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SGY > SEC Filings for SGY > Form 10-K on 27-Feb-2014All Recent SEC Filings

Show all filings for STONE ENERGY CORP

Form 10-K for STONE ENERGY CORP


27-Feb-2014

Annual Report


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our financial position and results of operations for each of the years in the three-year period ended December 31, 2013. Our Consolidated Financial Statements and the notes thereto, which are found elsewhere in this Form 10-K, contain detailed information that should be referred to in conjunction with the following discussion. See Item 1A. Risk Factors and Item 8. Financial Statements and Supplementary Data - Note 1.

Executive Overview

We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the Gulf Coast Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have expanded our reserve base outside of the conventional shelf of the GOM and into the more prolific reserve basins of the GOM deep water and GOM deep gas as well as onshore oil and gas shale opportunities, including the Marcellus Shale in Appalachia. See Item 1. Business - Operational Overview.

2013 Significant Events.

Reserve and Production Growth - 2013 represented our fourth consecutive year of growth in production and reserves. We had continued progress in our diversification strategy, resulting in a reserve mix of 55% Appalachia, 29% deep water, and 16% conventional shelf/deep gas on a volume equivalent basis. Our year-end 2013 total estimated proved reserves were 864 Bcfe, a 12% increase from 2012 year-end estimated proved reserves. Production volumes for 2013 averaged approximately 277 MMcfe per day, representing a 10% increase over 2012 production volumes.

Issuance of 2022 Senior Notes - On November 27, 2013, we completed the public offering of an additional $475 million aggregate principal amount of our 7 1/2% Senior Notes due 2022 at a 3% premium. The net proceeds from the offering after deducting fees and expenses totaled $480.2 million. Approximately $396.0 million of the net proceeds from the offering were used to fund the tender offer and consent solicitation and redemption of our outstanding 8 5/8% Senior Notes due 2017 (the "2017 Notes") and approximately $11.0 million of the net proceeds were used to pay the accrued and unpaid interest on the 2017 Notes. The remaining proceeds were used for general corporate purposes. As of December 31, 2013, we had approximately $331 million of cash on hand.

Franchise Tax Settlement - On November 22, 2013, we executed a settlement with the LDR in the amount of $13 million, resolving all claims asserted in litigation, as well as assessments proposed by the LDR for franchise and income taxes alleged to be due by Stone for the tax years 1999 through 2009, including claims for interest thereon. The settlement amount, less income tax and interest amounts previously accrued, has been recorded as an expense in the accompanying consolidated statement of income. The tax years 2011 through 2013 remain subject to examination, but the exposure to additional assessments is immaterial.

Sale of Shelf Properties - In 2013, we engaged a financial advisor to market certain of our properties in the GOM conventional shelf, state waters and onshore Louisiana. In October 2013, we completed the sale of our interest in the Weeks Island field, representing less than 1% of our total estimated proved reserves at December 31, 2012. In January 2014, we completed the sale of our interest in the Cut Off and Clovelly fields, representing less than 1% of our total estimated proved reserves at December 31, 2013. The remainder of our shelf properties that are subject to sale represented approximately 22% of our total production volumes and 18% of our total production revenue for the year ended December 31, 2013 and 9% of our total estimated proved reserves at December 31, 2013. The future sale of some or all of our shelf properties would be subject to an acceptable offer or offers and other market conditions.

2014 Outlook.

Our 2014 capital expenditure budget is approximately $825 million. This figure compares with a $710 million capital expenditure budget for 2013 and excludes material acquisitions and capitalized salaries, general and administrative expenses ("SG&A") and interest. The budget is spread across our major areas of investment, with approximately 58% allocated to the deep water, 26% allocated to Appalachia, 10% allocated to the GOM conventional shelf, 3% allocated to deep gas projects, and 3% allocated to onshore exploration projects. The allocation of capital across the various areas is subject to change based on several factors, including permitting times, rig availability, non-operator decisions, farm-in opportunities and commodity pricing.


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Known Trends and Uncertainties.

Hurricanes - Since the majority of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production.
Additionally, affordable and practical insurance coverage for property damage to our facilities for hurricanes has been difficult to obtain for some time so we have eliminated our hurricane insurance coverage. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.

Deep Water Operations - We are currently operating two significant properties in the deep water of the GOM. Additionally, we are engaged in deep water drilling operations. Operations in the deep water can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statement of income as well as going concern issues.

Non-U.S. Operations - In April 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Included in unevaluated oil and gas property costs at December 31, 2013 are $10.6 million of capital expenditures related to our oil and gas property investments in Canada. Under full cost accounting, investments in individual countries represent separate cost centers for computation of depreciation, depletion and amortization ("DD&A") as well as for full cost ceiling test evaluations. Given that this is our sole investment in Canada, it is possible that upon a more complete evaluation of this project that some or all of this investment could be recognized as a charge to expense on our statement of income.

Earnings Per Share - On March 6, 2012, we issued $300 million of 2017 Convertible Notes. These notes are convertible into cash, shares of our common stock or a combination thereof at our election. Current accounting standards require us to use the treasury method for determining potential dilution in our diluted earnings per share computation since it is management's intention to settle the principal in cash. However, if due to changes in facts and circumstances beyond our control such intention were to change, or it becomes probable that we will be unable to settle the principal in cash, we could be required to change our methodology for determining diluted earnings per share to the if-converted method. The if-converted method would result in a substantial dilutive effect on diluted earnings per share when compared to the treasury method.

Sale of Shelf Properties - In 2013, we engaged a financial advisor to market certain of our properties in the GOM conventional shelf, state waters and onshore Louisiana, and to date have completed the sales of our interests in the Weeks Island, Cut Off and Clovelly fields. Sales of oil and natural gas properties under the full cost method are accounted for as an adjustment to capitalized costs unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the applicable cost center. If such relationship would be altered significantly, we would be required to allocate the cost center between the properties sold and the properties retained and to recognize a gain or loss on the sale in the period in which the transaction is consummated. The Weeks Island, Cut Off and Clovelly sales did not result in a significant alteration of this relationship and, consequently, no gain or loss will be recognized. Whether a significant alteration would occur on future transactions, and therefore a gain or loss recognized, cannot be determined at this time.

Liquidity and Capital Resources

As of February 25, 2014, we had $378.6 million of availability under our bank credit facility and cash on hand of approximately $312 million. Our capital expenditure budget for 2014 has been set at $825 million, which excludes material acquisitions and capitalized SG&A expenses and interest. Based on our outlook of commodity prices and our estimated production, we expect our 2014 capital expenditures to exceed our cash flows from operating activities. We intend to finance a portion of our capital expenditure budget with cash flows from operating activities, cash on hand and our bank credit facility. However, a portion of our capital expenditure budget will likely need to be financed from other sources. We are considering accessing the public or private markets or monetizing other assets as a source of financing.

Cash Flow and Working Capital. Net cash flows from operating activities totaled $594.2 million during the year ended December 31, 2013 compared to $509.7 million and $570.9 million during the years ended December 31, 2012 and 2011, respectively.

Net cash used in investing activities totaled $623.0 million during the year ended December 31, 2013, which primarily represents our investment in oil and natural gas properties of $663.3 million and our investment in fixed and other assets of $6.8 million offset by proceeds from the sale of oil and natural gas properties of $48.8 million. Net cash used in investing activities totaled $568.7 million during the year ended December 31, 2012, which primarily represents our investment in oil and natural gas properties of $555.9 million and our investment in fixed and other assets of $13.4 million. Net cash used in investing activities totaled $679.3 million during the year ended December 31, 2011, which primarily represents our investment in oil and natural gas properties of $764.9 million offset by proceeds from the sale of oil and natural gas properties of $87.9 million. Approximately $270.4 million of the investment in oil and natural gas properties in 2011 related to leasehold acquisitions and the acquisition of producing properties.


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Net cash provided by financing activities totaled $80.6 million for the year ended December 31, 2013, which primarily represents $480.2 million of net proceeds from the issuance of the 2022 Notes, less $396.0 million used for the redemption of our 2017 Notes. Net cash provided by financing activities totaled $300.0 million during the year ended December 31, 2012. In 2012, we received $291.1 million of net proceeds from the issuance of the 2017 Convertible Notes and $40.1 million of proceeds from the Sold Warrants, and used $70.8 million for the cost of the Purchased Call Options (see Notes to Consolidated Financial Statements - NOTE 11 - Long-Term Debt). Additionally, we received $293.2 million of net proceeds from the issuance of the 2022 Notes. During 2012, we used $200.7 million for the redemption of our 2014 Notes. During the year ended December 31, 2012, we had $25.0 million of borrowings and $70.0 million of repayments of borrowings under our bank credit facility. Net cash provided by financing activities totaled $39.9 million for the year ended December 31, 2011, which primarily represents borrowings net of repayments under our bank credit facility of $45.0 million, less $4.0 million of deferred financing costs associated with our new bank credit facility and $2.6 million of net payments for share-based compensation.

We had working capital at December 31, 2013 of $181.3 million.

Capital Expenditures. During the year ended December 31, 2013, additions to oil and gas property costs of $836.2 million included $86.2 million of lease and property acquisition costs, $32.5 million of capitalized SG&A expenses (inclusive of incentive compensation) and $46.9 million of capitalized interest. These investments were financed with cash on hand and cash flows from operations.

Bank Credit Facility. On April 26, 2011, we entered into an amended and restated revolving credit facility totaling $700 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. Our bank credit facility matures on April 26, 2015. On December 18, 2013, our borrowing base under our bank credit facility was reaffirmed at $400 million. As of December 31, 2013 and February 25, 2014, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $21.4 million had been issued pursuant to our bank credit facility, leaving $378.6 million of availability under our bank credit facility. Our bank credit facility is guaranteed by our only significant subsidiary, Stone Energy Offshore, L.L.C. ("Stone Offshore").

The borrowing base under our bank credit facility is redetermined semi-annually, in May and November, by the lenders, taking into consideration the estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries in accordance with the lenders' customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. Our bank credit facility is collateralized by substantially all of Stone's and Stone Offshore's assets. Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and natural gas reserves representing at least 80% of the discounted present value of the future net cash flows from their oil and natural gas reserves reviewed in determining the borrowing base. At our option, loans under our bank credit facility will bear interest at a rate based on the adjusted London Interbank Offering Rate plus an applicable margin, or a rate based on the prime rate or Federal funds rate plus an applicable margin.

Under the financial covenants of our bank credit facility, we must (1) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (2) maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the credit agreement, for the preceding four quarterly periods of not less than 3.0 to 1. As of December 31, 2013, our debt to EBITDA ratio was 1.73 to 1 and our EBITDA to consolidated Net Interest Expense ratio was approximately 18.40 to 1. In addition, our bank credit facility includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of ownership and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances. We were in compliance with all covenants as of December 31, 2013.

7 1/2% Senior Notes due 2022. On November 27, 2013, we completed the public offering of an additional $475 million aggregate principal amount of our 2022 Notes at a 3% premium. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $480.2 million. Approximately $396.0 million of the net proceeds from the offering were used to fund the tender offer and consent solicitation and redemption of our outstanding 2017 Notes and approximately $11.0 million of the net proceeds were used to pay the accrued and unpaid interest on the 2017 Notes. The remaining proceeds were used for general corporate purposes.


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8 5/8% Senior Notes due 2017. In November 2013, we used proceeds from the 2022 Notes offering to purchase a portion of our 2017 Notes pursuant to a tender offer and consent solicitation. In December 2013, the remaining 2017 Notes were redeemed in full. The total cost of the redemption was $407.0 million, which included $396.0 million to redeem the notes plus accrued and unpaid interest of $11.0 million. The transaction resulted in a charge to earnings of $27.3 million in 2013.

Share Repurchase Program. On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Through December 31, 2013, 300,000 shares had been repurchased under this program at a total cost of approximately $7.1 million, or an average price of $23.57 per share. No shares were repurchased during the years ended December 31, 2013, 2012 or 2011.

Hedging. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk
- Commodity Price Risk.

Contractual Obligations and Other Commitments

The following table summarizes our significant contractual obligations and
commitments, other than hedging contracts, by maturity as of December 31, 2013
(in thousands):



                                                          Less                                         More
                                                          than                                         than
                                           Total         1 Year       1-3 Years      4-5 Years        5 Years
Contractual Obligations and
Commitments:
1 3/4% Senior Convertible Notes due
2017                                    $   300,000     $      -      $       -      $  300,000     $        -
7 1/2% Senior Notes due 2022                775,000            -              -              -          775,000
Interest and commitment fees (1)            536,763        65,294        127,360        118,875         225,234
Asset retirement obligations
including accretion                         898,874        69,270        202,187         84,524         542,893
Rig commitments                             142,291       142,291             -              -               -
Seismic data commitments                     74,436        28,297         30,759         15,380              -
Operating lease obligations                   2,179           736            995            448              -

Total Contractual Obligations and
Commitments                             $ 2,729,543     $ 305,888     $  361,301     $  519,227     $ 1,543,127

(1) Includes interest payable on the 2022 Notes and 2017 Convertible Notes. Assumes 0.5% fee on unused commitments under the bank credit facility.

Safety Performance

We measure our safety performance based on the total recordable incident rate ("TRIR"), which is the number of safety incidents per 200,000 man-hours worked for employees and certain contractors. All onshore safety incidents are reported to the Occupational Safety and Health Administration ("OSHA") and are tracked on OSHA Form 301. All offshore safety incidents are reported to the BOEM. Our TRIR is provided to the BOEM as part of a voluntary program for safety monitoring in the GOM. Our TRIR for the last three calendar years was as follows:

                       Year Ended         TRIR           TRIR
                       December 31,    Performance       Goal
                       2013                    0.47       0.50
                       2012                    0.45       0.55
                       2011                    0.33       0.65

Our safety initiative includes formal programs for observation and reporting of at-risk and safe behavior in and away from the work place, employee awards for results and observations, employee participation in training programs and internal safety audits. We have an annual cash incentive compensation plan that includes a safety component based on our annual TRIR.


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Results of Operations

2013 Compared to 2012. The following table sets forth certain information with respect to our oil and gas operations and summary information with respect to our estimated proved oil and natural gas reserves. See Item 2. Properties - Oil and Natural Gas Reserves.

                                                            Year Ended December 31,
                                             2013            2012          Variance         % Change
Production:
Oil (MBbls)                                    6,894           7,135            (241 )             (3 %)
Natural gas (MMcf)                            50,129          42,569           7,560               18 %
NGLs (MBbls)                                   1,603           1,163             440               38 %
Oil, natural gas and NGLs (MMcfe)            101,111          92,357           8,754               10 %
Revenue data (in thousands): (1)
Oil revenue                                $ 715,104       $ 761,304       ($ 46,200 )             (6 %)
Natural gas revenue                          190,580         134,739          55,841               41 %
NGL revenue                                   60,687          48,498          12,189               25 %

Total oil, natural gas and NGL revenue     $ 966,371       $ 944,541       $  21,830                2 %
Average prices: (1)
Oil (per Bbl)                              $  103.73       $  106.70          ($2.97 )             (3 %)
Natural gas (per Mcf)                           3.80            3.17            0.63               20 %
NGLs (per Bbl)                                 37.86           41.70           (3.84 )             (9 %)
Oil, natural gas and NGLs (per Mcfe)            9.56           10.23           (0.67 )             (7 %)
Expenses (per Mcfe):
Lease operating expenses                   $    1.99       $    2.33          ($0.34 )            (15 %)
Salaries, general and administrative
expenses (2)                                    0.59            0.59              -               N/A
DD&A expense on oil and gas properties          3.43            3.69           (0.26 )             (7 %)
Estimated Proved Reserves at
December 31:
Oil (MBbls)                                   43,827          44,918          (1,091 )             (2 %)
Natural gas (MMcf)                           460,766         395,374          65,392               17 %
NGLs (MBbls)                                  23,297          18,066           5,231               29 %
Oil, natural gas and NGLs (MMcfe)            863,513         773,285          90,228               12 %

(1) Includes the cash settlement of effective hedging contracts.

(2) Excludes incentive compensation expense.

Net Income. For the year ended December 31, 2013, we reported net income totaling $117.6 million, or $2.36 per share, compared to net income for the year ended December 31, 2012 of $149.4 million, or $3.03 per share. All per share amounts are on a diluted basis.

The variance in annual results was due to the following components:

Production. During the year ended December 31, 2013, total production volumes increased to 101.1 Bcfe compared to 92.4 Bcfe produced during the comparable 2012 period, representing a 10% increase. Oil production during the year ended December 31, 2013 totaled approximately 6,894,000 Bbls compared to 7,135,000 Bbls produced during the year ended December 31, 2012. Natural gas production totaled 50.1 Bcf during the year ended December 31, 2013 compared to 42.6 Bcf produced during the comparable 2012 period. NGL production during the year ended December 31, 2013 totaled approximately 1,603,000 Bbls compared to 1,163,000 Bbls produced during the comparable 2012 period. During the fourth quarter of 2013, ten new wells in the Mary field and two new wells in the Heather field were brought online. The third well in the La Cantera field was placed on production during the second quarter of 2013.

Prices. Prices realized during the year ended December 31, 2013 averaged $103.73 per Bbl of oil, $3.80 per Mcf of natural gas and $37.86 per Bbl of NGLs, or 7% lower, on an Mcfe basis, than 2012 average realized prices of $106.70 per Bbl of oil, $3.17 per Mcf of natural gas and $41.70 per Bbl of NGLs. All unit pricing amounts include the cash settlement of effective hedging contracts.


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We enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. During the year ended December 31, 2013, effective hedging transactions increased our average realized natural gas price by $0.33 per Mcf and increased our average realized oil price by $0.51 per Bbl. During the year ended December 31, 2012, effective hedging transactions increased our average realized natural gas price by $0.52 per Mcf and increased our average realized oil price by $1.20 per Bbl.

Revenue. Oil, natural gas and NGL revenue increased 2% to $966.4 million during the year ended December 31, 2013 from $944.5 million during the year ended December 31, 2012. The increase was attributable to a 10% increase in production quantities on a gas equivalent basis, which was partially offset by a 7% decrease in average realized prices.

Expenses. Lease operating expenses for the years ended December 31, 2013 and 2012 totaled $201.2 million and $215.0 million, respectively. On a unit of production basis, lease operating expenses were $1.99 per Mcfe and $2.33 per Mcfe for the years ended December 31, 2013 and 2012, respectively. The decrease in lease operating expenses in 2013 was primarily attributable to a decrease in insurance and major maintenance expenses.

Transportation, processing and gathering expenses during the years ended December 31, 2013 and 2012 totaled $42.2 million and $21.8 million, respectively. The increase is attributable to higher gas and NGL volumes and short term blending fees in Appalachia, as well as higher GOM pipeline fees.

DD&A expense on oil and gas properties for the year ended December 31, 2013 totaled $346.8 million, or $3.43 per Mcfe, compared to DD&A expense of $341.1 million, or $3.69 per Mcfe, for the year ended December 31, 2012.

For the years ended December 31, 2013 and 2012, SG&A expenses (exclusive of incentive compensation) totaled $59.5 million and $54.6 million, respectively. The increase in SG&A expenses in 2013 was primarily the result of increased staffing and compensation adjustments (including share-based compensation). Partially offsetting this increase was a reimbursement of $1.6 million of legal fees relating to the settlement of litigation in prior periods. Included in SG&A expenses in 2012 was a $1.0 million management fee for transition services related to the Pompano field acquisition.

For the years ended December 31, 2013 and 2012, incentive compensation expense totaled $15.3 million and $8.1 million, respectively. These amounts related to incentive compensation bonuses calculated based on the achievement of certain strategic objectives for each fiscal year.

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