Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - STONE ENERGY CORP | f8k022216earnings4q15.htm |
STONE ENERGY CORPORATION
Provides Fourth Quarter and Year-End 2015 Results and Reserves
LAFAYETTE, LA. February 22, 2016
Stone Energy Corporation (NYSE: SGY) today announced financial and operational results for the fourth quarter and year-end of 2015. Some of the highlights include:
• | Average daily production for the fourth quarter of 2015 was 24 MBoe per day, or 145 MMcfe per day, which was impacted by the shut-in of the Mary field in Appalachia for the entire quarter; average daily production for the year 2015 was 40 MBoe per day (238 MMcfe per day), which was within our original full year guidance range, despite the shut-in of the Mary field for four months. |
• | Estimated proved reserves as of December 31, 2015 were 57 MMBoe (342 Bcfe), which were affected by 95 MMBoe (570 Bcfe) of downward revisions into contingent resources due to depressed commodity prices (primarily in Appalachia). |
• | The Amethyst well was completed on schedule and began production in late December 2015. |
• | Drilling and completion operations are finished at the Cardona #7 well, and production is scheduled to commence in March 2016. |
Financial Results
Stone had fourth quarter 2015 adjusted net income of $2.1 million, or $0.04 per share, before pre-tax impairment charges of $351.1 million. Full year 2015 adjusted net loss was $28.6 million, or $0.52 per share, before pre-tax impairment charges of $1,362.4 million. After impairment charges, the net loss was $318.7 million for the fourth quarter of 2015, or $5.76 per share, and $1,090.9 million for the full year 2015, or $19.75 per share. The 2015 net loss compares with the 2014 net loss of $189.5 million, or $3.60 per share. The fourth quarter 2015 net loss compares with the fourth quarter 2014 net loss of $190.5 million, or $3.47 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.
Discretionary cash flow for the fourth quarter of 2015 totaled $114.6 million, compared to $90.1 million for the fourth quarter of 2014. Discretionary cash flow for 2015 totaled $351.9 million, compared to $437.8 million for 2014. 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 flow provided by operating activities.
Net daily production volumes for the fourth quarter of 2015 averaged 24 MBoe (145 MMcfe) per day, compared with net daily production of 42 MBoe (255 MMcfe) per day in the fourth quarter of 2014. Net daily production volumes for 2015 averaged 40 thousand barrels of oil equivalent (MBoe) per day (238 million cubic feet of gas equivalent (MMcfe) per day), compared with net daily production of 43 MBoe (256 MMcfe) per day in 2014. The decrease in fourth quarter and full year 2015 volumes was primarily due to the shut-in of approximately 100 MMcfe per day at the Mary field. The production mix for 2015 was 41% oil, 17% natural gas liquids (NGLs) and 42% natural gas, while the production mix for 2014 was 36% oil, 14% NGLs and 50% natural gas.
Excluding potential production from the currently shut-in Mary field (approximately 100 MMcfe per day), average daily production for the first quarter of 2016 is expected to be 32-33 MBoe (192-198 MMcfe) per day. Excluding potential production from the Mary field, production guidance for the full year 2016 is 31-33 MBoe (186-198 MMcfe) with approximately 55% projected as oil, 9% projected as natural gas liquids and 36% projected as natural gas. Please see “2016 Guidance.”
Realized prices during the fourth quarter of 2015 averaged $69.68 per Bbl of oil, $18.51 per Bbl of NGLs and $2.48 per Mcf of natural gas, compared to fourth quarter 2014 average realized prices of $83.30 per Bbl of oil, $32.28 per Bbl of NGLs and $2.89 per Mcf of natural gas. Price realizations in the fourth quarter of 2015 for oil, NGLs and natural gas benefited from the shut-in at the Mary field, since realized pricing in Appalachia has been lower than in the Gulf of Mexico. Realized prices during the year ended December 31, 2015 averaged $69.52 per barrel (Bbl) of oil, $13.46 per Bbl of NGLs and $2.29 per thousand cubic feet (Mcf) of natural gas, compared to
$92.69 per Bbl of oil, $40.51 per Bbl of NGLs and $3.51 per Mcf of natural gas realized during the year ended December 31, 2014.
All unit pricing amounts include the cash settlement of effective hedging contracts. During the fourth quarter and full year 2015, effective hedging transactions increased the average price received for natural gas by $0.91 and $0.39 per Mcf, respectively. Realized oil prices during the fourth quarter and full year 2015 were increased due to hedging by $29.33 and $22.64 per Bbl, respectively. Hedging transactions increased the average price received for natural gas during the fourth quarter 2014 by $0.03 per Mcf, and decreased the full year 2014 average price received for natural gas by $0.16 per Mcf. Realized oil prices during the fourth quarter and full year 2014 were increased due to hedging by $13.37 and $1.42 per Bbl, respectively.
In addition, for the full year of 2015, Stone realized net derivative income of approximately $8.0 million primarily related to non-qualifying natural gas hedging contracts that were designated to Gulf Coast production. After asset sales in 2014, the contracts were no longer deemed as qualifying hedges.
For the three months ended December 31, 2015 and 2014, lease operating expenses were $20.9 million ($9.42 per Boe or $1.57 per Mcfe) and $36.6 million ($9.37 per Boe or $1.56 per Mcfe), respectively. Lease operating expenses incurred during 2015 totaled $100.1 million ($6.92 per Boe or $1.15 per Mcfe), compared to $176.5 million ($11.32 per Boe or $1.89 per Mcfe) during 2014. The year-over-year decrease in lease operating expenses in 2015 from 2014 was primarily due to increased efficiencies, cost reduction efforts and the divestiture of non-core conventional shelf assets in 2014.
For the three months ended December 31, 2015 and 2014, transportation, processing and gathering expenses were $3.0 million and $19.5 million, respectively. Transportation, processing and gathering expenses during 2015 totaled $58.8 million, compared to $65.0 million during 2014. The decreases were primarily attributable to the September 1, 2015 shut-in of the Mary field in Appalachia, which remained shut-in throughout the fourth quarter 2015.
Depreciation, depletion and amortization (DD&A) expense on oil and gas properties for the three months ended December 31, 2015 totaled $54.2 million ($24.47 per Boe or $4.08 per Mcfe), compared to $83.1 million ($21.28 per Boe or $3.55 per Mcfe) during the comparable period of 2014. DD&A expense on oil and gas properties totaled $277.1 million ($19.15 per Boe or $3.19 per Mcfe) during 2015, compared to $336.0 million ($21.56 per Boe or $3.59 per Mcfe) during 2014. The decrease in DD&A from 2014 was primarily due to the ceiling test write-downs of our oil and gas properties in 2015.
Salaries, general and administrative (SG&A) expenses (excluding incentive compensation expense) for the three months ended December 31, 2015 totaled $16.4 million ($7.40 per Boe or $1.23 per Mcfe), compared to $17.2 million ($4.41 per Boe or $0.73 per Mcfe) during the comparable quarter of 2014. SG&A expenses (excluding incentive compensation expense) totaled $69.4 million ($4.80 per Boe or $0.80 per Mcfe) during 2015, compared to $66.5 million ($4.26 per Boe or $0.71 per Mcfe) during 2014. The increase in SG&A expenses in 2015 was the result of expenses associated with headcount reductions and early termination of various contracts, including office rental agreements, which totaled $5.8 million for the year.
Capital expenditures on oil and gas properties for 2015 were $464.5 million, which included $72.4 million of abandonment expenditures. This compares to capital expenditures on oil and gas properties during 2014 of $884.0 million, which included $56.4 million of abandonment expenditures. Capitalized SG&A expenses were $27.1 million and capitalized interest totaled $41.3 million for 2015. In 2014, capitalized SG&A was $30.7 million and capitalized interest totaled $45.7 million.
2016 Capital Expenditure Budget
Stone’s Board of Directors has authorized an initial 2016 capital expenditure budget of $200 million, subject to further Board review. The proposed expenditures are primarily focused on the Pompano platform rig development program and the utilization of the ENSCO 8503 deep water rig for a development well and one or two exploration wells. The budget includes minimal activity in the Appalachian basin, satisfying regulatory abandonment commitments and contractual seismic and leasehold commitments. The budget also assumes success in farming-out the ENSCO 8503 rig to another operator for 5-6 months and the reduction in our working interests on potential exploration wells to be drilled to an acceptable level or the stacking of the rig. The budget excludes acquisitions
and capitalized SG&A and interest as well as potential subsidy expense associated with a rig farm-out and potential rig stacking expense. In addition to the $200 million in budgeted capital expenditures, the farm-out subsidy and rig stacking expenses would be charges to our statement of operations as “Other operational expenses” and are projected to be approximately $40-$50 million. The 2016 budget is allocated approximately 80% to 85% to the Gulf of Mexico basin, 3% to 5% in Appalachia, and 10% to 15% to abandonment expenditures.
In the Gulf of Mexico, the budget assumes three development wells to be drilled using a platform rig on the Pompano platform. Additionally, Stone expects to use the ENSCO 8503 rig to drill and complete the Cardona #7 development well in the first quarter of 2016, followed by one or two farm-outs of the rig and the drilling of the deep water Lamprey or Derbio prospects (assuming reductions to our working interests). The Appalachia capital budget includes maintaining core leasehold interests and other maintenance operations.
The capital budget and allocation of capital across the various areas is subject to change based on several factors, including commodity pricing, liquidity, permitting times, regulatory, non-operator decisions and the sales of working interests in certain assets. The capital budget is expected to be funded primarily through the bank credit facility and expected cash flow, as well as possible financings or asset sales.
Liquidity
At December 31, 2015, Stone had cash on hand of $10.8 million and $480.8 million available for borrowing under its bank credit facility, based on a borrowing base of $500 million and outstanding letters of credit outstanding of $19.2 million. As of February 22, 2016, we had cash on hand of approximately $23 million and approximately $50 million drawn on the bank credit facility. Including the $19.2 million of letters of credit outstanding, there is approximately $431 million available for borrowing as of February 22, 2016. The borrowing base was affirmed at $500 million in October 2015 and is scheduled to be redetermined by May 2016. We are expecting a borrowing base reduction for the May 2016 redetermination.
The level of our indebtedness of approximately $1.1 billion and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. As of December 31, 2015 and February 22, 2016, we were in compliance with all of our financial covenants under our bank credit facility and indentures governing our outstanding notes. However, given the lower commodity prices and reduced hedged position, we anticipate that we could exceed the Consolidated Funded Debt to Consolidated EBITDA financial ratio covenant of 3.75 to 1 set forth in our bank credit facility at the end of the first quarter of 2016, which would require us to seek a waiver or amendment from our bank lenders. We are currently in discussions with our banks regarding an amendment to our bank credit facility to address this potential covenant issue. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it may result in an event of default and an acceleration under our other debt instruments. We do not expect to obtain an amendment from our banks before the filing of our 2015 Form 10-K.
We are actively reviewing various financings, asset sales and debt restructuring alternatives to provide additional and adequate longer term liquidity, and to address the March 1, 2017 maturity of our $300 million 2017 Convertible Notes.
Although we are currently exempt from supplemental bonding requirements on our offshore leases for abandonment obligations, we expect to lose this exemption in 2016, as suppressed commodity prices have negatively affected our net worth. If we cannot qualify for a waiver, we may need to obtain surety bonds or some other form of financial assurance, which could impact our liquidity.
We have an existing commitment for a deep water rig with ENSCO, which is projected to last until the fall of 2017. To lessen our financial exposure, we have executed a farm-out of the rig, starting in late February 2016, for a period of 60 to 90 days. We continue to pursue additional opportunities to farm-out the rig and anticipate that we may execute a second, separate farm-out agreement for another 90 to 120 days with another operator, which would immediately follow the currently scheduled farm-out. Including these projected farm-out arrangements, we expect to spend approximately $85 million on this contract in 2016 and approximately $50 million in 2017.
Reserves
Our estimated proved reserves as of December 31, 2015 were 57 MMBoe (million barrels of oil equivalent) or 342 Bcfe (billion cubic feet of natural gas equivalent), compared to 153 MMBoe (915 Bcfe) at year-end 2014. The decrease in estimated proved reserves is primarily attributable to the downward revision of 95 MMBoe (570 Bcfe) to contingent resources due to depressed commodity prices. Substantially all of Stone’s proved reserves in Appalachia were reclassified to contingent resources during 2015. From drilling additions, extensions, well performance, and the acquisition of Appalachia working interests, Stone replaced approximately 104% of 2015 production.
The year-end 2015 estimated proved reserves were 53% oil, 11% natural gas liquids (NGLs) and 36% gas on an equivalent basis. The changes from year-end 2014 estimated proved reserves to year-end 2015 estimated proved reserves included production of approximately 14 MMBoe (85 Bcfe), divestitures of 1 MMBoe (6 Bcfe), drilling additions/extensions of 1 MMBoe (7 Bcfe), acquisition of working interest in Appalachia of 6 MMBoe (34 Bcfe), positive performance revisions of 8 MMBoe (47 Bcfe) and net downward price revisions of 95 MMBoe or 570 Bcfe.
The standardized measure of discounted future net cash flows from our estimated proved reserves at December 31, 2015, using a 10% discount rate and 12-month average prices (after differentials) of $51.16 per barrel of oil, $16.40 per barrel of NGLs and $2.19 per Mcf of gas, was approximately $604 million. Estimated future income taxes had no effect on the standardized measure as of December 31, 2015. If current pricing was used to determine the estimated proved reserves or the standardized measure at December 31, 2015, the reserve volumes and values would be reduced.
The year-end 2015 estimated proved reserves included proved developed (PD) reserves of 42 MMBoe or 249 Bcfe (52% oil, 12% NGLs, 36% gas) and proved undeveloped (PUD) reserves of 15 MMBoe or 93 Bcfe (55% oil, 11% NGLs, 34% gas). In addition, there were 23 MMBoe or 139 Bcfe of estimated probable reserves and 59 MMBoe or 356 Bcfe of estimated possible reserves at year-end 2015.
All of Stone's estimated proved, probable and possible reserves and contingent resources were independently engineered by Netherland Sewell & Associates.
Operational Update
Deep Water Drilling Contract (Gulf of Mexico). In February of 2016, Stone reached an agreement with an experienced Gulf of Mexico deep water operator to farm-out and utilize the ENSCO 8503 for a period of 60 to 90 days. The agreement will carry some associated subsidy expenses and will commence late in the first quarter of 2016, after Stone has finished operations at the Cardona #7 well. Stone continues to pursue additional opportunities to farm-out the rig and is currently engaged in discussions with multiple experienced operators for potential projects, including a separate farm-out agreement for another 90 to 120 days with another operator that would immediately follow the currently scheduled farm-out. Additionally, Stone is reviewing farm-in opportunities whereby Stone would utilize the ENSCO 8503 rig as the operator with a relatively small working interest in the project.
Mississippi Canyon 29 - Cardona Field (Deep Water). The first two Cardona wells (#4 and #5) produced at a combined gross rate of approximately 10,000 Boe per day for most of 2015. Production from the Cardona #6 development well commenced in the second half of 2015 at a rate of approximately 5,000 Boe per day. The fourth and final well in the Cardona project, the Cardona #7, has been drilled and completed and is expected to be online in late March of 2016, with initial gross production expected to reach approximately 4,000 - 5,000 Boe per day. Stone holds a 65% working interest in the field and is the operator.
Mississippi Canyon 26 - Amethyst (Deep Water). The Amethyst prospect came online in late December 2015 and gross production is currently approximately 35 MMcfe per day. The reservoir pressure and rate will continue to be evaluated over the next few months for possible volume adjustments. The well is a tie-back to Stone’s Pompano platform, located less than five miles from the discovery and Stone holds a 100% working interest.
Pompano Platform Drilling Program (Deep Water). During the first week of November 2015, Stone mobilized and successfully installed an H&P platform drilling rig on its Pompano platform to begin a development drilling program, consisting of one workover project and two development wells. Stone may elect to drill up to two additional development wells based on capital availability. The workover of the A-30 well, which commenced in the first week of January 2016, has been completed and is producing approximately 250 Boe per day. Drilling has commenced on the Silverthrone development prospect and is expected to come online in late April or May of 2016. The well is expected to average daily gross production of approximately 1,400 Boe per day for the remainder of the year once online. Each additional development well is expected to provide a production increase ranging from 1,000 to 2,000 Boe per day per well, and would be brought on over the course of the program. Stone holds a 100% working interest in these wells.
Alaminos Canyon 943 - Lamprey (Deep Water). In the fourth quarter of 2015, Petróleos Mexicanos (“Pemex”) spud the Tiaras-1 exploration well, which is located approximately three miles southwest of Stone’s Lamprey exploration prospect in Alaminos Canyon block 943 in the Gulf of Mexico. The Tiaras-1 well was drilled to a total depth of approximately 15,850 feet by the end of December 2015, and the rig has remained on location since reaching total depth. Information on the results of the Tiaras-1 is expected to prove helpful in evaluating the Lamprey prospect. If a decision is made to move forward with the Lamprey prospect, it is estimated that the initial well would take two to three months to drill and, if successful, Stone may drill a follow-up appraisal well. Discussions with potential partners regarding the 100% owned Lamprey prospect are ongoing, with a reduction to Stone’s working interest expected before drilling the well.
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, which is currently projected to spud in late 2016, although a reduction to our working interest is expected before drilling commences. The well is estimated to take three months to drill.
Mississippi Canyon 117 - Rampart (Deep Water). The Rampart exploration well targets the Miocene interval and is expected to follow the Derbio exploration well. Stone currently holds 100% working interest in the prospect and is expected to reduce its working interest before drilling commences. The prospect is located nine miles from Stone’s Pompano platform and a tie-back is likely. The well is estimated to take three months to drill.
Appalachia Basin (Production and Drilling Update). In Appalachia, production averaged approximately 130 Mmcfe per day before shutting in production at the Mary Field on September, 1, 2015. Production for fourth quarter of 2015 at the Mary Field remained shut-in, and production from the Heather and Buddy fields was approximately 21 MMcfe per day. The Mary field remains shut-in due to low prices of natural gas, natural gas liquids and high midstream costs. The contracted rig for Appalachia was available for delivery late in the fourth quarter of 2015, but remains stacked. Our 2016 activity is expected to be limited to maintaining core leasehold interests and other maintenance operations.
2016 Guidance
Guidance for the first quarter and full year 2016 is shown in the table below. Guidance ranges provided below assume the Mary field in Appalachia remains shut-in for the full calendar year of 2016. Any Mary field production in 2016 would be additive to the production guidance below and expense guidance would have to be adjusted. The guidance is subject to all the cautionary statements and limitations described below and under the caption “Forward Looking Statements.”
First Quarter | Full Year | ||
Production - MBoe per day (MMcfe per day) | 32 - 33 (192 - 198) | 31 - 33 (186 - 198) | |
(excludes production from Mary field) | |||
Lease operating expenses (in millions) (excluding transportation/processing expenses) | — | $90 - 100 | |
Transportation, processing and gathering (in millions) | — | $18 - $20 | |
Salaries, General & Administrative expenses (in millions) | — | $52 - $56 | |
(excluding incentive compensation) | |||
Depreciation, Depletion & Amortization (per Boe) | — | $16.50 - $19.50 | |
(per Mcfe) | $2.75 - $3.25 | ||
Corporate Tax Rate (%) | —% | —% | |
Capital Expenditure Budget (in millions) | — | $200 | |
(excluding acquisitions, and associated | |||
expenses from rig farm-outs or rig stacking) | |||
Hedge Position
The following table illustrates our derivative positions as of February 22, 2016:
Fixed-Price Swaps | |||||||
NYMEX | |||||||
Natural Gas | Oil | ||||||
Daily Volume (MMBtus/d) | Swap Price | Daily Volume (Bbls/d) | Swap Price | ||||
2016 | 10,000 | 4.110 | 1,000 | 90.00 | |||
2016 | 10,000 | 4.120 | 1,000 | 52.78 | |||
2016 | 1,000 | 49.75 | |||||
2016 | 1,000* | 45.00-54.75 | |||||
*costless collar
Annual Meeting Information
Stone Energy will hold its 2016 Annual Meeting of Stockholders on Thursday, May 19, 2016, at 10:00 a.m. Central time at the Windsor Court Hotel, 300 Gravier Street, New Orleans, Louisiana. The close of business on March 24, 2016 has been fixed as the record date for determination of stockholders entitled to receive notification of and to vote at the Annual Meeting.
Other Information
Stone Energy has planned a conference call for 9:00 a.m. Central time on Tuesday, February 23, 2016 to discuss the operational and financial results for the fourth quarter and full year 2015. Anyone wishing to participate should visit our website at www.StoneEnergy.com for a live web cast or dial 1-877-228-3598 and request the “Stone Energy Call.” If you are unable to participate in the original conference call, a replay will be available immediately following the completion of the call on Stone Energy’s website. The replay will be available for one month.
Non-GAAP Financial Measures
In this press release, we refer to non-GAAP financial measures we call “discretionary cash flow” and “adjusted net income (loss).” 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 or loss, as defined by GAAP. Management believes adjusted net income (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 cash flow provided by operating activities and a reconciliation of adjusted net income (loss) to net loss.
Guidance Disclosure
Guidance is subject to all the cautionary statements and limitations described below and under the caption “Forward Looking Statements.” Estimates for Stone’s future production volumes are based on assumptions of capital expenditure 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. Currently production at the Mary field in Appalachia is curtailed, which affects annual production and expense guidance. The production, transportation and marketing of oil and gas are subject to disruption due to transportation and processing availability, mechanical failure, human error, hurricanes, commodity prices and numerous other factors. Stone’s estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. 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.
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 weather, the timing and extent of changes in commodity prices for oil and gas, operating risks, liquidity risks, access to capital including availability under our credit facility, 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 and Quarterly Reports on Form 10-Q as filed with the SEC. 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.
Estimates for Stone’s future production volumes are based on assumptions of capital expenditure 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.
Reserves
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions of such terms. Stone discloses only estimated proved reserves in its filings with the SEC. Stone's estimated proved, probable and possible reserves as of December 31, 2015 contained in this press release were prepared by Netherland, Sewell & Associates, Inc., a nationally recognized engineering firm, and comply with definitions promulgated by the SEC. Additional information on Stone's estimated proved reserves will be contained in Stone's Annual Report on Form 10-K.
In this press release, Stone also uses the term “contingent resources” which are volumes of resources potentially recoverable, except the volumes are deemed uneconomic at current pricing. The SEC's guidelines strictly prohibit Stone from including contingent resources in filings with the SEC. These estimates, as well as estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by Stone.
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. 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 (In thousands, except per share/unit amounts) (Unaudited) | ||||||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
FINANCIAL RESULTS | ||||||||||||||||
Net loss | $ | (318,656 | ) | $ | (190,515 | ) | $ | (1,090,915 | ) | $ | (189,543 | ) | ||||
Net loss per share | $ | (5.76 | ) | $ | (3.47 | ) | $ | (19.75 | ) | $ | (3.60 | ) | ||||
PRODUCTION QUANTITIES | ||||||||||||||||
Oil (MBbls) | 1,326 | 1,340 | 5,991 | 5,568 | ||||||||||||
Gas (MMcf) | 4,391 | 11,531 | 36,457 | 47,426 | ||||||||||||
Natural gas liquids (MBbls) | 159 | 642 | 2,401 | 2,114 | ||||||||||||
Oil, gas and NGLs (MBoe) | 2,217 | 3,904 | 14,468 | 15,586 | ||||||||||||
Oil, gas and NGLs (MMcfe) | 13,301 | 23,423 | 86,809 | 93,518 | ||||||||||||
AVERAGE DAILY PRODUCTION | ||||||||||||||||
Oil (MBbls) | 14 | 15 | 16 | 15 | ||||||||||||
Gas (MMcf) | 48 | 125 | 100 | 130 | ||||||||||||
Natural gas liquids (MBbls) | 2 | 7 | 7 | 6 | ||||||||||||
Oil, gas and NGLs (MBoe) | 24 | 42 | 40 | 43 | ||||||||||||
Oil, gas and NGLs (MMcfe) | 145 | 255 | 238 | 256 | ||||||||||||
REVENUE DATA | ||||||||||||||||
Oil revenue | $ | 92,392 | $ | 111,627 | $ | 416,497 | $ | 516,104 | ||||||||
Gas revenue | 10,898 | 33,311 | 83,509 | 166,494 | ||||||||||||
Natural gas liquids revenue | 2,943 | 20,722 | 32,322 | 85,642 | ||||||||||||
Total oil, gas and NGLs revenue | $ | 106,233 | $ | 165,660 | $ | 532,328 | $ | 768,240 | ||||||||
AVERAGE PRICES | ||||||||||||||||
Prior to the cash settlement of effective hedging transactions: | ||||||||||||||||
Oil (per Bbl) | $ | 40.35 | $ | 69.93 | $ | 46.88 | $ | 91.27 | ||||||||
Gas (per Mcf) | 1.57 | 2.86 | 1.90 | 3.67 | ||||||||||||
NGLs (per Bbl) | 18.51 | 32.28 | 13.46 | 40.51 | ||||||||||||
Oil, gas and NGLs (per Boe) | 28.56 | 37.77 | 26.43 | 49.26 | ||||||||||||
Oil, gas and NGLs (per Mcfe) | 4.76 | 6.30 | 4.40 | 8.21 | ||||||||||||
Including the cash settlement of effective hedging transactions: | ||||||||||||||||
Oil (per Bbl) | $ | 69.68 | $ | 83.30 | $ | 69.52 | $ | 92.69 | ||||||||
Gas (per Mcf) | 2.48 | 2.89 | 2.29 | 3.51 | ||||||||||||
NGLs (per Bbl) | 18.51 | 32.28 | 13.46 | 40.51 | ||||||||||||
Oil, gas and NGLs (per Boe) | 47.92 | 42.43 | 36.79 | 49.29 | ||||||||||||
Oil, gas and NGLs (per Mcfe) | 7.99 | 7.07 | 6.13 | 8.21 | ||||||||||||
AVERAGE COSTS | ||||||||||||||||
Lease operating expenses (per Boe) | $ | 9.42 | $ | 9.37 | $ | 6.92 | $ | 11.32 | ||||||||
Lease operating expenses (per Mcfe) | 1.57 | 1.56 | 1.15 | 1.89 | ||||||||||||
Transp, processing & gathering exp (per Boe) | 1.35 | 5.00 | 4.07 | 4.17 | ||||||||||||
Transp, processing & gathering exp (per Mcfe) | 0.23 | 0.83 | 0.68 | 0.69 | ||||||||||||
Salaries, general and admin expenses (per Boe) | 7.40 | 4.41 | 4.80 | 4.26 | ||||||||||||
Salaries, general and admin expenses (per Mcfe) | 1.23 | 0.73 | 0.80 | 0.71 | ||||||||||||
DD&A expense on oil and gas properties (per Boe) | 24.47 | 21.28 | 19.15 | 21.56 | ||||||||||||
DD&A expense on oil and gas properties (per Mcfe) | 4.08 | 3.55 | 3.19 | 3.59 | ||||||||||||
AVERAGE SHARES OUTSTANDING - Diluted | 55,286 | 54,868 | 55,250 | 52,721 | ||||||||||||
STONE ENERGY CORPORATION CONSOLIDATED STATEMENT OF OPERATIONS (In thousands) (Unaudited) | |||||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
Operating revenue: | |||||||||||||||
Oil production | $ | 92,392 | $ | 111,627 | $ | 416,497 | $ | 516,104 | |||||||
Natural gas production | 10,898 | 33,311 | 83,509 | 166,494 | |||||||||||
Natural gas liquids production | 2,943 | 20,722 | 32,322 | 85,642 | |||||||||||
Other operational income | 1,185 | 2,436 | 4,369 | 7,951 | |||||||||||
Derivative income, net | 3,081 | 16,684 | 7,952 | 19,351 | |||||||||||
Total operating revenue | 110,499 | 184,780 | 544,649 | 795,542 | |||||||||||
Operating expenses: | |||||||||||||||
Lease operating expenses | 20,889 | 36,577 | 100,139 | 176,495 | |||||||||||
Transportation, processing and gathering expenses | 2,996 | 19,506 | 58,847 | 64,951 | |||||||||||
Production taxes | 483 | 2,181 | 6,877 | 12,151 | |||||||||||
Depreciation, depletion and amortization | 55,379 | 84,234 | 281,688 | 340,006 | |||||||||||
Write-down of oil and gas properties | 351,062 | 304,062 | 1,362,447 | 351,192 | |||||||||||
Accretion expense | 6,673 | 6,584 | 25,988 | 28,411 | |||||||||||
Salaries, general and administrative expenses | 16,407 | 17,199 | 69,384 | 66,451 | |||||||||||
Incentive compensation expense | (1,379 | ) | 232 | 2,242 | 10,361 | ||||||||||
Other operational expenses | 748 | 352 | 2,360 | 862 | |||||||||||
Total operating expenses | 453,258 | 470,927 | 1,909,972 | 1,050,880 | |||||||||||
Loss from operations | (342,759 | ) | (286,147 | ) | (1,365,323 | ) | (255,338 | ) | |||||||
Other (income) expenses: | |||||||||||||||
Interest expense | 12,219 | 10,262 | 43,928 | 38,855 | |||||||||||
Interest income | (345 | ) | (69 | ) | (580 | ) | (574 | ) | |||||||
Other income | (616 | ) | (208 | ) | (1,783 | ) | (2,332 | ) | |||||||
Other expense | 286 | — | 434 | 274 | |||||||||||
Total other expenses | 11,544 | 9,985 | 41,999 | 36,223 | |||||||||||
Loss before income taxes | (354,303 | ) | (296,132 | ) | (1,407,322 | ) | (291,561 | ) | |||||||
Provision (benefit) for income taxes: | |||||||||||||||
Current portion | (44,096 | ) | 159 | (44,096 | ) | 159 | |||||||||
Deferred portion | 8,449 | (105,776 | ) | (272,311 | ) | (102,177 | ) | ||||||||
Total income taxes | (35,647 | ) | (105,617 | ) | (316,407 | ) | (102,018 | ) | |||||||
Net loss | $ | (318,656 | ) | $ | (190,515 | ) | $ | (1,090,915 | ) | $ | (189,543 | ) | |||
STONE ENERGY CORPORATION RECONCILIATION OF NON-GAAP FINANCIAL MEASURE DISCRETIONARY CASH FLOW to NET CASH FLOW FROM OPERATING ACTIVITIES (In thousands) (Unaudited) | ||||||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Net loss as reported | $ | (318,656 | ) | $ | (190,515 | ) | $ | (1,090,915 | ) | $ | (189,543 | ) | ||||
Reconciling items: | ||||||||||||||||
Depreciation, depletion and amortization | 55,379 | 84,234 | 281,688 | 340,006 | ||||||||||||
Deferred income tax provision (benefit) | 8,449 | (105,776 | ) | (272,311 | ) | (102,177 | ) | |||||||||
Accretion expense | 6,673 | 6,584 | 25,988 | 28,411 | ||||||||||||
Non-cash stock compensation expense | 3,161 | 2,916 | 12,324 | 11,325 | ||||||||||||
Excess tax benefits | (1,586 | ) | — | (1,586 | ) | — | ||||||||||
Write-down of oil and gas properties | 351,062 | 304,062 | 1,362,447 | 351,192 | ||||||||||||
Non-cash interest expense | 4,578 | 4,268 | 17,788 | 16,661 | ||||||||||||
Non-cash derivative expense (income) | 5,586 | (15,642 | ) | 16,440 | (18,028 | ) | ||||||||||
Discretionary cash flow | 114,646 | 90,131 | 351,863 | 437,847 | ||||||||||||
Change in current income taxes | (44,588 | ) | 164 | (37,377 | ) | 158 | ||||||||||
Settlement of asset retirement obligations | (12,556 | ) | (9,192 | ) | (72,382 | ) | (56,409 | ) | ||||||||
Other working capital changes | (9,008 | ) | (12,362 | ) | 5,370 | 19,545 | ||||||||||
Net cash provided by operating activities | $ | 48,494 | $ | 68,741 | $ | 247,474 | $ | 401,141 | ||||||||
STONE ENERGY CORPORATION RECONCILIATION OF NON-GAAP FINANCIAL MEASURE ADJUSTED NET INCOME (LOSS) to NET LOSS (In thousands) (Unaudited) | ||||||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Net loss as reported | $ | (318,656 | ) | $ | (190,515 | ) | $ | (1,090,915 | ) | $ | (189,543 | ) | ||||
Reconciling items: | ||||||||||||||||
Write-down of oil and gas properties | 351,062 | 304,062 | 1,362,447 | 351,192 | ||||||||||||
Tax effect | (116,164 | ) | (109,462 | ) | (480,263 | ) | (126,429 | ) | ||||||||
Valuation allowance on deferred tax assets | 85,827 | — | 180,121 | — | ||||||||||||
Total reconciling items | 320,725 | 194,600 | 1,062,305 | 224,763 | ||||||||||||
Adjusted net income (loss) | $ | 2,069 | $ | 4,085 | $ | (28,610 | ) | $ | 35,220 | |||||||
Net loss per share as reported | $ | (5.76 | ) | $ | (3.47 | ) | $ | (19.75 | ) | $ | (3.60 | ) | ||||
Per share effect of reconciling items | $ | 5.80 | $ | 3.54 | $ | 19.23 | $ | 4.25 | ||||||||
Net income (loss) per share before reconciling items | $ | 0.04 | $ | 0.07 | $ | (0.52 | ) | $ | 0.65 | |||||||
STONE ENERGY CORPORATION CONSOLIDATED BALANCE SHEET (In thousands) (Unaudited) | ||||||||
December 31, | December 31, | |||||||
2015 | 2014 | |||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 10,759 | $ | 74,488 | ||||
Restricted cash | — | 177,647 | ||||||
Accounts receivable | 48,031 | 120,359 | ||||||
Fair value of derivative contracts | 38,576 | 139,179 | ||||||
Current income tax receivable | 46,174 | 7,212 | ||||||
Inventory | 535 | 3,709 | ||||||
Other current assets | 6,346 | 8,118 | ||||||
Total current assets | 150,421 | 530,712 | ||||||
Oil and gas properties, full cost method of accounting: | ||||||||
Proved | 9,375,898 | 8,817,268 | ||||||
Less: accumulated depreciation, depletion and amortization | (8,603,955 | ) | (6,970,631 | ) | ||||
Net proved oil and gas properties | 771,943 | 1,846,637 | ||||||
Unevaluated | 440,043 | 567,365 | ||||||
Other property and equipment, net | 29,289 | 32,340 | ||||||
Fair value of derivative contracts | — | 14,333 | ||||||
Other assets, net | 18,473 | 18,470 | ||||||
Total assets | $ | 1,410,169 | $ | 3,009,857 | ||||
Liabilities and Stockholders’ Equity | ||||||||
Current liabilities: | ||||||||
Accounts payable to vendors | $ | 82,207 | $ | 132,629 | ||||
Undistributed oil and gas proceeds | 5,992 | 23,232 | ||||||
Accrued interest | 9,022 | 9,022 | ||||||
Deferred taxes | — | 20,119 | ||||||
Asset retirement obligations | 21,291 | 69,400 | ||||||
Other current liabilities | 40,712 | 49,505 | ||||||
Total current liabilities | 159,224 | 303,907 | ||||||
7½% Senior Notes due 2022 | 770,009 | 769,490 | ||||||
1¾% Convertible Notes due 2017 | 279,244 | 262,791 | ||||||
4.2% Building Loan | 11,702 | — | ||||||
Deferred taxes | — | 286,343 | ||||||
Asset retirement obligations | 204,575 | 247,009 | ||||||
Other long-term liabilities | 25,204 | 38,714 | ||||||
Total liabilities | 1,449,958 | 1,908,254 | ||||||
Common stock | 553 | 549 | ||||||
Treasury stock | (860 | ) | (860 | ) | ||||
Additional paid-in capital | 1,648,189 | 1,633,307 | ||||||
Accumulated deficit | (1,705,623 | ) | (614,708 | ) | ||||
Accumulated other comprehensive income | 17,952 | 83,315 | ||||||
Total stockholders’ equity | (39,789 | ) | 1,101,603 | |||||
Total liabilities and stockholders’ equity | $ | 1,410,169 | $ | 3,009,857 | ||||