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| 8-K - FORM 8-K - STONE ENERGY CORP | f8k110117earnings3q17.htm |
Exhibit 99.1
STONE ENERGY CORPORATION
Announces Third Quarter 2017 Results
LAFAYETTE, LA. November 1, 2017
Stone Energy Corporation (NYSE: SGY) (“Stone” or the “Company”) today announced financial and operational results for the third quarter of 2017. Some items of note include:
• | Production volumes averaged 19.2 thousand barrels of oil equivalent per day for the three months ended September 30, 2017, at the upper end of our third quarter 2017 guidance |
• | Positive results from the Rampart Deep exploration well; follow-up Derbio well to spud in the first half of 2018 |
• | Mt. Providence development well to spud in December 2017 |
• | Liquidity, including restricted cash, totaled $420 million at September 30, 2017 |
Interim Chief Executive Officer and President James M. Trimble stated, “We are pleased to be progressing our deep water drilling program and are encouraged by the Rampart Deep results. We are also excited about the December 2017 spud of Mt. Providence and the 2018 spud of Derbio. In addition, we are working with partners to evaluate several other near-term drilling prospects, both in our portfolio and outside-generated ideas, and we continue to review a number of asset acquisition opportunities. Our balance sheet, which includes over $245 million in unrestricted cash at quarter end, and an undrawn bank facility allow us the flexibility to pursue a variety of tactical and strategic options.”
Financial Results
For the quarter ended September 30, 2017, Stone reported net income of $1.3 million on oil and gas revenue of $69.8 million, which included $7.9 million of non-cash derivative expense. Net cash provided by operating activities for the third quarter of 2017 totaled $42.5 million, while discretionary cash flow for the same period totaled $45.5 million. See the “Non-GAAP Financial Measure” schedules and the accompanying financial statements for reconciliations of discretionary cash flow, a non-GAAP financial measure, to net cash provided by operating activities.
Net daily production during the third quarter of 2017 averaged approximately 19.2 thousand barrels of oil equivalent (“MBoe”) per day, compared to net daily production of approximately 20.6 MBoe per day for the quarter ended June 30, 2017. Third quarter 2017 volumes included the effects of one week of planned downtown at the Pompano platform for the rig demobilization and reinstallation of living quarters. The production mix for the third quarter of 2017 was approximately 73% oil, 21% natural gas, and 6% natural gas liquids (“NGLs”). We expect production rates to range from 17.0 MBoe per day to 18.0 MBoe per day for the fourth quarter of 2017, which includes five full days of downtime from Hurricane Nate and a ten day planned shut-in of the Pompano platform to replace a compressor engine in November.
Prices realized during the third quarter of 2017 averaged $48.13 per barrel of oil, $2.46 per Mcf of natural gas, and $21.69 per barrel of NGLs. Average realized prices for the third quarter of 2016 were $45.50 per barrel of oil, $1.93 per Mcf of natural gas, and $9.72 per barrel of NGLs.
In July 2017, we received a federal royalty recovery totaling $14.1 million as part of a multi-year federal royalty refund claim. Approximately $9.6 million of the refund was recognized as other operational income and $4.5 million as a reduction of lease operating expenses during the quarter ended September 30, 2017. Included in SG&A expenses during the quarter ended September 30, 2017 is a $3.9 million success-based consulting fee incurred in connection with the federal royalty recovery, resulting in an overall net gain of $10.2 million.
Lease operating expenses (“LOE”) during the third quarter of 2017 totaled approximately $11.8 million ($6.66 per Boe), and included approximately $6.7 million of planned major maintenance expense and the aforementioned $4.5 million reduction of LOE related to the federal royalty refund claim, compared to LOE of $16.6 million ($8.88 per Boe) for the quarter ended June 30, 2017. Adjusting for third quarter actuals, including the LOE reduction related to the federal royalty recovery, we now expect our full year 2017 LOE to range from $58 million to $60 million, which includes planned major maintenance projects scheduled for the fourth quarter of 2017.
Transportation, processing, and gathering (“TP&G”) expenses during the third quarter of 2017 totaled approximately $1.1 million ($0.61 per Boe). We expect TP&G expenses to approximate $1.0 million in the fourth quarter of 2017.
Depreciation, depletion, and amortization (“DD&A”) expense on oil and gas properties for the third quarter of 2017 totaled approximately $26.7 million ($15.10 per Boe). We expect DD&A to range from $14 per Boe to $16 per Boe for the fourth quarter of 2017.
Salaries, general, and administrative (“SG&A”) expenses for the third quarter of 2017 were $15.9 million ($8.98 per Boe), compared to SG&A expenses of $18.5 million ($9.88 per Boe) for the quarter ended June 30, 2017. This included the previously mentioned charge of approximately $3.9 million of success-based consulting fees paid in connection with the federal royalty recovery, as well as approximately $4 million of advisory fees tied to the Board-requested strategic review. We expect SG&A cash costs, excluding fees associated with the strategic review, to approximate $10 million to $11 million for the fourth quarter of 2017, of which we expect to capitalize approximately 17% - 18%. We capitalized $2.6 million of SG&A expenses in the third quarter of 2017.
Incentive compensation expense for the third quarter of 2017 was approximately $4.6 million, representing the accrual of three-fourths of the estimated annual incentive following the Board’s approval of the incentive and retention programs in July 2017.
Accretion expense for the third quarter of 2017 was approximately $8.1 million. We expect accretion expense to also approximate $8 million in the fourth quarter of 2017.
Other operational expenses for the third quarter of 2017 totaled approximately $0.7 million and included approximately $0.4 million of stacking charges for the platform rig at Pompano, while awaiting demobilization.
Net derivative expense for the third quarter of 2017 totaled approximately $6.7 million, comprised of $1.2 million of income from cash settlements and $7.9 million of non-cash expense resulting from changes in the fair value of derivative instruments.
Interest expense for the third quarter of 2017 was approximately $3.5 million, which primarily included interest associated with the Company’s $225 million 7.50% Senior Second Lien Notes due 2022. Capitalized interest was $1.2 million in the third quarter of 2017. We expect interest expense to remain constant for the fourth quarter of 2017.
Capital Expenditures Update
Capital expenditures for the third quarter of 2017 were approximately $34 million, which included $7 million related to drilling the Rampart Deep well, before reimbursement of lease costs, $5 million associated with removal of the rig and reinstallation of the living quarters at the Pompano platform, and $20 million of plugging and abandonment expenditures. In addition, approximately $2.6 million of SG&A expense and $1.2 million of interest expense were capitalized during the quarter ended September 30, 2017. For the nine months ended September 30, 2017, capital
expenditures totaled approximately $96 million, which included approximately $57 million of plugging and abandonment expenditures. Capitalized SG&A and interest expenses for the nine months ended September 30, 2017 totaled approximately $7.4 million and $5.2 million, respectively.
Our Board-approved capital expenditures budget for 2017 is $181 million and includes approximately $22 million for exploration opportunities, $69 million for development activities, and $90 million for the plugging and abandonment of idle wells and platforms, and excludes capitalized SG&A and interest expenses. We currently expect to spend less than the approved 2017 budget.
Liquidity Update
As of September 30, 2017, Stone’s liquidity approximated $420.8 million, which included approximately $137.4 million of undrawn capacity under the Company’s revolving credit facility plus approximately $245.7 million in cash on hand and approximately $37.7 million in cash being held in a restricted account to satisfy near-term plugging and abandonment activities. As of November 1, 2017, Stone had cash on hand of approximately $242 million, and $38 million in cash held in the restricted abandonment account.
As of September 30, 2017, Stone’s outstanding debt totaled approximately $236 million, consisting of $225 million of 7.50% Senior Second Lien Notes due 2022 and approximately $11 million outstanding under a building loan. Further, the Company had no outstanding borrowings and outstanding letters of credit of approximately $12.6 million under its $150 million available borrowing base. The borrowing base redetermination from the bank group is expected in early November 2017.
As of September 30, 2017, we had a current income tax receivable of $27.7 million, which we expect to collect within the next twelve months.
We expect that cash flows from operating activities, cash on hand, and availability under our revolving credit facility will be adequate to meet the current 2017 operating and capital expenditures needs of the Company.
Strategic Review
As previously announced, following the successful completion of the Company’s financial restructuring and emergence from Chapter 11 reorganization, Stone’s Board of Directors (the “Board”) retained Petrie Partners LLC to assist the Board in its determination of the Company’s strategic direction, including assessing its various strategic alternatives. The Board’s assessment with Petrie Partners is ongoing and there can be no assurance that this assessment will result in any transaction.
Fresh Start Accounting and Hedge Accounting Changes
Upon emergence from Chapter 11 reorganization, Stone adopted fresh start accounting effective February 28, 2017. Under the principles of fresh start accounting, a new reporting entity was created, and Stone’s assets and liabilities were recorded at their fair values as of the fresh start reporting date. Also, effective January 1, 2017, we have elected to not designate our 2017, 2018, and 2019 commodity derivative contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements on these derivative contracts will be recorded in earnings through derivative income/expense. As a result, Stone’s financial statements dated on or after March 1, 2017 will not be comparable with financial statements issued prior to that date. References to “Predecessor” refer to Stone prior to the adoption of fresh start accounting while references to “Successor” refer to Stone subsequent to the adoption of fresh start accounting. Please review Stone’s Quarterly Reports on Form 10-Q for the periods ended March 31, 2017 and September 30, 2017, respectively, for further details regarding fresh start accounting and the financial information presented at the end of this press release.
Operational Update
Mississippi Canyon 116 - Rampart Deep (Deep Water). As previously announced, the Rampart Deep well, operated by Deep Gulf Energy III, LLC, encountered approximately 107 net vertical feet of liquids-rich natural gas pay in three primary zones, as interpreted by Stone. In addition to the reserve potential of Rampart Deep, this well also provides critical information that reduces the exploration risk of Stone’s Derbio prospect. Completion of the Rampart Deep well was deferred while the partners analyze the well data, and will be further evaluated in conjunction with future Derbio drilling results, which may impact sanctioning of the project. Working interest partners in the Rampart Deep well are Stone with 40%, Deep Gulf Energy III, LLC with 30% and entities managed by Ridgewood Energy Corporation (including Riverstone Holdings, LLC and its portfolio company ILX Holdings III, LLC) with 30%.
Mississippi Canyon 72 - Derbio (Deep Water). The Derbio prospect is located five miles from Stone’s Pompano platform and targets the Miocene interval. Results from the Rampart Deep well reduced the exploration risk of the Derbio prospect. Current drilling plans for Derbio target a first half of 2018 spud date. The well is estimated to take three months to drill, and, if successful, first production from the Rampart Deep/Derbio project is expected by late 2019 and could be a multi-well tie back to the Stone 100% owned Pompano platform. Working interest partners in the Derbio prospect are Stone with 40%, Deep Gulf Energy III, LLC with 30% and entities managed by Ridgewood Energy Corporation (including Riverstone Holdings, LLC and its portfolio company ILX Holdings III, LLC) with 30%.
Mississippi Canyon 28 - Mt. Providence (Deep Water). The Mt. Providence prospect is located approximately five miles from the Pompano platform and targets the Miocene interval. We currently expect to spud the Mt. Providence development well in December 2017. The well is estimated to take two months to drill. If successful, the well will be tied back to the Pompano platform, with first production expected in the second quarter of 2018. Stone holds a 100% working interest in this prospect.
Hedge Position
The following table illustrates our derivative positions for 2017, 2018 and 2019 as of November 1, 2017:
Oil Hedging Contracts | ||||||||
NYMEX | ||||||||
Put Contracts | Swap Contracts | |||||||
Daily Volume (Bbls/d) | Put Price ($ per Bbl) | Daily Volume (Bbls/d) | Swap Price ($ per Bbl) | |||||
Feb 2017 - Dec 2017 | 2,000 | $50.00 | Mar 2017 - Dec 2017 | 1,000 | $53.90 | |||
Jul 2017 - Dec 2017 | 1,000 | $41.10 | Oct 2017 - Dec 2017 | 1,000 | $52.10 | |||
Jan 2018 - Dec 2018 | 1,000 | $54.00 | Jan 2018 - Dec 2018 | 1,000 | $52.50 | |||
Jan 2018 - Dec 2018 | 1,000 | $45.00 | Jan 2018 - Dec 2018 | 1,000 | $51.98 | |||
Jan 2018 - Dec 2018 | 1,000 | $53.67 | ||||||
Jan 2019 - Dec 2019 | 1,000 | $51.00 | ||||||
Jan 2019 - Dec 2019 | 1,000 | $51.57 | ||||||
Collar Contracts | ||||||
Daily Volume (Bbls/d) | Put Price ($ per Bbl) | Call Price ($ per Bbl) | ||||
Mar 2017 - Dec 2017 | 1,000 | $50.00 | $56.45 | |||
Apr 2017 - Dec 2017 | 1,000 | $50.00 | $56.75 | |||
Jan 2018 - Dec 2018 | 1,000 | $45.00 | $55.35 | |||
Natural Gas Hedging Contracts | ||||
NYMEX | ||||
Swap Contracts | ||||
Daily Volume (MMBtu/d) | Swap Price ($ per MMBtu) | |||
Jul 2017 - Dec 2017 | 11,000 | $3.00 | ||
Collar Contracts | ||||||
Daily Volume (MMBtu/d) | Put Price ($ per MMBtu) | Call Price ($ per MMBtu) | ||||
Jan 2018 - Dec 2018 | 6,000 | $2.75 | $3.24 | |||
Other Information
Stone has planned a conference call for 9:00 a.m. Central Time on November 2, 2017 to discuss the operational and financial results for the third quarter of 2017. The call will be available through a live webcast link located in the Investor Center section of the Company’s website at www.StoneEnergy.com. The call will also be accessible by dialing (844) 632-7353 and requesting the “Stone Energy Call” approximately ten minutes before the scheduled start time. If unable to participate in the original call, a webcast replay will be available three hours after the call through a link in the Investor Center section of the Company’s website.
Non-GAAP Financial Measure
In this press release, we refer to a non-GAAP financial measure we call “discretionary cash flow.” Discretionary cash flow equals cash flows from operating activities before changes in operating assets and liabilities. Management believes discretionary cash flow is a financial indicator of our company’s ability to internally fund capital expenditures and service debt. Management also believes this non-GAAP financial measure of cash flow is useful information to investors because it is widely used by professional research analysts in the valuation, comparison, rating, and investment recommendations of companies in the oil and gas exploration and production industry. Discretionary cash flow should not be considered an alternative to net cash provided by (used in) operating activities or net income (loss), as defined by GAAP. See the “Reconciliation of Non-GAAP Financial Measure” schedules for reconciliations of discretionary cash flow to net cash provided by (used in) operating activities.
Forward-Looking Statements
Certain statements in this press release are forward-looking and are based upon Stone’s current belief as to the outcome and timing of future events. All statements, other than statements of historical facts, that address activities
or results that Stone plans, expects, believes, projects, estimates, or anticipates will, should, or may occur in the future, including future production of oil and gas, future capital expenditures and drilling of wells, and future financial or operating results are forward-looking statements. All forward-looking numbers are approximate. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, the timing, extent, and volatility of changes in commodity prices for oil and gas; operating risks; liquidity risks, including risks relating to our bank credit facility and the Company's ability to access the capital markets; political and regulatory developments and legislation, including developments and legislation relating to our operations in the Gulf of Mexico basin; and other risk factors and known trends and uncertainties as described in Stone’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K as filed with the Securities and Exchange Commission. For a more detailed discussion of risk factors, please see Part I, Item 1A, “Risk Factors” of the Company’s most recent Annual Report on Form 10-K and Part II, Item 1A of the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2017. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Stone’s actual results and plans could differ materially from those expressed in the forward-looking statements. Stone assumes no obligation and expressly disclaims any duty to update the information contained herein, except as required by law.
Estimates for Stone’s future production volumes are based on assumptions of capital expenditures levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation, and marketing of oil and gas are subject to disruption due to transportation and processing availability, mechanical failure, human error, hurricanes, and numerous other factors. Stone’s estimates are based on certain other assumptions, such as well performance and uptime estimates, which may vary significantly from those assumed. Delays experienced in well permitting could affect the timing of drilling and production. Lease operating expenses, which include major maintenance costs, vary in response to changes in prices of services and materials used in the operation of our properties, and the amount of maintenance activity required. Estimates of DD&A rates can vary according to reserve additions, capital expenditures, future development costs, and other factors. Therefore, we can give no assurance that our future production volumes, lease operating expenses, or DD&A rates, if provided, will be as estimated.
Stone Energy is an independent oil and natural gas exploration and production company headquartered in Lafayette, Louisiana with an additional office in New Orleans. Stone is engaged in the acquisition, exploration, development, and production of properties in the Gulf of Mexico basin. For additional information, contact Kenneth H. Beer, Chief Financial Officer, at 337-521-2210 phone, 337-521-9880 fax or via e-mail at CFO@StoneEnergy.com.
STONE ENERGY CORPORATION | ||||||||||||||||
SUMMARY STATISTICS | ||||||||||||||||
(Unaudited) | ||||||||||||||||
Successor | Predecessor | Predecessor | ||||||||||||||
Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | Combined Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2016 | |||||||||||||
(1)(2) | ||||||||||||||||
PRODUCTION QUANTITIES | ||||||||||||||||
Oil (MBbls) | 1,285 | 1,563 | 3,902 | 4,746 | ||||||||||||
Natural gas (MMcf) | 2,220 | 8,096 | 10,630 | 20,042 | ||||||||||||
Natural gas liquids (MBbls) | 114 | 686 | 701 | 1,294 | ||||||||||||
Oil, natural gas and NGLs (MBoe) | 1,769 | 3,598 | 6,375 | 9,380 | ||||||||||||
AVERAGE DAILY PRODUCTION | ||||||||||||||||
Oil (MBbls) | 14.0 | 17.0 | 14.3 | 17.3 | ||||||||||||
Natural gas (MMcf) | 24.1 | 88.0 | 38.9 | 73.1 | ||||||||||||
Natural gas liquids (MBbls) | 1.2 | 7.5 | 2.6 | 4.7 | ||||||||||||
Oil, natural gas and NGLs (MBoe) | 19.2 | 39.1 | 23.4 | 34.2 | ||||||||||||
REVENUE DATA (in thousands) (3) | ||||||||||||||||
Oil revenue | $61,841 | $71,116 | $189,393 | $204,102 | ||||||||||||
Natural gas revenue | 5,451 | 15,601 | 27,677 | 43,327 | ||||||||||||
Natural gas liquids revenue | 2,473 | 6,666 | 14,970 | 15,119 | ||||||||||||
Total oil, natural gas and NGLs revenue | $69,765 | $93,383 | $232,040 | $262,548 | ||||||||||||
AVERAGE REALIZED PRICES (3) | ||||||||||||||||
Oil (per Bbl) | $48.13 | $45.50 | $48.54 | $43.01 | ||||||||||||
Natural gas (per Mcf) | 2.46 | 1.93 | 2.60 | 2.16 | ||||||||||||
Natural gas liquids (per Bbl) | 21.69 | 9.72 | 21.36 | 11.68 | ||||||||||||
Oil, natural gas and NGLs (per Boe) | 39.44 | 25.95 | 36.40 | 27.99 | ||||||||||||
AVERAGE COSTS PER BOE | ||||||||||||||||
Lease operating expenses | $6.66 | $4.72 | $6.58 | $5.90 | ||||||||||||
Transp, processing and gathering expenses | 0.61 | 2.96 | 1.57 | 1.99 | ||||||||||||
Salaries, general and administrative expenses | 8.98 | 4.29 | 7.43 | 5.14 | ||||||||||||
DD&A expense on oil and gas properties | 15.10 | 16.08 | 17.45 | 17.42 | ||||||||||||
(1) | Results include operational and financial results from the Appalachia basin through the close of the sale of Appalachia properties on February 27, 2017. |
(2) For illustrative purposes, the Company has combined the Successor and Predecessor results to derive combined results for the nine month period ended September 30, 2017. The combination was generated by addition of comparable financial statement line items. However, because of various adjustments to the consolidated financial statements in connection with the application of fresh start accounting, including asset valuation adjustments and liability adjustments, the results of operations for the Successor will not be comparable to those of the Predecessor. The financial information in the Consolidated Statement of Operations and Reconciliations of Non-GAAP Financial Measures on the following pages provides the Successor's and the Predecessor's GAAP results for the applicable periods. The Company believes that subject to consideration of the impact of fresh start accounting, combining the results of the Predecessor and Successor provides meaningful information about production, revenues, commodity prices and costs that assists a reader in understanding the Company’s financial results for the applicable period.
(3) | Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. Accordingly, they were recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. Monthly settlements of effective hedges were reflected in revenue from oil and natural gas production. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements on these derivative contracts will be recorded in earnings through derivative income/expense. As a result of these mark-to-market adjustments, we will likely experience volatility in earnings from time to time due to commodity price volatility. Further, this change in accounting method effects the comparability of 2017 revenues, average realized prices and derivative income/expense to 2016 revenues, average realized prices and derivative income/expense, respectively. |
STONE ENERGY CORPORATION | ||||||||
CONSOLIDATED STATEMENT OF OPERATIONS | ||||||||
(In thousands, except per share amounts) | ||||||||
(Unaudited) | ||||||||
Successor | Predecessor | |||||||
Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | |||||||
Operating revenue: | ||||||||
Oil production | $61,841 | $71,116 | ||||||
Natural gas production | 5,451 | 15,601 | ||||||
Natural gas liquids production | 2,473 | 6,666 | ||||||
Other operational income | 9,760 | 1,044 | ||||||
Total operating revenue | 79,525 | 94,427 | ||||||
Operating expenses: (1) | ||||||||
Lease operating expenses | 11,778 | 16,976 | ||||||
Transportation, processing and gathering expenses | 1,076 | 10,633 | ||||||
Production taxes | 188 | 835 | ||||||
Depreciation, depletion and amortization | 27,553 | 58,918 | ||||||
Write-down of oil and gas properties | — | 36,484 | ||||||
Accretion expense | 8,095 | 10,082 | ||||||
Salaries, general and administrative expenses | 15,887 | 15,425 | ||||||
Incentive compensation expense | 4,646 | 2,160 | ||||||
Restructuring fees | 129 | 5,784 | ||||||
Other operational expenses | 703 | 9,059 | ||||||
Derivative expense, net | 6,685 | 199 | ||||||
Total operating expenses | 76,740 | 166,555 | ||||||
Gain (loss) on Appalachia Properties divestiture | (132 | ) | — | |||||
Income (loss) from operations | 2,653 | (72,128 | ) | |||||
Other (income) expenses: | ||||||||
Interest expense | 3,529 | 16,924 | ||||||
Interest income | (366 | ) | (58 | ) | ||||
Other income | (276 | ) | (272 | ) | ||||
Other expense | 47 | 16 | ||||||
Total other expense | 2,934 | 16,610 | ||||||
Loss before income taxes | (281 | ) | (88,738 | ) | ||||
Provision (benefit) for income taxes: | ||||||||
Current | (1,578 | ) | (991 | ) | ||||
Deferred | — | 1,888 | ||||||
Total income taxes | (1,578 | ) | 897 | |||||
Net income (loss) | $1,297 | ($89,635 | ) | |||||
Net income (loss) per share | $0.06 | ($16.01 | ) | |||||
Average shares outstanding - diluted | 19,997 | 5,600 | ||||||
(1) | Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. Accordingly, they were recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. Monthly settlements of effective hedges were reflected in revenue from oil and natural gas production. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements on these derivative contracts will be recorded in earnings through derivative income/expense. As a result of these mark-to-market adjustments, we will likely experience volatility in earnings from time to time due to commodity price volatility. Further, this change in accounting method effects the comparability of 2017 revenues, average realized prices and derivative income/expense to 2016 revenues, average realized prices and derivative income/expense, respectively. |
STONE ENERGY CORPORATION | ||||||||||||||||
CONSOLIDATED STATEMENT OF OPERATIONS | ||||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
(Unaudited) | ||||||||||||||||
Successor | Predecessor | Predecessor | ||||||||||||||
Combined Nine Months Ended September 30, 2017 | Period from March 1, 2017 through September 30, 2017 | Period from January 1, 2017 through February 28, 2017 | Nine Months Ended September 30, 2016 | |||||||||||||
(1)(2) | (1) | |||||||||||||||
Operating revenue: (3) | ||||||||||||||||
Oil production | $189,393 | $143,556 | $45,837 | $204,102 | ||||||||||||
Natural gas production | 27,677 | 14,201 | 13,476 | 43,327 | ||||||||||||
Natural gas liquids production | 14,970 | 6,264 | 8,706 | 15,119 | ||||||||||||
Other operational income | 10,839 | 9,936 | 903 | 1,737 | ||||||||||||
Derivative income, net | — | 1,414 | — | — | ||||||||||||
Total operating revenue | 242,879 | 175,371 | 68,922 | 264,285 | ||||||||||||
Operating expenses: (3) | ||||||||||||||||
Lease operating expenses | 41,974 | 33,154 | 8,820 | 55,349 | ||||||||||||
Transportation, processing and gathering expenses | 9,978 | 3,045 | 6,933 | 18,657 | ||||||||||||
Production taxes | 1,128 | 446 | 682 | 1,894 | ||||||||||||
Depreciation, depletion and amortization | 113,982 | 76,553 | 37,429 | 166,707 | ||||||||||||
Write-down of oil and gas properties | 256,435 | 256,435 | — | 284,337 | ||||||||||||
Accretion expense | 25,145 | 19,698 | 5,447 | 30,147 | ||||||||||||
Salaries, general and administrative expenses | 47,347 | 37,718 | 9,629 | 48,193 | ||||||||||||
Incentive compensation expense | 6,654 | 4,646 | 2,008 | 11,809 | ||||||||||||
Restructuring fees | 739 | 739 | — | 16,173 | ||||||||||||
Other operational expenses | 3,822 | 3,292 | 530 | 49,266 | ||||||||||||
Derivative expense, net | 364 | — | 1,778 | 687 | ||||||||||||
Total operating expenses | 507,568 | 435,726 | 73,256 | 683,219 | ||||||||||||
Gain (loss) on Appalachia Properties divestiture | 213,348 | (105 | ) | 213,453 | — | |||||||||||
Income (loss) from operations | (51,341 | ) | (260,460 | ) | 209,119 | (418,934 | ) | |||||||||
Other (income) expenses: | ||||||||||||||||
Interest expense | 8,320 | 8,320 | — | 49,764 | ||||||||||||
Interest income | (620 | ) | (575 | ) | (45 | ) | (474 | ) | ||||||||
Other income | (1,034 | ) | (719 | ) | (315 | ) | (840 | ) | ||||||||
Other expense | 14,197 | 861 | 13,336 | 27 | ||||||||||||
Reorganization items, net | (437,744 | ) | — | (437,744 | ) | — | ||||||||||
Total other (income) expense | (416,881 | ) | 7,887 | (424,768 | ) | 48,477 | ||||||||||
Income (loss) before income taxes | 365,540 | (268,347 | ) | 633,887 | (467,411 | ) | ||||||||||
Provision (benefit) for income taxes: | ||||||||||||||||
Current | — | (3,570 | ) | 3,570 | (4,178 | ) | ||||||||||
Deferred | — | — | — | 10,947 | ||||||||||||
Total income taxes | — | (3,570 | ) | 3,570 | 6,769 | |||||||||||
Net income (loss) | $365,540 | ($264,777 | ) | $630,317 | ($474,180 | ) | ||||||||||
Net income (loss) per share | ($13.24 | ) | $110.99 | ($84.90 | ) | |||||||||||
Average shares outstanding - diluted | 19,997 | 5,634 | 5,585 | |||||||||||||
(1) | Results include operational and financial results from the Appalachia basin through the close of the sale of Appalachia properties on February 27, 2017. |
(2) For illustrative purposes, the Company has combined the Successor and Predecessor results to derive combined results for the nine month period ended September 30, 2017. The combination was generated by addition of comparable financial statement line items. However, because of various adjustments to the consolidated financial statements in connection with the application of fresh start accounting, including asset valuation adjustments and liability adjustments, the results of operations for the Successor will not be comparable to those of the Predecessor. The Company believes that subject to consideration of the impact of fresh start accounting, combining the results of the Predecessor and Successor provides meaningful information that assists a reader in understanding the Company’s financial results for the applicable period.
(3) | Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. Accordingly, they were recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. Monthly settlements of effective hedges were reflected in revenue from oil and natural gas production. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements on these derivative contracts will be recorded in earnings through derivative income/expense. As a result of these mark-to-market adjustments, we will likely experience volatility in earnings from time to time due to commodity price volatility. Further, this change in accounting method effects the comparability of 2017 revenues, average realized prices and derivative income/expense to 2016 revenues, average realized prices and derivative income/expense, respectively. |
STONE ENERGY CORPORATION | ||||||||
RECONCILIATION OF NON-GAAP FINANCIAL MEASURE | ||||||||
DISCRETIONARY CASH FLOW to NET CASH PROVIDED BY OPERATING ACTIVITIES | ||||||||
(In thousands) | ||||||||
(Unaudited) | ||||||||
Successor | Predecessor | |||||||
Three Months Ended September 30, 2017 | Three Months Ended September 30, 2016 | |||||||
Net income (loss) as reported | $1,297 | ($89,635 | ) | |||||
Reconciling items: | ||||||||
Depreciation, depletion and amortization | 27,553 | 58,918 | ||||||
Write-down of oil and gas properties | — | 36,484 | ||||||
Deferred income tax provision | — | 1,888 | ||||||
Accretion expense | 8,095 | 10,082 | ||||||
Loss on sale of oil and gas properties | 132 | — | ||||||
Non-cash stock compensation expense | 502 | 1,725 | ||||||
Non-cash interest expense | 3 | 4,875 | ||||||
Non-cash derivative expense (1) | 7,879 | 236 | ||||||
Other non-cash expense | 56 | — | ||||||
Discretionary cash flow | 45,517 | 24,573 | ||||||
Change in income taxes payable | (1,578 | ) | 24,771 | |||||
Settlement of asset retirement obligations | (20,293 | ) | (4,400 | ) | ||||
Other working capital changes | 18,844 | (9,921 | ) | |||||
Net cash provided by operating activities | $42,490 | $35,023 | ||||||
(1) | Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. Accordingly, they were recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. Monthly settlements of effective hedges were reflected in revenue from oil and natural gas production. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements on these derivative contracts will be recorded in earnings through derivative income/expense. As a result of these mark-to-market adjustments, we will likely experience volatility in earnings from time to time due to commodity price volatility. Further, this change in accounting method effects the comparability of 2017 revenues, average realized prices and derivative income/expense to 2016 revenues, average realized prices and derivative income/expense, respectively. |
STONE ENERGY CORPORATION | ||||||||||||||||
RECONCILIATION OF NON-GAAP FINANCIAL MEASURE | ||||||||||||||||
DISCRETIONARY CASH FLOW to NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES | ||||||||||||||||
(In thousands) | ||||||||||||||||
(Unaudited) | ||||||||||||||||
Successor | Predecessor | Predecessor | ||||||||||||||
Combined Nine Months Ended September 30, 2017 | Period from March 1, 2017 through September 30, 2017 | Period from January 1, 2017 through February 28, 2017 | Nine Months Ended September 30, 2016 | |||||||||||||
(1)(2) | (1) | |||||||||||||||
Net income (loss) as reported | $365,540 | ($264,777 | ) | $630,317 | ($474,180 | ) | ||||||||||
Reconciling items: | ||||||||||||||||
Depreciation, depletion and amortization | 113,982 | 76,553 | 37,429 | 166,707 | ||||||||||||
Write-down of oil and gas properties | 256,435 | 256,435 | — | 284,337 | ||||||||||||
Deferred income tax provision | — | — | — | 10,947 | ||||||||||||
Accretion expense | 25,145 | 19,698 | 5,447 | 30,147 | ||||||||||||
(Gain) loss on sale of oil and gas properties | (213,348 | ) | 105 | (213,453 | ) | — | ||||||||||
Non-cash stock compensation expense | 3,538 | 893 | 2,645 | 6,407 | ||||||||||||
Non-cash interest expense | 3 | 3 | — | 14,278 | ||||||||||||
Non-cash derivative expense (3) | 2,988 | 1,210 | 1,778 | 1,261 | ||||||||||||
Non-cash reorganization items | (458,677 | ) | — | (458,677 | ) | — | ||||||||||
Other non-cash expense | 1,049 | 877 | 172 | 6,081 | ||||||||||||
Discretionary cash flow | 96,655 | 90,997 | 5,658 | 45,985 | ||||||||||||
Change in income taxes payable | (1,586 | ) | (5,156 | ) | 3,570 | 21,584 | ||||||||||
Settlement of asset retirement obligations | (56,770 | ) | (53,129 | ) | (3,641 | ) | (15,106 | ) | ||||||||
Investment in derivative contracts | (6,152 | ) | (2,416 | ) | (3,736 | ) | — | |||||||||
Other working capital changes | 32,366 | 40,101 | (7,735 | ) | (19,570 | ) | ||||||||||
Net cash provided by (used in) operating activities | $64,513 | $70,397 | ($5,884 | ) | $32,893 | |||||||||||
(1) | Results include operational and financial results from the Appalachia basin through the close of the sale of Appalachia properties on February 27, 2017. |
(2) For illustrative purposes, the Company has combined the Successor and Predecessor results to derive combined results for the nine month period ended September 30, 2017. The combination was generated by addition of comparable financial statement line items. However, because of various adjustments to the consolidated financial statements in connection with the application of fresh start accounting, including asset valuation adjustments and liability adjustments, the results of operations for the Successor will not be comparable to those of the Predecessor. The Company believes that subject to consideration of the impact of fresh start accounting, combining the results of the Predecessor and Successor provides meaningful information that assists a reader in understanding the Company’s financial results for the applicable period.
(3) | Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. Accordingly, they were recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. Monthly settlements of effective hedges were reflected in revenue from oil and natural gas production. With respect to our 2017, 2018 and 2019 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements on these derivative contracts will be recorded in earnings through derivative income/expense. As a result of these mark-to-market adjustments, we will likely experience volatility in earnings from time to time due to commodity price volatility. Further, this change in accounting method effects the comparability of 2017 revenues, average realized prices and derivative income/expense to 2016 revenues, average realized prices and derivative income/expense, respectively. |
STONE ENERGY CORPORATION | |||||||||
CONSOLIDATED BALANCE SHEET | |||||||||
(In thousands) | |||||||||
(Unaudited) | |||||||||
Successor | Predecessor | ||||||||
September 30, | December 31, | ||||||||
2017 | 2016 | ||||||||
Assets | |||||||||
Current assets: | |||||||||
Cash and cash equivalents | $245,714 | $190,581 | |||||||
Restricted cash | 37,684 | — | |||||||
Accounts receivable | 35,670 | 48,464 | |||||||
Fair value of derivative contracts | 2,565 | — | |||||||
Current income tax receivable | 27,672 | 26,086 | |||||||
Other current assets | 9,295 | 10,151 | |||||||
Total current assets | 358,600 | 275,282 | |||||||
Oil and gas properties, full cost method of accounting: | |||||||||
Proved | 714,515 | 9,616,236 | |||||||
Less: accumulated depreciation, depletion and amortization | (330,921 | ) | (9,178,442 | ) | |||||
Net proved oil and gas properties | 383,594 | 437,794 | |||||||
Unevaluated | 102,283 | 373,720 | |||||||
Other property and equipment, net | 18,433 | 26,213 | |||||||
Fair value of derivative contracts | 1,040 | — | |||||||
Other assets, net | 18,252 | 26,474 | |||||||
Total assets | $882,202 | $1,139,483 | |||||||
Liabilities and Stockholders’ Equity | |||||||||
Current liabilities: | |||||||||
Accounts payable to vendors | $33,120 | $19,981 | |||||||
Undistributed oil and gas proceeds | 5,439 | 15,073 | |||||||
Accrued interest | 10,244 | 809 | |||||||
Fair value of derivative contracts | 368 | — | |||||||
Asset retirement obligations | 84,654 | 88,000 | |||||||
Current portion of long-term debt | 421 | 408 | |||||||
Other current liabilities | 28,503 | 18,602 | |||||||
Total current liabilities | 162,749 | 142,873 | |||||||
Bank credit facility | — | 341,500 | |||||||
7.5% Senior Second Lien Notes due 2022 | 225,000 | — | |||||||
4.2% Building Loan | 10,567 | 10,876 | |||||||
Asset retirement obligations | 182,956 | 154,019 | |||||||
Fair value of derivative contracts | 74 | — | |||||||
Other long-term liabilities | 10,110 | 17,315 | |||||||
Total liabilities not subject to compromise | 591,456 | 666,583 | |||||||
Liabilities subject to compromise | — | 1,110,182 | |||||||
Total liabilities | 591,456 | 1,776,765 | |||||||
Predecessor common stock | — | 56 | |||||||
Predecessor treasury stock | — | (860 | ) | ||||||
Predecessor additional paid-in capital | — | 1,659,731 | |||||||
Successor common stock | 200 | — | |||||||
Successor additional paid-in capital | 555,323 | — | |||||||
Accumulated deficit | (264,777 | ) | (2,296,209 | ) | |||||
Total stockholders’ equity | 290,746 | (637,282 | ) | ||||||
Total liabilities and stockholders’ equity | $882,202 | $1,139,483 | |||||||