non-producing platform in the Gulf of Mexico located in a National Marine Sanctuary. As a result, we are subject to additional federal regulation, including regulations issued by the National Oceanic and Atmospheric Administration. Unique regulations related to operations in a sanctuary include prohibition of drilling activities within certain protected areas, restrictions on the types of water and other substances that may be discharged, required depths of discharge in connection with drilling and production activities and limitations on mooring of vessels. FailureDuring 2017, we reached an agreement with the various governmental agencies to comply with these laws and regulations may resultremove the topside structure on our non-producing platform located in the assessmentNational Marine Sanctuary and leave the bottom of administrative, civilthe platform structure below the water line in place. This bottom portion of the platform structure will remain due to the density and criminal penalties, incurrencediversity of investigatory or remedial obligations ormarine growth attached to and around the imposition of injunctive relief.structure.
Other federal statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the National Environmental Policy Act, the Coastal Zone Management Act, the Emergency Planning and Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Magnuson-Stevens Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands. These and other protected areas may require certain mitigation measures to avoid harm to wildlife, and such laws and regulations may impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities.
9Financial Information
We maintain liability insurance and well control insurance for all ofoperate our operations. In addition, we maintain property and hurricane damage insurance coverage for some, but not all, of our properties, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain does not cover the risks described above from gradual pollution events which occur overbusiness as a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover such risks or that such insurance will be available at a cost that would justify its purchase. The occurrence of a significant environmental event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.single segment. See Management’s Discussion and Analysis ofSelected Financial Condition and Results of Operations – Liquidity and Capital Resources – Hurricane Remediation, Insurance Claims and Insurance CoverageData under Part II, Item 76 and Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for additional information on insurance coverage.our financial information.
Seasonality
ForGenerally, 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 discussionportion of seasonaltheir anticipated winter requirements of natural gas. As utilities continue to switch from coal to natural gas, some of this seasonality has been reduced as natural gas is used for both heating and cooling. In addition, the demand for oil is higher in the winter months, but does not fluctuate seasonally as much as natural gas. Seasonal weather changes that affect our business, see Management’s Discussionoperations. Tropical storms and Analysishurricanes occur in the Gulf of Financial ConditionMexico during the summer and Resultsfall, which require us to evacuate personnel and shut in production until the storm subsides. Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which delays the installation of Operations – Inflationproduction facilities, thereby delaying production and Seasonality under Part II, Item 7 in this Form 10-K.sales of our oil and natural gas.
Employees
As of December 31, 2014,2017, we employed 339298 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.
We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, other reports and otheramendments to those reports with the SEC. Our reports filed with the SEC are available free of charge to the general public through our website at www.wtoffshore.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Investor Relations, W&T Offshore, Inc., Nine Greenway Plaza, Suite 300, Houston, Texas 77046 or by calling (713) 297-8024. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. Information on our website is not a part of this Form 10-K.
In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to us and our industry could materially impact our future performance and results of operations. We have provided below a list of known material risk factors that should be reviewed when considering buying or selling our securities. These are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.
Risks Relating to the Oil and Natural GasOur Industry, Our Business and Our BusinessFinancial Condition
Substantial or extended declines inCrude oil, NGLs and natural gas and NGL prices maycan fluctuate widely due to a number of factors that are beyond our control. Depressed oil, natural gas or NGL prices could adversely affect our business, financial condition, cash flow, liquidity or results of operations and could affect our ability to fund future capital expenditures needed to find and replace reserves, meet our capital expenditure obligations and financial commitments and to implement our business strategy.
The price we receive for our crude oil, NGLs and natural gas production directly affects our revenues, profitability, access to capital and future rate of growth. Oil,Crude oil, NGLs and natural gas are commodities and arehistorically have been subject to wide price fluctuations, sometimes in response to relatively minor changes in supply and demand. Lower pricesThese markets 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 forcrude oil, NGLs and natural gas have been volatile and will likely continue to be volatile in the future. Although prices increased during 2017 from 2016 and 2015 levels, these past three years of lower prices have substantially decreased our revenues on a per unit basis and reduced the amount of crude oil, NGLs and natural gas that we could produce economically. The prices we receive for our production and the volume of our production depend on numerous factors beyond our control. These factors include the following:
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changes in global supply and demand for crude oil, NGLs and natural gas;
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the actions of the Organization of Petroleum Exporting Countries (“OPEC”);
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the price and quantity of imports of foreign crude oil, NGLs, natural gas and liquefied natural gas;
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acts of war, terrorism or political instability in oil producing countries;
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national and global economic conditions;
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domestic and foreign governmental regulations;
political conditions and events, including embargoes, affecting oil-producing activities;
the level of domestic oil and natural gas exploration and production activities;
the level of global oil and natural gas exploration and production activities;
the level of global crude oil, NGLs and natural gas inventories;
weather conditions;
technological advances affecting energy consumption;
the price, availability and acceptance of alternative fuels; and
geographic differences in pricing.
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The prices of crude oil domestic natural gas and NGLs have declined substantially since June 2014.began declining in the second half of 2014 and continued declining until reaching a bottom in the first quarter of 2016, and then slowly rising in 2017. The average price per barrel of West Texas Intermediate (“WTI”) crude oil has decreased from $107was over $90.00 in 2014, approximately $49.00 in 2015, approximately $43.00 per barrel in the middle of June 2014 to as low as $442016 and approximately $50.00 per barrel in January 2015.2017. During 2014, the average Henry Hub spot price for natural gas was above $4.00 per MMBtu compared to approximately $2.60 per MMBtu during 2015, approximately $2.50 per MMBtu in 2016 and approximately $3.00 per MMBtu in 2017. This decrease and volatility in prices has impacted all companies throughout the oil and gas producers to varying degrees depending on hedging strategies. Natural gas and NGLsindustry. Although oil prices have been negatively affected by excess natural gas production, high levelsincreased from the lows of stored natural gas and weather conditions affecting demand. In recent months, Henry Hub spotthe first quarter of 2016, margins are still below historical levels. Low 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 and NGLs. An environment of further or continued lowercrude oil, NGLs and natural gas prices wouldcould materially and adversely affect our future business, financial condition, results of operations, liquidity, and/or ability to finance planned capital expenditures.expenditures, ability to fund our ARO, ability to repay any borrowings per our debt agreements, to secure supplemental bonding, to secure collateral for such bonding, if required, and to meet our other financial obligations.
IfThe borrowing base under our Credit Agreement may be reduced or may not be extended by our lenders.
Availability of borrowings and letters of credit under the Credit Agreement is determined by establishment of a borrowing base, which is periodically redetermined during the year based on our lenders’ view of crude oil, NGLs and natural gas prices stayand on our proved reserves. During 2017, there were no changes in the borrowing base under the Credit Agreement from year-end 2016, but during 2016, the borrowing base was reduced from $350 million to $150 million. The borrowing base was lowered primarily due to declines in commodity prices and a decrease in proved reserves. The borrowing base could be further reduced in the future as a result of the continued impact of low commodity prices, our lenders’ outlook for future prices or our inability to replace reserves as a result of constrained capital spending. To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base, such excess or deficiency is required to be repaid within 90 days in three equal monthly payments. In addition to the borrowing base limitation, the Credit Agreement limits our ability to incur additional indebtedness if we cannot comply with specified financial covenants and ratios.
We may not have the financial resources in the future to repay an excess or deficiency resulting from a borrowing base redetermination as required under our Credit Agreement, which could result in an event of default. Additionally, a material reduction of our current cash position could substantially limit our ability to comply with other cash needs, such as collateral needs for existing or additional supplemental surety bonds or other financial assurances issued to the BOEM for our decommissioning obligations. Further, the failure to repay an excess or deficiency that may result from a borrowing base redetermination under our Credit Agreement may result in a cross-default under our other debt agreements. If crude oil, NGLs and natural gas prices fall back to the levels experienced in 2016, this would adversely affect our cash flow, which could result in further reductions in our borrowing base, adversely affect prospects for alternative credit availability or affect our ability to satisfy our covenants and ratios under our Credit Agreement.
The Credit Agreement matures on November 8, 2018 and our lenders have indicated that they are unwilling to extend the Credit Agreement given the current maturities of our other debt instruments, including the potential maturity acceleration of two of our debt instruments to February 28, 2019. We may not be able to execute our plans to address this issue, which would cause us to operate without a revolving bank credit facility.
We may be unable to provide the financial assurances if the BOEM submits future demands to cover our decommissioning obligations in the amounts and under the time periods required by the BOEM. If extensions and modifications to the BOEM’s demands are needed and cannot be obtained, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases.
The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS. In July 2016, the BOEM issued the NTL #2016-N01 to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs or RUEs. NTL #2016-N01 became effective in September 2016, but the BOEM has since extended indefinitely the start date for implementation.
In December 2016, we received the December 2016 Order totaling approximately $29.5 million for our sole liability properties. However, following the BOEM’s action in January 2017 to extend the implementation date of NTL #2016-N01 for a period of six months, the BOEM elected to include sole liability properties as being covered under the extension and thus issued us a letter on February 21, 2017, rescinding the December 2016 Order, while the BOEM reviewed its financial assurance program. In June 2017, the BOEM further extended the start date for the implementation of NTL #2016-N01 indefinitely beyond June 30, 2017. This extension currently remains in effect; however, the BOEM reserved the right to re-issue sole liability orders in the future, including in the event that it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning sole liabilities.
As of the filing date of this Form 10-K, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders or financial assurance obligations. Following completion of its review, the BOEM may elect to retain NTL #2016-N01 in its current form or may make revisions thereto and, thus, until the review is completed and the BOEM determines what additional financial assurance may be required by us, we cannot provide assurance that such financial assurance coverage can be obtained. Moreover, the BOEM could in the future make other demands for additional financial assurances covering our obligations under sole liability properties and/or our non-sole liability properties. The BOEM may reject our proposals and make demands that exceed the Company’s capabilities.
If we fail to comply with the current or future orders of the BOEM to provide additional surety bonds or other financial assurances, the BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.
We may be required to post cash collateral pursuant to our agreements with sureties under our existing bonding arrangements, which could have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan, our ARO plan and comply with our existing debt instruments.
Pursuant to the terms of our agreements with various sureties under our existing bonding arrangements or under any additional bonding arrangements we may enter into, we may be required to post collateral at any time, on demand, at the surety’s discretion. We have received such demands and have provided collateral to a couple of our existing sureties. If additional collateral is required to support surety bond obligations, this collateral would probably be in the form of cash or letters of credit. Given current commodity prices’ effect on our creditworthiness and the willingness of the surety to post bonds without the requisite collateral, we cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for additional bonds.
If we are required to provide collateral, our liquidity position will be negatively impacted and may require us to seek alternative financing. To the extent we are unable to secure adequate financing; we may be forced to reduce our capital expenditures in the current year and/or future years. In addition, a reduction in our liquidity may impair our ability to comply with the financial and other restrictive covenants in our indebtedness. Moreover, if we default on our Credit Agreement, then we would need a waiver or amendment from our bank lenders to prevent the acceleration of the outstanding debt under our Credit Agreement. There is no assurance that the bank lenders will waive or amend the Credit Agreement. Realization of any of these factors could have a material adverse effect on our financial condition, results of operations and cash flows. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 in this Form 10-K for additional information.
We have a significant amount of indebtedness. Our leverage and debt service obligations may have a material adverse effect on our financial condition, results of operations and business prospects, and we may have difficulty paying our debts as they become due.
As of December 31, 2017, we had $889.8 million principal amount of indebtedness outstanding, which consists of $189.8 million principal amount of unsecured indebtedness and $700.0 million principal amount of secured indebtedness. Our current availability on our revolving bank credit facility is the full borrowing base of $150.0 million. We did not incur any borrowings on our revolving bank credit facility during 2017. For example, our leverage could:
limit our ability to fund future working capital requirements, capital expenditures and ARO, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets;
limit our opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt obligations or to comply with any restrictive terms of our debt obligations;
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
impair our ability to obtain additional financing in the future; and
place us at a competitive disadvantage compared to our competitors that have less debt.
Any of the above listed factors could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Our ability to pay our expenses and fund our working capital needs and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as commodity prices, other economic conditions and governmental regulation. Substantially all of our oil, NGLs and natural gas properties are pledged as collateral under our Credit Agreement and also pledged as collateral on a subordinate basis under certain other debt agreements. Sustained or lower crude oil, NGLs and natural gas prices in the future will continue to adversely affect our cash flow and could result in further reductions in our borrowing base, reduce prospects for alternate credit availability, and affect our ability to satisfy the covenants and ratios under our Credit Agreement. Further asset sales may also reduce available collateral and availability under our Credit Agreement. In addition, we cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations.
If we are unable to service our indebtedness and other obligations, we may be required to further restructure or refinance all or part of our existing debt, sell assets, reduce capital expenditures, borrow more money or raise equity. We may not be able to further restructure or refinance our debt, reduce capital expenditures, sell assets, borrow more money or raise equity on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness. In addition, our ability to comply with the financial and other restrictive covenants in our debt instruments is uncertain and will be affected by our future performance and events or circumstances beyond our control. Failure to comply with these covenants would result in an event of default under such indebtedness, the potential acceleration of our obligation to repay outstanding debt and the potential foreclosure on the collateral securing such debt, and could cause a cross-default under our other outstanding indebtedness. Any of the above risks could have a material adverse effect on our business, financial condition, cash flows and results of operations and could lead to a restructuring.
We may be able to incur substantially more debt. This could exacerbate the risks associated with our indebtedness.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to the terms of our debt agreements. As of December 31, 2017, we had $700.0 million principal amount of secured indebtedness outstanding and $189.8 million principal amount of unsecured indebtedness outstanding (which does not include amounts recorded in the carrying value of certain debt instruments for future payment-in-kind (“PIK”) and cash interest payments). The components of our indebtedness are:
$75.0 million in aggregate principal amount of 1.5 Lien Term Loan;
$300.0 million in aggregate principal amount of the 9.00% Term Loan, due May 2020 (the “Second Lien Term Loan”);
$171.8 million of Second Lien PIK Toggle Notes;
$153.2 million of Third Lien PIK Toggle Notes; and
$189.8 million in aggregate principal amount of the Unsecured Senior Notes.
If new debt is added to our current debt levels, the related risks that we face could intensify. As of December 31, 2017, the various debt agreements allowed for approximately $200 million of second lien debt and approximately $400 million of third lien debt. Our level of indebtedness may prevent us from engaging in certain transactions that might otherwise be beneficial to us by limiting our ability to obtain additional financing, limiting our flexibility in operating our business or otherwise. In addition, we could be at a competitive disadvantage against other less leveraged competitors that have more cash flow to devote to their current levelsbusiness.
Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions.
The indentures and credit agreements governing our indebtedness contain a number of significant restrictive covenants in addition to covenants restricting the incurrence of additional debt. These covenants limit our ability and the ability of our restricted subsidiaries, among other things, to:
make loans and investments;
incur additional indebtedness or decrease further,issue preferred stock;
create certain liens;
sell assets;
enter into agreements that restrict dividends or other payments from our subsidiaries to us;
consolidate, merge or transfer all or substantially all of the assets of our company;
engage in transactions with our affiliates;
maintain certain cash balances;
pay dividends or make other distributions on capital stock or subordinated indebtedness; and
create unrestricted subsidiaries.
Our revolving bank credit facility requires us, among other things, to maintain certain financial ratios and satisfy certain financial condition tests or reduce our debt. These restrictions may also limit our ability to obtain future financings, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us from the restrictive covenants under our indentures governing our other debt instruments.
A breach of any covenant in the agreements governing our debt would result in a default under such agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the debt outstanding under such agreement and in a default with respect to, and acceleration of, the debt outstanding under any other debt agreements. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance such accelerated debt. Even if new financing were then available, it may not be on terms that are acceptable to us.
A significant amount of our indebtedness will accelerate if we are not able to extend, renew, refund, defease, discharge, replace or refinance our Unsecured Senior Notes by certain dates under various debt agreements, which would adversely impact our liquidity.
The maturity of the Third Lien PIK Toggle Notes and the 1.5 Lien Term Loan will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes are not extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. The Unsecured Senior Notes mature on June 15, 2019 with a principal balance of $189.8 million. Assuming the PIK option is fully utilized for the Third Lien PIK Toggle Notes, the principal balance would be approximately $164.5 million as of February 28, 2019. For the 1.5 Lien Term Loan, no PIK option is available and the principal of $75.0 million would be unchanged as of February 28, 2019. Thus, a total of $239.5 million may become due on February 28, 2019.
In addition, the lenders under our Credit Agreement, which matures on November 8, 2018, have indicated that they are unwilling to extend the Credit Agreement, and other lenders may be unwilling to extend a replacement revolving credit facility, unless and until the potential maturity acceleration of our Third Lien PIK Toggle Notes and the 1.5 Lien Term Loan to February 28, 2019 is addressed. Each of our Second Lien Term Loan and Second Lien PIK Toggle Notes require us to offer to repay or repurchase the Second Lien Term Loan and Second Lien PIK Toggle Notes, as applicable, at par plus accrued and unpaid interest if, by May 16, 2019, the aggregate outstanding principal amount of Unsecured Senior Notes that have not been repurchased, redeemed, discharged, defeased or called for redemption exceeds $50.0 million.
We may not be able to execute on various financing alternatives under consideration to address these maturity issues, which include having sufficient available cash or net proceeds from replacement financings to redeem the Unsecured Senior Notes, which are currently callable at par, and the 1.5 Lien Term Loan, which is callable after September 7, 2018 at 102.75% of par. In addition, certain amendments under the 1.5 Lien Term Loan and the Credit Agreement will likely be required in the event replacement financing is not utilized. We may not have available funds to make these payments, which may cause us to be in default if we are unable to refinance the Unsecured Senior Notes before February 28, 2019. A default, if not waived, could result in acceleration of the debt outstanding under such agreement and in a default with respect to, and acceleration of, the debt outstanding under any other debt agreements. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance such accelerated debt. Even if new financing were then available, it may be on less favorable terms or on terms that are not acceptable to us. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 in this Form 10-K for additional information.
We may be unable to access the equity or debt capital markets to meet our obligations.
Sustained or lower crude oil, NGLs and natural gas prices will adversely affect our cash flow and may lead to further reductions in the borrowing base, which could also lead to reduced prospects for alternate credit availability. The capital markets we have historically accessed as an alternative source of equity and debt capital are currently very constrained. Other capital sources may arise with significantly different terms and conditions. These limitations in the capital markets may affect our ability to grow and limit our ability to replace our reserves of oil and gas.
Our plans for growth may include accessing the equity and debt capital markets. If those markets are unavailable, or if we are unable to access alternative means of financing on acceptable terms, we may be unable to implement all of our drilling and development plans, make acquisitions or otherwise carry out our business strategy, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
If we default on our secured debt, the value of the collateral securing our secured debt may not be sufficient to ensure repayment of all of such debt.
As of December 31, 2017, we had $700.0 million principal amount of secured indebtedness outstanding, (which does not include amounts recorded in the carrying value of certain debt instruments for PIK and cash interest payments). If in the future we default on one or more issues or tranches of our secured debt, we cannot assure you that the proceeds from the sale of the collateral will be sufficient to repay all of our secured debt in full. In addition, we have certain rights to issue or incur additional secured debt, including up to $149.7 million as of December 31, 2017, available for borrowing on our revolving bank credit facility, that would be secured by additional liens on the collateral and an issuance or incurrence of such additional secured debt would dilute the value of the collateral securing our outstanding secured debt. If the proceeds of any sale of the collateral are not sufficient to repay all amounts due in respect of our secured debt, then claims against our remaining assets to repay any amounts still outstanding under our secured obligations would be unsecured and our ability to pay our other unsecured obligations and any distributions in respect of our capital stock would be significantly impaired.
The collateral securing the various issues of our secured debt has not been appraised. The value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the collateral. The value of the assets pledged as collateral for our secured debt could be impaired in the future as a result of changing economic conditions, commodity prices, competition or other future trends. Likewise, we cannot assure you that the pledged assets will be saleable or, if saleable, that there will not be substantial delays in their liquidation.
In addition, to the extent that third parties hold prior liens, such third parties may have rights and remedies with respect to the property subject to such liens that, if exercised, could adversely affect the value of the collateral securing our secured debt.
With respect to some of the collateral securing our secured debt, any collateral trustee’s security interest and ability to foreclose on the collateral will also be limited by the need to meet certain requirements, such as obtaining third party consents, paying court fees that may be based on the principal amount of the parity lien obligations and making additional filings. If we are unable to obtain these consents, pay such fees or make these filings, the security interests may be invalid and the applicable holders and lenders will not be entitled to the collateral or any recovery with respect thereto. We cannot assure you that any such required consents, fee payments or filings can be obtained on a timely basis or at all. These requirements may limit the number of potential bidders for certain collateral in any foreclosure and may delay any sale, either of which events may have an adverse effect on the sale price of the collateral. Therefore, the practical aspect of realizing value from the collateral may, without the appropriate consents, fees and filings, be limited.
If crude oil, NGLs and natural gas prices decrease from their current levels, we may be required to further write down the carrying values and/or the estimates of total reserves of our oil and natural gas properties.
Accounting rules applicable to us require that we periodically review the carrying value of our oil and natural gas properties quarterly for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we will likely be required to write down the carrying value of our oil and natural gas properties. Such write-downs constitute a non-cash charge to earnings. Impairment of proved properties under our full cost oil and gas accounting method is largely driven by the present valuesvalue of future net revenues of proved reserves estimated using SEC mandated 12-month unweighted first-day-of-the-month commodity prices. Since oil, gasIn addition to commodity prices, impairment assessments of proved properties include the evaluation of development plans, production data, economics 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 recent pricing downturns will continue to adversely affect our SEC average pricing as recent and current prices roll into the SEC average prices used in evaluating impairment of our proved reserves under the full cost accounting “ceiling test”. While we have not had any ceiling test impairments since 2009, sustained current prices or further declines in prices forother factors. As crude oil, NGLs and natural gas will likely resultprices declined in 2015, we incurred impairment charges in each quarter in 2015 totaling $987.2 million for the year. Such write-downs constitute a non-cash charge to earnings. As prices fell further during 2016, we incurred impairment charges in the first three quarters of 2016 which totaled $279.1 million. We did not incur any such write-downs during 2017. If prices fall below 2016 levels, this may cause write-downs during 2018 or in future ceiling test impairments. You should not assume that the $2.6 billion present value of future net revenues, PV-10, from our provedperiods. In addition, lower crude oil, NGLs and natural gas reserves shown elsewhere in this document isprices may reduce our estimates of the current marketreserve volumes that may be economically recovered, which would reduce the total value of our estimated oil and natural gasproved reserves. (PV-10 is not a financial measure defined under GAAP. For additional information about our proved reserves and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, see Properties – Proved Reserve under Part I, Item 2 in this Form 10-K.) In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month unweighted first-day-of-the-month average price for each product and costs in effect on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, the average price used in the standardized measure of discounted cash flows for December 31, 2014 for crude oil was $91.12 per barrel and the average price of WTI crude oil in December 2014 was $59.29 per barrel.
No assurance can be given that we will not experience additional ceiling test impairments in future periods, which could have a material adverse effect on our results of operations in the periods taken. As a result of lower oil, NGLs and natural gas prices, we may also reduceAlso, no assurance can be given that commodity price decreases will not affect our estimates of the reserve volumes that may be economically recovered, which would reduce the total value of our proved reserves.volumes. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview and Critical Accounting Policies – Impairment of oil and natural gas properties under Part II, Item 7 and Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K for additional information on the ceiling test.
We may be limited in our ability to maintain proved undeveloped reserves under current SEC guidance.
Current SEC guidance requires that proved undeveloped reserves (“PUDs”) may only be classified as such if a development plan has been adopted indicating that they are scheduledreasonably certain to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reservesPUDs as we pursue our drilling program. If current low price conditions persist,prices decline, we also may be compelled to further postpone the drilling of proved undeveloped reservesPUDs until prices recover. Further, ifIf we postpone drilling of proved undeveloped reservesPUDs beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped.
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As In addition, if we are unable to demonstrate funding sources for our development plan with reasonable certainty, we may have to write-off all or a portion of December 31, 2014, approximately 31%our PUDs.
Our PUDs comprised 16% of our total proved reserves were undevelopedas of December 31, 2017 and approximately 12% of our total proved reserves were developed non-producing. There can be no assurance that all of those reserves will ultimately be developed or produced.
Our undeveloped proved reserves and developed non-producing proved reserves require additional expenditures and/or activities to convert these into producing reserves. WeAs circumstances change, we cannot provide assurance thesethat all future expenditures will be made and that activities will be entirely successful in converting these reserves into proved producing reserves. Additionally,Although we are the operator for all the fields containing our PUDs as of December 31, 2017, in the past, we were not the operator for approximately 17%a portion of our undeveloped proved reserves and approximately 11% of our proved developed non-producing reserves, so wePUDs, which if this were to occur in the future, may not beput us in a position of not being able to control the timing of all development activities. Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reservesPUDs will ultimately be produced during the time periods we have planned, at the costs we have budgeted, or at all, which could result in the write-off of previously recognized reserves.
Relatively short production periods for our Gulf of Mexico properties subject us to high reserve replacement needs and require significant capital expenditures to replace our reserves at a faster rate than companies whose reserves have longer production periods. Our failure to replace those reserves would result in decreasing reserves, production and cash flows over time.
Unless we conduct successful development and exploration activities at sufficient levels or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. High production rates generally result in recovery of a relatively higher percentage of reserves during the initial few years of production. The majorityAll of our current production is from the Gulf of Mexico. Reserves in the Gulf of Mexico generally decline more rapidly than from reserves in many other producing regions of the United States. Our independent petroleum consultant estimates that 42%50% of our total proved reserves will be depleted within three years. As a result, our need to replace reserves and production from new investments is relatively greater than that of producers who recover lower percentages of their reserves over a similar time period, such as those producers who have a larger portion of their reserves in areas other than the Gulf of Mexico. We may not be able to develop, find or acquire additional reserves in sufficient quantities to sustain our current production levels or to grow production beyond current levels. In addition, due to the significant time requirements involved with exploration and development activities, particularly for wells in the deepwater or wells not located near existing infrastructure, actual oil and natural gas production from new wells may not occur, if at all, for a considerable period of time following the commencement of any particular project.
Significant capital expenditures are required to replace our reserves. If we are not able to replace reserves, we will not be able to sustain production at current levels.
Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful exploration, development or acquisition activities, our proved reserves and production will decline over time. Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures and acquisitions with cash on hand, cash provided by operating activities, securities offerings and bank borrowings. The capital markets we have historically accessed are currently constrained butbecause of our relatively high leverage and we believe we couldour access otherto capital markets if the need arises. These limitations in the capital markets may affect our ability to grow and changes in our capitalization structure may significantly affect our financial risk profile. Furthermore, we cannot be certain that financing for futureremains limited at this time. Our capital expenditures will be available if needed,in 2017 were below historical levels and we continue to the extent required, onhave a low capital expenditure budget for 2018 in order to conserve capital and target projects with a high probability of acceptable terms. For additional financing risks, see “– Risks Related to Financings.”
returns. Future cash flows are subject to a number of variables, such as the level of production from existing wells, the prices of oil, NGLs and natural gas, and our success in developing and producing new reserves. Any reductions in our capital expenditures to stay within internally generated cash flow (which could be adversely affected by decliningif commodity prices)prices decline) and cash on hand will make replacing produced reserves more difficult. If our cash flow from operations and cash on hand are not sufficient to fund our capital expenditure budget, we may be limited in our ability to access additional debt, equity or other methods of financing on an economic or timely basis to replace our proved reserves.
Lower oil and natural gas prices could negatively impact our ability to borrow.
As of December 31, 2014, borrowing availability under our revolving bank credit facility was $750 million, less outstanding borrowings of $447 million and letters of credit of less than $1 million, resulting in net availability of $302 million. Availability is determined semi-annually by our lenders and is based on oil, NGLs and natural gas prices and on our proved reserves. Substantially all of our oil and natural gas properties are pledged as collateral under the Fifth Amended and Restated Credit Agreement (the “Credit Agreement”) governing our revolving bank credit facility. The Credit Agreement limits our ability to incur additional indebtedness based on specified financial covenants, ratios or other criteria. Sustained and/or lower oil, NGLs and natural gas pricesThese limitations in the future could result in a reduction in credit availabilitycapital markets and alsoour recently constrained capital budget may adversely affect our ability to satisfy these covenants, ratios orsustain our production at 2017 levels. We cannot be certain that financing for future capital expenditures will be available if needed, and to the extent required, on acceptable terms. For additional financing risks, see “–Risks Relating to Our Industry, Our Business and Our Financial Condition.”
Additional deepwater drilling laws, regulations and other criteria and thus could reduce our ability to incur additional indebtedness and our ability to replace reserves.
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The Company could face additional requirements if it does not comply with the terms of its probation.
On January 3, 2013, the Company (i) pled guilty to one felony count under the Clean Water Act for altering monthly produced water discharge samples for the Ewing Banks 910 platform in 2009 and one misdemeanor count under the Clean Water Act for failure to report the discharge of a small amount of oil from the same platform in November 2009, (ii) paid a $0.7 million fine and $0.3 million for community service and (iii) entered into an environmental compliance program subject to a third-party audit. Under the agreement, the Company was placed on a three-year term of probation, which ends on January 3, 2016. The probation terms require that the Company commit no further environmental law violations, comply with an Environmental Compliance Plan during the probation period and take no adverse action against personnel who cooperatedrestrictions, delays in the investigation. The agreement further stipulates that the Government will not seek any further criminal charges against the Company in this matter. Failure to comply with the termsprocessing and approval of the agreement could lead to additional requirements and/or operating restrictions.
More stringent regulatory initiatives relating to offshore explorationdrilling permits and production activities may have an adverse effect on our results of operations, financial position and liquidity.
In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in the deep water of the Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, there have been many proposals, and substantial rules adopted, by governmental and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. The federal government, acting through the U.S. Department of the Interior and its implementing agencies that have since evolved into the present day BOEM and BSEE, has issued various rules, NTLs and temporary drilling moratoria. These rules and requirements impose or result in added environmental and safety measures upon exploration, development, oil spill-response and production operatorsdecommissioning plans, and other related developments in the Gulf of Mexico includingmay have a material adverse effect on our business, financial condition, or results of operations.
In recent years, we have expanded our drilling efforts on deepwater projects in the following:
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TheseGulf of Mexico. The BSEE and the BOEM have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill-response, and decommissioning plans and possible additional regulatory initiatives may serve to effectively slow down the pace ofcould result in difficult and more costly actions and adversely affect or delay new drilling and production operationsongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico dueand, as a result, are continuing to adjustmentsdevelop and implement new, more restrictive requirements. For example, in operating proceduresApril 2016, the BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation and certification practices as well as increased lead timesmaintenance of blow-out preventers, real-time monitoring of deepwater and high temperature, high pressure drilling activities, and enhanced reporting requirements. Also, in April 2016, the BOEM published a proposed rule that would update existing air emissions requirements relating to obtain explorationoffshore oil and production plan reviews, develop drilling applications, and apply for and receive new well permits. These new requirements also increase the cost of preparing permit applications and increase the cost of each new well, particularly for wells drilled in the deepwaternatural gas activity on the OCS. WeThe BOEM regulates these air emissions in connection with its review of exploration and development plans, and ROWs and RUEs applications. The proposed rule would bolster existing air emissions requirements by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the EPA to affect human health and public welfare. These rules and other potential rulemakings could become subjectfurther restrict offshore air emissions.
In May 2017, the Department of the Interior Secretary Ryan Zinke issued Order 3350 (“Order 3350”) directing the BSEE and the BOEM to fines,reconsider a number of regulatory initiatives governing oil and natural gas exploration in offshore federal waters related to safety, air quality control and performance-related activities. Examples of such regulatory initiatives being reconsidered include NTL #2016-N01 and the rules relating to blow-out preventers and well control. Following completion of their reviews, these agencies are to provide recommendations on whether such regulatory initiatives should continue or be implemented. Moreover, Order 3350 directed the BOEM to immediately cease all activities to promulgate the April 2016 proposed rule relating to offshore air quality control. One consequence of this review is that in December 2017, the BSEE published proposed revisions to its regulations regarding offshore drilling safety equipment, which proposal includes the removal of the requirement for offshore operators to certify through an independent third party that their critical safety and pollution prevention equipment (e.g., subsea safety equipment, including blowout preventers) is operational and functioning as designed in the most extreme conditions. The December 2017 proposed rule has not been finalized and there remains substantial uncertainty as to the scope and extent of any revisions to existing oil and gas safety and performance-related regulations and other regulatory initiatives that ultimately will be adopted by the BSEE and the BOEM pursuant to those agencies’ review process.
To the extent that the BOEM and the BSEE do not reduce the stringency of existing oil and gas safety and performance-related regulations and other regulatory initiatives, the regulatory requirements imposed by such existing or future, more stringent regulations or other regulatory initiatives could delay operations, disrupt our operations or increase the risk of leases expiring before exploration and development efforts have been completed due to the time required to develop new technology. Additionally, if left unchanged, the existing, or future, more stringent oil and gas safety and performance-related regulations and other regulatory initiatives imposed by the BOEM and BSEE could result in increased financial assurance requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties or orders requiring us to modifyshut-in production at one or suspendmore of our operations in the Gulf of Mexicofacilities. Also, if we fail to comply with these requirements. Moreover, if similar oilmaterial spill incidents were to occur in the future, in the Gulf of MexicoUnited States or elsewhereother countries where we conduct operations, the relevant governmental authoritiessuch an event may occur could elect to again issue directives to temporarily cease drilling activities. Inactivities and, in any event, they may from time to time issue further safety and environmental regulatory initiativeslaws and regulations regarding offshore oil and natural gas exploration and development, activities,any of which any one or more of such events could have a material adverse effect on our production activities as well asbusiness. We cannot predict with any certainty the full impact of any new laws or regulations on our financial position, results ofdrilling operations and liquidity.
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Requirements imposed by the BOEM and BSEE related to the decommissioning, plugging, and abandonment of offshore facilities could significantly impactor on the cost or availability of operating our business.
In additioninsurance to the NTLs discussed previously, the BOEM issued NTL No. 2010-G05 dated effective October 15, 2010 that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron” – wells, platforms and pipelines that are no longer producingcover some or serving exploration or support functions related to an operator’s lease – in the Gulf of Mexico. This NTL sets forth more stringent standards for decommissioning timing requirements by requiring that any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulfur zones are appropriately isolated. Similarly, platforms or other facilities which are no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts which could cause an increase, perhaps materially, in our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future ARO required to meet such increased costs. We have continued to review and revise our ARO estimates each year following BOEM’s issuance of this NTL. The increase in decommissioning activity in the Gulf of Mexico expected over the next few years as a result of the NTL may result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related ARO.
To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees demonstrate financial strength and reliability according to regulations or post bonds or other acceptable assurances that such obligations will be satisfied. In addition, in August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements for companies operating in federal waters. If BOEM were to increase its financial assurance requirements substantially, such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. The significant reductions in oil and natural gas pricing since the middle of 2014 may also adversely impact the BOEM’s financial assurance determinations with respect to the Company. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations. In addition, the BOEM can require supplemental bonding from operators for decommissioning, plugging, and abandonment liabilities if financial strength and reliability criteria are not met.
Proposed rules regulating air emissions from oil and gas operations could cause us to incur increased capital expenditures and operating costs.
The EPA has adopted new regulations under the CAA that, among other things, require additional emissions controls for the production of oil, NGLs and natural gas, including New Source Performance Standards to address emissions of sulfur dioxide and VOCs and a separate set of emission standards to address hazardous air pollutants frequentlyrisks associated with such production activities. The final regulations require, among other things, the reduction of VOC emissions through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. Compliance with these requirements could significantly increase our costs of development and production.operations.
Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.
We are and could be exposed to uninsured losses in the future. We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells. The current policy limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements. With respect to coverage for named windstorms, we have a $150.0 million aggregate limit covering all of our properties, subject to a retention (deductible) of $30.0 million. Included within the $150.0 million aggregate limit is total loss only (“TLO”) coverage on our Mahogany platform, which has no retention.
The occurrence of a significant accident or other event not covered in whole or in part by our insurance could have a material adverse impact on our financial condition and operations. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. In May and June 2014,2017, we renewedentered into our insurance policies covering well control and hurricane damage (described above) and for general liability and pollution. These policies are effective for one year from their respective execution date. These policies reduce, but do notin no way totally mitigate our risk as we are exposed to amounts for retention and co-insurance, limits on coverage and some events that are not insured. TheseRenewal of these policies expire in May and June 2015.at a cost commensurate with current premiums is not assured. We also have other smaller per-occurrence retention amounts for various other events. In addition, pollution and environmental risks are generally not fully insurable, as gradual seepage and pollution are not covered under our policies. Because third-party drilling contractors are used to drill our wells, we may not realize the full benefit of workmen’s compensation laws in dealing with their employees.
OPA requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. We are currently required to demonstrate, on an annual basis, that we have ready access to $150 million that can be used to respond to an oil spill from our facilities on the OCS. If OPA is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We cannot predict at this time whether OPA will be amended, or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.
For some risks, we mayhave not obtainobtained insurance ifas we believe the cost of available insurance is excessive relative to the risks presented. We may take on further risks in the future if we believe the cost is excessive to the risks. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Hurricane Remediation, Insurance Claims and Insurance Coverage under Part II, Item 7 in this Form 10-K for additional information on insurance coverage.
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Insurance for well control and hurricane damage may become significantly more expensive for less coverage and some losses currently covered by insurance may not be covered in the future.
Due to insurance claims in recent years associated withIn the past, hurricanes in the Gulf of Mexico and globalhave caused catastrophic losses and property damage and welldamage. Well control insurance coverage has become morebecomes limited from time to time and the cost of such coverage has becomebecomes both more costly and more volatile. In the past, we have been able to renew our policies each annual period, but our coverage has varied depending on the premiums charged, our assessment of the risks and our ability to absorb a portion of the risks. The insurance market may further change dramatically in the future due to thehurricane damage, major oil spill that occurred in 2010 at BP’s Macondo well inspills or other events.
In the deepwater Gulf of Mexico. As of December 31, 2014, virtually all offuture, our PV-10 value of proved reserves attributable to our Gulf of Mexico properties is on platforms that are covered under our current insurance policies for named windstorm damage. Our insurers may not continue to offer us the type and level of our currentwhat we view as reasonable coverage, or our costs may increase substantially as a result of increased premiums and therepremiums. There could be an increased risk of uninsured losses that may have been previously insured. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurance companies will not pay our claims. The occurrence of any or all of these possibilities could have a material adverse effect on our financial condition and results of operations.
Commodity derivative positions may limit our potential gains.
In order to manage our exposure to price risk in the marketing of our oil and natural gas, we may periodically enter into oil and natural gas price commodity derivative positions with respect to a portion of our expected production. During the first quarter of 2017, we entered into commodity derivative contracts, which expired on or before December 31, 2017. As of the filing date of this Form 10-K, we did not have any open commodity derivative positions. We may enter into more contracts in the future. While these commodity derivative positions are intended to reduce the effects of volatile crude oil and natural gas prices, they may also limit future income if crude oil and natural gas prices were to rise substantially over the price established by such positions. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
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our production is less than expected;
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there is a widening of price differentials between delivery points for our production and the delivery points assumed in the hedge arrangements; or
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the counterparties to the derivative contracts fail to perform under the terms of the contracts.
See Financial Statements and Supplementary Data– Note 68 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information on derivative transactions.
Competition for oil and natural gas properties and prospects is intense; some of our competitors have larger financial, technical and personnel resources that may give them an advantage in evaluating and obtaining properties and prospects.
We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil, NGLs and natural gas and securing trained personnel. Many of our competitors have financial resources that allow them to obtain substantially greater technical expertise and personnel than we have. We actively compete with other companies in our industry when acquiring new leases or oil and natural gas properties. For example, new leases acquired from the BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. Our competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay.pay or finance. On the acquisition opportunities made available to us, we compete with other companies in our industry for such properties through a private bidding process, direct negotiations or some combination thereof. Our abilitycompetitors may have significantly more capital resources and less expensive sources of capital. In addition, they may be able to acquire additionalgenerate acceptable rates of return from marginal prospects anddue to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.their lower costs of capital. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted. The availability of properties for acquisition depends largely on the divesting practices of other oil and natural gas companies, commodity prices, general economic conditions and other factors we cannot control or influence. Additional requirements and limitations recently imposed on us and our ability to finance such acquisitions may put us at a competitive disadvantage for acquiring properties. These risks are described above in the risk factor entitled: Requirements imposedWe may be unable to provide the financial assurances if the BOEM submits future demands to cover our decommissioning obligations in the amounts and under the time periods required by the BOEMBOEM. If extensions and BSEE relatedmodifications to the decommissioning, plugging,BOEM’s demands are needed and abandonment ofcannot be obtained, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore facilities could significantly impact the cost of operating our business.leases.
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We conduct exploration, development and production operations on the deep shelf and in the deepwater of the Gulf of Mexico, which presents unique operating risks.
The deep shelf and the deepwater of the Gulf of Mexico are areas that have had less drilling activity due, in part, to their geological complexity, depth and higher cost to drill and ultimately develop. There are additional risks associated with deep shelf and deepwater drilling that could result in substantial cost overruns and/or result in uneconomic projects or wells. Deeper targets are more difficult to interpret with traditional seismic processing. Moreover, drilling costs and the risk of mechanical failure are significantly higher because of the additional depth and adverse conditions, such as high temperature and pressure. For example, the drilling of deepwater wells requires specific types of rigs with significantly higher day rates, and limited availability, as compared to the rigs used in shallower water. Deepwater wells have greater mechanical risks because the wellhead equipment is installed on the sea floor. Deepwater development costs can be significantly higher than development costs for wells drilled on the conventional shelf because deepwater drilling requires larger installation equipment, sophisticated sea floor production handling equipment, expensive state-of-the-art platforms and investment in infrastructure.infrastructure investments. Deep shelf development can also be more expensive than conventional shelf projects because deep shelf development requires more drilling days and higher drilling and service costs due to extreme pressure and temperatures associated with greater depths. Accordingly, we cannot assure you that our oil and natural gas exploration activities in the deep shelf, the deepwater and elsewhere will be commercially successful.
Our estimates of future asset retirement obligationsARO may vary significantly from period to period and are especially significant because our operations are concentrated in the Gulf of Mexico.
We are required to record a liability for the present value of our ARO to plug and abandon inactive non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or such requirements may be interpreted more restrictive interpretation,restrictively, and asset removal technologies are constantly evolving, which may result in additional or increased costs. As a result, we may make significant increases or decreases to our estimated ARO in future periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future ARO couldwill differ dramatically from whatour recorded estimate if we may ultimately incur ashave a result of platform damage.damaged platform.
As described above in the risk factor titled “NewThe additional requirements imposed by the BOEM and BSEE related to the decommissioning, plugging, and abandonment of offshore facilities could significantly impact the cost of operating our business,”under the BOEM’s NTL 2010-G05#2016-N01, if ever fully implemented, would increase our operating costs and reduce the availability of surety bonds due to the increased our liabilitydemands for ARO by acceleratingsuch bonds in a low-price commodity environment. While the time frame for plugging, abandonment and removal for somecurrent implementation timeline has been extended indefinitely, except in certain circumstances where there was a substantial risk of our platformsnonperformance of the interest holder’s decommissioning liabilities, this timeline could change at the BOEM’s discretion and the BOEM further increased ourmay re-issue sole liability after issuing regulation interpretations which affected scope and requirements. In addition, the potential increase in decommissioning activityorders in the Gulffuture, including if it determines there is a substantial risk of Mexico over the next several years as a resultnonperformance of the interest holder’s decommissioning liabilities. Under NTL could likely result#2016-N01, the BOEM has given broader interpretation authority to the BOEM’s district personnel, which increases the difficulty in complying with this NTL should it be fully implemented. In addition, increased demand for salvage contractors and equipment resultingcould result in increased estimates ofcosts for decommissioning activities, including plugging and abandonment operations. These items have, and removalmay further increase our costs and increasesmay impact our liquidity adversely.
We may be obligated to pay costs related to other companies that have filed for bankruptcy or have indicated they are unable to pay their share of costs in joint ownership arrangements.
In our contractual arrangements of joint ownership of oil and natural gas interests with other companies, we are obligated to pay our share of operating, capital and decommissioning costs, and have the right to a share of revenues after royalties and certain other cash inflows. If one of the companies in the arrangement is unable to pay its agreed upon share of costs, generally the other companies in the arrangement are obligated to pay the non-paying company’s obligations. Under joint operating agreements (“JOAs”) among working interest owners, the non-paying company would typically lose the right to future revenues, which would be applied to the non-paying company’s share of operating, capital and decommissioning costs. If future revenues are insufficient to defray these additional costs, especially in cases where the well has stopped producing and is being decommissioned, we could be obligated to pay certain costs of the defaulting party. In addition, the liability to the U.S. Government for obligations of lessees under federal oil and gas leases, including obligations for decommissioning costs, is generally joint and several among the various co-owners of the lease, which means that any single owner may be liable to the U.S. Government for the full amount of all lessees’ obligations under the lease. In certain circumstances, we also could be liable for decommissioning liabilities on federal oil and gas leases that we previously owned and the assignee is bankrupt or unable to pay its decommissioning costs. For example, we have in the past received a demand for payment of such costs related ARO.to property interests that were sold several years prior. These indirect obligations would affect our costs, operating profits and cash flows negatively and could be substantial.
We may not be in a position to control the timing of development efforts, associated costs or the rate of production of the reserves from our non-operated properties.
As we carry out our drilling program, we may not serve as operator of all planned wells. WeIn that case, we have limited ability to exercise influence over the operations of some non-operated properties and their associated costs. Our dependence on the operator and other working interest owners and our limited ability to influence operations and associated costs of properties operated by others could prevent the realization of anticipated results in drilling or acquisition activities. The success and timing of exploration and development activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:
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unusual or unexpected geological formations;
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the timing and amount of capital expenditures;
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the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;
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the operator’s expertise and financial resources;
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approval of other participants in drilling wells and such participants’ financial resources;
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Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our development activities may be unsuccessful for many reasons, including adverse weather conditions, cost overruns, equipment shortages, geological issues, technical difficulties and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not assure us that we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells hinder our efforts to replace reserves.
Our oil and natural gas exploration and production activities, including well stimulation and completion activities, which include, among other things, hydraulic fracturing, involve a variety of operating risks, including:
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fires;
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explosions;
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blow-outs and surface cratering;
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uncontrollable flows of natural gas, oil and formation water;
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natural disasters, such as tropical storms, hurricanes and other adverse weather conditions;
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inability to obtain insurance at reasonable rates;
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failure to receive payment on insurance claims in a timely manner, or for the full amount claimed;
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pipe, cement, subsea well or pipeline failures;
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casing collapses or failures;
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mechanical difficulties, such as lost or stuck oil field drilling and service tools;
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abnormally pressured formations or rock compaction; and
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environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, encountering NORM, and discharges of brine, well stimulation and completion fluids, toxic gases, or other pollutants into the surface and subsurface environment.
If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:
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injury or loss of life;
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damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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clean-up responsibilities;
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regulatory investigation and penalties;
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suspension of our operations;
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repairs required to resume operations; and
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loss of reserves.
Offshore operations are also subject to a variety of operating risks related to the marine environment, such as capsizing, collisions and damage or loss from tropical storms, hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. Companies that incur environmental liabilities frequently also confront third-party claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. We may have liability for releases of hazardous substances at our properties by prior owners, operators, other third parties, or at properties we have sold. As a result, we could incur substantial liabilities that could reduce or eliminate funds available for exploration, development and acquisitions or result in the loss of property and equipment.
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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 OCS means that some or all of our properties could be affected by the same event should the Gulf of Mexico experience:
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severe weather, including tropical storms and hurricanes;
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delays or decreases in production, the availability of equipment, facilities or services;
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changes in the status of pipelines that we depend on for transportation of our production to the marketplace;
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delays or decreases in the availability of capacity to transport, gather or process production; and
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changes in the regulatory environment.
Because a majority of our properties could experience the same conditions at the same time, these conditions could have a greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area. For example, net production of approximately 8.7 Bcfe1.7 MMBoe was deferred as a result of damage caused primarily byduring 2017 due to Hurricane 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.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight rock formations. We utilize hydraulic fracturing techniques in connection with developing our properties in the Spraberry fieldNate, pipeline issues and other onshore properties. The process involves the injectionevents. A similar amount was deferred during 2016 due to events outside of water, sand or other proppants and chemicals under pressure into the rock formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. The EPA, however, recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWA Underground Injection Control Program and issued permitting guidance covering such activities in February 2015. In addition, the EPA has commenced a broad study of the potential environmental effects of hydraulic fracturing activities, and the agency has indicated that it expects to issue its study report in 2015. A number of other federal agencies, including the U.S. Department of Energy, Department of Interior, and White House Council on Environmental Quality, are also studying various aspects of hydraulic fracturing. The results of these studies could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. From time to time, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local governments have adopted, and other states and local governments are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations, including states in which we operate. For example, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to associated permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.control.
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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.of such properties.
Our business strategy includes growing by making acquisitions, which may include acquisitions of exploration and production companies, producing properties and undeveloped leasehold interests. Our acquisition of oil and natural gas properties requires assessments of many factors that are inherently inexact and may be inaccurate, including the following:
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acceptable prices for available properties;
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amounts of recoverable reserves;
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estimates of future crude oil, NGLs and natural gas prices;
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estimates of future exploratory, development and operating costs;
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estimates of the costs and timing of plugging and abandonment; and
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estimates of potential environmental and other liabilities.
Our assessment of the acquired properties will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies. In the course of our due diligence, we have historically not physically inspected every well, platform or pipeline. Even if we had physically inspected each of these, our inspections may not have revealed structural and environmental problems, such as pipeline corrosion, well bore issues or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities associated with such risks. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.
Increasing our reserve base through acquisitions ishas historically been an important part of our business strategy. We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses. 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:
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a significant increase in our indebtedness and working capital requirements;
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the inability to timely and effectively integrate the operations of recently acquired businesses or assets;
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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;
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our lack of drilling history in the geographic areas in which the acquired business operates;
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customer or key employee loss from the acquired business;
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increased administration of new personnel;
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additional costs due to increased scope and complexity of our operations; and
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potential disruption of our ongoing business.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. To the extent that we acquire properties substantially different from the properties in our primary operating region or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as with acquisitions within our primary operating region. We may not be successful in addressing these risks or any other problems encountered in connection with any acquisition we may make.
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Estimates of our proved reserves depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in the estimates or underlying assumptions will materially affect the quantities of and present value of future net revenues from our proved reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of our reserves at December 31, 2014.2017. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Oil and natural gas reserve quantities, under Part II, Item 7 for a discussion of the estimates and assumptions about our estimated oil and natural gas reserves information reported in Business under Part I, Item 1, Properties under Part I, Item 2 and Financial Statements and Supplementary Data – Note 21 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K.
In order to prepare our year-end reserve estimates, our independent petroleum consultant projected our production rates and timing of development expenditures. Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary and may not be under our control. The process also requires economic assumptions about matters such as crude oil and natural gas prices, operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues from our proved oil and natural gas reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month unweighted first-day-of-the-month average price for each product and costs in effect on the date of the estimate, which prices are not reflective of the substantially lower prices realized in December 2014 and January 2015.estimate. Actual future prices and costs may differ materially from those used in the present value estimate.
Prospects that we decide to drill may not yield oil or natural gas in commercial quantities or quantities sufficient to meet our targeted rate of return.
A prospect is an area in which we own an interest, could acquire an interest or have operating rights, and have what our geoscientists believe, based on available seismic and geological information, to be indications of economic accumulations of oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure that the analysis we perform using data from other wells, more fully explored prospects and/or producing fields will accurately predict the characteristics and potential reserves associated with our drilling prospects. The recent downturn inSustained low crude oil, NGLs and natural gas pricing will also significantly impact the projected rates of return of our projects without the assurance of significant reductions in costs of drilling and development. To the extent we drill additional wells in the deepwater and/or on the deep shelf, our drilling activities could become more expensive. In addition, the geological complexity of deepwater and deep shelf and various onshore formations may make it more difficult for us to sustain our historical rates of drilling success. As a result, we can offer no assurance that we will find commercial quantities of oil and natural gas and, therefore, we can offer no assurance that we will achieve positive rates of return on our investments.
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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 2013.2013 from Tropical Storm Karen and in 2017 from Hurricane Nate.
In some cases, our wells are tied back to platforms owned by partiesthird-parties who do not have an economic interest in our wells and we cannot be assured that such parties will continue to process our oil and natural gas.
Currently, a portion of our oil and natural gas is processed for sale on platforms owned by partiesthird-parties with no economic interest in our wells and no other processing facilities would be available to process such oil and natural gas without significant investment by us. In addition, third-party platforms could be damaged or destroyed by hurricanes which could reduce or eliminate our ability to market our production. As of December 31, 2014, 122017, 10 fields, accounting for approximately 12.8 Bcfe0.8 MMBoe (or 12%6%) of our 20142017 production, are tied back to separate, third-party owned platforms. There can be no assurance that the owners of such platforms will continue to process our oil and natural gas production. If any of these platform operators ceases to operate their processing equipment, we may be required to shut in the associated wells, construct additional facilities or assume additional liability to re-establish production.
If third-party pipelines connected to our facilities become partially or fully unavailable to transport our crude oil and natural gas or oil, or if the prices charged by these third-party pipelines increase, our revenues or costs could be adversely affected.
We depend upon third-party pipelines that provide delivery options from our facilities. Because we do not own or operate these pipelines, their continued operation is not within our control. These pipelines may become unavailable for a number of reasons, including testing, maintenance, capacity constraints, accidents, government regulation, weather-related events or other third-party actions. If any of these third-party pipelines become partially or fully unavailable to transport crude oil and natural gas, and oil, or if the gas quality specification for the natural gas pipelines changes so as to restrict our ability to transport natural gas on those pipelines, our revenues could be adversely affected. For example, in 2013,2017, various pipelines were shut down at various times causing production deferral of approximately 6.3 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 more than half of 2014.0.4 MMBoe.
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 increase our operating costs, either of which would adversely impact our operating profits, cash flows and reserves.
We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration, development, production and transportation of crude oil and natural gas and operational safety. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with such legal requirements may harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as:
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land use restrictions;
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lease permit restrictions;
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drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds;
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spacing of wells;
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unitization and pooling of properties;
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safety precautions;
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operational reporting;
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reporting of natural gas sales for resale; and
taxation.
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Under these laws and regulations, we could be liable for:
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personal injuries;
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property and natural resource damages;
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well site reclamation costs; and
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governmental sanctions, such as fines and penalties.
Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. It is also possible that a portion of our oil and natural gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See Business – Regulation under Part I, Item 1 in this Form 10-K for a more detailed explanation of regulations impacting our regulatory risks.business.
Our operations may incur substantial liabilities to comply with environmental laws, endangered species laws and regulations.
Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:
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require the acquisition of a permit or other approval before drilling or other regulated activity commences;
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restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;
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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
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impose substantial liabilities for pollution resulting from our operations.
Failure to comply with these laws and regulations may result in:
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the assessment of administrative, civil and criminal penalties;
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loss of our leases;
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incurrence of investigatory, remedial or corrective obligations; and
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the imposition of injunctive relief, which could prohibit, limit or restrict our operations in a particular area.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and regardless of whether our operations met previous standards in the industry at the time they were conducted. Our permits require that we report any incidents that cause or could cause environmental damages.
Future environmental laws and regulations could significantly increase our capital expenditures and operating costs or could result in delays to or limitations on our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows. See Business – RegulationEnvironmental Regulations under Part I, Item 1 in this Form 10-K for a more detailed description of our environmental risks.and endangered species regulations.
The ONNR’s revised interpretations on determining appropriate allowances related to transportation and processing costs for natural gas could cause us to pay substantial amounts in back royalties and in future royalties.
The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases. The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant for which we had gas processed. In the second quarter of 2015, pursuant to the initiative, the Company received requests from the ONRR for additional data regarding the Company’s transportation and processing allowances on natural gas production that was processed through a specific processing plant. The Company also received a preliminary determination notice from the ONRR asserting its preliminary determination that the Company’s allocation of certain processing costs and plant fuel use at another processing plant were impermissibly allowed as deductions in the determination of royalties owed under Federal oil and gas leases. The Company has submitted responses covering certain plants and certain time periods and has not yet received responses as to the preliminary determination asserting the reasonableness of its revised allocation methodology of such costs. These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under the Company’s Federal oil and gas leases for current and prior periods. Through December 31, 2017, we paid $2.1 million of additional royalties and expect to pay more in the future. We are not able to determine the range of any additional royalties or if such amounts would be material.
Should we fail to comply with all applicable FERC, CFTC and FTC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1.2 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Under the Commodity Exchange Act and regulations promulgated thereunder by the CFTC and under the Energy Independence and Security Act of 2007 and regulations promulgated thereunder by the FERC, the CFTC and FTC have adopted anti-market manipulation rules relating to the prices or futures of commodities. Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, the FERC, the CFTC or the FTC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability. See Business – Regulation under Part I, Item 1 in this Form 10-K for further description of our regulations.
Climate change legislation or regulations restricting emissions of greenhouse gasesGHG could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHG. These efforts have included consideration of cap-and-trade programs, carbon taxes, greenhouse gas reporting and tracking programs, and regulations that directly limit greenhouse gas emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented. The EPA, however, has determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health andadopted regulations under 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 regulationsexisting CAA to restrict emissions of greenhouse gases under existing provisions ofGHG. For example, the CAA. The EPA has adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which imposes preconstruction and operating permit requirements ofon certain large stationary sources.sources that are already potential sources of certain other significant pollutant emissions. The EPA also adopted rules requiring the monitoring and reporting of greenhouse gas emissions on an annual basis from specified large greenhouse gas emission sources in the United States, as well as certainincluding onshore and offshore oil and natural gas production facilities,facilities. Federal agencies have also begun directly regulating emissions of methane, a greenhouse gas, from oil and natural gas operations as described above. Compliance with these rules could result in increased compliance costs on an annual basis.our operations.
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In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gasesGHG and almost one-halfa number of thestates and grouping of states have already taken legal measures to reduce emissions of greenhouse gasesGHG primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. On an international level, the United States is one of numerous nations that prepared an international climate change agreement in Paris, France in December 2015, requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and became effective in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but does include pledges to voluntarily limit or reduce future emissions. In August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gasesGHG 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 gasesGHG could have an adverse effect on our business, financial condition and results of operations. Additionally, with concerns over GHG emissions, certain non-governmental activists have recently directed their efforts at shifting funding away from companies with energy-related assets, which could result in limitations or restrictions on certain sources of funding for the energy sector. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gasesGHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. Our offshore operations are particularly at risk from severe climatic events. If any such affectsclimate effects were to occur, they could have an adverse effect on our business, financial condition and results of operations. Please seeSee – Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses. – under this Item 1A.
The enactment of derivativesDerivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price, changes, interest rate and other risks associated with our business.
In July 2010, new comprehensive financial reform legislation, known as theThe Dodd-Frank Wall Street Reform and Consumer Protection Act, (the “DF Act”), was enacted thatamong other things, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The DF Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the DF Act. Although the CFTCCommodity Futures Trading Commission (the “CFTC”) has finalized certain of its regulations under the Dodd-Frank Act, but others remain to be finalized or implemented and itimplemented. It is not possible at this time to predict when this will be accomplished.
In October 2011,accomplished or what the CFTC issued regulations to set position limits for certain futures and option contracts interms of the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Colombia in September 2012. However, in November 2013, the CFTC proposed newfinal 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 new position limit rules are not yet final,will be, so the impact of those provisions on usrules is uncertain at this time.
The CFTC has designated certain types of swaps (thus far, only certain interest rate swaps and credit default swaps) for mandatory clearing and exchange trading, and may designate other types of swaps for mandatory clearing and exchange trading in the associatedfuture. To the extent we engage in such transactions or transactions that become subject to such rules alsoin the future, we will require us in connection with covered derivatives activitiesbe required to comply with clearing and trade-execution requirements or to take steps to qualify for an exemption to such requirements. Although the Company expects to qualify forwe are availing ourselves of the end-user exception fromto the mandatory clearing and exchange trading requirements for swaps entereddesigned to hedge itsour 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 useswe use for hedging. If any of our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or execute them on a derivatives contract or swap facility market.
In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from margin requirements for swaps to other market participants, such as swap dealers, these rules may change the CFTC or federal banking regulators may require end-userscost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, we could be required to enter into credit support documentation and/or post initial andor variation margins. Posting of collateral couldmargin, which would impact our liquidity and reduce our cash. This would in turn reduce our ability to execute hedges to reduce risk and protect cash 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. flows.
The full impact of the DFDodd-Frank 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 andany new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing derivative contracts, increase our exposure to less creditworthy counterparties or reduce liquidity.commodity price contracts. If we reduce our use of derivativescommodity price contracts as a result of the DF Actlegislation 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,expenditures and make cash distributions to our unitholders. Further, to the DF Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Ourextent our revenues are unhedged, they could therefore be adversely affected if a consequence of the DFDodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.
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We own a platform in a highly regulated National Marine Sanctuary, which increases our compliance costs and subjects us to risk of significant fines and penalties if we do not maintain rigorous compliance.
We own a 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,rely on our information technology infrastructure and management information systems to operate and record aspects of our business. Although we take measures to protect against cybersecurity risks, including cyber-security exposure, from unauthorized access to our facilitiesconfidential and proprietary information, our security measures may not be able to detect or prevent every attempted breach. Similar to other companies, we have experienced cyber-attacks, although we have not suffered any material losses related to such attacks. Security breaches include, among other things, illegal hacking, computer systems. This exposure includesviruses, or acts of vandalism or terrorism. A breach could result in an interruption in our operations, unauthorized access to sensitive information; malicious damage to our facilities, infrastructure, and computer systems; malicious damage to third-party facilities, infrastructure, and computer systems; safety exposure for our employees and contractors; and disruptionspublication of our operations. Cyber-security exposures in particular are fluidconfidential business or proprietary information, unauthorized release of customer or employee data, violation of privacy or other laws and adaptive, and include malicious software, unauthorized accessexposure to confidential data and disruptions to operations that use computers and data systems. Although we utilize various procedures and controls to reduce these exposures, there can be no assurances that these procedures and controls will be sufficient to prevent such events from occurring. We do not carry business interruption insurance.litigation. Any of these security breaches could have a material adverse effect on our consolidated financial position, results of operations and cash flows.
The loss of members of our senior management could adversely affect us.
To a large extent, we depend on the services of our senior management. The loss of the services of any of our senior management, including Tracy W. Krohn, our Founder, Chairman andof the Board, Chief Executive Officer; Jamie L. Vazquez, ourOfficer and President; John D. Gibbons, our Senior Vice President and Chief Financial Officer; Thomas P. Murphy, our Senior Vice President and Chief Operations Officer; and Stephen L. Schroeder, our Senior Vice President and Chief Technical Officer; and Thomas F. Getten, our Vice President, General Counsel and Corporate Secretary,Officer, could have a negative impact on our operations. We do not maintain or plan to obtain for the benefit of the Company any insurance against the loss of any of these individuals. Please readSee Executive Officers of the Registrant under Part I following Item 3 in this Form 10-K for more information regarding our senior management team.
The unavailability or high cost of certain types of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
The U.S. oil and natural gas industry may experience shortages in the availability of certain types of drilling rigs or experience drilling rigs with high costs in relation to the recent change in price of crude oil and natural gas. This could delay or adversely affect our exploration and development operations, which could have a material adverse effect on our business, financial condition or results of operations. If the unavailability or high cost of rigs, equipment, supplies or personnel were particularly severe in the offshore waters of the U.S. Gulf of Mexico or Texas, we could be materially and adversely affected because our operations and properties are concentrated in those areas.
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Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
Legislation has beenIn past years, legislation was proposed that would if enacted into law, makehave made significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax preferencesprovisions currently available to oil and gas exploration and production companies. These changes include,Such legislative proposals have included, but are not been limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities, and (iv)(iii) an extension of the amortization period for certain geological and geophysical expenditures.
It is unclear whether Congress could consider, and could include, some or all of these or similar changes will be enacted and, if enacted, how soon any such changes could become effective.proposals as part of future tax reform legislation. The passage of thisany legislation as a result of these proposals or any other similar changes in U.S. federal income tax lawlaws could eliminate or postpone certain tax deductions that are currently available to us, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
The Tax Cuts and Jobs Act (“TCJA”) of 2017 modified certain U.S. Federal income tax provisions available to corporations. Along with respect tolowering the corporate income tax rate, the TCJA changed certain income tax rules and deductions including cost recovery, limits on the deductions of interest expense, the elimination of the deduction from domestic production activities and utilization of net operating losses. These changes will have an impact on our taxation and generally take effect for tax years beginning after 2017. The TCJA did not (i) repeal the percentage depletion allowance for oil and gas explorationproperties, (ii) eliminate current deductions for intangible drilling and production,development costs, or (iii) extend the amortization period for certain geological and any such change could have a negative effect on the results of our operations.geophysical expenditures.
Counterparty credit risk may negatively impact the conversion of our accounts receivables to cash.
Substantially all of our accounts receivable result from crude oil, NGLs and natural gas sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by any adverse changes in economic or other conditions. In recent years, market conditions resultingresulted in downgrades to credit ratings of energy merchants affected the liquiditysome of our oil and gas customers and joint interest partners. While we have not experienced collection issues from our customers, we have experienced collection issues from several of our purchasers.joint interest partners.
Risks Related to Financings
Adverse changes in the financial and credit markets could negatively impact our economic growth. In addition, the continuation of the current commodity price environment, or further declines of oil, NGLs and natural gas prices can affect our ability to obtain funding on acceptable terms or under our current credit facility. These impacts may hinder or prevent us from meeting our future capital needs and may restrict or limit our ability to increase reserves of oil and natural gas.
The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises. These limitations in the capital markets may affect our ability to grow and limit our ability to replace our reserves of oil and gas.
During 2012 and 2011, world financial markets were affected by the instability of the Euro and the uncertainty of some Euro-based countries to repay their debt. In addition, one credit agency downgraded the debt of the U.S. government. These types of events bring uncertainty to the financial markets and may produce volatility and may decrease financing availability. For example, in 2009, the global financial markets and economic conditions were severely distressed. There were concerns, both with respect to bank failures and bank liquidity, as to whether our banks would be able to meet their commitments under credit arrangements in place during that time. These concerns led to very few financing transactions being completed.
Our revolving bank credit facility is subject to a semi-annual borrowing base re-determination, and available credit could be reduced or eliminated at the sole discretion of the banks within the facility. Our borrowing base may decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves, lending requirements or regulations, or the issuance of new indebtedness. We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms.
If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due and could be required to repay any borrowings in excess of the redetermined borrowing base, or we may be unable to implement our exploratory and development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.
25
We may not be able to generate enough cash flow to meet our debt obligations.
We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may become insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay off our outstanding indebtedness. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or initiatives by our competitors, are beyond our control.
If we do not generate enough cash flow from operations to satisfy our current or any future debt obligations, we may have to undertake alternative financing plans, such as:
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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:
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In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders will have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Assuming continuing oil and gas prices near levels realized in December 2014 and January 2015, we likely will be out of compliance with certain of our financial ratio maintenance covenants under our Credit Agreement sometime during 2015. We intend to engage the lenders under the Credit Agreement in discussions regarding amending our financial ratio covenants at such time as our borrowing base is next redetermined, but we can provide no assurance that we will be successful in obtaining such an amendment. While we believe we will obtain the appropriate covenant relief, if we are unable to obtain such an amendment from our lenders, we believe that we can find alternative financing, albeit at a higher cost, and we may have to reduce our cash outlays further for capital expenditures and other activities until such time as market conditions recover. Realization of any of these factors could adversely affect our financial condition, results of operations and cash flows.
26
Risks Related to Our Principal Shareholder, Tracy W. Krohn
We will be controlled by Tracy W. Krohn as long as he owns a majority of our outstanding common stock, and other shareholders will be unable to affect the outcome of shareholder voting during that time. This control may adversely affect the value of our common stock and inhibit potential changes of control.
Tracy W. Krohn owns and controls 39,876,501 shares of our common stock, representing approximately 52.5% of our voting interests as of February 15, 2015. As a result, Mr. Krohn has the ability to control the outcome of matters that require a simple majority of shareholders for approval and other investors, by themselves, will not be able to affect the outcome of virtually any shareholder vote. Mr. Krohn, subject to any duty owed to our minority shareholders under Texas law, is able to control all matters affecting us, including:
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Mr. Krohn is generally not prohibited from selling a controlling interest in us to a third party. In addition, his concentrated control could discourage others from initiating any potential merger, takeover or other change of control transaction that might be beneficial to our business or shareholders. As a result, the market price of our common stock could be adversely affected.
Due to Mr. Krohn’s ownership and control, we are exempted from many New York Stock Exchange (“NYSE”) corporate governance rules, and, as a result, our other shareholders may not have the protections set forth in those rules, particularly in the event of conflicts of interest with Mr. Krohn.
Mr. Krohn owns a majority of our common stock, and, therefore, we are a “controlled company” within the meaning of the rules of the NYSE. As such, we are not required to comply with certain corporate governance rules of the NYSE that would otherwise apply to us as a listed company on that exchange. These rules are generally intended to increase the likelihood that boards will make decisions in the best interests of shareholders. Should the interests of Mr. Krohn differ from those of other shareholders, the other shareholders will not be afforded the protections of having all of the other directors on the board being independent from our principal shareholder.
Item 1B. Unresolved Staff Comments
None.
27
Our producing fields are located in federal and state waters in the Gulf of Mexico Alabama and Texas. The offshore fields are found in water depths ranging from less than 10 feet up to 7,2007,300 feet. The reservoirs in our offshore fields are generally characterized as having high porosity and permeability, which typically results inwith high initial production rates. The reservoirs in our onshore fields are generally characterized as having low porosity and permeability and require stimulation and artificial lift to produce. The following map provides the locations of our 10 largest fields as of December 31, 2014,2017, based on quantities of proved reserves on an energy equivalent basis. At December 31, 2014,2017, these fields accounted for approximately 82%80% of our proved reserves.
28
The following table provides information for our 10 largest fields in descending orderdetermined using quantities of proved net reserves on an energy equivalent basis as of December 31, 2014, based on quantities on an energy equivalent basis.2017. Deepwater refers to acreage in over 500 feet of water. Our interests in several of our offshore fields are owned by our wholly-owned subsidiary, W & T Energy VI, LLC. Unless indicated otherwise, “drilling” or “drilled” in the field descriptions below refers to when the drilling reached target depth, as this measurement usually has a higher correlation to changes in proved reserves compared to using the SEC’s definition for completion.completion:
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| Percent Oil and NGLs of |
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| 2014 Average Daily Equivalent Sales Rate (Boe/d) (1) |
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| 2014 Average Daily Equivalent Sales Rate (Mcfe/d) (1) |
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| Percent Oil and NGLs of |
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| 2017 Average Daily Equivalent Sales Rate (Boe/d) (1) |
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Field Name | Field Category |
| Net Reserves (1) |
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| Gross |
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| Net |
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| Gross |
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| Net |
| Field Category |
| Proved Reserves (1) |
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| Gross |
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| Net |
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Spraberry (Yellow Rose) | Onshore |
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| 89 | % |
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| 4,502 |
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| 3,408 |
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| 27,013 |
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| 20,450 |
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Ship Shoal 349 (Mahogany) | Shelf |
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| 81 | % |
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| 8,851 |
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| 7,388 |
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| 53,105 |
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| 44,330 |
| Shelf |
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| 82 | % |
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| 8,332 |
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| 6,943 |
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Fairway | Shelf |
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| 26 | % |
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| 5,253 |
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| 4,305 |
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| 31,515 |
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| 25,830 |
| Shelf |
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| 25 | % |
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| 5,176 |
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| 3,882 |
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Miss. Canyon 243 (Matterhorn) | Deepwater |
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| 81 | % |
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| 1,613 |
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| 1,613 |
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Viosca Knoll 783 (Tahoe/SE Tahoe) | Deepwater |
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| 26 | % |
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| 6,292 |
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| 4,668 |
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| 37,753 |
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| 28,007 |
| Deepwater |
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| 29 | % |
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| 4,142 |
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| 2,816 |
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Miss. Canyon 243 (Matterhorn) | Deepwater |
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| 74 | % |
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| 4,832 |
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| 4,832 |
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| 28,989 |
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| 28,989 |
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Viosca Knoll 823 (Virgo) | Deepwater |
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| 32 | % |
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| 2,231 |
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| 1,420 |
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Main Pass 108 | Shelf |
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| 18 | % |
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| 2,862 |
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| 2,356 |
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| 17,173 |
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| 14,133 |
| Shelf |
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| 19 | % |
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| 3,682 |
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| 2,894 |
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Miss. Canyon 782 (Dantzler) (2) | Deepwater |
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| 73 | % |
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| — |
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| — |
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| — |
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| — |
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Viosca Knoll 823 (Virgo) | Deepwater |
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| 39 | % |
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| 2,094 |
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| 1,303 |
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| 12,567 |
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| 7,820 |
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East Cameron 321 | Shelf |
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| 96 | % |
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| 1,263 |
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| 931 |
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| 7,580 |
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| 5,583 |
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Main Pass 283 | Shelf |
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| 40 | % |
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| 1,636 |
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| 1,336 |
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| 9,819 |
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| 8,014 |
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Miss. Canyon 698 (Big Bend) | Deepwater |
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| 93 | % |
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| 17,320 |
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| 2,815 |
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Brazos A133 | Shelf |
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| — |
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| 2,081 |
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| 867 |
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Ewing Bank 910 | Deepwater |
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| 68 | % |
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| 4,513 |
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| 2,055 |
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Miss. Canyon 582 (Medusa) | Deepwater |
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| 92 | % |
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| 4,634 |
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| 695 |
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Volume measurements:
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Boe/d – barrel of oil equivalent per day |
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29
Our Fields
On December 31, 2014,2017, we had two fields of major individual significance (which we define as having year-end proved reserves of 15% or more of the Company’s total proved reserves, calculated on an energy equivalent basis). The Spraberry field (Yellow Rose) is located in the Permian Basin in West Texas and: the Ship Shoal 349 field (Mahogany) is located on the conventional shelf in the Gulf of Mexico. Below is a descriptionMexico and the Fairway Field, located in the Mobile Bay area of Alabama, which includes the associated Yellowhammer gas processing plant located onshore in Alabama. Following are descriptions of these fields.
Spraberry Field (Yellow Rose).
The Spraberry field is located in the Permian Basin in West Texas. We acquired a 100% working interest in approximately 21,900 net acres in connection with the acquisition of properties (the ‘Opal Properties”) from Opal Resources LLC and Opal Resources Operating LLC (collectively, “Opal”) in May 2011. In separate transactions, we acquired approximately 9,500 net acres in 2011 and approximately 2,200 net acres in 2013. We are the operator for these properties. The Spraberry field was discovered in 1935 and extends over several counties in West Texas comprising about 1.6 million acres. The field is 150 miles long and 75 miles wide, and it has undergone much change and expansion over the years, both aerially and vertically. The correlative interval is now over 3,500 feet thick and includes the Clearfork, Upper Spraberry, Lower Spraberry, Dean, and Wolfcamp formations. These formations are correlative over the area but are lenticular in nature and vary in thickness, porosity, and permeability even over short distances. The general completion technique includes hydraulic fracturing and installation of sucker rod pumps. During 2014, we drilled 38 wells, which included nine horizontal wells. During 2013, we drilled 32 wells, which included five horizontal wells. During 2012, we drilled 64 wells, which included one horizontal well. Cumulative field production through 2014 is approximately 6.4 MMBoe (38.3 Bcfe) from our wells. In 2015, we plan to drill one horizontal well. Total proved reserves associated with our interest in the Spraberry field were 37.3 MMBoe (223.6 Bcfe) at December 31, 2014, 38.2 MMBoe (229.3 Bcfe) at December 31, 2013 and 31.6 MMBoe (189.8 Bcfe) at December 31, 2012.
The following presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Spraberry field over the past three years.
| Year Ended December 31, |
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| 2014 |
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| 2013 |
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| 2012 |
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Net Sales: |
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Oil (MBbls) |
| 1,000 |
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| 1,075 |
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| 751 |
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NGLs (MBbls) |
| 141 |
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| 170 |
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| 103 |
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Natural gas (MMcf) |
| 614 |
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| 575 |
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| 376 |
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Total oil equivalent (MBoe) |
| 1,244 |
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| 1,341 |
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| 916 |
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Total natural gas equivalents (MMcfe) |
| 7,464 |
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| 8,047 |
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| 5,496 |
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Average daily equivalent sales (Boe/day) |
| 3,408 |
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| 3,674 |
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| 2,503 |
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Average daily equivalent sales (Mcfe/day) |
| 20,450 |
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| 22,046 |
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| 15,016 |
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Average realized sales prices: |
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Oil ($/Bbl) | $ | 85.53 |
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| $ | 93.75 |
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| $ | 88.11 |
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NGLs ($/Bbl) |
| 36.84 |
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| 35.86 |
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| 36.94 |
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Natural gas ($/Mcf) |
| 3.67 |
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| 3.48 |
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| 2.50 |
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Oil equivalent ($/Boe) |
| 74.77 |
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| 81.21 |
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| 77.38 |
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Natural gas equivalent ($/Mcfe) |
| 12.46 |
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| 13.54 |
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| 12.90 |
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Average production costs (1): |
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Oil equivalent ($/Boe) | $ | 17.66 |
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| $ | 17.66 |
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| $ | 18.92 |
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Natural gas equivalent ($/Mcfe) |
| 2.94 |
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| 2.94 |
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| 3.15 |
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30
Ship Shoal 349 Field (Mahogany).
Ship Shoal 349 field is located off the coast of Louisiana, approximately 235 miles southeast of New Orleans, in 375 feet of water.Louisiana. The field area covers Ship Shoal blocks 349 and 359, with a single production platform on Ship Shoal block 349.349 in 375 feet of water. Phillips Petroleum Company discovered the field in 1993. We initially acquired a 25% working interest in the field from BP Amoco in 1999. In 2003, we acquired an additional 34% working interest through a transaction with ConocoPhillips that increased our working interest to approximately 59%, and we became the operator of the field in December 2004. In early 2008, we acquired the remaining working interest from Apache Corporation (“Apache”) and we now own a 100% working interest in this field. Cumulative field production through 20142017 is approximately 37.346.4 MMBoe gross (223.6 Bcfe gross).gross. This field is a sub-salt development with eightnine productive horizons below salt at depths up to 17,00018,000 feet. In 2010, we developed a reservoir simulation model to determine the most optimal future development plan (the “2010 Development Plan”). As a result, in 2011, weof December 31, 2017, 28 wells have been drilled and 23 were successful. Since acquiring an interest and subsequently taking over as operator, we have directly participated in drilling 14 wells with a 100% success rate. During 2017, one well was completed one development well and one exploration well. In 2012, twowhich had been drilled to target depth during 2016. Three additional wells were sidetracked, one well was drilled andduring 2017, two of which were completed and another well was drilledin 2017 with the third expected to target depth. In 2013,be completed in the well reaching target depth in 2012 was completed, one well was drilled and completed and we had one well being drilled. In 2014, the well being drilled in 2013 was completed and we drilled and completed another well. A third well was spud at year end 2014 and, in January 2015, drilling on this well was suspended at an intermediate casing point pending higher crude oil prices.first half of 2018. All of the wells drilled under thea plan developed in 2010 Development Plan have been successful. Total proved reserves associated with our interest in this field were 18.821.6 MMBoe (112.9 Bcfe) at December 31, 2014, 22.92017, 19.8 MMBoe (137.7 Bcfe) at December 31, 20132016 and 22.722.3 MMBoe (136.3 Bcfe) at December 31, 2012.2015.
The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Ship Shoal 349 field over the past three years.
years:
| Year Ended December 31, |
| Year Ended December 31, |
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| 2014 |
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| 2013 |
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| 2012 |
| 2017 |
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| 2016 |
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| 2015 |
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Net Sales: |
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Oil (MBbls) |
| 2,020 |
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| 1,943 |
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| 960 |
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| 1,896 |
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| 1,332 |
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| 2,313 |
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NGLs (MBbls) |
| 104 |
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| 90 |
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| 85 |
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| 163 |
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| 159 |
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| 97 |
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Natural gas (MMcf) |
| 3,433 |
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| 3,328 |
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| 2,108 |
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| 2,853 |
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| 1,871 |
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| 3,764 |
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Total oil equivalent (MBoe) |
| 2,697 |
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| 2,589 |
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| 1,397 |
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| 2,534 |
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| 1,802 |
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| 3,037 |
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Total natural gas equivalents (MMcfe) |
| 16,181 |
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| 15,533 |
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| 8,380 |
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| 15,205 |
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| 10,812 |
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| 18,221 |
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Average daily equivalent sales (Boe/day) |
| 7,388 |
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| 7,093 |
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| 3,816 |
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| 6,943 |
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| 4,924 |
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| 8,320 |
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Average daily equivalent sales (Mcfe/day) |
| 44,330 |
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| 42,556 |
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| 22,896 |
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| 41,656 |
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| 29,543 |
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| 49,922 |
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Average realized sales prices: |
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Oil ($/Bbl) | $ | 87.21 |
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| $ | 98.69 |
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| $ | 102.55 |
| $ | 46.64 |
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| $ | 31.97 |
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| $ | 42.73 |
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NGLs ($/Bbl) |
| 46.46 |
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| 43.24 |
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| 41.74 |
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| 25.42 |
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| 17.88 |
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| 21.27 |
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Natural gas ($/Mcf) |
| 4.40 |
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| 3.72 |
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| 2.78 |
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| 3.16 |
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| 2.38 |
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| 2.86 |
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Oil equivalent ($/Boe) |
| 72.73 |
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| 80.39 |
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| 77.24 |
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| 40.08 |
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| 27.67 |
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| 36.77 |
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Natural gas equivalent ($/Mcfe) |
| 12.12 |
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| 13.40 |
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| 12.87 |
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| 6.68 |
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| 4.61 |
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| 6.13 |
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Average production costs (1): |
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Average production costs: (1) |
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Oil equivalent ($/Boe) | $ | 4.12 |
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| $ | 3.68 |
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| $ | 6.27 |
| $ | 4.30 |
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| $ | 5.16 |
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| $ | 3.30 |
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Natural gas equivalent ($/Mcfe) |
| 0.69 |
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| 0.61 |
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| 1.05 |
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| 0.72 |
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| 0.86 |
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| 0.55 |
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(1) | Includes lease operating expenses and gathering and transportation costs. |
Volume measurements: |
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| Mcf – thousand cubic feet | ||
MBbls – thousand barrels for crude oil, condensate or NGLs |
| MMcf – million cubic feet | ||
Boe – barrel of oil equivalent | Mcfe – thousand cubic feet of gas equivalent | |||
MBoe – thousand barrels of oil equivalent |
| MMcfe – million cubic feet of gas equivalent |
31
The following is a description of the remainder of our top 10 properties, measured by proved reserves at December 31, 2014, three of which are located on the conventional shelf and five are located in the deepwater. We do not believe that individually any of these properties are of major significance (each has proved reserves which comprise less than 15% of our year-end total proved reserves, calculated on a natural gas equivalent basis).
Fairway Field.
The Fairway fieldField is comprised of Mobile Bay Area blocks 113 (Alabama State Lease #0531) and 132 (Alabama State Lease #0532) and located in 25 feet of water, approximately 35 miles south of Mobile, Alabama. We acquired our initial 64.3% working interest, along with operatorship, in the Fairway field,Field and associated Yellowhammer gas processing plant, from Shell Offshore, Inc. (“Shell”) in August 2011 and acquired the remaining working interest of 35.7% in September 2014. Cumulative field production through 2017 is approximately 131.8 MMBoe gross. 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, 2014,2017, 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. Total proved reserves associated with our interest in this field were 13.2 MMBoe at December 31, 2017, 13.7 MMBoe at December 31, 2016 and 14.0 MMBoe at December 31, 2015.
The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Fairway field over the past three years:
| Year Ended December 31, |
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| 2017 |
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| 2016 |
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| 2015 |
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Net Sales: |
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Oil (MBbls) |
| 10 |
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| 9 |
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| 10 |
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NGLs (MBbls) |
| 362 |
|
|
| 400 |
|
|
| 319 |
|
Natural gas (MMcf) |
| 6,270 |
|
|
| 7,817 |
|
|
| 8,277 |
|
Total oil equivalent (MBoe) |
| 1,417 |
|
|
| 1,712 |
|
|
| 1,708 |
|
Total natural gas equivalents (MMcfe) |
| 8,501 |
|
|
| 10,272 |
|
|
| 10,250 |
|
Average daily equivalent sales (Boe/day) |
| 3,882 |
|
|
| 4,678 |
|
|
| 4,680 |
|
Average daily equivalent sales (Mcfe/day) |
| 23,292 |
|
|
| 28,065 |
|
|
| 28,083 |
|
Average realized sales prices: |
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl) | $ | 47.65 |
|
| $ | 41.15 |
|
| $ | 47.22 |
|
NGLs ($/Bbl) |
| 21.13 |
|
|
| 16.72 |
|
|
| 18.97 |
|
Natural gas ($/Mcf) |
| 2.93 |
|
|
| 2.42 |
|
|
| 2.60 |
|
Oil equivalent ($/Boe) |
| 18.68 |
|
|
| 17.32 |
|
|
| 16.40 |
|
Natural gas equivalent ($/Mcfe) |
| 3.11 |
|
|
| 2.89 |
|
|
| 2.73 |
|
Average production costs: (1) |
|
|
|
|
|
|
|
|
|
|
|
Oil equivalent ($/Boe) | $ | 8.46 |
|
| $ | 7.95 |
|
| $ | 8.96 |
|
Natural gas equivalent ($/Mcfe) |
| 1.41 |
|
|
| 1.32 |
|
|
| 1.49 |
|
(1) | Includes lease operating expenses and gathering and transportation costs. |
Volume measurements: | ||||
Bbl – barrel | Mcf – thousand cubic feet | |||
MBbls – thousand barrels for crude oil, condensate or NGLs | MMcf – million cubic feet | |||
Boe – barrel of oil equivalent | Mcfe – thousand cubic feet of gas equivalent | |||
MBoe – thousand barrels of oil equivalent | MMcfe – million cubic feet of gas equivalent |
The following is a description of the remainder of our top 10 properties, measured by proved reserves at December 31, 2017, two of which are located on the conventional shelf and six of which are located in the deepwater. We do not believe that individually any of these properties are of major significance (each has proved reserves which comprise less than 15% of our year-end total proved reserves, calculated on a barrel of oil equivalent basis):
Mississippi Canyon 243 Field (Matterhorn). Mississippi Canyon 243 field is located off the coast of Louisiana, approximately 100 miles southeast of New Orleans, Louisiana in 2,552 feet of water. The field area covers Mississippi Canyon block 243, with a single floating, tension leg production platform. Société Nationale Elf Aquitaine discovered the field in 2002. We acquired a 100% working interest in the field from Total E&P USA Inc. (“Total E&P”) in 2010. Cumulative field production through 2017 is approximately 37.1 MMBoe gross. This field is a supra-salt development with 17 productive horizons, with the maximum depth of 9,850 feet. This field also has a successful secondary recovery project with plans for another secondary recovery project. As of December 31, 2017, 30 wells have been drilled, 13 of which have been successful. Since acquiring 100% working interest in this field, we have drilled three wells with a 100% success rate. During December 2014,2017, production from this field, net to our interest, averaged 47 Bbls775 barrels of crude oil per day, 1,696 Bbls27 barrels of NGLs per day and 25.9 MMcf1,956 Mcf of natural gas per day, for total production of 6,0651,128 Boe per day (36.4 MMcfe per day).day.
Viosca Knoll 783 Field (Viosca Knoll 783 Lease (Tahoe) and Viosca Knoll 784 Lease (SE Tahoe)). The Viosca Knoll 783 field is located off the coast of Louisiana, approximately 140 miles southeast of New Orleans, Louisiana in 1,500 to 1,700 feet of water. The field area covers Viosca Knoll blocks 783 and 784, with subsea tiebacks to two platforms in Main Pass 252. Shell discovered the Tahoe prospect in 1984 and the SE Tahoe prospect in 1996. We acquired a 70% working interest in the Tahoe lease and a 100% working interest in the SE Tahoe lease from Shell in 2010. We are the operator forof these properties. Cumulative field production through 20142017 is approximately 96.3101.5 MMBoe gross (577.6 Bcfe gross).gross. The Tahoe prospect is a supra-salt (above the salt layer) development with two productive horizons at depths ranging to 10,300 feet. The SE Tahoe prospect is also a supra-salt development with one productive horizon at a depth of 9,325 feet. As of December 31, 2014,2017, 16 wells have been drilled at the Tahoe prospect, eight of which have been successful and one successful well has been drilled at the SE Tahoe prospect. During December 2014,2017, production from this field, net to our interest, averaged 212 Bbls113 barrels of crude oil per day, 1,362 Bbls645 barrels of NGLs per day and 18.8 MMcf11,605 Mcf of natural gas per day, for total production of 4,7002,692 Boe per day (28.2 MMcfe per day).day.
Mississippi Canyon 243 Field (Matterhorn). Mississippi Canyon 243 field is located off the coast of Louisiana, approximately 100 miles southeast of New Orleans, in 2,552 feet of water. The field area covers Mississippi Canyon block 243, with a single floating, tension leg production platform on Mississippi Canyon block 243. Société Nationale Elf Aquitaine discovered the field in 2002. We acquired a 100% working interest in the field from Total E&P USA Inc. (“Total E&P”) in 2010. Cumulative field production through 2014 is approximately 31.7 MMBoe gross (190.4 Bcfe gross). This field is a supra-salt development with 17 productive horizons at depths ranging to 9,850 feet. As of December 31, 2014, 30 wells have been drilled, 13 of which have been successful. During 2013, we drilled one well, which began production in 2013, and we drilled another well, that had reached target depth but had not yet been completed. During 2014, the well that had reached target depth in 2013 was completed. During December 2014, production from this field, net to our interest, averaged 1,553 Bbls of oil per day, 463 Bbls of NGLs per day and 12.2 MMcf of natural gas per day, for total production of 4,051 Boe per day (24.3 MMcfe per day).
Main Pass 108 Field. Main Pass 108 field consists of Main Pass blocks 107, 108 and 109. This field is located off the coast of Louisiana approximately 50 miles east of Venice in 50 feet of water. We acquired our working interests in these blocks, which range from 33% to 100%, in a transaction with Kerr-McGee Oil and Gas Corporation and we are the operator for the majority of these properties. The field produces from a number of low relief, predominantly stratigraphically trapped sands. The productive interval ranges in age from Upper Miocene Big A through Middle Miocene Big Hum. As of December 31, 2014, 48 wells have been drilled in this field, 30 of which were successful. Cumulative field production through 2014 is approximately 53.1 MMBoe gross (318.7 Bcfe gross). One new well reached target depth in 2011 and began production in 2012. In addition, one workover was performed in 2012. In 2013, we drilled and completed one well, which began production during 2013. During December 2014, production from this field, net to our interest, averaged 118 Bbls of oil per day, 178 Bbls of NGLs per day and 10.7 MMcf of natural gas per day, for total production of 2,086 Boe per day (12.5 MMcfe per day).
Mississippi Canyon 782 Field (Dantzler) Mississippi Canyon 782 field is located off the coast of Louisiana, approximately 160 miles southeast of New Orleans, in 6,600 feet of water. The field area covers Mississippi Canyon block 782 and 738. We have a 20% working interest, which is operated by Noble Energy. We, along with Noble Energy, discovered the field in 2013. This field is currently under development as a subsea tieback to the Thunderhawk Field approximately 12 miles to the northwest. The field is a three-way closure trapped against a salt wall. There are two pay horizons, the upper Miocene U5 and U6 sands. As of December 31, 2014, two wells have been drilled, of which both have been successful and are targeted for first production in the first quarter of 2016.
32
Viosca Knoll 823 Field (Virgo). Viosca Knoll 823 field is located off the coast of Louisiana, approximately 125 miles southeast of New Orleans, Louisiana in 1,014 feet of water. The field area covers Viosca Knoll blockblocks 823 and Viosca Knoll block 822, with a single fixed leg production platform on Viosca Knoll block 823. Total E&P discovered the field in 1997. We acquired a 64% working interest in the field from Total E&P in 2010 and we are the operator forof this property. Cumulative field production through 20142017 is approximately 21.723.7 MMBoe gross (130.4 Bcfe gross).gross. This field is a supra-salt development with 17 productive horizons at depths ranging to 13,335 feet. As of December 31, 2014,2017, 14 wells have been drilled, 10 of which have been successful. During December 2014,2017, production from this field, net to our interest, averaged 128 Bbls224 barrels of crude oil per day, 145 Bbls129 barrels of NGLs per day and 5.2 MMcf5,368 Mcf of natural gas per day, for total production of 1,1371,248 Boe per day (6.8 MMcfe per day).
East Cameron 321. East Cameron 321 field is located approximately 97 miles off the Louisiana coastline in 225 feet of water. Two production facilities, the “A” and “B” platforms, are located on the block. This field has multiple sands that are productive in faulted, structural traps. These sands are Pleistocene Ang B in age. As of December 31, 2014, 76 wells have been drilled of which 58 have been successful. In 2014 we drilled and completed one well. Cumulative field production through 2014 is approximately 94.6 MMBoe gross (567.3 Bcfe) gross. We own a 100% working interest in the field and are the operator of the field. This field is producing at a restricted rate as a result of a damaged departing gas sales line. During January to October 2014, which was prior to the departing gas sales line damage, production from this field, net to our interest, averaged 890 Bbls of oil per day and 0.2 MMcf of natural gas per day, for total production of 928 Boe per day (5.6 MMcfe per day).day.
Main Pass 283. 108 Field. Main Pass 283108 field consists of Main Pass blocks 284, 279107, 108 and 283 and Viosca Knoll Block 734.109. This field is located off the coast of Louisiana approximately 7550 miles east of Venice, Louisiana in 31550 feet of water. We acquired our working interests in these blocks, in 2003, which range from 50%33% to 100%, in a transaction with ConocoPhillips.Kerr-McGee Oil and Gas Corporation (“Kerr-McGee”) and we are the operator of this field. Cumulative field production through 2017 is approximately 48.6 MMBoe gross. The field produces from a number of low relief, predominantly stratigraphically trapped sands. The productive interval ranges in age from Upper Miocene Big A through Middle Miocene Cristellaria I. Cumulative field production through 2014 is approximately 24.3 MMBoe gross (145.8 Bcfe gross).Big Hum. As of December 31, 2014, 122017, 48 wells have been drilled in this field, 30 of which 10 were successful. Since acquiring an interest this field, we have directly participated in drilling seven wells with a 100% success rate. During December 2014,2017, production from this field, net to our interest, averaged 398 Bbls317 barrels of crude oil per day, 195 Bbls264 barrels of NGLs per day and 3.9 MMcf13,189 Mcf of natural gas per day, for total production of 1,2512,779 Boe per day.
Mississippi Canyon 698 Field (Big Bend). Mississippi Canyon 698 is located approximately 160 miles southeast of New Orleans, Louisiana in 7,221 feet of water. The field area covers portions of Mississippi Canyon blocks 697, 698, and 742. We have a 20% working interest, which is operated by Noble Energy Inc. We, along with Noble Energy Inc., discovered the field in 2012. This field is a subsea tieback to the Thunder Hawk production host facility approximately 18 miles to the northwest. Cumulative field production through 2017 is approximately 12.4 MMBoe gross. The field is a supra-salt development with two productive horizons at depths ranging from 14,660’ to 15,533’ total vertical depth. As of December 31, 2017, one well has been drilled, which was successful, with the well beginning production in the fourth quarter of 2015. During December 2017, production from this field, net to our interest, averaged 2,340 barrels of crude oil per day, (7.5 MMcfe62 barrels of NGLs per day).day and 1,413 Mcf of natural gas per day, for total production of 2,637 Boe per day.
Brazos A-133 Field. Brazos A-133 field is located 85 miles east of Corpus Christi, Texas in 200 feet of water. The field was discovered in 1978 by Cities Service Oil Company with production commencing in the same year. There are five active platforms, three of which are production platforms. Cumulative field production through 2017 is approximately 154.9 MMBoe gross from the Middle Miocene Tex W and Big Hum sections. The bulk of the production is from the Big Hum CM-7 sand, which is a 4-way closure downthrown to the Corsair Fault and bisected by antithetic faults. The top of the CM-7 sand is at a subsea depth of 12,000 feet. Since its discovery, 22 wells have been drilled, 17 of which were successful. We own a 50% working interest, of which 25% was obtained through a transaction with Kerr-McGee in 2006 and an additional 25% was obtained through a transaction with Chevron U.S.A. Inc. in 2015. During December 2017, production from this field, net to our interest, averaged 49 barrels of crude oil per day and 4,426 Mcf of natural gas per day, for total production of 787 Boe per day.
Ewing Bank 910. Ewing Bank 910 is located approximately 68 miles off the Louisiana coast in 560 feet of water. The field area covers Ewing Bank blocks 910 and 954, and South Timbalier blocks 320 and 311. Kerr-McGee discovered the field in 1996. We own a 100% working interest in the main field pays, having acquired a 40% working interest from Kerr-McGee in 2006 and the remaining 60% from Petrobras America Inc. in 2014. Two recently successful deep wells are subject to a 50% working interest with Walter Oil and Gas Corporation. A single production platform is located on Block 910. Cumulative field production through 2017 is approximately 17.6 MMBoe gross. Production occurs from Pliocene and upper Miocene channel/levee sands set up by a combination of stratigraphic and structural traps. Since its discovery, 11 wells have been drilled, nine of which were successful. Since acquiring an interest in this field, we have directly participated in drilling three wells with 100% success rate. During December 2017, production from this field, net to our interest, averaged 1,069 barrels of crude oil per day, 225 barrels of NGLs per day and 3,543 Mcf of natural gas per day, for total production of 1,884 Boe per day.
Mississippi Canyon 582 Field. (Medusa) Mississippi Canyon 582 field is located off the coast of Louisiana, approximately 110 miles south-southeast of New Orleans in 2,200 feet of water. The field area covers Mississippi Canyon blocks 538, 582 and 583. Murphy Oil Corporation discovered the field in 1999 and is the operator. First production commenced in 2003. We acquired a 15% working interest in the field from Callon Petroleum Operating Company in 2013. The Medusa Spar facility is located on Block 582. Cumulative field production through 2017 is approximately 82.0 MMBoe gross. Production occurs from late Miocene to early Pliocene deep water, channel/levee sand reservoirs. Hydrocarbon traps are a combination of both structural and stratigraphic traps. Since its discovery, 15 wells have been drilled, 11 of which were successful. Additional drilling opportunities have been identified and are currently being evaluated. During December 2017, production from this field, net to our interest, averaged 565 barrels of crude oil per day, 4 barrels of NGLs per day and 1,593 Mcf of natural gas per day, for total production of 835 Boe per day.
Our proved reserves were estimated by NSAI, our independent petroleum consultant, and amounts provided in this Annual Report on Form 10-K are consistent with filings we make with other federal agencies. Our proved reserves as of December 31, 20142017 are summarized below and the mix by product was 52%46% oil, 13%11% NGLs and 35%43% natural gas determined using the energy-equivalent ratio noted below.below:
|
|
|
|
|
|
|
|
|
|
|
|
| Total Energy-Equivalent Reserves (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Energy-Equivalent Reserves (2) |
|
|
|
|
| ||||||||||||||||||
Classification of Proved Reserves (1) | Oil (MMBbls) |
|
| NGLs (MMBbls) |
|
| Natural Gas (Bcf) |
|
| Oil Equivalent (MMBoe) |
|
| Natural Gas Equivalent (Bcfe) |
|
| % of Total Proved |
|
| PV-10 (3) (In millions) |
| Oil (MMBbls) |
|
| NGLs (MMBbls) |
|
| Natural Gas (Bcf) |
|
| Oil Equivalent (MMBoe) |
|
| Natural Gas Equivalent (Bcfe) |
|
| % of Total Proved |
|
| PV-10 (3) (In millions) |
| ||||||||||||||
Proved developed producing |
| 29.8 |
|
|
| 9.2 |
|
|
| 177.7 |
|
|
| 68.7 |
|
|
| 412.2 |
|
|
| 57 | % |
| $ | 1,903 |
|
| 22.4 |
|
|
| 6.6 |
|
|
| 153.1 |
|
|
| 54.5 |
|
|
| 326.9 |
|
|
| 74 | % |
| $ | 716.8 |
|
Proved developed non-producing |
| 5.9 |
|
|
| 1.5 |
|
|
| 43.4 |
|
|
| 14.6 |
|
|
| 87.5 |
|
|
| 12 | % |
|
| 304 |
|
| 3.7 |
|
|
| 0.6 |
|
|
| 20.4 |
|
|
| 7.7 |
|
|
| 46.4 |
|
|
| 10 | % |
|
| 87.8 |
|
Total proved developed |
| 35.7 |
|
|
| 10.7 |
|
|
| 221.1 |
|
|
| 83.3 |
|
|
| 499.7 |
|
|
| 69 | % |
|
| 2,207 |
|
| 26.1 |
|
|
| 7.2 |
|
|
| 173.5 |
|
|
| 62.2 |
|
|
| 373.3 |
|
|
| 84 | % |
|
| 804.6 |
|
Proved undeveloped |
| 26.0 |
|
|
| 5.1 |
|
|
| 33.8 |
|
|
| 36.7 |
|
|
| 220.3 |
|
|
| 31 | % |
|
| 398 |
|
| 8.3 |
|
|
| 0.6 |
|
|
| 18.7 |
|
|
| 12.0 |
|
|
| 72.0 |
|
|
| 16 | % |
|
| 188.3 |
|
Total proved |
| 61.7 |
|
|
| 15.8 |
|
|
| 254.9 |
|
|
| 120.0 |
|
|
| 720.0 |
|
|
| 100 | % |
| $ | 2,605 |
|
| 34.4 |
|
|
| 7.8 |
|
|
| 192.2 |
|
|
| 74.2 |
|
|
| 445.3 |
|
|
| 100 | % |
| $ | 992.9 |
|
Volume measurements: |
|
|
MMBbls – million barrels for crude oil, condensate or NGLs |
| Bcf – billion cubic feet |
|
| Bcfe – billion cubic feet of gas equivalent |
(1) | In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, |
33
(2) | Energy equivalents are determined using the energy-equivalent ratio of six Mcf of natural gas to one |
The reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves is as follows (in millions):
| As of December 31, 2014 |
| December 31, 2017 |
| ||
Present value of estimated future net revenues (PV-10) | $ | 2,605 |
| $ | 992.9 |
|
Present value of estimated ARO, discounted at 10% |
| (301 | ) |
| (192.2 | ) |
PV-10 after ARO |
| 2,304 |
|
| 800.7 |
|
Future income taxes, discounted at 10% |
| (601 | ) |
| (60.1 | ) |
Standardized measure of discounted future net cash flows | $ | 1,703 |
| $ | 740.6 |
|
Changes in Proved Reserves
Our total proved reserves increased more than production, resulting in a net increase, andat December 31, 2017 were 120.074.2 MMBoe compared to 74.0 MMBoe at December 31, 2014 compared to 117.7 MMBoe at December 31, 2013. The change between periods is a result2016, representing an overall increase of extensions and discoveries of 9.7 MMBoe, acquisitions of 6.1 MMBoe and positive net revisions of 4.1 MMBoe, partially offset by 17.60.2 MMBoe. After accounting for 14.6 MMBoe of production.2017 production, total revisions were a positive 14.8 MMBoe. Increases forfrom extensions and discoveries were primarily at Mississippi Canyon 782 (Dantzler) related to two wells5.2 MMBoe, positive technical revisions (including increased well performance) were 6.2 MMBoe and the Spraberry field related to 51 wells. Increases from acquisitions were primarilyincreases due to acquiring interests in the Woodside Propertieshigher commodity prices were estimated to be 3.4 MMBoe. Due to successful drilling 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. recompletion projects, our proved developed producing reserves increased from 47.3 MMBoe as of December 31, 2016 to 54.5 MMBoe as of December 31, 2017, after accounting for 2017 production.
See Development of Proved Undeveloped ReserReservesves below for a table reconciling the change in proved undeveloped reserves during 2014.2017. See Financial Statements and Supplementary Data– Note 21 – Supplemental Oil and Gas Disclosuresunder Part II, Item 8 in this Form 10-K for additional information.
Our estimates of proved reserves, PV-10 and the standardized measure as of December 31, 20142017 are calculated based upon SEC mandated 20142017 unweighted average first-day-of-the-month crude oil and natural gas benchmark prices, and adjusting for quality, transportation fees, energy content and regional price differentials, which are substantially abovemay or may not represent current prices. If 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 infall below 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,2017 levels, absent significant proved reserve additions, willthis may reduce future estimated proved reserve volumes due to lower economic limits and economic return thresholds for undeveloped reserves, as well as impact our results of operations, cash flows, quarterly full cost impairment ceiling tests and volume-dependent depletion cost calculations. See Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 in this Form 10-K for additional information.
34
Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process
Our estimated proved reserve information as of December 31, 20142017 included in this Form 10-K was prepared by our independent petroleum consultants, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The scope and results of their procedures are summarized in a letter included as an exhibit to this Form 10-K. The primary technical person at NSAI responsible for overseeing the preparation of the reserves estimates presented herein has B.S. and M.S. degrees in Civil Engineeringbeen practicing consulting petroleum engineering at NSAI since 2013 and has been a Registered Professional Engineer in the State of Texas for 26 years and a member of the Society of Petroleum Engineers for over 30 years. He has over 37 years total experience in the oil and gas industry, with over 2314 years of reservoir engineeringprior industry experience. His areas of experience are the continental shelf and deepwater Gulf of Mexico, San Juan Basin, onshore and offshore Mexico, offshore Africa, and unconventional gas sources worldwide. NSAI has informed us that he meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in the application of industry standard practices to engineering evaluations as well as the application of SEC and other industry definitions and guidelines.
We maintain an internal staff of reservoir engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of the data, methods and assumptions used in the preparation of the reserves estimates. Additionally, our senior management reviews any significant changes to our proved reserves on a quarterly basis. Our Director of Reservoir Engineering Director has served in that capacity since 2013, as Reservoir Engineering Manager since 2006,over 28 years of oil and as Staff Reservoir Engineer upon joininggas industry experience and has managed the preparation of public company reserve estimates the last 14 years. He joined the Company in 2004. Prior to joiningmid-2016 after spending the Company, hepreceding 12 years as Director of Corporate Engineering for Freeport-McMoRan Oil & Gas. He has also served as a Reservoir Engineer at Shell, then VP of Reservoir Engineering at Freeport-McMoRanin various engineering and strategic planning roles with both Kerr-McGee Oil & Gas and later as Manager Acquisitions Engineering at Matrix Oil & Gas.with Conoco, Inc. He receivedearned a Bachelor of Science degree in Petroleum Engineering Science from Iowa StateTexas A&M University in 1972.1989 and a Master’s degree in Business Administration from the University of Houston in 1999.
Reserve Technologies
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our independent petroleum consultant employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:
|
|
the quality and quantity of available data and the engineering and geological interpretation of that data;
|
|
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 crude oil, NGLs 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. We convert Bblbarrels to Mcfe using an energy-equivalent ratio of six Mcf to one Bblbarrel of oil, condensate or NGLs. This energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ substantially.
35
Development of Proved Undeveloped Reserves
Our proved undeveloped reserves (“PUDs”) were estimated by NSAI, our independent petroleum consultant. Future development costs associated with our PUDs at December 31, 20142017 were estimated at $865.8$119.5 million.
The following table presents our PUDs by field (in MMBoe):
| As of December 31, |
| December 31, |
| ||||||||||||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| 2017 |
|
| 2016 |
|
| 2015 |
| ||||||
Ship Shoal 349 (Mahogany) |
| 2.1 |
|
|
| 1.3 |
|
|
| 4.8 |
|
| 5.8 |
|
|
| 4.5 |
|
|
| 4.0 |
|
Mississippi Canyon 243 (Matterhorn) |
| 1.4 |
|
|
| 1.3 |
|
|
| 2.1 |
|
| 1.8 |
|
|
| 2.2 |
|
|
| 2.0 |
|
Viosca Knoll 823 (Virgo) |
| 2.0 |
|
|
| 1.4 |
|
|
| 1.4 |
|
| 2.4 |
|
|
| 2.1 |
|
|
| — |
|
Spraberry (Yellow Rose) |
| 24.9 |
|
|
| 25.7 |
|
|
| 19.6 |
| |||||||||||
Ewing Bank 910 |
| 0.5 |
|
|
| 0.5 |
|
|
| 0.5 |
| |||||||||||
Mississippi Canyon 698 (Big Bend) |
| 1.9 |
|
|
| 1.9 |
|
|
| — |
|
| — |
|
|
| — |
|
|
| 0.9 |
|
Mississippi Canyon 538/582 (Medusa) |
| 0.3 |
|
|
| — |
|
|
| — |
| |||||||||||
Mississippi Canyon 782 (Dantzler) (1) |
| 4.1 |
|
|
| — |
|
|
| — |
| |||||||||||
High Island 21/22 |
| — |
|
|
| — |
|
|
| 2.7 |
| |||||||||||
Main Pass 286 |
| 1.5 |
|
|
| — |
|
|
| — |
| |||||||||||
Total |
| 36.7 |
|
|
| 31.6 |
|
|
| 30.6 |
|
| 12.0 |
|
|
| 9.3 |
|
|
| 7.4 |
|
|
|
The following table presents a reconciliation of our PUDs (in MMBoe):
| 2014 |
|
| 2013 |
|
| 2012 |
| |||
Proved undeveloped reserves, beginning of year |
| 31.6 |
|
|
| 30.6 |
|
|
| 40.5 |
|
Reductions: |
|
|
|
|
|
|
|
|
|
|
|
Ship Shoal 349 (Mahogany) |
| — |
|
|
| (4.8 | ) |
|
| (11.8 | ) |
Mississippi Canyon 243 (Matterhorn) |
| — |
|
|
| (0.7 | ) |
|
| (1.6 | ) |
Spraberry (Yellow Rose) drilling, completions and technical |
| (2.3 | ) |
|
| (4.6 | ) |
|
| (9.7 | ) |
Spraberry (Yellow Rose) well performance and viability |
| (2.4 | ) |
|
| (1.5 | ) |
|
| (0.2 | ) |
High Island 21/22 |
| — |
|
|
| (2.7 | ) |
|
| — |
|
Subtotal - reductions |
| (4.7 | ) |
|
| (14.3 | ) |
|
| (23.3 | ) |
Balance after reductions |
| 26.9 |
|
|
| 16.3 |
|
|
| 17.2 |
|
Additions: |
|
|
|
|
|
|
|
|
|
|
|
Ship Shoal 349 (Mahogany) |
| 0.8 |
|
|
| 1.3 |
|
|
| — |
|
Viosca Knoll 823 (Virgo) |
| 0.6 |
|
|
| — |
|
|
| — |
|
Spraberry (Yellow Rose) well additions and other |
| 3.9 |
|
|
| 7.9 |
|
|
| 10.0 |
|
Spraberry (Yellow Rose) 40 acre down-spacing in 2013 |
| — |
|
|
| 4.2 |
|
|
| — |
|
Mississippi Canyon 698 (Big Bend) (2) |
| — |
|
|
| 1.9 |
|
|
| — |
|
Mississippi Canyon 782 (Dantzler) (2) |
| 4.1 |
|
|
| — |
|
|
| — |
|
High Island 21/22 |
| — |
|
|
| — |
|
|
| 2.7 |
|
Other changes |
| 0.4 |
|
|
| — |
|
|
| 0.7 |
|
Subtotal - additions |
| 9.8 |
|
|
| 15.3 |
|
|
| 13.4 |
|
Proved undeveloped reserves, end of year |
| 36.7 |
|
|
| 31.6 |
|
|
| 30.6 |
|
| |
|
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Proved undeveloped reserves, beginning of year |
| 9.3 |
|
|
| 7.4 |
|
|
| 36.7 |
|
Reductions: |
|
|
|
|
|
|
|
|
|
|
|
Ship Shoal 349 (Mahogany) |
| (2.3 | ) |
|
| (1.9 | ) |
|
| — |
|
Mississippi Canyon 243 (Matterhorn) |
| (0.4 | ) |
|
| — |
|
|
| (0.2 | ) |
Viosca Knoll 823 (Virgo) |
| — |
|
|
| — |
|
|
| (2.0 | ) |
Mississippi Canyon 698 (Big Bend) |
| — |
|
|
| (0.9 | ) |
|
| (1.0 | ) |
Mississippi Canyon 582 (Medusa) |
| — |
|
|
| — |
|
|
| (0.3 | ) |
Mississippi Canyon 782 (Dantzler) |
| — |
|
|
| — |
|
|
| (4.1 | ) |
Spraberry (Yellow Rose) |
| — |
|
|
| — |
|
|
| (24.9 | ) |
Subtotal - reductions |
| (2.7 | ) |
|
| (2.8 | ) |
|
| (32.5 | ) |
Balance after reductions |
| 6.6 |
|
|
| 4.6 |
|
|
| 4.2 |
|
Additions: |
|
|
|
|
|
|
|
|
|
|
|
Ship Shoal 349 (Mahogany) |
| 3.6 |
|
|
| 2.4 |
|
|
| 2.0 |
|
Mississippi Canyon 243 (Matterhorn) |
| — |
|
|
| 0.2 |
|
|
| 0.7 |
|
Viosca Knoll 823 (Virgo) |
| 0.3 |
|
|
| 2.1 |
|
|
| — |
|
Ewing Bank 910 |
| — |
|
|
| — |
|
|
| 0.5 |
|
Main Pass 286 |
| 1.5 |
|
|
| — |
|
|
| — |
|
Subtotal - additions |
| 5.4 |
|
|
| 4.7 |
|
|
| 3.2 |
|
Proved undeveloped reserves, end of year |
| 12.0 |
|
|
| 9.3 |
|
|
| 7.4 |
|
Activity related to PUDs in 2017:
36During 2017, we drilled and converted one PUD location described below, which resulted in 2.3 MMBoe reclassified from PUDs to proved developed reserves (“PDs”). Approximately $17.8 million of capital expenditures were incurred in 2017 related to developing this one PUD location to PD and related to activities in progress at December 31, 2017 to develop another PUD location to PD if drilling results are successful. This development activity in 2017 resulted in reclassification of approximately 25% of the PUDs existing at December 31, 2016 to proved developed status measured on a Boe basis.
At our Ship Shoal 349 field (Mahogany), we converted one PUD location to PD with the successful drilling and completion of the A-8 BP1 well. Subsequent exploration drilling in the field resulted in the addition of one new extension PUD location that is expected to be completed in the first half of 2018.
Successful exploratory drilling in Main Pass block 286 resulted in the addition of one PUD location in a new field. Development planning is ongoing with plans to complete the well in late 2018 or early 2019.
At our Viosca Knoll 823 field (Virgo), a rig has been mobilized to the platform during the first quarter of 2018 and drilling is expected to commence during the first half of 2018.
Activity related to PUDs in 2014:2016:
|
|
During 2016, we drilled and converted one PUD location and 1.9 MMBoe to PDs. Approximately $25.7 million of capital expenditures were incurred related to developing this PUD location to PD. Development activity in 2016 resulted in reclassification of approximately 26% of the PUDs existing at December 31, 2015 to proved developed status.
At our Ship Shoal 349 field (Mahogany), PUD reserves were added due to drilling the A-18 well to target depth and beginning completion activities. Although the A-18 well was not completed by year-end 2016, the data available from the drilling activity and initial completion activities led to the conversion of the A-18 well from PUD to PD and resulted in the recognition of one additional offsetting PUD location.
At our Viosca Knoll 823 field (Virgo), PUDs were added as two locations were reclassified from probable to PUD, which we plan on drilling in 2018.
At our Mississippi Canyon 243 field (Matterhorn), reserves associated with existing PUD locations were added due to performance evaluations of adjacent PDs and economic field life extension resulting from ongoing success in managing and reducing lease operating expenses.
At our Mississippi Canyon 698 field (Big Bend), updated field performance data demonstrated that all proved reserves could be recovered from the producing SS1 well and that an additional take point previously classified as a PUD was unnecessary. These proved reserve volumes were reclassified from PUD to PDP and the associated future development capital was eliminated.
Activity related to PUDs in 2015:
During 2015, we completed five offshore wells which affected the conversion of PUDs to PDs and affected additional PUDs to be recognized. Three of the five wells were drilled prior to 2015. Approximately $141.0 million of capital expenditures was incurred related to these five wells during 2015. Activity, divestitures and development assessments in 2015 resulted in reclassification of approximately 88% of the PUDs existing at December 31, 2014.
At our Spraberry field (Yellow Rose), our interests were divested and we were assigned an ORRI.
At our Mississippi Canyon 698 field (Big Bend), we completed one well which moved PUDs to PDs.
At our Viosca Knoll 823 field (Virgo), one well was removed from PUDs as the development timing was beyond the five year limitation and another well was removed from PUDs as it was determined to be uneconomic.
At our Mississippi Canyon 782 field (Dantzler), we completed two wells which moved PUDs into PDs.
|
|
|
|
|
|
ActivityAt our Mississippi Canyon 243 field (Matterhorn), PUDs were added due to the assessment related to PUDs in 2013:two wells.
|
|
|
|
|
|
|
|
|
|
|
|
37
Activity related to PUDs in 2012:
|
|
|
|
|
|
|
|
|
|
See Business under Part I, Item 1, Our Fields in Item 2 above and Financial Statements and Supplementary Data – Note 2 – Acquisitions and Divestitures7 –Divestitures under Part II, Item 8 in this Form 10-K for additional information.
We believe that we will be able to develop all but 1.41.8 MMBoe of the reserves classified as PUDs, or approximately 96%, out(approximately 15%) of the total of 36.712.0 MMBoe classified as PUDs at December 31, 2014,2017, within five years from the date such reserves were initially recorded. The exception islone exceptions are 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 recordedTwo sidetrack PUD locations in our reserves as of December 31, 2010. The development of the 1.4 MMBoe of PUDsthis field will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, a well isthese PUD locations are expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDsdeveloped in 2020.2023.
Our capital expenditure budget for 20152018 is $130 million, which excludes potential acquisitions, and has over 50% allocated for development is approximately $120 million. The capital allocateddevelopment. Four of the eight wells that comprised our PUD locations as of December 31, 2017 are scheduled to our development activities will assist usbe developed in converting the PUDs to PDPs. A recovery in crude oil prices could lead to an increase in development expenditures.2018.
38
Acreage
The following table summarizes our leasehold at December 31, 2014.2017. Deepwater refers to acreage in over 500 feet of water.
water:
| Developed Acreage |
|
| Undeveloped Acreage |
|
| Total Acreage |
| Developed Acreage |
|
| Undeveloped Acreage |
|
| Total Acreage |
| ||||||||||||||||||||||||||||||
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||||||||
Shelf |
| 507,102 |
|
|
| 331,450 |
|
|
| 77,985 |
|
|
| 77,985 |
|
|
| 585,087 |
|
|
| 409,435 |
|
| 414,178 |
|
|
| 235,345 |
|
|
| 53,604 |
|
|
| 38,536 |
|
|
| 467,782 |
|
|
| 273,881 |
|
Deepwater |
| 179,331 |
|
|
| 76,434 |
|
|
| 359,746 |
|
|
| 212,603 |
|
|
| 539,077 |
|
|
| 289,037 |
|
| 147,689 |
|
|
| 61,219 |
|
|
| 87,715 |
|
|
| 36,560 |
|
|
| 235,404 |
|
|
| 97,779 |
|
Total Offshore |
| 686,433 |
|
|
| 407,884 |
|
|
| 437,731 |
|
|
| 290,588 |
|
|
| 1,124,164 |
|
|
| 698,472 |
| |||||||||||||||||||||||
Onshore |
| 30,228 |
|
|
| 25,952 |
|
|
| 24,500 |
|
|
| 15,749 |
|
|
| 54,728 |
|
|
| 41,701 |
| |||||||||||||||||||||||
Total |
| 716,661 |
|
|
| 433,836 |
|
|
| 462,231 |
|
|
| 306,337 |
|
|
| 1,178,892 |
|
|
| 740,173 |
|
| 561,867 |
|
|
| 296,564 |
|
|
| 141,319 |
|
|
| 75,096 |
|
|
| 703,186 |
|
|
| 371,660 |
|
Approximately 58%80% of our total net offshore acreage is developed and approximately 62% of our total net onshore acreage is developed. Within the onshore net acreage, the Spraberry field (Yellow Rose) is approximately 90% developed and all the other onshore prospects combined are approximately 17% developed.held by production. We have the right to propose future exploration and development projects on the majority of our acreage.
ForRegarding the offshore undeveloped leasehold, 59,49821,870 net acres (20%(29%) of the total 290,58875,096 net undeveloped offshore acres could expire in 2015, 35,9652018, 27,719 net acres (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%(37%) could expire in 2019, and beyond. For the onshore undeveloped leasehold, 10,61211,912 net acres (67%) of the total 15,749 net undeveloped onshore acres could expire in 2015 and 5,088 net acres (33%(16%) could expire in 2016. Within the onshore net undeveloped acreage, the Spraberry field (Yellow Rose) comprises 2,4862020, 5,760 net acres (8%) could expire in 2021, and the other onshore prospects comprise the remaining 13,2637,835 net acres of the total 15,749 net acres. The expiration of the onshore undeveloped acreage may be extended through the purchase of new leasehold rights or extension of leasehold rights, but these potential arrangements were not contractual rights as of December 31, 2014.(10%) could expire in 2022 and beyond. In making decisions regarding drilling and operations activity for 20152018 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. For the leaseholds that may expire in 2018, a substantial amount is on prospects that would not be economical to develop at current prices, the probability of successful drilling is estimated to be low or were acquired as part of an acquisition with no intent to develop by the acquiring party.
Our net offshore acreage decreased 39,06780,876 net acres (5%(18%) from December 31, 2013 and our net onshore acreage decreased 141,170 net acres (77%) from December 31, 2013. The decrease in our net onshore acreage was primarily2016 due to reassigning acres back to our original assignor at our Star Project in East Texas.sales, lease expirations and relinquishments.
For the years 2014, 20132017, 2016 and 2012,2015, our net daily production averaged 48.3 MBoe, 49.3 MBoe39,921 Boe, 41,980 Boe and 46.8 MBoe,46,709 Boe, respectively. Production decreased in 20142017 from 20132016 primarily due to an out of period adjustment of 0.9 MBoe/day recorded in 2013, natural production declines, production deferralspipeline and divestitures,platform outages, and tropical storm activity, partially offset by acquisitions and new production. Production increased in 2013production from 2012 primarily due to acquisitions and increases in the Ship Shoal 349 field attributable to development activities and the out of period adjustment, partially offset by natural production declines and production deferrals.four completed wells, which came on-line during various months throughout 2017. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations under Part II, Item 7 in this Form 10-K for additional information.
39
Production History
The following presents historical information about our produced oil, NGLs and natural gas volumes from all of our producing fields over the past three years.years:
| Year Ended December 31, |
| Year Ended December 31, |
| ||||||||||||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| 2017 |
|
| 2016 |
|
| 2015 |
| ||||||
Net Sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
| 7,176 |
|
|
| 7,018 |
|
|
| 6,033 |
|
| 7,064 |
|
|
| 7,201 |
|
|
| 7,751 |
|
NGLs (MBbls) |
| 2,112 |
|
|
| 2,091 |
|
|
| 2,129 |
|
| 1,381 |
|
|
| 1,542 |
|
|
| 1,604 |
|
Oil and NGLs (MBbls) |
| 9,288 |
|
|
| 9,110 |
|
|
| 8,163 |
|
| 8,445 |
|
|
| 8,743 |
|
|
| 9,355 |
|
Natural gas (MMcf) |
| 50,088 |
|
|
| 53,257 |
|
|
| 53,825 |
|
| 36,754 |
|
|
| 39,731 |
|
|
| 46,163 |
|
Total oil equivalent (MBoe) |
| 17,636 |
|
|
| 17,986 |
|
|
| 17,133 |
|
| 14,571 |
|
|
| 15,365 |
|
|
| 17,049 |
|
Total natural gas equivalents (MMcfe) |
| 105,815 |
|
|
| 107,915 |
|
|
| 102,800 |
|
| 87,428 |
|
|
| 92,188 |
|
|
| 102,294 |
|
Volume measurements: |
|
|
MBbls – thousand barrels for crude oil, condensate or NGLs |
| MMcf – million cubic feet |
MBoe – thousand barrels of oil equivalent |
| MMcfe – million cubic feet equivalent |
Refer to the descriptions of our 10 largest fields reported earlier in this Item 2, Properties, for historical information about our produced volumes from our Spraberry field (Yellow Rose) and Ship Shoal 349/359 field (Mahogany) and the Fairway Field over the past three fiscal years, each of which have proved reserves exceeding 15% of our total proved reserves. Also refer to Selected Financial Data – Historical Reserve and Operating Information under Part II, Item 6 in this Form 10-K for additional historical operating data, including average realized sale prices and production costs.
Productive Wells
The following presents our ownership interest at December 31, 20142017 in our productive oil and natural gas wells. A net well represents our fractional working interest of a gross well in which we own less than all of the working interest.
interest:
Offshore Wells | Oil Wells |
|
| Gas Wells |
|
| Total Wells |
| |||||||||||||||
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||
Operated |
| 86 |
|
|
| 75 |
|
|
| 59 |
|
|
| 46 |
|
|
| 145 |
|
|
| 121 |
|
Non-operated |
| 28 |
|
|
| 8 |
|
|
| 35 |
|
|
| 11 |
|
|
| 63 |
|
|
| 19 |
|
Total offshore wells |
| 114 |
|
|
| 83 |
|
|
| 94 |
|
|
| 57 |
|
|
| 208 |
|
|
| 140 |
|
Onshore Wells | Oil Wells |
|
| Gas Wells |
|
| Total Wells |
| |||||||||||||||
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||
Operated |
| 238 |
|
|
| 237 |
|
|
| 10 |
|
|
| 8 |
|
|
| 248 |
|
|
| 245 |
|
Non-operated |
| 6 |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| 6 |
|
|
| 2 |
|
Total onshore wells |
| 244 |
|
|
| 239 |
|
|
| 10 |
|
|
| 8 |
|
|
| 254 |
|
|
| 247 |
|
Total Productive Wells | Oil Wells (1) |
|
| Gas Wells (1) |
|
| Total Wells |
| ||||||||||||||||||||||||||||||||||||||
Offshore Wells | Oil Wells (1) |
|
| Gas Wells (1) |
|
| Total Wells |
| ||||||||||||||||||||||||||||||||||||||
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||||||||
Operated |
| 324 |
|
|
| 312 |
|
|
| 69 |
|
|
| 54 |
|
|
| 393 |
|
|
| 366 |
|
| 84 |
|
|
| 75 |
|
|
| 60 |
|
|
| 50 |
|
|
| 144 |
|
|
| 125 |
|
Non-operated |
| 34 |
|
|
| 10 |
|
|
| 35 |
|
|
| 11 |
|
|
| 69 |
|
|
| 21 |
|
| 34 |
|
|
| 8 |
|
|
| 28 |
|
|
| 7 |
|
|
| 62 |
|
|
| 15 |
|
Total productive wells |
| 358 |
|
|
| 322 |
|
|
| 104 |
|
|
| 65 |
|
|
| 462 |
|
|
| 387 |
| |||||||||||||||||||||||
Total offshore wells |
| 118 |
|
|
| 83 |
|
|
| 88 |
|
|
| 57 |
|
|
| 206 |
|
|
| 140 |
|
(1) | Includes |
As presented in the tables below, our drilling activity decreasedincreased in 20142017 as compared to 2013 in our onshore operations. In 2014,2016. As the Yellow Rose properties were divested during 2015 and we increased the onshore horizontal drilling activity compared to 2013, which take longer to drill and are more expensive on a per well basis compared to vertical wells. Ourdo not currently have any onshore drilling activity is primarily inactivities, historical data for onshore drilling was excluded from the Spraberry field, which was acquired by acquisition in May 2011, coupled with additional leasehold interests acquired in 2011 and 2013.table below.
40
The tablestable below areis based on the SEC’s criteria of completion or abandonment to determine productive wells drilled.
Development and Exploration Drilling
The following table sets forth information related tosummarizes our development and exploration offshore wells drilledcompleted over the past three years.
years:
| Year Ended December 31, |
| |||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| |||
Gross Wells: |
|
|
|
|
|
|
|
|
|
|
|
Productive: |
|
|
|
|
|
|
|
|
|
|
|
Offshore |
| 1 |
|
|
| 4 |
|
|
| 3 |
|
Onshore |
| 20 |
|
|
| 33 |
|
|
| 53 |
|
Non-productive |
|
|
|
|
|
|
|
|
|
|
|
Offshore |
| — |
|
|
| — |
|
|
| — |
|
Onshore |
| — |
|
|
| — |
|
|
| — |
|
Total development wells - gross |
| 21 |
|
|
| 37 |
|
|
| 56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Wells: |
|
|
|
|
|
|
|
|
|
|
|
Productive: |
|
|
|
|
|
|
|
|
|
|
|
Offshore |
| 1.0 |
|
|
| 4.0 |
|
|
| 3.0 |
|
Onshore |
| 19.3 |
|
|
| 32.9 |
|
|
| 52.8 |
|
Non-productive |
|
|
|
|
|
|
|
|
|
|
|
Offshore |
| — |
|
|
| — |
|
|
| �� |
|
Onshore |
| — |
|
|
| — |
|
|
| — |
|
Total development wells - net |
| 20.3 |
|
|
| 36.9 |
|
|
| 55.8 |
|
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Development Wells Completed: |
|
|
|
|
|
|
|
|
|
|
|
Gross wells |
| 3.0 |
|
|
| — |
|
|
| — |
|
Net wells |
| 3.0 |
|
|
| — |
|
|
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration Wells Completed: |
|
|
|
|
|
|
|
|
|
|
|
Gross wells |
| 1.0 |
|
|
| 1.0 |
|
|
| 5.0 |
|
Net wells |
| 0.8 |
|
|
| 0.5 |
|
|
| 1.2 |
|
Our success rates related to our gross development and exploration wells drilled was 80% in 2017 and 100% in each of the last three years.
Exploration Drilling
The following table sets forth information related to our2016 and 100% in 2015. One 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 wellswell drilled during 2014, 2013 and 2012 were 100%, 89% and 96%, respectively.2017 was non-commercial, of which we had a 39% working interest.
41
Recent Drilling Activity
During January 2017, we completed the A-18 offshore development well at the Ship Shoal 349 field (Mahogany). We also drilled and completed two other wells at Mahogany, one of which began production in April 2017 and the other began production in July 2017. The following table sets forth 2015 drilling activityfourth successful well was at the Ship Shoal 300 field and began production in November 2017.
During the first two months of 2018, we mobilized a rig 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 werethe Viosca Knoll 823 (Virgo) platform and drilled the Viosca Knoll 823 A-10 ST1 well to target depth. The A-17 well at Mahogany and the #1 well at Main Pass 286 have both been drilled to target depth. Completion operations are in progress for the process of drilling and/or completing onA-17 well at Mahogany. The Main Pass 286 #1 well was successful and logged pay as a grossnew field discovery. The Main Pass 286 #1 well basis five offshore exploration wells, six onshore exploration wellshas been cased and five onshoreis waiting for development wells.sanction, which is expected during 2018. First production is expected in early 2019.
Capital Expenditures
The level of our investment in oil and gas properties changes from time to time depending on numerous factors, including the prices of crude oil, NGLs and natural gas,gas; acquisition opportunitiesopportunities; liquidity and financing options; and the results of our exploration and development activities. We have set our 2018 capital expenditure budget at $130 million, which excludes potential acquisitions, and is similar to the level of capital expenditures incurred in 2017. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Expenditures under Part II, Item 7 in this Form 10-K for additional capital expendituresexpenditure information.
Apache Lawsuit. InOn December 15, 2014, Apache Corporation (“Apache”) filed a lawsuit against W&T Offshore, Inc.,the Company alleging that W&T breached the joint operating agreement related to, plugging andamong other things, the abandonment costs forof three deepwater wells in the Mississippi Canyon (“MC”) area of the Gulf of Mexico. A trial court judgment was rendered from the U.S. District Court for the Southern District of Texas on May 31, 2017 directing the Company to pay Apache $43.2 million, plus $6.3 million in prejudgment interest, attorney's fees and costs assessed in the judgment. We contendfiled an appeal of the trial court judgment in the U.S. Court of Appeals for the Fifth Circuit. Prior to filing the appeal, in order to stay execution of the judgment, we deposited $49.5 million with the registry of the court in June 2017.
The dispute relates to Apache's use of drilling rigs instead of a previously contracted intervention vessel for the plugging and abandonment work. We contended that the costs incurredto use the drilling rigs were unnecessary and unreasonable, and that Apache chose to use the rigs without W&T's consent because they otherwise would have been idle at Apache's expense. We believe the use of the rigs was in bad faith, as found by the jury, and that such conduct caused W&T not to comply with the applicable joint operating agreement, particularly since another vessel had been contracted by Apache for the abandonment a year in advance. We had previously paid $24.9 million to Apache as an undisputed amount for the plug and abandonment work.
On October 28, 2016, the jury made the following findings:
1. | W&T failed to comply with the contract by failing to pay its proportionate share of the costs to plug and abandon the MC 674 wells. |
2. | The amount of money to compensate Apache for W&T’s failure to pay its proportionate share of the costs to plug and abandon the MC 674 wells was $43.2 million. |
3. | The $43.2 million referred to in #2 should be offset by $17.0 million. |
4. | Apache acted in bad faith thereby causing W&T to not comply with the contract. |
Appeal with ONRR. In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited the calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which was denied in May 2014. On June 17, 2014, we filed an appeal with the IBLA under the Department of the Interior. On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties. We filed an appeal of the IBLA decision on July 25, 2017 in the U.S. District Court for the Eastern District of Louisiana.
Monetary Sanctions by Government Authorities. (Notices of Proposed Civil Penalty Assessment) We currently have four open civil penalties issued by the BSEE arising from Incidents of Noncompliance (“INCs”), which have not been settled as of the filing of this Form 10-K. The INC’s underlying the civil penalties were issued during 2015, with one re-issued during 2016, and relate to four separate offshore locations with occurrence dates ranging from July 2012 to June 2014. The proposed civil penalties for these INCs total $7.3 million. We have accrued approximately $3.3 million in expenses, which is our best estimate of the final settlement once all appeals have been exhausted. Our position is that the proposed civil penalties are excessive given the specific facts and unreasonable. Apache seeks unspecified actualcircumstances related to these INCs. For 2017 and 2016, we paid $0.2 million and $0.1 million, respectively, related to civil penalties issued by the BSEE.
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. In addition, the BOEM considers all owners of record title and/or operating rights interest court costsin an OCS lease to be jointly and attorneys’ fees. severally liable for the satisfaction of the financial assurance requirements and/or decommissioning obligations that have accrued to such owners. Accordingly, we may be required to satisfy financial assurance requirements or decommissioning obligations of a defaulting owner of record title and/or operating rights interest in an OCS lease in which we are (or in some cases were) an owner of record title and/or operating rights interest in the same OCS lease. We are also subject to federal and state administrative proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federally-owned properties. Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.
See Financial Statements and Supplementary Data - Note 1817 – Contingencies under Part II, Item 8 in this Form 10-K for 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. information on this matters described above.
Monetary Sanctions by Government Authorities. During 2014, we paid a civil penalty assessment from the BSEE for $30,000 and we also paid the United States Coast Guard penalties for insignificant discharges (less than 0.0017 barrels in the aggregate) totaling less than $4,000. In February 2015, the Company received a Notice of Proposed Civil Penalty Assessment from the BSEE affecting the Company’s operated platform A in the East Cameron 321 field in the Gulf of Mexico. The BSEE proposed civil penalties totaled $990,000, which arose from two Incidents of Noncompliance (“INCs”) issued in 2014 during drilling operations. No injuries or spills occurred related to these two issues and the Company is contesting the BSEE proposal.
42
Other Litigation. From time to time, we are party to other litigation or legal and administrative proceedings that we consider to be a part of the ordinary course of our business. Except for the matters noted above, we are not involved in any legal proceedings nor are we party to any pending or threatened claims that could, individually or in the aggregate, reasonably be expected to have a material adverse effect on our consolidated financial condition, cash flow or results of operations.
Executive Officers of the Registrant
The following table lists our executive officers:
Name | Age (1) |
|
| Position | |
Tracy W. Krohn |
|
|
|
|
|
|
| and President | |||
John D. Gibbons |
|
|
|
| Senior Vice President and Chief Financial Officer |
Thomas P. Murphy |
|
|
|
| Senior Vice President and Chief Operations Officer |
Stephen L. Schroeder |
|
|
|
| Senior Vice President and Chief Technical Officer |
|
|
|
|
| Vice President, General Counsel and Secretary |
(1)Ages as of February 23, 2018 |
|
Tracy W. Krohn has served as Chief Executive Officer since he founded the Company in 1983 and as Chairman since 2004. He also served as President of the Company until September 2008.2008 and again since March 2017. During 1996 to 1997, Mr. Krohn was also Chairman and Chief Executive Officer of Aviara Energy Corporation. Prior to founding the Company, from 1982 to 1983, Mr. Krohn was a senior engineer with Taylor Energy, and he began his career as a petroleum engineer and offshore drilling supervisor with Mobil Oil Corporation.
Jamie L. Vazquez joined the Company in 1998 as Manager of Land and in 2003 she was named Vice President of Land. In September 2008, Ms. Vazquez was appointed President of the Company. Prior to joining the Company, Ms. Vazquez was with CNG Producing Company for 17 years, holding positions of increasing responsibility ending as Manager, Land/Business Development Gulf of Mexico.
John D. Gibbons joined the Company in February 2007 as Senior Vice President and Chief Financial Officer. Prior to joining the Company, Mr. Gibbons was Senior Vice President and Chief Financial Officer of Westlake Chemical Corporation from March 2006 to February 2007. Prior to joining Westlake, Mr. Gibbons was with Valero Energy Corporation for 23 years, holding positions of increasing responsibility ending as Executive Vice President and Chief Financial Officer.
Thomas P. Murphy joined the Company in June 2012 as Senior Vice President and Chief Operations Officer. From 2009 to 2012, Mr. Murphy worked at Woodside Energy USA Inc. as Vice President Engineering and Operations. From 2008 to 2009 he worked for PetroQuest Energy, Inc. as Vice President Engineering. From 2000 to 2008, Mr. Murphy worked for Devon Energy Corporation in a variety of positions, including Gulf of Mexico Deep-Water Development Supervisor, New Business Development Supervisor and culminating in his position as Sr. Exploration Advisor.
Stephen L. Schroeder joined the Company in 1998 and served as Production Manager from 1999 until 2005. In 2005, Mr. Schroeder was named Vice President of Production and in July 2006 he was named Senior Vice President and Chief Operating Officer. In June 2012, Mr. Schroeder was named Senior Vice President and Chief Technical Officer. Prior to joining the Company, Mr. Schroeder was with Exxon USA for 12 years holding positions of increasing responsibility, ending with Offshore Division Reservoir Engineer.
Thomas F. GettenShahid A. Ghauri joined the Company in July 2006March 2017 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. GettenGhauri served as a partner with King, LeBlanc & Bland, P.L.L.C.,Jones Walker, a New Orleans, Louisiana law firm since February 2001. From 19962015. Prior to December 2000,that, Mr. GettenGhauri served as Vice President, Secretary andAssistant General Counsel of Forcenergy Inc until its merger into Forest Oil Corporation.BHP Billiton Petroleum and in private practice as a partner working with top tier oil and gas firms for 17 years.
Item 4. Mine Safety Disclosures
Not applicable.
43
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed and principally traded on the NYSE under the symbol “WTI”.“WTI.” The following table sets forth the high and low sales priceprices of our common stock as reported on the NYSE.NYSE:
| High |
|
| Low |
| High |
|
| Low |
| ||||
2014: |
|
|
|
|
|
|
| |||||||
2017: |
|
|
|
|
|
|
| |||||||
First Quarter | $ | 17.33 |
|
| $ | 13.52 |
| $ | 3.39 |
|
| $ | 2.50 |
|
Second Quarter |
| 19.78 |
|
|
| 14.00 |
|
| 2.81 |
|
|
| 1.85 |
|
Third Quarter |
| 16.75 |
|
|
| 10.87 |
|
| 3.69 |
|
|
| 1.81 |
|
Fourth Quarter |
| 11.32 |
|
|
| 5.34 |
|
| 3.68 |
|
|
| 2.60 |
|
2013: |
|
|
|
|
|
|
| |||||||
|
|
|
|
|
|
|
| |||||||
2016: |
|
|
|
|
|
|
| |||||||
First Quarter |
| 18.45 |
|
|
| 14.07 |
| $ | 3.50 |
|
| $ | 1.23 |
|
Second Quarter |
| 15.86 |
|
|
| 10.68 |
|
| 2.74 |
|
|
| 1.93 |
|
Third Quarter |
| 18.16 |
|
|
| 14.23 |
|
| 2.35 |
|
|
| 1.51 |
|
Fourth Quarter |
| 20.43 |
|
|
| 14.77 |
|
| 3.47 |
|
|
| 1.31 |
|
As of March 3, 2015,February 28, 2018, there were 199195 registered holders of our common stock.
Dividends
UnderDuring 2017 and 2016, no dividends were paid as dividend payments have been suspended. Dividends are subject to certain statutory requirements which include positive net equity. Our Board of Directors decides the Credit Agreement, wetiming and amounts of any dividends for the Company. Dividends are allowedsubject to pay annual dividendsperiodic review of up to $60.0 million per year if we are not in default. In addition, the indenture governing our 8.50% Senior Notes due in 2019 (the “8.50% Senior Notes”) contains restrictions onCompany’s performance, which includes the payment of dividends unless we meet certain restricted payments test.current economic environment and applicable debt agreement restrictions. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 and Financial Statements and Supplementary Data – Note 72 – Long-Term Debt under Part II, Item 8 in this Form 10-K for more information regarding covenants related to dividends in our Credit Agreement and the indenture governing the 8.50% Senior Notes.
The following reflects the frequency and amounts of all cash dividends declared during the two most recent fiscal years (in thousands, except per share data):debt agreements.
| Aggregate Dividends on Common Stock |
|
| Dividends per Share of Common Stock |
| ||
2014: |
|
|
|
|
|
|
|
First Quarter | $ | 7,562 |
|
| $ | 0.10 |
|
Second Quarter |
| 7,566 |
|
|
| 0.10 |
|
Third Quarter |
| 7,566 |
|
|
| 0.10 |
|
Fourth Quarter |
| 7,566 |
|
|
| 0.10 |
|
2013: |
|
|
|
|
|
|
|
First Quarter |
| 6,020 |
|
|
| 0.08 |
|
Second Quarter |
| 6,775 |
|
|
| 0.09 |
|
Third Quarter |
| 6,775 |
|
|
| 0.09 |
|
Fourth Quarter (1) |
| 39,276 |
|
|
| 0.52 |
|
|
|
Our Board of Directors decides on the dividend for the Company. Dividends are subject to periodic review of the Company’s performance and the current economic environment and applicable debt agreement restrictions. In light of current market conditions, the Board of Directors has elected to suspend the regular quarterly dividend.
44
The graph below shows the cumulative total shareholder return assuming the investment of $100 in our common stock and the reinvestment of all dividends thereafter. The information contained in the graph below is furnished and not filed, and is not incorporated by reference into any document that incorporates this Annual Report on Form 10-K by reference.
Our peer group is comprised of Apache Corporation, Bill Barrett Corp., Cabot Oil & Gas Corp., Comstock Resources, Inc., Energy XXI (Bermuda) Limited, Forest Oil Corp., Newfield Exploration Co., SM Energy Co., SandRidge Energy, Inc.,and Stone Energy Corp., Three of the companies in our 2016 peer group have been delisted as of December 31, 2017 and Swift Energy Company.
Forest Oil Corp. merged with another company during December 2014. Its shares were includedhave been excluded from the 2017 peer group in the peer group since the transaction did not occur until near the end of 2014.above graph.
Securities Authorized for Issuance Underunder Equity Compensation Plans
The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K. For descriptions of the plans and additional information, see Financial Statements and Supplementary Data – Note 10 –Incentive Compensation Plan and Note 11– Share-Based–Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 in this Form 10-K.
Issuer Purchases of Equity Securities
For the year 2014,2017, we did not purchase any of our equity securities.
The following table sets forth information about restricted stock units (“RSUs”) delivered by employees during the quarter ended December 31, 20142017 to satisfy tax withholding obligations on the vesting of restricted stock units.RSUs:
Period |
| Total Number of Restricted Stock Units Delivered |
|
| Average Price per Restricted Stock Unit |
|
| Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |
| Maximum Number (or Approximate Dollar Value) of Shares that May Yet be Purchased Under the Plans or Programs | ||
October 1, 2014 - October 31, 2014 |
| N/A |
|
| N/A |
|
| N/A |
| N/A | ||
November 1, 2014 - November 30, 2014 |
| N/A |
|
| N/A |
|
| N/A |
| N/A | ||
December 1, 2014 - December 31, 2014 |
|
| 107,173 |
|
| $ | 5.49 |
|
| N/A |
| N/A |
Period |
| Total Number of Restricted Stock Units Delivered |
|
| Average Price per Restricted Stock Unit |
|
| Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |
| Maximum Number (or Approximate Dollar Value) of Shares that May Yet be Purchased Under the Plans or Programs | ||
October 1, 2017 - October 31, 2017 |
| N/A |
|
| N/A |
|
| N/A |
| N/A | ||
November 1, 2017 - November 30, 2017 |
| N/A |
|
| N/A |
|
| N/A |
| N/A | ||
December 1, 2017 - December 31, 2017 |
|
| 505,087 |
|
| $ | 2.60 |
|
| N/A |
| N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
ItemItem 6. Selected Financial Data
SELECTED HISTORICAL FINANCIAL INFORMATION
The selected historical financial information set forth below should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and with Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K.10-K:
| Year Ended December 31, |
| Year Ended December 31, |
| ||||||||||||||||||||||||||||||||||
| 2014(1) |
|
| 2013(2) |
|
| 2012(3) |
|
| 2011(4) |
|
| 2010(5) |
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2013 |
| ||||||||||
| (In thousands, except per share data) |
| (In thousands, except per share data) |
| ||||||||||||||||||||||||||||||||||
Consolidated Statement of Operations Information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil | $ | 652,776 |
|
| $ | 718,944 |
|
| $ | 629,548 |
|
| $ | 643,222 |
|
| $ | 453,435 |
| $ | 340,010 |
|
| $ | 268,950 |
|
| $ | 349,191 |
|
| $ | 652,776 |
|
| $ | 718,944 |
|
NGLs |
| 72,837 |
|
|
| 73,345 |
|
|
| 84,637 |
|
|
| 105,559 |
|
|
| 51,931 |
|
| 32,257 |
|
|
| 26,429 |
|
|
| 27,665 |
|
|
| 72,837 |
|
|
| 73,345 |
|
Natural gas |
| 217,816 |
|
|
| 189,290 |
|
|
| 158,390 |
|
|
| 221,194 |
|
|
| 203,533 |
|
| 108,923 |
|
|
| 100,405 |
|
|
| 123,435 |
|
|
| 217,816 |
|
|
| 189,290 |
|
Other |
| 5,279 |
|
|
| 2,509 |
|
|
| 1,916 |
|
|
| 1,072 |
|
|
| (3,116 | ) |
| 5,906 |
|
|
| 4,202 |
|
|
| 6,974 |
|
|
| 5,279 |
|
|
| 2,509 |
|
Total revenues |
| 948,708 |
|
|
| 984,088 |
|
|
| 874,491 |
|
|
| 971,047 |
|
|
| 705,783 |
|
| 487,096 |
|
|
| 399,986 |
|
|
| 507,265 |
|
|
| 948,708 |
|
|
| 984,088 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
| 264,751 |
|
|
| 270,839 |
|
|
| 232,260 |
|
|
| 219,206 |
|
|
| 169,670 |
|
| 143,738 |
|
|
| 152,399 |
|
|
| 192,765 |
|
|
| 264,751 |
|
|
| 270,839 |
|
Production taxes |
| 7,932 |
|
|
| 7,135 |
|
|
| 5,840 |
|
|
| 4,275 |
|
|
| 1,194 |
|
| 1,740 |
|
|
| 1,889 |
|
|
| 3,002 |
|
|
| 7,932 |
|
|
| 7,135 |
|
Gathering and transportation |
| 19,821 |
|
|
| 17,510 |
|
|
| 14,878 |
|
|
| 16,920 |
|
|
| 16,484 |
|
| 20,441 |
|
|
| 22,928 |
|
|
| 17,157 |
|
|
| 19,821 |
|
|
| 17,510 |
|
Depreciation, depletion and amortization |
| 490,469 |
|
|
| 430,611 |
|
|
| 336,177 |
|
|
| 299,015 |
|
|
| 268,415 |
|
| 138,510 |
|
|
| 194,038 |
|
|
| 373,368 |
|
|
| 490,469 |
|
|
| 430,611 |
|
Asset retirement obligations accretion |
| 20,633 |
|
|
| 20,918 |
|
|
| 20,055 |
|
|
| 29,771 |
|
|
| 25,685 |
|
| 17,172 |
|
|
| 17,571 |
|
|
| 20,703 |
|
|
| 20,633 |
|
|
| 20,918 |
|
Ceiling test write-down of oil and natural gas properties |
| — |
|
|
| 279,063 |
|
|
| 987,238 |
|
|
| — |
|
|
| — |
| |||||||||||||||||||
General and administrative expenses |
| 86,999 |
|
|
| 81,874 |
|
|
| 82,017 |
|
|
| 74,296 |
|
|
| 53,290 |
|
| 59,744 |
|
|
| 59,740 |
|
|
| 73,110 |
|
|
| 86,999 |
|
|
| 81,874 |
|
Derivative (gain) loss |
| (3,965 | ) |
|
| 8,470 |
|
|
| 13,954 |
|
|
| (1,896 | ) |
|
| 4,256 |
|
| (4,199 | ) |
|
| 2,926 |
|
|
| (14,375 | ) |
|
| (3,965 | ) |
|
| 8,470 |
|
Total costs and expenses |
| 886,640 |
|
|
| 837,357 |
|
|
| 705,181 |
|
|
| 641,587 |
|
|
| 538,994 |
|
| 377,146 |
|
|
| 730,554 |
|
|
| 1,652,968 |
|
|
| 886,640 |
|
|
| 837,357 |
|
Operating income |
| 62,068 |
|
|
| 146,731 |
|
|
| 169,310 |
|
|
| 329,460 |
|
|
| 166,789 |
| |||||||||||||||||||
Operating income (loss) |
| 109,950 |
|
|
| (330,568 | ) |
|
| (1,145,703 | ) |
|
| 62,068 |
|
|
| 146,731 |
| |||||||||||||||||||
Interest expense, net of amounts capitalized |
| 78,396 |
|
|
| 75,581 |
|
|
| 49,994 |
|
|
| 42,516 |
|
|
| 37,706 |
|
| 45,836 |
|
|
| 92,271 |
|
|
| 97,336 |
|
|
| 78,396 |
|
|
| 75,581 |
|
Loss on extinguishment of debt (9) |
| — |
|
|
| — |
|
|
| — |
|
|
| 22,694 |
|
|
| — |
| |||||||||||||||||||
Other income, net (10) |
| 208 |
|
|
| 8,946 |
|
|
| 215 |
|
|
| 84 |
|
|
| 710 |
| |||||||||||||||||||
Gain on exchange of debt |
| 7,811 |
|
|
| 123,923 |
|
|
| — |
|
|
| — |
|
|
| — |
| |||||||||||||||||||
Other (income) expense, net |
| 4,812 |
|
|
| (6,520 | ) |
|
| 4,663 |
|
|
| (208 | ) |
|
| (8,946 | ) | |||||||||||||||||||
Income (loss) before income tax expense (benefit) |
| (16,120 | ) |
|
| 80,096 |
|
|
| 119,531 |
|
|
| 264,334 |
|
|
| 129,793 |
|
| 67,113 |
|
|
| (292,396 | ) |
|
| (1,247,702 | ) |
|
| (16,120 | ) |
|
| 80,096 |
|
Income tax expense (benefit) |
| (4,459 | ) |
|
| 28,774 |
|
|
| 47,547 |
|
|
| 91,517 |
|
|
| 11,901 |
|
| (12,569 | ) |
|
| (43,376 | ) |
|
| (202,984 | ) |
|
| (4,459 | ) |
|
| 28,774 |
|
Net income (loss) | $ | (11,661 | ) |
| $ | 51,322 |
|
| $ | 71,984 |
|
| $ | 172,817 |
|
| $ | 117,892 |
| $ | 79,682 |
|
| $ | (249,020 | ) |
| $ | (1,044,718 | ) |
| $ | (11,661 | ) |
| $ | 51,322 |
|
Basic and diluted earnings (loss) per common share | $ | (0.16 | ) |
| $ | 0.68 |
|
| $ | 0.95 |
|
| $ | 2.29 |
|
| $ | 1.58 |
| $ | 0.56 |
|
| $ | (2.60 | ) |
| $ | (13.76 | ) |
| $ | (0.16 | ) |
| $ | 0.68 |
|
Dividends on common stock (11) |
| 30,260 |
|
|
| 58,846 |
|
|
| 82,832 |
|
|
| 58,756 |
|
|
| 59,609 |
| |||||||||||||||||||
Dividends on common stock |
| — |
|
|
| — |
|
|
| — |
|
|
| 30,260 |
|
|
| 58,846 |
| |||||||||||||||||||
Cash dividends per common share |
| 0.40 |
|
|
| 0.78 |
|
|
| 1.11 |
|
|
| 0.79 |
|
|
| 0.80 |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 0.40 |
|
|
| 0.78 |
|
Consolidated Cash Flow Information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash providing by operating activities | $ | 511,423 |
|
| $ | 561,358 |
|
| $ | 385,137 |
|
| $ | 521,478 |
|
| $ | 464,772 |
| $ | 159,408 |
|
| $ | 14,180 |
|
| $ | 133,228 |
|
| $ | 474,821 |
|
| $ | 562,708 |
|
Capital expenditures - oil and natural gas properties |
| 626,612 |
|
|
| 634,378 |
|
|
| 684,863 |
|
|
| 719,026 |
|
|
| 415,653 |
| |||||||||||||||||||
Capital expenditures - oil and natural gas properties (1) |
| 130,048 |
|
|
| 48,606 |
|
|
| 230,161 |
|
|
| 626,612 |
|
|
| 634,378 |
|
| December 31, |
| December 31, |
| ||||||||||||||||||||||||||||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
|
| 2011 |
|
| 2010 |
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2013 |
| ||||||||||
| (In thousands) |
| (In thousands) |
| ||||||||||||||||||||||||||||||||||
Consolidated Balance Sheet Information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents | $ | 23,666 |
|
| $ | 15,800 |
|
| $ | 12,245 |
|
| $ | 4,512 |
|
| $ | 28,655 |
| $ | 99,058 |
|
| $ | 70,236 |
|
| $ | 85,414 |
|
| $ | 23,666 |
|
| $ | 15,800 |
|
Total assets |
| 2,709,107 |
|
|
| 2,507,302 |
|
|
| 2,348,987 |
|
|
| 1,868,925 |
|
|
| 1,424,094 |
|
| 907,580 |
|
|
| 829,726 |
|
|
| 1,208,022 |
|
|
| 2,689,508 |
|
|
| 2,497,180 |
|
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 |
| |||||||||||||||||||
Long-term debt (including current portion) |
| 992,052 |
|
|
| 1,020,727 |
|
|
| 1,196,855 |
|
|
| 1,352,120 |
|
|
| 1,195,883 |
| |||||||||||||||||||
Shareholders' equity (deficit) |
| (573,508 | ) |
|
| (659,037 | ) |
|
| (526,491 | ) |
|
| 509,308 |
|
|
| 540,610 |
|
46
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HISTORICAL RESERVE AND OPERATING INFORMATION
The following presentstables present summary information regarding our estimated net proved oil, NGLs and natural gas reserves and our historical operating data for the years shown below. Estimated net proved reserves are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December of the respective year in accordance with SEC guidelines. For additional information regarding our estimated proved reserves, please read Business under Part I, Item 1 and Properties under Part I, Item 2 of this Form 10-K. The selected historical operating data set forth below should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and with Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K.10-K:
| December 31, |
| December 31, |
| ||||||||||||||||||||||||||||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
|
| 2011 |
|
| 2010 |
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2013 |
| ||||||||||
Reserve Data: (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated net proved reserves |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
| 61.7 |
|
|
| 58.5 |
|
|
| 54.8 |
|
|
| 51.4 |
|
|
| 34.0 |
|
| 34.4 |
|
|
| 32.9 |
|
|
| 35.5 |
|
|
| 61.7 |
|
|
| 58.5 |
|
NGLs (MMBbls) |
| 15.8 |
|
|
| 15.9 |
|
|
| 15.2 |
|
|
| 17.1 |
|
|
| 4.2 |
|
| 7.8 |
|
|
| 8.2 |
|
|
| 6.6 |
|
|
| 15.8 |
|
|
| 15.9 |
|
Natural Gas (Bcf) |
| 254.9 |
|
|
| 259.9 |
|
|
| 285.1 |
|
|
| 289.7 |
|
|
| 256.3 |
|
| 192.2 |
|
|
| 197.8 |
|
|
| 205.4 |
|
|
| 254.9 |
|
|
| 259.9 |
|
Total barrel equivalents (MMBoe) |
| 120.0 |
|
|
| 117.7 |
|
|
| 117.5 |
|
|
| 116.9 |
|
|
| 80.9 |
|
| 74.2 |
|
|
| 74.0 |
|
|
| 76.4 |
|
|
| 120.0 |
|
|
| 117.7 |
|
Total natural gas equivalents (Bcfe) |
| 720.0 |
|
|
| 705.9 |
|
|
| 705.1 |
|
|
| 701.1 |
|
|
| 485.4 |
|
| 445.4 |
|
|
| 444.0 |
|
|
| 458.1 |
|
|
| 720.0 |
|
|
| 705.9 |
|
Proved developed producing (MMBoe) |
| 68.7 |
|
|
| 60.6 |
|
|
| 62.6 |
|
|
| 54.3 |
|
|
| 39.4 |
|
| 54.5 |
|
|
| 47.3 |
|
|
| 57.6 |
|
|
| 68.7 |
|
|
| 60.6 |
|
Proved developed non-producing (MMBoe) |
| 14.6 |
|
|
| 25.5 |
|
|
| 24.3 |
|
|
| 22.1 |
|
|
| 25.8 |
|
| 7.7 |
|
|
| 17.4 |
|
|
| 11.4 |
|
|
| 14.6 |
|
|
| 25.5 |
|
Total proved developed (MMBoe) |
| 83.3 |
|
|
| 86.1 |
|
|
| 86.9 |
|
|
| 76.4 |
|
|
| 65.2 |
|
| 62.2 |
|
|
| 64.7 |
|
|
| 69.0 |
|
|
| 83.3 |
|
|
| 86.1 |
|
Proved undeveloped (MMBoe) |
| 36.7 |
|
|
| 31.6 |
|
|
| 30.6 |
|
|
| 40.5 |
|
|
| 15.7 |
|
| 12.0 |
|
|
| 9.3 |
|
|
| 7.4 |
|
|
| 36.7 |
|
|
| 31.6 |
|
Proved developed reserves as % |
| 69.4 | % |
|
| 73.2 | % |
|
| 74.0 | % |
|
| 65.4 | % |
|
| 80.6 | % |
| 83.8 | % |
|
| 87.4 | % |
|
| 90.3 | % |
|
| 69.4 | % |
|
| 73.2 | % |
Reserve additions (reductions) (MMBoe): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions |
| 4.1 |
|
|
| (3.9 | ) |
|
| (4.7 | ) |
|
| 8.6 |
|
|
| 3.4 |
|
| 9.6 |
|
|
| 13.0 |
|
|
| (12.7 | ) |
|
| 4.1 |
|
|
| (3.9 | ) |
Extensions and discoveries |
| 9.7 |
|
|
| 20.2 |
|
|
| 15.8 |
|
|
| 5.3 |
|
|
| 4.9 |
|
| 5.2 |
|
|
| — |
|
|
| 4.1 |
|
|
| 9.7 |
|
|
| 20.2 |
|
Purchases of minerals in place |
| 6.1 |
|
|
| 2.4 |
|
|
| 7.0 |
|
|
| 39.0 |
|
|
| 25.3 |
|
| — |
|
|
| — |
|
|
| 1.0 |
|
|
| 6.1 |
|
|
| 2.4 |
|
Sales of minerals in place |
| — |
|
|
| (0.5 | ) |
|
| (0.4 | ) |
|
| — |
|
|
| — |
|
| — |
|
|
| — |
|
|
| (19.0 | ) |
|
| — |
|
|
| (0.5 | ) |
Production |
| (17.6 | ) |
|
| (18.0 | ) |
|
| (17.1 | ) |
|
| (16.9 | ) |
|
| (14.5 | ) |
| (14.6 | ) |
|
| (15.4 | ) |
|
| (17.0 | ) |
|
| (17.6 | ) |
|
| (18.0 | ) |
Net reserve additions |
| 2.3 |
|
|
| 0.2 |
|
|
| 0.6 |
|
|
| 36.0 |
|
|
| 19.1 |
| |||||||||||||||||||
Net reserve additions (reductions) |
| 0.2 |
|
|
| (2.4 | ) |
|
| (43.6 | ) |
|
| 2.3 |
|
|
| 0.2 |
|
(1) | The conversions to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one |
(2) |
|
(3) | In 2015, sales of minerals in place related primarily to the sale of the Yellow Rose field. |
Volume measurements: |
|
|
MMBbls – million barrels of crude oil, condensate or NGLs |
| Bcf – billion cubic feet |
MMBoe – million barrels of oil equivalent |
| Bcfe – billion cubic feet of gas equivalent |
| Year Ended December 31, |
| Year Ended December 31, |
| ||||||||||||||||||||||||||||||||||
| 2014 |
|
| 2013(1) |
|
| 2012 |
|
| 2011 |
|
| 2010 |
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2014 |
|
| 2013 |
| ||||||||||
Operating: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
| 7,176 |
|
|
| 7,018 |
|
|
| 6,033 |
|
|
| 6,073 |
|
|
| 5,863 |
|
| 7,064 |
|
|
| 7,201 |
|
|
| 7,751 |
|
|
| 7,176 |
|
|
| 7,018 |
|
NGLs (MBbls) |
| 2,112 |
|
|
| 2,091 |
|
|
| 2,129 |
|
|
| 1,892 |
|
|
| 1,190 |
|
| 1,382 |
|
|
| 1,542 |
|
|
| 1,604 |
|
|
| 2,112 |
|
|
| 2,091 |
|
Oil and NGLs (MBbls) |
| 9,288 |
|
|
| 9,110 |
|
|
| 8,163 |
|
|
| 7,964 |
|
|
| 7,053 |
|
| 8,446 |
|
|
| 8,743 |
|
|
| 9,355 |
|
|
| 9,288 |
|
|
| 9,110 |
|
Natural gas (MMcf) |
| 50,088 |
|
|
| 53,257 |
|
|
| 53,825 |
|
|
| 53,743 |
|
|
| 44,713 |
|
| 36,754 |
|
|
| 39,731 |
|
|
| 46,163 |
|
|
| 50,088 |
|
|
| 53,257 |
|
Total oil equivalent (MBoe) |
| 17,636 |
|
|
| 17,986 |
|
|
| 17,133 |
|
|
| 16,921 |
|
|
| 14,505 |
|
| 14,571 |
|
|
| 15,365 |
|
|
| 17,049 |
|
|
| 17,636 |
|
|
| 17,986 |
|
Total natural gas equivalents (MMcfe) |
| 105,815 |
|
|
| 107,915 |
|
|
| 102,800 |
|
|
| 101,528 |
|
|
| 87,032 |
|
| 87,428 |
|
|
| 92,188 |
|
|
| 102,294 |
|
|
| 105,815 |
|
|
| 107,915 |
|
Average daily equivalent sales (Boe/day) |
| 48,317 |
|
|
| 49,276 |
|
|
| 46,813 |
|
|
| 46,360 |
|
|
| 39,741 |
|
| 39,921 |
|
|
| 41,980 |
|
|
| 46,709 |
|
|
| 48,317 |
|
|
| 49,276 |
|
Average daily equivalent sales (Mcfe/day) |
| 289,904 |
|
|
| 295,657 |
|
|
| 280,875 |
|
|
| 278,158 |
|
|
| 238,445 |
|
| 239,528 |
|
|
| 251,879 |
|
|
| 280,256 |
|
|
| 289,904 |
|
|
| 295,657 |
|
Average realized sales prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl) | $ | 90.96 |
|
| $ | 102.44 |
|
| $ | 104.35 |
|
| $ | 105.92 |
|
| $ | 77.33 |
| $ | 48.13 |
|
| $ | 37.35 |
|
| $ | 45.05 |
|
| $ | 90.96 |
|
| $ | 102.44 |
|
NGLs ($/Bbl) |
| 34.49 |
|
|
| 35.07 |
|
|
| 39.75 |
|
|
| 55.81 |
|
|
| 43.65 |
|
| 23.35 |
|
|
| 17.14 |
|
|
| 17.25 |
|
|
| 34.49 |
|
|
| 35.07 |
|
Oil and NGLs ($/Bbl) |
| 78.13 |
|
|
| 86.97 |
|
|
| 87.50 |
|
|
| 94.02 |
|
|
| 71.65 |
|
| 44.08 |
|
|
| 33.79 |
|
|
| 40.28 |
|
|
| 78.13 |
|
|
| 86.97 |
|
Natural gas ($/Mcf) |
| 4.35 |
|
|
| 3.55 |
|
|
| 2.94 |
|
|
| 4.12 |
|
|
| 4.55 |
|
| 2.96 |
|
|
| 2.53 |
|
|
| 2.67 |
|
|
| 4.35 |
|
|
| 3.55 |
|
Oil equivalent ($/Boe) |
| 53.49 |
|
|
| 54.58 |
|
|
| 50.93 |
|
|
| 57.32 |
|
|
| 48.87 |
|
| 33.02 |
|
|
| 25.76 |
|
|
| 29.34 |
|
|
| 53.49 |
|
|
| 54.58 |
|
Natural gas equivalent ($/Mcfe) |
| 8.92 |
|
|
| 9.10 |
|
|
| 8.49 |
|
|
| 9.55 |
|
|
| 8.15 |
|
| 5.50 |
|
|
| 4.29 |
|
|
| 4.89 |
|
|
| 8.92 |
|
|
| 9.10 |
|
Average per Boe ($/Boe): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses | $ | 15.01 |
|
| $ | 15.06 |
|
| $ | 13.56 |
|
| $ | 12.95 |
|
| $ | 11.70 |
| $ | 9.86 |
|
| $ | 9.92 |
|
| $ | 11.31 |
|
| $ | 15.01 |
|
| $ | 15.06 |
|
Gathering and transportation |
| 1.14 |
|
|
| 0.95 |
|
|
| 0.85 |
|
|
| 1.01 |
|
|
| 1.16 |
|
| 1.40 |
|
|
| 1.49 |
|
|
| 1.01 |
|
|
| 1.14 |
|
|
| 0.95 |
|
Production costs |
| 16.15 |
|
|
| 16.01 |
|
|
| 14.41 |
|
|
| 13.96 |
|
|
| 12.86 |
|
| 11.26 |
|
|
| 11.41 |
|
|
| 12.32 |
|
|
| 16.15 |
|
|
| 16.01 |
|
Production taxes |
| 0.42 |
|
|
| 0.42 |
|
|
| 0.36 |
|
|
| 0.24 |
|
|
| 0.06 |
|
| 0.12 |
|
|
| 0.12 |
|
|
| 0.17 |
|
|
| 0.42 |
|
|
| 0.42 |
|
DD&A |
| 28.98 |
|
|
| 25.10 |
|
|
| 20.79 |
|
|
| 19.43 |
|
|
| 20.28 |
|
| 10.68 |
|
|
| 13.77 |
|
|
| 23.11 |
|
|
| 28.98 |
|
|
| 25.10 |
|
General and administrative expenses |
| 4.93 |
|
|
| 4.55 |
|
|
| 4.79 |
|
|
| 4.39 |
|
|
| 3.67 |
|
| 4.10 |
|
|
| 3.89 |
|
|
| 4.29 |
|
|
| 4.93 |
|
|
| 4.55 |
|
| $ | 50.48 |
|
| $ | 46.08 |
|
| $ | 40.35 |
|
| $ | 38.02 |
|
| $ | 36.87 |
| $ | 26.16 |
|
| $ | 29.19 |
|
| $ | 39.89 |
|
| $ | 50.48 |
|
| $ | 46.08 |
|
Average per Mcfe ($/Mcfe): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses | $ | 2.50 |
|
| $ | 2.51 |
|
| $ | 2.26 |
|
| $ | 2.16 |
|
| $ | 1.95 |
| $ | 1.64 |
|
| $ | 1.65 |
|
| $ | 1.88 |
|
| $ | 2.50 |
|
| $ | 2.51 |
|
Gathering and transportation |
| 0.19 |
|
|
| 0.16 |
|
|
| 0.14 |
|
|
| 0.17 |
|
|
| 0.19 |
|
| 0.23 |
|
|
| 0.25 |
|
|
| 0.17 |
|
|
| 0.19 |
|
|
| 0.16 |
|
Production costs |
| 2.69 |
|
|
| 2.67 |
|
|
| 2.40 |
|
|
| 2.33 |
|
|
| 2.14 |
|
| 1.87 |
|
|
| 1.90 |
|
|
| 2.05 |
|
|
| 2.69 |
|
|
| 2.67 |
|
Production taxes |
| 0.07 |
|
|
| 0.07 |
|
|
| 0.06 |
|
|
| 0.04 |
|
|
| 0.01 |
|
| 0.02 |
|
|
| 0.02 |
|
|
| 0.03 |
|
|
| 0.07 |
|
|
| 0.07 |
|
DD&A |
| 4.83 |
|
|
| 4.18 |
|
|
| 3.47 |
|
|
| 3.24 |
|
|
| 3.38 |
|
| 1.78 |
|
|
| 2.30 |
|
|
| 3.85 |
|
|
| 4.83 |
|
|
| 4.18 |
|
General and administrative expenses |
| 0.82 |
|
|
| 0.76 |
|
|
| 0.80 |
|
|
| 0.73 |
|
|
| 0.61 |
|
| 0.68 |
|
|
| 0.65 |
|
|
| 0.71 |
|
|
| 0.82 |
|
|
| 0.76 |
|
| $ | 8.41 |
|
| $ | 7.68 |
|
| $ | 6.73 |
|
| $ | 6.34 |
|
| $ | 6.14 |
| $ | 4.35 |
|
| $ | 4.87 |
|
| $ | 6.64 |
|
| $ | 8.41 |
|
| $ | 7.68 |
|
Wells drilled (gross): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Offshore |
| 6 |
|
|
| 6 |
|
|
| 5 |
|
|
| 8 |
|
|
| 7 |
|
| 5 |
|
|
| 1 |
|
|
| 5 |
|
|
| 6 |
|
|
| 6 |
|
Onshore |
| 33 |
|
|
| 40 |
|
|
| 77 |
|
|
| 40 |
|
|
| 2 |
|
| — |
|
|
| — |
|
|
| 5 |
|
|
| 33 |
|
|
| 40 |
|
Productive wells drilled (gross) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Productive wells drilled (gross): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Offshore |
| 6 |
|
|
| 5 |
|
|
| 4 |
|
|
| 8 |
|
|
| 6 |
|
| 4 |
|
|
| 1 |
|
|
| 5 |
|
|
| 6 |
|
|
| 5 |
|
Onshore |
| 33 |
|
|
| 40 |
|
|
| 77 |
|
|
| 39 |
|
|
| — |
|
| — |
|
|
| — |
|
|
| 5 |
|
|
| 33 |
|
|
| 40 |
|
49
(1) |
|
| The conversions to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one |
DD&A - depreciation, depletion, amortization and accretion
Volume measurements: |
|
|
Bbl – barrel |
| |
Boe – barrel of oil |
| |
|
| |
MBoe – thousand barrels of oil equivalent | Mcf – thousand cubic feet | MMcf – million cubic feet |
Mcfe – thousand cubic feet equivalent | MMcfe – million cubic feet equivalent |
|
DD&A - depreciation, depletion, amortization and accretion
ItemItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K, particularly in Risk Factors under Part I, Item 1A in this Form 10-K10-K.
Overview
We are an independent oil and natural gas producer with operations offshore in the Gulf of Mexico and onshore in the Permian Basin of West Texas.Mexico. We have grown through acquisitions, exploration and development, and currently hold working interests in approximately 6349 offshore fields in federal and state waters (61(47 producing and two fields capable of producing). We currently have under lease approximately 1.2 million700,000 gross acres, includingwith approximately 0.6 million470,000 gross acres on the Gulf of Mexico Shelf,shelf and approximately 0.5 million230,000 gross acres in the deepwater and approximately 50,000 gross acres onshore, primarily in Texas.deepwater. A substantial majority of our daily production is derived from wells we operate offshore.operate. We operate wells accounting for approximately 87% of our average daily production. Wecurrently own interests in approximately 203135 offshore structures, 13887 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.us directly and by our wholly-ownwholly-owned subsidiary, W & T Energy VI, LLC.
In managing our business, we are concerned primarily with maximizing returnfocused on shareholders’ equity. To accomplish this primary goal, we focus on increasingoptimizing production and growing reserves atin a profit. We striveprofitable and prudent manner, while managing cash flows to growmeet our obligations and investment needs. Our cash flows are materially impacted by the prices of our commodities produced (crude oil and natural gas, and the NGL��s extracted from the natural gas). In addition, the prices of goods and services used in our business impact our cash flows and margins. During 2017, commodity prices improved from the low price levels experienced during 2016 and 2015, but were nonetheless below the levels realized in years prior to 2015. Our margins in 2017 have improved from 2016 and 2015 levels, and are approaching the margin levels achieved prior to 2015. Although we have historically grown our reserves and production through acquisitions and our drilling programs. Weprograms, for the last three years, we have focused on acquiring properties where we can develop an inventoryincreasing reserves and production through drilling and through projects to optimize production on existing wells. While our production decreased 5.2% in 2017 from the prior year, our reserves increased more than production and resulted in a net increase in reserves year-over-year. The increase in proved reserves is a result of drilling, prospects that will enable us to continue to add reserves post-acquisition.
In September 2014,recompletion and workover effects, and improved commodity prices. During 2017, we acquired an additional ownership interest indrilled five wells on the Fairway 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 additional proved reserves associated with the increased ownership interest in the Fairway Field as of the acquisition date were approximately 4.4 MMBoe (26.4 Bcfe), comprised of approximately 26% NGLs and 74% natural gas, allcontinental shelf, four of which were classified as proved developed. Including adjustments from an effective date of July 1, 2014,successful, and began producing during 2017. Our plans for the adjusted purchase price was $17.4 millionshort-term include operating within cash flow, maintaining liquidity, meeting our financial obligations, establishing a drilling joint venture to provide drilling capital on a promoted basis and we assumedpursuing acquisitions meeting our criteria. See Liquidity and Capital Resources - Drilling Joint Venture under this Item 7 in this Form 10-K for additional information on the additional ARO associated with the increased ownership interest in Fairway, which we have estimated to be $6.1 million. The acquisition was funded from borrowingsdrilling joint venture.
See Properties – Proved Reserves under our revolving bank credit facilityPart I, Item 2; Selected Financial Data under Part II, Item 6 and cash on hand.
In May 2014, we acquired from Woodside certain oil and gas leasehold interests in the Gulf of Mexico (the “Woodside Properties”). The Woodside Properties consisted of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks. Internal estimates of proved reserves associated with the Woodside Properties as of the acquisition dates were approximately 1.6 MMBoe (9.4 Bcfe), comprised of approximately 89% oil, 1% NGLs and 10% natural gas, all of which were classified as proved developed. Including adjustments from an effective date of November 1, 2013, the adjusted purchase price was $54.8 million and we assumed the ARO associated with the Woodside Properties, which we have estimated to be $11.3 million. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.
In November and December 2013, we acquired from Callon certain oil and gas leasehold interests in the Gulf of Mexico. The Callon Properties consist of a 15% working interest in the Medusa field (deepwater Mississippi Canyon blocks 582 and 583), interest in associated production facilities and various interests in other non-operated fields. Internal estimates of proved reserves associated with the Callon Properties as of the acquisition dates were approximately 2.1 MMBoe (12.7 Bcfe), comprised of approximately 67% oil and 33% natural gas, all of which were classified as proved developed. Including adjustments from an effective date of July 1, 2013, the adjusted purchase price was $83.0 million and we assumed the ARO associated with the Callon Properties, which we have estimated to be $4.2 million. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.
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 approximately 7.0 MMBoe (42.0 Bcfe), comprised of approximately 36% oil, 3% NGLs and 61% natural gas, all of which were classified as proved developed. Including adjustments from an effective date of July 1, 2012, the adjusted purchase price was $205.8 million and we assumed the ARO associated with the Newfield Properties, which we have estimated to be $31.7 million. The acquisition was initially funded from borrowings under our revolving bank credit facility and cash on hand. Subsequently in the same month, the amounts borrowed under our revolving bank credit facility were paid down with funds provided from the issuance of an additional $300.0 million of 8.50% Senior Notes.
See Financial Statements and Supplementary Data – Note 221 – AcquisitionsSupplemental Oil and DivestituresGas Disclosures under Part II, Item 8 in this Form 10-K for additional information on acquisitions.our proved reserves.
Our drilling efforts in recent years have included the deepwater of the Gulf of Mexico. During 2017 and 2016, our volumes included production from the deepwater fields, Big Bend and Dantzler, which commenced production in late 2015. Both fields are composed of mostly oil and NGLs, having over 75% of reserves in oil and NGLs on a Boe basis. As of December 31, 2017, the Big Bend field was in our top ten fields based on reserves, net to our interest, on a Boe basis.
In September 2016, we consummated the Exchange Transaction whereby we exchanged approximately $710.2 million principal amount, or 79%, of our Unsecured Senior Notes for $301.8 million principal amount of new secured notes and 60.4 million shares of our common stock, and closed on a new $75.0 million 1.5 Lien Term Loan. The funds from the 1.5 Lien Term Loan were used to partially pay down borrowings outstanding on the revolving bank credit facility to maintain liquidity and to pay transaction costs associated with the Exchange Transaction. See Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for a full description of the transaction, the new debt instruments and the accounting for the transaction.
In October 2015, we sold our interests in the Yellow Rose onshore field in the Permian Basin to Ajax. Our interest in the field covered approximately 25,800 net acres. During 2015, the Yellow Rose field accounted for approximately 5% and 6% of our production and revenues, respectively. In connection with the sale, we retained a non-expense bearing overriding royalty interest (“ORRI”) equal to a variable percentage in production from the working interests sold, which percentage varies on a sliding scale from one percent for each month that the prompt month New York Mercantile Exchange (“NYMEX”) trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than $90.00 per barrel. Internal estimates of proved reserves at the date of the sale were 19.0 MMBoe, consisting of approximately 71% oil, 11% NGL and 18% natural gas. Including adjustments from an effective date of January 1, 2015, the adjusted sales price was $370.9 million and the buyer assumed the ARO associated with our interests in the Yellow Rose field, which we had estimated at $6.9 million at the time of the sale. We used a portion of the proceeds of the sale to repay all the outstanding borrowings under our revolving bank credit facility, while the remaining balance of approximately $100 million was added to available cash. See Financial Statements and Supplementary Data– Note 7 – Divestitures under Part II, Item 8 in this Form 10-K for additional information.
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 20142017 were comprised of approximately 41%49% oil and condensate, 12%9% NGLs and 47%42% natural gas, determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs. The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices per Mcfe for crude oil, NGLs and natural gas may differ significantly. For 2014,2017, our combined total production of oil, NGLs and natural gas was consistent with 2013, as we had new5.2% below 2016, primarily due to natural production from recently drilled wells and acquisitions,declines, partially offset by various pipeline outages, platform outages and maintenance shut-ins offshore and weather onshore. During 2013, sales volumes also benefited from new wells that were brought on line along with production from acquisitions. The year 2013 was also negatively impacted by various pipeline outages, shut downs for maintenance, Tropical Storm Karenwells drilled and various operational issues. During 2012, sales volumes were negatively impacted by various pipeline outages, Hurricane Isaaccompleted during 2017 and Tropical Storm Debbie.2016.
Our realized sales prices received for our crude oil, NGLs and natural gas production are affected by not only domestic production activities and political issues, but more importantly, international events, including both geopolitical and economic events. For the first nine months of 2014, WTI and BrentDuring 2017, crude oil, NGL, and natural gas realized prices averagedwere significantly above $100 per barrel.2016 realized prices, increasing 28.9%, 36.2% and 17.0%, respectively. In fact, crude oilJanuary 2018, realized prices have averaged over $90increased from December 31, 2017 levels. In addition, our lease operating costs in 2017 declined from the prior year, both on an absolute and per barrel for WTI and $100 per barrel for Brent for the last four years. This in turn has led to significant cost inflation in the oil and gas 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 2014 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:Boe basis.
The U.S. Energy Information Administration’sAdministration (“EIA”) data estimates theestimated worldwide supply of crude oil will outpace consumption in 2014 by approximately 800,000and petroleum liquids inventory draws averaged 0.4 million barrels per day.day during 2017, which was the first year of inventory draws since 2013. These inventory draws were supportive to higher crude oil prices worldwide. EIA currently forecasts worldwide crude oil and petroleum liquids inventories to increase by 0.2 million barrels per day and 0.3 million barrels per day in 2018 and 2019, respectively.
EIA estimates worldwide petroleum production increased by 0.7 million barrels per day in 2017 over 2016. The increase in 2017 over 2016 was primarily in the U.S. and Canada, partially offset by decreases in Russia and China. For 20152018 and 2016,2019, EIA forecasts crude oil supply being above consumption by approximately 600,000year over year production increases of 2.4 million barrels per day and 100,0001.8 million barrels per day, respectively, which is expectedwith the increases coming primarily from the U.S. and partially from Canada, Brazil and the Organization of the Petroleum Exporting Countries (“OPEC”) for both periods. Petroleum liquid consumption was estimated to keep downward pressure on prices. Worldwide storage capacity exists for the excess oil in the next two years but this is only a temporary solution that has historically led to lower prices. The extreme rapid decrease in crude oil prices appears to be due to supply-side growth. Over the past five years, supply has increased at 1.7% per year, while consumption increased 1.5% per year. Over the five year period, 2014 had the largest market imbalance, with supply increasing 2.3% compared to demand increasing at 1.0%. For 2014, production growth from countries outside of OPEC grew at a record high of 2.0increase by 1.4 million barrels per day in 2017 over 2013, of which2016 with the largest increases coming from China and the U.S. grew productionFor 2018 and 2019, EIA forecasts year over year consumption increases of 1.7 million barrels per day and 1.6 million barrels per day, and Canada grew production 0.3 million barrels per day. OPEC production was relatively flat for 2014 compared to 2013. OPEC members have taken no actions to reduce supplies and Saudi Arabia has made statements that it intends to protect its market share regardless ofrespectively, with the price of crude oil. Manyincreases coming primarily from China, other Asian countries, such as Russia, Iraq, Iran, Venezuela, have economies that are highly (or solely) dependent on oil revenues and do not have significant cash reserves like Saudi Arabia. These countries are not able to reduce production to wait for higher prices in the future; therefore, these types of countries would not have the economic ability to withstand lower production, which would further hurt their economies and continue to pressure crude oil prices. Iran, which has suffered under economic sanctions imposed by the United States and other NATO countries, is ramping up its production further exacerbating the excess crude oil supply situation.
While many U. S. producers have reduced capital budgets for 2015 compared to 2014, the U.S. producers have projected constant or increased production of crude oil for 2015. EIA estimates U.S. petroleum and other liquids production for 2014, 2015 and 2016 to be 14.0, 14.8 and 15.4 million barrels per day, respectively, and estimates Canada’s petroleum and other liquids production for 2014, 2015 and 2016 to be 4.4, 4.5 and 4.7 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. although increases are projectedforecasted for almost every country or groups of countries reported by EIA.
According 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 expecteddata provided 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 toEIA, 2017 U.S. crude oil production another factor affecting(excluding other petroleum liquids) increased by 5% from 2016 and is expected to further increase year over year by 10% and 6% in 2018 and 2019, respectively. If EIA’s forecast is achieved in 2018, oil production in the priceU.S will be at the highest level in recorded history, surpassing the current record set in 1970. Net imports of domestic crude oil isin the abilityU.S. decreased 7% in 2017 compared to get2016, and are forecasted to decrease year-over-year in 2018 and 2019 by 8% and 9%, respectively. As noted below, the number of rigs drilling for oil has more than doubled compared to 2016.
Geopolitical events could greatly affect the prices for oil, natural gas and other petroleum products. While these events are difficult to predict, countries like Venezuela, Nigeria, Libya, and Middle East countries have had, and could continue to have, disruptions due to political and economic factors outside of production issues. The proposed initial public offering of Saudi Arabian American Oil Company (Aramco) may provide an additional incentive for Saudi Arabia to market. Over the past few years, the infrastructure (both pipeline and rail)take actions to transportmaintain or increase crude oil withinprices to help drive the United States has seen a majorshare value prior to 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 toafter 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.offering.
During 2014,2017, our average realized oil sales price was 11.2% lower$48.13 per barrel, up from $37.35 per barrel (28.9% higher) for 2016. The two primary benchmarks are the prices for WTI and Brent crude oil. As reported by the EIA, WTI crude oil prices averaged $50.80 per barrel for 2017, up from $43.29 per barrel (17.3% higher) for 2016. Brent crude oil prices averaged $54.12 per barrel for 2017, up from $43.67 per barrel (23.9% higher) for 2016. The reductions in international crude oil supply and rising U.S. crude oil production puts price pressure on the discount of WTI to Brent , as the Brent-to-WTI premium increased in 2017 to over $3.00 per barrel compared to less than that realized$0.50 per barrel in 2013. 2016.
Our average realized oil sales price percentage decrease for 2014 was lower than($48.13 per barrel compared to a WTI benchmark price of $50.80 per barrel) 2017 differs from the benchmark crude oil benchmark WTIprices due to premiums or discounts (referred to as differentials), crude quality adjustments, volume weighting and other factors. All of our oil is produced offshore in the reduction in our offshore crude oil premiumsGulf of Mexico and is characterized as discussed above. As reported by the EIA, WTI prices averaged $93.17 per barrel for 2014, down from $97.98 per barrel for 2013. Brent prices decreased to $98.97 per barrel for 2014 from $108.53 per barrel for 2013. Crude oil prices fell dramatically during the fourth quarter of 2014Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and have fallen further thus far in 2015. In December 2014 and January 2015, WTI average prices were $59.29 and $47.22, respectively.others. WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors. In addition, beginning inSimilar to crude oil prices, the fourth quarter of 2013 and continuing through 2014, the premiumsdifferentials for the Gulf of Mexicoour offshore crude oil have declined to virtually be at parity with one another as the crude being moved to the U.S. Gulf Coast increased and imports continued. Over 85% of our oil is produced from offshorealso experienced volatility in the Gulf of Mexico and is characterized as Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”), Poseidon and others. For example, thepast. The monthly average premiums todifferentials of WTI versus Poseidon, LLS and HLS for LLS, HLS and Poseidon for 20142017 were $3.88, $3.52a negative $0.95, a positive $2.85 and a negative $1.20positive $2.44 per barrel, respectively, compared to $11.06, $11.02a negative $3.57, a positive $1.70 and $5.58a positive $0.84 per barrel, respectively, for 2013.2016. The majority of our crude oil is priced similar to Poseidon and therefore, experienced negative differentials for 2017. In addition, a few of our crude oil fields have a negative quality bank adjustment. However, our oil price differentials turned positive in the last two months of 2017 as the Brent-WTI differential widened.
EIA projects average crude oil prices for both WTI and Brent to increase by approximately $5.00 per barrel in 2018 compared to 2017. EIA’s forecast of crude oil prices for WTI and Brent are expected to increase by approximately $2.00 per barrel each, for the year 2019 compared to 2018. OPEC and certain non-OPEC countries agreed in November 2017 to extend their previously agreed on production cuts to the end of 2018 in an effort to reduce global inventories. In the U.S., onshore areas such as the Permian Basin, crudes alsoEagle Ford area, and the Bakken region are expected to have traded at a discount to WTI (at times the discount has been significant) in much of 2014 as supply growth outpaced infrastructure capacity. This bottleneck has been relieved recently with the new pipeline expansions from Longhorn, Bridge Tex and Cactus coming on line and allowing the WTI to Permian differentials to revert to more normal levels. Our oilincreased production in West Texas incurs discounts for transportation costs incurred by2018 over 2017 as the purchaser,areas have shown to be responsive to price change. Prices in the mid $50’s are expected to increasing drilling activity in these areas, which can occur fairly quickly. However, lasting upward and downward price movements could be limited over the next year because a substantial majority of U.S. producers have locked in their prices with larger discounts applied wherefinancial commodity derivatives allowing them to continue to drill and produce regardless of price changes. During 2017, the U.S. dollar weakened relative to other major currencies, which had a positive effect on crude oil is trucked due to lack of pipeline access. prices. Because all barrels are traded in U.S. dollars, as the U.S. dollar loses strength, crude oil prices are less expensive in other currencies and thus spur consumption.
OurDuring 2017, our average realized NGLs sales prices decreased 1.7% during 2014 versus 2013.price increased 36.2% compared to 2016. Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. During 2014,2017, the average pricesprice for domestic ethane increased 2%20% and the average domestic propane pricesprice increased 4%59% from the comparable 2013 period. Average price changesaverage 2016 prices. The average 2017 prices for other domestic NGLs rangedincreased from a decrease of 13% to a decrease of 7%, which caused the average realized NGLs sales price2016 prices, ranging from 21% to decline. Colder weather was a major factor for42%. We believe the increase in prices for NGLs is mostly a function of the price of 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 extracted from natural gas. Once the cold weather passed, ethane prices declined to pre-winter pricing and prices for the balance of 2014 were below the comparable 2013 period. Similar to propane, ethane prices for December 2014 fell dramatically and were 38% below the 2014 average. The decreaseschange in the prices of crude oil and natural gas haveprices. Per EIA, production of ethane was estimated to increase 9% for 2017 compared to 2016 and propane production was estimated to increase by 5% for 2017 compared to 2016. Ethane inventories as of year-end 2017 increased 23% over year-end 2016 levels. Ethane usage is not impacted by weather, but primarily by demand from petrochemical plants. Ethane production in 2018 and 2019 is forecast to increase year-over-year leading to further inventory builds. Two new petrochemical plants came on line in the first half of 2017 and five more are expected to be operational by the end of 2018. On the other hand, propane usage is affected by weather as it is used for house heating fuel in certain areas and for crop drying, along with other uses. Propane inventory levels were 26% lower at the pricesend of NGLs. As long as U.S. crude oil and2017 compared to the same period last year.
During 2017, our average realized natural gas production remain high and thesales price ratio of crude oilincreased 17.0 % compared to natural gas remains wide (as measured on a six to one energy equivalency), the production of NGLs may continue to be high relative to historical norms and would, in turn, suggest continued downward price pressure on the price of ethane. Many natural gas processing facilities have been and 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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2016. According to the EIA, spot prices for natural gas at Henry Hub (the primary U.S. price benchmark) were 17%18.5% higher in 20142017 compared to 2013 largely due to above-average storage withdrawals in response to the colder winter weather early in 2014 and higher industrial demand. The amount of heating degree days for the winter of 2014 was 13% higher than that of 2013, which was a primary causal factor for the increased demand.2016. Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues, other fuel competition (coal) and domestic economic conditions, and they have historically been subject to substantial fluctuation. However, with the surplus of naturalNatural 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 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 increased during 2014 on a percentage basis, it is still weak from an overall economic standpoint, and we expect continued weakness in natural gas prices for a number of reasons, including (i) producers continuing to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas continuing to be produced as a by-product in conjunction with the high level of oil drilling (as evidenced by the year over year increase in natural gas production despite the decline in the number of rigs drilling for natural gas as explained below), (iii) production efficiency gains being achieved in the shale gas areas resulting from better hydraulic fracturing, horizontal drilling, pad drilling and production techniques and (iv) 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 2017 were 5% lower than year-end 2016, and were 8% below the December 2014 were estimated at 3.1 trillion cubic feet, which is 8% above the comparable 2013 period. five-year average.
EIA estimates the Henry Hub natural gas spot price was $4.52 per Mcf in 2014 and forecasts $3.55 and $3.98 per Mcf for 2015 and 2016, respectively. Many research analysts are projecting thatprojects natural gas prices willto be lower than this forecast by EIA primarily duerelatively flat in 2018 and 2019, decreasing 3% in 2018 from 2017 and increasing 1% in 2019 from 2018. U.S. supply is projected to growthbe slightly above consumption in 2018 and 2019, resulting in minor inventory increases. As a result, excess inventory is not expected to be significantly changed, which limits any significant upward price movement. EIA’s estimate of fuel used for electrical power generation in 2017 was 32% from natural gas, supplies.30% from coal and 17% from renewable sources (includes hydropower and wind) and 21% for all other sources. For 2018 and 2019, EIA projectsforecasts electrical power from natural gas to increase to 33% and 34%, respectively, with the offset primarily in electrical power generation from coal.
During 2017, the number of working rigs drilling for oil and natural gas in the U.S. supply to bewere higher than consumption2016 levels for both 2015 andland based rigs. During 2017, offshore rigs were approximately the same as 2016 levels during most of the year, but were lower in the fourth quarter of 2017 compared to levels in the fourth quarter of 2016.
According to Baker Hughes, the oil rig count at December 31, 2017 and 2016 was 747 and 525, respectively (a 42% increase). The U.S. natural gas rig count at December 31, 2017 and 2016 was 439 at the beginning of 2013. The natural gas rig count decreased during 2013 to 372 rigs at the end of 2013182 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 searching for oil increasing from 1,318 at the beginning of 2013 to 1,378 at the end of 2013, and further increasing to 1,482 as of the end of December 2014. As of mid-February, the oil rig count decreased to 1,056.132, respectively (a 38% increase). In the Gulf of Mexico, there were 48the number of working rigs (29was 18 rigs (14 oil 19and four natural gas) at the beginning of 2013, 59December 31, 2017, and 22 rigs (39(22 oil 20and no natural gas) at December 31, 2016. The majority of working rigs in the endGulf of 2013Mexico are currently “floaters” with very few jack-up rigs working.
We also believe that private equity and 54 rigs (42 oilhedge funds are increasingly demanding cash flow positive projects in shale resource projects as opposed to solely focusing on increased reserves and 12 natural gas) as ofproduction growth. This may decrease future drilling in 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,shale resource areas, which in effect creates limits on both the extent of a price rise and the duration of a price increase. This will be the case until such time as demand for natural gas increases from either current consumers or new uses are developed to consume this resource. The demand for natural gas is expected to continue to increase as the announced petrochemical facilities are constructed and power producers convert to consuming natural gas to reduce emissions to ever tighter emission regulations and standards. Several companies are currently building or are planning to build liquefaction capacity to export liquefied natural gas due to significantly higher natural gas prices in Europe and Asia.turn would decrease future production.
Our current capital expenditure budget for 2015 is $200 million, not including any potential acquisitions. This is down from our 2014 and 2013 actual expenditures of approximately $630 million and $636 million, respectively. The plan for 2015 reflects the significantly lower estimated crude oil prices and our attempt to always drill within cash flow from operating activities. We continue to closely monitor current and forecasted prices to assess if changes are needed to our plans.
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Should the recent price decline in oil continue, it would negatively impact our future revenues, earnings and liquidity, cause impairment write-downs of the carrying value of our oil and natural gas properties, reduce proved reserves, create issues with financial ratio compliance, and lead to a reduction of the borrowing base associated with our Credit Agreement, depending on the longevity and severity of such price weakness. As required by the full cost accounting rules, we performedperform our ceiling test calculation as of December 31, 2014each quarter using the SEC pricing guidelines, which require using the 12-month average commodity price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price adjusted for price differentials. The average price usingDuring 2017, we did not have any ceiling-test write downs. Due to the SEC required methodology was $91.12 per barrel for crude oil and $4.27 per Mcf for natural gas. (For reference, thelower prices at the end of the year 2014 for those two 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 record a write-down of the carrying value of our oil and natural gas properties atoccurring during 2016 and 2015, we had ceiling-test write downs in 2016 and 2015 of $279.1 million and $987.2 million, respectively. The incurrence of ceiling-test write downs is dependent primarily on the price of crude oil and natural gas, but also is affected by quantities of proved reserves, future development costs and future lease operating costs. Using information available as of the filing date of this Form 10-K, we do not anticipate a ceiling-test write downs in the first quarter of 2018.
As of December 31, 2014. We are required to perform the ceiling test calculation at the end2017, we had $99.1 million of each quarter. If WTIavailable cash and Brent prices remain at levels occurring during December 2014 and January 2015, we estimate that we will likely recognize$149.7 million available on our revolving bank credit facility, which currently has a non-cash ceiling test write-down during 2015, and could have a non-cash ceiling test write-down in more than one quarterborrowing base 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$150.0 million. See the Liquidity and Capital Resources section of this Item 7, and Financial Statements and Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for additional information abouta description of our Credit Agreementdebt structure.
For 2017, our capital expenditures for oil and financing.gas properties and equipment on an accrual basis were $130.0 million, which was a substantial increase from the $48.6 million of capital expenditures in 2016, but below the capital expenditures in 2015 and 2014, which were $230.1 million and $626.6 million, respectively. For 2018, we have set our initial capital expenditure budget at $130.0 million is composed of select lower-risk, high-return, oil-focused projects combined with higher-risk, higher return, oil-focused projects that, assuming success, would be placed on production fairly quickly. We have flexibility in our capital expenditure programs as we have no long-term rig commitments and no pressure from co-owners to drill or complete a well. Some of our expenditures incurred during 2017 impacted our production for 2017, but most of the effect of lower commodity prices on revenuesimpact is expected to occur in 2018 and earnings, see Quantitativebeyond. In addition, we spent $72.4 million in 2017 and Qualitative Disclosures on Market Risks under Part II, Item 7A$72.3 million in this Form 10-K2016 for additional information.ARO and plan to spend $23.6 million in 2018 for ARO.
Our operating costs in 2017 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 points of sale. OurMexico. These operating costs are generally comprised of several components, including direct or base lease operating costs, facility repairs and maintenance, workover costs, insurance premiums, and gathering and transportation costs. During 2017, our lease operating expenses decreased 5.7% compared to 2016 on an absolute basis. The decrease was primarily due to lower costs production taxes, insurance premiums, workover costsof goods and ad valorem taxes.services from vendors. Additionally, we received higher product handling arrangement (“PHA”) fees in 2017 for certain fields as compared to 2016, which are recorded as credits to expense. Our operating costs depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties. Workover costs can vary significantly from year to year depending on the level of activity (either required or desired) and type of equipment used. In those instances where a drilling rig is required as opposed to some other type of intervention vessel or equipment, the costs tend to be much higher and require more time. During the last two years, we performed two offshore workovers each year that required the use of a drilling rig. At our Spraberry field (Yellow Rose) operations more workover activity has been performed due to the expanded well count.
In recent years, we acquired and built platformshave operated or participated in wells near the outer edge of the continental shelf and operated wells in the deepwater of the Gulf of Mexico. To the extent we continue expanding our deepwater operations, our operating costs will likelymay increase, especially as we find and produce more crude oil rather than natural gas. While each field can present operating 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 normally we obtain insurance to reduce, but not totally mitigate, our financial exposure risk. See Liquidity and Capital Resources - Hurricane Remediation, Insurance Claims and Insurance Coverage under this Item 7 and Financial Statementsand Supplementary Data – Note 18 – Contingencies under Part II, Item 8 in this Form 10-K for additional information.
Applicable environmental regulations require us to remove our platforms after production has ceased, to plug and abandon all wells and to remediate any environmental damage our operations may have caused. These types of activities are collectively referred to as decommissioning or ARO. The costs per well associated with our ARO generally increase as we drill wells in deeper parts of the continental shelf and in the deepwater. We generally do not pre-fund our ARO, but have obtained $273.8 million in bonds related to ARO and have restricted deposits for certain ARO arrangements. Over the last ten years, we have spent over $750 million for ARO. We estimated the present value of our liability related to our ARO at $390.6$300.4 million as of December 31, 2014.2017, of which $23.6 million is estimated to be spent during 2018. Inherent in the present value calculation of our liability are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, changes to our credit-adjusted risk-free rate, timing of settlement and expenditure, and changes in the legal, regulatory, environmental and political environments. Actual expenditures for ARO could vary significantly from these estimates. Overestimates and have varied significantly in the last several years,past. Prior to 2015, we have seensaw upward revisions in costs to do this work partly due to significant changes in the regulatory requirements and partly due to the escalation in the cost of goods and services required to do the work. Lower crudeThe increase in oil prices are expectedthat occurred over several years before the decline that began in June 2014 led to lead to lowersignificant cost inflation of goods and services in the Gulf of Mexico and other producing basins. Overall, service costs related to plugging and abandonment were relatively lower in 2017 compared to 2016 on a reduction in the estimated liability.per project basis.
Many changes in laws, regulations, guidance, interpretations and policy continue to be proposed and issued in our industry. The process for obtaining offshore drilling permits, especially deepwater drilling permits, has expanded and lengthened in the past few years. The most significant regulationSignificant regulatory changes in recent years areinclude NTL #2016-N01 and interpretations related to unbundling costs at natural gas plants, which adversely impact royalty payments. In addition, regulations have expanded related to potential environmental impacts, spill response documentation, compliance reviews and operator practices related to safety and implementing aenvironmental matters. This has led to higher costs for revisions, training, implementations and monitoring related to our safety and environmental management system.systems. The new regulations and increased review process increases the time to obtain drilling permits and increases the cost of operations. Also, the regulations have changed related to decommissioning, including plugging and abandonment of offshore wells and related infrastructure considerably, driving up both the time and cost to perform the work. As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time. See Business - Regulation under Part I, Item 1 in this Form 10-K for additional information.
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Year Ended December 31, 20142017 Compared to Year Ended December 31, 20132016
Revenues. Total revenues decreased $35.4increased $87.1 million, or 3.6%21.8%, to $948.7$487.1 million in 20142017 as compared to 2013.$400.0 million in 2016. Oil revenues decreased $66.2increased $71.1 million, or 9.2%26.4%, NGLs revenues decreased $0.5increased $5.8 million, or 0.7%22.1%, natural gas revenues increased $28.5$8.5 million, or 15.1%8.5%, and other revenues increased $2.8$1.7 million. The oil revenue decreaseincrease was attributable to an 11.2% Bbl decreasea 28.9% per barrel increase in the average realized sales price to $90.96$48.13 per Bblbarrel in 2017 from $102.44$37.35 per barrel in 2013,2016, partially offset by a 2.3% increase1.9% decrease in sales volumes. The NGLs revenue decreaseincrease was attributable to a 1.7% decrease36.2% increase in the average realized sales price to $34.49$23.35 per Bblbarrel in 20142017 from $35.07$17.14 per Bblbarrel in 2013,2016, partially offset by an increasea decrease of 1.0%10.4% in sales volumes. The increase in natural gas revenue increase was attributable to a 22.5%17.0% increase in the average realized natural gas sales price to $4.35$2.96 per Mcf in 2017 from $3.55$2.53 per Mcf for 2013,in 2016, partially offset by a 7.5% decrease in sales volumes. Overall, prices increased 28.2 % on a per Boe basis and production declined 4.9% on a per Boe per day basis. The largest production increases for 2017 compared to 2016 were at the Mahogany, Ewing Bank 910, Viosco Knoll 823 (“Virgo”) and East Cameron 321 fields. In addition, we received royalty relief in 2017 for a portion of 2016 crude oil royalties and all 2016 natural gas royalties related to the Mississippi Canyon 698 (“Big Bend”) and Mississippi Canyon 782 (“Dantzler”) fields, which increased revenues by $5.0 million and sales volumes by 6.0%. We experienced increases inapproximately 175,000 MBoe. Offsetting were 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 Fairwaydecreases primarily 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 and production deferrals. Production deferrals affecting various fields and the divestitures of certain fields in 2013. The production deferrals were attributable to third-partyfrom hurricanes, pipeline outages platform maintenance, and various operational issues. We estimate production deferralsother events were 2.6estimated at 1.7 MMBoe, during 2014. Specifically, production at Mississippi Canyon 506 (Wrigley) was deferredapproximately the same amount 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.2016.
Revenues from oil and liquids as a percent of our total revenues were 76.5%76.4% for 20142017 compared to 80.5%73.8% for 2013.2016. NGLs realized sales prices as a percent of crude oil realized prices increased to 37.9%48.5% for 20142017 compared to 34.2%45.9% for 2013.2016.
Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, and facilities maintenance, on our facilities, and hurricane remediation costs net of insurance claims, decreased $6.1$8.7 million, or 5.7%, to $264.8$143.7 million in 20142017 compared to 2013.$152.4 million in 2016. On a per Boe basis, lease operating expenses decreased to $15.01$9.86 per Boe during 20142017 compared to $15.06$9.92 per Boe during 2013.2016. On a component basis, workover expensebase lease operating expenses decreased $13.2 million, facilities maintenance expense decreased $4.6$10.5 million and insurance premiums decreased $3.3$2.4 million, partially offset by facilities maintenance increases of $2.5 million, insurance reimbursements of $1.2 million in basethe 2016 period only and workover expense increases of $0.5 million. Base lease operating expenses decreased primarily due to lower costs from service providers resulting primarily from lower levels of $15.4 million.activity in the Gulf of Mexico, higher PHA fees (cost offsets) at certain fields and lower charges from non-operated properties. Insurance premium reductions are primarily due to reduction in the Energy Package related to named windstorms coverage. The decreaseincrease in facilities maintenance expenses was primarily due to engine and compressor overhauls. For insurance reimbursements, we received reimbursements in 2016, of which a component was for lease operating expenses. No such insurance reimbursements were received during 2017. The increase in workover costs was primarily due to workoverswell work 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).Mahogany field.
Production taxes. Production taxes increased to $7.9decreased $0.1 million during 2014in 2017 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.2016. Most of our production is from federal waters where there are no production taxes while onshore operations are imposed. Our Fairway field, which is in state waters, is subject to production taxes.
Gathering and transportation costs. Gathering and transportation costs increaseddecreased to $19.8$20.4 million, or 10.8%, in 2017 compared to $22.9 million in 2014 compared to $17.5 million in 20132016 primarily due to escalation in third-party transportation fees.due to lower production volumes of NGLs and natural gas.
Depreciation, depletion, amortization and accretion. DD&A, includingwhich includes accretion for ARO, increaseddecreased to $28.98$10.68 per Boe for 2014in 2017 from $25.10$13.77 per Boe for 2013.in 2016. On a nominal basis, DD&A increaseddecreased to $511.1$155.7 million for 2014(26.4%) in 2017 from $451.5$211.6 million in 2013.2016. 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 2013decreased primarily due to increasesthe ceiling test write-downs recorded during 2016 and lower capital expenditures in salaries, share-based compensation, contract laborrelation to DD&A expense during 2016, both of which lowers the full-cost pool subject to DD&A. Other factors affecting the DD&A rate are changes in future development costs on remaining reserves and reductionschanges in charge-outs to third-parties, partially offset by lower cash-based incentive compensation. G&A on a per BOE basis was $4.93 Boeproved reserve volumes.
Ceiling test write-downof oil and natural gas properties. For 2017, no ceiling test write-downs were recorded. For 2016, we recorded non-cash ceiling test write-downs of $279.1 million as the book value of our oil and natural gas properties exceeded the ceiling test limitation. The write-down is the result of decreases in prices during 2016 for 2014 compared to $4.55 per Boe for 2013.all three commodities we sell, which are crude oil, NGLs and natural gas. See Financial Statementsand Supplementary Data – Note 11 – Share-Based and Cash-Based Incentive Compensation 1 - Basis of Presentation under Part II, Item 8 in this Form 10-K, for additionalwhich provides a description of the ceiling test limit determination.
General and administrative expenses (“G&A”). For 2017, G&A expenses of $59.7 million were essentially at the same level as in 2016. We experienced reductions in salary expense, legal expense, benefits costs and information.
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Derivative (gain)/loss. For 2014 and 2013, our derivative positions resulted technology costs, offset by increases in a net gain of $4.0 million and a net loss $8.5 million, respectively, and relatedincentive compensation, accrued civil penalties from the BSEE (which we are appealing to the change in the fair value of our then open crude oil commodity derivatives positions asIBLA) and surety bond costs. G&A on a result of changes in crude oil prices. During 2014, all open positions expired and closed. For 2013, the contracts relatedper BOE basis was $4.10 Boe for 2017 compared to production anticipated in both 2013 and 2014 and reflect changes in the fair value$3.89 Boe 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 2013.2016. 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 $109.6 million, or 12.5%, to $984.1 million in 2013 compared to 2012. Oil revenues increased $89.4 million, or 14.2%, NGLs revenues decreased $11.3 million, or 13.3%, natural gas revenues increased $30.9 million, or 19.5%, and other revenues increased $0.6 million. The oil revenue increase was attributable to a 16.3% increase in sales volumes, partially offset by a $1.91 per Bbl decrease in the average realized sales price to $102.44 per Bbl. The NGLs revenue decrease was attributable to a 11.8% decrease in the average realized sales price to $35.07 per Bbl in 2013 from $39.75 per Bbl in 2012 and a slight decrease of 1.8% in sales volumes. The natural gas revenue increase was attributable to a 20.7% increase in the average realized natural gas sales price to $3.55 per Mcf from $2.94 per Mcf for 2012, with sales volumes decreasing slightly by 1.1%. Production for all commodities was positively impacted by production increases at Ship Shoal 349 and the onshore properties in West Texas. In addition, production was positively impacted by the Newfield Properties acquired in the fourth quarter 2012, the Callon Properties acquired in the fourth quarter of 2013 and the volume adjustments described above in the Overview section. Production was negatively impacted for all commodities from natural production declines and from production deferrals affecting various fields. The production deferrals were attributable to third-party pipeline outages, platform maintenance, Tropical Storm Karen and various operational issues. We estimate production deferrals were 2.2 MMBoe during 2013 for all these issues. Specifically, production at Mississippi Canyon 506 (Wrigley) continues to be deferred as a result of maintenance at Shell’s Cognac platform and related pipelines. Also, production was deferred at our Fairway field due to well and maintenance issues and a turnaround at our Yellowhammer plant. During 2012, we also experienced production deferrals primarily due to Hurricane Isaac and various pipeline outages, but not near the same magnitude as in 2013.
Revenues from oil and liquids as a percent of our total revenues were 80.5% for 2013 compared to 81.7% for 2012. NGLs realized sales prices as a percent of oil realized prices decreased to 34.2% for 2013 compared to 38.1% for 2012.
Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, increased $38.6 million to $270.8 million in 2013 compared to 2012. On a per BOE basis, lease operating expenses increased to $15.06 per Boe during 2013 compared to $13.56 per Boe during 2012. On a component basis, workover expense increased $25.0 million primarily as a result of rig workovers on wells at our Ship Shoal 349/359 field and our Main Pass 69 field. Base lease operating expenses increased $14.5 million primarily as a result of the acquisition of the Newfield Properties, expanded onshore operations and ad valorem tax refunds received in 2012, partially offset by increased processing fees charged to third-parties. Facilities maintenance expense increased $5.1 million primarily attributable to a shutdown for scheduled maintenance at our Yellowhammer plant. Partially offsetting these increases were decreases in insurance premiums of $4.6 million and hurricane costs net of insurance claims of $1.5 million.
Production taxes. Production taxes increased to $7.1 million during 2013 compared to $5.8 million in 2012 primarily due to onshore production and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.
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Gathering and transportation costs. Gathering and transportation costs increased to $17.5 million in 2013 compared to $14.9 million in 2012 primarily due to escalation in third-party transportation fees.
Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, increased to $25.10 per Boe for 2013 from $20.79 per Boe for 2012. On a nominal basis, DD&A increased to $451.5 million for 2013 from $356.2 million in 2012. DD&A on a per Boe basis and nominal basis increased primarily due to: increasing estimates of future development costs; moving costs to the full cost pool from the unevaluated pool; increasing our ARO estimates without a corresponding increase in proved reserves; and incurring higher than expected development costs related to proved reserves. The acquisitions of the Newfield Properties and the Callon Properties also attributed to the increase in DD&A per Boe. In addition to the increase in DD&A per Boe, the nominal increase was affected by the increase in production volumes described above in Revenues, which include the cumulative effect of the volumes adjustments, as described above in the Overview section.
General and administrative expenses. G&A decreased slightly to $81.9 million for 2013 from $82.0 million for 2012 primarily due to lower litigation and settlement cost, mostly offset by increases in consulting services related to drilling operations, higher professional services, supplemental bonding fees and increased incentive compensation expense. G&A on a per Boe basis was $4.55 per Boe for 2013 compared to $4.79 per Boe for 2012. See Financial Statements and Supplementary Data – Note 1110 – Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 in this Form 10-K for additional information.
Derivative loss(gain) loss. . For 20132017, a $4.2 million derivative gain was recorded for crude oil and 2012,natural gas derivative contracts. We entered into derivative contracts for crude oil and natural gas during the first quarter of 2017 relating to a portion of our 2017 estimated production and there were no open contracts as of December 31, 2017. For 2016, a $2.9 million derivative positions resulted in net losses of $8.5 million and $14.0 million, respectively, and relate to the change in the fair value ofloss was recorded for 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.natural gas derivative contracts. See Financial Statements and Supplementary Data – Note 68 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.
Interest expense. Interest expense was $45.8 million in 2017, decreasing 50.3% from $92.3 million (net of capitalized interest) in 2016. The decrease was primarily attributable to the Exchange Transaction that was completed on September 7, 2016, when we exchanged $710.2 million of our Unsecured Senior Notes for $301.8 million of new secured notes and 60.4 million shares of common stock, and at the same time, closed on a $75.0 million, 1.5 Lien Term Loan. In addition, interest expense was lower as we had no borrowings on the revolving bank credit facility during 2017 compared to borrowings averaging approximately $150.0 million during the period from January 1, 2016 to the close of the Exchange Transaction on September 7, 2016. See Financial Statements and Supplementary Data - Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for additional information.
Gain on exchange of debt. During 2017, an additional net gain of $7.8 million was recognized primarily as a result of paying interest in cash on the Second Lien PIK Toggles Notes and the Third Lien PIK Toggle Notes versus paying the interest in kind. The cash interest payments on Second Lien PIK Toggles Notes and the Third Lien PIK Toggle Notes lowered the carrying value of the respective notes under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”), resulting in the recognition of a non-cash gain. The cash payments have a lower interest rate compared to the PIK option and this also reduced future interest and principal payments. Partially offsetting were additional expenses related to the Exchange Transaction for differences between estimated and actual expense. During 2016, a net gain of $123.9 million was recognized related to the Exchange Transaction. Under ASC 470-60, a gain was recognized as undiscounted future cash flows of the debt issued in the Exchange Transaction, plus the fair value of the common stock issued and deal transaction costs were less than the sum of the carrying value of the Unsecured Senior Notes exchanged combined with the funds received from the 1.5 Lien Term Loan issued. See Financial Statements and Supplementary Data - Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for additional information.
Other (income) expense, net. During 2017 and 2016, other (income) expense, net, was $4.8 million of net expense and $6.5 million of net income, respectively. For 2017, the amount consists primarily of expense items related to the Apache lawsuit of $6.3 million, partially offset by loss-of-use reimbursements from a third-party for damages incurred at one of our platforms of $1.1 million. For 2016, $7.7 million of income was recorded related to the settlements with certain insurance companies. Also, in 2016, write-downs of unamortized debt issuance costs were recorded related to a reduction in the borrowing base on the revolving bank credit facility. The reductions in the borrowing base resulted in proportional reductions in 2016 of $1.4 million in the unamortized debt issuance costs related to the revolving bank credit facility. See Financial Statements and Supplementary Data - Note 17 – Contingencies under Part II, Item 8 in this Form 10-K for additional information.
Income tax benefit.Our income tax benefit for 2017 and 2016 was $12.6 million and $43.4 million, respectively. The income tax benefit for both years was primarily attributable to claims made pursuant to Internal Revenue Code (“IRC”) Section 172(f), (related to rules for “specified liability losses”) which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.Our annual effective tax rate for 2017 and 2016 was not meaningful and differs from the federal statutory rate of 35% primarily due to the valuation allowances recorded for our deferred tax assets in both periods. During 2017, we recorded a decrease to the valuation allowance of $118.6 million, and during 2016, we recorded increases to the valuation allowance of $52.9 million related to federal and state deferred tax assets. A corresponding change for substantially an equivalent amount occurred in our deferred tax assets for both years. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. See Financial Statements and Supplementary Data – Note 12 – Income Taxes under Part II, Item 8 in this Form 10-K for additional information.
On December 22, 2017, the TCJA was enacted into law. This new law impacted certain components of our 2017 financial statements by requiring us to provisionally re-measure our net deferred tax assets at year-end 2017 downwards by $105.9 million. A corresponding reduction in our valuation allowance for substantially an equivalent amount was also recorded at year-end 2017. Our tax benefit recorded on the Consolidated Statement of Income for the year 2017 was not materially impacted as a result of the provisional re-measurement of our net deferred tax assets and its related valuation allowance. Our Consolidated Balance Sheet as of December 31, 2017 and our Consolidated Statement of Cash Flows for the year 2017 were also not impacted as a result of the enactment of the TCJA. However, due to the timing and the complexity involved in applying the provisions of the TCJA, our application of the TCJA may require further adjustments during 2018 in the determination of the final effects on our financial statements. For 2018, we do not expect to make any significant income tax payments.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Revenues. Total revenues decreased $107.3 million, or 21.1%, to $400.0 million in 2016 compared to $507.3 million in 2015. Oil revenues decreased $80.2 million, or 23.0%, NGLs revenues decreased $1.2 million, or 4.5%, natural gas revenues decreased $23.0 million, or 18.7%, and other revenues decreased $2.8 million. The oil revenue decrease was attributable to a 17.1% per barrel decrease in the average realized sales price to $37.35 per barrel in 2016 from $45.05 per barrel in 2015 and a 7.1% decrease in sales volumes. The NGLs revenue decrease was attributable to a 0.6% decrease in the average realized sales price to $17.14 per barrel in 2016 from $17.25 per barrel in 2015 and a decrease of 3.9% in sales volumes. The decrease in natural gas revenue was attributable to a 5.2% decrease in the average realized natural gas sales price to $2.53 per Mcf in 2016 from $2.67 per Mcf for 2015 and a 13.9% decrease in sales volumes. We experienced increases in production at the Big Bend and Dantzler fields, which began production in the fourth quarter of 2015. Also, production increases were achieved at the Ewing Bank 910 field, the Main Pass 108, the Main Pass 98 field and the East Cameron 321 field. Offsetting these production increases were production declines primarily from the sale of the Yellow Rose field in October 2015 (0.8 MMBoe); decreases at Mahogany, Matterhorn and Garden Banks 302 (Power Play) and other fields due to natural production declines; and various operational issues. Production deferrals, which occurred at Mahogany and other locations, were attributable to third-party pipeline outages, operational issues, and maintenance. For 2016, production deferrals were estimated to be 1.8 MMBoe compared to 2.0 MMBoe for 2015.
Revenues from oil and liquids as a percent of our total revenues were 73.8% for 2016 compared to 74.3% for 2015. NGLs realized sales prices as a percent of crude oil realized prices increased to 45.9% for 2016 compared to 38.3% for 2015 as crude oil prices continued to decline during most of 2016.
Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, and facilities maintenance, decreased $40.4 million, or 20.9%, to $152.4 million in 2016 compared to 192.8 million in 2015. On a per Boe basis, lease operating expenses decreased to $9.92 per Boe during 2016 compared to $11.31 per Boe during 2015. On a component basis, base lease operating expenses decreased $18.1 million, workover expense decreased $12.6 million, insurance premiums decreased $6.6 million, facilities maintenance decreased $2.1 million and insurance reimbursements increased $1.0 million (offset to expense). Base lease operating expenses decreased primarily due to lower costs from service providers and elimination of field expenses related to the sale of the Yellow Rose field, which was sold in October 2015; partially offset by increases in expenses related to our new deepwater fields at Dantzler and Big Bend; and lower PHA fees (cost offsets) at our Matterhorn field. The decrease in workover costs was primarily due to the sale of the Yellow Rose field and various activities that occurred in 2015 that did not reoccur in 2016. Insurance premium reductions were primarily due to revisions in the Energy Package related to named windstorms coverage.
Production taxes. Production taxes decreased to $1.9 million, or 37.1%, during 2016 compared to $3.0 million in 2015 primarily due to lower commodity prices and the sale of the Yellow Rose field. Our 2016 production taxes were not a large component of our operating costs. Most of our production was from federal waters where there are no production taxes, while onshore and state water operations are subject to production taxes.
Gathering and transportation costs. Gathering and transportation costs increased to $22.9 million, or 33.6%, in 2016 compared to $17.2 million in 2015 primarily due to production increases from the Big Bend and Dantzler fields, both of which began producing in the fourth quarter of 2015.
Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, decreased to $13.77 per Boe for 2016 from $23.11 per Boe for 2015. On a nominal basis, DD&A decreased to $211.6 million, or 46.3%, for 2016 from $394.1 million in 2015. DD&A on a per Boe and nominal basis decreased primarily due to the ceiling test write-downs recorded during 2016 and 2015, and lower capital expenditures in relation to DD&A expense, which lowered the full-cost pool subject to DD&A. In addition, the proceeds from the sale of our Yellow Rose field reduced the full cost pool along with the removal of future development costs associated with the Yellow Rose field proved reserves. Other factors affecting the DD&A rate were changes to future development costs on remaining proved reserves and changes to proved reserves.
Ceiling test write-down of oil and natural gas properties. For 2016 and 2015, we recorded non-cash ceiling test write-downs of $279.1 million and $987.2 million, respectively, as the book value of our oil and natural gas properties exceeded the ceiling test limitation. The ceiling test write-downs were the result of decreases in prices for all three commodities we sell, which are crude oil, NGLs and natural gas. See Financial Statements and Supplementary Data – Note 1 - Basis of Presentation under Part II, Item 8 in this Form 10-K, which provides a description of the ceiling test limit determination, and above under the section Overview in this Item regarding our prospects for a future significant ceiling test write-downs.
General and administrative expenses. G&A decreased to $59.7 million, or 18.3%, for 2016 from $73.1 million for 2015 primarily due to decreases in headcount related expense (salaries, benefits, and contractor expenses), elimination of certain employee benefits, increased reimbursements from stop-loss medical policies, and reductions in legal settlements, partially offset by higher legal costs. G&A on a per BOE basis was $3.89 Boe for 2016 compared to $4.29 per Boe for 2015. See Financial Statements and Supplementary Data – Note 10 – Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 in this Form 10-K for additional information.
Derivative (gain) loss. For 2016, there was a $2.9 million derivative net loss recorded for derivative contracts for crude oil and natural gas. At December 31, 2016, we did not have any open derivative contracts. We entered into derivative contracts for crude oil and natural gas during the second quarter of 2015, relating to 2015 and 2016 estimated production. For 2015, there was a $14.4 million derivative net gain recorded for derivative contracts for crude oil and natural gas. For both periods, the amount includes changes in the fair value of commodity derivative contracts. See Financial Statements and Supplementary Data – Note 8 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.
Interest expense. Interest expense incurred increasedwas $92.8 million in 2016, compared to $85.6$104.6 million in 2015. The decrease was primarily attributable to the Exchange Transaction. Interest expense was reduced for 2013 from $63.3 million for 2012. The aggregate principal amount of our 8.50%the Unsecured Senior Notes outstandingexchanged on September 7, 2016. For the debt issued in the Exchange Transaction, undiscounted future cash flows (principal, PIK and cash interest) were recorded as part of the carrying value of the debt under ASC 470-60; therefore, no interest expense was $900.0 million during 2013 compared to $600.0 million outstanding from January torecorded for the debt issued in the Exchange Transaction for the period of September 2012 and $900.0 million from October 20127, 2016 to December 201231, 2016. In addition, interest expense was lower due to lower average borrowings on the issuancerevolving bank credit facility. During 2016 and 2015, interest of an additional $300.0 million of 8.50% Senior Notes. During 2013 and 2012, $10.1$0.5 million and $13.3$7.3 million, respectively, of interest werewas capitalized to unevaluated oil and natural gas properties. The decrease is primarily attributable to reclassifying unevaluated properties to the full cost poolsale of the Yellow Rose field during the fourth quarter of 2012.2015 and reclassifying all other remaining unevaluated properties to the full-cost pool during 2016.
Gain on exchange of debt. In 2016, a gain of $123.9 million was recorded related to the Exchange Transaction. Under ASC 470-60, a gain was recognized as undiscounted future cash flows of the debt issued in the Exchange Transaction, plus the fair value of the common stock issued and deal transaction costs were less than the sum of the carrying value of the Unsecured Senior Notes exchanged combined with the funds received from the 1.5 Lien Term Loan issued.
Other (income) expense, net. Other (income) expense, net was income of $6.5 million in 2016 and was an expense of $4.7 million for 2015. For 2016, $7.7 million of income was recorded related to the settlements with certain insurance companies. In both 2016 and 2015, write-downs of unamortized debt issuance costs were recorded related to a reduction in the borrowing base on the revolving bank credit facility. The reductions in the borrowing base resulted in proportional reductions in 2016 and 2015 of $1.4 million and $3.2 million, respectively, in the unamortized debt issuance costs related to the revolving bank credit facility. In addition, during 2015, a net loss on sale of assets of $1.0 million was recorded primarily related to the sale of computer equipment used for backup processes.
Income tax benefit. Our income tax benefit for 2016 and 2015 was $43.4 million and $203.0 million, respectively, with the change attributable primarily to the deferred tax assets and the valuation allowance recorded for the respective periods. Our annual effective tax rate for 2016 and 2015 was not meaningful for either year, and differs from the federal statutory rate of 35% primarily due to the valuation allowances recorded for our deferred tax assets in both years. During 2016 and 2015, we recorded increases to the valuation allowance of $52.9 million and $232.9 million, respectively, related to federal and state deferred tax assets. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. See Financial Statements and Supplementary Data – Note 712 – Long-Term Debt Income Taxesunder Part II, Item 8 in this Form 10-K for additional information.
Other income, net. For 2013, other income was $8.9 million and consisted primarily of funds received in conjunction with a payment to us for an option exercised by a counterparty. For 2012, other income was $0.2 million.
Income tax expense. Income tax expense decreased to $28.8 million for 2013 compared to $47.5 million for 2012 due to lower pre-tax income and a lower effective tax rate. Our effective tax rate for 2013 was 35.9% and differed from the federal statutory rate of 35.0% primarily as a result of state income taxes. Our effective tax rate for 2012 was 39.8% and differed from the federal statutory rate of 35% primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the Internal Revenue Code (“IRC”) as a function of loss carrybacks to prior years and the impact of state income taxes.
Liquidity and Capital Resources
Our primary liquidity needs are to fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings, and make related interest payments and pay dividends.satisfy our AROs. We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank borrowings. These sources
If commodity prices were to return to the weaker levels seen in the early part of 2016, especially relative to our cost of finding and producing new reserves, this could have a significant adverse effect on our liquidity. In addition, other events outside of our control could significantly affect our liquidity such as demands for additional financial assurances from the BOEM. If such events were to occur in the future, we may seek relief under the U.S. Bankruptcy Code, which relief may include (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of our assets and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks.
Additionally, a prolonged period of weak commodity prices could have historically been sufficientother potential negative impacts including:
recognizing additional ceiling test write-downs of the carrying value of our oil and gas properties;
reductions in our proved reserves and the estimated value thereof;
additional supplemental bonding and potential collateral requirements;
further reductions in our borrowing base under the Credit Agreement; and
our ability to fund capital expenditures needed to replace produced reserves, which must be replaced on a long-term basis to provide cash to fund liquidity needs described above.
During 2016, we engaged legal and financial advisors to assist the Board of Directors and our ongoing cash requirements.management team to evaluate the various alternatives available to us. On September 7, 2016, we consummated the Exchange Transaction, which changed our debt and equity structure. See Financial Statements and Supplementary Data - Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for additional information.
Cash flowDuring 2017, we paid the interest payment for the Second Lien PIK Toggle Notes and working capital. Net cash provided by operating activities for 2014 was $511.4 million, compared to $561.4 million for 2013. Cash flows from operating activities, before changesthe Third Lien PIK Toggle Notes due in working capitalMay 2017 and ARO settlements, were $500.8 million in 2014, a decrease of $46.0 million compared to 2013. The changeJune 2017, respectively, in cash flows excluding working capitalrather than in kind. These cash payments and ARO settlements was primarily due to lower revenues. Our combined average realized sales price per Boe decreased 2.0%, with lower average realized sales prices of oil being partially offset by higher average realized natural gas sales prices. Our combined production of oil, NGLs and natural gas on a Boe basis during 2014 decreased 1.9% from 2013.
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The changes in working capital and ARO settlements led to a net reduction of $4.0 million in netthe cash provided by operating activities between 2014 and 2013. The reduction was primarily caused by large income tax refunds received in 2013 due to carryback of tax-based net operating losses and higher receivable collections received in 2013. At the beginning of 2013, receivable balances were higher than historical trends and led to higher collections in 2013. For 2014, receivable balances were lower due to lower average realized sales oil prices, but not as large a decrease as experienced in 2013. Partially offsetting were reductions of escrowed depositspayments related to ARO arrangements. Escrowed depositsthe 1.5 Lien Term Loan are included within Prepaid and Other Assets onreported in the Condensedfinancing section of the Consolidated Statements of Cash Flows. Flows under ASC 470-60. In addition, the cash interest payments on the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes lowered the carrying value of the respective notes under ACS 470-60, resulting in the recognition of a non-cash gain in 2017.
Net cash usedDuring 2018, the paid-in-kind option for the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes will expire in investing activities during 2014March 2018 and 2013 was $630.0 million and $614.8 million, respectively, which represents our investments in both offshore and onshore oil and gas properties. The increase is primarily due to proceeds from properties sales and other items of $21.0 million received in 2013 and no similar transactions occurred in 2014. Partially offsetting were decreases in acquisition expenditures, as we paid $72.2 million relatedSeptember 2018, respectively. Subsequent to the increased ownership in Fairway and for the acquisitionexpiration of the Woodside Propertiespaid-in-kind option, interest may only be paid in 2014 (two separate transactions) comparedcash.
We are reviewing several alternatives to $82.4 million relatedaddress the upcoming maturity of our revolving bank credit facility on November 8, 2018 and the repayment or refinancing of our Unsecured Senior Notes to address the acquisitionmaturity acceleration of certain of our debt instruments, which is described below. We believe the maturity of the Callon Propertiesrevolving bank credit facility can be extended if we are able to extinguish the Unsecured Notes and extended further if we are able to extinguish the 1.5 Lien Term Loan, both of which mature in 2013.2019.
NetOur Unsecured Senior Notes with total outstanding principal of $189.8 million mature on June 15, 2019. Our 1.5 Lien Term Loan with outstanding principal of $75.0 million matures on November 15, 2019. Our Second Lien Term Loan with outstanding principal of $300.0 million matures on May 15, 2020. Our Second Lien PIK Toggle Notes with current outstanding principal of $171.8 million matures on May 15, 2020, and our Third Lien PIK Toggle Notes with outstanding principal of $153.2 million matures on June 15, 2021. Each of our 1.5 Lien Term Loan and the Third Lien PIK Toggle Notes contain terms that accelerate their maturities to February 28, 2019 if all of the outstanding Unsecured Senior Notes are not refinanced, paid off, defeased, or otherwise extinguished prior to February 28, 2019. Assuming full utilization of the PIK option for our Third Lien PIK Toggle Notes, the combined principal of our 1.5 Lien Term Loan and our Third Lien PIK Toggle Notes would be $239.5 million on February 28, 2019. Each of our Second Lien Term Loan and Second Lien PIK Toggle Notes require us to offer to repay or repurchase the Second Lien Term Loan and Second Lien PIK Toggle Notes, as applicable, at par plus accrued and unpaid interest if by May 16, 2019, the aggregate outstanding principal amount of Unsecured Senior Notes that have not been repurchased, redeemed, discharged, defeased or called for redemption exceeds $50.0 million. Certain amendments under the 1.5 Lien Term Loan and the Credit Agreement will likely be required in the event replacement financing is not utilized.
We expect to build sufficient cash provided by financing activities was $126.4 million during 2014. The netbalances in 2018 to be able to redeem, repurchase or refinance the Unsecured Senior Notes and repay or refinance our 1.5 Lien Term Loan. This should enable us to amend our revolving bank credit facility in such a manner that will permit an extension of the maturity of such facility. There can be no assurance that lenders will extend our revolving bank credit facility maturity, but under current market conditions and based on the outlook of our cash provided during 2014 was primarily attributableposition in 2018, we believe our lenders or replacement lenders will be amenable to net borrowingsparticipating in a refinancing or other liability management transaction.
Credit Agreement. As indicated above, our revolving bank credit facility matures on November 8, 2018. Availability on our revolving bank credit facility as of $157.0 million, whichDecember 31, 2017 was partially offset by dividend payments of $30.3$149.7 million. Net cash provided by financing activities was $57.0 million during 2013. The net cash provided during 2013 was primarily attributable to net borrowings on our revolving bank credit facility of $120.0 million, which was partially used for dividend payments of $58.8 million and debt issuance costs of $3.9 million.
At December 31, 2014, we had a cash balance2017 and December 31, 2016, no amounts were outstanding and letters of $23.7 million and $302.4 million of undrawn capacity available undercredit were minimal. During 2017, no borrowings were made on the revolving bank credit facility, which had a borrowing base of $750.0 million as of December 31, 2014.facility.
Credit agreement and long-term debt. At December 31, 2014, $447.0 million was outstanding under our revolving bank credit facility compared to $290.0 million at December 31, 2013. At December 31, 2014 and 2013, $900.0 million principal amount of our 8.50% Senior Notes were outstanding. We believe that cash provided by operations and borrowings availableAvailability under our revolving bank credit facility is sufficient to fund our ongoing cash requirements. See Capital Expenditures below.
On November 8, 2013, we entered into the Credit Agreement which provides a revolving bank credit facility of up to $1.2 billion. Letters of credit may be issued up to $300.0 million, provided availability under the revolving bank credit facility exists. This is a secured facility that is collateralized by our oil and natural gas properties. The Credit Agreement terminates on November 8, 2018 and replaced the Prior Credit Agreement. Availability under the Credit Agreement is subject to a semi-annual redetermination of our borrowing base re-determination set atthat occurs in the discretionspring and fall of our lenders,each year and the Company and the lenders may each request one additional re-determination per year. The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. See Risk Factors – Lower oil and natural gas prices could negatively impact our ability to borrow under Part I, Item 1A in this Form 10-K.The 2017 fall redetermination reaffirmed the borrowing base amount at $150.0 million. Any determinationredetermination by our lenders to change our borrowing base as a result of the current commodity price environment or otherwise, will result in a similar change in the availability under our revolving bank credit facility. During 2014, the borrowing base was re-determinedThe revolving bank credit facility is secured 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 levelis collateralized by substantially all 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%,our oil 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%. natural gas properties.
We currently have 20 lenders within the revolving bank credit facility, with commitments ranging from $20.0$4.1 million to $58.0$11.6 million for the current borrowing base. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, any lack of or delay in funding by members of our banking group could negatively impact our liquidity position.
The Credit Agreement contains covenants that limit, among other things, the payment of cash dividends in excess of $60.0 million per year. In December 2012, we were granted a one-time waiver which allowed for cash dividends of up to $85.0 million during 2012. The Credit Agreement contains various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio and a maximum leverage ratio,which include thresholds on financial ratios, as defined in the agreements.Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement and the other debt instruments as of December 31, 2014. Assuming continuing oil and gas prices near levels realized in December 2014 and January 2015, we likely will be out of compliance with certain2017.
Long-Term Debt. The primary terms of our financial ratio maintenance covenants under our Credit Agreement sometime during 2015. We intendlong-term debt, the conditions related to engageincurring additional debt, and the lenders under the Credit Agreementconditions and limitations concerning early repayment of certain debt are disclosed 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.
59
During 2014, the outstanding borrowings on the revolving bank credit facility reached a high of $447.0 million, which was also the outstanding balance at December 31, 2014, primarily to fund acquisitions, our various deepwater development efforts and our ongoing onshore operations. Letters of credit outstanding as of December 31, 2014 were $0.6 million.
The 8.50% Senior Notes mature on June 15, 2019 and interest is payable semi-annually in arrears on June 15 and December 15 of each year. SeeFinancial Statements and Supplementary Data –- Note 72 – Long-Term Debt under Part II, Item 8 in this Form 10-K.
Drilling Joint Venture: To provide additional financial flexibility, as we have previously reported, throughout 2017 and now into 2018 we have been working to establish a drilling joint venture with private investors. We are in final stages of establishing a drilling joint venture to be formed with private investors that will allow us to drill and exploit assets on a promoted basis and with reduced capital outlay. We have completed negotiations with an initial group of investors, the terms of which are subject to funding at an initial closing expected to occur by mid-March. It is expected that entities owned and controlled by Tracy W. Krohn, Chairman and Chief Executive Officer of the Company, and his family will invest on the same terms as are negotiated with the unaffiliated investors to acquire an approximate 4% interest in the drilling joint venture. More investors may join the joint venture before or after the initial closing. If completed, this joint venture arrangement should reduce cash commitments for capital expenditures depending on the level of outside investor participation.
BOEM Matters. As of the filing date of this Form 10-K, for additional information about our Credit Agreement and long-term debt. We werethe Company is in compliance with its financial assurance obligations to the BOEM and has no outstanding BOEM orders related to financial assurance obligations. We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive demands in the future for financial assurances from the BOEM. For more information on the BOEM and financial assurance obligations to that agency, see “Business–Regulation–Decommissioning and Financial Assurance Requirements” under Part I, Item 1 of this Form 10-K.
Surety Bond Collateral. Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and could impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion.
The issuance of any additional surety bonds or other security to satisfy future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third-parties may require the posting of cash collateral, which may be significant, and may require the creation of escrow accounts.
Cash flow and working capital. Net cash provided by operating activities for 2017 was $159.4 million, compared to $14.2 million for 2016. Cash flows from operating activities and income taxes, (before changes in working capital, insurance reimbursements, escrow deposits and ARO settlements), were $235.6 million in 2017 compared to $103.1 million in 2016. The increase in cash flows was primarily due to higher realized prices for all applicable covenantsour commodities - oil, NGLs and natural gas, lower operating expenses and lower interest payments, partially offset by lower production volumes. Our combined average realized sales price per Boe increased 28.2%, which increased revenues $100.8 million. Partially offsetting were decreased combined volumes on a Boe basis of 5.2%, which lowered revenues by $15.4 million. Additionally, cash operating expenses and interest expenses combined were 13.2% lower on a per Boe basis, which increased cash flows from operating activities by $58.2 million. Interest payments related to the 8.50% SeniorNew Debt are reported within cash flows from financing activities under ASC 470-60.
Other items affecting operating cash flows for 2017 were ARO settlements of $72.4 million and an escrow deposit related to the Apache matter of $49.5 million, partially offset by insurance reimbursements of $31.7 million.
Net cash used in investing activities of oil and gas properties and equipment in 2017 was $107.1 million compared to $82.4 million in 2016. Both of these represent our investments in oil and gas properties and equipment in the Gulf of Mexico. There were no acquisitions during either year. Investments in oil and natural gas properties on an accrual basis during 2017 were $130.0 million compared to $48.6 million for 2016. In addition, adjustments from working capital changes associated with investing activities decreased net cash used by $23.9 million in 2017 compared to adjustments increasing net cash used of $35.2 million for 2016. Both of these adjustments are made to present capital expenditures on a cash basis.
Net cash used in financing activities for 2017 was $23.5 million and net cash provided by financing activities for 2016 was $53.0 million. The net cash used by financing activities for 2017 was primarily attributable to the interest payments on the 1.5 Lien Term Loan, the Second Lien PIK Toggle Notes, and the Third Lien PIK Toggle Notes, which are reported as financing activities under ASC 470-60. The net cash provided by financing activities in 2016 was attributable to the issuance of December 31, 2014.the 1.5 Lien Term Loan, partially offset by interest payments on the 1.5 Lien Term Loan and costs related to the Debt Exchange transaction.
Derivative financial instruments. From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility. As of December 31, 2014,2017, we did not have any outstanding open derivatives. See Financial Statementsderivatives for crude oil and Supplementary Data – Note 6 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information about our derivatives.natural gas.
Hurricane remediation, insurance claims and insurance coverage. During 2008, Hurricane Ike caused substantial property damage. Substantially all the costs related to Hurricane Ike have been incurred and we submitted claims under our insurance policies effective at that time, of which $161.2$203.1 million has been collected through December 31, 2014. 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 removal2017, which includes $31.7 million collected during 2017. As of wreckDecember 31, 2017, there were no claims outstanding 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. Given the Fifth Circuit’s ruling, we expect to be reimbursed and compensated for all these costs, interest, fees and damages. See Financial Statements and Supplementary Data - Note 18 – Contingencies under Part II, Item 8 in this Form 10-K for additional information. any hurricanes.
We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells. The current policy limits for well control range from $30.0$30.0 million to $500.0 million depending on the risk profile and contractual requirements. We requirements. With respect to coverage for named windstorms, we have $75.0a $150.0 million aggregate limit covering all of our properties, subject to a retention (deductible) of $30.0 million. Included within the $150.0 million aggregate limit is total loss only (“TLO”) coverage on our Mahogany platform, which has no retention. The operational and named windstorm (hurricane and tropical storm) coveragecoverages are effective 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 excess of scheduled ARO amounts. The well control, named windstorm and physical damage coverage is effective untilone year beginning June 1, 2015. A per-occurrence retention amount of $30.0 million for named windstorm events must be satisfied by us before our insurers will indemnify us for losses and we co-insure 15% of our named windstorm coverage. We also have other smaller per-occurrence retention amounts for various other events.2017. Coverage for pollution causing a negative environmental impact is provided under the well control and named windstormother sections ofwithin the policy.
All of our Gulf of Mexico properties with estimated future net revenues are covered under our current insurance policies for named windstorm damage. The risk exposure varies per property and we have exposure for applicable retentions, co-insurance amounts and coverage limits.
Our general and excess liability policies are effective untilfor one year beginning May 1, 20152017 and provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination. We have a builder’s risk and separate liability policy for certain non-operated properties for platforms and drilling operations under construction, which has coverage net to our interest of $137 million and $50 million, respectively, with retentions ranging from $0.1 to $0.3 million for different events and is effective until the estimated completion date of December 31, 2015. With respect to the Oil Spill Financial Responsibility requirement under the Oil Pollution Act of 1990, we are required to evidence $150.0 million of financial responsibility to the BSEE. We qualify to self-insure for $54.0 millionBSEE and we have insurance coverage of this amount and the remaining $96.0 million is covered by insurance.such amount.
Although we were able to renew our Energy Package and our general and excess liability policies in the second quarter of 2014effective on May 1, 2017, and have not been informed otherwise, in the future,our Energy Package effective on June 1, 2017, our insurers may not continue to offer this type and level of coverage to us in the future, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurers will not pay our claims. However, we are not aware of any financial issues related to any of our insurance underwriters that would affect their ability to pay claims. We do not carry business interruption insurance.
60
The premiums for the above policies including brokerage fees were $25.6$10.8 million for the May/June 20142017 policy renewals compared to $24.1$8.5 million for the expiring policies. The increase in our premiums effective with the May/June 1, 20142017 renewal was primarily attributable to expanding the additionnumber of properties covered and the builder’s risk policy and partially offset by lower premiums due to an improved insurance market.type of coverage for named windstorm damage.
Capital expenditures. The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors including the prices of crude oil, NGLs and natural gas,gas; acquisition opportunities,opportunities; liquidity and financing options; and the results of our exploration and development activities. The following table presents our capital expenditures on an accrual basis for acquisitions, exploration, development, acquisitions and other leasehold costs:
|
| Year Ended December 31, |
| |||||||||
|
| 2014 |
|
| 2013 |
|
| 2012 |
| |||
|
| (In thousands) |
| |||||||||
Acquisition of additional interest in Fairway |
| $ | 17,407 |
|
| $ | — |
|
| $ | — |
|
Acquisition of Woodside Properties |
|
| 54,827 |
|
|
| — |
|
|
| — |
|
Acquisition of Callon Properties |
|
| 576 |
|
|
| 82,424 |
|
|
| — |
|
Acquisition of Newfield Properties |
|
| — |
|
|
| 238 |
|
|
| 205,550 |
|
Exploration (1) |
|
| 179,196 |
|
|
| 198,740 |
|
|
| 137,055 |
|
Development (1) |
|
| 346,388 |
|
|
| 308,327 |
|
|
| 310,205 |
|
Seismic, capitalized interest, other leasehold costs |
|
| 28,218 |
|
|
| 44,649 |
|
|
| 32,053 |
|
Acquisitions and investments in oil and gas property/equipment |
| $ | 626,612 |
|
| $ | 634,378 |
|
| $ | 684,863 |
|
|
| Year Ended December 31, |
| |||||||||
|
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
|
| (In thousands) |
| |||||||||
Exploration (1) |
| $ | 57,088 |
|
| $ | 1,541 |
|
| $ | 51,768 |
|
Development (1) |
|
| 71,054 |
|
|
| 45,183 |
|
|
| 160,500 |
|
Acquisition of additional interest in Fairway (2) |
|
| — |
|
|
| — |
|
|
| 1,285 |
|
Acquisition of Woodside Properties (2) |
|
| — |
|
|
| — |
|
|
| 214 |
|
Seismic, capitalized interest, other |
|
| 1,906 |
|
|
| 1,882 |
|
|
| 16,394 |
|
Acquisitions and investments in oil and gas property/equipment |
| $ | 130,048 |
|
| $ | 48,606 |
|
| $ | 230,161 |
|
(1) | Reported geographically in the subsequent table. |
(2) | The amounts in 2015 represent adjustments to the purchase price for post-effective adjustments. |
The following table presents our exploration and development capital expenditures on an accrual basis geographically:
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| ||||||||||||||||||
|
| 2014 |
|
| 2013 |
|
| 2012 |
|
| 2017 |
|
| 2016 |
|
| 2015 |
| ||||||
|
| (In thousands) |
|
| (In thousands) |
| ||||||||||||||||||
Conventional shelf |
| $ | 131,215 |
|
| $ | 143,151 |
|
| $ | 104,401 |
|
| $ | 121,922 |
|
| $ | 38,631 |
|
| $ | 13,933 |
|
Deepwater |
|
| 216,539 |
|
|
| 143,745 |
|
|
| 65,856 |
|
|
| 6,220 |
|
|
| 8,093 |
|
|
| 186,579 |
|
Deep shelf |
|
| 23,615 |
|
|
| 61,953 |
|
|
| 11,961 |
|
|
| — |
|
|
| — |
|
|
| 195 |
|
Onshore |
|
| 154,215 |
|
|
| 158,218 |
|
|
| 265,042 |
|
|
| — |
|
|
| — |
|
|
| 11,561 |
|
Exploration and development capital expenditures |
| $ | 525,584 |
|
| $ | 507,067 |
|
| $ | 447,260 |
|
| $ | 128,142 |
|
| $ | 46,724 |
|
| $ | 212,268 |
|
The following table sets forth our drilling activity for completed wells on a gross basis.
| Completed |
|
| Non-commercial |
| Completed |
| |||||||||||||||||||||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
|
| 2014 |
|
| 2013 |
|
| 2012 |
| 2017 |
|
| 2016 |
|
| 2015 |
| |||||||||
Offshore - gross wells drills: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Offshore - gross wells drilled: |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Conventional shelf |
| 3 |
|
|
| 4 |
|
|
| 3 |
|
|
| — |
|
|
| 1 |
|
|
| 1 |
|
| 4 |
|
|
| — |
|
|
| — |
|
Deepwater |
| 3 |
|
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
| — |
|
|
| 1 |
|
|
| 5 |
|
Deep shelf |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
| |||||||||||
Wells operated by W&T |
| 4 |
|
|
| 5 |
|
|
| 3 |
|
| n/a |
|
| n/a |
|
| n/a |
|
| 4 |
|
|
| — |
|
|
| — |
| |||
Onshore: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Gross wells drilled |
| 33 |
|
|
| 40 |
|
|
| 77 |
|
|
| — |
|
|
| — |
|
|
| — |
| |||||||||||
Wells operated by W&T |
| 32 |
|
|
| 40 |
|
|
| 73 |
|
| n/a |
|
| n/a |
|
| n/a |
|
AsWe had an 80% success rate in 2017, 100% in 2016 and 100% in 2015. We drilled one exploration well on the conventional shelf during 2017 that was non-commercial, of December 31, 2014,which we werehad a 39% working interest.
During 2015, we sold our interest in the processonshore Yellow Rose field. Therefore, the historical information for onshore wells was excluded from the table above.
During the first two months of drilling and/or completing five offshore exploration wells, six onshore2018, we mobilized a rig to the Viosca Knoll 823 (Virgo) platform and drilled the Viosca Knoll 823 A-10 ST1 well to target depth. The A-17 well at Mahogany and the #1 well at Main Pass 286 have both been drilled to target depth. Completion operations are in progress for the A-17 well at Mahogany. The Main Pass 286 #1 well was successful and logged pay as a new field discovery. The Main Pass 286 #1 well has been cased and is waiting for development wellssanction, which is expected during 2018. First production is expected in Texas and seven onshore exploration wells in Texas.early 2019.
See Properties –Drilling Activity under Part I, Item 2 of this Form 10-K for a breakdown of exploration and development wells and additional drilling activity information.
See Properties –Development of Proved Undeveloped Reserves under Part I, Item 2 of this Form 10-K for a discussion on activity related to proved undeveloped reserves.
WeOver the last three years, we have acquired the followingfour leases for approximately $0.5 million from the BOEM: five leasesBOEM in the Federal Offshore Lease Sale. Per year, we acquired one lease ($2.40.1 million), one lease ($0.1 million) and two leases ($0.50.3 million) and 11 leases ($2.5 million) forin the years 2014, 20132017, 2016 and 2012,2015, respectively.
61
From time to time, we sell various oil and gas properties for a variety of reasons including, change of focus, perception of value and to reduce debt, among other reasons. As previously discussed, in 2015 we sold our interest in the Yellow Rose field for $370.9 million after adjustments and reduced related ARO by $6.9 million. In 2014,2017 and 2016, there were no property sales of significance. In 2013, we sold our working interests in the Green Canyon 60 field, the Green Canyon 19 field, the West Delta area block 29 and, combined with various other transactions and adjustments, produced net cash receipts of $10.2 million and reduced ARO by $19.6 million. Also in 2013, we received $9.1 million in conjunction with a payment to us for an option exercised by a counterparty. In 2012, we sold our 40% non-operated working interest in the South Timbalier 41 field for $30.5 million and reduced ARO by $4.0 million. See Financial Statements and Supplementary Data – Note 2 – Acquisitions and Divestitures7 –Divestitures under Part II, Item 8 in this Form 10-K for additional information on divestitures.this divestiture.
Capital expenditures.Our currentinitial capital expenditure budget for 20152018 is $200$130 million, not including any potential acquisitions. The 2015 budget is being allotted as follows: 38% for exploration, 61% for development and less than 1% for other items. Geographically, the budget is split 92% for offshore and 8% for onshore, with the substantial majority of offshore dedicated to the deepwater. Through February 2015, we have not closed any acquisitions, but we continue to evaluate and bid on opportunities as they arise. We anticipate funding our 2015 capital budget, anywhich excludes potential acquisitions, with over 50% allocated to development. Because of the level of commodity prices and other expenditures with cash flow from operating activities, cash on hand and borrowings underthe outlook for the remainder of 2018, we believe this level will enhance our revolving bank credit facility. For the portion of our capital budget related to drilling, our operating policy has been to fund these expenditures with cash flow provided by operations. See below for information on capital markets. Our 2015 capital budget is subject to change as conditions warrant.liquidity capacity throughout 2018. We strive to be as flexible as possible and believe this strategy holds the best promise for value creation, growth and managing the volatility inherentmaintain flexibility in our business.capital expenditure projects and if prices improve, we may increase our investments. See the Overview section in this Item for additional information.
Income taxes. During 2014, 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, $9.52017, we have recorded a current income taxes receivable of $13.0 million and a non-current income taxes receivable of $52.1 million. The current income taxes receivable relates primarily to an estimated NOL claim for 2017, which is expected to be received during 2018. During 2017, we received $11.9 million of income tax refunds related primarily to a 2016 NOL claim carried back to 2006. The non-current income taxes receivable relates to our NOL claims for the refunds receivedyears 2012, 2013 and 2014 that were carried back to prior years and require a review from the Congressional Joint Committee on Taxation prior to payments being made, the timing of which cannot be estimated at this time. These receivables relate to claims made pursuant to IRC rules for specified liability losses, which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years. Under the TCJA effective in 20132018, the rules related to specified liability losses have been accounted for as unrecognized tax benefits. We have $516.4 million of Federal net operating loss carryforwards (tax basis) available to offset future taxable incomeeliminated and additional claims will not be allowed in 20152018 and forward. We also have $12.1 million of alternative minimumThe TCJA does not affect our claims previously filed, noted above, nor does the TCJA affect the review process for such claims. For 2018, we do not expect to make any significant income tax credit carryforwards (tax basis) available to be utilized in 2015 and forward.payments.
Dividends. In 2014,During 2017, 2016 and 2015, we paid $30.3 milliondid not pay any dividends and a suspension of dividends remains in dividends. In 2013, we paid $58.8 million in dividends, which included a special dividend totaling $31.8 million and regular dividends of $27.0 million. In 2012, we paid $82.8 million in dividends, which included two special dividends totaling $59.0 million and regular dividends of $23.8 million. Dividends are subject to periodic review of the Company’s performance and the current economic environment and applicable debt agreement restrictions. In light of current market conditions, the Board of Directors has elected to suspend the regular quarterly dividend.effect.
Capital markets and impact on liquidity. At this time, we do not have current plans to obtain additional financing in 2015, but this situation could change depending on a number of factors, such as acquisition opportunities and prices of oil and natural gas. The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises. Additionally, we may be restricted on accessing certain capital markets due to terms within our Credit Agreement and Senior Note Indenture if certain covenants, primarily certain financial ratios, are not achieved on a current and pro forma basis as defined within the agreements. We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations through December 31, 2015; however, we cannot predict how an extended period of low commodity prices will affect our operations and liquidity levels.
Asset retirement obligations. Each year (and often more frequently) we review and revise our ARO estimates. Our ARO at December 31, 20142017 and 20132016 were $390.6$300.4 million and $354.4$334.4 million, respectively. In 2014respectively, recorded using discounted values. Our estimate of ARO spending in 2018 is $23.6 million. During 2017 and 2013,2016, we revised our estimates of costs anticipated to be charged by service providers for plug and abandonment projects. As these estimates are for work to be performed in the future, and in many cases, several years in the future, actual expenditures could be substantially different than our estimates. Additionally, we revise our estimates to account for the increased cost to comply with new and revised regulations, including an increaseincreases in work scope and cost changes from interpretation of work scope. See Risk Factors – Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are concentrated in the Gulf of Mexico under Part I, Item 1A and Financial Statements and Supplementary Data – Note 54 – Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our estimation of our ARO.
62
Contractual obligations. At December 31, 2017, we did not have any capital leases or open derivative contracts. The following table summarizes our significant contractual obligations by maturity as of December 31, 2014. At December 31, 2014, we did not have any capital leases.2017:
| Payments Due by Period as of December 31, 2014 |
| Payments Due by Period as of December 31, 2017 |
| ||||||||||||||||||||||||||||||||||
| Total |
|
| Less than One Year |
|
| One to Three Years |
|
| Three to Five Years |
|
| More Than Five Years |
| Total |
|
| Less than One Year |
|
| One to Three Years |
|
| Three to Five Years |
|
| More Than Five Years |
| ||||||||||
Long-term debt - principal | $ | 1,347.0 |
|
| $ | — |
|
| $ | — |
|
| $ | 1,347.0 |
|
| $ | — |
| $ | 906.8 |
|
| $ | — |
|
| $ | 442.3 |
|
| $ | 464.5 |
|
| $ | — |
|
Long-term debt - interest |
| 390.6 |
|
|
| 89.4 |
|
|
| 178.8 |
|
|
| 122.4 |
|
|
| — |
|
| 194.9 |
|
|
| 63.0 |
|
|
| 97.5 |
|
|
| 34.4 |
|
|
| — |
|
Drilling rigs |
| 12.6 |
|
|
| 12.6 |
|
|
| — |
|
|
| — |
|
|
| — |
|
| 5.7 |
|
|
| 5.7 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Operating leases |
| 13.9 |
|
|
| 1.5 |
|
|
| 3.2 |
|
|
| 3.5 |
|
|
| 5.7 |
|
| 9.3 |
|
|
| 1.8 |
|
|
| 3.6 |
|
|
| 3.7 |
|
|
| 0.2 |
|
Asset retirement obligations |
| 390.6 |
|
|
| 36.0 |
|
|
| 179.4 |
|
|
| 19.0 |
|
|
| 156.2 |
|
| 300.4 |
|
|
| 23.6 |
|
|
| 87.2 |
|
|
| 15.8 |
|
|
| 173.8 |
|
Other liabilities and commitments |
| 61.7 |
|
|
| 7.9 |
|
|
| 15.7 |
|
|
| 9.7 |
|
|
| 28.4 |
|
| 69.6 |
|
|
| 7.7 |
|
|
| 14.1 |
|
|
| 10.4 |
|
|
| 37.4 |
|
Total | $ | 2,216.4 |
|
| $ | 147.4 |
|
| $ | 377.1 |
|
| $ | 1,501.6 |
|
| $ | 190.3 |
| $ | 1,486.7 |
|
| $ | 101.8 |
|
| $ | 644.7 |
|
| $ | 528.8 |
|
| $ | 211.4 |
|
(1) |
|
(2) | Interest |
| ARO in the above table is presented on a discounted basis, consistent with the amounts reported on the Consolidated Balance Sheet as of December 31, |
| Other liabilities and commitments primarily consist of estimated fees for |
Inflation. For 2014,2017, our realized prices for crude oil decreased 11.2%increased 28.9%, NGLs decreased 1.7%increased 36.2% and natural gas increased 22.5%17.0% from 2013.2016. These are discussed in the Overview section above. Costs measured on a $/Boe basis increased by 9.5% in 2014 compared to 2013. The cost per Boe is impacted by factors other than cost changes, such as work activity including workovers, production levels and insurance reimbursements. Historically, our costs for goods and services have moved directionally with the price of crude oil, NGLs and natural gas, as these commodities affect the demand for these goods and services. In recent years,Operating costs directly related to production (lease operating expenses, production taxes and gathering and transportation) measured on a $/Boe basis decreased by 1.3% in 2017 compared to 2016. These operating costs directly related to production are impacted by factors other factors have influenced the cost of goods and services. Demandthan inflation or deflation, such as workovers, facility repairs, PHA fees for offshore third-party contractors can be affected bycertain fields (recorded as credits to expense), production levels, hurricanes, oil spills and changes in regulations which are outsideand the level of the influences from commodity price changes. Other costs, such as insurance premiums, have fluctuated with changes in hurricaneoil and gas activity the oil spills and other factors besides production volumes. 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 changes in economic activity in certain parts of the world, while other changes appear to be driven by political events around the world, the changes in the value of the US dollar (both up and down) and other foreign currencies. In addition, inflation in our industry is impacted as a result of record federal deficits and expectations that large deficits will continue.
Seasonality. Generally, the demand for and price of natural gas increases during the winter months and decreases during the summer months. However, these seasonal fluctuations are somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas. In addition, the demand for oil is higher in the winter months, but does not fluctuate as much as natural gas. Seasonal weather changes affect our operations. Tropical storms and hurricanes occur in the Gulf of Mexico during the summer and fall, which require us to evacuate personnel and shut in production until the storm subsides. Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which delays the installation of production facilities, thereby delaying production and sales of our oil and natural gas.Mexico.
63
Critical Accounting Policies
This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with GAAP in the United States. The preparation of our financial statements requires us to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our estimates on historical experience and other sources that we believe to be reasonable at the time. Changes in the facts and circumstances or the discovery of new information may result in revised estimates and actual results may vary from our estimates. Our significant accounting policies are detailed in Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K. We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management.
Revenue recognition. We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured. We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership. Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. If crude oil and natural gas prices decrease, we may need to increase this liability. Also, disputes may arise as to volume measurements and allocation of production components between parties. These disputes could cause us to increase our liability for such potential exposure. We do not record receivables for those properties in which the Company has taken less than its ownership share of production which could cause us to delay recognition of amounts due us.
Full-cost accounting. We account for our investments in oil and natural gas properties using the full-cost method of accounting. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and gas properties are capitalized. Capitalization of geological and geophysical costs, certain employee costs and G&A expenses related to these activities is permitted. We amortize our investment in oil and natural gas properties, capitalized ARO and future development costs (including ARO of wells to be drilled) through DD&A, using the units-of-production method. The units-of-production method uses reserve information in its calculations. The cost of unproved properties related to acquisitions are excluded from the amortization base until it is determined that proved reserves exist or until such time that impairment has occurred. We capitalize interest on unproved properties that are excluded from the amortization base. The costs of drilling non-commercial exploratory wells are included in the amortization base immediately upon determination that such wells are non-commercial. Under the full-cost method, sales of oil and natural gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized unless an adjustment would significantly alter the relationship between capitalized costs and the value of proved reserves.
Our financial position and results of operations may have been significantly different had we used the successful-efforts method of accounting for our oil and natural gas investments. GAAP allows successful-efforts accounting as an alternative method to full-cost accounting. The primary difference between the two methods is in the treatment of exploration costs, including geological and geophysical costs, and in the resulting computation of DD&A. Under the full-cost method, which we follow, exploratory costs are capitalized, while under successful-efforts, the cost associated with unsuccessful exploration activities and all geological and geophysical costs are expensed. In following the full-cost method, we calculate DD&A based on a single pool for all of our oil and natural gas properties, while the successful-efforts method utilizes cost centers represented by individual properties, fields or reserves. Typically, the application of the full-cost method of accounting for oil and natural gas properties results in higher capitalized costs and higher DD&A rates, compared to similar companies applying the successful efforts method of accounting.
DD&A can be affected by several factors other than production. The rate computation includes estimates of reserves which requires significant judgmentsjudgment and is subject to change at each assessment. The determination of when proved reserves exist for our unproved properties requires judgment, which can affect our DD&A rate. Also, estimates of our ARO and estimates of future development costs require significant judgment. Actual results may be significantly different from thesesuch estimates, which would affect the timing of when these expenses would be recognized inas DD&A. See Oil and natural gas reserve quantities and Asset retirement obligations below for more information.
64
Impairment of oil and natural gas properties. Under the full costfull-cost method of accounting, we are required to periodically perform a “ceiling test,”test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties. Any write downs occurring as a result of the ceiling test impairment are not recoverable or reversible in future periods. We incurred significant ceiling test write-downs during 2016 and 2015. We did not have any ceiling test impairments in 2014 or2017. Ceiling test impairments in future periods are highly dependent on commodity prices, and also are impacted by other factors and events. See the previous four years. If WTI and Brent prices remain at levels occurring during December 2014 and January 2015, we estimate that we will likely recognizeOverview section for a non-cashdiscussion on the price sensitivity of the ceiling test write-down during 2015, and could have a non-cash ceiling test write-down in more than one quarter of 2015.under certain assumptions. For the effect of lower commodity prices on liquidity, see Risk Factors - Risks Related to Financing under Part I, Item 1A and in the Liquidity and Capital Resources section of this Item in this Form 10-K for additional information about our Credit Agreement and financing. For the effect of lower commodity prices on revenues and earnings, see Quantitative and Qualitative Disclosures on Market Risks under Part II, Item 7A in this Form 10-K for additional information.
Oil and natural gas reserve quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of DD&A and impairment assessment of our oil and natural gas properties. We make changes to DD&A rates and impairment calculations in the same period that changes to our reserve estimates are made. Our proved reserve information as of December 31, 20142017 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 crude 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. See the Overview section for a discussion on the price sensitivity of the ceiling test under certain assumptions and the resulting sensitivity to reserve quantities.
Asset retirement obligations. We have significant obligations to plug and abandon all well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. Pursuant to GAAP, we are required to record a separate liability for the discounted present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet.
Inherent in the present value calculation of our liability are numerous estimates and judgments, including the ultimate settlement amounts, inflation factors, changes to our credit-adjusted risk-free rate, timing of settlement and changes in the legal, regulatory, environmental and political environments. Revisions to these estimates impact the value of our abandonment liability, our oil and natural gas property balance and our DD&A rates.
Fair value measurements. We measure the fair value of our derivative financial instruments by applying the income approach and using inputs that are derived principally from observable market data. Changes in the underlying commodity prices of the derivatives impact the unrealized and realized gain or loss recognized. We do not apply hedge accounting to our derivatives; therefore, the change in fair value for all outstanding derivatives, which include derivatives that are entered into in anticipation of future production, are reflected currently in our statements of operations. This can create timing differences between when the production is recognized and when the gain or loss on the derivative is recognized in the income statement. We estimate the fair value of our debt based on trades when such information is available. The market for our debt has low volumes of activity and has experienced high volatility in the past; therefore, the fair values presented may not represent the fair value of our debt in future periods.
65
Income taxes. We provide for income taxes in accordance with GAAP which requires the use of the liability method of computing deferred income taxes, whereby deferred income taxes are recognized for the future tax consequences of the differences between the tax basis of assets and liabilities and the carrying amount in our financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Because our tax returns are filed after the financial statements are prepared, estimates are required in recording tax assets and liabilities. We record adjustments to reflect actual taxes paid in the period we complete our tax returns. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.
We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken. When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense. The final settlement of these tax positions may occur several years after the tax return is filed and may result in significant adjustments depending on the outcome of these settlements.
As a result of the TCJA being enacted on December 22, 2017, we provisionally re-measured our deferred tax assets as of December 31, 2017. Further adjustments may be required in 2018 to determine the final effects on our financial statements.
Share-based compensation. In accordance with GAAP, weWe recognize compensation cost for share-based payments to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of the grant.grant, which may be significantly different than on the date of vesting. We estimate forfeitures during the service period and make adjustments depending on actual experience. These adjustments can create timing differences on when expense is recognized.
Troubled Debt Restructuring. We accounted for the Exchange Transaction in 2016 as a troubled debt restructuring pursuant to the guidance under ASC 470-60. Under ASC 470-60, the carrying value of the New Debt is measured using all future undiscounted payments (principal and interest); therefore, no interest expense has been recorded for the New Debt in the Consolidated Statements of Operations since September 7, 2016. Thus, our reported interest expense is significantly less than the contractual interest payments and this will continue through the maturities of the New Debt. The amounts recorded for the carrying value of the New Debt were determined using certain assumptions, which primarily were: (i) the PIK options, when available, would be fully utilized and (ii) the maturity of 1.5 Lien Term Loan and the Third Lien PIK Toggle Notes would not be accelerated, which implies the Unsecured Senior Notes will be repaid prior to February 28, 2019. These assumptions may prove to be incorrect, which would change the carrying value of the New Debt.
Revenue Recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), 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, 2017. Upon adoption, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application (modified retrospective approach). Our analysis of contracts with customers against the requirements of ASU 2014-09 is complete and we have not identified any changes to the timing of revenue recognition, or any changes to the classification of transactions previously recorded as revenue or credits to expense based on requirements of the standard. We will adopt ASU 2014-09 using the modified retrospective method that requires application of the new standard prospectively from the date of adoption with a cumulative effect adjustment, if any, recorded to retained earnings as of January 1, 2018 and revise our disclosures under ASU 2014-09 as applicable. ASU 2014-09 is more conceptual than previously issued guidance and covers virtually all industries, therefore, interpretation and judgment was required in applying ASU 2014-09 to our specific transactions. Our analysis and interpretations of ASU 2014-09 may be different than other companies, and upon further review and analysis, our application of ASU 2014-09 may need to be modified, which may require revisions to previously reported amounts.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks arising from fluctuating prices of crude oil, NGLs, natural gas and interest rates as discussed below. We have utilized derivative contracts from time to time to reduce the risk of fluctuations in commodity prices and expect to use these instruments in the future. We did not have anyentered into derivative contracts for crude oil and natural gas during 2017 and had no open derivative contracts as of December 31, 2014.
Commodity price risk. Our revenues, profitability and future rate of growth substantially depend upon market prices for oil, NGLs and natural gas, which fluctuate widely. Oil, NGLs and natural gas price declines and volatility could adversely affect our revenues, net cash provided by operating activities and profitability. For example, assuming a 10% decline in our average realized oil, NGLs and natural gas sales prices in 2014 and assuming no other items had changed, our loss before income tax would have increased by approximately $94 million in 2014. If costs and expenses of operating our properties had increased by 10% in 2014, our loss before income tax would have increased by approximately $29 million in 2014.
As of December 31, 2014, we did not have any open derivative contracts.2017. We do not designate our commodity derivative contracts as hedging instruments. While previous derivative contracts were intended to reduce the effects of volatile oil prices, they may also have limited income from favorable price movements. For additional details about our derivative contracts, refer to Financial Statements and Supplementary Data – Note 68 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K.
Commodity price risk. Our revenues, profitability and future rate of growth substantially depend upon market prices for crude oil, NGLs and natural gas, which fluctuate widely. Crude oil, NGLs and natural gas price declines and volatility could adversely affect our revenues, net cash provided by operating activities and profitability. For example, assuming a 10% decline in our average realized oil, NGLs and natural gas sales prices in 2017 and assuming no other items had changed, our income before income tax would have decreased by approximately $48 million in 2017. If costs and expenses of operating our properties had increased by 10% in 2017, our income before income tax would have decreased by approximately $17 million in 2017. These amounts would be representative of the effect on operating cash flows under these price and cost change assumptions.
Interest rate risk. As of December 31, 2014,2017, we had $447.0 millionno borrowings outstanding on our revolving bank credit facility and during 20142017, we had amounts outstanding that ranged from $242.0 million to $447.0 million.no borrowings. The revolving bank credit facility has a variable interest rate which is primarily impacted by the rates for the LIBORLondon Interbank Offered Rate and the current margin ranges from 1.75%3.00% to 2.75%4.00% depending on the amount outstanding. In 2014,2017, if interest rates would have been 100 basis points higher (an additional 1%);, our interest expense would not have been approximately $3.3 million higher.changed as no borrowings were made during 2017. We did not have any derivative contracts related to interest rates as of December 31, 2014.2017.
66
Item 8. FinancialFinancial Statements and Supplementary Data
W&T OFFSHORE, INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
| Page |
Management’s Report on Internal Control over Financial Reporting |
|
|
|
| |
|
| |
Consolidated Financial Statements: |
|
|
Consolidated Balance Sheets as of December 31, |
|
|
|
| |
|
| |
|
| |
|
|
67
MANAGEMENT’SMANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States (GAAP). Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework).
Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 20142017 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, 20142017 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.
68
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMReport of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of W&T Offshore, Inc. and Subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited W&T Offshore, Inc. and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2014,2017, based on criteria established in the Internal Control - Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the “COSO criteria”)COSO criteria). In our opinion, W&T Offshore, Inc. and subsidiaries’subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of W&T Offshore, Inc. and subsidiaries as of December 31, 2017 and 2016, and the related consolidated statements of operations, changes in shareholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2017, and related notes and our report dated March 2, 2018 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s 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’sCompany’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to W&T Offshore, Inc. and subsidiaries in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. 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.
Definition and Limitations of Internal Control Over Financial Reporting
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.
/s/ Ernst & Young LLP |
In our opinion,Houston, Texas
March 2, 2018
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of W&T Offshore, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, basedSubsidiaries
Opinion on the COSO criteria.Financial Statements
We also have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), theaccompanying consolidated balance sheets of W&T Offshore, Inc. and subsidiaries (the Company) as of December 31, 20142017 and 2013,2016, and the related consolidated statements of operations, changes in shareholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2014 and our report dated March 6, 2015 expressed an unqualified opinion thereon.
|
Houston, Texas
March 6, 2015
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, 2014 and 2013,2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations changes in shareholders' equity and its cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of W&T Offshore, Inc. and subsidiaries at December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2014,2017, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), W&T Offshore, Inc. and subsidiaries’the Company's internal control over financial reporting as of December 31, 2014,2017, based on criteria established in the Internal Control - IntegratedControl-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 6, 20152, 2018 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ Ernst & Young LLP We have served as the Company’s auditor since 2000.
|
|
Houston, Texas
March 6, 20152, 2018
70
W&T OFFSHORE, INC. AND SUBSIDIARIES
(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, |
| |||||
| 2017 |
|
| 2016 |
| ||
Assets |
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
Cash and cash equivalents | $ | 99,058 |
|
| $ | 70,236 |
|
Receivables: |
|
|
|
|
|
|
|
Oil and natural gas sales |
| 45,443 |
|
|
| 43,073 |
|
Joint interest |
| 19,754 |
|
|
| 21,885 |
|
Insurance reimbursement |
| — |
|
|
| 30,100 |
|
Income taxes |
| 13,006 |
|
|
| 11,943 |
|
Total receivables |
| 78,203 |
|
|
| 107,001 |
|
Prepaid expenses and other assets (Note 1) |
| 13,419 |
|
|
| 14,504 |
|
Total current assets |
| 190,680 |
|
|
| 191,741 |
|
|
|
|
|
|
|
|
|
Oil and natural gas properties and other, net - at cost: (Note 1) |
| 579,016 |
|
|
| 547,053 |
|
|
|
|
|
|
|
|
|
Restricted deposits for asset retirement obligations |
| 25,394 |
|
|
| 27,371 |
|
Income tax receivables |
| 52,097 |
|
|
| 52,097 |
|
Other assets (Note 1) |
| 60,393 |
|
|
| 11,464 |
|
Total assets | $ | 907,580 |
|
| $ | 829,726 |
|
Liabilities and Shareholders’ Deficit |
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
Accounts payable | $ | 83,665 |
|
| $ | 81,039 |
|
Undistributed oil and natural gas proceeds |
| 20,129 |
|
|
| 26,254 |
|
Asset retirement obligations |
| 23,613 |
|
|
| 78,264 |
|
Long-term debt |
| 22,925 |
|
|
| 8,272 |
|
Accrued liabilities (Note 1) |
| 17,930 |
|
|
| 9,200 |
|
Total current liabilities |
| 168,262 |
|
|
| 203,029 |
|
Long-term debt: (Note 2) |
|
|
|
|
|
|
|
Principal |
| 889,790 |
|
|
| 873,733 |
|
Carrying value adjustments |
| 79,337 |
|
|
| 138,722 |
|
Long term debt, less current portion - carrying value |
| 969,127 |
|
|
| 1,012,455 |
|
|
|
|
|
|
|
|
|
Asset retirement obligations, less current portion |
| 276,833 |
|
|
| 256,174 |
|
Other liabilities (Note 1) |
| 66,866 |
|
|
| 17,105 |
|
Commitments and contingencies (Note 9) |
| — |
|
|
| — |
|
Shareholders’ deficit: |
|
|
|
|
|
|
|
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at December 31, 2017 and December 31, 2016 |
| — |
|
|
| — |
|
Common stock, $0.00001 par value; 200,000,000 shares authorized; 141,960,462 issued and 139,091,289 outstanding at December 31, 2017 and 140,543,545 issued and 137,674,372 outstanding at December 31, 2016 |
| 1 |
|
|
| 1 |
|
Additional paid-in capital |
| 545,820 |
|
|
| 539,973 |
|
Retained earnings (deficit) |
| (1,095,162 | ) |
|
| (1,174,844 | ) |
Treasury stock, at cost; 2,869,173 shares at December 31, 2017 and December 31, 2016 |
| (24,167 | ) |
|
| (24,167 | ) |
Total shareholders’ deficit |
| (573,508 | ) |
|
| (659,037 | ) |
Total liabilities and shareholders’ deficit | $ | 907,580 |
|
| $ | 829,726 |
|
See accompanying notes.
71
W&T OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, |
| |||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| |||
| (In thousands except per share data) |
| |||||||||
Revenues | $ | 948,708 |
|
| $ | 984,088 |
|
| $ | 874,491 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
| 264,751 |
|
|
| 270,839 |
|
|
| 232,260 |
|
Production taxes |
| 7,932 |
|
|
| 7,135 |
|
|
| 5,840 |
|
Gathering and transportation |
| 19,821 |
|
|
| 17,510 |
|
|
| 14,878 |
|
Depreciation, depletion and amortization |
| 490,469 |
|
|
| 430,611 |
|
|
| 336,177 |
|
Asset retirement obligations accretion |
| 20,633 |
|
|
| 20,918 |
|
|
| 20,055 |
|
General and administrative expenses |
| 86,999 |
|
|
| 81,874 |
|
|
| 82,017 |
|
Derivative (gain) loss |
| (3,965 | ) |
|
| 8,470 |
|
|
| 13,954 |
|
Total costs and expenses |
| 886,640 |
|
|
| 837,357 |
|
|
| 705,181 |
|
Operating income |
| 62,068 |
|
|
| 146,731 |
|
|
| 169,310 |
|
Interest expense: |
|
|
|
|
|
|
|
|
|
|
|
Incurred |
| 86,922 |
|
|
| 85,639 |
|
|
| 63,268 |
|
Capitalized |
| (8,526 | ) |
|
| (10,058 | ) |
|
| (13,274 | ) |
Other income, net |
| 208 |
|
|
| 8,946 |
|
|
| 215 |
|
Income (loss) before income tax expense (benefit) |
| (16,120 | ) |
|
| 80,096 |
|
|
| 119,531 |
|
Income tax expense (benefit) |
| (4,459 | ) |
|
| 28,774 |
|
|
| 47,547 |
|
Net income (loss) | $ | (11,661 | ) |
| $ | 51,322 |
|
| $ | 71,984 |
|
Basic and diluted earnings (loss) per common share | $ | (0.16 | ) |
| $ | 0.68 |
|
| $ | 0.95 |
|
See accompanying notes.
72
W&T OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY(In thousands except per share data)
| Common Stock |
|
| Additional |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
| |||||||
| Outstanding |
|
| Paid-In |
|
| Retained |
|
| Treasury Stock |
|
| Shareholders’ |
| |||||||||||||
| Shares |
|
| Value |
|
| Capital |
|
| Earnings |
|
| Shares |
|
| Value |
|
| Equity |
| |||||||
| (In thousands) |
| |||||||||||||||||||||||||
Balances at December 31, 2011 |
| 74,352 |
|
| $ | 1 |
|
| $ | 386,920 |
|
| $ | 181,820 |
|
|
| 2,869 |
|
| $ | (24,167 | ) |
| $ | 544,574 |
|
Cash dividends: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock regular ($0.32 per share) |
| — |
|
|
| — |
|
|
| — |
|
|
| (23,798 | ) |
|
| — |
|
|
| — |
|
|
| (23,798 | ) |
Common stock special ($0.79 per share) |
| — |
|
|
| — |
|
|
| — |
|
|
| (59,034 | ) |
|
| — |
|
|
| — |
|
|
| (59,034 | ) |
Share-based compensation |
| — |
|
|
| — |
|
|
| 12,398 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 12,398 |
|
Stock issued, net of forfeitures |
| 898 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
RSUs surrendered for payroll taxes |
| — |
|
|
| — |
|
|
| (5,329 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| (5,329 | ) |
Other |
| — |
|
|
| — |
|
|
| 2,197 |
|
|
| (1,805 | ) |
|
| — |
|
|
| — |
|
|
| 392 |
|
Net income |
| — |
|
|
| — |
|
|
| — |
|
|
| 71,984 |
|
|
| — |
|
|
| — |
|
|
| 71,984 |
|
Balances at December 31, 2012 |
| 75,250 |
|
|
| 1 |
|
|
| 396,186 |
|
|
| 169,167 |
|
|
| 2,869 |
|
|
| (24,167 | ) |
|
| 541,187 |
|
Cash dividends: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock regular ($0.36 per share) |
| — |
|
|
| — |
|
|
| — |
|
|
| (27,098 | ) |
|
| — |
|
|
| — |
|
|
| (27,098 | ) |
Common stock special ($0.42 per share) |
| — |
|
|
| — |
|
|
| — |
|
|
| (31,748 | ) |
|
| — |
|
|
| — |
|
|
| (31,748 | ) |
Share-based compensation |
| — |
|
|
| — |
|
|
| 11,525 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 11,525 |
|
Stock issued, net of forfeitures |
| 342 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
RSUs surrendered for payroll taxes |
| — |
|
|
| — |
|
|
| (2,370 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2,370 | ) |
Other |
| — |
|
|
| — |
|
|
| (1,777 | ) |
|
| (431 | ) |
|
| — |
|
|
| — |
|
|
| (2,208 | ) |
Net income |
| — |
|
|
| — |
|
|
| — |
|
|
| 51,322 |
|
|
| — |
|
|
| — |
|
|
| 51,322 |
|
Balances at December 31, 2013 |
| 75,592 |
|
|
| 1 |
|
|
| 403,564 |
|
|
| 161,212 |
|
|
| 2,869 |
|
|
| (24,167 | ) |
|
| 540,610 |
|
Cash dividends: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock regular ($0.40 per share) |
| — |
|
|
| — |
|
|
| — |
|
|
| (30,260 | ) |
|
| — |
|
|
| — |
|
|
| (30,260 | ) |
Share-based compensation |
| — |
|
|
| — |
|
|
| 14,744 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 14,744 |
|
Stock issued, net of forfeitures |
| 307 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
RSUs surrendered for payroll taxes |
|
|
|
|
|
|
|
|
| (848 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (848 | ) |
Other |
| — |
|
|
| — |
|
|
| (2,880 | ) |
|
| (397 | ) |
|
| — |
|
|
| — |
|
|
| (3,277 | ) |
Net income |
| — |
|
|
| — |
|
|
| — |
|
|
| (11,661 | ) |
|
| — |
|
|
| — |
|
|
| (11,661 | ) |
Balances at December 31, 2014 |
| 75,899 |
|
| $ | 1 |
|
| $ | 414,580 |
|
| $ | 118,894 |
|
|
| 2,869 |
|
| $ | (24,167 | ) |
| $ | 509,308 |
|
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
|
|
| |||||||||
Revenues | $ | 487,096 |
|
| $ | 399,986 |
|
| $ | 507,265 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
| 143,738 |
|
|
| 152,399 |
|
|
| 192,765 |
|
Production taxes |
| 1,740 |
|
|
| 1,889 |
|
|
| 3,002 |
|
Gathering and transportation |
| 20,441 |
|
|
| 22,928 |
|
|
| 17,157 |
|
Depreciation, depletion and amortization |
| 138,510 |
|
|
| 194,038 |
|
|
| 373,368 |
|
Asset retirement obligations accretion |
| 17,172 |
|
|
| 17,571 |
|
|
| 20,703 |
|
Ceiling test write-down of oil and natural gas properties |
| — |
|
|
| 279,063 |
|
|
| 987,238 |
|
General and administrative expenses |
| 59,744 |
|
|
| 59,740 |
|
|
| 73,110 |
|
Derivative (gain) loss |
| (4,199 | ) |
|
| 2,926 |
|
|
| (14,375 | ) |
Total costs and expenses |
| 377,146 |
|
|
| 730,554 |
|
|
| 1,652,968 |
|
Operating income (loss) |
| 109,950 |
|
|
| (330,568 | ) |
|
| (1,145,703 | ) |
Interest expense: |
|
|
|
|
|
|
|
|
|
|
|
Incurred |
| 45,836 |
|
|
| 92,791 |
|
|
| 104,592 |
|
Capitalized |
| — |
|
|
| (520 | ) |
|
| (7,256 | ) |
Gain on exchange of debt |
| 7,811 |
|
|
| 123,923 |
|
|
| — |
|
Other (income) expense, net |
| 4,812 |
|
|
| (6,520 | ) |
|
| 4,663 |
|
Income (loss) before income tax benefit |
| 67,113 |
|
|
| (292,396 | ) |
|
| (1,247,702 | ) |
Income tax benefit |
| (12,569 | ) |
|
| (43,376 | ) |
|
| (202,984 | ) |
Net income (loss) | $ | 79,682 |
|
| $ | (249,020 | ) |
| $ | (1,044,718 | ) |
Basic and diluted earnings (loss) per common share | $ | 0.56 |
|
| $ | (2.60 | ) |
| $ | (13.76 | ) |
See accompanying notes.
73
W&T Offshore, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, |
| |||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| |||
| (In thousands) |
| |||||||||
Operating activities: |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) | $ | (11,661 | ) |
| $ | 51,322 |
|
| $ | 71,984 |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion |
| 511,102 |
|
|
| 451,529 |
|
|
| 356,232 |
|
Amortization of debt issuance costs and premium |
| 701 |
|
|
| 1,645 |
|
|
| 2,575 |
|
Share-based compensation |
| 14,744 |
|
|
| 11,525 |
|
|
| 12,398 |
|
Derivative (gain) loss |
| (3,965 | ) |
|
| 8,470 |
|
|
| 13,954 |
|
Cash payments on derivative settlements, net |
| (5,318 | ) |
|
| (8,589 | ) |
|
| (7,664 | ) |
Deferred income taxes |
| (4,760 | ) |
|
| 30,920 |
|
|
| 88,109 |
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas receivables |
| 29,510 |
|
|
| 980 |
|
|
| 818 |
|
Joint interest and other receivables |
| (4,255 | ) |
|
| 34,257 |
|
|
| (28,823 | ) |
Income taxes |
| 3,143 |
|
|
| 44,328 |
|
|
| (58,011 | ) |
Prepaid expenses and other assets |
| 15,012 |
|
|
| (10,044 | ) |
|
| 7,440 |
|
Asset retirement obligation settlements |
| (74,313 | ) |
|
| (81,543 | ) |
|
| (112,827 | ) |
Accounts payable, accrued liabilities and other |
| 41,483 |
|
|
| 26,558 |
|
|
| 38,952 |
|
Net cash provided by operating activities |
| 511,423 |
|
|
| 561,358 |
|
|
| 385,137 |
|
Investing activities: |
|
|
|
|
|
|
|
|
|
|
|
Acquisition of property interest in oil and natural gas properties |
| (72,234 | ) |
|
| (82,424 | ) |
|
| (205,550 | ) |
Investment in oil and natural gas properties and equipment |
| (554,378 | ) |
|
| (551,954 | ) |
|
| (479,313 | ) |
Proceeds from sales of assets and other, net |
| — |
|
|
| 21,008 |
|
|
| 30,453 |
|
Purchases of furniture, fixtures and other |
| (3,340 | ) |
|
| (1,435 | ) |
|
| (3,031 | ) |
Net cash used in investing activities |
| (629,952 | ) |
|
| (614,805 | ) |
|
| (657,441 | ) |
Financing activities: |
|
|
|
|
|
|
|
|
|
|
|
Issuance of 8.50% Senior Notes |
| — |
|
|
| — |
|
|
| 318,000 |
|
Borrowings of long-term debt - revolving bank credit facility |
| 556,000 |
|
|
| 563,000 |
|
|
| 732,000 |
|
Repayments of long-term debt - revolving bank credit facility |
| (399,000 | ) |
|
| (443,000 | ) |
|
| (679,000 | ) |
Debt issuance costs |
| — |
|
|
| (3,892 | ) |
|
| (8,510 | ) |
Dividends to shareholders |
| (30,260 | ) |
|
| (58,846 | ) |
|
| (82,832 | ) |
Other |
| (345 | ) |
|
| (260 | ) |
|
| 379 |
|
Net cash provided by financing activities |
| 126,395 |
|
|
| 57,002 |
|
|
| 280,037 |
|
Increase in cash and cash equivalents |
| 7,866 |
|
|
| 3,555 |
|
|
| 7,733 |
|
Cash and cash equivalents, beginning of period |
| 15,800 |
|
|
| 12,245 |
|
|
| 4,512 |
|
Cash and cash equivalents, end of period | $ | 23,666 |
|
| $ | 15,800 |
|
| $ | 12,245 |
|
See accompanying notes.
W&T OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (DEFICIT)
(In thousands)
| Common Stock |
|
| Additional |
|
| Retained |
|
|
|
|
|
|
|
|
|
| Total |
| ||||||||
| Outstanding |
|
| Paid-In |
|
| Earnings |
|
| Treasury Stock |
|
| Shareholders’ |
| |||||||||||||
| Shares |
|
| Value |
|
| Capital |
|
| (Deficit) |
|
| Shares |
|
| Value |
|
| Equity (Deficit) |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2014 |
| 75,899 |
|
| $ | 1 |
|
| $ | 414,580 |
|
| $ | 118,894 |
|
|
| 2,869 |
|
| $ | (24,167 | ) |
| $ | 509,308 |
|
Share-based compensation |
| — |
|
|
| — |
|
|
| 10,242 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 10,242 |
|
Stock issued |
| 607 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
RSUs and shares surrendered for payroll taxes |
| — |
|
|
| — |
|
|
| (674 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (674 | ) |
Other |
| — |
|
|
| — |
|
|
| (649 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (649 | ) |
Net loss |
| — |
|
|
| — |
|
|
| — |
|
|
| (1,044,718 | ) |
|
| — |
|
|
| — |
|
|
| (1,044,718 | ) |
Balances at December 31, 2015 |
| 76,506 |
|
|
| 1 |
|
|
| 423,499 |
|
|
| (925,824 | ) |
|
| 2,869 |
|
|
| (24,167 | ) |
|
| (526,491 | ) |
Share-based compensation |
| — |
|
|
| — |
|
|
| 11,013 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 11,013 |
|
Stock issued |
| 61,168 |
|
|
| — |
|
|
| 106,366 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 106,366 |
|
RSUs surrendered for payroll taxes |
| — |
|
|
| — |
|
|
| (905 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (905 | ) |
Net loss |
| — |
|
|
| — |
|
|
| — |
|
|
| (249,020 | ) |
|
| — |
|
|
| — |
|
|
| (249,020 | ) |
Balances at December 31, 2016 |
| 137,674 |
|
|
| 1 |
|
|
| 539,973 |
|
|
| (1,174,844 | ) |
|
| 2,869 |
|
|
| (24,167 | ) |
|
| (659,037 | ) |
Share-based compensation |
| — |
|
|
| — |
|
|
| 7,191 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 7,191 |
|
Stock issued |
| 1,417 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
RSUs surrendered for payroll taxes |
| — |
|
|
| — |
|
|
| (1,344 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (1,344 | ) |
Net income |
| — |
|
|
| — |
|
|
| — |
|
|
| 79,682 |
|
|
| — |
|
|
| — |
|
|
| 79,682 |
|
Balances at December 31, 2017 |
| 139,091 |
|
| $ | 1 |
|
| $ | 545,820 |
|
| $ | (1,095,162 | ) |
|
| 2,869 |
|
| $ | (24,167 | ) |
| $ | (573,508 | ) |
See accompanying notes.
W&T Offshore, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities: |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) | $ | 79,682 |
|
| $ | (249,020 | ) |
| $ | (1,044,718 | ) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion |
| 155,682 |
|
|
| 211,609 |
|
|
| 394,071 |
|
Ceiling test write-down of oil and gas properties |
| — |
|
|
| 279,063 |
|
|
| 987,238 |
|
Gain on exchange of debt |
| (7,811 | ) |
|
| (123,923 | ) |
|
| — |
|
Debt issuance costs write-down/amortization of debt items |
| 1,715 |
|
|
| 2,548 |
|
|
| 4,411 |
|
Share-based compensation |
| 7,191 |
|
|
| 11,013 |
|
|
| 10,242 |
|
Derivative (gain) loss |
| (4,199 | ) |
|
| 2,926 |
|
|
| (14,375 | ) |
Cash receipts on derivative settlements, net |
| 4,199 |
|
|
| 4,746 |
|
|
| 6,703 |
|
Deferred income taxes |
| 217 |
|
|
| 28,392 |
|
|
| (203,272 | ) |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas receivables |
| (2,370 | ) |
|
| (7,005 | ) |
|
| 32,236 |
|
Joint interest receivables |
| 2,131 |
|
|
| 12 |
|
|
| 21,645 |
|
Insurance reimbursements |
| 31,740 |
|
|
| — |
|
|
| — |
|
Income taxes |
| (1,063 | ) |
|
| (64,274 | ) |
|
| (7 | ) |
Prepaid expenses and other assets |
| 3,238 |
|
|
| (14,946 | ) |
|
| 17,816 |
|
Escrow deposit - Apache lawsuit |
| (49,500 | ) |
|
| — |
|
|
| — |
|
Asset retirement obligation settlements |
| (72,409 | ) |
|
| (72,320 | ) |
|
| (32,555 | ) |
Accounts payable, accrued liabilities and other |
| 10,965 |
|
|
| 5,359 |
|
|
| (46,207 | ) |
Net cash provided by operating activities |
| 159,408 |
|
|
| 14,180 |
|
|
| 133,228 |
|
Investing activities: |
|
|
|
|
|
|
|
|
|
|
|
Investment in oil and natural gas properties and equipment |
| (130,048 | ) |
|
| (48,606 | ) |
|
| (230,161 | ) |
Changes in operating assets and liabilities associated with investing activities |
| 23,874 |
|
|
| (35,194 | ) |
|
| (55,425 | ) |
Proceeds from sales of assets, net |
| — |
|
|
| 1,500 |
|
|
| 372,939 |
|
Purchases of furniture, fixtures and other |
| (933 | ) |
|
| (96 | ) |
|
| (1,278 | ) |
Net cash provided by (used in) investing activities |
| (107,107 | ) |
|
| (82,396 | ) |
|
| 86,075 |
|
Financing activities: |
|
|
|
|
|
|
|
|
|
|
|
Borrowings of long-term debt - revolving bank credit facility |
| — |
|
|
| 340,000 |
|
|
| 263,000 |
|
Repayments of long-term debt - revolving bank credit facility |
| — |
|
|
| (340,000 | ) |
|
| (710,000 | ) |
Issuance of 1.5 Lien Term Loan |
| — |
|
|
| 75,000 |
|
|
| — |
|
Issuance of Second Lien Term Loan |
| — |
|
|
| — |
|
|
| 297,000 |
|
Payment of interest on 1.5 Lien Term Loan |
| (8,227 | ) |
|
| (2,570 | ) |
|
| — |
|
Payment of interest on 2nd Lien PIK Toggle Notes |
| (7,335 | ) |
|
| — |
|
|
| — |
|
Payment of interest on 3rd Lien PIK Toggle Notes |
| (6,201 | ) |
|
| — |
|
|
| — |
|
Debt exchange/issuance costs |
| (421 | ) |
|
| (18,464 | ) |
|
| (6,669 | ) |
Other |
| (1,295 | ) |
|
| (928 | ) |
|
| (886 | ) |
Net cash provided by (used in) financing activities |
| (23,479 | ) |
|
| 53,038 |
|
|
| (157,555 | ) |
Increase (decrease) in cash and cash equivalents |
| 28,822 |
|
|
| (15,178 | ) |
|
| 61,748 |
|
Cash and cash equivalents, beginning of period |
| 70,236 |
|
|
| 85,414 |
|
|
| 23,666 |
|
Cash and cash equivalents, end of period | $ | 99,058 |
|
| $ | 70,236 |
|
| $ | 85,414 |
|
See accompanying notes.
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies
Operations
W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,”, “us,” “our,” or the “Company”, is an independent oil and natural gas producer focused primarilywith substantially all of its operations in the Gulf of Mexico andMexico. On October 15, 2015, a substantial amount of our interest in onshore Texas. The Companyacreage was sold, which is described in Note 7. We are active in the exploration, development and acquisition of oil and natural gas properties. Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our wholly-ownwholly-owned subsidiary, W & T Energy VI, LLC (“Energy VI”).
Basis of Presentation
Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries. All significant intercompany transactions and amounts have been eliminated for all years presented.
Reclassifications
Certain reclassifications Our consolidated financial statements have been made to prior periods’ financial statements to conform toprepared in accordance with United States generally accepted accounting principles (“GAAP”) and the current presentation as follows: Income tax – receivables was combined with Joint interestappropriate rules and other – receivables onregulations of the Consolidated Balance Sheets. Loss on extinguishment of debt was combined with Other income, net on the Consolidated Statements of Operations. Insurance proceeds was combined with the changes in Joint interestSecurities and other receivables and changes in Other – operating assets and liabilities was combined with the changes in Accounts payable, accrued liabilities and other on the Consolidated Statements of Cash Flows.Exchange Commission (“SEC”).
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”)GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.
Recent Events
The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate of growth. The average realized prices of these commodities began fallingimproved in June 20142017 compared to the average realized prices in 2016. Operating costs were lower for 2017 on an absolute and on a per barrel oil equivalent (“Boe”) basis compared to the operating costs for 2016.
In September 2016, we consummated the Exchange Transaction, as defined and described below in Note 2, which reduced our interest payments for 2017 as compared to 2016. In addition, the Exchange Transaction extended the maturities on a portion of our debt, although for a portion of the New Debt, as defined and described in Note 2, the maturities of two of the new loans will accelerate if certain events do not transpire.
We have continued working to further reduce our operating costs, capital expenditures and costs related to asset retirement obligations (“ARO”). Our capital expenditures incurred in 2017 were higher than the capital expenditures incurred during 2016, but were significantly lower than spending levels incurred during 2015 and prior years. Our current capital expenditure budget for 2018 is approximately the same level as incurred in January and February2017.
87
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of 2015 comparedthe filing date of this Form 10-K, the Company is in compliance with its financial assurance obligations to the last few years. Bureau of Ocean Energy Management (“BOEM”) and has no outstanding BOEM orders related to financial assurance obligations.
We have taken several stepsDuring the second quarter of 2017, a trial court judgment was rendered in Apache Corporation’s (“Apache”) lawsuit against us. As a result, we deposited $49.5 million with the registry of the court from cash on hand as a first step to mitigateallow us to appeal 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 furtherdecision. See Note 17 for capital expenditures and other activities until such time as market conditions recover.additional information.
We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices andprices. We believe we will have adequate liquidity to fund our operations through December 31, 2015; however,March 2019, the period of assessment to qualify as a going concern. We are evaluating various alternatives and believe our plans can be executed in the current market and are within our capabilities. Our plans address the possible maturity acceleration of certain debt instruments, which could accelerate to February 28, 2019 if certain events were not to occur, and address events needed to extend our Credit Agreement, which matures on November 8, 2018. However, we cannot predict how an extended period of lowthe potential changes in commodity prices willor future bonding requirements, either of which could affect our operations, liquidity levels and liquidity levels.
75
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Adjustment Related to Additional Volumes
In January 2014, we identified that we had been receiving an erroneous million British thermal unit (“MMBtu”) conversion factor from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field (Tahoe). The incorrect conversion factor had been used on all natural gas production from the field since we acquired it in 2011. The effect of using this incorrect conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production and the calculation of depletion expense. We performed an analysis of the information, assessing both quantitative and qualitative factors, and determined that the impact on our net income reported for prior annual periods, as well as the impact to our earnings trend, was not material to 2011 and 2012 results, thus the adjustment was recognized in 2013. The 2013 period reflects a one-time increase in natural gas production volumes of 1.9 billion cubic feet (“Bcf”) (with no corresponding increase in revenue) for the annual periods of 2011 and 2012, which increased depreciation, depletion, amortization and accretion (“DD&A”) by $5.0 million and decreased net income by $3.2 million. compliance with debt obligations.
Cash Equivalents
We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents.
Revenue Recognition
We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured. We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership. Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which the Company haswe have taken less than itsour ownership share of production. At both December 31, 20142017 and 2013, $6.42016, $4.7 million wasand $5.3 million, respectively, were included in current liabilities related to natural gas imbalances.
Concentration of Credit Risk
Our customers are primarily large integrated oil and natural gas companies, large financial institutions and large financial institutions. Ourtrading houses. The majority of our production is sold utilizing month-to-month contracts that are based on bid prices. We also have receivables from joint interest owners on properties we operate and we may have the ability to withhold future revenue disbursements to recover amounts due us. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guarantiesguarantees 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 of any material amounts.
The following table identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas.gas:
| Year Ended December 31, |
| Year Ended December 31, |
| ||||||||||||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| 2017 |
|
| 2016 |
|
| 2015 |
| ||||||
Customer |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shell Trading (US) Co. |
| 47 | % |
|
| 48 | % |
|
| 35 | % |
| 46 | % |
|
| 43 | % |
|
| 50 | % |
ConocoPhillips (1) | ** |
|
| ** |
|
|
| 16 | % | |||||||||||||
Vitol Inc. |
| 15 | % |
|
| 20 | % |
| ** |
| ||||||||||||
J. P. Morgan | ** |
|
| ** |
|
|
| 14 | % |
|
|
|
|
** Less than 10%
88
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 SUBSIDIARIESAccounts Receivables and Allowance for Bad Debts
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)Our accounts receivables are recorded at their historical cost, less an allowance for doubtful accounts. The carrying value approximates fair value because of the short-term nature of such accounts. In addition to receivables from sales of our production to our customers, we also have receivables from joint interest owners on properties we operate. In certain arrangements, we have the ability to withhold future revenue disbursements to recover amounts due us from the joint interest partners. We have not had any significant problems collecting our receivables from our customers, but with the decline in commodity prices starting in 2015, several oil and gas companies have filed for bankruptcy where we have joint interest arrangements. We use the specific identification method of determining if an allowance for doubtful accounts is needed. The following table describes the balance and changes to the allowance for doubtful accounts:
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Allowance for doubtful accounts, beginning of period | $ | 7,602 |
|
| $ | 2,490 |
|
| $ | 704 |
|
Additional provisions for the year |
| 1,512 |
|
|
| 5,112 |
|
|
| 1,786 |
|
Uncollectable accounts written off |
| — |
|
|
| — |
|
|
| — |
|
Allowance for doubtful accounts, end of period | $ | 9,114 |
|
| $ | 7,602 |
|
| $ | 2,490 |
|
Insurance Receivables
We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs primarily as a result of hurricane damage when we deem those to be probable of collection, which normally arises when our insurance underwriters’company’s adjuster reviews and approves such costs for payment byor when the underwriters.insurance company has agreed to reimbursement amounts. Claims that have been processed in this manner have customarily been paid on a timely basis. During 2017, we received payments by certain insurance companies related to settlement of previously unpaid claims. See Note 185 for information relatedadditional information.
Prepaid expenses and other
Amounts recorded in Prepaid expenses and other on the Consolidated Balance Sheets are expected to unpaid claims by certain underwriters.be realized within one year. The following table describes the major items for the periods presented:
| Year Ended December 31, |
| |||||
| 2017 |
|
| 2016 |
| ||
Prepaid/accrued insurance | $ | 2,401 |
|
| $ | 2,924 |
|
Surety bonds unamortized premiums |
| 2,676 |
|
|
| 2,462 |
|
Prepaid deposits related to royalties |
| 6,456 |
|
|
| 6,237 |
|
Other |
| 1,886 |
|
|
| 2,881 |
|
Prepaid expenses and other | $ | 13,419 |
|
| $ | 14,504 |
|
89
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Properties and Equipment
We use the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred.
Oil and natural gas properties and equipment include costs of unproved properties. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as the Company haswe have made an evaluation that impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial.
We capitalize interest on the amount of unproved properties that are excluded from the amortization base. Interest is capitalized only for the period that exploration and development activities are in progress. Capitalization of interest ceases when the property is moved into the amortization base. All capitalized interest is recorded within Oil and natural gas property and equipment on the Consolidated Balance Sheets.
Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”),ARO, the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense.
Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.
UnderFurniture, 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. Oil and natural gas properties and equipment are recorded at cost using the full cost method.
Oil and Natural Gas Properties and Other, Net – at cost
Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no amounts excluded from amortization as of the dates presented in the following table (in thousands):
| December 31, |
| |||||
| 2017 |
|
| 2016 |
| ||
Oil and natural gas properties and equipment | $ | 8,102,044 |
|
| $ | 7,932,504 |
|
Furniture, fixtures and other |
| 21,831 |
|
|
| 20,898 |
|
Total property and equipment |
| 8,123,875 |
|
|
| 7,953,402 |
|
Less accumulated depreciation, depletion and amortization |
| 7,544,859 |
|
|
| 7,406,349 |
|
Oil and natural gas properties and other, net | $ | 579,016 |
|
| $ | 547,053 |
|
90
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Under the full-cost method of accounting, we are required to periodically perform a “ceiling test,”test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized ARO), net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed. Any such write downs are not recoverable or reversible in future periods. The ceiling test limit is comprised of:calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects. Estimated future net revenues used in the ceiling test for each yearperiod are based on current prices for each product, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the period January through Decemberprior twelve months for that year.period. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials.
77
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DeclinesWe did not record a ceiling test write-down during 2017. We recorded ceiling test write-downs in 2016 and 2015, which are reported as a separate line in the Statements of Operations, due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices infor oil and natural gas. The ceiling test write-downs of the carrying value of our oil and natural gas properties were $279.1 million and $987.2 million for 2016 and 2015, respectively. If average crude oil and natural gas prices after December 31, 2014 may require us to record ceiling-test impairments in the future. We did not have anydecrease from 2016 levels, it is possible that ceiling test write-downs related to ceiling-test impairmentscould be recorded during 2014, 2013 and 2012, respectively.
Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years. Leasehold improvements are amortized over the shorter of their economic lives2018 or the lease term. Repairs and maintenance costs are expensed in the period incurred.future periods.
Asset Retirement Obligations
Pursuant to GAAP, weWe are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. For additional information, refer to Note 5.4.
Oil and Natural Gas Reserve Information
Pursuant to GAAP, weWe use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices. Another provision of the guidance is a general requirement that, subject to limited exceptions, provedProved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.years, with some limited exceptions allowed. Refer to Note 21 for additional information about our proved reserves.
Derivative Financial Instruments
Our market risk exposure relates primarily to commodity prices and interest rates.prices. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas andgas. When we have outstanding borrowings on our revolving bank credit facility, we may use various derivative financial instruments to manage our exposure to interest rate risk from floating interest ratesrates. During 2017, no borrowings were outstanding on our revolving bank credit facility. Our derivative instruments currently consist of commodity swap contracts for oil. We do not enter into derivative instruments for speculative trading purposes. We entered into commodity derivatives contracts during 2017, which were settled or expired during 2017. As of December 31, 2017 and 2016, we did not have any open derivative financial instruments.
In accordance with GAAP, a derivative is91
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Derivative instruments are recorded on the balance sheet as an asset or a liability at its fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into. WeWhenever we have electedentered into derivative contracts, we did not to designate our commodity derivatives as hedging instruments, therefore, all changes in fair value are recognized in earnings.
Fair Value of Financial Instruments
We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments. We believe the carrying amount of debt under our revolving bank credit facility11.00% 1.5 Lien Term Loan, due November 2019, (the “1.5 Lien Term Loan”) approximates fair value because of the interest rates are variable and reflective of market rates.
78
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
debt’s superior collateral ranking amongst our various debt instruments even though such debt was not traded.
Fair Value of Acquisitions
Acquisitions are recorded on the closing date of the transaction at their fair value, which is determined by applying the market and income approaches using Level 3 inputs. The Level 3 inputs are: (i) analysis of comparable transactions obtained from various third-parties, (ii) estimates of ultimate recoveries of reserves, and (iii) estimates of discounted cash flows based on estimated reserve quantities, reserve categories, timing of production, costs to produce and develop reserves, future prices, ARO and discount rates. The estimates and assumptions are determined by management and third-parties. The fair value is based on subjective estimates and assumptions, which are inherently imprecise, and the actual realized values can vary significantly from estimates that are made. No goodwill was recorded for the acquisitions completed in 2014, 2013 or 2012.
Income Taxes
We use the liability method of accounting for income taxes in accordance with the Income Taxes topic of the Accounting Standard Codification. Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. The effects of changes in tax rates and laws on deferred tax balances are recognized in the period in which the new legislation is enacted. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken. When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense. See Note 12 for additional information.
Other Assets (long-term)
The major categories recorded in Other assets are presented in the following table (in thousands):
| December 31, |
| |||||
| 2017 |
|
| 2016 |
| ||
Escrow deposit - Apache lawsuit | $ | 49,500 |
|
| $ | — |
|
Appeal bond deposits |
| 6,925 |
|
|
| 6,925 |
|
Investment in White Cap, LLC |
| 2,511 |
|
|
| 2,520 |
|
Other |
| 1,457 |
|
|
| 2,019 |
|
Total other assets | $ | 60,393 |
|
| $ | 11,464 |
|
92
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The major categories recorded in Accrued liabilities are presented in the following table (in thousands):
| December 31, |
| |||||
| 2017 |
|
| 2016 |
| ||
Accrued interest | $ | 4,200 |
|
| $ | 4,189 |
|
Accrued salaries/payroll taxes/benefits |
| 2,454 |
|
|
| 2,777 |
|
Incentive compensation plans |
| 7,366 |
|
|
| — |
|
Litigation accruals |
| 3,480 |
|
|
| 1,891 |
|
Other |
| 430 |
|
|
| 343 |
|
Total accrued liabilities | $ | 17,930 |
|
| $ | 9,200 |
|
Troubled Debt Restructuring
We accounted for a debt exchange transaction in 2016, which is described in Note 2, as a troubled debt restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”). Under ASC 470-60, the carrying value of the New Debt (as defined in Note 2) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense has been recorded for the newly issued debt in the Consolidated Statements of Operations since September 7, 2016. Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on this debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments beginning on September 7, 2016 and through the maturities of the New Debt. See Note 2 for additional information.
Debt Issuance Costs
Debt issuance costs associated with our revolving loanbank credit facility are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. Unamortized debt issuance costs associated with our revolving bank credit facility is reported within Other Assets (noncurrent) and unamortized debt issuance costs associated with our other debt is reported as a reduction in Long-term debt, less current maturities in the Consolidated Balance Sheets. See Note 2 for additional information.
Premiums Received and Discounts Provided on Debt Issuance
Premiums and discounts are recorded in long-term liabilitiesLong-term debt, less current maturities in the Consolidated Balance Sheets and are amortized over the term of the related debt using the effective interest method.
Other Liabilities (long-term)
The major categories recorded in Other liabilities are presented in the following table (in thousands):
| December 31, |
| |||||
| 2017 |
|
| 2016 |
| ||
Apache lawsuit | $ | 49,500 |
|
| $ | — |
|
Uncertain tax positions including interest/penalties |
| 11,015 |
|
|
| 10,584 |
|
Other |
| 6,351 |
|
|
| 6,521 |
|
Total other liabilities (long-term) | $ | 66,866 |
|
| $ | 17,105 |
|
93
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In accordance with GAAP, compensationCompensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant. The fair value of equity instruments subject to market-based performance measurements was determined using a Monte Carlo simulation probabilistic model. We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award. Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 1110 for moreadditional information.
Earnings (Loss) Per Share
In accordance with GAAP, unvestedUnvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings (loss) per share under the two-class method.method when the effect is dilutive. For additional information, refer to Note 14.13.
Other Income,(Income) Expense, Net
For 2013,2017, the amount reported consistedconsists primarily of $9.2expense items related to the Apache lawsuit of $6.3 million, receivedpartially offset by loss-of-use reimbursements from a third-party for damages incurred at one of our platforms of $1.1 million. For 2016, the amount includes $7.7 million of income related to the settlement of certain insurance claims. In 2016 and 2015, the amount includes write-offs of debt issuance costs of $1.4 million and $3.2 million, respectively, related to a reduction in conjunction with a payment forthe borrowing base of the revolving bank credit facility under the Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”). The write-offs of debt issuance costs in both 2016 and 2015 are included as an option exercisedadjustment to net income in determining Net cash provided by a counterparty. Partially offsetting the proceeds were related third-party expenses of $0.1 million. The net amount was included in net cash flows from investingoperating activities within the line, Proceeds from sales of assets and other, net in the consolidated statementsConsolidated Statements of cash flows.
79
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cash Flows as the write-offs were non-cash transactions.
Recent Accounting Developments
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Topic 606) (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, 2016.2017. Upon application,adoption, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application. Weapplication (modified retrospective approach). Our analysis of contracts with customers against the requirements of ASU 2014-09 is complete and we have not determinedidentified any changes to the effecttiming of revenue recognition, or any changes to the classification of transactions previously recorded as revenue or credits to expense based on requirements of the standard. Therefore, the implementation of ASU 2014-09 will not have a material impact on our consolidated financial statements. We will adopt ASU 2014-09 using the recognitionmodified retrospective method that requires application of our revenue,the new standard prospectively from the date of adoption with a cumulative effect adjustment, if any, nor have we determined the method we will utilize upon adoption, which would be in the first quarterrecorded to retained earnings as of 2017.January 1, 2018 and revise our disclosures under ASU 2014-09 as applicable.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15 (“ASU 2014-15”), Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). The guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. We do not expect the revised guidance to materially affect our evaluation as to being a going concern, or have an effect on our financial statements or related disclosures.
2. Acquisitions and Divestitures
2014 Acquisitions
Fairway
On September 15, 2014, the Parent Company entered into an asset purchase agreement with a third party to increase its ownership interest from 64.3% to 100% in the Mobile Bay blocks 113 and 132 located offshore Alabama (the “Fairway Field”) and the associated Yellowhammer gas processing plant (collectively, “Fairway”). The Fairway Field is located in the state waters of Alabama and the Yellowhammer gas processing plant is located in the state of Alabama. The effective date of the transaction was July 1, 2014. The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO. The purchase price was finalized during the fourth quarter of 2014. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.
The following table presents the preliminary purchase price allocation, including estimated adjustments, for the increased ownership interest in Fairway (in thousands):
Cash consideration: |
|
|
|
Evaluated properties including equipment | $ | 17,407 |
|
Non-cash consideration: |
|
|
|
Asset retirement obligations - non-current |
| 6,124 |
|
Total consideration | $ | 23,531 |
|
The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value. See Note 1 for a description of the Level 3 inputs. No goodwill was recorded in connection with the acquisition of this additional working interest in Fairway.
Woodside Properties
On May 20, 2014, Energy VI entered into a purchase and sale agreement to acquire certain oil and natural gas property interests from Woodside Energy (USA) Inc. (“Woodside”). The properties acquired from Woodside (the “Woodside Properties”) consisted of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks. All of the Woodside Properties are located in the Gulf of Mexico. The effective date of the transaction was November 1, 2013. The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.
8094
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presentsIn February 2016, the purchase price allocation, including estimated adjustments,FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases (Subtopic 842). Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Consistent with current GAAP, the acquisitionrecognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. However, unlike current GAAP, which requires only capital leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet. ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements. ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources. Our current operating leases that will be impacted by ASU 2016-02 are leases for office space in Houston, Texas and New Orleans, Louisiana, although ASU 2016-02 may impact the accounting for leases related to equipment depending on the term of the Woodside Properties (in thousands):
Cash consideration: |
|
|
|
Evaluated properties including equipment | $ | 52,167 |
|
Unevaluated properties |
| 2,660 |
|
Sub-total cash consideration |
| 54,827 |
|
Non-cash consideration: |
|
|
|
Asset retirement obligations - current |
| 782 |
|
Asset retirement obligations - non-current |
| 10,543 |
|
Sub-total non-cash consideration |
| 11,325 |
|
Total consideration | $ | 66,152 |
|
The acquisition waslease. We currently do not have any leases classified as financing leases nor do we have any leases recorded at fair value, which was determined using bothon the market and income approaches, and Level 3 inputs were used to determine fair value. See Note 1Condensed Consolidated Balance Sheets. ASU 2016-02 is effective for a description of the Level 3 inputs. No goodwill was recorded in connection with the Woodside Properties acquisition.
2014 Acquisitions — Revenues, Net Income and Pro Forma Financial Information - Unaudited
The increase in working interest ownership for Fairway was not included in our consolidated results until the property transfer date, which occurred in September 2014 and the incremental revenue and operating expenses were immaterial for 2014. Unaudited pro forma information is not presented as the pro forma information is not materially different from the reported results for 2014 and 2013.
The Woodside Properties were not included in our consolidated results until the property transfer date, which occurred on May 20 2014. For the period of May 20, 2014 to December 31, 2014, the Woodside Properties accounted for $28.4 million of revenues, $5.5 million of direct operating expenses, $11.0 million of DD&A and $4.2 million of income taxes, resulting in $7.7 million of net income. The net income attributable to the Woodside Properties does not reflect certain expenses, such as general and administrative expenses (“G&A”) and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. In addition, the Woodside Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate.
In accordance with the applicable accounting guidance, the unaudited pro forma financial information was computed as if the acquisition of the Woodside Properties had been completed on January 1, 2013. The financial information was derived from W&T’s audited historical consolidated financial statements for annual periods, W&T’s unaudited historical condensed consolidated financial statements for interim periods, and the Woodside Properties’ unaudited historical financial statements for the annual and interim periods.
The pro forma adjustments were based on estimates by managementperiods beginning after December 15, 2018 and information believedis to be directly relatedapplied using the modified retrospective approach. We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.
In June 2016, the FASB issued Accounting Standards Update No. 2016-13, (“ASU 2016-13”), Financial Instruments – Credit Losses (Subtopic 326). The new guidance eliminates the probable recognition threshold and broadens the information to consider past events, current conditions and forecasted information in estimating credit losses. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted for fiscal years beginning after December 15, 2018. We have not yet fully determined or quantified the purchaseeffect ASU 2016-13 will have on our financial statements.
In August 2016, the FASB issued Accounting Standards Update No. 2016-15, (“ASU 2016-15”), Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 addresses the classification of several items that previously had diversity in practice. Items identified in the new standard which were incurred by us in the past are: (a) debt prepayment or extinguishment costs; (b) contingent consideration made after a business acquisition; and (c) proceeds from settlement of insurance claims. The item described in clause (b) would be the only such item changed under our historical classification in the statement of cash flows (financing vs. investing) and the amount of such change would not have been material; therefore, we do not anticipate the new standard will have a material effect on our financial statements. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017 and early adoption is permitted.
In November 2016, the FASB issued Accounting Standards Update No. 2016-18, (“ASU 2016-18”), Statement of Cash Flows (Topic 230) – Restricted Cash. ASU 2016-18 addresses diversity in practice and requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. ASU 2016-18 is expected to change some of the Woodside Properties.presentation in our statement of cash flows, but not materially impact total cash flows from operating, investing or financing activities. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period.
In August 2017, the FASB issued Accounting Standards Update No. 2017-12, (“ASU 2017-12”), Derivatives and Hedging (Topic 815) – Targeted Improvements to Accounting for Hedging Activities. The pro forma financial information is not necessarily indicativeamendments in ASU 2017-12 require an entity to present the earnings effect of the resultshedging instrument in the same income statement line in which the earning effect of operations had the purchase occurred on January 1, 2013. Had we owned the Woodside Properties during the periods indicated,hedged item is reported. This presentation enables users of financial statements to better understand 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 operatingan entity’s hedging program. Also, relative to current GAAP, this approach simplifies the Woodside Properties may have been different.
The following table presents a summaryfinancial statement reporting for qualifying hedging relationships. As we do not designate our commodity derivative positions as qualifying hedging instruments, our assessment is this amendment will not impact the presentation of the changes in fair values of our pro formacommodity derivative instruments on our financial information (in thousands, except earnings per share):statements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2019 and interim periods within fiscal years beginning after December 15, 2020. Early adoption is permitted, including adoption in an interim period.
|
| (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 |
|
8195
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. 2. Long-Term Debt
The following table presents incremental items includedcomponents of our long-term debt are presented in the pro forma information reported above for the Woodside Propertiesfollowing tables (in thousands):
|
| (unaudited) |
| |||||
|
| Year Ended December 31, |
| |||||
|
| 2014 (a) |
|
| 2013 |
| ||
Revenues (b) |
| $ | 22,887 |
|
| $ | 62,949 |
|
Direct operating expenses (b) |
|
| 4,417 |
|
|
| 9,583 |
|
DD&A (c) |
|
| 8,374 |
|
|
| 20,476 |
|
G&A (d) |
|
| 300 |
|
|
| 800 |
|
Interest expense (e) |
|
| 329 |
|
|
| 987 |
|
Capitalized interest (f) |
|
| (19 | ) |
|
| 164 |
|
Income tax expense (g) |
|
| 3,320 |
|
|
| 10,829 |
|
| December 31, 2017 |
|
| December 31, 2016 |
| ||||||||||||||||||
|
|
|
|
| Adjustments to |
|
|
|
|
|
|
|
|
|
| Adjustments to |
|
|
|
|
| ||
|
|
|
|
| Carrying |
|
| Carrying |
|
|
|
|
|
| Carrying |
|
| Carrying |
| ||||
| Principal |
|
| Value (1) |
|
| Value |
|
| Principal |
|
| Value (1) |
|
| Value |
| ||||||
11.00% 1.5 Lien Term Loan, due November 2019: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal | $ | 75,000 |
|
| $ | — |
|
| $ | 75,000 |
|
| $ | 75,000 |
|
| $ | — |
|
| $ | 75,000 |
|
Future interest payments |
| — |
|
|
| 15,596 |
|
|
| 15,596 |
|
|
| — |
|
|
| 23,823 |
|
|
| 23,823 |
|
Subtotal |
| 75,000 |
|
|
| 15,596 |
|
|
| 90,596 |
|
|
| 75,000 |
|
|
| 23,823 |
|
|
| 98,823 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9.00 % Second Lien Term Loan, due May 2020: |
| 300,000 |
|
|
| — |
|
|
| 300,000 |
|
|
| 300,000 |
|
|
| — |
|
|
| 300,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal |
| 171,769 |
|
|
| — |
|
|
| 171,769 |
|
|
| 163,007 |
|
|
| — |
|
|
| 163,007 |
|
Future payments-in-kind |
| — |
|
|
| 5,745 |
|
|
| 5,745 |
|
|
| — |
|
|
| 24,048 |
|
|
| 24,048 |
|
Future interest payments |
| — |
|
|
| 34,872 |
|
|
| 34,872 |
|
|
| — |
|
|
| 36,850 |
|
|
| 36,850 |
|
Subtotal |
| 171,769 |
|
|
| 40,617 |
|
|
| 212,386 |
|
|
| 163,007 |
|
|
| 60,898 |
|
|
| 223,905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal |
| 153,192 |
|
|
| — |
|
|
| 153,192 |
|
|
| 145,897 |
|
|
| — |
|
|
| 145,897 |
|
Future payments-in-kind |
| — |
|
|
| 11,323 |
|
|
| 11,323 |
|
|
| — |
|
|
| 26,844 |
|
|
| 26,844 |
|
Future interest payments |
| — |
|
|
| 38,682 |
|
|
| 38,682 |
|
|
| — |
|
|
| 40,705 |
|
|
| 40,705 |
|
Subtotal |
| 153,192 |
|
|
| 50,005 |
|
|
| 203,197 |
|
|
| 145,897 |
|
|
| 67,549 |
|
|
| 213,446 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.50% Unsecured Senior Notes, due June 2019 |
| 189,829 |
|
|
| — |
|
|
| 189,829 |
|
|
| 189,829 |
|
|
| — |
|
|
| 189,829 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt premium, discount, issuance costs, net of amortization |
| — |
|
|
| (3,956 | ) |
|
| (3,956 | ) |
|
| — |
|
|
| (5,276 | ) |
|
| (5,276 | ) |
Total long-term debt |
| 889,790 |
|
|
| 102,262 |
|
|
| 992,052 |
|
|
| 873,733 |
|
|
| 146,994 |
|
|
| 1,020,727 |
|
Current maturities of long-term debt (2) |
| — |
|
|
| 22,925 |
|
|
| 22,925 |
|
|
| — |
|
|
| 8,272 |
|
|
| 8,272 |
|
Long term debt, less current maturities | $ | 889,790 |
|
| $ | 79,337 |
|
| $ | 969,127 |
|
| $ | 873,733 |
|
| $ | 138,722 |
|
| $ | 1,012,455 |
|
The sources of information and significant assumptions are described below:
|
| Future interest payments and future payments-in-kind (“PIK”) are |
|
|
|
|
|
|
|
|
|
|
|
|
The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures.
Aggregate annual maturities of amounts recorded for long-term debt as of December 31, 2017 are as follows (in millions): 2018–$22.9; 2019–$302.1; 2020–$499.5; 2021–$171.5. See below for a discussion of our debt instruments.
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.
8296
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our 8.500% Senior Notes, due June 15, 2019 (the “Unsecured Senior Notes”), for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Senior Second Lien PIK Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); (ii) $142.0 million in aggregate principal amount of 8.50%/10.00% Senior Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”); and (iii) 60.4 million shares of our common stock (collectively, the “Debt Exchange”). At the same time on closing on the Debt Exchange, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 2019, 1.5 Lien Term Loan with the then largest holder of our Unsecured Senior Notes (collectively with the Debt Exchange, the “Exchange Transaction”). We accounted for the Exchange Transaction as a Troubled Debt Restructuring pursuant to the guidance under ASC 470-60. Under ASC 470-60, the carrying value of the Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Consolidated Statements of Operations since September 7, 2016. Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the maturities of the New Debt. Under ASC 470-60, payments related to the New Debt are reported in the financing section of the Condensed Consolidated Statements of Cash Flows.
A gain of $123.9 million was recognized related to the Exchange Transaction during 2016. Under ASC 470-60, a gain was recognized as the sum of (i) the future undiscounted payments (principal and interest) related to the New Debt, (ii) the fair value of the common stock issued and (iii) deal transaction costs of $18.9 million was less than the sum of (iv) the carrying value of the Unsecured Senior Notes exchanged and (v) the funds received from the 1.5 Lien Term Loan. The shares of common stock issued were valued at $1.76 per share, which was the closing price on September 7, 2016. The effect on both basic and diluted earnings per share for 2016 was $1.30 per share, which assumes the gain would not affect our income tax benefit for 2016.
The following table presentsfunds received from 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 inputs1.5 Lien Term Loan were used to determine fair value. See Note 1 for a description of the Level 3 inputs. No goodwill was recorded in connection with the acquisition of the Callon Properties.
2013 Acquisition — Revenues, Net Income and Pro Forma Financial Information — Unaudited
The Callon Properties were not included in our consolidated results until the respective property transfer dates, which occurred during the fourth quarter of 2013. In 2014, the Callon Properties accounted for $32.5 million of revenue, $6.6 million of direct operating expenses, $16.4 million of DD&A and $3.3 million of income taxes, resulting in $6.2 million of net income. In the fourth quarter of 2013, the Callon Properties accounted for $5.8 million of revenues, $1.3 million of direct operating expenses, $2.4 million of DD&A and $0.7 million of income taxes, resulting in $1.4 million of net income. The net income attributable to these properties does not reflect certain expenses, such as G&A and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. In addition, the Callon Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate.
The unaudited pro forma financial information presented below was computed as if the acquisition of the Callon Properties had been completed on January 1, 2012. The financial information was derived from W&T’s audited historical consolidated financial statements, the Callon Properties’ audited historical financial statement, and the Callon Properties’ unaudited historical financial statement for the periods presented.
The pro forma adjustments were based on estimates by management and information believed to be directlypay transaction costs related to the purchaseExchange Transaction and to pay down borrowings on the revolving bank credit facility. The balance of the Callon Properties. The pro forma financial information is not necessarily indicativeborrowings on the revolving bank credit facility was paid down from available cash.
During the second quarter of 2017, interest on the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes was paid in cash rather than in kind. As a result of the results of operations hadcash interest payment, an $8.2 million net reduction was recorded to long-term debt on the purchase occurred on January 1, 2012. If the transaction had been in effect for the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than Callon; the realized sales prices for oil, NGLs and natural gas may have been different;Consolidated Balance Sheet and the costsoffset to Gain on exchange of operatingdebt in the Callon Properties may have been different. Consolidated Statement of Operations. We anticipate the remaining eligible interest payments will be made in kind versus paid in cash. For 2017, $0.4 million of additional expense was recorded to Gain on exchange of debt for differences between actual and estimated transaction expenses. The effect of these transactions on both basic and diluted earnings per share for 2017 was $0.06 per share, which assumes the net gain would not affect our income tax benefit for that period.
The following table presents a summaryprimary terms 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 |
|
long-term debt following the Exchange Transaction are described below.
8397
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ForThe Credit Agreement provides a revolving bank credit facility. Availability under the Credit Agreement is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. We and our lenders may request one additional determination per year. The borrowing base as of December 31, 2017 was $150.0 million. Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility. To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base, such excess or deficiency is required to be repaid within 90 days in three equal monthly payments. Letters of credit may be issued in amounts up to $150.0 million, provided availability under the revolving bank credit facility exists. The revolving bank credit facility is secured and is collateralized by a first priority lien on substantially all of our oil and natural gas properties. The Credit Agreement matures on November 8, 2018.
The Credit Agreement contains covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock or outstanding debt; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) eliminate certain hedging contracts or enter into certain hedging contracts in excess of 75% of projected oil and gas production on a monthly basis; (vii) enter into certain liens; and (viii) enter into certain other transactions, without the prior consent of the lenders. We are permitted to issue additional indebtedness if certain conditions are met including: (i) the additional debt is subordinate in security and right of payment; (ii) the borrowers enter into an intercreditor agreement with terms acceptable to the Administrative Agent of the Credit Agreement; (iii) we are in compliance with the financial covenants after giving pro forma financial information, certain information was derived from financial recordseffect to the additional indebtedness; and certain information was estimated. The following table presents incremental items included(iv) such additional unsecured indebtedness matures at least six months after the maturity date of the Credit Agreement and is not subject to restrictive covenants materially more onerous than those provided for in the pro forma information reported above forCredit Agreement. With consent of the Callon Properties (in thousands):
| (unaudited) |
| |||||
| Year Ended December 31, |
| |||||
| 2013 (a) |
|
| 2012 |
| ||
Revenues (b) | $ | 34,030 |
|
| $ | 48,559 |
|
Direct operating expenses (b) |
| 6,405 |
|
|
| 8,525 |
|
DD&A (c) |
| 14,931 |
|
|
| 17,578 |
|
G&A (d) |
| (361 | ) |
|
| — |
|
Interest expense (e) |
| 1,383 |
|
|
| 1,660 |
|
Capitalized interest (f) |
| (164 | ) |
|
| 295 |
|
Income tax expense (g) |
| 4,143 |
|
|
| 7,175 |
|
The sources of information and significant assumptions are described below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The pro forma adjustments dolenders, such limitation will 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. Dueapply to the lengthrepurchase of time fromour existing debt in an aggregate principal amount equal to or less than the effective date, we paid $4.3 millionaggregate principal amount of any new issuance of such debt. We are permitted 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 $15.6redeem, repurchase, prepay or defease up to $35 million of our ARO.Unsecured Senior Notes if after giving effect to such redemption, repayment, prepayment or defeasance: (i) no amounts are outstanding on the revolving bank credit facility; (ii) letters of credit outstanding do not exceed $5 million; (iii) the Consolidated Cash balance is at least $35 million after the redemption or repayment; and (iv) no event of default shall have occurred and be continuing, and no borrowing base deficiency shall have occurred and be continuing or result therefrom.
On September 26, 2013, we sold our working interestsThe Credit Agreement also contains various customary covenants for certain financial tests, as defined in the West Delta area block 29Credit Agreement and measured as of the end of each quarter, and for customary events of default. These financial test ratios and limits as of December 31, 2017 and thereafter are: (i) the First Lien Leverage Ratio must be less than 2.00 to 1.00; and (ii) the Current Ratio must be greater than 1.00 to 1.00. As of December 31, 2017, the Current Ratio was 2.80 to 1.00. As of December 31, 2017, the First Lien Leverage Ratio was in compliance, but not meaningful as no borrowings were outstanding on the revolving bank credit facility and only minor amounts of letters of credit were outstanding. The customary events of default include: (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with an effective daterespect to the Company or any 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 exchangeits subsidiaries guaranteeing borrowings under the Internal Revenue Service Code (“IRC”) Section 1031revolving bank credit facility; or (iii) a change of control. The Credit Agreement contains cross-default clauses with the other debt agreements, and otherthese agreements contain similar cross-default clauses with the Credit Agreement. We were in compliance with all applicable regulations,covenants of the Credit Agreement as of December 31, 2017.
We are required to have deposit accounts only with funds held by a qualified intermediary until replacement purchasesbanks party to the Credit Agreement with certain exceptions. We may not have unrestricted cash balances above $35 million if outstanding balances on the revolving bank credit agreement (including letters of credit) are 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.greater than $5 million.
84
98
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 inBorrowings under 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 bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 3.00% to 4.00% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the greater of (a) Prime Rate, (b) Federal Funds Rate plus 0.50%, or (c) LIBOR plus 1.0%, plus applicable margin ranging from 2.00% to 3.00%. The unused portion of the borrowing base is subject to a commitment fee of 0.50%.
During 2016 and cash on hand. Subsequently2015, the borrowing base under the Credit Agreement was reduced. The reductions in the same month,borrowing base resulted in proportional reductions in the amounts borrowedunamortized costs related to the Credit Agreement of $1.4 million and $3.2 million in 2016 and 2015, respectively, which is included in the line Other (income)/expense, net on the Consolidated Statements of Operations.
At December 31, 2017 and 2016, we had no borrowings outstanding under ourthe revolving bank credit facility were paid downfacility. At December 31, 2017 and 2016, we had $0.3 million and $0.5 million, respectively, outstanding in letters of credit under the revolving bank credit facility.
1.5 Lien Term Loan
As part of the Exchange Transaction, we entered into the 1.5 Lien Term Loan on September 7, 2016 with funds provided froma maturity date of November 15, 2019. The maturity date will accelerate to February 28, 2019 if the issuanceremaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. Certain amendments under the 1.5 Lien Term Loan and the Credit Agreement will likely be required in the event replacement financing is not utilized. Interest accrues at 11.00% per annum and is payable quarterly in cash. The holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction. The 1.5 Lien Term Loan is secured by a 1.5 priority lien on all of our assets pledged under the Credit Agreement. The lien securing the 1.5 Lien Term Loan is subordinate to the liens securing the Credit Agreement and has priority above the liens securing the Second Lien Term Loan (defined below), the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes. All future undiscounted cash flows have been included in the carrying value under ASC 470-60. Current maturities of our long-term debt in October 2012. See Note 7 for information on long-term debt.
The following table presentsinclude the purchase price allocation, including adjustments,cash interest payable for the acquisition1.5 Lien Term Loan payable in the next 12 months. The 1.5 Lien Term Loan contains various covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) enter into certain liens; and (vii) enter into transactions with affiliates. We were in compliance with those covenants as of December 31, 2017.
Second Lien Term Loan
In May 2015, we entered into 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 |
|
9.00% Term Loan (the “Second Lien Term Loan”), which bears an annual interest rate of 9.00%. The acquisitionSecond Lien Loan was issued at a 1.0% discount to par, matures on May 15, 2020 and is recorded at fairits carrying value consisting of principal, unamortized discount and unamortized debt issuance costs. Interest on the Second Lien Term Loan is payable in arrears semi-annually on May 15 and November 15. The estimated annual effective interest rate on the Second Lien Term Loan is 9.6%, which was determined using bothincludes amortization of debt issuance costs and discounts. The Second Lien Term Loan is secured by a second-priority lien on all of our assets that are secured under the marketCredit Agreement. The Second Lien Term Loan is effectively subordinate to the Credit Agreement and income approaches,the 1.5 Lien Term Loan (discussed above) 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.
Consistenteffectively pari passu with the computationSecond Lien PIK Toggle Notes (discussed below). The Second Lien Term Loan contains covenants that restrict our ability and the ability of pro forma financial information presentedcertain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. We were in Item 8, Financial Statements and Supplementary Data, in the Annual Report on Form 10-K for the year endcompliance with all applicable covenants as of 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.2017.
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.
8599
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As part of the Exchange Transaction, we issued Second Lien PIK Toggle Notes on September 7, 2016, with a maturity date of May 15, 2020. Cash interest accrues at 9.00% per annum and is payable on May 15 and November 15 of each year. The following table presentsSecond Lien PIK Toggle Notes contain payment-in-kind interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period. This payment-in-kind provision expires on March 7, 2018. For the initial interest payment on November 15, 2016, interest could only be paid-in-kind at 10.75% per annum. For the six month interest period ending May 15, 2017, we paid the interest payment in cash rather than using the payment-in-kind provision. For the six-month period ended November 15, 2017, we exercised the payment-in-kind provision. For the interest period ending May 15, 2018, we have exercised the payment-in-kind provision to pay interest through March 7, 2018, and, thereafter, interest will be paid in cash. When the PIK option is utilized, the principal amount of the notes increases. The Second Lien PIK Toggle Notes are secured by a summarysecond-priority lien on all of our pro forma financial information (in thousands except earningsassets that are pledged under the Credit Agreement. The Second Lien PIK Toggle Notes are effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and are effectively pari passu with the Second Lien Term Loan (discussed above). Current maturities of long-term debt as of December 31, 2017 include the cash interest payable for the Second Lien PIK Toggle Notes for the next 12 months. The Second Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. We were in compliance with all applicable covenants as of December 31, 2017.
Third Lien PIK Toggle Notes
As part of the Exchange Transaction, we issued Third Lien PIK Toggle Notes on September 7, 2016, with a maturity date of June 15, 2021. The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. Certain amendments under the 1.5 Lien Term Loan and the Credit Agreement will likely be required in the event replacement financing is not utilized. Cash interest accrues at 8.50% per share):
|
| (unaudited) |
| |
|
| Year Ended December 31, 2012 |
| |
Revenue |
| $ | 980,196 |
|
Net income |
|
| 77,036 |
|
Basic and diluted earnings per common share |
|
| 1.01 |
|
annum and is payable on June 15 and December 15 of each year. The Third Lien PIK Toggle Notes contain PIK interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period. This payment-in-kind provision expires on September 7, 2018. For the pro forma financial information,initial interest payment on December 15, 2016, interest could only be paid-in-kind at 10.00% per annum. For the six month interest period ending June 15, 2017, we paid the interest payment in cash rather than using the payment-in-kind provision. For the six-month period ended November 15, 2017, we exercised the payment-in-kind provision. For the six-month period ended June 15, 2018, we have exercised the payment-in-kind provision. When the PIK option is utilized, the principal amount of the notes increases. The Third Lien PIK Toggle Notes are secured by a third-priority lien on all of our assets that are secured under the Credit Agreement. The Third Lien PIK Toggle Notes are effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes. For purposes of determining the carrying amount under ASC 470-60, we anticipate the remaining eligible interest payments will be paid-in-kind versus paid in cash. The Third Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain information was derived from financial recordsof our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and certain information was estimated. The following table presents incremental items included(vii) merge or consolidate with another company. We were 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 sourcescompliance with all applicable covenants as of information and significant assumptions are described below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The pro forma adjustments do not included adjustments related to any other acquisitions or divestitures.December 31, 2017.
86100
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2012 Divestiture
On MayAt December 31, 2017 and 2016, our outstanding Unsecured Senior Notes, which bear an annual interest rate of 8.50% and mature on June 15, 2012,2019, were classified as long-term at their carrying value. The Unsecured Senior Notes are currently redeemable at par. Subject to limited exceptions, our 1.5 Lien Term Loan and Credit Agreement restrict us from using cash on hand to repay or repurchase our Unsecured Senior Notes prior to their stated maturity, although we soldcan generally refinance our 40%, non-operated working interestUnsecured Senior Notes with new indebtedness within customary parameters. Certain amendments under the 1.5 Lien Term Loan and the Credit Agreement will likely be required in the South Timbalier 41 field locatedevent replacement financing is not utilized. Interest on the Unsecured Senior Notes is payable semi-annually in arrears on June 15 and December 15. The estimated annual effective interest rate on the GulfUnsecured Senior Notes is 8.3%, which includes amortization of Mexico for $30.5 million, net, with an effective datedebt issuance costs and premiums. The Unsecured Senior Notes contain covenants that restrict our ability and the ability of April 1, 2012. The transaction was structured as a like-kind exchange under the IRC Section 1031 and other applicable regulations, with funds held by a qualified intermediary until replacement purchases could be executed. Replacement purchases were consummated during 2012, which were within the replacement periods as defined under the IRC. In connection with this sale, we reversed $4.0 million of ARO.
3. Hurricane Remediation and Insurance Claims
During the third quarter of 2008, Hurricane Ike caused substantial damage to certain of our properties. Our insurance policies in effectsubsidiaries to: (i) incur additional debt; (ii) make payments or distributions on the occurrence dateaccount of Hurricane Ike had a retention requirementour or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of $10.0 million per occurrence, which has been satisfied,our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.
For 2014, 2013 and 2012, we have received insurance proceeds of $12.2 million, $6.7 million and $2.9 million, respectively. These amounts are included within Net cash provided by operating activities in the Consolidated Statement of Cash Flows and are primarily recorded as reductions in Oil and natural gas properties and equipment on the Consolidated Balance Sheets,(vii) merge or consolidate with minor amounts recorded as reductions in Lease operating expense in the Consolidated Statements of Operations. From the third quarter of 2008 through December 31, 2014, we have received $161.2 million cumulative from our insurance underwriters related to Hurricane Ike. See Note 18 for information regarding legal actions involving certain insurers and the Company concerning claims related to Hurricane Ike damages.
4. Restricted Deposits
Restricted deposits as of December 31, 2014 and 2013 consisted of funds escrowed for the future plugging and abandonment of certain oil and natural gas properties.
Pursuant to the Purchase and Sale Agreement with Total E&P USA Inc. (“Total E&P”), security for future plugging and abandonment of certain oil and natural gas properties is required either through bonds or payments to an escrow account or a combination thereof. Monthly payments are made to an escrow account and these funds are returned to us once verification is made that the security amount requirements have been met.another company. We were in compliance with the security requirementsall applicable covenants as of December 31, 2014. See2017.
For information about fair value measurements of our long-term debt, refer to Note 163.
3. Fair Value Measurements
Under GAAP, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether using an in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk.
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 potential future security requirements.the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:
Level 1 – quoted prices in active markets for identical assets or liabilities.
Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).
Level 3 – unobservable inputs that reflect our expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.
The following table presents the fair value of our long-term debt (in thousands):
|
|
| December 31, |
| |||||
| Hierarchy |
| 2017 |
|
| 2016 |
| ||
11.00% 1.5 Lien Term Loan, due November 2019 | Level 2 |
| $ | 75,000 |
|
| $ | 75,000 |
|
9.00 % Second Lien Term Loan, due May 2020 | Level 2 |
|
| 288,000 |
|
|
| 255,000 |
|
9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 | Level 2 |
|
| 162,322 |
|
|
| 122,255 |
|
8.50%/10.00% Third Lien PIK Toggle Notes due June 2021 | Level 2 |
|
| 119,490 |
|
|
| 80,243 |
|
8.50% Unsecured Senior Notes, due June 2019 | Level 2 |
|
| 178,439 |
|
|
| 123,389 |
|
101
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5.The fair value of long-term debt is based on quoted prices, although the market is not an active market; therefore, the fair value is classified within Level 2. An exception is the fair value of the 1.5 Lien Term Loan, which is held by one entity, and has not traded since its inception in September 2016. We believe the carrying amount of debt under our 1.5 Lien Term Loan approximates fair value because of the debt’s superior collateral ranking amongst our debt instruments even though such debt was not traded. Given the relatively short time until maturity, having an interest rate higher than any our other debt instruments and having superior collateral ranking over our other debt instruments, we assessed the fair value of the 1.5 Lien Term Loan to be at least equivalent to its carrying value.
As of December 31, 2017 and 2016, there were no open derivatives financial instruments.
The carrying value of our long-term debt is disclosed in Note 2 above.
4. Asset Retirement Obligations
Pursuant to GAAP, an assetAsset retirement obligationobligations associated with the retirement of a tangible long-lived asset isassets are required to be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The fair value of the ARO is measured using expected cash outflows associated with the ARO, discounted at our credit-adjusted risk-free rate when the liability is initially recorded. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.
87The following table is a reconciliation of our ARO liability (in thousands):
| Year Ended December 31, |
| |||||
| 2017 |
|
| 2016 |
| ||
Asset retirement obligations, beginning of period | $ | 334,438 |
|
| $ | 378,322 |
|
Liabilities settled |
| (72,409 | ) |
|
| (72,320 | ) |
Accretion of discount |
| 17,172 |
|
|
| 17,571 |
|
Liabilities incurred |
| 163 |
|
|
| 398 |
|
Revisions of estimated liabilities |
| 21,082 |
|
|
| 10,467 |
|
Asset retirement obligations, end of period |
| 300,446 |
|
|
| 334,438 |
|
Less current portion |
| 23,613 |
|
|
| 78,264 |
|
Long-term | $ | 276,833 |
|
| $ | 256,174 |
|
During 2017, we decreased our ARO liability on an overall basis primarily due to plug and abandonment work performed during 2017, partially offset by increases from accretion and revisions of previous estimates. Revisions were primarily related to increased costs associated with wells at four fields that experienced sustained casing pressure issues. Wells that experience sustained casing pressure require more days and greater work scope to complete the abandonment project. Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations.
During 2016, we decreased our ARO liability on an overall basis primarily due to plug and abandonment work performed during 2016, partially offset by increases from accretion and revisions of previous estimates. Upward revisions were primarily related to sustained casing pressure issues at our West Cameron fields identified while performing preliminary plug and abandonment work at these fields. In addition, increases were attributable to several non-operated properties under which we have no control. Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations.
102
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following is a reconciliationDuring the third quarter of 2008, Hurricane Ike caused substantial damage to certain of our ARO liability (in thousands):
| 2014 |
|
| 2013 |
| ||
Asset retirement obligations, beginning of period | $ | 354,422 |
|
| $ | 384,053 |
|
Liabilities settled |
| (74,313 | ) |
|
| (81,543 | ) |
Accretion of discount |
| 20,633 |
|
|
| 20,918 |
|
Disposition of properties |
| — |
|
|
| (19,564 | ) |
Liabilities assumed through acquisition |
| 21,820 |
|
|
| 4,233 |
|
Liabilities incurred |
| 3,258 |
|
|
| 1,745 |
|
Revisions of estimated liabilities |
| 64,748 |
|
|
| 44,580 |
|
Asset retirement obligations, end of period |
| 390,568 |
|
|
| 354,422 |
|
Less current portion |
| 36,003 |
|
|
| 77,785 |
|
Long-term | $ | 354,565 |
|
| $ | 276,637 |
|
During 2014, we increased our AROproperties. Our insurance policies in effect on an overall basis primarilythe occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to revisions, acquisitions and accretion of discount. Revisions increased ARO on a net basis primarily attributable to: a) increasesnamed windstorms (excluding damage at certain non-operatedfacilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.
For 2017, 2016 and 2015, we received insurance reimbursements of $31.7 million, $10.2 million and $0.2 million, respectively, primarily related to hurricane damage. Cash receipts from insurance proceeds are included within Net cash provided by operating activities in the Consolidated Statements of Cash Flows and are primarily recorded as reductions in Oil and natural gas properties b) regulation interpretations issued byand equipment on the BureauConsolidated Balance Sheets, with some amounts recorded as reductions in Lease operating expense, General and administrative expenses and Other income (expense), net in the Consolidated Statements of SafetyOperations. From the third quarter of 2008 through December 31, 2017, we have received $203.1 million cumulative reimbursements from insurance companies related to hurricane reimbursements. As of December 31, 2017, there were no outstanding hurricane claims.
6. Restricted Deposits
Restricted deposits as of December 31, 2017 and Environmental Enforcement (“BSEE”), which increased2016 consisted of funds escrowed for collateral related to 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 thefuture plugging and abandonment work than previously estimated due to operational issues. Increases related to acquisitions include the increase in our ownership 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 and the dispositionobligations of certain oil and natural gas properties.
During 2013, we reduced our ARO on an overall basis primarily duePursuant to the plugPurchase and abandonment work performed during the year. In addition, the disposition of certain properties, as described in Note 2, reduced our ARO. The acquisition of the Callon Properties and drilling activity caused ARO to increase. Revisions that increased ARO on a net basis primarily attributable to: a) regulation interpretations issued by the BSEE, which increased the amount of work involved, b) revisions to third-party contractor estimated pricesSale Agreement with Total E&P USA Inc. (“Total E&P”), security for certain work on wells and structures, c) revisions accelerating the timing of planned work for certain wells and d) revisions for certain wells that took longer to complete thefuture plugging and abandonment workof certain oil and natural gas properties is required either through surety bonds or payments to an escrow account or a combination thereof. Monthly payments are made to an escrow account and these funds are returned to us once verification is made that the security amount requirements have been met. See Note 15 for potential future security requirements.
7. Divestitures
2015 Divestiture
On October 15, 2015, we sold certain onshore oil and natural gas property interests to Ajax Resources, LLC (“Ajax”) for approximately $370.9 million in cash, which includes certain customary price adjustments, and Ajax assumed responsibility for the related ARO. The effective date of the sale was January 1, 2015. A net purchase price adjustment of $0.9 million for final customary effective date adjustments was recorded during 2016. Ajax acquired all of our interest in the Yellow Rose field in the Permian Basin, covering approximately 25,800 net acres in Andrews, Martin, Gaines and Dawson counties in West Texas. We retained a non-expense bearing overriding royalty interest (“ORRI”) equal to a variable percentage in production from the working interests assigned to Ajax, which percentage varies on a sliding scale from one percent for each month that the prompt month New York Mercantile Exchange (“NYMEX”) trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than previously estimated due$90.00 per barrel. We used a portion of the proceeds of the sale to operational issues. In addition, increases were maderepay all outstanding borrowings under the revolving bank credit facility, while the remaining balance of approximately $100.0 million was added to available cash.
Under the full-cost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, are accounted for certain locations affected by Hurricane Ikeas adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and increasesproved reserves of oil and natural gas attributable to the cost center. The sale to Ajax did not represent greater than 25% of our proved reserves of oil and natural gas attributable to the full cost pool. As a result, alteration in estimates were made for certain non-operated properties.the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool was not deemed significant and no gain or loss was recognized from the sale.
6.103
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. Derivative Financial Instruments
Our market risk exposure relates primarily to commodity prices and, interest rates. Fromfrom time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility.gas. All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility. We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations. Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders, and we do not require collateral from our derivative counterparties.
In accordance with GAAP, we record eachEach derivative contract is recorded on the balance sheet as an asset or a liability at its fair value.value as of the respective period. We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all changes in the fair value of derivative contracts arewere recognized currently in earnings. The cash flows of all of our commodity derivativeearnings during the periods presented. While these contracts are included in Net cash provided by operating activities onintended to reduce the Consolidated Statementseffects of Cash Flows.price volatility, they may have limited incremental income from favorable price movements.
For information about fair value measurements, refer to Note 8.
88
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Commodity Derivatives
As of December 31, 2014,2017 and 2016, we did not have any open commodityderivative contracts. During the years ended December 31, 2014, 2013 and 2012,2017, we entered into crude oil and natural gas derivative contracts for a portion of our anticipated future production. Some of the commodity derivative contracts are known as “three-way collars” consisting of a purchased put option, a sold call option and thesea purchased call option, each at varying strike prices. The strike prices of the contracts consisted entirelywere set so that the contracts were premium neutral (“costless”), which means no net premium was paid to or received from a counterparty. The three-way collar contracts are structured to provide price risk protection if the commodity price falls below the strike price of the put option and provides us the opportunity to benefit if the commodity price rises above the strike price of the purchased call option. In addition, we entered into oil derivative contracts known as “two-way”, “costless” collars, which consist of a purchased put option and a sold call option. These two-way collars provide price risk protection if crude oil swap contracts. While these contracts were intendedprices fall below certain levels, but have the potential to reduce the effects of price volatility, they may have limitedlimit incremental income from favorable price movements.movements above certain limits. The crude oil swap contracts were comprised of a portionare based on Brent crude oil prices, a portion based on West Texas Intermediate (“WTI”) crude oil prices and a portionas quoted off the NYMEX. The natural gas contracts are based on Light Louisiana Sweet (“LLS”) crude oil prices. The Brent based swap contracts were pricedHenry Hub natural gas prices as quoted off the Brent crude oil price quoted on the Intercontinental Exchange, known as ICE. The WTI based swap contracts were priced off the New York Mercantile Exchange, known as NYMEX. The LLS based swap contracts were priced from data provided by Argus, an independent media organization. Although our Gulf of Mexico crude oil price is based off the WTI crude oil price plus a premium, the realized prices received for our Gulf of Mexico crude oil, up until October 2013, had been closer to the Brent crude oil price because of competition with foreign supplied crude oil, which was based off the Brent crude oil price. Therefore, a portion of the swap oil contracts were priced off the Brent crude oil price to mitigate a portion of the price risk associated with our Gulf of Mexico crude oil production.
The following balance sheet line items included amounts related to the estimated fair value of our open derivative contracts as indicated in the following table (in thousands):
| December 31, |
| |||||
| 2014 |
|
| 2013 |
| ||
Prepaid and other assets | $ | — |
|
| $ | 141 |
|
Accrued liabilities |
| — |
|
|
| 9,423 |
|
Changes in the fair value and settlements of our commodity derivative contracts are recognized currently in earnings and were as follows (in thousands):
| Year Ended December 31, |
| |||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| |||
Derivative (gain) loss: | $ | (3,965 | ) |
| $ | 8,470 |
|
| $ | 13,954 |
|
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Derivative (gain) loss | $ | (4,199 | ) |
| $ | 2,926 |
|
| $ | (14,375 | ) |
Cash paymentsreceipts (payments), net, on commodity derivative contract settlements net, are included within Net cash provided by operating activactivitiesities 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 |
|
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Cash receipts on derivative settlements, net | $ | 4,199 |
|
| $ | 4,746 |
|
| $ | 6,703 |
|
Offsetting Commodity Derivatives
During 2014, 2013 and 2012, all of our derivative agreements allowed for netting of derivative gains and losses upon settlement. In general, the terms of the agreements provided for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our 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 as either an asset or liability.
89104
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
There were no open derivative contracts asDuring 2016, after receiving shareholder approval, the Company increased the amount of December 31, 2014. The following table provides a reconciliationcommon stock authorized from 118.3 million shares to 200.0 million shares, which allowed for the issuance of the gross assets and liabilities reflected60.4 million additional shares in the balance sheet and the potential effects of master netting agreements on the fair value of open derivative contracts as of December 31, 2013 (in thousands):
| December 31, 2013 |
| |||||
| Derivative |
|
| Derivative |
| ||
| Assets |
|
| Liabilities |
| ||
Gross amounts presented in the balance sheet | $ | 141 |
|
| $ | 9,423 |
|
Amounts not offset in the balance sheet |
| (141 | ) |
|
| (141 | ) |
Net Amounts | $ | — |
|
| $ | 9,282 |
|
7. Long-Term Debt
As of December 31, 2014 and 2013, our long-term debt was as follows (in thousands):
| December 31, |
| |||||
| 2014 |
|
| 2013 |
| ||
8.50% Senior Notes | $ | 900,000 |
|
| $ | 900,000 |
|
Debt premiums, net of amortization |
| 13,057 |
|
|
| 15,421 |
|
Revolving bank credit facility |
| 447,000 |
|
|
| 290,000 |
|
Total long-term debt |
| 1,360,057 |
|
|
| 1,205,421 |
|
Current maturities of long-term debt |
| — |
|
|
| — |
|
Long term debt, less current maturities | $ | 1,360,057 |
|
| $ | 1,205,421 |
|
|
|
Senior Notes
On October 24, 2012, we issued $300.0 million of Senior Notes at a premium of 106% par value with an interest rate of 8.50% (7.7% effective interest rate) and maturity date of June 15, 2019, which have identical terms to the Senior Notes issued in June 2011 (collectively, the “8.50% Senior Notes”). The net proceeds after fees and expenses were approximately $312.0 million. The funds were used to repay all of our outstanding indebtedness under our revolving bank credit facility, a portion of which was incurred to partially fund our acquisition of the Newfield Properties described in Note 2, and for general corporate purposes. In February 2013, holders of the 8.50% Senior Notes issued in October 2012 exchanged their 8.50% Senior Notes for registered notesconjunction with the same terms.Exchange Transaction executed during 2016.
On June 10, 2011,During 2017, 2016 and 2015, we issued $600.0 million of Senior Notes at par with an interest rate of 8.50% and maturity date of June 15, 2019. The net proceeds after fees and expenses were approximately $593.5 million. In January 2012, holders of the Senior Notes issued in June 2011 exchanged their Senior Notes for registered notes with the same terms.
Interest on the 8.50% Senior Notes is payable semi-annually in arrears on June 15 and December 15 of each year and all of the 8.50% Senior Notes are subject to the same indenture. The 8.50% Senior Notes are unsecured and are fully and unconditionally guaranteed by certain of our subsidiaries. At December 31, 2014 and 2013, the outstanding balance of our 8.50% Senior Notes was classified at their carrying value as long-term debt. The estimated annual effective interest rate on the 8.50% Senior Notes is 8.4% for 2014, which includes amortization of debt issuance costs and premiums. At December 31, 2014 and 2013, the estimated fair value of the 8.50% Senior Notes was approximately $594.0 million and $962.5 million, respectively.
We and our restricted subsidiaries are subject to certain covenants under the indenture governing the 8.50% Senior Notes, which limit our and our restricted subsidiaries’ ability to, among other things, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of our assets, engage in transactions with affiliates, pay dividends or make other distributions on capital stock or subordinated indebtedness and create unrestricted subsidiaries. We were in compliance with all applicable covenants of the indenture governing the 8.50% Senior Notes as of December 31, 2014.
90
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Credit Agreement
On November 8, 2013, we entered into the Fifth Amended and Restated Credit Agreement (the “Credit Agreement”), which provides a revolving bank credit facility of up to $1.2 billion. Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our 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 limit, among other things, our ability to: (i) pay cash dividends in excess of $60.0 million per year; (ii) repurchase our common stock or outstanding senior notes in excess of $100.0 million in the aggregate, provided that such limitation will not apply to the repurchase of our existing senior notes in an aggregate principal amount equal to the aggregate principal amount of any new issuance of notes; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) eliminate certain hedging contracts or enter into certain hedging contacts in excess of 75% of projected oil and gas production on a monthly basis; (vii) enter into certain liens; and (viii) enter into certain other transactions, without the prior consent of the lenders. We are permitted to issue additional unsecured indebtedness above our current 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 restrictive covenants materially more onerous than those provided for in the Credit Agreement. If we issue additional unsecured indebtedness in excess of the current $900.0 million in aggregate principal amount, the borrowing base then in effect will be reduced by $0.25 for each dollar of such excess until the borrowing base is redetermined by our lenders.
Borrowings under the revolving bank credit facility 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%. The estimated annual effective interest rate was 2.9% for 2014 for borrowings under the Credit Agreement. The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs.
The 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 the 20 banks in the syndication under the Prior Credit Agreement was replaced with a different bank under the Credit Agreement and the other 19 banks were unchanged. Accordingly, we apportioned the unamortized debt issuance cost related to the Prior Credit Agreement and expensed the portion related to the bank whose debt was extinguished and did not participate in the Credit Agreement. The remaining unamortized debt issuance costs related to the Prior Credit Agreement was combined with the debt issuance costs related to the Credit Agreementpay any dividends and is being amortized over the term of the Credit Agreement on a straight line basis.
At December 31, 2014, we had $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.
For information about fair value measurements, refer to Note 8.
91
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. Fair Value Measurements
Under GAAP, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether using an in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk.
Valuation techniquesdividends 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:
|
|
|
|
|
|
The following table presents the fair value of our derivative financial instruments, our 8.50% Senior Notes and our revolving bank credit facility (in thousands):
|
|
| December 31, 2014 |
|
| December 31, 2013 |
| ||||||||||
| Hierarchy |
| Assets |
|
| Liabilities |
|
| Assets |
|
| Liabilities |
| ||||
Derivatives | Level 2 |
| $ | — |
|
| $ | — |
|
| $ | 141 |
|
| $ | 9,423 |
|
8.50% Senior Notes | Level 2 |
|
| — |
|
|
| 594,000 |
|
|
| — |
|
|
| 962,460 |
|
Revolving bank credit facility | Level 2 |
|
| — |
|
|
| 447,000 |
|
|
| — |
|
|
| 290,000 |
|
We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity futures prices. The 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.
92
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Equity Structure and Transactions
As of December 31, 2014 and 2013, the Company was authorized to issue 20 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.
During 2014, 2013 and 2012, we paid regular cash dividends of $0.40, $0.36 and $0.32 common share per year, respectively. In December 2013, we paid a special dividend of $0.42 per share or $31.8 million. In December 2012, we paid two special dividends totaling $0.79 per share or $59.0 million. Dividends are subject to periodic review of the Company’s performance and the current economic environment and applicable debt agreement restrictions. In light of current market conditions, the Board of Directors has elected to suspend the regular quarterly dividend.
currently suspended.
10. Incentive Compensation PlanShare-Based Awards and Directors Compensation PlanCash-Based Awards
Incentive Compensation Plan
In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholdersshareholders. During 2017, 2016, and 2013, amendments to the Plan were approved by our shareholders in 2013.shareholders. The Plan covers the Company’s eligible employees and consultants. In addition to other cash and share-based compensation awards, the Plan ishas historically been designed to grant awards that qualifyqualified as performance-based compensation within the meaning of section 162(m) of the IRC.Internal Revenue Code (“IRC”). Beginning in 2018, IRC section 162(m) will no longer contain deduction exemptions for performance-based compensation except for plans in place prior to November 2, 2017 that meet certain certifications. The Plan grants the Compensation Committee of the Board of Directors administrative authority over all participants, and grants the President and Chief Executive Officer (“CEO”) with authority over the administration of awards granted to participants that are not subject to section 16 of the Exchange Act (as applicable, the “Committee”).
Pursuant to the terms of the Plan, the Committee establishes the vesting or performance criteria applicable to the award and may use a single measure or combination of business measures as described in the Plan. Also, individual goals may be established by the Committee. Performance awards may be granted in the form of stock options, stock appreciation rights, restricted stock, restricted stock units (“RSUs”), bonus stock, dividend equivalents, or other awards related to stock, and awards may be paid in cash, stock, or any combination of cash and stock, as determined by the Committee. The performance awards granted under the Plan can be measured over a performance period of up to 10 years and annual incentive awards (a type of performance award) will generally be paid within 90 days following the applicable year end.
The 2017 amendment increased the number of shares available in the Plan by 7,700,000 shares of common stock. As of December 31, 2017, there were 13,363,792 shares of common stock available for issuance in satisfaction of awards under the Plan. RSUs reduce the shares available in the Plan when settled in shares of common stock, net of withholding tax.
Share-based Awards: Restricted Stock Units
For 2014, 20132017, 2016 and 2012,2015, performance awards under the Plan were granted in the form of restricted stock units (“RSUs”).RSUs to eligible employees. As defined by the Plan, RSUs are rights to receive stock, cash or a combination thereof at the end of a specified vesting period, subject to certain terms and conditions as determined by the Committee. RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period using a predefined scale based on the Company achieving certain predetermined performance criteria. Vesting occurs upon completion of the specified vesting period applicable to each grant. Subsequent to the determination of the performance achievement and prior to vesting, the RSUs earn dividend equivalents at the same rate as dividends paid on our common stock. RSUs are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period.
During 2014,2017, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which iswas comprised of: (i) net income before income tax expense, net interest expense, depreciation, depletion, amortization, accretion and certain other items (“Adjusted EBITDA”) for 20142017 and (ii) Adjusted EBITDA as a percent of total revenue (“Adjusted EBITDA Margin”) for 2014.2017. Adjustments range from 0% to 100% dependentbased upon actual results compared against pre-defined performance levels. For 2014,2017, the Company was aboveachieved target for Adjusted EBITDA and was slightly below target for Adjusted EBITDA Margin.
During 2013, RSUs granted were subject to a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2013; (ii) Adjusted EBITDA Margin for 2013; and (iii) the Company’s total shareholder return (“TSR”) ranking against peer companies’ TSR for 2013, 2014 and January 1, 2015 to October 31, 2015. TSR is determined based upon the change in the entity’s stock price plus dividends for the applicable performance period. Adjustments range from 0% to 150% for portions subject toboth Adjusted EBITDA and Adjusted EBITDA Margin measurements and adjustments range from 0% to 200% for the portion subject to TSR measurement. For 2013, the Company exceeded the target for Adjusted EBITDA and was approximately at target for 2013 Adjusted EBITDA Margin. For 2014 and 2013, the Company was below target for the TSR rankings for each period. In addition, RSUs were granted during 2013 which were not subject to performance criteria and were less than 3% of total grants.
93105
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
During 2012,2016 and 2015, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) earnings per share (“EPS”) for 2012;Adjusted EBITDA and (ii) the Company’s TSR ranking against peer companies’ TSRAdjusted EBITDA Margin for 2012, 2013 and January 1, 2014 to October 31, 2014.each respective year. 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 thebased upon actual results compared against pre-defined performance measurement.levels. For both 2016 and 2015, the Company was below target for Adjusted EBITDA and achieved target for Adjusted EBITDA Margin.
All RSUs granted to date are subject to employment-based criteria in addition to performance criteria. Vesting occurs in December of the thirdsecond calendar year afterfollowing the date of grant. For example, the RSUs granted during 20122015 (after adjustment for performance) vested in December 20142017 to eligible employees.
Cash-based Awards
For 2014, 2013 and 2012, cash-based awards were granted under The Company has the Planoption to substantially all eligible employees. The cash-based awards, which are a short-term component of the Plan, were determined based on multiple performance measures, such as Adjusted EBITDA, reserve and production growth, cost containment and individual performance measures. With respectsettle RSUs in stock or cash at vesting. Prior to the 2014 cash-based awards, some of the performance criteria targets were achieved and were combined with estimates of personal performance measurements to record potential payments. With respect to the 2013 cash-based awards, most of the performance criteria targets were achieved and were combined with the individual’s performance to determine the cash-based award. With respect to the 2012 cash-based awards, some of the performance criteria targets were achieved and were combined with the individual’s performance to determine the cash-based award. In addition, pursuant to the Plan, discretionary authority was exercised for certain non-executive employees, which increased cash-based award amounts in 2012. Eligible employees are paid their cash-based awards within 75 days following year end.
Share-based Awards: Common Stock
The 2014 annual incentive plan award for the Chief Executive Officer (“CEO”) was settled in2017, only shares of common stock based on a pre-determined pricewere used to settle vested RSUs. During 2017, cash was used to settle vested RSUs related to the retirement of $14.66 per share, subjectan executive officer and shares of common stock were used to pre-definedsettle all other vested RSUs. The Company plans to settle RSUs that vest in the future using shares of common stock.
During 2017, 2016 and 2015, the Company granted RSUs to certain employees, with nearly all grants being contingent upon meeting specified performance measures and approvalrequirements described above. The fair value of the Compensation Committee. As the number of shares could not beRSUs granted for all years presented was determined until the full-year 2014 results were determined and approved by the Committee, the CEO’s 2014 award was accounted for as a liability award during 2014 and adjusted to fair value using the Company’s closing price aton the endgrant dates.
A summary of each reporting period. The grant was madeactivity related to RSUs is as follows:
| 2017 |
|
| 2016 |
|
| 2015 |
| |||||||||||||||
| 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 |
| 6,107,248 |
|
| $ | 2.73 |
|
|
| 3,474,079 |
|
| $ | 7.42 |
|
|
| 1,977,335 |
|
| $ | 15.29 |
|
Granted |
| 2,128,879 |
|
|
| 2.76 |
|
|
| 4,213,964 |
|
|
| 2.21 |
|
|
| 2,626,930 |
|
|
| 3.59 |
|
Vested |
| (2,108,553 | ) |
|
| 3.45 |
|
|
| (968,652 | ) |
|
| 16.69 |
|
|
| (721,038 | ) |
|
| 13.23 |
|
Forfeited |
| (362,323 | ) |
|
| 2.87 |
|
|
| (612,143 | ) |
|
| 3.64 |
|
|
| (409,148 | ) |
|
| 10.63 |
|
Nonvested, end of period |
| 5,765,251 |
|
| $ | 2.48 |
|
|
| 6,107,248 |
|
| $ | 2.73 |
|
|
| 3,474,079 |
|
| $ | 7.42 |
|
Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2017 are eligible to vest in the first quarteryear indicated in the table below:
| Restricted Stock Units |
| |
2018 |
| 3,742,509 |
|
2019 |
| 2,022,742 |
|
Total |
| 5,765,251 |
|
RSUs fair value at grant date - During 2017, 2016 and 2015, the grant date fair value of 2015 once the number of shares could be determinedRSUs granted was $5.9 million, $9.3 million and approved by the Committee.$9.4 million, respectively.
RSUs fair value at vested date - The 2013 annual incentive plan award for the CEO was settled in shares of common stock based using the pricefair value of the stock immediately precedingRSUs that vested during 2017, 2016 and 2015 was $5.5 million, $2.4 million and $2.1 million, respectively, based on the dayCompany’s closing price on the award was settled and the grant was made in the first quarter of 2014. Adjustments were made to both grants to satisfy withholding tax requirements. The performance measures for the CEO’s awards were the same as the cash-based-awards performance measures established for the other eligible Company employees for 2014 and 2013, respectively.vesting date.
Directors Compensation Plan 106
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Share-Based AwardsAwards: Restricted Stock
Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2014, 20132017, 2016 and 20122015 to the Company’s non-employee directors as a component of their compensation arrangement. Vesting occurs upon completion of the specified vesting period and one-third of each grant vests each year over a three-year period. The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. Restricted Shares are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restriction period.
For additional information concerning share-based awards and cash-based awards, including expense recognition, see Note 11.
11. Share-Based and Cash-Based Incentive Compensation
As allowed by the Plan, in 2014, 2013 and 2012, the Company granted RSUs to certain of its employees. In 2014, 2013 and 2012, restricted stock was granted to the Company’s non-employee directors under the Directors Compensation Plan. In addition to share-based compensation, the Company granted cash-based incentive awards to substantially all eligible employees in 2014, 2013 and 2012.
94
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2014,2017, there were 4,790,082 shares of common stock available for issuance in satisfaction of awards under the Plan and 500,564170,524 shares of common stock available for issuance in satisfaction of awards under the Directors Compensation Plan. TheReductions in shares available for both plans are reducedmade when restricted stock isRestricted Shares are 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 |
| 2017 |
|
| 2016 |
|
| 2015 |
| ||||||||||||||||||||||||||||||
| 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 |
| 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 |
|
| 161,296 |
|
| $ | 3.47 |
|
|
| 78,230 |
|
| $ | 8.95 |
|
|
| 43,210 |
|
| $ | 16.20 |
|
Granted |
| 18,815 |
|
|
| 18.60 |
|
|
| 27,450 |
|
|
| 12.75 |
|
|
| 21,954 |
|
|
| 19.13 |
|
| 147,372 |
|
|
| 1.90 |
|
|
| 126,128 |
|
|
| 2.22 |
|
|
| 56,540 |
|
|
| 6.19 |
|
Vested |
| (19,445 | ) |
|
| 18.00 |
|
|
| (27,297 | ) |
|
| 17.09 |
|
|
| (27,475 | ) |
|
| 13.59 |
|
| (62,140 | ) |
|
| 4.51 |
|
|
| (43,062 | ) |
|
| 9.75 |
|
|
| (21,520 | ) |
|
| 16.26 |
|
Forfeited |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2,662 | ) |
|
| 18.78 |
| |||||||||||||||||||||||
Nonvested, end of period |
| 43,210 |
|
| $ | 16.20 |
|
|
| 43,840 |
|
| $ | 15.96 |
|
|
| 43,687 |
|
| $ | 18.69 |
|
| 246,528 |
|
| $ | 2.27 |
|
|
| 161,296 |
|
| $ | 3.47 |
|
|
| 78,230 |
|
| $ | 8.95 |
|
Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 20142017 are expected to vest as follows:
| Restricted Shares |
| |
2015 |
| 21,520 |
|
2016 |
| 15,420 |
|
2017 |
| 6,270 |
|
Total |
| 43,210 |
|
| Restricted Shares |
| |
2018 |
| 106,240 |
|
2019 |
| 91,164 |
|
2020 |
| 49,124 |
|
Total |
| 246,528 |
|
Restricted stock fair value at grant date and vested date:- The grant date fair value of restricted stock granted during 2014, 20132017, 2016 and 20122015 was $0.3 million $0.3 million and $0.4 million, respectively,each year for all years presented based on the Company’s closing price on the date of grant.
Restricted stock fair value at vested date - The fair value of the restricted stock that vested during 2014, 20132017, 2016 and 20122015 was $0.3$0.1 million $0.4 million and $0.5 million, respectively,each year for all years presented 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.
95107
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The fair value of the RSUs granted in 2013 was determined separately for each component. For the components related to the company-specific performance measures (Adjusted EBITDA and Adjusted EBITDA Margin), the fair value was determined using the Company’s closing price on the grant date. The components related to Adjusted EBITDA and Adjusted EBITDA Margin comprised 40% and 30%, respectively, of the amount granted. For the component related to TSR ranking, the fair value was determined using a Monte Carlo simulation probabilistic model. The component related to TSR ranking totaled 30% of the amount granted, with 10% for each of the three-year performance periods. The inputs used in the model for the Company and the peer companies were: average closing stock prices during January 2013; risk-free interest rates using the LIBOR ranging from 0.27% to 0.91% over the service period; expected volatilities ranging from 30% to 63%; expected dividend yields ranging from 0.0% to 3.1%; and correlation factors ranging from a negative 84% to a positive 95%. The expected volatilities, expected dividends and correlation factors were developed using historical data. For the RSUs granted in 2013 that were not subject to performance measures, the fair value was determined using the closing price on the date of grant.
The fair value of the RSUs granted in 2012 was determined separately for the two components. For the component related to the company-specific performance measure, which was comprised of only EPS, the fair value was determined using the Company’s closing price on the grant date. The component related to EPS comprised 70% of the amount granted. For the component related to TSR ranking, the fair value was determined by using a Monte Carlo simulation probabilistic model. The component related to TSR ranking totaled 30% of the amount granted, with 10% for each of the three-year performance periods. The inputs used in the model for the Company and the peer companies were: average closing stock prices during January 2012; risk-free interest rates using the LIBOR ranging from 0.15% to 0.72% over the service period; expected volatilities ranging from 33% to 74%; expected dividend yields ranging from 0.0% to 2.5%; and correlation factors ranging from a negative 67% to a positive 94%. The expected volatilities, expected dividends and correlation factors were developed using historical data.
A summary of activity related to RSUs is as follows:
| 2014 |
|
| 2013 |
|
| 2012 |
| |||||||||||||||
| Restricted Stock Units |
|
| Weighted Average Grant Date Fair Value Per Share |
|
| Restricted Stock Units |
|
| Weighted Average Grant Date Fair Value Per Share |
|
| Restricted Stock Units |
|
| Weighted Average Grant Date Fair Value Per Share |
| ||||||
Nonvested, beginning of period |
| 1,331,753 |
|
| $ | 14.96 |
|
|
| 969,820 |
|
| $ | 22.70 |
|
|
| 1,732,703 |
|
| $ | 14.67 |
|
Granted |
| 1,195,388 |
|
|
| 16.84 |
|
|
| 969,919 |
|
|
| 13.23 |
|
|
| 764,654 |
|
|
| 18.64 |
|
Vested |
| (354,692 | ) |
|
| 18.59 |
|
|
| (468,925 | ) |
|
| 26.93 |
|
|
| (1,198,208 | ) |
|
| 9.36 |
|
Forfeited |
| (195,114 | ) |
|
| 16.53 |
|
|
| (139,061 | ) |
|
| 16.50 |
|
|
| (329,329 | ) |
|
| 19.56 |
|
Nonvested, end of period |
| 1,977,335 |
|
| $ | 15.29 |
|
|
| 1,331,753 |
|
| $ | 14.96 |
|
|
| 969,820 |
|
| $ | 22.70 |
|
Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2014 are eligible to vest in the year indicated in the table below:
| |||
|
| ||
| |||
|
| ||
|
|
|
|
RSUs fair value at grant date: During 2014, 2013 and 2012, the grant date fair value of RSUs granted was $20.1 million, $12.8 million and $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, |
| ||||||||||||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| 2017 |
|
| 2016 |
|
| 2015 |
| ||||||
Share-based compensation expense from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock units | $ | 7,785 |
|
| $ | 10,640 |
|
| $ | 9,978 |
| |||||||||||
Restricted stock | $ | 369 |
|
| $ | 397 |
|
| $ | 399 |
|
| 280 |
|
|
| 373 |
|
|
| 358 |
|
Restricted stock units |
| 13,150 |
|
|
| 11,128 |
|
|
| 11,999 |
| |||||||||||
Common shares |
| 1,225 |
|
|
| — |
|
|
| — |
|
| — |
|
|
| — |
|
|
| (94 | ) |
Total | $ | 14,744 |
|
| $ | 11,525 |
|
| $ | 12,398 |
| $ | 8,065 |
|
| $ | 11,013 |
|
| $ | 10,242 |
|
Share-based compensation tax benefit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax benefit computed at the statutory rate | $ | 5,160 |
|
| $ | 4,034 |
|
| $ | 4,339 |
| $ | 1,694 |
|
| $ | 3,855 |
|
| $ | 3,585 |
|
As of December 31, 2014,2017, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares RSUs and common stock was $0.5 million, $16.5$6.2 million and $0.1$0.4 million, respectively. Unrecognized compensation expense will be recognized through April 2017November 2019 for restricted shares, November 2016 forour RSUs and February 2015April 2020 for common stock.our Restricted Shares.
Cash-based Incentive CompensationAwards
As defined byIn addition to share-based compensation, cash-based awards were granted under the Plan annual incentiveto substantially all eligible employees in 2017, 2016 and 2015. The cash-based awards, payable in cash may be granted to eligible employees. These awardswhich are a short-term component of the Plan, are performance-based awards consisting of one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each of such criteria. Generally,In addition, these cash-based awards included an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred for any fiscal quarter plus the three preceding quarters to exceed defined levels measured over defined time periods for each cash-based award. Expense is recognized over the service period once the business criteria, individual performance period iscriteria and financial condition are met.
For the calendar year and determination and payment is made in cash in the first quarter2017 cash-based awards, a portion of the following year.
Share-Based Compensationbusiness criteria and Cash-Based Incentive Compensationindividual performance criteria were achieved. The financial condition requirement of Adjusted EBITDA less reported Interest Expense
A summary of Incurred exceeding $200 million over four consecutive quarters was achieved; therefore, incentive compensation expense was recognized in 2017 for the 2017 cash-based awards. Payments are expected to be made in March 2018 and are subject to all the terms of the 2017 Annual Incentive Award Agreement.
For the 2016 cash-based awards, the financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $300 million over four consecutive quarters was not achieved as of December 31, 2017; therefore no expense was recognized during 2017 or 2016. The terms of the 2016 cash-based awards allow for the measurement of the financial condition to be made up through December 31, 2018. If the financial condition is as follows (in thousands):achieved, payment is to be made within 30 days of achievement of the financial condition.
| 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 |
|
|
|
For the 2015 cash-based awards, the financial condition was not achieved through the measurement date; therefore, all awards granted were forfeited and no expense was recognized in any of the reported periods.
97
108
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Share-Based Awards and Cash-Based Awards Compensation Expense
12.A summary of compensation expense related to share-based awards and cash-based awards is as follows (in thousands):
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Share-based compensation included in: |
|
|
|
|
|
|
|
|
|
|
|
General and administrative | $ | 8,065 |
|
| $ | 11,013 |
|
| $ | 10,242 |
|
Cash-based incentive compensation included in: |
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
| 2,101 |
|
|
| — |
|
|
| 364 |
|
General and administrative (1) |
| 5,032 |
|
|
| — |
|
|
| (233 | ) |
Total charged to operating income | $ | 15,198 |
|
| $ | 11,013 |
|
| $ | 10,373 |
|
(1) | Adjustments to true up estimates to actual payments resulted in net credit balances to expense in 2015. |
11. Employee Benefit Plan
We maintain a defined contribution benefit plan in compliance with Section 401(k) of the IRC (the “401(k) Plan”), which covers those employees who meet the 401(k) Plan’s eligibility requirements. From March 5, 2016 to March 1, 2017, the Company suspended matching contributions. During 2014, 2013 and 2012,the time periods where matching occurred, the Company’s matching contribution was 100% of each participant’s contribution up to a maximum of 6% for 2014, 2013 and 2012 of the participant’s eligible compensation, subject to limitations imposed by the IRC. The 401(k) Plan provides 100% vesting in Company match contributions on a pro rata basis over five years of service (20% per year). Our expenses relating to the 401(k) Plan were $2.4$1.4 million, $2.1$0.4 million and $2.1$2.3 million for 2014, 20132017, 2016 and 2012,2015, respectively.
13.12. Income Taxes
Income Tax Expense (Benefit)
Components of income tax expense (benefit) were as follows (in thousands):
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Current | $ | (12,786 | ) |
| $ | (71,768 | ) |
| $ | 288 |
|
Deferred |
| 217 |
|
|
| 28,392 |
|
|
| (203,272 | ) |
Total income tax (benefit) | $ | (12,569 | ) |
| $ | (43,376 | ) |
| $ | (202,984 | ) |
109
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)benefit is as follows (in thousands)thousands, except percentages):
| Year Ended December 31, |
| Year Ended December 31, |
| ||||||||||||||||||||||||||||||||||||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| 2017 |
|
| 2016 |
|
| 2015 |
| ||||||||||||||||||||||||||||||
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 |
| |||||||||||||||||||||||
Income tax (benefit) at the federal statutory rate | $ | 23,490 |
|
|
| 35.0 | % |
| $ | (102,339 | ) |
|
| 35.0 | % |
| $ | (436,696 | ) |
|
| 35.0 | % | |||||||||||||||||||||||
Share-based compensation |
| 664 |
|
|
| 1.0 |
|
|
| 4,920 |
|
|
| (1.7 | ) |
|
| 2,940 |
|
|
| (0.2 | ) | |||||||||||||||||||||||
State income taxes |
| 263 |
|
|
| (1.6 | ) |
|
| 343 |
|
|
| 0.4 |
|
|
| 750 |
|
|
| 0.7 |
|
| 63 |
|
|
| 0.1 |
|
|
| (755 | ) |
|
| 0.2 |
|
|
| (2,343 | ) |
|
| 0.2 |
|
Debt restructuring cost |
| 18 |
|
|
| — |
|
|
| 1,463 |
|
|
| (0.5 | ) |
|
| — |
|
|
| — |
| |||||||||||||||||||||||
Change in statutory federal tax rate |
| 105,933 |
|
|
| 157.8 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
| |||||||||||||||||||||||
Gain on exchange of debt |
| (24,981 | ) |
|
| (37.2 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
| |||||||||||||||||||||||
Valuation allowance |
| (118,643 | ) |
|
| (176.8 | ) |
|
| 52,915 |
|
|
| (18.1 | ) |
|
| 232,925 |
|
|
| (18.7 | ) | |||||||||||||||||||||||
Other |
| 920 |
|
|
| (5.7 | ) |
|
| 398 |
|
|
| 0.5 |
|
|
| 705 |
|
|
| 0.6 |
|
| 887 |
|
|
| 1.4 |
|
|
| 420 |
|
|
| (0.1 | ) |
|
| 190 |
|
|
| — |
|
| $ | (4,459 | ) |
|
| 27.7 | % |
| $ | 28,774 |
|
|
| 35.9 | % |
| $ | 47,547 |
|
|
| 39.8 | % | |||||||||||||||||||||||
Total income tax (benefit) | $ | (12,569 | ) |
|
| (18.7 | %) |
| $ | (43,376 | ) |
|
| 14.8 | % |
| $ | (202,984 | ) |
|
| 16.3 | % |
Our effective tax rate for the year 2014 is distorted due to a small pre-tax loss; consequently, our permanent differences have a larger impact on our effective tax rate. Our effective tax rate for the year 2013years 2017, 2016 and 2015 differed from the federal statutory rate of 35.0% primarily asdue to recording and adjusting a result of state income taxes. Our effectivevaluation allowance for our deferred tax rate for the year 2012 differed from the federal statutory rate primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a function of loss carrybacks to prior years and the impact of state income taxes.assets, which is discussed below.
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, |
| December 31, |
| ||||||||||
| 2014 |
|
| 2013 |
| 2017 |
|
| 2016 |
| ||||
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment | $ | 518,566 |
|
| $ | 422,805 |
| |||||||
Other |
| 5,019 |
|
|
| 3,602 |
| $ | 695 |
|
| $ | 1,423 |
|
Total deferred tax liabilities |
| 523,585 |
|
|
| 426,407 |
|
| 695 |
|
|
| 1,423 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alternative minimum tax credit |
| 20,486 |
|
|
| 20,486 |
| |||||||
Property and equipment |
| 18,234 |
|
|
| 42,385 |
| |||||||
Asset retirement obligations |
| 137,597 |
|
|
| 124,863 |
|
| 63,755 |
|
|
| 117,588 |
|
Federal net operating losses |
| 180,024 |
|
|
| 91,472 |
|
| 18,988 |
|
|
| — |
|
State net operating losses |
| 5,008 |
|
|
| 5,028 |
|
| 7,126 |
|
|
| 5,615 |
|
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 |
| |||||||
Exchange transaction |
| 55,807 |
|
|
| 118,467 |
| |||||||
Share-based compensation |
| 1,335 |
|
|
| 2,353 |
| |||||||
Valuation allowance |
| (171,547 | ) |
|
| (290,190 | ) | |||||||
Other |
| 798 |
|
|
| 643 |
|
| 6,805 |
|
|
| 4,798 |
|
Total deferred tax assets |
| 348,259 |
|
|
| 248,848 |
|
| 503 |
|
|
| 1,016 |
|
Net deferred tax liabilities | $ | 175,326 |
|
| $ | 177,559 |
| |||||||
Net deferred tax assets (liabilities) | $ | (192 | ) |
| $ | (407 | ) |
During 2014,2017, we received refunds of $11.9 million and made income tax payments of $0.2 million. During 2016, we received $7.8 million of refunds and made income tax payments of $0.3 million. The refunds received in 2017 and 2016 were primarily due to net operating loss (“NOL”) carryback claims made pursuant to IRC Section 172 (f) (related to rules of “specified liability losses”). During 2015, we did not make any payments for federal andor state income taxes and we receivedor receive any refunds of $3.0 million. During 2013,significance.
110
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2017, we made payments primarily for federal and statehave recorded a current income taxes receivable of approximately $3.0 million. During 2013, we received refunds of $59.1$13.0 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 statea non-current income taxes receivable of $16.1 million$52.1 million. The current income taxes receivable primarily relate to a net operating loss carried back claim for 2017. The non-current income taxes receivable relates to our NOL claims for the years 2012, 2013 and we received refunds related2014 that were carried back to prior years of $0.5 million.
At December 31, 2014, we did not haveyears. These carryback claims are made pursuant to IRC Section 172(f), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years. The refund claims require a federal income tax receivable. At December 31, 2013, we had a federal income tax receivable of $3.1 million. This amount is comprised principally of refunds related to estimated taxes paid during 2013. review by the Congressional Joint Committee on Taxation and are accordingly classified as non-current.
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, 20142017 (in thousands):
| Amount |
|
| Expiration Year | Amount |
|
| Expiration Year | ||
Federal net operating loss | $ | 516,393 |
|
| 2032-2034 | $ | 18,988 |
|
| 2037 |
State net operating losses |
| 99,656 |
|
| 2021-2029 |
| 118,027 |
|
| 2025-2036 |
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
During 2017, we recorded a decrease in the valuation allowance of $118.6 million and in 2016, we recorded an increase in the valuation allowance of $52.9 million related to federal and state deferred tax assets. As a result of the enactment of the Tax Cuts and Jobs Act (“TCJA”), on December 22, 2017, our net deferred tax assets and its respective valuation allowance were provisionally adjusted downwards by $105.9 million as of December 31, 2014 and 2013, we had a valuation allowance2017. Deferred tax assets are recorded related to Louisiana state net operating losses.losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions during periods in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. As part of December 31, 2017 and 2016, we had a valuation allowance related to our assessment, we consider future reversalsfederal and state deferred tax assets. Due to the timing and the complexity involved in applying the provisions of existing taxable temporary differences.the TCJA, our application of the TCJA may require further adjustments during 2018 in the determination of the final effects in our financial statements.
Uncertain Tax Positions
The table below sets forth the reconciliation of the beginning and ending balancesbalance of the total amount of unrecognized tax benefits. There are no unrecognized benefits that would impact the effective tax rate if recognized. While amounts could change in the next 12 months, we do not anticipate it having a material impact on our financial statements.
Balances and changes in the uncertain tax positions are as follows (in thousands):
| December 31, |
| |||||
| 2014 |
|
| 2013 |
| ||
Balance, beginning of period | $ | 9,482 |
|
| $ | — |
|
Increases related to carryback positions |
| — |
|
|
| 9,482 |
|
Balance, end of period | $ | 9,482 |
|
| $ | 9,482 |
|
| December 31, |
| |||||
| 2017 |
|
| 2016 |
| ||
Balance, beginning and end of period | $ | 9,482 |
|
| $ | 9,482 |
|
We recognize interest and penalties related to uncertain tax positions in income tax expense. For 2014, 20132017, 2016 and 2012,2015, the amounts recognized in income tax expense were immaterial.
Years open to examination
The tax years from 20102013 through 20142017 remain open to examination by the tax jurisdictions to which we are subject.
111
W&T OFFSHORE, INC. AND SUBSIDIARIES
14.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In accordance with GAAP, theThe Company’s unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are deemed participating securities and are included in the computation of earnings per share under the two-class method.method when the effect is dilutive.
The following table presents the calculation of basic and diluted earnings (loss) per common share (in thousands, except per share amounts):
| Year Ended December 31, |
| Year Ended December 31, |
| ||||||||||||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| 2017 |
|
| 2016 |
|
| 2015 |
| ||||||
Net income (loss) | $ | (11,661 | ) |
| $ | 51,322 |
|
| $ | 71,984 |
| $ | 79,682 |
|
| $ | (249,020 | ) |
| $ | (1,044,718 | ) |
Less portion allocated to nonvested shares |
| 269 |
|
|
| 303 |
|
|
| 983 |
|
| 3,244 |
|
|
| — |
|
|
| — |
|
Net income (loss) allocated to common shares | $ | (11,930 | ) |
| $ | 51,019 |
|
| $ | 71,001 |
| $ | 76,438 |
|
| $ | (249,020 | ) |
| $ | (1,044,718 | ) |
Weighted average common shares outstanding |
| 75,609 |
|
|
| 75,239 |
|
|
| 74,354 |
|
| 137,617 |
|
|
| 95,644 |
|
|
| 75,931 |
|
Basic and diluted earnings (loss) per common share | $ | (0.16 | ) |
| $ | 0.68 |
|
| $ | 0.95 |
| $ | 0.56 |
|
| $ | (2.60 | ) |
| $ | (13.76 | ) |
Shares excluded due to being anti-dilutive (weighted-average) |
| 29 |
|
|
| — |
|
|
| 1,923 |
|
| — |
|
|
| 5,269 |
|
|
| 2,195 |
|
14. Supplemental Cash Flow Information
100The following table reflects our supplemental cash flow information (in thousands):
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Supplemental cash items: |
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of interest capitalized of $0 in 2017, $520 in 2016 and $7,256 in 2015 (1) | $ | 65,873 |
|
| $ | 96,501 |
|
| $ | 92,622 |
|
Cash paid for income taxes |
| 185 |
|
|
| 310 |
|
|
| 390 |
|
Cash refunds received for income taxes |
| 11,906 |
|
|
| 7,796 |
|
|
| 90 |
|
Cash paid for share-based compensation (2) |
| 874 |
|
|
| — |
|
|
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash investing activities: |
|
|
|
|
|
|
|
|
|
|
|
Accruals of property and equipment |
| 33,003 |
|
|
| 9,129 |
|
|
| 44,324 |
|
ARO - additions, dispositions and revisions, net |
| 21,245 |
|
|
| 10,865 |
|
|
| (394 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash financing activities: |
|
|
|
|
|
|
|
|
|
|
|
Exchange transaction — non-cash securities issued: |
|
|
|
|
|
|
|
|
|
|
|
11.00% 1.5 Lien Term Loan - interest payable |
| — |
|
|
| 23,823 |
|
|
| — |
|
9.00%/10.75% Second Lien PIK Toggle Notes - carrying value |
| — |
|
|
| 223,905 |
|
|
| — |
|
8.50%/10.00% Third Lien PIK Toggle Notes - carrying value |
| — |
|
|
| 213,446 |
|
|
| — |
|
Common stock issued - fair value at issuance date |
| — |
|
|
| 106,366 |
|
|
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange transaction — non-cash securities exchanged: |
|
|
|
|
|
|
|
|
|
|
|
8.50% Unsecured Senior Notes - carrying value |
| — |
|
|
| (712,967 | ) |
|
| — |
|
(1) | During 2017 and 2016, cash paid for interest included amounts related to the New Debt, which are accounted for under ASC 470-60 and recorded against the carrying value of the New Debt instruments on the Consolidated Balance Sheets and included in financing activities on the Consolidated Statements of Cash Flows. |
(2) | During 2017, cash was used to settle vested RSUs related to the retirement of an executive officer and shares of common stock were used to settle all other vested RSUs and to settle restricted stock. During 2016 and 2015, only common shares were used to settle vested RSUs and Restrict stock. |
112
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. Supplemental Cash Flow Information
The following reflects our supplemental cash flow information (in thousands):
| 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 |
|
|
|
|
|
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, 20142017 are as follows: 2015–2018–$1.51.8 million; 2016–2019–$1.61.8 million; 2017–2020–$1.61.8 million; 2018–2021–$1.71.8 million thereafter–$7.52.0 million. Total rent expense was approximately $3.0 million, $3.2 million $2.6 million and $1.7$3.3 million during 2014, 20132017, 2016 and 2012,2015, respectively.
Pursuant to the Purchase and Sale Agreement with Total E&P, we are required tomay fulfill security requirements related to ARO for certain properties through securing bonds, or through making payments to an escrow account under a formula pursuant to the agreement, or a combination.combination thereof, until certain prescribed thresholds are met. Once the threshold is met for that year, excess funds in the escrow account are returned to us. As of December 31, 2014,2017, we werehad bonds related to the agreement with Total E&P totaling $81.3 million and had no amounts in compliance with the security amount requirement of $64.0 million. Additional security requirements are $9.0escrow. The threshold is $88.0 million in 2015, $6.0for 2018, $91.0 million in 2016, $4.0 million in 2017, $5.0 million in 2018for 2019 and $15.0 million in the 2019escalates to 2023 time period to a total security requirement of $103.0 million by 2023.for 2023 in $3.0 million per year increments.
Pursuant to the Purchase and Sale agreementAgreement with Shell Offshore Inc. (“Shell”) related to ARO for certain properties, we have bonds that are subject to re-appraisal in the 2015.by either party. As of December 31, 2017, neither party had requested a re-appraisal to be made. The current security requirement of $74.0$64.0 million could be increased up to $94.0 million depending on certain conditions and circumstances.
We have bonding requirementsDuring 2017, 2016 and 2015, we had surety bonds primarily related to properties owned by our subsidiary, W & T Energy VI, LLC, which require bonds in compliance with requirements set by the Bureau of Ocean Energy Management (“BOEM”). These bonds are required as long as W & T Energy VI, LLC owns the properties, including completion of plugging and abandonment activities.
decommissioning obligations or ARO. Total expenses related to surety bonds, inclusive of the surety bonds in connection with the Total E&P and Shell agreements described above, were $4.1$5.7 million, $5.0$4.3 million and $2.9$5.5 million during 2014, 20132017, 2016 and 2012,2015, respectively. The amount of future commitments is dependent on rates charged in the market place and when asset retirements are completed. Estimated future expenses related to surety bonds were based on current market prices and estimates of the timing of asset retirements, of which some wells and structures are estimated to extend to 2030. Future costs are estimated as follows: 2015–2018–$5.86.2 million; 2016–2019–$5.86.0 million; 2017–2020–$5.45.7 million; 2018–2021–$5.25.3 million; thereafter–$32.942.4 million. Future surety bond costs may change due to a number of factors, including changes and interpretations of regulations by the BOEM regulations.
As of December 31, 2017, we had $16.9 million of collateral deposits for certain sureties related to certain surety bonds for decommissioning obligations and appeals submitted to the Interior Board of Land Appeals (the “IBLA”).
Pursuant to an agreement with the Helix Well Containment Group, we are required to make payments quarterly in advance to have access to certain equipment to respond to a subsea spill should a spill occur at a property we operate. As of December 31, 2014, future payments due are $2.12017, our commitment is $1.5 million in 2015 and $2.1 million in 2016.for 2018. These payments may increase or decrease depending on whether the number of companies participating in the consortium changes.
We have no drilling rig commitments with a term that exceeded one year as of December 31, 20142017 and our drilling rig commitments meet the criteria of an operating lease. Future payments of all drilling rig commitments as of December 31, 20142017 were $12.6$5.7 million.
101113
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
During 2014, 20132017, 2016 and 2012,2015, there were certain transactions between us and other companies our majority shareholderCEO either controlled or in which he had an ownership interest. In addition, there were transactions with a company that employs the spouse of our majority shareholder.CEO. Our majority shareholderCEO owns an aircraft that the Company used and reimbursed him for such use and for his use.use pursuant to his employment contract. Airplane services were charged to us at rates that were either equal to or below rates charged by non-related, third-party companies. Airplane services transactions were approximately $0.9 million, $1.2 million, $1.1 million and $1.0$1.1 million for the years 2014, 20132017, 2016 and 2012,2015, respectively. Our majority shareholderCEO has ownership interests in certain wells operated by us (such ownership interests pre-date our initial public offering). Revenues are disbursed and expenses are collected in accordance with ownership interest. Proportionate insurance premiums were paid to us and proportionate collections of insurance reimbursements attributable to damage on certain wells were disbursed. W&T hired the services of a directional drilling services company, in which our majority 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.CEO. The rates charged for these marine and transportation services were either equal to or below rates charged by non-related, third-party companies. Payments to such company totaled $22.8 million in 2017. The spouse received commissions partially based on services rendered to W&T which totaledwere approximately $0.2 million 2017 and less than $0.2 million per year for 2014, 2013both 2016 and 2012. All these transactions were determined to be priced at competitive rates and were reviewed2015. During 2015, an entity controlled by our CEO participated in the Second Lien Term Loan for a $5.0 million principal commitment on the same terms as the other lenders.
17. Contingencies
Supplemental Bonding Requirements by the Audit Committee forBOEM
The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to satisfy lease obligations, including decommissioning activities on the OCS. As of the filing date of this Form 10-K, the Company is in compliance with our policiesits financial assurance obligations to the BOEM and procedures.
18. Contingencies
Notification by ONRRhas no outstanding BOEM orders related to assurance obligations. W&T and other offshore Gulf of FineMexico producers may in the ordinary course receive future demands 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 noticefinancial assurances from the ONRRBOEM as the BOEM continues to reevaluate its requirements for financial assurances.
Surety Bond Issuers’ Collateral Requirements
The issuers of a statutory fine of $2.3 million relativesurety bonds in some cases have requested and received additional collateral related to such underpayment.surety bonds for plugging and abandonment activities. We believe the fine is excessive and extreme considering the circumstances and in relationmay be required to post collateral at any time pursuant to the amountterms 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.our agreement with various sureties under our existing bonds, if they so demand at their discretion. 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 thandid not receive 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. collateral demands from surety bond providers during 2017.
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.
102114
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Insurance Claims
DuringOn December 15, 2014, Apache filed a lawsuit against the fourth quarterCompany alleging that W&T breached the joint operating agreement related to, among other things, the abandonment of 2012, underwriters of W&T’s excess liability policies (“Excess Policies”) (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company, XL Specialty Insurance Company, National Liability & Fire Insurance Company (“Starr Marine”) and Liberty Mutual Insurance Co.) filed declaratory judgment actionsthree deepwater wells in the United StatesMississippi Canyon (“MC”) area of the Gulf of Mexico. A trial court judgment was rendered from the U.S. District Court for the Southern District of Texas (the “District Court”) seeking a determination that our Excess Policies do not cover removal-of-wreckon May 31, 2017 directing the Company to pay Apache $43.2 million, plus $6.3 million in prejudgment interest, attorney's fees and debris claims arising from Hurricane Ike except tocosts assessed in 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 suitsjudgment. We 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 favoran appeal 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 decisiontrial court judgment in the United StatesU.S. Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) and,Circuit. Prior to filing the appeal, in order to stay execution of the judgment, we deposited $49.5 million with the registry of the court in June 2014,2017.
The dispute relates to Apache's use of drilling rigs instead of a previously contracted intervention vessel for the Fifth Circuit reversedplugging and abandonment work. We contended that the District Court’s rulingcosts to use the drilling rigs were unnecessary and ruled in our favor. The underwriters filed three separate briefs requesting a rehearing or a certificationunreasonable, and that Apache chose to use the Texas Supreme Court, all of whichrigs without W&T's consent because they otherwise would have been idle at Apache's expense. We believe the Court denied. A brief was subsequently filed by one underwriter requesting a rehearing to the District Courtuse of the Fifth Circuit’s decision, whichrigs was in bad faith, as found by the District Court denied. Claimsjury, and that such conduct caused W&T not to comply with the applicable joint operating agreement, particularly since another vessel had been contracted by Apache for the abandonment a year in advance. We had previously paid $24.9 million to Apache as an undisputed amount for the plug and abandonment work.
On October 28, 2016, the jury made the following findings:
1. | W&T failed to comply with the contract by failing to pay its proportionate share of the costs to plug and abandon the MC 674 wells. |
2. | The amount of money to compensate Apache for W&T’s failure to pay its proportionate share of the costs to plug and abandon the MC 674 wells was $43.2 million. |
3. | The $43.2 million referred to in #2 should be offset by $17.0 million. |
4. | Apache acted in bad faith thereby causing W&T to not comply with the contract. |
The deposit of approximately $43$49.5 million were filed, of which approximately $1 million was paid underwith the Energy Package and of which approximately $1 million was paid under our Comprehensive General Liability policy. Oneregistry of the underwriters, Liberty Mutual Insurance Co., has paid their portioncourt is recorded in Other assets (long-term) with a corresponding reduction to Cash and cash equivalents on the Consolidated Balance Sheet as of December 31, 2017. Although we are appealing the first excess liability policy (approximately $5 million), including interest, althoughdecision, based solely on the commencement date of the interest calculation is under discussion. The other underwritersdecision rendered, we have not paidrecorded $49.5 million in accordance with the Fifth Circuit ruling,Other liabilities (long-term) and we filed a lawsuit$43.2 million 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 recordedcapitalized ARO included in Oil and natural gas properties and equipmentother, net on the Consolidated Balance SheetsSheet as of December 31, 2017 and recoveries from claims madehave recognized $6.3 million of expense included in Other (income) expense, net on these Excess Policies will be recorded as reductions in this line item, which will reduce our future DD&A rate.the Consolidated Statement of Operations for 2017.
RoyaltiesAppeal with ONRR
In 2009, the Companywe recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited the calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which was denied in May 2014. On June 17, 2014, we filed an appeal with the Board of Land Appeals (the “BLA”)IBLA under the Department of the Interior. On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T’s brief was&T to pay approximately $4.7 million in additional royalties. We filed an appeal of the IBLA decision on July 25, 2017 in November 2014the U.S. District Court for the Eastern District of Louisiana.
115
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Royalties – “Unbundling” Initiative
The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and we expect the briefing before BLAprocessing costs that are permitted to be completeddeducted in determining royalties under Federal oil and gas leases. The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant that processed our gas. In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production related to a specific processing plant. We also received a preliminary determination notice from the ONRR asserting that our allocation of certain processing costs and plant fuel use at another processing plant was not allowed as deductions in the first halfdetermination of 2015.royalties owed under Federal oil and gas leases. We have submitted revised calculations covering certain plants and time periods to the ONRR. As of the filing date of this Form 10-K, we have not received a response from the ONRR related to our submissions. These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under our Federal oil and gas leases for current and prior periods. During 2017 and 2016, we paid $1.6 million and $0.5 million, respectively, of additional royalties and expect to pay more in the future. We are not able to determine the range of any additional royalties or if such amounts would be material.
Notices of Proposed Civil Penalty Assessment
During 2017 and 2016, we paid $0.2 million and $0.1 million, respectively, of civil penalties to the BSEE related to Incidents of Noncompliance (“INCs”) issued by the BSEE at various offshore locations. We currently have four open civil penalties issued by the BSEE arising from INCs, which have not been settled as of the filing of this Form 10-K. The INC’s underlying the civil penalties were issued during 2015, with one re-issued during 2016, and relate to four separate offshore locations with occurrence dates ranging from July 2012 to June 2014. The proposed civil penalties for these INCs total $7.3 million. We have accrued approximately $3.3 million, which is our best estimate of the final settlement once all appeals have been exhausted. Our position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs.
Other Claims
We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold. We are also subject to federal and state administrative proceedings conducted in the ordinary course of business.business including matters related to alleged royalty underpayments on certain federal-owned properties. Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, management believeswe believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.
Contingent Liability Recorded
We recognized expenses related to accrued and settled claims, complaints and fines of $0.4 million, $0.5 million and $9.3 million for the years 2014, 2013 and 2012, respectively. These expenses are reported within Operating costs and expenses on the statements of operations and reflect the items noted above and other various claims, complaints and fines. As of December 31, 2014 and 2013, we have recorded a liability of $0.1 million and $0.2 million, respectively, which is included in Accrued liabilities on the Consolidated Balance Sheets, for the loss contingencies matters that include the events described above and other minor environmental and litigation matters which we are addressing in the normal course of business.
103116
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
19.18. Selected Quarterly Financial Data—UNAUDITED
Unaudited quarterly financial data are as follows (in thousands, except per share amounts):
| 1st Quarter |
|
| 2nd Quarter |
|
| 3rd Quarter |
|
| 4th Quarter |
| 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 |
| 0.15 |
|
|
| 0.13 |
|
|
| 0.01 |
|
|
| (0.44 | ) | |||||||||||||||
Year Ended December 31, 2013 (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Year Ended December 31, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Revenues | $ | 259,222 |
|
| $ | 235,383 |
|
| $ | 244,555 |
|
| $ | 244,928 |
| $ | 124,393 |
|
| $ | 123,323 |
|
| $ | 110,281 |
|
| $ | 129,099 |
|
Operating income |
| 60,321 |
|
|
| 53,823 |
|
|
| 31,965 |
|
|
| 622 |
|
| 28,196 |
|
|
| 32,888 |
|
|
| 15,700 |
|
|
| 33,166 |
|
Net income (loss) |
| 26,618 |
|
|
| 22,396 |
|
|
| 14,194 |
|
|
| (11,886 | ) |
| 24,299 |
|
|
| 33,315 |
|
|
| (1,297 | ) |
|
| 23,365 |
|
Basic and diluted earnings (loss) per common share (1) |
| 0.35 |
|
|
| 0.29 |
|
|
| 0.19 |
|
|
| (0.16 | ) |
| 0.17 |
|
|
| 0.23 |
|
|
| (0.01 | ) |
|
| 0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Year Ended December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Revenues | $ | 77,715 |
|
| $ | 99,655 |
|
| $ | 107,403 |
|
| $ | 115,213 |
| |||||||||||||||
Operating income (loss) (1) |
| (166,614 | ) |
|
| (126,997 | ) |
|
| (58,276 | ) |
|
| 21,319 |
| |||||||||||||||
Net income (loss) (1) |
| (190,509 | ) |
|
| (120,922 | ) |
|
| 45,928 |
|
|
| 16,483 |
| |||||||||||||||
Basic and diluted earnings (loss) per common share (1) (2) |
| (2.49 | ) |
|
| (1.58 | ) |
|
| 0.48 |
|
|
| 0.12 |
|
(1) | During 2016, we recorded in first, second and third quarter ceiling test write-downs of oil and natural gas properties of $116.6 million, $104.6 million and $57.9 million, respectively. In the third quarter of 2016, we recorded a gain on exchange of debt of $123.9 million. See Note 1 and Note 2 for additional information. |
(2) | The sum of the individual quarterly earnings (loss) per share |
|
|
|
104117
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
20.19. Supplemental Guarantor Information
Our payment obligations under the 8.50% SeniorCredit Agreement, the 1.5 Lien Term Loan, the Second Lien Term Loan, the Second Lien PIK Toggle Notes, the Third Lien PIK Toggle Notes and the Credit AgreementUnsecured Senior Notes (see Note 7)2) are fully and unconditionally guaranteed by certain of our 100%-owned subsidiaries, W & T Energy VI LLC and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”). W & T Energy VII, LLC does not currently have any active operations or contain any assets. Guarantees of the 8.50% Senior Notes will be released under certain circumstances, including:
(1) | in connection with any sale or other disposition of all or substantially all of the assets of a Guarantor Subsidiary (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary, |
(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 |
(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 |
(4) | upon Legal Defeasance or Covenant Defeasance (as such terms are defined in the applicable indenture) or upon satisfaction and discharge of the |
(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 |
The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. Transfers of property, including related ARO and deferred income tax liabilities, were made from the Parent CompanyAs to the Guarantor Subsidiariesceiling test write-downs recorded in 2016 and 2015, the computation is performed for each subsidiary on a stand-alone basis and also for the consolidated Company. Due to assist the Parent Companythis methodology, consolidating adjustments are required 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 onpresent the consolidated results for the current or prior periods presented.appropriately.
105
118
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Balance Sheet as of December 31, 20142017
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
| ||
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| ||||||
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| ||||||||
| (In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents | $ | 23,666 |
|
| $ | — |
|
| $ | — |
|
| $ | 23,666 |
| $ | 99,058 |
|
| $ | — |
|
| $ | — |
|
| $ | 99,058 |
|
Receivables: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
| 41,820 |
|
|
| 25,422 |
|
|
| — |
|
|
| 67,242 |
|
| 5,665 |
|
|
| 39,778 |
|
|
| — |
|
|
| 45,443 |
|
Joint interest and other |
| 142,885 |
|
|
| — |
|
|
| (99,240 | ) |
|
| 43,645 |
| |||||||||||||||
Joint interest |
| 19,754 |
|
|
| — |
|
|
| — |
|
|
| 19,754 |
| |||||||||||||||
Income taxes |
| 128,835 |
|
|
| — |
|
|
| (115,829 | ) |
|
| 13,006 |
| |||||||||||||||
Total receivables |
| 184,705 |
|
|
| 25,422 |
|
|
| (99,240 | ) |
|
| 110,887 |
|
| 154,254 |
|
|
| 39,778 |
|
|
| (115,829 | ) |
|
| 78,203 |
|
Deferred income taxes |
| 9,797 |
|
|
| 1,865 |
|
|
| — |
|
|
| 11,662 |
| |||||||||||||||
Prepaid expenses and other assets |
| 28,728 |
|
|
| 7,619 |
|
|
| — |
|
|
| 36,347 |
|
| 11,154 |
|
|
| 2,265 |
|
|
| — |
|
|
| 13,419 |
|
Total current assets |
| 246,896 |
|
|
| 34,906 |
|
|
| (99,240 | ) |
|
| 182,562 |
|
| 264,466 |
|
|
| 42,043 |
|
|
| (115,829 | ) |
|
| 190,680 |
|
Property and equipment – at cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Oil and natural gas properties and equipment |
| 6,038,915 |
|
|
| 2,006,751 |
|
|
| — |
|
|
| 8,045,666 |
| |||||||||||||||
Furniture, fixtures and other |
| 23,269 |
|
|
| — |
|
|
| — |
|
|
| 23,269 |
| |||||||||||||||
Total property and equipment |
| 6,062,184 |
|
|
| 2,006,751 |
|
|
| — |
|
|
| 8,068,935 |
| |||||||||||||||
Less accumulated depreciation, depletion and amortization |
| 4,442,899 |
|
|
| 1,132,179 |
|
|
| — |
|
|
| 5,575,078 |
| |||||||||||||||
Net property and equipment |
| 1,619,285 |
|
|
| 874,572 |
|
|
| — |
|
|
| 2,493,857 |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Oil and natural gas properties and other, net - at cost: |
| 430,354 |
|
|
| 152,464 |
|
|
| (3,802 | ) |
|
| 579,016 |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Restricted deposits for asset retirement obligations |
| 15,444 |
|
|
| — |
|
|
| — |
|
|
| 15,444 |
|
| 25,394 |
|
|
| — |
|
|
| — |
|
|
| 25,394 |
|
Income tax receivables |
| 52,097 |
|
|
| — |
|
|
| — |
|
|
| 52,097 |
| |||||||||||||||
Other assets |
| 974,049 |
|
|
| 349,912 |
|
|
| (1,306,717 | ) |
|
| 17,244 |
|
| 505,304 |
|
|
| 453,306 |
|
|
| (898,217 | ) |
|
| 60,393 |
|
Total assets | $ | 2,855,674 |
|
| $ | 1,259,390 |
|
| $ | (1,405,957 | ) |
| $ | 2,709,107 |
| $ | 1,277,615 |
|
| $ | 647,813 |
|
| $ | (1,017,848 | ) |
| $ | 907,580 |
|
Liabilities and Shareholders’ Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Liabilities and Shareholders’ Equity (Deficit) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable | $ | 188,654 |
|
| $ | 5,455 |
|
| $ | — |
|
| $ | 194,109 |
| $ | 76,703 |
|
| $ | 6,962 |
|
| $ | — |
|
| $ | 83,665 |
|
Undistributed oil and natural gas proceeds |
| 36,130 |
|
|
| 879 |
|
|
| — |
|
|
| 37,009 |
|
| 18,762 |
|
|
| 1,367 |
|
|
| — |
|
|
| 20,129 |
|
Asset retirement obligations |
| 30,711 |
|
|
| 5,292 |
|
|
| — |
|
|
| 36,003 |
|
| 22,488 |
|
|
| 1,125 |
|
|
| — |
|
|
| 23,613 |
|
Long-term debt |
| 22,925 |
|
|
| — |
|
|
| — |
|
|
| 22,925 |
| |||||||||||||||
Accrued liabilities |
| 17,437 |
|
|
| 99,180 |
|
|
| (99,240 | ) |
|
| 17,377 |
|
| 18,058 |
|
|
| 115,701 |
|
|
| (115,829 | ) |
|
| 17,930 |
|
Total current liabilities |
| 272,932 |
|
|
| 110,806 |
|
|
| (99,240 | ) |
|
| 284,498 |
|
| 158,936 |
|
|
| 125,155 |
|
|
| (115,829 | ) |
|
| 168,262 |
|
Long-term debt, less current maturities |
| 1,360,057 |
|
|
| — |
|
|
| — |
|
|
| 1,360,057 |
| |||||||||||||||
Long-term debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Principal |
| 889,790 |
|
|
| — |
|
|
| — |
|
|
| 889,790 |
| |||||||||||||||
Carrying value adjustments |
| 79,337 |
|
|
| — |
|
|
| — |
|
|
| 79,337 |
| |||||||||||||||
Long term debt, less current portion - carrying value |
| 969,127 |
|
|
| — |
|
|
| — |
|
|
| 969,127 |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Asset retirement obligations, less current portion |
| 235,876 |
|
|
| 118,689 |
|
|
| — |
|
|
| 354,565 |
|
| 152,883 |
|
|
| 123,950 |
|
|
| — |
|
|
| 276,833 |
|
Deferred income taxes |
| 59,616 |
|
|
| 127,372 |
|
|
| — |
|
|
| 186,988 |
| |||||||||||||||
Other liabilities |
| 417,885 |
|
|
| — |
|
|
| (404,194 | ) |
|
| 13,691 |
|
| 566,375 |
|
|
| — |
|
|
| (499,509 | ) |
|
| 66,866 |
|
Shareholders’ equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Shareholders’ equity (deficit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Common stock |
| 1 |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Additional paid-in capital |
| 414,580 |
|
|
| 703,440 |
|
|
| (703,440 | ) |
|
| 414,580 |
|
| 545,820 |
|
|
| 704,885 |
|
|
| (704,885 | ) |
|
| 545,820 |
|
Retained earnings |
| 118,894 |
|
|
| 199,083 |
|
|
| (199,083 | ) |
|
| 118,894 |
| |||||||||||||||
Retained earnings (deficit) |
| (1,091,360 | ) |
|
| (306,177 | ) |
|
| 302,375 |
|
|
| (1,095,162 | ) | |||||||||||||||
Treasury stock, at cost |
| (24,167 | ) |
|
| — |
|
|
| — |
|
|
| (24,167 | ) |
| (24,167 | ) |
|
| — |
|
|
| — |
|
|
| (24,167 | ) |
Total shareholders’ equity |
| 509,308 |
|
|
| 902,523 |
|
|
| (902,523 | ) |
|
| 509,308 |
| |||||||||||||||
Total liabilities and shareholders’ equity | $ | 2,855,674 |
|
| $ | 1,259,390 |
|
| $ | (1,405,957 | ) |
| $ | 2,709,107 |
| |||||||||||||||
Total shareholders’ equity (deficit) |
| (569,706 | ) |
|
| 398,708 |
|
|
| (402,510 | ) |
|
| (573,508 | ) | |||||||||||||||
Total liabilities and shareholders’ equity (deficit) | $ | 1,277,615 |
|
| $ | 647,813 |
|
| $ | (1,017,848 | ) |
| $ | 907,580 |
|
106119
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Balance Sheet as of December 31, 20132016
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
| ||
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| ||||||
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| ||||||||
| (In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents | $ | 15,800 |
|
| $ | — |
|
| $ | — |
|
| $ | 15,800 |
| $ | 70,236 |
|
| $ | — |
|
| $ | — |
|
| $ | 70,236 |
|
Receivables: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
| 61,373 |
|
|
| 35,379 |
|
|
| — |
|
|
| 96,752 |
|
| 2,173 |
|
|
| 40,900 |
|
|
| — |
|
|
| 43,073 |
|
Joint interest and other |
| 123,595 |
|
|
| — |
|
|
| (92,491 | ) |
|
| 31,104 |
| |||||||||||||||
Joint interest |
| 21,885 |
|
|
| — |
|
|
|
|
|
|
| 21,885 |
| |||||||||||||||
Insurance reimbursement |
| 30,100 |
|
|
| — |
|
|
| — |
|
|
| 30,100 |
| |||||||||||||||
Income taxes |
| 111,215 |
|
|
| — |
|
|
| (99,272 | ) |
|
| 11,943 |
| |||||||||||||||
Total receivables |
| 184,968 |
|
|
| 35,379 |
|
|
| (92,491 | ) |
|
| 127,856 |
|
| 165,373 |
|
|
| 40,900 |
|
|
| (99,272 | ) |
|
| 107,001 |
|
Deferred income taxes |
| 584 |
|
|
| - |
|
|
| — |
|
|
| 584 |
| |||||||||||||||
Prepaid expenses and other assets |
| 23,090 |
|
|
| 6,272 |
|
|
| — |
|
|
| 29,362 |
|
| 12,448 |
|
|
| 2,056 |
|
|
| — |
|
|
| 14,504 |
|
Total current assets |
| 224,442 |
|
|
| 41,651 |
|
|
| (92,491 | ) |
|
| 173,602 |
|
| 248,057 |
|
|
| 42,956 |
|
|
| (99,272 | ) |
|
| 191,741 |
|
Property and equipment – at cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Oil and natural gas properties and equipment |
| 5,667,389 |
|
|
| 1,671,708 |
|
|
| — |
|
|
| 7,339,097 |
| |||||||||||||||
Furniture, fixtures and other |
| 21,431 |
|
|
| — |
|
|
| — |
|
|
| 21,431 |
| |||||||||||||||
Total property and equipment |
| 5,688,820 |
|
|
| 1,671,708 |
|
|
| — |
|
|
| 7,360,528 |
| |||||||||||||||
Less accumulated depreciation, depletion and amortization |
| 4,166,359 |
|
|
| 918,345 |
|
|
| — |
|
|
| 5,084,704 |
| |||||||||||||||
Net property and equipment |
| 1,522,461 |
|
|
| 753,363 |
|
|
| — |
|
|
| 2,275,824 |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Oil and natural gas properties and other, net |
| 360,966 |
|
|
| 187,040 |
|
|
| (953 | ) |
|
| 547,053 |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Restricted deposits for asset retirement obligations |
| 37,421 |
|
|
| — |
|
|
| — |
|
|
| 37,421 |
|
| 27,371 |
|
|
| — |
|
|
| — |
|
|
| 27,371 |
|
Income tax receivables |
| 52,097 |
|
|
| — |
|
|
| — |
|
|
| 52,097 |
| |||||||||||||||
Other assets |
| 951,203 |
|
|
| 479,820 |
|
|
| (1,410,568 | ) |
|
| 20,455 |
|
| 394,931 |
|
|
| 344,742 |
|
|
| (728,209 | ) |
|
| 11,464 |
|
Total assets | $ | 2,735,527 |
|
| $ | 1,274,834 |
|
| $ | (1,503,059 | ) |
| $ | 2,507,302 |
| $ | 1,083,422 |
|
| $ | 574,738 |
|
| $ | (828,434 | ) |
| $ | 829,726 |
|
Liabilities and Shareholders’ Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Liabilities and Shareholders’ Equity (Deficit) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable | $ | 144,492 |
|
| $ | 720 |
|
| $ | — |
|
| $ | 145,212 |
| $ | 74,306 |
|
| $ | 6,733 |
|
| $ | — |
|
| $ | 81,039 |
|
Undistributed oil and natural gas proceeds |
| 41,735 |
|
|
| 372 |
|
|
| — |
|
|
| 42,107 |
|
| 24,493 |
|
|
| 1,761 |
|
|
| — |
|
|
| 26,254 |
|
Asset retirement obligations |
| 65,329 |
|
|
| 12,456 |
|
|
| — |
|
|
| 77,785 |
|
| 62,261 |
|
|
| 16,003 |
|
|
| — |
|
|
| 78,264 |
|
Long-term debt |
| 8,272 |
|
|
| — |
|
|
| — |
|
|
| 8,272 |
| |||||||||||||||
Accrued liabilities |
| 28,000 |
|
|
| 92,491 |
|
|
| (92,491 | ) |
|
| 28,000 |
|
| 9,293 |
|
|
| 99,179 |
|
|
| (99,272 | ) |
|
| 9,200 |
|
Total current liabilities |
| 279,556 |
|
|
| 106,039 |
|
|
| (92,491 | ) |
|
| 293,104 |
|
| 178,625 |
|
|
| 123,676 |
|
|
| (99,272 | ) |
|
| 203,029 |
|
Long-term debt, less current maturities |
| 1,205,421 |
|
|
| — |
|
|
| — |
|
|
| 1,205,421 |
| |||||||||||||||
Long-term debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Principal |
| 873,733 |
|
|
| — |
|
|
| — |
|
|
| 873,733 |
| |||||||||||||||
Carrying value adjustments |
| 138,722 |
|
|
| — |
|
|
| — |
|
|
| 138,722 |
| |||||||||||||||
Long term debt, less current portion - carrying value |
| 1,012,455 |
|
|
| — |
|
|
| — |
|
|
| 1,012,455 |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Asset retirement obligations, less current portion |
| 189,507 |
|
|
| 87,130 |
|
|
| — |
|
|
| 276,637 |
|
| 142,376 |
|
|
| 113,798 |
|
|
| — |
|
|
| 256,174 |
|
Deferred income taxes |
| 79,424 |
|
|
| 98,718 |
|
|
| — |
|
|
| 178,142 |
| |||||||||||||||
Other liabilities |
| 441,009 |
|
|
| — |
|
|
| (427,621 | ) |
|
| 13,388 |
|
| 408,050 |
|
|
| — |
|
|
| (390,945 | ) |
|
| 17,105 |
|
Shareholders’ equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Shareholders’ equity (deficit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Common stock |
| 1 |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Additional paid-in capital |
| 403,564 |
|
|
| 784,104 |
|
|
| (784,104 | ) |
|
| 403,564 |
|
| 539,973 |
|
|
| 704,885 |
|
|
| (704,885 | ) |
|
| 539,973 |
|
Retained earnings |
| 161,212 |
|
|
| 198,843 |
|
|
| (198,843 | ) |
|
| 161,212 |
| |||||||||||||||
Retained earnings (deficit) |
| (1,173,891 | ) |
|
| (367,621 | ) |
|
| 366,668 |
|
|
| (1,174,844 | ) | |||||||||||||||
Treasury stock, at cost |
| (24,167 | ) |
|
| — |
|
|
| — |
|
|
| (24,167 | ) |
| (24,167 | ) |
|
| — |
|
|
| — |
|
|
| (24,167 | ) |
Total shareholders’ equity |
| 540,610 |
|
|
| 982,947 |
|
|
| (982,947 | ) |
|
| 540,610 |
| |||||||||||||||
Total liabilities and shareholders’ equity | $ | 2,735,527 |
|
| $ | 1,274,834 |
|
| $ | (1,503,059 | ) |
| $ | 2,507,302 |
| |||||||||||||||
Total shareholders’ equity (deficit) |
| (658,084 | ) |
|
| 337,264 |
|
|
| (338,217 | ) |
|
| (659,037 | ) | |||||||||||||||
Total liabilities and shareholders’ equity (deficit) | $ | 1,083,422 |
|
| $ | 574,738 |
|
| $ | (828,434 | ) |
| $ | 829,726 |
|
107120
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Operations for the Year Ended December 31, 20142017
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
| ||
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| ||||||
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| ||||||||
| (In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Revenues | $ | 592,460 |
|
| $ | 356,248 |
|
| $ | — |
|
| $ | 948,708 |
| $ | 231,396 |
|
| $ | 255,700 |
|
| $ | — |
|
| $ | 487,096 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
| 179,344 |
|
|
| 85,407 |
|
|
| — |
|
|
| 264,751 |
|
| 79,695 |
|
|
| 64,043 |
|
|
| — |
|
|
| 143,738 |
|
Production taxes |
| 7,932 |
|
|
| — |
|
|
| — |
|
|
| 7,932 |
|
| 1,740 |
|
|
| — |
|
|
| — |
|
|
| 1,740 |
|
Gathering and transportation |
| 11,712 |
|
|
| 8,109 |
|
|
| — |
|
|
| 19,821 |
|
| 9,781 |
|
|
| 10,660 |
|
|
| — |
|
|
| 20,441 |
|
Depreciation, depletion, amortization and accretion |
| 276,636 |
|
|
| 213,833 |
|
|
| — |
|
|
| 490,469 |
| |||||||||||||||
Depreciation, depletion and amortization |
| 73,962 |
|
|
| 61,700 |
|
|
| 2,848 |
|
|
| 138,510 |
| |||||||||||||||
Asset retirement obligations accretion |
| 10,981 |
|
|
| 9,652 |
|
|
| — |
|
|
| 20,633 |
|
| 7,416 |
|
|
| 9,756 |
|
|
| — |
|
|
| 17,172 |
|
General and administrative expenses |
| 48,084 |
|
|
| 38,915 |
|
|
| — |
|
|
| 86,999 |
|
| 28,170 |
|
|
| 31,574 |
|
|
| — |
|
|
| 59,744 |
|
Derivative gain |
| (3,965 | ) |
|
| — |
|
|
| — |
|
|
| (3,965 | ) |
| (4,199 | ) |
|
| — |
|
|
| — |
|
|
| (4,199 | ) |
Total costs and expenses |
| 530,724 |
|
|
| 355,916 |
|
|
| — |
|
|
| 886,640 |
|
| 196,565 |
|
|
| 177,733 |
|
|
| 2,848 |
|
|
| 377,146 |
|
Operating income |
| 61,736 |
|
|
| 332 |
|
|
| — |
|
|
| 62,068 |
| |||||||||||||||
Operating Income |
| 34,831 |
|
|
| 77,967 |
|
|
| (2,848 | ) |
|
| 109,950 |
| |||||||||||||||
Earnings of affiliates |
| 240 |
|
|
| — |
|
|
| (240 | ) |
|
| — |
|
| 61,444 |
|
|
| — |
|
|
| (61,444 | ) |
|
| — |
|
Interest expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Incurred |
| 84,460 |
|
|
| 2,462 |
|
|
| — |
|
|
| 86,922 |
| |||||||||||||||
Capitalized |
| (6,064 | ) |
|
| (2,462 | ) |
|
| — |
|
|
| (8,526 | ) | |||||||||||||||
Other income, net |
| 208 |
|
|
| — |
|
|
| — |
|
|
| 208 |
| |||||||||||||||
Income (loss) before income tax expense (benefit) |
| (16,212 | ) |
|
| 332 |
|
|
| (240 | ) |
|
| (16,120 | ) | |||||||||||||||
Interest expense incurred |
| 45,836 |
|
|
| — |
|
|
| — |
|
|
| 45,836 |
| |||||||||||||||
Gain on exchange of debt |
| 7,811 |
|
|
| — |
|
|
| — |
|
|
| 7,811 |
| |||||||||||||||
Other expense, net |
| 4,812 |
|
|
| — |
|
|
| — |
|
|
| 4,812 |
| |||||||||||||||
Income before income tax expense (benefit) |
| 53,438 |
|
|
| 77,967 |
|
|
| (64,292 | ) |
|
| 67,113 |
| |||||||||||||||
Income tax expense (benefit) |
| (4,551 | ) |
|
| 92 |
|
|
| — |
|
|
| (4,459 | ) |
| (29,092 | ) |
|
| 16,523 |
|
|
| — |
|
|
| (12,569 | ) |
Net income (loss) | $ | (11,661 | ) |
| $ | 240 |
|
| $ | (240 | ) |
| $ | (11,661 | ) | |||||||||||||||
Net income | $ | 82,530 |
|
| $ | 61,444 |
|
| $ | (64,292 | ) |
| $ | 79,682 |
|
108121
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Operations for the Year Ended December 31, 20132016
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
| ||
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| ||||||
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| ||||||||
| (In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Revenues | $ | 631,267 |
|
| $ | 352,821 |
|
| $ | — |
|
| $ | 984,088 |
| $ | 161,063 |
|
| $ | 238,923 |
|
| $ | — |
|
| $ | 399,986 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
| 202,096 |
|
|
| 68,743 |
|
|
| — |
|
|
| 270,839 |
|
| 84,415 |
|
|
| 67,984 |
|
|
| — |
|
|
| 152,399 |
|
Production taxes |
| 7,135 |
|
|
| — |
|
|
| — |
|
|
| 7,135 |
|
| 1,889 |
|
|
| — |
|
|
| — |
|
|
| 1,889 |
|
Gathering and transportation |
| 9,248 |
|
|
| 8,262 |
|
|
| — |
|
|
| 17,510 |
|
| 9,795 |
|
|
| 13,133 |
|
|
| — |
|
|
| 22,928 |
|
Depreciation, depletion, amortization and accretion |
| 236,600 |
|
|
| 194,011 |
|
|
| — |
|
|
| 430,611 |
| |||||||||||||||
Depreciation, depletion and amortization |
| 73,268 |
|
|
| 112,277 |
|
|
| 8,493 |
|
|
| 194,038 |
| |||||||||||||||
Asset retirement obligations accretion |
| 14,218 |
|
|
| 6,700 |
|
|
|
|
|
|
| 20,918 |
|
| 8,165 |
|
|
| 9,406 |
|
|
| — |
|
|
| 17,571 |
|
Ceiling test write-down of oil and natural gas properties |
| 28,305 |
|
|
| 110,709 |
|
|
| 140,049 |
|
|
| 279,063 |
| |||||||||||||||
General and administrative expenses |
| 44,040 |
|
|
| 37,834 |
|
|
| — |
|
|
| 81,874 |
|
| 24,817 |
|
|
| 34,923 |
|
|
| — |
|
|
| 59,740 |
|
Derivative loss |
| 8,470 |
|
|
| — |
|
|
| — |
|
|
| 8,470 |
|
| 2,926 |
|
|
| — |
|
|
| — |
|
|
| 2,926 |
|
Total costs and expenses |
| 521,807 |
|
|
| 315,550 |
|
|
| — |
|
|
| 837,357 |
|
| 233,580 |
|
|
| 348,432 |
|
|
| 148,542 |
|
|
| 730,554 |
|
Operating income |
| 109,460 |
|
|
| 37,271 |
|
|
| — |
|
|
| 146,731 |
| |||||||||||||||
Earnings of affiliates |
| 24,400 |
|
|
| — |
|
|
| (24,400 | ) |
|
| — |
| |||||||||||||||
Operating loss |
| (72,517 | ) |
|
| (109,509 | ) |
|
| (148,542 | ) |
|
| (330,568 | ) | |||||||||||||||
Loss of affiliates |
| (109,853 | ) |
|
| — |
|
|
| 109,853 |
|
|
| — |
| |||||||||||||||
Interest expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
| 82,570 |
|
|
| 3,069 |
|
|
| — |
|
|
| 85,639 |
|
| 92,607 |
|
|
| 184 |
|
|
| — |
|
|
| 92,791 |
|
Capitalized |
| (6,989 | ) |
|
| (3,069 | ) |
|
| — |
|
|
| (10,058 | ) |
| (336 | ) |
|
| (184 | ) |
|
| — |
|
|
| (520 | ) |
Gain on exchange of debt |
| 123,923 |
|
|
| — |
|
|
| — |
|
|
| 123,923 |
| |||||||||||||||
Other income, net |
| 8,946 |
|
|
| — |
|
|
| — |
|
|
| 8,946 |
|
| (6,520 | ) |
|
| — |
|
|
| — |
|
|
| (6,520 | ) |
Income before income tax expense |
| 67,225 |
|
|
| 37,271 |
|
|
| (24,400 | ) |
|
| 80,096 |
| |||||||||||||||
Income tax expense |
| 15,903 |
|
|
| 12,871 |
|
|
| — |
|
|
| 28,774 |
| |||||||||||||||
Net income | $ | 51,322 |
|
| $ | 24,400 |
|
| $ | (24,400 | ) |
| $ | 51,322 |
| |||||||||||||||
Loss before income tax expense (benefit) |
| (144,198 | ) |
|
| (109,509 | ) |
|
| (38,689 | ) |
|
| (292,396 | ) | |||||||||||||||
Income tax expense (benefit) |
| (43,720 | ) |
|
| 344 |
|
|
| — |
|
|
| (43,376 | ) | |||||||||||||||
Net loss | $ | (100,478 | ) |
| $ | (109,853 | ) |
| $ | (38,689 | ) |
| $ | (249,020 | ) |
109122
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Operations for the Year Ended December 31, 20122015
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
| ||
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| ||||||
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| ||||||||
| (In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Revenues | $ | 539,958 |
|
| $ | 334,533 |
|
| $ | — |
|
| $ | 874,491 |
| $ | 290,212 |
|
| $ | 217,053 |
|
| $ | — |
|
| $ | 507,265 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
| 168,033 |
|
|
| 64,227 |
|
|
| — |
|
|
| 232,260 |
|
| 126,189 |
|
|
| 66,576 |
|
|
| — |
|
|
| 192,765 |
|
Production taxes |
| 5,840 |
|
|
| — |
|
|
| — |
|
|
| 5,840 |
|
| 3,002 |
|
|
| — |
|
|
| — |
|
|
| 3,002 |
|
Gathering and transportation |
| 10,197 |
|
|
| 4,681 |
|
|
| — |
|
|
| 14,878 |
|
| 9,209 |
|
|
| 7,948 |
|
|
| — |
|
|
| 17,157 |
|
Depreciation, depletion, amortization and accretion |
| 187,039 |
|
|
| 149,138 |
|
|
| — |
|
|
| 336,177 |
| |||||||||||||||
Depreciation, depletion and amortization |
| 201,154 |
|
|
| 172,214 |
|
|
| — |
|
|
| 373,368 |
| |||||||||||||||
Asset retirement obligations accretion |
| 14,979 |
|
|
| 5,076 |
|
|
|
|
|
|
| 20,055 |
|
| 11,587 |
|
|
| 9,116 |
|
|
| — |
|
|
| 20,703 |
|
Ceiling test write-down of oil and natural gas properties |
| 616,947 |
|
|
| 517,880 |
|
|
| (147,589 | ) |
|
| 987,238 |
| |||||||||||||||
General and administrative expenses |
| 45,260 |
|
|
| 36,757 |
|
|
| — |
|
|
| 82,017 |
|
| 39,009 |
|
|
| 34,101 |
|
|
| — |
|
|
| 73,110 |
|
Derivative loss |
| 13,954 |
|
|
| — |
|
|
| — |
|
|
| 13,954 |
| |||||||||||||||
Derivative gain |
| (14,375 | ) |
|
| — |
|
|
| — |
|
|
| (14,375 | ) | |||||||||||||||
Total costs and expenses |
| 445,302 |
|
|
| 259,879 |
|
|
| — |
|
|
| 705,181 |
|
| 992,722 |
|
|
| 807,835 |
|
|
| (147,589 | ) |
|
| 1,652,968 |
|
Operating income |
| 94,656 |
|
|
| 74,654 |
|
|
| — |
|
|
| 169,310 |
| |||||||||||||||
Earnings of affiliates |
| 49,799 |
|
|
| — |
|
|
| (49,799 | ) |
|
| — |
| |||||||||||||||
Operating loss |
| (702,510 | ) |
|
| (590,782 | ) |
|
| 147,589 |
|
|
| (1,145,703 | ) | |||||||||||||||
Loss of affiliates |
| (464,931 | ) |
|
| — |
|
|
| 464,931 |
|
|
| — |
| |||||||||||||||
Interest expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
| 60,778 |
|
|
| 2,490 |
|
|
| — |
|
|
| 63,268 |
|
| 101,542 |
|
|
| 3,050 |
|
|
| — |
|
|
| 104,592 |
|
Capitalized |
| (10,784 | ) |
|
| (2,490 | ) |
|
| — |
|
|
| (13,274 | ) |
| (4,206 | ) |
|
| (3,050 | ) |
|
| — |
|
|
| (7,256 | ) |
Other income, net |
| 215 |
|
|
| — |
|
|
| — |
|
|
| 215 |
| |||||||||||||||
Income before income tax expense |
| 94,676 |
|
|
| 74,654 |
|
|
| (49,799 | ) |
|
| 119,531 |
| |||||||||||||||
Income tax expense |
| 22,692 |
|
|
| 24,855 |
|
|
| — |
|
|
| 47,547 |
| |||||||||||||||
Net income | $ | 71,984 |
|
| $ | 49,799 |
|
| $ | (49,799 | ) |
| $ | 71,984 |
| |||||||||||||||
Other expense, net |
| 4,663 |
|
|
| — |
|
|
| — |
|
|
| 4,663 |
| |||||||||||||||
Loss before income tax benefit |
| (1,269,440 | ) |
|
| (590,782 | ) |
|
| 612,520 |
|
|
| (1,247,702 | ) | |||||||||||||||
Income tax benefit |
| (77,133 | ) |
|
| (125,851 | ) |
|
| — |
|
|
| (202,984 | ) | |||||||||||||||
Net loss | $ | (1,192,307 | ) |
| $ | (464,931 | ) |
| $ | 612,520 |
|
| $ | (1,044,718 | ) |
110123
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 20142017
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
| ||
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| ||||||
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| ||||||||
| (In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) | $ | (11,661 | ) |
| $ | 240 |
|
| $ | (240 | ) |
| $ | (11,661 | ) | |||||||||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Net income | $ | 82,530 |
|
| $ | 61,444 |
|
| $ | (64,292 | ) |
| $ | 79,682 |
| |||||||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Depreciation, depletion, amortization and accretion |
| 287,617 |
|
|
| 223,485 |
|
|
| — |
|
|
| 511,102 |
|
| 81,378 |
|
|
| 71,456 |
|
|
| 2,848 |
|
|
| 155,682 |
|
Amortization of debt issuance costs and premium |
| 701 |
|
|
| — |
|
|
| — |
|
|
| 701 |
| |||||||||||||||
Gain on exchange of debt |
| (7,811 | ) |
|
| — |
|
|
| — |
|
|
| (7,811 | ) | |||||||||||||||
Amortization of debt items |
| 1,715 |
|
|
| — |
|
|
| — |
|
|
| 1,715 |
| |||||||||||||||
Share-based compensation |
| 14,744 |
|
|
| — |
|
|
| — |
|
|
| 14,744 |
|
| 7,191 |
|
|
| — |
|
|
| — |
|
|
| 7,191 |
|
Derivative gain |
| (3,965 | ) |
|
| — |
|
|
| — |
|
|
| (3,965 | ) |
| (4,199 | ) |
|
| — |
|
|
| — |
|
|
| (4,199 | ) |
Cash payments on derivative settlements, net |
| (5,318 | ) |
|
| — |
|
|
| — |
|
|
| (5,318 | ) | |||||||||||||||
Cash receipts on derivative settlements, net |
| 4,199 |
|
|
| — |
|
|
| — |
|
|
| 4,199 |
| |||||||||||||||
Deferred income taxes |
| (32,456 | ) |
|
| 27,696 |
|
|
| — |
|
|
| (4,760 | ) |
| 217 |
|
|
| — |
|
|
| — |
|
|
| 217 |
|
Earnings of affiliates |
| (240 | ) |
|
| — |
|
|
| 240 |
|
|
| — |
| |||||||||||||||
Loss of affiliates |
| (61,444 | ) |
|
| — |
|
|
| 61,444 |
|
|
| — |
| |||||||||||||||
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas receivables |
| 19,553 |
|
|
| 9,957 |
|
|
| — |
|
|
| 29,510 |
|
| (3,491 | ) |
|
| 1,121 |
|
|
| — |
|
|
| (2,370 | ) |
Joint interest and other receivables |
| (4,255 | ) |
|
| — |
|
|
| — |
|
|
| (4,255 | ) | |||||||||||||||
Joint interest receivables |
| 2,131 |
|
|
| — |
|
|
| — |
|
|
| 2,131 |
| |||||||||||||||
Insurance reimbursements |
| 31,740 |
|
|
| — |
|
|
| — |
|
|
| 31,740 |
| |||||||||||||||
Income taxes |
| 30,747 |
|
|
| (27,604 | ) |
|
| — |
|
|
| 3,143 |
|
| (17,586 | ) |
|
| 16,523 |
|
|
| — |
|
|
| (1,063 | ) |
Prepaid expenses and other assets |
| 25,555 |
|
|
| 12,882 |
|
|
| (23,425 | ) |
|
| 15,012 |
|
| 3,447 |
|
|
| (108,773 | ) |
|
| 108,564 |
|
|
| 3,238 |
|
Escrow deposit - Apache lawsuit |
| (49,500 | ) |
|
| — |
|
|
| — |
|
|
| (49,500 | ) | |||||||||||||||
Asset retirement obligation settlements |
| (57,253 | ) |
|
| (17,060 | ) |
|
| — |
|
|
| (74,313 | ) |
| (55,672 | ) |
|
| (16,737 | ) |
|
| — |
|
|
| (72,409 | ) |
Accounts payable, accrued liabilities and other |
| 12,816 |
|
|
| 5,242 |
|
|
| 23,425 |
|
|
| 41,483 |
|
| 127,496 |
|
|
| (7,967 | ) |
|
| (108,564 | ) |
|
| 10,965 |
|
Net cash provided by operating activities |
| 276,585 |
|
|
| 234,838 |
|
|
| — |
|
|
| 511,423 |
|
| 142,341 |
|
|
| 17,067 |
|
|
| — |
|
|
| 159,408 |
|
Investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of property interest in oil and natural gas properties |
| (17,407 | ) |
|
| (54,827 | ) |
|
| — |
|
|
| (72,234 | ) | |||||||||||||||
Investment in oil and natural gas properties and equipment |
| (312,044 | ) |
|
| (242,334 | ) |
|
| — |
|
|
| (554,378 | ) |
| (105,179 | ) |
|
| (24,869 | ) |
|
| — |
|
|
| (130,048 | ) |
Investment in subsidiary |
| (62,323 | ) |
|
| — |
|
|
| 62,323 |
|
|
| — |
| |||||||||||||||
Changes in operating assets and liabilities associated with investing activities |
| 16,072 |
|
|
| 7,802 |
|
|
| — |
|
|
| 23,874 |
| |||||||||||||||
Purchases of furniture, fixtures and other |
| (3,340 | ) |
|
| — |
|
|
| — |
|
|
| (3,340 | ) |
| (933 | ) |
|
| — |
|
|
| — |
|
|
| (933 | ) |
Net cash used in investing activities |
| (395,114 | ) |
|
| (297,161 | ) |
|
| 62,323 |
|
|
| (629,952 | ) |
| (90,040 | ) |
|
| (17,067 | ) |
|
| — |
|
|
| (107,107 | ) |
Financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings of long-term debt – revolving bank credit facility |
| 556,000 |
|
|
| — |
|
|
| — |
|
|
| 556,000 |
| |||||||||||||||
Repayments of long-term debt – revolving bank credit facility |
| (399,000 | ) |
|
| — |
|
|
| — |
|
|
| (399,000 | ) | |||||||||||||||
Dividends to shareholders |
| (30,260 | ) |
|
| — |
|
|
| — |
|
|
| (30,260 | ) | |||||||||||||||
Payment of interest on 1.5 Lien Term Loan |
| (8,227 | ) |
|
| — |
|
|
| — |
|
|
| (8,227 | ) | |||||||||||||||
Payment of interest on 2nd Lien PIK Toggle Notes |
| (7,335 | ) |
|
| — |
|
|
| — |
|
|
| (7,335 | ) | |||||||||||||||
Payment of interest on 3rd Lien PIK Toggle Notes |
| (6,201 | ) |
|
| — |
|
|
| — |
|
|
| (6,201 | ) | |||||||||||||||
Debt exchange costs |
| (421 | ) |
|
| — |
|
|
| — |
|
|
| (421 | ) | |||||||||||||||
Other |
| (345 | ) |
|
| — |
|
|
| — |
|
|
| (345 | ) |
| (1,295 | ) |
|
| — |
|
|
| — |
|
|
| (1,295 | ) |
Investment from parent |
| — |
|
|
| 62,323 |
|
|
| (62,323 | ) |
|
| — |
| |||||||||||||||
Net cash provided in financing activities |
| 126,395 |
|
|
| 62,323 |
|
|
| (62,323 | ) |
|
| 126,395 |
| |||||||||||||||
Net cash used in financing activities |
| (23,479 | ) |
|
| — |
|
|
| — |
|
|
| (23,479 | ) | |||||||||||||||
Increase in cash and cash equivalents |
| 7,866 |
|
|
| — |
|
|
| — |
|
|
| 7,866 |
|
| 28,822 |
|
|
| — |
|
|
| — |
|
|
| 28,822 |
|
Cash and cash equivalents, beginning of period |
| 15,800 |
|
|
| — |
|
|
| — |
|
|
| 15,800 |
|
| 70,236 |
|
|
| — |
|
|
| — |
|
|
| 70,236 |
|
Cash and cash equivalents, end of period | $ | 23,666 |
|
| $ | — |
|
| $ | — |
|
| $ | 23,666 |
| $ | 99,058 |
|
| $ | — |
|
| $ | — |
|
| $ | 99,058 |
|
111124
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 20132016
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
| ||
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| ||||||
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| ||||||||
| (In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income | $ | 51,322 |
|
| $ | 24,400 |
|
| $ | (24,400 | ) |
| $ | 51,322 |
| |||||||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Net loss | $ | (100,478 | ) |
| $ | (109,853 | ) |
| $ | (38,689 | ) |
| $ | (249,020 | ) | |||||||||||||||
Adjustments to reconcile net loss to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Depreciation, depletion, amortization and accretion |
| 250,818 |
|
|
| 200,711 |
|
|
| — |
|
|
| 451,529 |
|
| 81,433 |
|
|
| 121,683 |
|
|
| 8,493 |
|
|
| 211,609 |
|
Amortization of debt issuance costs and premium |
| 1,645 |
|
|
| — |
|
|
| — |
|
|
| 1,645 |
| |||||||||||||||
Ceiling test write-down of oil and gas properties |
| 28,305 |
|
|
| 110,709 |
|
|
| 140,049 |
|
|
| 279,063 |
| |||||||||||||||
Gain on exchange of debt |
| (123,923 | ) |
|
| — |
|
|
| — |
|
|
| (123,923 | ) | |||||||||||||||
Debt issuance costs write-down/amortization of debt items |
| 2,548 |
|
|
| — |
|
|
| — |
|
|
| 2,548 |
| |||||||||||||||
Share-based compensation |
| 11,525 |
|
|
| — |
|
|
| — |
|
|
| 11,525 |
|
| 11,013 |
|
|
| — |
|
|
| — |
|
|
| 11,013 |
|
Derivative loss |
| 8,470 |
|
|
| — |
|
|
| — |
|
|
| 8,470 |
| |||||||||||||||
Derivative gain |
| 2,926 |
|
|
| — |
|
|
| — |
|
|
| 2,926 |
| |||||||||||||||
Cash payments on derivative settlements |
| (8,589 | ) |
|
| — |
|
|
| — |
|
|
| (8,589 | ) |
| 4,746 |
|
|
| — |
|
|
| — |
|
|
| 4,746 |
|
Deferred income taxes |
| 7,564 |
|
|
| 23,356 |
|
|
| — |
|
|
| 30,920 |
|
| 28,048 |
|
|
| 344 |
|
|
| — |
|
|
| 28,392 |
|
Earnings of affiliates |
| (24,400 | ) |
|
| — |
|
|
| 24,400 |
|
|
| — |
| |||||||||||||||
Loss of affiliates |
| 109,853 |
|
|
| — |
|
|
| (109,853 | ) |
|
| — |
| |||||||||||||||
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas receivables |
| 6,182 |
|
|
| (5,202 | ) |
|
| — |
|
|
| 980 |
|
| 1,630 |
|
|
| (8,635 | ) |
|
| — |
|
|
| (7,005 | ) |
Joint interest and other receivables |
| 34,257 |
|
|
| — |
|
|
| — |
|
|
| 34,257 |
| |||||||||||||||
Joint interest receivables |
| 12 |
|
|
| — |
|
|
| — |
|
|
| 12 |
| |||||||||||||||
Income taxes |
| 54,813 |
|
|
| (10,485 | ) |
|
| — |
|
|
| 44,328 |
|
| (64,274 | ) |
|
| — |
|
|
| — |
|
|
| (64,274 | ) |
Prepaid expenses and other assets |
| (25,329 | ) |
|
| (18,835 | ) |
|
| 34,120 |
|
|
| (10,044 | ) |
| (14,395 | ) |
|
| (78,547 | ) |
|
| 77,996 |
|
|
| (14,946 | ) |
Asset retirement obligations |
| (65,438 | ) |
|
| (16,105 | ) |
|
| — |
|
|
| (81,543 | ) |
| (49,303 | ) |
|
| (23,017 | ) |
|
| — |
|
|
| (72,320 | ) |
Accounts payable, accrued liabilities and other |
| 59,961 |
|
|
| 717 |
|
|
| (34,120 | ) |
|
| 26,558 |
|
| 45,817 |
|
|
| 37,538 |
|
|
| (77,996 | ) |
|
| 5,359 |
|
Net cash provided by operating activities |
| 362,801 |
|
|
| 198,557 |
|
|
| — |
|
|
| 561,358 |
| |||||||||||||||
Net cash provided by (used in) operating activities |
| (36,042 | ) |
|
| 50,222 |
|
|
| — |
|
|
| 14,180 |
| |||||||||||||||
Investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of property interest in oil and natural gas properties |
| — |
|
|
| (82,424 | ) |
|
| — |
|
|
| (82,424 | ) | |||||||||||||||
Investment in oil and natural gas properties and equipment |
| (349,804 | ) |
|
| (202,150 | ) |
|
| — |
|
|
| (551,954 | ) |
| (37,418 | ) |
|
| (11,188 | ) |
|
| — |
|
|
| (48,606 | ) |
Investment in subsidiary |
| (86,017 | ) |
|
| — |
|
|
| 86,017 |
|
|
| — |
| |||||||||||||||
Proceeds from sales of assets and other, net |
| 21,008 |
|
|
| — |
|
|
| — |
|
|
| 21,008 |
| |||||||||||||||
Changes in operating assets and liabilities associated with investing activities |
| 4,340 |
|
|
| (39,534 | ) |
|
| — |
|
|
| (35,194 | ) | |||||||||||||||
Proceeds from sales of assets, net |
| 1,000 |
|
|
| 500 |
|
|
| — |
|
|
| 1,500 |
| |||||||||||||||
Purchases of furniture, fixtures and other |
| (1,435 | ) |
|
| — |
|
|
| — |
|
|
| (1,435 | ) |
| (96 | ) |
|
| — |
|
|
| — |
|
|
| (96 | ) |
Net cash used in investing activities |
| (416,248 | ) |
|
| (284,574 | ) |
|
| 86,017 |
|
|
| (614,805 | ) |
| (32,174 | ) |
|
| (50,222 | ) |
|
| — |
|
|
| (82,396 | ) |
Financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings of long-term debt – revolving bank credit facility |
| 563,000 |
|
|
| — |
|
|
| — |
|
|
| 563,000 |
|
| 340,000 |
|
|
| — |
|
|
| — |
|
|
| 340,000 |
|
Repayments of long-term debt – revolving bank credit facility |
| (443,000 | ) |
|
| — |
|
|
| — |
|
|
| (443,000 | ) |
| (340,000 | ) |
|
| — |
|
|
| — |
|
|
| (340,000 | ) |
Debt issuance costs |
| (3,892 | ) |
|
| — |
|
|
| — |
|
|
| (3,892 | ) | |||||||||||||||
Dividends to shareholders |
| (58,846 | ) |
|
| — |
|
|
| — |
|
|
| (58,846 | ) | |||||||||||||||
Investment from parent |
| — |
|
|
| 86,017 |
|
|
| (86,017 | ) |
|
| — |
| |||||||||||||||
Issuance of 1.5 Lien Term Loan |
| 75,000 |
|
|
| — |
|
|
| — |
|
|
| 75,000 |
| |||||||||||||||
Payment of interest on 1.5 Lien Term Loan |
| (2,570 | ) |
|
| — |
|
|
| — |
|
|
| (2,570 | ) | |||||||||||||||
Debt exchange costs |
| (18,464 | ) |
|
| — |
|
|
| — |
|
|
| (18,464 | ) | |||||||||||||||
Other |
| (260 | ) |
|
| — |
|
|
| — |
|
|
| (260 | ) |
| (928 | ) |
|
| — |
|
|
| — |
|
|
| (928 | ) |
Net cash used in financing activities |
| 57,002 |
|
|
| 86,017 |
|
|
| (86,017 | ) |
|
| 57,002 |
| |||||||||||||||
Increase in cash and cash equivalents |
| 3,555 |
|
|
| — |
|
|
| — |
|
|
| 3,555 |
| |||||||||||||||
Net cash provided by financing activities |
| 53,038 |
|
|
| — |
|
|
| — |
|
|
| 53,038 |
| |||||||||||||||
Decrease in cash and cash equivalents |
| (15,178 | ) |
|
| — |
|
|
| — |
|
|
| (15,178 | ) | |||||||||||||||
Cash and cash equivalents, beginning of period |
| 12,245 |
|
|
| — |
|
|
| — |
|
|
| 12,245 |
|
| 85,414 |
|
|
| — |
|
|
| — |
|
|
| 85,414 |
|
Cash and cash equivalents, end of period | $ | 15,800 |
|
| $ | — |
|
| $ | — |
|
| $ | 15,800 |
| $ | 70,236 |
|
| $ | — |
|
| $ | — |
|
| $ | 70,236 |
|
112125
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 20122015
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
| Consolidated |
| ||
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| Parent |
|
| Guarantor |
|
|
|
|
|
| W&T |
| ||||||
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| Company |
|
| Subsidiaries |
|
| Eliminations |
|
| Offshore, Inc. |
| ||||||||
| (In thousands) |
|
|
| ||||||||||||||||||||||||||
Operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income | $ | 71,984 |
|
| $ | 49,799 |
|
| $ | (49,799 | ) |
| $ | 71,984 |
| |||||||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Net loss | $ | (1,192,307 | ) |
| $ | (464,931 | ) |
| $ | 612,520 |
|
| $ | (1,044,718 | ) | |||||||||||||||
Adjustments to reconcile loss to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Depreciation, depletion, amortization and accretion |
| 202,018 |
|
|
| 154,214 |
|
|
| — |
|
|
| 356,232 |
|
| 212,741 |
|
|
| 181,330 |
|
|
| — |
|
|
| 394,071 |
|
Amortization of debt issuance costs and premium |
| 2,575 |
|
|
| — |
|
|
| — |
|
|
| 2,575 |
| |||||||||||||||
Ceiling test write-down of oil and gas properties |
| 616,947 |
|
|
| 517,880 |
|
|
| (147,589 | ) |
|
| 987,238 |
| |||||||||||||||
Debt issuance costs write-down/amortization of debt items |
| 4,411 |
|
|
| — |
|
|
| — |
|
|
| 4,411 |
| |||||||||||||||
Share-based compensation |
| 12,398 |
|
|
| — |
|
|
| — |
|
|
| 12,398 |
|
| 10,242 |
|
|
| — |
|
|
| — |
|
|
| 10,242 |
|
Derivative loss |
| 13,954 |
|
|
| — |
|
|
| — |
|
|
| 13,954 |
|
| (14,375 | ) |
|
| — |
|
|
| — |
|
|
| (14,375 | ) |
Cash payments on derivative settlements |
| (7,664 | ) |
|
| — |
|
|
| — |
|
|
| (7,664 | ) |
| 6,703 |
|
|
| — |
|
|
| — |
|
|
| 6,703 |
|
Deferred income taxes |
| 81,653 |
|
|
| 6,456 |
|
|
| — |
|
|
| 88,109 |
|
| (77,421 | ) |
|
| (125,851 | ) |
|
| — |
|
|
| (203,272 | ) |
Earnings of affiliates |
| (49,799 | ) |
|
| — |
|
|
| 49,799 |
|
|
| — |
|
| 464,931 |
|
|
| — |
|
|
| (464,931 | ) |
|
| — |
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas receivables |
| (3,783 | ) |
|
| 4,601 |
|
|
| — |
|
|
| 818 |
|
| 39,078 |
|
|
| (6,842 | ) |
|
| — |
|
|
| 32,236 |
|
Joint interest and other receivables |
| (28,823 | ) |
|
| — |
|
|
| — |
|
|
| (28,823 | ) | |||||||||||||||
Joint interest receivables |
| 21,645 |
|
|
| — |
|
|
| — |
|
|
| 21,645 |
| |||||||||||||||
Income taxes |
| (76,411 | ) |
|
| 18,400 |
|
|
| — |
|
|
| (58,011 | ) |
| (7 | ) |
|
| — |
|
|
| — |
|
|
| (7 | ) |
Prepaid expenses and other assets |
| 9,017 |
|
|
| (119,895 | ) |
|
| 118,318 |
|
|
| 7,440 |
|
| (13,916 | ) |
|
| 122,977 |
|
|
| (91,245 | ) |
|
| 17,816 |
|
Asset retirement obligations |
| (105,773 | ) |
|
| (7,054 | ) |
|
| — |
|
|
| (112,827 | ) |
| (26,637 | ) |
|
| (5,918 | ) |
|
| — |
|
|
| (32,555 | ) |
Accounts payable, accrued liabilities and other |
| 159,774 |
|
|
| (2,504 | ) |
|
| (118,318 | ) |
|
| 38,952 |
|
| (141,608 | ) |
|
| 4,156 |
|
|
| 91,245 |
|
|
| (46,207 | ) |
Net cash provided by operating activities |
| 281,120 |
|
|
| 104,017 |
|
|
| — |
|
|
| 385,137 |
| |||||||||||||||
Net cash provided by (used in) operating activities |
| (89,573 | ) |
|
| 222,801 |
|
|
| — |
|
|
| 133,228 |
| |||||||||||||||
Investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of property interest in oil and natural gas properties |
| (151,429 | ) |
|
| (54,121 | ) |
|
| — |
|
|
| (205,550 | ) | |||||||||||||||
Investment in oil and natural gas properties and equipment |
| (375,296 | ) |
|
| (104,017 | ) |
|
| — |
|
|
| (479,313 | ) |
| (31,534 | ) |
|
| (198,627 | ) |
|
| — |
|
|
| (230,161 | ) |
Changes in operating assets and liabilities associated with investing activities |
| (29,806 | ) |
|
| (25,619 | ) |
|
| — |
|
|
| (55,425 | ) | |||||||||||||||
Proceeds from sales of assets, net |
| 372,939 |
|
|
| — |
|
|
| — |
|
|
| 372,939 |
| |||||||||||||||
Investment in subsidiary |
| (54,121 | ) |
|
| — |
|
|
| 54,121 |
|
|
| — |
|
| (1,445 | ) |
|
| — |
|
|
| 1,445 |
|
|
| — |
|
Proceeds from sales of assets and other, net |
| 30,453 |
|
|
| — |
|
|
| — |
|
|
| 30,453 |
| |||||||||||||||
Purchases of furniture, fixtures and other |
| (3,031 | ) |
|
| — |
|
|
| — |
|
|
| (3,031 | ) |
| (1,278 | ) |
|
| — |
|
|
| — |
|
|
| (1,278 | ) |
Net cash used in investing activities |
| (553,424 | ) |
|
| (158,138 | ) |
|
| 54,121 |
|
|
| (657,441 | ) | |||||||||||||||
Net cash provided by (used in) investing activities |
| 308,876 |
|
|
| (224,246 | ) |
|
| 1,445 |
|
|
| 86,075 |
| |||||||||||||||
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 |
|
| 263,000 |
|
|
| — |
|
|
| — |
|
|
| 263,000 |
|
Repayments of long-term debt – revolving bank credit facility |
| (679,000 | ) |
|
| — |
|
|
| — |
|
|
| (679,000 | ) |
| (710,000 | ) |
|
| — |
|
|
| — |
|
|
| (710,000 | ) |
Issuance of 9.00% Second Lien Term Loan |
| 297,000 |
|
|
| — |
|
|
| — |
|
|
| 297,000 |
| |||||||||||||||
Debt issuance costs |
| (8,510 | ) |
|
| — |
|
|
| — |
|
|
| (8,510 | ) |
| (6,669 | ) |
|
| — |
|
|
| — |
|
|
| (6,669 | ) |
Dividends to shareholders |
| (82,832 | ) |
|
| — |
|
|
| — |
|
|
| (82,832 | ) | |||||||||||||||
Other |
| (886 | ) |
|
| — |
|
|
| — |
|
|
| (886 | ) | |||||||||||||||
Investment from parent |
| — |
|
|
| 54,121 |
|
|
| (54,121 | ) |
|
| — |
|
| — |
|
|
| 1,445 |
|
|
| (1,445 | ) |
|
| — |
|
Other |
| 379 |
|
|
| — |
|
|
| — |
|
|
| 379 |
| |||||||||||||||
Net cash used in financing activities |
| 280,037 |
|
|
| 54,121 |
|
|
| (54,121 | ) |
|
| 280,037 |
| |||||||||||||||
Net cash provided by (used in) financing activities |
| (157,555 | ) |
|
| 1,445 |
|
|
| (1,445 | ) |
|
| (157,555 | ) | |||||||||||||||
Increase in cash and cash equivalents |
| 7,733 |
|
|
| — |
|
|
| — |
|
|
| 7,733 |
|
| 61,748 |
|
|
| — |
|
|
| — |
|
|
| 61,748 |
|
Cash and cash equivalents, beginning of period |
| 4,512 |
|
|
| — |
|
|
| — |
|
|
| 4,512 |
|
| 23,666 |
|
|
| — |
|
|
| — |
|
|
| 23,666 |
|
Cash and cash equivalents, end of period | $ | 12,245 |
|
| $ | — |
|
| $ | — |
|
| $ | 12,245 |
| $ | 85,414 |
|
| $ | — |
|
| $ | — |
|
| $ | 85,414 |
|
113126
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
21.20. Supplemental Oil and Gas Disclosures—UNAUDITED
Geographic Area of Operation
All of our proved reserves are located within the United States with a majority of those reserves located in the Gulf of Mexico and a minority located in Texas.Mexico. Therefore, the following disclosures about our costs incurred, results of operations and proved reserves are on a total-company basis.
Capitalized Costs
Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions):
| December 31, |
| December 31, |
| ||||||||||||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| 2017 |
|
| 2016 |
|
| 2015 |
| ||||||
Net capitalized cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and natural gas properties and equipment | $ | 7,924.2 |
|
| $ | 7,207.1 |
|
| $ | 6,551.5 |
| $ | 8,102.0 |
|
| $ | 7,932.5 |
|
| $ | 7,882.3 |
|
Unproved oil and natural gas properties and equipment |
| 121.5 |
|
|
| 132.0 |
|
|
| 143.0 |
|
| — |
|
|
| — |
|
|
| 20.2 |
|
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities |
| (5,557.6 | ) |
|
| (5,069.2 | ) |
|
| (4,640.8 | ) | |||||||||||
Accumulated depreciation, depletion and amortization (1) related to oil, NGLs and natural gas activities |
| (7,525.0 | ) |
|
| (7,387.8 | ) |
|
| (6,916.2 | ) | |||||||||||
Net capitalized costs related to producing activities | $ | 2,488.1 |
|
| $ | 2,269.9 |
|
| $ | 2,053.7 |
| $ | 577.0 |
|
| $ | 544.7 |
|
| $ | 986.3 |
|
Costs Not Subject To Amortization
Costs not subject to amortization relate to unproved properties which are excluded from amortizable capital costs until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. Subject to industry conditions, evaluation of most of these properties is expected to be completed within one to five years. The following table provides a summary of costs that are not being amortized as of December 31, 2014, by the year in which the costs were incurred (in millions):
| Total |
|
| 2014 |
|
| 2013 |
|
| 2012 |
|
| Prior to 2012 |
| |||||
Costs excluded by year incurred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs | $ | 75.5 |
|
| $ | 2.6 |
|
| $ | 5.7 |
|
| $ | 7.0 |
|
| $ | 60.2 |
|
Capitalized interest not subject to amortization |
| 34.3 |
|
|
| 7.5 |
|
|
| 7.3 |
|
|
| 6.4 |
|
|
| 13.1 |
|
Total costs not subject to amortization | $ | 109.8 |
|
| $ | 10.1 |
|
| $ | 13.0 |
|
| $ | 13.4 |
|
| $ | 73.3 |
|
114
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| (1) | Includes ceiling test write-down in 2016 and 2015. |
Costs Incurred In Oil and Gas Property Acquisition, Exploration and Development Activities
The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions):
| December 31, |
| Year Ended December 31, |
| ||||||||||||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| 2017 |
|
| 2016 |
|
| 2015 |
| ||||||
Costs incurred: (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties acquisitions | $ | 111.5 |
|
| $ | 96.9 |
|
| $ | 239.8 |
| $ | 1.1 |
|
| $ | 1.3 |
|
| $ | 15.6 |
|
Exploration (2) (3) |
| 411.1 |
|
|
| 215.3 |
|
|
| 151.3 |
|
| 62.0 |
|
|
| 4.8 |
|
|
| 152.4 |
|
Development |
| 198.7 |
|
|
| 352.9 |
|
|
| 363.7 |
|
| 92.5 |
|
|
| 56.9 |
|
|
| 65.5 |
|
Unproved properties acquisitions |
| 3.1 |
|
|
| 26.3 |
|
|
| 26.5 |
|
| — |
|
|
| 0.5 |
|
|
| 0.1 |
|
Total costs incurred in oil and gas property acquisition, exploration and development activities | $ | 724.4 |
|
| $ | 691.4 |
|
| $ | 781.3 |
| $ | 155.6 |
|
| $ | 63.5 |
|
| $ | 233.6 |
|
(1) | Includes net additions from capitalized ARO of |
(2) | Includes seismic costs of |
(3) | Includes geological and geophysical costs charged to expense of |
|
|
127
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Depreciation, depletion, amortization and accretion expense
The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent (“Boe”) of products sold.
| Year Ended December 31, |
| |||||||||
| 2014 |
|
| 2013 |
|
| 2012 |
| |||
Depreciation, depletion, amortization and accretion per Boe | $ | 28.98 |
|
| $ | 25.10 |
|
| $ | 20.79 |
|
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Depreciation, depletion, amortization and accretion per Boe | $ | 10.68 |
|
| $ | 13.77 |
|
| $ | 23.11 |
|
Oil and Natural Gas Reserve Information
There are numerous uncertainties in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve information representrepresents estimates only and are inherently imprecise and may be subject to substantial revisions as additional information such as reservoir performance, additional drilling, technological advancements and other factors become available. Decreases in the prices of oil, NGLs and natural gas could have an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow. We are not the operator with respect to approximately 11%25% of our proved developed non-producing reserves as of December 31, 2017 so we may not be in a position to control the timing of all development activities. We are the operator for all of our proved undeveloped reserves as of December 31, 2017. In prior years, we were not the operator of all proved undeveloped reserves.
The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves. All of the reserves are located in the Unites States with 69%all located in state and federal waters in the Gulf of Mexico and the remainder located in the West Texas Permian Basin. TheseMexico. The reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. In addition to other criteria, estimated reserves are assessed for economicallyeconomic viability based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. The prices used do not purport, nor should it be interpreted, to present the current market prices related to our estimated oil and natural gas reserves. Actual future prices and costs may differ materially from those used in determining our proved reserves for the periods presented. The prices used are presented in the section below entitled “Standardized Measure of Discounted Future Net Cash Flows”.
115128
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 |
|
|
|
|
|
|
|
|
|
|
|
|
| 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, 2014 |
| 61.7 |
|
|
| 15.8 |
|
|
| 254.9 |
|
|
| 120.0 |
|
|
| 720.0 |
|
Revisions of previous estimates (2) |
| 4.8 |
|
|
| (0.9 | ) |
|
| 4.9 |
|
|
| 4.7 |
|
|
| 28.0 |
|
Revisions related to sold properties (3) |
| (12.1 | ) |
|
| (4.8 | ) |
|
| (2.9 | ) |
|
| (17.4 | ) |
|
| (104.3 | ) |
Extensions and discoveries (4) |
| 2.4 |
|
|
| 0.2 |
|
|
| 8.8 |
|
|
| 4.1 |
|
|
| 24.4 |
|
Purchase of minerals in place (5) |
| — |
|
|
| — |
|
|
| 6.1 |
|
|
| 1.0 |
|
|
| 6.1 |
|
Sales of reserves (6) |
| (13.5 | ) |
|
| (2.1 | ) |
|
| (20.2 | ) |
|
| (19.0 | ) |
|
| (113.8 | ) |
Production |
| (7.8 | ) |
|
| (1.6 | ) |
|
| (46.2 | ) |
|
| (17.0 | ) |
|
| (102.3 | ) |
Proved reserves as of Dec. 31, 2015 |
| 35.5 |
|
|
| 6.6 |
|
|
| 205.4 |
|
|
| 76.4 |
|
|
| 458.1 |
|
Revisions of previous estimates (7) |
| 4.6 |
|
|
| 3.1 |
|
|
| 32.1 |
|
|
| 13.0 |
|
|
| 78.1 |
|
Production |
| (7.2 | ) |
|
| (1.5 | ) |
|
| (39.7 | ) |
|
| (15.4 | ) |
|
| (92.2 | ) |
Proved reserves as of Dec. 31, 2016 |
| 32.9 |
|
|
| 8.2 |
|
|
| 197.8 |
|
|
| 74.0 |
|
|
| 444.0 |
|
Revisions of previous estimates (8) |
| 4.5 |
|
|
| 0.7 |
|
|
| 25.8 |
|
|
| 9.6 |
|
|
| 57.4 |
|
Extensions and discoveries (9) |
| 4.1 |
|
|
| 0.3 |
|
|
| 5.4 |
|
|
| 5.2 |
|
|
| 31.3 |
|
Production |
| (7.1 | ) |
|
| (1.4 | ) |
|
| (36.8 | ) |
|
| (14.6 | ) |
|
| (87.4 | ) |
Proved reserves as of Dec. 31, 2017 |
| 34.4 |
|
|
| 7.8 |
|
|
| 192.2 |
|
|
| 74.2 |
|
|
| 445.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-end proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
| 26.1 |
|
|
| 7.2 |
|
|
| 173.5 |
|
|
| 62.2 |
|
|
| 373.3 |
|
2016 |
| 26.6 |
|
|
| 7.6 |
|
|
| 183.1 |
|
|
| 64.7 |
|
|
| 388.2 |
|
2015 |
| 29.4 |
|
|
| 6.4 |
|
|
| 198.5 |
|
|
| 69.0 |
|
|
| 413.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-end proved undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 (10) |
| 8.3 |
|
|
| 0.6 |
|
|
| 18.7 |
|
|
| 12.0 |
|
|
| 72.0 |
|
2016 |
| 6.3 |
|
|
| 0.6 |
|
|
| 14.7 |
|
|
| 9.3 |
|
|
| 55.8 |
|
2015 |
| 6.1 |
|
|
| 0.2 |
|
|
| 6.9 |
|
|
| 7.4 |
|
|
| 44.6 |
|
Volume measurements: |
|
|
|
| |
MMBbls – million barrels for crude oil, condensate or NGLs |
| Bcf – billion cubic feet |
MMBoe – million barrels of oil equivalent |
| Bcfe – billion cubic feet of gas equivalent |
116129
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(1) | The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one |
(2) | Includes upwards revisions of 7.4 MMBoe at the Ship Shoal 349 field (Mahogany), 1.9 MMBoe at our Brazo A-133 field, 1.3 MMBoe at out Atwater 575 field, 1.3 MMBoe at out Mississippi Canyon 243 field (Matterhorn), 1.1 MMBoe at our Fairway Field, partially offset by downward revisions due to price of |
(3) |
|
(4) |
|
(5) |
|
(6) |
|
(7) |
|
(8) | Primarily related to upward revisions of 6.2 MMBoe, which included upwards revisions of 1.1 MMBoe at our Mississippi Canyon 698 (Big Bend) field, 1.0 MMBoe at our Fairway field, 0.8 MMBoe at our Ewing Bank 910 field and 0.8 MMBoe at our Viosca Knoll 783 (Virgo) field. Additionally, increases of 3.4 MMBoe were due to |
(9) | Primarily |
(10) |
|
|
|
|
|
| We believe that we will be able to develop all but |
130
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Standardized Measure of Discounted Future Net Cash Flows
The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the crude oil realized price. Then, this ratio is applied to the crude oil price using FASB/SEC guidance. The average commodity prices weighted by field production and after adjustments related to the proved reserves are as follows:
| December 31, |
| |||||||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
|
| 2014 |
| ||||
Oil - per barrel | $ | 46.58 |
|
| $ | 36.28 |
|
| $ | 46.94 |
|
| $ | 91.12 |
|
NGLs per barrel |
| 22.65 |
|
|
| 16.82 |
|
|
| 17.60 |
|
|
| 34.63 |
|
Natural gas per Mcf |
| 2.86 |
|
|
| 2.47 |
|
|
| 2.50 |
|
|
| 4.27 |
|
Future production, development costs and ARO are based on costs in effect at the end of each of the respective years with no escalations. Estimated future net cash flows, net of future income taxes, have been discounted to their present values based on a 10% annual discount rate.
The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of our oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2017 or later years and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions):
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Standardized Measure of Discounted Future Net Cash Flows |
| ||||||||||
Future cash inflows | $ | 2,328.8 | $ | 1,818.4 | $ | 2,296.7 | |||||
Future costs: | |||||||||||
Production | (813.8 | ) | (691.5 | ) | (840.1 | ) | |||||
Development | (157.4 | ) | (141.1 | ) | (161.4 | ) | |||||
Dismantlement and abandonment | (361.9 | ) | (427.7 | ) | (471.8 | ) | |||||
Income taxes (1) | (74.8 | ) | — | — | |||||||
Future net cash | 920.9 | 558.1 | 823.4 | ||||||||
10% annual discount factor | (180.3 | ) | (79.8 | ) | (209.5 | ) | |||||
Total | $ | 740.6 | $ | 478.3 | $ | 613.9 |
| 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 |
|
|
|
|
131
W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The change in the standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions):
| Year Ended December 31, |
| |||||||||
| 2017 |
|
| 2016 |
|
| 2015 |
| |||
Changes in Standardized Measure |
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, beginning of year | $ | 478.3 |
|
| $ | 613.9 |
|
| $ | 1,702.8 |
|
Increases (decreases): |
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced, net of production costs |
| (315.3 | ) |
|
| (218.6 | ) |
|
| (289.1 | ) |
Net changes in price, net of future production costs |
| 288.0 |
|
|
| (275.2 | ) |
|
| (1,455.6 | ) |
Extensions and discoveries, net of future production and development costs |
| 119.3 |
|
|
| — |
|
|
| 65.3 |
|
Changes in estimated future development costs |
| (38.9 | ) |
|
| (32.5 | ) |
|
| (8.5 | ) |
Previously estimated development costs incurred |
| 102.8 |
|
|
| 114.5 |
|
|
| 158.9 |
|
Revisions of quantity estimates |
| 106.4 |
|
|
| 190.1 |
|
|
| 137.9 |
|
Accretion of discount |
| 30.2 |
|
|
| 52.6 |
|
|
| 150.6 |
|
Net change in income taxes |
| (54.7 | ) |
|
| — |
|
|
| 600.8 |
|
Purchases of reserves in-place |
| — |
|
|
| — |
|
|
| 6.0 |
|
Sales of reserves in-place |
| — |
|
|
| — |
|
|
| (401.4 | ) |
Changes in production rates due to timing and other |
| 24.5 |
|
|
| 33.5 |
|
|
| (53.8 | ) |
Net increase (decrease) in standardized measure |
| 262.3 |
|
|
| (135.6 | ) |
|
| (1,088.9 | ) |
Standardized measure, end of year | $ | 740.6 |
|
| $ | 478.3 |
|
| $ | 613.9 |
|
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that any information relating to us is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have each concluded that as of December 31, 20142017 our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2014,2017, is set forth in “Management’s Report on Internal Control over Financial Reporting” included under Part II, Item 8 in this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
The effectiveness of our internal control over financial reporting as of December 31, 2014,2017, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included under Part II, Item 8 in this Form 10-K.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting that occurred during the quarterly period ended December 31, 20142017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
None.
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K and to the information set forth following Item 3 of this report.
Item 11. Executive Compensation
The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.
Item 14. Principal Accountant Fees and Services
The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.
Item 15. Exhibits and Financial Statement Schedules
(a) Documents filed as a part of this report:
1. | Financial Statements. See “Index to Consolidated Financial Statements” in Part II, Item 8 of this Form 10-K. |
All schedules are omitted because they are not applicable, not required or the required information is included in the consolidated financial statements or related notes.
2. | Exhibits: |
Exhibit |
| Description |
| ||
2.1 |
| |
|
|
|
|
| |
3.1 |
| |
| ||
3.2 |
| |
| ||
3.3 |
| |
| ||
3.4 | ||
3.5 | ||
4.1 |
| |
| ||
4.2 |
| |
| ||
4.3 |
| |
| ||
4.4 |
| |
|
Exhibit | Description | |
4.6 | ||
4.7 | ||
4.8 | ||
4.9 | ||
4.10 | ||
10.1* |
| |
| ||
10.2* |
| |
| ||
10.3* |
|
|
|
|
10.4* |
|
|
| ||
|
|
|
10.5* | ||
|
|
|
10.6* | ||
|
Exhibit | Description | |
10.8* |
| |
10.9* | ||
|
|
|
10.10* | ||
|
|
|
10.11* | ||
|
|
|
10.12* | ||
|
|
|
10.13* | ||
|
|
|
|
|
|
|
| |
|
| |
| ||
|
| |
10.15 | ||
10.16 | ||
10.17 | ||
Exhibit | Description | |
10.19 | ||
10.20 | ||
10.21 | ||
10.22 | ||
10.23 | ||
10.24 | ||
10.25 | ||
10.26 | ||
10.27 | ||
Exhibit | Description | |
10.29* | ||
10.30* | ||
10.31* | ||
10.32* | ||
|
| |
10.33* | ||
|
|
|
12.1** |
|
|
|
|
14.1 |
| |
| ||
21.1** |
| |
| ||
23.1** |
| Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm. |
| ||
23.2** |
| Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists. |
| ||
31.1** |
| Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. |
| ||
31.2** |
| Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. |
| ||
32.1** |
| |
| ||
99.1** |
| Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists. |
| ||
101.INS** |
| XBRL Instance Document. |
| ||
101.SCH** |
| XBRL Schema Document. |
| ||
101.CAL** |
| XBRL Calculation Linkbase Document |
| ||
101.DEF** |
| XBRL Definition Linkbase Document. |
| ||
101.LAB** |
| XBRL Label Linkbase Document. |
| ||
101.PRE** |
| XBRL Presentation Linkbase Document. |
* | Management Contract or Compensatory Plan or Arrangement. |
** | Filed or furnished herewith. |
GLOSSARY OF OIL AND NATURALNATURAL GAS TERMS
The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry that are used in this report.
Acquisitions. Refers to acquisitions, mergers or exercise of preferential rights of purchase.
Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.
Bcf. Billion cubic feet.
Bcfe. One billion cubic feet equivalent, determined using an energy-equivalent ratio of six Mcf of natural gas to one Bblbarrel of crude oil, condensate or natural gas liquids.
Boe. Barrel of oil equivalent.
Boe/d. Barrel of oil equivalent per day.
BOEM. Bureau of Ocean Energy Management. The agency is responsible for managing development of the nation’s offshore resources in an environmentally and economically responsible way. Previously, this function was managed by the Bureau of Ocean Energy Management, Regulation and Enforcement.
BOEMRE. Bureau of Ocean Energy Management, Regulation and Enforcement (formerly the Minerals Management Service), was the federal agency that manages the nation’s natural gas, oil and other mineral resources on the outer continental shelf. The BOEMRE was split into three separate entities: the Office of Natural Resources Revenue; the Bureau of Ocean Energy Management; and the Bureau of Safety and Environmental Enforcement.
BSEE. Bureau of Safety and Environmental Enforcement. The agency is responsible for enforcement of safety and environmental regulations. Previously, this function was managed by the Bureau of Ocean Energy Management, Regulation and Enforcement.
Conventional shelf well. A well drilled in water depths less than 500 feet.
Deep shelf well. A well drilled on the outer continental shelf to subsurface depths greater than 15,000 feet and water depths of less than 500 feet.
Deepwater. Water depths greater than 500 feet in the Gulf of Mexico.
Deterministic estimate. Refers to a method of estimation whereby a single value for each parameter in the reserves calculation is used in the reserves estimation procedure.
Developed reserves. Oil and natural gas reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development project. A project by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Economically producible. Refers to a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.
Extension well. A well drilled to extend the limits of a known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBoe. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the energy-equivalent ratio of six Mcf of natural gas to one Bblbarrel of crude oil or other hydrocarbon.
Mcfe/d. One thousand cubic feet equivalent per day.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBoe. One million barrels of oil equivalent.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using an energy-equivalent ratio of six Mcf of natural gas to one Bblbarrel of crude oil condensate or natural gas liquids.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NGLs. Natural gas liquids. These are created during the processing of natural gas.
Non-productive well. A well that is found not to have economically producible hydrocarbons.
Oil. Crude oil and condensate.
OCS. Outer continental shelfshelf.
OCS block. A unit of defined area for purposes of management of offshore petroleum exploration and production by the BOEM.
ONRR. Office of Natural Resources Revenue. The agency assumed the functions of the former Minerals Revenue Management Program, which had been renamed to the Bureau of Ocean Energy Management, Regulation and Enforcement.
Probabilistic estimate. Refers to a method of estimation whereby the full range of values that could reasonably occur for each unknown parameter in the reserves estimation procedure is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
Productive well. A well that is found to have economically producible hydrocarbons.
Proved properties. Properties with proved reserves.
Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. As used in
this definition, “existing economic conditions” include prices and costs at which economic producibilityproduction from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The SEC provides a complete definition of proved reserves in Rule 4-10(a)(22) of Regulation S-X.
Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
PV-10 value. A term used in the industry that is not a defined term in generally accepted accounting principles. We define PV-10 as the present value of estimated future net revenues of estimated proved reserves as calculated by our independent petroleum consultant using a discount rate of 10%. This amount includes projected revenues, estimated production costs and estimated future development costs. PV-10 excludes cash flows for asset retirement obligations, general and administrative expenses, derivatives, debt service and income taxes.
Reasonable certainty. When deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities of hydrocarbons will be recovered. When probabilistic methods are used, reasonable certainty means at least a 90% probability that the quantities of hydrocarbons actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of
geoscience, engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.
Recompletion. The completion for production of an existing well bore in another formation from that which the well has been previously completed.
Reliable technology. A grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Reserves. Estimated remaining quantities of oil, natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering the oil, natural gas or related substances to market, and all permits and financing required to implement the project.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Sub-salt. A geological layer lying below the salt layer.
Supra-salt. A geological layer lying above the salt layer.
Undeveloped reserves. Oil and natural gas reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibilityproduction at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Unproved properties. Properties with no proved reserves.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 6, 2015.2, 2018.
W&T OFFSHORE, INC. | ||
By: |
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/s/ John D. Gibbons |
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| John D. Gibbons |
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| Senior Vice President and Chief Financial Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 6, 2015.2, 2018.
/s/ Tracy W. Krohn |
| Chairman, Chief Executive Officer and Director |
Tracy W. Krohn |
| (Principal Executive Officer) |
/s/ John D. Gibbons |
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Senior Vice President and Chief Financial Officer |
John D. Gibbons |
| (Principal Financial |
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| |
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/s/ Virginia Boulet |
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Director |
Virginia Boulet | ||
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/s/ Stuart B. Katz |
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Director |
Stuart B. Katz |
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/s/ S. James Nelson, Jr |
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Director |
S. James Nelson, Jr. |
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/s/ B. Frank Stanley |
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Director |
B. Frank Stanley |
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