Stone Energy Corporation Announces Fourth Quarter and Year-end 2016 Results and Reserves

LAFAYETTE, La., Feb. 23, 2017 /PRNewswire/ -- Stone Energy Corporation SGY ("Stone" or the "Company") today announced financial and operational results for the fourth quarter of 2016.  Some items of note from the fourth quarter of 2016 and early 2017 include:

• Production volumes exceeded the upper end of fourth quarter 2016 guidance
• Confirmation Order approved plan of reorganization
• Sale Order approved sale of Appalachian assets
• Pompano platform rig program reinitiated

Financial Results

Stone reported a fourth quarter of 2016 net loss of $116.4 million, or $20.76 per share, on oil and gas revenue of $112.2 million, compared to a net loss of $318.7 million, or $57.63 per share, on oil and gas revenue of $106.2 million in the fourth quarter of 2015.  The adjusted net loss for the fourth quarter of 2016, which excludes impairment charges of $73.1 million, was $27.3 million, or $4.88 per share.  For full year 2016, Stone reported a net loss of $590.6 million, or $105.63 per share, on oil and gas revenue of $374.7 million, compared to a net loss of $1.1 billion, or $197.45 per share, on oil and gas revenue of $532.3 million for full year 2015.  The adjusted net loss for full year 2016, which excludes impairment charges of $357.4 million, was $154.5 million, or $27.63 per share.  Please see "Non-GAAP Financial Measures" and the accompanying financial statements for reconciliations of adjusted net income or loss, a non-GAAP financial measure, to net loss.

Net cash provided by operating activities totaled $45.7 million for the fourth quarter of 2016, while discretionary cash flow totaled $37.1 million during the fourth quarter of 2016, as compared to $48.5 million and $114.6 million, respectively, during the fourth quarter of 2015.  Net cash provided by operating activities totaled $78.6 million for full year 2016, while discretionary cash flow totaled $83.1 million for full year 2016, as compared to $247.5 million and $351.9 million, respectively, during full year 2015.  Please see "Non-GAAP Financial Measures" 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 fourth quarter of 2016 averaged 43.7 thousand barrels of oil equivalent ("MBoe") per day (262 million cubic feet of gas equivalent ("MMcfe") per day), which included approximately 22.3 MBoe (133.8 MMcfe) per day from the Gulf of Mexico (GOM) and 21.4 MBoe (128.2 MMcfe) per day from Appalachia, compared to net daily production of 39.1 MBoe (234.7 MMcfe) per day in the third quarter of 2016 and net daily production of 24.1 MBoe (144.6 Mcfe) per day in the fourth quarter of 2015.  The fourth quarter 2016 production mix was approximately 39% oil, 39% natural gas and 22% natural gas liquids ("NGLs").  Net daily production volumes for full year 2016 averaged 36.6 MBoe (219.6 MMcfe) per day, compared to net daily production of 39.6 MBoe (237.8 MMcfe) per day in 2015.  The decrease in full year production volumes for 2016 was primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016.  The production mix for full year 2016 was 47% oil, 37% natural gas and 16% NGLs, while the production mix for full year 2015 was 41% oil, 42% natural gas and 17% NGLs.  Excluding Appalachia production, volumes for the Gulf of Mexico basin in January and February 2017 averaged approximately 18 - 20 MBoe per day (108 - 120 MMcfe per day).

Prices realized during the fourth quarter of 2016 averaged $49.39 per barrel of oil, $15.49 per barrel of NGLs and $2.26 per Mcf of natural gas.  Average realized prices for the fourth quarter of 2015 were $69.68 per barrel of oil, $18.51 per barrel of NGLs and $2.48 per Mcf of natural gas. Effective hedging transactions increased the average realized price of oil by $2.62 per barrel and increased the average realized price of natural gas by $0.21 per Mcf in the fourth quarter of 2016.  Effective hedging transactions increased the average realized price of oil by $29.33 per barrel and increased the average realized price of natural gas by $0.91 per Mcf in the fourth quarter of 2015.  Realized prices for the year ended December 31, 2016 averaged $44.59 per barrel of oil, $13.23 per barrel of NGLs and $2.19 per MCF of natural gas, compared to $69.52 per barrel of oil, $13.46 per barrel of NGLs and $2.29 per Mcf of natural gas realized during the year ended December 31, 2015.  Effective hedging transactions increased the average realized price of oil by $3.77 per barrel and $22.64 per barrel for the years ended December 31, 2016 and 2015, respectively.  Effective hedging transactions increased the average realized price of natural gas by $0.39 in both 2016 and 2015.

Lease operating expenses during the fourth quarter of 2016 totaled $24.3 million ($6.05 per Boe or $1.01 per Mcfe), compared to $20.9 million ($9.42 per Boe or $1.57 per Mcfe) in the fourth quarter of 2015.  The quarter over quarter increase is primarily due to well intervention operations on the deep water Amethyst well.  Lease operating expenses for the years ended December 31, 2016 and 2015 totaled $79.7 million and $100.1 million, respectively. On a unit of production basis, lease operating expenses were $5.94 per Boe or $0.99 per Mcfe and $6.92 per Boe or $1.15 per Mcfe for the years ended December 31, 2016 and 2015, respectively. The decrease in full year 2016 lease operating expenses is primarily attributable to service cost reductions, the implementation of cost-savings measures, operating efficiencies and the shut-in of production at our Mary field from September 2015 until late June 2016. 

Other operational expenses during the fourth quarter of 2016 totaled $6.2 million, compared to $0.7 million in the fourth quarter of 2015. The increase is primarily due to payments related to contract termination charges and stacking charges associated with the platform rig at Pompano.  Other operational expenses for the year ended December 31, 2016 totaled $55.5 million, and included $6.1 million relating to a non-cash, cumulative foreign currency loss, $29.9 million in contract termination charges and $17.7 million in rig subsidy and stacking charges, compared to $2.4 million for full year 2015.  We expect other operational expenses to decline significantly in the first quarter of 2017 due to the termination of the rig, vessel and other contracts and the return to service of the Pompano platform rig in January 2017.                                                  

Transportation, processing and gathering (TP&G) expenses during the fourth quarter of 2016 totaled $9.1 million ($2.27 per Boe or $0.38 per Mcfe), compared to $3.0 million ($1.35 per Boe or $0.23 per Mcfe) during the fourth quarter of 2015.  This increase is due primarily to the restoration of production at our Mary field that was shut-in from September 2015 until late June 2016.  TP&G expenses for the year ended December 31, 2016 totaled $27.8 million ($2.07 per Boe or $0.35 per Mcfe), which included a $7.9 million Office of Natural Resources Revenue credit, compared to TP&G expenses for 2015 of $58.8 million ($4.07 per Boe or $0.68 Mcfe).  The decrease in TP&G expenses during the year ended December 31, 2016 was primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016 and the beneficial terms of the interim gas gathering and processing agreement in Appalachia that was executed at the end of the second quarter of 2016.  For the year ended December 31, 2016, TP&G expenses attributable to the Appalachia Properties were $28.1 million. 

Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the fourth quarter of 2016 totaled $53.4 million ($13.02 per Boe or $2.17 per Mcfe), compared to $55.4 million ($24.47 per Boe or $4.08 per Mcfe) in the fourth quarter of 2015.  DD&A expense on oil and gas properties for the year ended December 31, 2016 totaled $220.1 million ($16.10 per Boe or $2.68 per Mcfe), compared to DD&A expense of $281.7 million ($19.15 per Boe or $3.19 per Mcfe) for the year ended December 31, 2015.  The quarterly and annual decreases are primarily attributable to the ceiling test write-downs of oil and gas properties.

Salaries, general and administrative ("SG&A") expenses (exclusive of incentive compensation) for the fourth quarter of 2016 were $10.7 million ($2.67 per Boe or $0.45 per Mcfe), compared to $16.4 million ($7.40 per Boe or $1.23 per Mcfe) in the fourth quarter of 2015.  SG&A expenses (exclusive of incentive compensation) totaled $58.9 million ($4.40 per Boe or $0.73 per Mcfe) and $69.4 million ($4.80 per Boe or $0.80 per Mcfe) for the years ended December 31, 2016 and 2015, respectively. The quarterly and annual decreases in SG&A were primarily attributable to staff and other cost reductions.  SG&A expenses for 2015 included $2.1 million of termination charges associated with the early termination of an office lease.

Incentive compensation expense for the fourth quarter of 2016 was $1.7 million, compared to ($1.4) million in the fourth quarter of 2015.  For the years ended December 31, 2016 and 2015, incentive compensation expense totaled $13.5 million and $2.2 million, respectively.  The 2016 incentive compensation cash bonuses are calculated based on the achievement of certain strategic objectives for each quarter of 2016. Portions of the 2016 incentive cash bonuses replace amounts previously awarded to employees as stock-based compensation, which is reflected in SG&A, resulting in higher incentive compensation expense in 2016 compared to 2015. 

Accretion expense for the fourth quarter of 2016 was $10.1 million, compared to $6.7 million in the fourth quarter of 2015.  Accretion expense totaled $40.2 million and $26.0 million for the years ended December 31, 2016 and 2015, respectively.  The quarterly and annual increases were due to a higher applicable discount rate used to calculate the present value of the asset retirement obligations compared to prior years.  Stone expects accretion expense to decrease upon implementation of fresh start accounting, which will be implemented upon emergence from bankruptcy proceedings.

Interest expense for the fourth quarter of 2016 was $14.7 million, compared to $12.2 million in the fourth quarter of 2015.  Interest expense totaled $64.5 million and $43.9 million for the years ended December 31, 2016 and 2015, respectively.  The quarterly and annual increases in interest expense were primarily due to an increase in borrowed funds, combined with a lower capitalized portion. Stone expects interest expense to significantly decrease in 2017, upon emergence from bankruptcy proceedings. 

Restructuring expenses for the fourth quarter of 2016 were $13.4 million, and for full year 2016 were $29.6 million.  These fees, incurred prior to the filing of the Bankruptcy Petitions on December 14, 2016, related to expenses supporting a restructuring effort, including legal and financial advisory costs for Stone, our bank group and our noteholders.  Stone does not expect to incur further restructuring expenses since all legal and advisory fees incurred post-bankruptcy filing will be classified as "Reorganization Items."

Reorganization items for the fourth quarter and full year 2016 were $10.9 million, which represented an $8.3 million non-cash charge to write-off all deferred financing costs and associated unamortized discounts and premiums associated with our 2017 Convertible Notes and 2022 Notes and $2.6 million of expenses supporting a restructuring effort including legal and financial advisory costs for Stone, our bank group and our noteholders incurred post-bankruptcy filing.  The quarterly amount of reorganization items is difficult to forecast as they will be highly dependent on the level of legal and financial advisory activity.

Reserves

Our estimated proved reserves as of December 31, 2016 were 53 MMBoe (million barrels of oil equivalent) or 321 Bcfe (billion cubic feet of natural gas equivalent), compared to 57 MMBoe (342 Bcfe) at year-end 2015.  The decrease in estimated proved reserves is primarily attributable to 2016 production, which was partially offset by upward revisions of previous estimates resulting from positive gas pricing changes that extended the economic limits of the reservoirs by 15 MMBoe (92 Bcfe) primarily in Appalachia, slightly offset by negative well performance of 6 MMBoe (35 Bcfe).  Through the upward revisions of previous estimates, Stone replaced approximately 73% of 2016 production.  Substantially all of Stone's proved reserves in Appalachia were reclassified to contingent resources at December 31, 2015.  The Appalachia Properties accounted for approximately 34% of our estimated proved oil, natural gas and NGLs reserves at December 31, 2016 compared to 1% at December 31, 2015.  There were no estimated proved reserve quantities booked at December 31, 2016 for the Amethyst well.  As of December 31, 2015, Amethyst represented approximately 23% and 25% of our estimated proved reserves quantities and standardized measure of discounted future net cash flows, respectively.

The year-end 2016 estimated proved reserves were 44% oil, 20% NGLs and 36% natural gas on an equivalent basis.  The changes from year-end 2015 estimated proved reserves to year-end 2016 estimated proved reserves included production of approximately 13 MMBoe (80 Bcfe), positive price revisions of 15 MMBoe (92 Bcfe) and negative well performance of 6 MMBoe (35 Bcfe). 

The standardized measure of discounted future net cash flows from our estimated proved reserves at December 31, 2016, using a 10% discount rate and 12-month average prices (after differentials) of $40.15 per barrel of oil, $9.46 per barrel of NGLs and $1.71 per Mcf of natural gas, was approximately $226 million.  Estimated future income taxes had no effect on the standardized measure as of December 31, 2016.  If current pricing was used to determine the estimated proved reserves or the standardized measure at December 31, 2016, the reserve volumes and values would be increased.

The year-end 2016 estimated proved reserves included proved developed (PD) reserves of 43 MMBoe or 256 Bcfe (43% oil, 22% NGLs, 35% natural gas) and proved undeveloped (PUD) reserves of 11 MMBoe or 65 Bcfe (46% oil, 13% NGLs, 41% natural gas).  In addition, there were 35 MMBoe or 213 Bcfe of estimated probable reserves and 32 MMBoe or 191 Bcfe of estimated possible reserves at year-end 2016.

All of Stone's estimated proved, probable and possible reserves were independently engineered by Netherland Sewell & Associates.

Capital Expenditures Update

Capital expenditures for the fourth quarter of 2016 were approximately $22.0 million, which included $5.4 million of plugging and abandonment expenditures.  Fourth quarter 2016 capital expenditures included increasing our working interest in a number of units in the Mary field in Appalachia to 100% and recompletion operations on our Mississippi Canyon 109 No. A-22 well.  During the fourth quarter of 2016, we incurred charges of approximately $4.8 million for contract termination charges and stacking charges associated with the platform rig at Pompano, all of which were charged to other operational expenses and excluded from capital expenditures.  Further, $4.1 million of SG&A expenses and $5.4 million of interest were capitalized during the fourth quarter of 2016, and were excluded from the capital expenditures budget.  For the year ended December 31, 2016, capital expenditures totaled $161.1 million, which included $15.4 million of seismic expenditures and $18.9 million of plugging and abandonment expenditures.  The rig stacking and subsidy charges and contract termination charges for the year ended December 31, 2016 totaled $47.6 million and were included in other operational expenses.  For the year ended December 31, 2015, capital expenditures totaled $464.5 million, which included $72.4 million of plugging and abandonment expenditures.  Capitalized SG&A expenses were $27.1 million and capitalized interest totaled $41.3 million for full year 2015.

Although our capital expenditures budget for 2017 has not yet been approved by the board of directors and is dependent on the outcome of our Chapter 11 proceedings and the related reorganization of the Company, the financial projections prepared in connection with our restructuring efforts included estimated preliminary capital expenditures of approximately $200 million for 2017. The projected capital expenditures budget of $200 million includes approximately $86 million of plugging and abandonment costs.

Liquidity Update   

As previously reported, on June 14, 2016, we entered into an amendment (the "June Amendment") with our bank group, which amended the credit agreement to (i) increase the borrowing base to $360.0 million from $300.0 million, (ii) provide for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of the company's properties, (iii) permit second lien indebtedness, (iv) revise the maximum Consolidated Funded Leverage ratio to be 5.25x for the fiscal quarter ending June 30, 2016, 6.50x for the fiscal quarter ending September 30, 2016, 9.50x for the fiscal quarter ending December 31, 2016 and 3.75x thereafter, (v) require minimum liquidity of at least $125.0 million until January 15, 2017, (vi) impose limitations on capital expenditures to $60.0 million from June 2016 through December 2016 (excluding up to $25 million for completion expenditures in Appalachia), (vii) grant the lenders a perfected security interest in all deposit accounts and (viii) provide for anti-hoarding cash provisions for amounts in excess of $50.0 million to apply after December 10, 2016.  Upon execution of the June Amendment, we repaid $56.8 million of borrowings, resulting in the elimination of our borrowing base deficiency and bringing our total borrowings and letters of credit outstanding under the credit facility in conformity with the $360.0 million borrowing base.

We have $300 million of 1¾% Senior Convertible Notes (the "2017 Convertible Notes") that we need to restructure or repay by March 1, 2017.  Additionally, we had an interest payment obligation under our 7½% Senior Notes due 2022 (the "2022 Notes") of approximately $29.2 million, due on November 15, 2016.  The indenture governing the 2022 Notes provides a 30-day grace period that extended the latest date for making this cash interest payment to December 15, 2016 before an event of default occurred under the indenture.  Although we had sufficient liquidity to make the interest payment by the due date, we elected to not make this interest payment and utilized the 30-day grace period provided by the indenture before entering into the Chapter 11 proceedings.  Subject to certain exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Debtors or their property to recover, collect or secure a pre-petition claim. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements.

As of September 30, 2016, we were in compliance with all covenants under the bank credit facility and the indentures governing our notes, however, we anticipated that the minimum liquidity requirement and other restrictions under the June Amendment would prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016, as well as the subsequent maturity of our 2017 Convertible Notes on March 1, 2017. As a result of these conditions, continued decreases in commodity prices and the significant level of our indebtedness, we continued to work with our financial and legal advisors throughout 2016 to structure a plan of reorganization to improve our financial position and liquidity and allow for growth and long-term success.  See Chapter 11 Proceedings below.

As of December 31, 2016, the current portion of long-term debt of $0.4 million represented principal payments due within one year on our building loan.  On December 31, 2016 and February 23, 2017, we had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit, leaving $6.0 million of availability under the bank credit facility.

The face value of the 2017 Convertible Notes of $300 million and the 2022 Notes of $775 million have been reclassified as liabilities subject to compromise in the consolidated financial statements at December 31, 2016. Additionally, a non-cash charge to write-off all deferred financing costs and associated unamortized discounts and premiums of approximately $8.3 million is included in reorganization items in the consolidated statement of operations for the year ended December 31, 2016. 

The Debtors filed the Bankruptcy Petitions on December 14, 2016, and on February 15, 2017, the Bankruptcy Court entered an order confirming the Plan. We expect the Plan to become effective on February 28, 2017, at which point the Debtors will emerge from bankruptcy.  Upon emergence from bankruptcy, we expect that we will eliminate approximately $1.2 billion in principal amount of outstanding debt, resulting in remaining debt outstanding of approximately $236 million, consisting of the $225 million of Second Lien Notes and $11 million outstanding under the Building Loan; however, there is no assurance that the effectiveness of the Plan will occur on February 28, 2017, or at all.

As of December 31, 2016 and February 23, 2017, Stone had cash on hand of approximately $190.6 million and $208.0 million, respectively.

Upon emergence, we expect that cash flows from operating activities, cash on hand and availability under our bank credit facility will be adequate to meet the 2017 operating and capital expenditures needs of the post-reorganized Company, however, there are no assurances that we will emerge from bankruptcy on February 28, 2017 as expected.

Chapter 11 Proceedings

On December 14, 2016, the Company and its subsidiaries Stone Energy Offshore, L.L.C. and Stone Energy Holding, L.L.C. (together with the Company, the "Debtors") filed voluntary petitions for reorganization (the "Bankruptcy Petitions") in the United States Court for the Southern District of Texas, Houston Division (the "Bankruptcy Court") seeking relief under the provisions of Chapter 11 of Title 11 ("Chapter 11") of the United States Bankruptcy Code (the "Bankruptcy Code").  On February 15, 2017, the Bankruptcy Court entered an order confirming the Company's Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (the "Plan"). During the bankruptcy proceedings, the Debtors are operating as "debtors-in-possession" in accordance with applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by the Debtors, allowing the Company to operate its business in the ordinary course throughout the bankruptcy process. The first day motions included, among other things, a cash collateral motion, a motion maintaining the Company's existing cash management system and motions making various vendor payments, wage payments and tax payments in the ordinary course of business.

Subject to certain exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Debtors or their property to recover, collect or secure a pre-petition claim. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements.

Restructuring Support Agreement

Prior to filing the Bankruptcy Petitions, as previously announced, on October 20, 2016, the Debtors entered into a restructuring support agreement (the "Original RSA") with certain holders of the 2017 Convertible Notes and the 2022 Notes (collectively, the "Notes" and the holders thereof, the "Noteholders"), to support a restructuring on the terms of a pre-packaged plan of reorganization.  On November 17, 2016, the Debtors commenced a solicitation to seek acceptance by a majority of those voting in each voting class of claims of the Company's creditors under the Plan, including (a) the lenders (the "Banks") under the Fourth Amended and Restated Credit Agreement, dated as of June 24, 2014, as amended, modified, or otherwise supplemented from time to time (the "Credit Facility") among Stone as borrower, Bank of America, N.A. as administrative agent and issuing bank, and the financial institutions named therein, and (b) the Noteholders.  The solicitation period ended on December 16, 2016 and (i) of the 94.24% of Noteholders in aggregate outstanding principal amount that voted, 99.95% voted in favor of the Plan and .05% voted to reject the Plan, and (ii) 100% of the Banks voted to accept the Plan.

On December 14, 2016, the Debtors, the Noteholders holding approximately 79.7% of the aggregate principal amount of Notes and the Banks holding 100% of the aggregate principal amount owing under the Credit Facility entered into an Amended and Restated Restructuring Support Agreement (the "A&R RSA") that amended, superseded and restated in its entirety the Original RSA.  In connection with entry into the A&R RSA and the commencement of the bankruptcy cases, the Debtors amended the plan of reorganization then in effect.  Additionally, on December 16, 2016, an ad hoc group of certain of the Company's stockholders (the "Stockholder Ad Hoc Group") filed a motion (the "Equity Committee Motion") to appoint an official committee of equity security holders in connection with the Debtors' Chapter 11 proceedings. On December 21, 2016, the Company reached a settlement agreement with the Stockholder Ad Hoc Group (the "Settlement") and on December 28, 2016, the plan of reorganization was amended.

Upon emergence from bankruptcy by the Debtors, and pursuant to the terms of the Plan, as amended to be consistent with the terms of the A&R RSA and the term sheet annexed to the A&R RSA (the "Term Sheet") and as amended pursuant to the Settlement, the Noteholders will receive their pro rata share of (i) $100 million of cash, (ii) 95% of the common stock in reorganized Stone and (iii) $225 million of new 7.5% second lien notes due 2022 (the "Second Lien Notes").  Existing common stockholders of Stone will receive their pro rata share of (i) 5% of the common stock in reorganized Stone, and (ii) warrants for ownership of up to 15% of reorganized Stone's common equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants and which may be exercised any time prior to the fourth anniversary of the Plan's effective date, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company.  Banks signatory to the A&R RSA will receive their respective pro rata share of commitments and obligations under an amended credit agreement (the "Amended Credit Facility"), as well as their respective share of the Company's unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA, defined below.

All claims of creditors with unsecured claims other than claims by the Noteholders, including vendors, shall be unaltered and will be paid in full in the ordinary course of business to the extent such claims are undisputed.

Each of the foregoing common equity percentages in reorganized Stone is subject to dilution from the exercise of the new warrants described above and a management incentive plan. Assuming implementation of the Plan, Stone expects that it will eliminate approximately $1.2 billion in principal amount of outstanding debt.

The A&R RSA contains certain covenants on the part of the Company and the Noteholders and Banks who are signatories to the A&R RSA, including that such Noteholders and Banks will support the sale of Stone's producing properties and acreage, including approximately 86,000 net acres, in the Appalachia regions of Pennsylvania and West Virginia (the "Appalachia Properties"), and otherwise facilitate the restructuring transaction, in each case subject to certain terms and conditions in the A&R RSA. The consummation of the Plan is subject to customary conditions and other requirements, as well as the sale by Stone of the Appalachia Properties for a cash purchase price of at least $350 million and approval of the Bankruptcy Court.

On February 15, 2017, the Bankruptcy Court entered the Order Confirming the Plan (the "Confirmation Order").  We currently expect to the Plan to become effective on February 28, 2017, at which point the Debtors will emerge from bankruptcy; however, there can be no assurance that the effectiveness of the Plan will occur on such date, or at all.

Purchase and Sale Agreement

As previously announced, on October 20, 2016, Stone entered into a purchase and sale agreement with TH Exploration III, LLC, an affiliate of Tug Hill, Inc., (the "Tug Hill PSA") for the sale of the Appalachia Properties for $360 million in cash, subject to customary purchase price adjustments.  Pursuant to Bankruptcy Court orders dated January 11, 2017 and January 31, 2017, two additional bidders were allowed to participate in competitive bidding on the Appalachia Properties.  On January 18, 2017, the Bankruptcy Court approved the Bidding Procedures in connection with the sale of the Appalachia Properties. In accordance with the Bidding Procedures, Stone conducted an auction for the sale of the Appalachia Properties on February 8, 2017 and upon conclusion, selected the final bid submitted by EQT Production Company ("EQT"), with a final purchase price of $527 million in cash, subject to customary purchase price adjustments and approval by the Bankruptcy Court, with an upward adjustment to the purchase price of up to $16 million in an amount equal to certain downward adjustments, as the prevailing bid.

On February 9, 2017, the Company entered into a purchase and sale agreement with EQT (the "EQT PSA"), reflecting the terms of the prevailing bid. Under the EQT PSA, the sale of the Appalachia Properties has an effective date of June 1, 2016. The EQT PSA contains customary representations, warranties and covenants. The EQT PSA may be terminated, subject to certain exceptions, (i) upon mutual written consent, (ii) if the closing has not occurred by March 1, 2017, (iii) for certain material breaches of representations and warranties or covenants that remain uncured, and (iv) upon the occurrence of certain other events specified in the EQT PSA.

At the close of the sale of the Appalachia Properties, the Tug Hill PSA will terminate, and the Company will use a portion of the cash consideration received to pay Tug Hill a break-up fee of $10.8 million.  On February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions. At December 31, 2016, the estimated proved reserves associated with these assets represented approximately 34% of our total estimated proved oil and natural gas reserves.

Bank Credit Facility

On December 14, 2016, the Debtors and the Banks holding 100% of the aggregate principal amount owing under the Credit Facility entered into the A&R RSA, pursuant to which the Banks will receive their respective pro rata share of commitments and obligations under the Amended Credit Facility on the terms set forth in Exhibit 1(a) to the Term Sheet, as well as their respective share of the Company's unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA. The terms of the Amended Credit Facility under the Plan are substantially consistent with the pre-petition facility, except, the borrowing base will be reduced to $200 million subject to a $150 million borrowing cap until the first redetermination of the borrowing base scheduled for November 1, 2017, and subject to decrease under certain circumstances. Additionally, the Consolidated Funded Leverage financial covenant will be adjusted to levels ranging from 2.50 to 1 to 3.00 to 1 for 2017 and ranging from 2.50 to 1 to 3.50 to 1 thereafter. The interest cost for loans at the LIBOR rate will be increased to a range of 3.00% to 4.00%. The Amended Credit Facility will be a four-year facility. There can be no assurance that we will emerge from bankruptcy on February 28, 2017 as expected.

For additional details regarding (i) the A&R RSA, please see Stone's Current Report on Form 8-K filed on December 14, 2016, (ii) the Plan, please see Stone's Current Report on Form 8-K filed on December 28, 2016, and (iii) the EQT PSA, please see Stone's Current Report on Form 8-K filed on February 10, 2017.

Supplemental Bonding Update

As previously reported, on March 21, 2016, the Bureau of Ocean Energy Management ("BOEM") notified Stone that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM's guidance to lessees at that time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting incremental financial assurances in favor of BOEM.  On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to work with BOEM to finalize the implementation of our long-term tailored plan. A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to reflect the updated decommissioning estimates. Additionally, on July 14, 2016, BOEM issued a Notice to Lessees ("NTL"), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurances by offshore lessees. The NTL discontinues the policy of supplemental bonding waivers and allows for the ability to self-insure up to 10% of a company's tangible net worth where a company could demonstrate a certain level of financial strength.  BOEM tentatively expects to approve or deny tailored plans submitted by lessees on or around September 11, 2017, although extensions may be granted to companies actively working with BOEM to finalize tailored plans.  We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are not eligible to self-insure any of our additional security obligations. We received a Proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required, and we are continuing to work with BOEM to adjust our previously submitted tailored plan for variances between our decommissioning estimates and that of the Bureau of Safety and Environmental Enforcement ("BSEE"). In the first quarter of 2017, BOEM announced that it will extend the implementation timeline for the new NTL by an additional six months.  The revised proposed plan may require approximately $7 million to $10 million of incremental financial assurance or bonding for sole liability properties and potentially an additional $30 million to $60 million of incremental financial assurance or bonding for non-sole liability properties by the end of 2017 or in 2018, dependent on adjustments following ongoing discussions with BSEE and any modifications to the NTL.  Under the revised plan, additional financial assurance would be required for subsequent years.  There is no assurance this tailored plan will be approved by BOEM.  Additionally, it is uncertain at this time what impact the new Trump administration may have on the current financial regulatory framework.

Operational Update  

Pompano Platform Drilling Program (Deep Water).  In early June 2016, we temporarily stacked the platform rig in place to preserve liquidity.  In January 2017, we reinitiated drilling operations on the Mt. Bona prospect, the first of a three well development program to be drilled from the Pompano platform. Each development well is expected to provide additional production volumes ranging from 500 to over 1,500 Boe per day per well after hook-up.  Stone holds a 100% working interest in these wells. 

Pompano Platform Production Update (Deep Water).  On June 28, 2016, a third-party gas processing plant in Pascagoula, Mississippi experienced an explosion that shut down the facility and impacted Pompano gas volumes.  In late December 2016, the gas processing plant returned to normal operations, with no further curtailments anticipated.

Mississippi Canyon 26 – No. 1 Amethyst Well (Deep Water).  As previously reported, production from our Amethyst well was shut in during late April 2016 to allow for a technical evaluation.  During the first week of November, we initiated acid stimulation work and intermittently flowed the well at a rate of 10-15 MMcf per day, while we continued to observe and evaluate the well's performance.  On November 30, 2016, we performed a routine shut in of the well to record pressures and determined that pressure communication existed between the production tubing and production casing strings, resulting from a suspected tubing leak.  We expect to begin temporary abandonment operations on the well late in the first quarter of 2017, and we plan to evaluate the well for potential sidetrack operations in the second half of 2017.

Mississippi Canyon 109 – No. A-22 Well Recompletion (Deep Water).  On September 27, 2016, we initiated recompletion operations on the Mississippi Canyon 109 No. A-22 ST1 well to target the "H" sand in the Pliocene interval.  Following the successful completion of this operation in November 2016, the well has produced at a rate of approximately 430 Boe per day.  Stone holds a 100% working interest in this well, which ties back to our Amberjack platform.

Mississippi Canyon 117 - Rampart Deep and Rampart Shallow (Deep Water).  The Rampart exploration prospects (Deep and Shallow) target the Miocene interval and are expected to be tied back to the Pompano platform, if successful.  Stone currently holds a 100% working interest in the prospect, but has been in discussions with another deep water operator to reduce its working interest to 50% or less.  The prospects are located nine miles from Stone's Pompano platform, and each well is estimated to take three months to drill. 

Mississippi Canyon 72 - Derbio (Deep Water).  The Derbio prospect is located five miles from Stone's Pompano platform and targets the Miocene interval.  If successful, a tie-back to the Pompano platform is likely.  Stone currently holds a 100% working interest in the prospect, but has been in discussions with another deep water operator to reduce its working interest to 50% or less.  The well is estimated to take three months to drill. 

Alaminos Canyon 943 - Lamprey (Deep Water).  We were unable to secure a partner on this project, and we have elected to not further progress this prospect. 

Appalachia Basin.  As reported on June 29, 2016, Stone entered into an interim gas gathering and processing agreement to produce the Mary field in Appalachia.  The initial term of the interim agreement was through August 31, 2016, and it continued on a month to month basis thereafter.  We expect the interim agreement to continue through the sale of the Appalachia Properties, which we expect to close before February 28, 2017.  During the fourth quarter of 2016, production from the Mary field averaged over 109 MMcfe per day, with total Appalachia volumes averaging 128 MMcfe per day.

Hedge Position

The following table illustrates our derivative positions for 2017 and 2018 as of February 23, 2017: 

 

 

New York Stock Exchange Notifications

On April 29, 2016, we were notified by the New York Stock Exchange ("NYSE") that we were not in compliance with the NYSE's continued listing requirements, as the average closing price of our shares of common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average share price for continued listing on the NYSE. On May 17, 2016, we were notified by the NYSE that our average global market capitalization had been less than $50 million over a consecutive 30 trading-day period at the same time that our stockholders' equity was less than $50 million, which is non-compliant with the NYSE's rules.

At the close of business on June 10, 2016, we effected a 1-for-10 reverse stock split in order to increase the market price per share of our common stock in order to regain compliance with the NYSE's minimum share price requirement.  We were notified on July 1, 2016 that we cured the minimum share price deficiency and that we were no longer considered non-compliant with the $1.00 per share average closing price requirement, although we remain non-compliant with the $50 million market capitalization and stockholders' equity requirements.

On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders' equity deficiencies to the NYSE.  The NYSE accepted the plan on August 4, 2016 and will continue to review the Company on a quarterly basis for compliance with the plan. On September 20, 2016, we submitted a second quarter 2016 update to our plan to mitigate listing deficiencies, and the update was accepted by the NYSE on September 22, 2016.  On December 22, 2016, we submitted our third quarter 2016 update, and the update was accepted by the NYSE on January 5, 2017.  We expect to submit our fourth quarter 2016 update to the NYSE by mid-March 2017.

Upon acceptance of the plan by the NYSE, and after two consecutive quarters of sustained market capitalization above $50 million, we would no longer be non-compliant with the market capitalization and stockholders' equity requirements. During the 18-month cure period, our shares of common stock will continue to be listed and traded on the NYSE, unless we experience other circumstances that subject us to delisting, including abnormally low market capitalization.  If we fail to meet the material aspects of the plan or any of the quarterly milestones, the NYSE will review the circumstances and variance, and determine whether such variance warrants commencement of suspension and delisting procedures. Upon filing, or announcement of intention to file, for relief under chapter 11 of the Bankruptcy Code, a company below a listing standard is subject to immediate suspension and delisting.  However, if we are profitable or have positive cash flow, or if we are demonstrably in sound financial health despite the bankruptcy proceedings, the NYSE may evaluate our plan in light of the filing without immediately suspending and delisting our common stock.  To date, and throughout the chapter 11 filing period, we have continued to trade on the NYSE.

Other Information

Stone Energy will not be hosting a conference call to discuss the fourth quarter and full year 2016 operational and financial results.

Non-GAAP Financial Measures

In this press release, we refer to non-GAAP financial measures we call "discretionary cash flow" and "adjusted net loss."  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 operating activities or net income, as defined by GAAP.  Management believes adjusted net loss is useful 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.  Please see the "Reconciliation of Non-GAAP Financial Measures" for a reconciliation of discretionary cash flow to net cash provided by operating activities and a reconciliation of adjusted net loss to net loss.

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 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.  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 and extent of changes in commodity prices for oil and gas, operating risks, liquidity risks, including risks relating to our bank credit facility; the ability to consummate the sale of the Appalachia Properties as contemplated by the EQT PSA; the ability to consummate a plan of reorganization in accordance with the terms of the Plan; risks attendant to the bankruptcy process, including the effects thereof on the Company's business and on the interests of various constituents, the length of time that the Company might be required to operate in bankruptcy and the continued availability of operating capital during the pendency of such proceedings; risks associated with third party motions in any bankruptcy case, which may interfere with the ability to consummate a plan of reorganization in accordance with the terms of the Plan; potential adverse effects on the Company's liquidity or results of operations; increased costs to execute the reorganization in accordance with the terms of the Plan; effects of our bankruptcy proceedings and emergence from bankruptcy on the market price of the Company's common stock and on 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 and Appalachia, 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.  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, 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 will be as estimated.

Stone Energy is an independent oil and natural gas exploration and production company headquartered in Lafayette, Louisiana with additional offices in New Orleans, Houston and Morgantown, West Virginia. Stone is engaged in the acquisition, exploration, development and production of properties in the Gulf of Mexico and Appalachian basins.

Contact:
Jennifer E. Mercer
Epiq Strategic Communications for Stone Energy
310-712-6215
jmercer@epiqsystems.com

 

 

 

 

 

 

 

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SOURCE Stone Energy Corporation