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SGY > SEC Filings for SGY > Form 10-Q on 6-Nov-2013All Recent SEC Filings

Show all filings for STONE ENERGY CORP

Form 10-Q for STONE ENERGY CORP


6-Nov-2013

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (this "Form 10-Q") includes "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements as described in our 2012 Annual Report on Form 10-K and in this Form 10-Q.

Forward-looking statements appear in a number of places in this Form 10-Q and include statements with respect to, among other things:

any expected results or benefits associated with our acquisitions;

expected results from risked weighted drilling success;

estimates of our future oil and natural gas production, including estimates of any increases in oil and gas production;

planned capital expenditures and the availability of capital resources to fund capital expenditures;

our outlook on oil and gas prices;

estimates of our oil and gas reserves;

any estimates of future earnings growth;

the impact of political and regulatory developments;

our outlook on the resolution of pending litigation and government inquiry;

estimates of the impact of new accounting pronouncements on earnings in future periods;

our future financial condition or results of operations and our future revenues and expenses;

the amount, nature and timing of any potential divestiture transactions;

our access to capital and our anticipated liquidity;

estimates of future income taxes; and

our business strategy and other plans and objectives for future operations.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and natural gas. These risks include, among other things:

commodity price volatility;

consequences of a catastrophic event like the Deepwater Horizon oil spill;

domestic and worldwide economic conditions;

the availability of capital on economic terms to fund our capital expenditures and acquisitions;

our level of indebtedness;

declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our bank credit facility and impairments;

our ability to replace and sustain production;

the impact of a financial crisis on our business operations, financial condition and ability to raise capital;

the ability of financial counterparties to perform or fulfill their obligations under existing agreements;

third-party interruption of sales to market;

inflation;

lack of availability and cost of goods and services;

market conditions relating to potential acquisition and divestiture transactions;

regulatory and environmental risks associated with drilling and production activities;

drilling and other operating risks;

unsuccessful exploration and development drilling activities;

hurricanes and other weather conditions;

adverse effects of changes in applicable tax, environmental, derivatives and other regulatory legislation, including changes affecting our offshore and Appalachian operations; and

uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures.


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For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part II, Item 1A. Risk Factors, of this Form 10-Q and (2) Part I, Item 1A, of our 2012 Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our 2012 Annual Report on Form 10-K or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") contained in this Form 10-Q should be read in conjunction with the MD&A contained in our 2012 Annual Report on Form 10-K.

Overview

We are an independent oil and 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 Gulf of Mexico (the "GOM") and into the more prolific reserve basins of the GOM deep water and Gulf Coast deep gas, as well as onshore oil and gas shale opportunities, including the Marcellus Shale in Appalachia.

Critical Accounting Estimates

Our 2012 Annual Report on Form 10-K describes the accounting estimates that we believe are critical to the reporting of our financial position and operating results and that require management's most difficult, subjective or complex judgments. Our most significant estimates are:

remaining proved oil and gas reserve volumes and the timing of their production;

estimated costs to develop and produce proved oil and gas reserves;

accruals of exploration costs, development costs, operating costs and production revenue;

timing and future costs to abandon our oil and gas properties;

effectiveness and estimated fair value of derivative positions;

classification of unevaluated property costs;

capitalized general and administrative costs and interest;

insurance recoveries related to hurricanes and other events;

estimates of fair value in business combinations;

current and deferred income taxes; and

contingencies.

This Form 10-Q should be read together with the discussion contained in our 2012 Annual Report on Form 10-K regarding these critical accounting policies.

Other Factors Affecting Our Business and Financial Results

In addition to the matters discussed above, our business, financial condition and results of operations are affected by a number of other factors. This Form 10-Q should be read in conjunction with the discussion in Part I, Item 1A, of our 2012 Annual Report on Form 10-K and in this Form 10-Q under Part II, Item 1A. Risk Factors, of this Form 10-Q regarding our known material risk factors.

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 insurance coverage for property damage to our facilities for hurricanes has been difficult to obtain for some time. We have assumed all hurricane-related risk due to these rising insurance rates. 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.

Louisiana Franchise Taxes - We have been involved in litigation with the State of Louisiana over the proper computation of franchise taxes allocable to the state. This litigation relates to the state's position that sales of crude oil and natural gas from properties located on the OCS, which are transported through the State of Louisiana, should be sourced to Louisiana for purposes of computing franchise taxes. We disagree with the state's position. However, if the state's position were to be upheld, we could incur additional expenses for alleged underpaid franchise taxes in prior years and higher franchise tax expense in future years. For additional information, see Part II, Item 1. Legal Proceedings, of this Form 10-Q.


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Deep Water Operations - With our acquisition of interests in the Pompano field, we are now 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 operations 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 September 30, 2013 are $9.7 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 operations.

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 amount of the notes 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 fully 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 - We have engaged a financial advisor to market certain of our properties in the GOM conventional shelf, state waters and onshore Louisiana. The properties represented approximately 12% of our total estimated proved reserves as of December 31, 2012. 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. Production volumes at the Weeks Island field represented approximately 2% of our total production volumes and 3% of our total production revenue for the nine months ended September 30, 2013. The remainder of our shelf properties that are subject to sale represented approximately 24% of our total production volumes and 21% of our total production revenue for the nine months ended September 30, 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.

Sales of oil and 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 recognize a gain or loss on the sale in the period in which the transaction is consummated. The Weeks Island sale 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

At November 5, 2013, we had $378.5 million of availability under our bank credit facility and cash on hand of approximately $275 million. In September 2013, our capital expenditure budget for 2013 was increased from $650 million to $710 million. Most of the increase is in the GOM deep water, with minor increase in the Appalachia area. Our capital expenditure budget excludes material acquisitions and capitalized salaries, general and administrative ("SG&A") expenses and interest. Based on our outlook of commodity prices and our estimated production, we expect our 2013 capital expenditures to exceed our cash flow from operating activities. We intend to finance our remaining capital expenditure budget with cash on hand and cash flow from operations.

Cash Flows and Working Capital. Net cash from operating activities totaled $439.5 million during the nine months ended September 30, 2013 compared to $373.9 million in the comparable period in 2012.

Net cash used in investing activities totaled $472.2 million and $448.8 million during the nine months ended September 30, 2013 and 2012, respectively, which primarily represents our investment in oil and natural gas properties.

Net cash used in financing activities totaled $3.6 million for the nine months ended September 30, 2013, which primarily represents net payments for share-based compensation. Net cash provided by financing activities totaled $212.6 million for the nine months ended September 30, 2012, which primarily represents $291.1 million of net proceeds from the issuance of the 2017 Convertible Notes and $40.1 million of proceeds from the Sold Warrants, partially offset by $70.8 million for the cost of the Purchased Call Options. Additionally, we had $25.0 million of borrowings and $70.0 million of repayments of borrowings under our bank credit facility during the nine months ended September 30, 2012.

We had working capital at September 30, 2013 of $237.0 million.


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Capital Expenditures. During the three months ended September 30, 2013, additions to oil and gas property costs of $151.9 million included $17.5 million of lease and property acquisition costs, $8.5 million of capitalized SG&A expenses (inclusive of incentive compensation) and $11.9 million of capitalized interest. During the nine months ended September 30, 2013, additions to oil and gas property costs of $473.3 million included $79.4 million of lease and property acquisition costs, $22.6 million of capitalized SG&A expenses (inclusive of incentive compensation) and $32.8 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 through a syndicated bank group, replacing our previous facility. Our bank credit facility matures on April 26, 2015. On April 30, 2013, the bank group reaffirmed our existing borrowing base at $400 million. As of September 30 and November 5, 2013, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $21.5 million had been issued pursuant to our bank credit facility, leaving $378.5 million of availability under the facility. Our bank credit facility is guaranteed by our only material subsidiary, 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 gas reserves representing at least 80% of the discounted present value of the future net cash flows from their oil and 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 Libor 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 September 30, 2013, our debt to EBITDA ratio was 1.51 to 1 and our EBITDA to consolidated Net Interest Expense ratio was approximately 19.53 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 September 30, 2013.

Contractual Obligations and Other Commitments

In addition to our significant contractual obligations and commitments summarized in our 2012 Annual Report on Form 10-K, in April 2013, we contracted two deep water drilling rigs for minimum total commitments of approximately $123.5 million to be incurred during the second half of 2013 and the first half of 2014. Additionally, in September 2013, we entered into a flowline agreement in excess of $70 million for the development of the Cardona deep water field, with project management and engineering work to commence immediately and offshore operations due to commence in the third quarter of 2014.


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Results of Operations

The following tables set forth certain information with respect to our oil and
gas operations.



                                              Three Months Ended
                                                 September 30,
                                             2013            2012          Variance         % Change
Production:
Oil (MBbls)                                    1,809           1,736              73                4 %
Natural gas (MMcf)                            13,866          10,615           3,251               31 %
Natural gas liquids ("NGLs") (MBbls)             425             341              84               25 %
Oil, natural gas and NGLs (MMcfe)             27,270          23,077           4,193               18 %
Revenue data (in thousands) (a):
Oil revenue                                $ 186,608       $ 180,806       $   5,802                3 %
Natural gas revenue                           52,728          34,003          18,725               55 %
NGLs revenue                                  16,476          11,910           4,566               38 %

Total oil, natural gas and NGL revenue     $ 255,812       $ 226,719       $  29,093               13 %
Average prices (a):
Oil (per Bbl)                              $  103.16       $  104.15       ($   0.99 )             (1 %)
Natural gas (per Mcf)                           3.80            3.20            0.60               19 %
NGLs (per Bbl)                                 38.77           34.93            3.84               11 %
Oil, natural gas and NGLs (per Mcfe)            9.38            9.82           (0.44 )             (4 %)
Expenses (per Mcfe):
Lease operating expenses                   $    1.98       $    2.64       ($   0.66 )            (25 %)
SG&A expenses (b)                               0.52            0.59           (0.07 )            (12 %)
DD&A expense on oil and gas properties          3.37            3.83           (0.46 )            (12 %)

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

(b) Excludes incentive compensation expense.

                                               Nine Months Ended
                                                 September 30,
                                             2013            2012          Variance          % Change
Production:
Oil (MBbls)                                    5,243           5,289             (46 )              (1 %)
Natural gas (MMcf)                            35,969          31,031           4,938                16 %
NGLs (MBbls)                                   1,048             794             254                32 %
Oil, natural gas and NGLs (MMcfe)             73,715          67,529           6,186                 9 %
Revenue data (in thousands) (a):
Oil revenue                                $ 558,031       $ 564,745       ($  6,714 )              (1 %)
Natural gas revenue                          137,382          91,006          46,376                51 %
NGLs revenue                                  36,854          35,228           1,626                 5 %

Total oil, natural gas and NGL revenue     $ 732,267       $ 690,979       $  41,288                 6 %
Average prices (a):
Oil (per Bbl)                              $  106.43       $  106.78       ($   0.35 )            (0.3 %)
Natural gas (per Mcf)                           3.82            2.93            0.89                30 %
NGLs (per Bbl)                                 35.17           44.37           (9.20 )             (21 %)
Oil, natural gas and NGLs (per Mcfe)            9.93           10.23           (0.30 )              (3 %)
Expenses (per Mcfe):
Lease operating expenses                   $    2.14       $    2.33       ($   0.19 )              (8 %)
SG&A expenses (b)                               0.59            0.60           (0.01 )              (2 %)
DD&A expense on oil and gas properties          3.43            3.83           (0.40 )             (10 %)

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

(b) Excludes incentive compensation expense.

Net Income. During the three months ended September 30, 2013, we reported net income totaling $36.1 million, or $0.72 per share, compared to net income for the three months ended September 30, 2012 of $23.7 million, or $0.48 per share. During the nine months ended September 30, 2013, we reported net income totaling $115.9 million, or $2.32 per share, compared to net income for the nine months ended September 30, 2012 of $105.2 million, or $2.13 per share. All per share amounts are on a diluted basis.


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The variance in the three and nine month periods' results was due to the following components:

Production. During the three months ended September 30, 2013, total production volumes increased to 27.3 Bcfe compared to 23.1 Bcfe produced during the comparable 2012 period, representing an 18% increase. Oil production during the three months ended September 30, 2013 totaled approximately 1,809,000 Bbls compared to 1,736,000 Bbls produced during the comparable 2012 period. Natural gas production totaled 13.9 Bcf during the three months ended September 30, 2013 compared to 10.6 Bcf during the comparable 2012 period. NGL production during the three months ended September 30, 2013 totaled approximately 425,000 Bbls compared to 341,000 Bbls produced during the comparable 2012 period.

During the nine months ended September 30, 2013, total production volumes increased to 73.7 Bcfe compared to 67.5 Bcfe produced during the comparable 2012 period, representing a 9% increase. Oil production during the nine months ended September 30, 2013 totaled approximately 5,243,000 Bbls compared to 5,289,000 Bbls produced during the nine months ended September 30, 2012. Natural gas production totaled 36.0 Bcf during the nine months ended September 30, 2013 compared to 31.0 Bcf during the comparable 2012 period. NGL production during the nine months ended September 30, 2013 totaled approximately 1,048,000 Bbls compared to 794,000 Bbls produced during the comparable 2012 period.

During the three months ended September 30, 2013, seven new wells in the Mary field were brought online. During the three months ended June 30, 2013, the third well in the La Cantera field was placed on production. Also during the three months ended June 30, 2013, the Williams pipeline was repaired and pressure restrictions were eliminated, which allowed us to restore shut-in production in the Mary field.

Prices. Prices realized during the three months ended September 30, 2013 averaged $103.16 per Bbl of oil, $3.80 per Mcf of natural gas and $38.77 per Bbl of NGLs, or 4% lower, on an Mcfe basis, than average realized prices of $104.15 per Bbl of oil, $3.20 per Mcf of natural gas and $34.93 per Bbl of NGLs during the comparable 2012 period. Prices realized during the nine months ended September 30, 2013 averaged $106.43 per Bbl of oil, $3.82 per Mcf of natural gas and $35.17 per Bbl of NGLs, or 3% lower, on an Mcfe basis, than average realized prices of $106.78 per Bbl of oil, $2.93 per Mcf of natural gas and $44.37 per Bbl of NGLs during the comparable 2012 period. All unit pricing amounts include the cash settlement of effective hedging contracts.

We enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. Our effective hedging transactions increased our average realized natural gas price by $0.39 per Mcf and decreased our average realized oil price by $4.14 per Bbl during the three months ended September 30, 2013. During the three months ended September 30, 2012, our effective hedging transactions increased our average realized natural gas price by $0.55 per Mcf and increased our average realized oil price by $2.34 per Bbl. During the nine months ended September 30, 2013, effective hedging transactions increased our average realized natural gas price by $0.32 per Mcf and increased our average realized oil price by $0.45 per Bbl. During the nine months ended September 30, 2012, effective hedging transactions increased our average realized natural gas price by $0.55 per Mcf and increased our average realized oil price by $0.21 per Bbl.

Revenue. Oil, natural gas and NGL revenue was $255.8 million during the three . . .

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