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21.02.2018 22:15:00
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SandRidge Energy, Inc. Reports Financial and Operational Results for Fourth Quarter and Full Year of 2017
OKLAHOMA CITY, Feb. 21, 2018 /PRNewswire/ -- SandRidge Energy, Inc. (the "Company" or "SandRidge") (NYSE:SD) today announced financial and operational results for the quarter and fiscal year ended December 31, 2017. Additionally, the Company will host a conference call to discuss these results on February 22, at 8:00 a.m. CT (833-245-9650, International: 647-689-4222 – passcode: 4489951). Presentation slides will be available on the Company's website, www.sandridgeenergy.com, under Investor Relations/Presentations & Events.
Highlights During 2017 Include:
Net Income of $47 Million and Adjusted Net Income of $52 Million for 2017
EBITDA of $175 Million and Adjusted EBITDA of $193 Million for 2017
Proved Reserves at Year End 2017 of 178 MMBoe with 17% Increase in Proved Oil Reserves Over Year End 2016
SEC Total Proved PV-10 of $749 Million ($835 Million Using Year End Strip Pricing), 71% Increase Over Year End 2016
Production of 14.9 MMBoe at High End of Guidance for 2017
Oil Production Increase of 73 MBo or 8% in Fourth Quarter 2017 Over Third Quarter 2017
Bill Griffin, President and CEO said, "SandRidge enters 2018 with a revised strategy and strong platform for economic growth. I step into this role with a full and determined commitment to work diligently with our veteran, senior executive team to quickly implement the announced G&A reductions, while maintaining core competencies and shifting organizational focus. 2017 was a year of solid operating performance, delivering within, or exceeding our production and cost guidance. Importantly, the NPV-10 of our total proved reserve base increased to $835 million when utilizing year-end strip pricing. SandRidge has tremendous potential moving forward. We are taking steps for meaningful improvements in our cash flow margins and we have a significant undeveloped acreage position and prospect inventory. These facts, in combination with a strong and clean balance sheet, give us significant optionality to capture the most attractive opportunities and create meaningful value."
Financial Results
Fourth Quarter
For the fourth quarter, the Company reported a net loss of $19 million, or $0.54 per share, and net cash provided by operating activities of $33 million. When adjusting these reported amounts for items that are typically excluded by the investment community on the basis that such items affect the comparability of results, the Company's "adjusted net income" amounted to $12 million, or $0.34 per share, and "operating cash flow" totaled $41 million. Earnings before interest, income taxes, depreciation, depletion, and amortization, adjusted for certain other items, otherwise referred to as "adjusted EBITDA," for the fourth quarter was $49 million.(1)
Full Year
For the full year of 2017, the Company reported net income of $47 million, or $1.44 per share, and net cash provided by operating activities of $181 million. Adjusted net income amounted to $52 million, or $1.61 per share, and operating cash flow totaled $183 million. Adjusted EBITDA for the full year was $193 million. (1)
1) The Company has defined and reconciled certain non-GAAP financial measures including adjusted net income, operating cash flow, EBITDA, adjusted EBITDA, PV-10 and adjusted G&A expense and current net debt, to the most directly comparable GAAP financial measures in supporting tables at the conclusion of this press release under the "Non-GAAP Financial Measures" beginning on page 15. |
Liquidity & Capital Structure
As of February 15, 2018, the Company's total liquidity was $496 million, which includes $78 million of cash and $418 million capacity under the credit facility, net of outstanding letters of credit.
The Company currently has no funds drawn under its credit facility and has provided notice that it intends to repay in full its $38 million building note on February 24, 2018. Interest on the building note is scheduled to increase from 8% to 10% in October 2018. Following repayment of the building note, the Company will have no outstanding long-term debt.
Hedging
For 2018, 86% of the Company's expected liquids production is hedged (at the midpoint of guidance) using derivative instruments for approximately 3.8 million barrels of oil at an average NYMEX WTI price of $55.75. In light of the high correlation between NGL and NYMEX WTI prices, the Company manages a portion of its NGL price exposure using NYMEX WTI contracts at a three-to-one (3:1) NGL to crude ratio. For 2018, the Company also has approximately 17.3 billion cubic feet of natural gas (54% of the midpoint of our guidance) hedged at an average price of $3.16 per MMBtu. For 2019, the Company has approximately 1.8 million barrels of oil hedged at an average WTI price of $54.29.
Operational Results and Activity
Production totaled 3.5 MMBoe (29% oil, 22% NGLs and 49% natural gas) for the fourth quarter, and 14.9 MMBoe for the full year of 2017, at the high end of guidance (14.2-14.9 MMBoe). Oil production grew 8% during the fourth quarter to 1,027 MBo from 954 MBo in the third quarter. The Company averaged two rigs in the NW STACK targeting the Meramec and one rig targeting multiple benches of the Niobrara in the North Park Basin during the quarter. Capital expenditures were $80 million during the quarter, bringing the total for the year to $248 million (excluding acquisitions) compared to 2017 guidance of $250-260 million.
Mid-Continent Assets in Oklahoma and Kansas
In the fourth quarter, production in the Mid-Continent totaled 3.2 MMBoe (23% oil). The Company averaged two rigs in the NW STACK targeting the Meramec and drilled three wells (two SRLs and one XRL). Of the three wells drilled, two were under the previously announced Drilling Participation Agreement. The Company brought eight wells online (six SRLs and two XRLs), and the wells with available 30-Day IPs averaged 565 Boepd (72% oil) for SRLs and 770 Boepd (73% oil) for XRLs.
In 2017, the Company drilled eight XRLs and nine SRLs in the NW STACK targeting the Meramec with one to two rigs. Of the 17 wells drilled, three were under the Drilling Participation Agreement that primarily covers Major and Woodward counties. Drilling and completion costs for SRLs and XRLs are currently $4.4 million and $6.5 million, respectively.
Niobrara Asset in North Park Basin, Jackson County, Colorado
Oil production in the North Park Basin totaled 201 MBo for the fourth quarter. During the quarter, the Company averaged one rig targeting multiple benches in the Niobrara, drilled three XRLs and brought three XRLs online. Two of the XRLs brought online had available 30-Day IPs averaging 1,109 Boepd (91% oil).
In 2017, the Company drilled eight XRLs and brought five wells to sales with one rig in North Park, confirming all four Niobrara benches (A, B, C and D) productive. Commercial productivity was confirmed in the B, C and D benches, while further determination of the A bench commerciality is ongoing. The Company has drilled the first four wells of an eight well spacing test, evaluating the B, C and D benches in a wine rack configuration. The Company will drill the remaining four wells of the test during the second quarter of 2018.
Other Operational Activities
During the fourth quarter, Permian Central Basin Platform properties produced 119 MBoe (1.3 MBoepd, 81% oil, 12% NGLs, 7% natural gas).
Year End 2017 Estimated Proved Reserves
The Company's total estimated SEC proved reserves as of December 31, 2017 were 178 MMBoe, an increase of 8% year over year. Reserves increased due to reserve additions and pricing revisions, with a 130% reserve replacement ratio (excluding pricing adjustments). SEC proved reserves PV-10 was $749 million, an increase of 71% year over year. SEC pricing used in the preparation of the December 31, 2017 reserves was $51.34 per Bbl for oil and $2.98 per MMBtu for natural gas, before adjustments.
For comparative purposes, utilizing NYMEX forward closing prices for oil and natural gas on December 29, 2017 (the last trading day of 2017), total NYMEX strip-based proved reserves at December 31, 2017 were 181 MMBoe, with a PV-10 of $835 million. NYMEX strip-based proved reserves are calculated based on the SEC proved reserves estimation methodology, but applying NYMEX strip prices rather than SEC pricing. NYMEX strip-based PV-10 uses annual average prices for oil and natural gas shown in the NYMEX Strip Pricing table below.
Oil MBbls | NGLs MBbls | Gas MMcf | Equivalent | Standardized | |||||||||||||
Proved Reserves, December 31, 2016 | 52,884 | 33,607 | 464,782 | 163,955 | $ | 438 | |||||||||||
Revisions | 804 | 2,628 | 44,679 | 10,879 | |||||||||||||
Purchases | 18 | 70 | 683 | 202 | |||||||||||||
Extensions & Additions | 12,446 | 1,914 | 30,080 | 19,373 | |||||||||||||
Sales of Assets | (204) | (529) | (7,055) | (1,909) | |||||||||||||
Production | (4,157) | (3,376) | (44,237) | (14,906) | |||||||||||||
Proved Reserves, December 31, 2017 | 61,791 | 34,314 | 488,932 | 177,594 | $ | 749 | |||||||||||
1) Equivalent Boe are calculated using an energy equivalent ratio of six Mcf of natural gas to one Bbl of oil. Using an energy-equivalent ratio does not factor in price differences and energy-equivalent prices may differ significantly among produced products. | ||||||||||||||||
SEC Proved Reserves and NYMEX Strip-Based Proved Reserves
YE 2017@SEC Pricing1 | YE 2017@ NYMEX Strip Pricing2 | |||||||||
Equivalent MBoe | Standardized | Equivalent MBoe | PV-10 $MM | |||||||
Developed | 123,765 | $574 | 126,675 | $630 | ||||||
Undeveloped | 53,829 | $175 | 53,905 | $206 | ||||||
Total Proved | 177,594 | $749 | 180,580 | $835 | ||||||
1) SEC Pricing remains flat for reserve life at $51.34/Bo & $2.98/MMBtu | ||||||||||
2) NYMEX Strip pricing as of December 29, 2017, shown in table below | ||||||||||
NYMEX Strip Pricing (as of 12/29/2017) | ||||
Year | Oil | Gas | ||
2017 | $50.96 | $3.11 | ||
2018 | $59.40 | $2.83 | ||
2019 | $55.94 | $2.81 | ||
2020 | $53.60 | $2.82 | ||
2021 | $52.20 | $2.85 | ||
2022 | $51.66 | $2.89 | ||
2023+ | $52.44 | $3.08 | ||
2018 Operational and Capital Expenditure Guidance
The Company is currently running one drilling rig in the NW STACK under its Drilling Participation Agreement as well as one rig in the North Park Basin. Capital allocation opportunities based on total return are also under review to exploit high-graded Mississippian Lime locations. The 2018 capital expenditure guidance range is $180 - $190 million. As previously announced, the Company is in the process of instituting changes in its organizational structure to efficiently execute its strategic objectives. These changes are expected to reduce ongoing G&A cash expenses by one-third to $36 - $39 million per year. At these new levels of expense, G&A cash expenses will have been cut by more than half since the Company's emergence from bankruptcy in October 2016. Production and other operational guidance detail for the full year of 2018 can be found below.
Guidance | ||
Projection as of | ||
February 21, 2018 | ||
Production | ||
Oil (MMBbls) | 3.4 - 3.6 | |
Natural Gas Liquids (MMBbls) | 2.6 - 2.8 | |
Total Liquids (MMBbls) | 6.0 - 6.4 | |
Natural Gas (Bcf) | 31.5 - 33.0 | |
Total (MMBoe) | 11.3 - 11.9 | |
Price Realization | ||
Oil (per Bbl) | $2.80 | |
Natural Gas Liquids (realized % of NYMEX WTI) | 33% | |
Natural Gas (per MMBtu) | $1.20 | |
Expenses | ||
LOE | $95 - $105 million | |
Adjusted G&A Expense1 | $41 - $44 million | |
% of Revenue | ||
Production Taxes | 4.80% | |
Capital Expenditures ($ in millions) | ||
Drilling and Completion | ||
Mid-Continent | $6 - $8 | |
North Park Basin | 76 - 84 | |
Other2 | 34 | |
Total Drilling and Completion | $116 - $126 | |
Other E&P | ||
Land, G&G, and Seismic | $15 | |
Infrastructure3 | 15 | |
Workover | 25 | |
Capitalized G&A and Interest | 8 | |
Total Other Exploration and Production | $63 | |
General Corporate | 1 | |
Total Capital Expenditures | $180 - $190 | |
(excluding acquisitions and plugging and abandonment) | ||
1) | Adjusted G&A expense is a non-GAAP financial measure. The Company has defined this measure at the conclusion of this press release under "Non-GAAP Financial Measures" beginning on page 15. Information to reconcile this non-GAAP financial measure to the most directly comparable GAAP financial measure is not available at this time, as management is unable to forecast the excluded items for future periods. |
2) | Primarily 2017 Carryover |
3) | Includes Production facilities, Pipeline ROW and Electrical |
2017 Actual Results vs. 2017 Capital Expenditure and Operational Guidance
The table below presents the actual results of the Company's operations and capital expenditures for the full year of 2017 in comparison to its previous guidance, provided on November 1, 2017.
FY 2017 Actuals | FY 2017 | Delta | |||||||||||||
Production | |||||||||||||||
Oil (MMBbls) | 4.2 | 4.2 | 0.0 | ||||||||||||
Natural Gas Liquids (MMBbls) | 3.4 | 3.2 | 0.2 | ||||||||||||
Total Liquids (MMBbls) | 7.6 | 7.4 | 0.2 | ||||||||||||
Natural Gas (Bcf) | 44.2 | 42.8 | 1.5 | ||||||||||||
Total (MMBoe) | 14.9 | 14.5 | 0.4 | ||||||||||||
Cost per Boe | |||||||||||||||
LOE | $6.89 | $7.08 | (0.19) | ||||||||||||
Adjusted G&A Expense1 | $3.72 | $4.10 | (0.38) | ||||||||||||
Capital Expenditures ($ in Millions) | |||||||||||||||
Drilling and Completion | |||||||||||||||
Mid-Continent | $ | 66 | $ | 63 | $ | 3 | |||||||||
North Park Basin | 56 | 63 | (6) | ||||||||||||
Other2 | 22 | 20 | 2 | ||||||||||||
Total Drilling and Completion | 144 | 145 | (1) | ||||||||||||
Other E&P | |||||||||||||||
Land, G&G, and Seismic | 48 | 46 | 2 | ||||||||||||
Infrastructure3 | 15 | 18 | (3) | ||||||||||||
Workovers | 28 | 30 | (2) | ||||||||||||
Capitalized G&A and Interest | 12 | 14 | (2) | ||||||||||||
Total Other Exploration and Production | 102 | 108 | (6) | ||||||||||||
General Corporate | 1 | 2 | (1) | ||||||||||||
Total Capital Expenditures (excluding acquisitions and plugging and abandonment) | $ | 248 | $ | 255 | $ | (7) | |||||||||
1) Adjusted G&A expense is a non-GAAP financial measure. The Company has defined this measure at the conclusion of this press release under the "Non-GAAP Financial Measures" beginning on page 15. Information to reconcile this non-GAAP financial measure to the most directly comparable GAAP financial measure is not available at this time, as management is unable to forecast the excluded items for future periods. | |||||||||||||||
2) 2016 Carryover, Coring, Non-Op and SWD | |||||||||||||||
3) Includes Production facilities, Pipeline ROW and Electrical | |||||||||||||||
Operational and Financial Statistics
Upon emergence from Chapter 11 reorganization on October 4, 2016, the Company elected to adopt fresh start accounting effective October 1, 2016. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the financial statements on or after October 1, 2016 are not comparable with the financial statements prior to that date. References to the "Successor" refer to SandRidge subsequent to adoption of fresh start accounting. References to the "Predecessor" refer to SandRidge prior to adoption of fresh start accounting.
Information regarding the Company's production, pricing, costs and earnings is presented below:
Successor | Successor | Predecessor | ||||||||||||||||||
Three Months | Year Ended | Combined | Period from | Period from | ||||||||||||||||
December 31, 2017 | ||||||||||||||||||||
Production - Total | ||||||||||||||||||||
Oil (MBbl) | 1,027 | 4,157 | 5,529 | 1,214 | 4,315 | |||||||||||||||
NGL (MBbl) | 775 | 3,376 | 4,357 | 999 | 3,358 | |||||||||||||||
Natural Gas (MMcf) | 10,354 | 44,237 | 56,895 | 12,771 | 44,124 | |||||||||||||||
Oil equivalent (MBoe) | 3,528 | 14,906 | 19,369 | — | 4,342 | 15,027 | ||||||||||||||
Daily production (MBoed) | 38.3 | 40.8 | 52.9 | 47.2 | 54.8 | |||||||||||||||
Average price per unit | ||||||||||||||||||||
Realized oil price per barrel - as reported | $ | 53.31 | $ | 48.72 | $ | 39.09 | $ | 47.03 | $ | 36.85 | ||||||||||
Realized impact of derivatives per barrel | (2.54) | 1.03 | 12.74 | 7.56 | 14.20 | |||||||||||||||
Net realized price per barrel | $ | 50.77 | $ | 49.75 | $ | 51.83 | $ | 54.59 | $ | 51.05 | ||||||||||
Realized NGL price per barrel - as reported | $ | 23.69 | $ | 18.16 | $ | 13.15 | $ | 14.77 | $ | 12.67 | ||||||||||
Realized impact of derivatives per barrel | — | — | — | — | — | |||||||||||||||
Net realized price per barrel | $ | 23.69 | $ | 18.16 | $ | 13.15 | $ | 14.77 | $ | 12.67 | ||||||||||
Realized natural gas price per Mcf - as reported | $ | 1.92 | $ | 2.09 | $ | 1.84 | $ | 2.07 | $ | 1.78 | ||||||||||
Realized impact of derivatives per Mcf | 0.21 | 0.06 | (0.03) | (0.11) | (0.01) | |||||||||||||||
Net realized price per Mcf | $ | 2.13 | $ | 2.15 | $ | 1.81 | $ | 1.96 | $ | 1.77 | ||||||||||
Realized price per Boe - as reported | $ | 26.35 | $ | 23.90 | $ | 19.53 | $ | 22.64 | $ | 18.63 | ||||||||||
Net realized price per Boe - including impact of derivatives | $ | 26.23 | $ | 24.38 | $ | 23.08 | $ | 24.41 | $ | 22.70 | ||||||||||
Average cost per Boe | ||||||||||||||||||||
Lease operating (1) | $ | 7.29 | $ | 6.89 | $ | 7.98 | $ | 5.76 | $ | 8.63 | ||||||||||
Production taxes | $ | 1.19 | $ | 0.92 | $ | 0.45 | $ | 0.61 | $ | 0.41 | ||||||||||
Depletion (2) | $ | 8.66 | $ | 7.92 | $ | 6.56 | $ | 8.31 | $ | 6.05 | ||||||||||
Earnings per share | ||||||||||||||||||||
(Loss) earnings per share applicable to common stockholders | ||||||||||||||||||||
Basic | $ | (0.54) | $ | 1.45 | $ | (17.61) | $ | 2.01 | ||||||||||||
Diluted | $ | (0.54) | $ | 1.44 | $ | (17.61) | $ | 2.01 | ||||||||||||
Adjusted net income (loss) per share available to common stockholders | ||||||||||||||||||||
Basic | $ | 0.34 | $ | 1.62 | $ | 1.53 | $ | (0.13) | ||||||||||||
Diluted | $ | 0.34 | $ | 1.61 | $ | 0.86 | $ | (0.13) | ||||||||||||
Weighted average number of shares outstanding (in thousands) | ||||||||||||||||||||
Basic | 34,494 | 32,442 | 18,967 | 708,928 | ||||||||||||||||
Diluted (3) | 34,547 | 32,663 | 33,573 | 708,928 | ||||||||||||||||
(1) | Transportation costs are presented as a reduction of revenue by the Successor Company compared to the Predecessor Company's presentation of these costs as lease operating expenses. |
(2) | Includes accretion of asset retirement obligation. |
(3) | Includes shares considered antidilutive for calculating loss per share in accordance with GAAP. |
Capital Expenditures
The table below presents actual results of the Company's capital expenditures for the three months and full year periods ended December 31, 2017 at the same level of detail as its full year capital expenditure guidance.
Three Months Ended | Year Ended | ||||||
December 31, 2017 | December 31, 2017 | ||||||
(In thousands) | (In thousands) | ||||||
Drilling and Completion | |||||||
Mid-Continent | $ | 18,312 | $ | 65,959 | |||
North Park Basin | 31,449 | 56,230 | |||||
Other1 | 3,870 | 22,245 | |||||
Total Drilling and Completion | 53,631 | 144,435 | |||||
Other E&P | |||||||
Land, G&G, and Seismic | 7,718 | 47,633 | |||||
Infrastructure2 | 9,970 | 14,759 | |||||
Workovers | 6,241 | 27,908 | |||||
Capitalized G&A and Interest | 2,748 | 12,151 | |||||
Total Other Exploration and Production | 26,677 | 102,452 | |||||
General Corporate | (49) | 1,358 | |||||
Total Capital Expenditures | $ | 80,260 | $ | 248,244 | |||
(excluding acquisitions and plugging and abandonment) | |||||||
1) 2016 Carryover, Coring, Non-Op and SWD | |||||||
2) Infrastructure - Production facilities, Pipeline ROW and Electrical |
Derivative Contracts
The table below sets forth the Company's consolidated oil and natural gas price swaps for 2018 and 2019 as of February 21, 2018:
Quarter Ending | ||||||||||
3/31/2018 | 6/30/2018 | 9/30/2018 | 12/31/2018 | FY 2018 | ||||||
WTI Swaps: | ||||||||||
Total Volume (MMBbls) | 1.05 | 1.00 | 0.92 | 0.83 | 3.80 | |||||
Daily Volume (MBblspd) | 11.7 | 11.0 | 10.0 | 9.0 | 10.4 | |||||
Swap Price ($/bbl) | $55.46 | $55.50 | $56.04 | $56.12 | $55.75 | |||||
Natural Gas Swaps: | ||||||||||
Total Volume (Bcf) | 6.30 | 3.64 | 3.68 | 3.68 | 17.30 | |||||
Daily Volume (MMBtupd) | 70.0 | 40.0 | 40.0 | 40.0 | 47.4 | |||||
Swap Price ($/MMBtu) | $3.24 | $3.11 | $3.11 | $3.11 | $3.16 | |||||
3/31/2019 | 6/30/2019 | 9/30/2019 | 12/31/2019 | FY 2019 | ||||||
WTI Swaps: | ||||||||||
Total Volume (MMBbls) | 0.45 | 0.46 | 0.46 | 0.46 | 1.83 | |||||
Daily Volume (MBblspd) | 5.0 | 5.0 | 5.0 | 5.0 | 5.0 | |||||
Swap Price ($/bbl) | $54.29 | $54.29 | $54.29 | $54.29 | $54.29 | |||||
Capitalization
The Company's capital structure as of December 31, 2017 and December 31, 2016 is presented below:
December 31, | December 31, | ||||||
2017 | 2016 | ||||||
(In thousands) | |||||||
Cash, cash equivalents and restricted cash | $ | 101,308 | $ | 174,071 | |||
Credit facility | $ | — | $ | — | |||
Building note | 37,502 | 36,528 | |||||
Mandatorily convertible 0% notes | — | 268,780 | |||||
Total debt | 37,502 | 305,308 | |||||
Stockholders' equity | |||||||
Common stock | 36 | 20 | |||||
Warrants | 88,500 | 88,381 | |||||
Additional paid-in capital | 1,038,324 | 758,498 | |||||
Accumulated deficit | (286,920) | (333,982) | |||||
Total SandRidge Energy, Inc. stockholders' equity | 839,940 | 512,917 | |||||
Total capitalization | $ | 877,442 | $ | 818,225 | |||
SandRidge Energy, Inc. and Subsidiaries Condensed Consolidated Statements of Operations | ||||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Successor | Predecessor | |||||||||||||||
Year Ended | Period from | Period from | Year Ended | |||||||||||||
Revenues | ||||||||||||||||
Oil, natural gas and NGL | $ | 356,210 | $ | 98,307 | $ | 279,971 | $ | 707,434 | ||||||||
Other | 1,089 | 149 | 13,838 | 61,275 | ||||||||||||
Total revenues | 357,299 | 98,456 | 293,809 | 768,709 | ||||||||||||
Expenses | ||||||||||||||||
Production | 102,728 | 24,997 | 129,608 | 308,701 | ||||||||||||
Production taxes | 13,644 | 2,643 | 6,107 | 15,440 | ||||||||||||
Depreciation and depletion—oil and natural gas | 118,035 | 36,061 | 90,978 | 324,390 | ||||||||||||
Depreciation and amortization—other | 13,852 | 3,922 | 21,323 | 47,382 | ||||||||||||
Impairment | 4,019 | 319,087 | 718,194 | 4,534,689 | ||||||||||||
General and administrative | 76,024 | 9,837 | 116,091 | 137,715 | ||||||||||||
Terminated merger costs | 8,162 | — | — | — | ||||||||||||
Employee termination benefits | 4,815 | 12,334 | 18,356 | 12,451 | ||||||||||||
(Gain) loss on derivative contracts | (24,090) | 25,652 | 4,823 | (73,061) | ||||||||||||
Loss on settlement of contract | — | — | 90,184 | 50,976 | ||||||||||||
Other operating expenses | 479 | 268 | 4,348 | 52,704 | ||||||||||||
Total expenses | 317,668 | 434,801 | 1,200,012 | 5,411,387 | ||||||||||||
Income (loss) from operations | 39,631 | (336,345) | (906,203) | (4,642,678) | ||||||||||||
Other (expense) income | ||||||||||||||||
Interest expense | (3,868) | (372) | (126,099) | (321,421) | ||||||||||||
Gain on extinguishment of debt | — | — | 41,179 | 641,131 | ||||||||||||
Gain on reorganization items, net | — | — | 2,430,599 | — | ||||||||||||
Other income, net | 2,550 | 2,744 | 1,332 | 2,040 | ||||||||||||
Total other (expense) income | (1,318) | 2,372 | 2,347,011 | 321,750 | ||||||||||||
Income (loss) before income taxes | 38,313 | (333,973) | 1,440,808 | (4,320,928) | ||||||||||||
Income tax (benefit) expense | (8,749) | 9 | 11 | 123 | ||||||||||||
Net income (loss) | 47,062 | (333,982) | 1,440,797 | (4,321,051) | ||||||||||||
Less: net loss attributable to noncontrolling interest | — | — | — | (623,506) | ||||||||||||
Net income (loss) attributable to SandRidge Energy, Inc. | 47,062 | (333,982) | 1,440,797 | (3,697,545) | ||||||||||||
Preferred stock dividends | — | — | 16,321 | 37,950 | ||||||||||||
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders | $ | 47,062 | $ | (333,982) | $ | 1,424,476 | $ | (3,735,495) | ||||||||
Earnings (loss) per share | ||||||||||||||||
Basic | $ | 1.45 | $ | (17.61) | $ | 2.01 | $ | (7.16) | ||||||||
Diluted | $ | 1.44 | $ | (17.61) | $ | 2.01 | $ | (7.16) | ||||||||
Weighted average number of common shares outstanding | ||||||||||||||||
Basic | 32,442 | 18,967 | 708,928 | 521,936 | ||||||||||||
Diluted | 32,663 | 18,967 | 708,928 | 521,936 | ||||||||||||
SandRidge Energy, Inc. and Subsidiaries Condensed Consolidated Balance Sheets | |||||||
(In thousands) | |||||||
December 31, | December 31, | ||||||
2017 | 2016 | ||||||
ASSETS | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | 99,143 | $ | 121,231 | |||
Restricted cash - collateral | — | 50,000 | |||||
Restricted cash - other | 2,165 | 2,840 | |||||
Accounts receivable, net | 71,277 | 74,097 | |||||
Derivative contracts | 1,310 | — | |||||
Prepaid expenses | 5,248 | 5,375 | |||||
Other current assets | 15,954 | 3,633 | |||||
Total current assets | 195,097 | 257,176 | |||||
Oil and natural gas properties, using full cost method of accounting | |||||||
Proved (includes development and project costs excluded from amortization of $16.7 million at December 31, 2016) | 1,056,806 | 840,201 | |||||
Unproved | 100,884 | 74,937 | |||||
Less: accumulated depreciation, depletion and impairment | (460,431) | (353,030) | |||||
697,259 | 562,108 | ||||||
Other property, plant and equipment, net | 225,981 | 255,824 | |||||
Other assets | 1,290 | 6,284 | |||||
Total assets | $ | 1,119,627 | $ | 1,081,392 | |||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current liabilities | |||||||
Accounts payable and accrued expenses | $ | 139,155 | $ | 116,517 | |||
Derivative contracts | 10,627 | 27,538 | |||||
Asset retirement obligations | 41,017 | 66,154 | |||||
Other current liabilities | 8,115 | 3,497 | |||||
Total current liabilities | 198,914 | 213,706 | |||||
Long-term debt | 37,502 | 305,308 | |||||
Derivative contracts | 3,568 | 2,176 | |||||
Asset retirement obligations | 36,527 | 40,327 | |||||
Other long-term obligations | 3,176 | 6,958 | |||||
Total liabilities | 279,687 | 568,475 | |||||
Commitments and contingencies (Note 15) | |||||||
Stockholders' Equity | |||||||
Common stock, $0.001 par value; 250,000 shares authorized; 35,650 issued and outstanding at December 31, 2017 and 21,042 issued and 19,635 outstanding at December 31, 2016 | 36 | 20 | |||||
Warrants | 88,500 | 88,381 | |||||
Additional paid-in capital | 1,038,324 | 758,498 | |||||
Accumulated deficit | (286,920) | (333,982) | |||||
Total stockholders' equity | 839,940 | 512,917 | |||||
Total liabilities and stockholders' equity | $ | 1,119,627 | $ | 1,081,392 | |||
SandRidge Energy, Inc. and Subsidiaries Condensed Consolidated Cash Flows | ||||||||||||||||
(In thousands) | ||||||||||||||||
Successor | Predecessor | |||||||||||||||
Year Ended | Period from | Period from | Year Ended | |||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||||
Net income (loss) | $ | 47,062 | $ | (333,982) | $ | 1,440,797 | $ | (4,321,051) | ||||||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities | ||||||||||||||||
Provision for doubtful accounts | 406 | (13,166) | 16,704 | — | ||||||||||||
Depreciation, depletion and amortization | 131,887 | 39,983 | 112,301 | 371,772 | ||||||||||||
Impairment | 4,019 | 319,087 | 718,194 | 4,534,689 | ||||||||||||
Gain on reorganization items, net | — | — | (2,442,436) | — | ||||||||||||
Debt issuance costs amortization | 430 | — | 4,996 | 11,884 | ||||||||||||
Amortization of discount, net of premium, on debt | (330) | (81) | 2,734 | 3,130 | ||||||||||||
Gain on extinguishment of debt | — | — | (41,179) | (641,131) | ||||||||||||
Write off of debt issuance costs | — | — | — | 7,108 | ||||||||||||
(Gain) loss on debt derivatives | — | — | (1,324) | 10,377 | ||||||||||||
Cash paid for early conversion of convertible notes | — | — | (33,452) | (32,741) | ||||||||||||
(Gain) loss on derivative contracts | (24,090) | 25,652 | 4,823 | (73,061) | ||||||||||||
Cash received on settlement of derivative contracts | 7,260 | 7,698 | 72,608 | 327,702 | ||||||||||||
Loss on settlement of contract | — | — | 90,184 | 50,976 | ||||||||||||
Cash paid on settlement of contract | — | — | (11,000) | (24,889) | ||||||||||||
Stock-based compensation | 15,750 | 6,250 | 9,075 | 18,380 | ||||||||||||
Other | 344 | 717 | (3,260) | 2,842 | ||||||||||||
Changes in operating assets and liabilities increasing (decreasing) cash | ||||||||||||||||
Deconsolidation of noncontrolling interest | — | — | (9,654) | — | ||||||||||||
Receivables | 115 | 12,872 | 36,116 | 201,907 | ||||||||||||
Prepaid expenses | 127 | (1,079) | (5,681) | 1,148 | ||||||||||||
Other current assets | 191 | (260) | (181) | 12,710 | ||||||||||||
Other assets and liabilities, net | 4,186 | 1,505 | (7,542) | 2,239 | ||||||||||||
Accounts payable and accrued expenses | (2,199) | 990 | (3,595) | (86,470) | ||||||||||||
Asset retirement obligations | (3,979) | (591) | (61,305) | (3,984) | ||||||||||||
Net cash provided by (used in) operating activities | 181,179 | 65,595 | (112,077) | 373,537 | ||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||
Capital expenditures for property, plant and equipment | (219,246) | (51,676) | (186,452) | (879,201) | ||||||||||||
Acquisitions of assets | (48,312) | — | (1,328) | (216,943) | ||||||||||||
Proceeds from sale of assets | 21,834 | 11,841 | 20,090 | 56,504 | ||||||||||||
Net cash used in investing activities | (245,724) | (39,835) | (167,690) | (1,039,640) | ||||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||
Proceeds from borrowings | — | — | 489,198 | 2,065,000 | ||||||||||||
Repayments of borrowings | — | (414,954) | (74,243) | (939,466) | ||||||||||||
Debt issuance costs | (1,488) | — | (333) | (53,244) | ||||||||||||
Proceeds from building mortgage | — | — | 26,847 | — | ||||||||||||
Payment of mortgage proceeds and cash recovery to debt holders | — | — | (33,874) | — | ||||||||||||
Noncontrolling interest distributions | — | — | — | (138,305) | ||||||||||||
Cash paid for tax withholdings on vested stock awards | (6,730) | (110) | (44) | (3,535) | ||||||||||||
Dividends paid—preferred | — | — | — | (11,262) | ||||||||||||
Other | — | 3 | — | 1,250 | ||||||||||||
Net cash (used in) provided by financing activities | (8,218) | (415,061) | 407,551 | 920,438 | ||||||||||||
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH | (72,763) | (389,301) | 127,784 | 254,335 | ||||||||||||
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year | 174,071 | 563,372 | 435,588 | 181,253 | ||||||||||||
CASH, CASH EQUIVALENTS and RESTRICTED CASH end of year | $ | 101,308 | $ | 174,071 | $ | 563,372 | $ | 435,588 | ||||||||
Conference Call Information
The Company will host a conference call to discuss these results on Thursday, February 22, 2018 at 8:00 am CT. The telephone number to access the conference call from within the U.S. is (833) 245-9650 and from outside the U.S. is (647) 689-4222. The passcode for the call is 4489951. An audio replay of the call will be available from February 22, 2018 until 11:59 pm CT on March 24, 2018. The number to access the conference call replay from within the U.S. is (800) 585-8367 and from outside the U.S. is (416) 621-4642. The passcode for the replay is 4489951.
A live audio webcast of the conference call will also be available via SandRidge's website, www.sandridgeenergy.com, under Investor Relations/Presentation & Events. The webcast will be archived for replay on the Company's website for 30 days.
Non-GAAP Financial Measures
This press release includes non-GAAP financial measures. These non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. Below is additional disclosure regarding each of the non-GAAP measures used in this press release, including reconciliations to their most directly comparable GAAP measure.
Reconciliation of Cash Provided by (Used in) Operating Activities to Operating Cash Flow
The Company defines operating cash flow as net cash provided by (used in) operating activities before changes in operating assets and liabilities, as shown in the following table. Operating cash flow is a supplemental financial measure used by the Company's management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the Company's ability to internally fund exploration and development activities and to service or incur additional debt. The Company also uses this measure because operating cash flow relates to the timing of cash receipts and disbursements that the Company may not control and may not relate to the period in which the operating activities occurred. Further, operating cash flow allows the Company to compare its operating performance and return on capital with those of other companies without regard to financing methods and capital structure. This measure should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with GAAP.
Successor | Successor | Predecessor | |||||||||||||||||
Three Months | Year Ended | Combined | Period from | Period from | |||||||||||||||
December 31, 2017 | |||||||||||||||||||
(In thousands) | |||||||||||||||||||
Net cash provided by (used in) operating activities | $ | 33,273 | $ | 181,179 | $ | (46,482) | $ | 65,595 | $ | (112,077) | |||||||||
Changes in operating assets and liabilities | 7,258 | 1,559 | 37,759 | (13,437) | 51,196 | ||||||||||||||
Operating cash flow | $ | 40,531 | $ | 182,738 | $ | (8,723) | $ | 52,158 | $ | (60,881) | |||||||||
Reconciliation of Net (Loss) Income to EBITDA and Adjusted EBITDA
The Company defines EBITDA as net (loss) income before income tax (benefit) expense, interest expense, depreciation and amortization - other and depreciation and depletion - oil and natural gas. Adjusted EBITDA, as presented herein, is EBITDA excluding items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring, as shown in the following tables.
Adjusted EBITDA is presented because management believes it provides useful additional information used by the Company's management and by securities analysts, investors, lenders, ratings agencies and others who follow the industry, for analysis of the Company's financial and operating performance on a recurring basis and the Company's ability to internally fund exploration and development, and to service or incur additional debt. In addition, management believes that adjusted EBITDA is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry. The Company's adjusted EBITDA may not be comparable to similarly titled measures used by other companies.
Successor | Successor | Predecessor | |||||||||||||||||
Three Months | Year Ended | Combined | Period from | Period from | |||||||||||||||
December 31, 2017 | |||||||||||||||||||
(In thousands) | |||||||||||||||||||
Net (loss) income | $ | (18,760) | $ | 47,062 | $ | 1,106,815 | $ | (333,982) | $ | 1,440,797 | |||||||||
Adjusted for | |||||||||||||||||||
Income tax (benefit) expense | (253) | (8,749) | 20 | 9 | 11 | ||||||||||||||
Interest expense | 1,377 | 4,886 | 129,107 | 1,590 | 127,517 | ||||||||||||||
Depreciation and amortization - other | 3,123 | 13,852 | 25,245 | 3,922 | 21,323 | ||||||||||||||
Depreciation and depletion - oil and natural gas | 30,549 | 118,035 | 127,039 | 36,061 | 90,978 | ||||||||||||||
EBITDA | 16,036 | 175,086 | 1,388,226 | (292,400) | 1,680,626 | ||||||||||||||
Asset impairment | 544 | 4,019 | 1,037,281 | 319,087 | 718,194 | ||||||||||||||
Stock-based compensation | 3,134 | 13,923 | 6,257 | 1,966 | 4,291 | ||||||||||||||
Loss (gain) on derivative contracts | 21,934 | (24,090) | 30,475 | 25,652 | 4,823 | ||||||||||||||
Cash (paid) received upon settlement of derivative contracts (1) | (440) | 7,260 | 80,306 | 13,455 | 66,851 | ||||||||||||||
Loss on settlement of contract | — | — | 90,184 | — | 90,184 | ||||||||||||||
Restructuring costs (2) | — | 8,554 | 53,544 | 17,138 | 36,406 | ||||||||||||||
Drilling participation agreement transaction costs | 20 | 2,901 | — | — | — | ||||||||||||||
Terminated merger costs | 8,162 | 8,162 | — | — | — | ||||||||||||||
Oil field services - exit costs | — | — | 2,428 | — | 2,428 | ||||||||||||||
Gain on extinguishment of debt | — | — | (41,179) | — | (41,179) | ||||||||||||||
Gain on reorganization items, net | — | — | (2,430,599) | — | (2,430,599) | ||||||||||||||
Employee incentive and retention | — | — | 22,984 | 2,843 | 20,141 | ||||||||||||||
Other | 92 | (2,620) | (1,840) | (16,660) | 14,820 | ||||||||||||||
Adjusted EBITDA | $ | 49,482 | $ | 193,195 | $ | 238,067 | $ | 71,081 | $ | 166,986 | |||||||||
(1) | Excludes amounts received for early settlement of contracts in the year ended December 31, 2016. | |||||||||||||||||||
(2) | Includes severance. | |||||||||||||||||||
Reconciliation of Cash Provided by (Used in) Operating Activities to Adjusted EBITDA
Successor | Successor | Predecessor | |||||||||||||||||
Three Months | Year Ended | Combined | Period from | Period from | |||||||||||||||
December 31, 2017 | |||||||||||||||||||
(In thousands) | |||||||||||||||||||
Net cash provided by (used in) operating activities | $ | 33,273 | $ | 181,179 | $ | (46,482) | 65,595 | $ | (112,077) | ||||||||||
Changes in operating assets and liabilities | 7,258 | 1,559 | 37,759 | (13,437) | 51,196 | ||||||||||||||
Interest expense | 1,377 | 4,886 | 129,107 | 1,590 | 127,517 | ||||||||||||||
Cash received on early settlement of derivative contracts | — | — | (17,894) | — | (17,894) | ||||||||||||||
Contractual maturity reached on previous early settlements | — | — | 17,893 | 5,756 | 12,137 | ||||||||||||||
Cash paid on early conversion of convertible notes | — | — | 33,452 | — | 33,452 | ||||||||||||||
Cash paid on settlement of contract | — | — | 11,000 | — | 11,000 | ||||||||||||||
Gain on convertible notes derivative liability | — | — | 1,324 | — | 1,324 | ||||||||||||||
Oil field services - exit costs (1) | — | — | 2,386 | — | 2,386 | ||||||||||||||
Restructuring costs (1)(2) | — | 6,729 | 44,180 | 12,852 | 31,328 | ||||||||||||||
Drilling participation agreement transaction costs | 20 | 2,901 | — | — | — | ||||||||||||||
Income tax (benefit) expense | (253) | (8,749) | — | — | — | ||||||||||||||
Terminated merger costs | 8,162 | 8,162 | — | — | — | ||||||||||||||
Cash paid for reorganization items | — | — | 12,483 | — | 12,483 | ||||||||||||||
Employee incentive and retention | — | — | 22,984 | 2,843 | 20,141 | ||||||||||||||
Other | (355) | (3,472) | (10,125) | (4,118) | (6,007) | ||||||||||||||
Adjusted EBITDA | $ | 49,482 | $ | 193,195 | $ | 238,067 | $ | 71,081 | $ | 166,986 | |||||||||
(1) | Excludes associated stock-based compensation. |
(2) | Includes severance. |
Reconciliation of Net (Loss) Income Available to Common Stockholders to Adjusted Net Income Available to Common Stockholders
The Company defines adjusted net (loss) income as net (loss) income excluding items that the Company believes affect the comparability of operating results and are typically excluded from published estimates by the investment community, including items whose timing and/or amount cannot be reasonably estimated or are non-recurring, as shown in the following tables.
Management uses the supplemental measure of adjusted net (loss) income as an indicator of the Company's operational trends and performance relative to other oil and natural gas companies and believes it is more comparable to earnings estimates provided by securities analysts. Adjusted net (loss) income is not a measure of financial performance under GAAP and should not be considered a substitute for net (loss) income available to common stockholders.
Successor | |||||||||||||||
Three Months Ended December 31, 2017 | Year Ended December 31, 2017 | ||||||||||||||
$ | $/Diluted Share | $ | $/Diluted Share | ||||||||||||
(In thousands, except per share amounts) | |||||||||||||||
Net (loss) income available to common stockholders | $ | (18,760) | $ | (0.54) | $ | 47,062 | $ | 1.44 | |||||||
Asset impairment | 544 | 0.02 | 4,019 | 0.12 | |||||||||||
Loss (gain) on derivative contracts | 21,934 | 0.62 | (24,090) | (0.73) | |||||||||||
Cash (paid) received upon settlement of derivative contracts | (440) | (0.01) | 7,260 | 0.22 | |||||||||||
Restructuring costs (1) | — | — | 8,554 | 0.26 | |||||||||||
Drilling participation agreement transaction costs | 20 | — | 2,901 | 0.09 | |||||||||||
Terminated merger costs | 8,162 | 0.24 | 8,162 | 0.25 | |||||||||||
Other | 246 | 0.01 | (1,396) | (0.04) | |||||||||||
Adjusted net income available to common stockholders | $ | 11,706 | $ | 0.34 | $ | 52,472 | $ | 1.61 | |||||||
Basic | Diluted (2) | Basic | Diluted (2) | ||||||||||||
Weighted average number of common shares outstanding | 34,494 | 34,547 | 32,442 | 32,663 | |||||||||||
Total adjusted net income per share | $ | 0.34 | $ | 0.34 | $ | 1.62 | $ | 1.61 | |||||||
(1) | Includes severance. | |||||||||||||||
(2) | Weighted average fully diluted common shares outstanding for certain periods presented includes shares that are considered antidilutive for calculating loss per share in accordance with GAAP. | |||||||||||||||
Reconciliation of Net Income (Loss) Available to Common Stockholders to Adjusted Net (Loss) Income Available to Common Stockholders
Combined | Successor | Predecessor | |||||||||||||||||
Period from October 2, 2016 | Period from January 1, 2016 | ||||||||||||||||||
$ | $ | $/Diluted Share | $ | $/Diluted Share | |||||||||||||||
(In thousands, except per share amounts) | |||||||||||||||||||
Net income (loss) available to common stockholders | $ | 1,090,494 | $ | (333,982) | $ | (9.95) | $ | 1,424,476 | $ | 2.01 | |||||||||
Asset impairment | 1,037,281 | 319,087 | 9.50 | 718,194 | 1.01 | ||||||||||||||
Loss on derivative contracts | 30,475 | 25,652 | 0.76 | 4,823 | 0.01 | ||||||||||||||
Cash received upon settlement of derivative contracts (1) | 80,306 | 13,455 | 0.40 | 66,851 | 0.09 | ||||||||||||||
Gain on convertible notes derivative liability | (1,324) | — | — | (1,324) | — | ||||||||||||||
Loss on settlement of contract | 90,184 | — | — | 90,184 | 0.13 | ||||||||||||||
Restructuring costs (2) | 53,544 | 17,138 | 0.51 | 36,406 | 0.05 | ||||||||||||||
Oil field services - exit costs | 2,428 | — | — | 2,428 | — | ||||||||||||||
Gain on extinguishment of debt | (41,179) | — | — | (41,179) | (0.06) | ||||||||||||||
Gain on reorganization items, net | (2,430,599) | — | — | (2,430,599) | (3.43) | ||||||||||||||
Employee incentive and retention | 22,984 | 2,843 | 0.08 | 20,141 | 0.03 | ||||||||||||||
Other | 1,565 | (15,171) | (0.44) | 16,736 | 0.03 | ||||||||||||||
Adjusted net (loss) income available to common stockholders | $ | (63,841) | $ | 29,022 | $ | 0.86 | $ | (92,863) | $ | (0.13) | |||||||||
Basic | Diluted (3) | Basic | Diluted (3) | ||||||||||||||||
Weighted average number of common shares outstanding | 18,967 | 33,573 | 708,928 | 708,928 | |||||||||||||||
Total adjusted net income (loss) per share | $ | 1.53 | $ | 0.86 | $ | (0.13) | $ | (0.13) | |||||||||||
(1) | Excludes amounts received for early settlement of contracts in the 2016 periods. | |||||||||||||||||||
(2) | Includes severance. | |||||||||||||||||||
(3) | Weighted average fully diluted common shares outstanding for certain periods presented includes shares that are considered antidilutive for calculating loss per share in accordance with GAAP. | |||||||||||||||||||
Reconciliation of G&A to Adjusted G&A
The Company reports and provides guidance on Adjusted G&A per Boe because it believes this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period, compare and make investment recommendations of companies in the oil and gas industry. This non-GAAP measure allows for the analysis of general and administrative spend without regard to stock-based compensation programs, and other non-recurring cash items which can vary significantly between companies. Adjusted G&A per Boe is not a measure of financial performance under GAAP and should not be considered a substitute for general and administrative expense per Boe. Therefore, the Company's Adjusted G&A per Boe may not be comparable to other companies' similarly titled measures.
The Company defines adjusted G&A as general and administrative expense adjusted for certain non-cash stock-based compensation and other non-recurring items, as shown in the following tables.
Successor | |||||||||||||||
Three Months Ended December 31, 2017 | Year Ended December 31, 2017 | ||||||||||||||
$ | $/Boe | $ | $/Boe | ||||||||||||
(In thousands, except per Boe amounts) | |||||||||||||||
General and administrative | $ | 16,840 | $ | 4.77 | $ | 76,024 | $ | 5.10 | |||||||
Stock-based compensation (1) | (3,134) | (0.88) | (13,925) | (0.94) | |||||||||||
Restructuring costs | — | — | (3,739) | (0.25) | |||||||||||
Drilling participation agreement transaction costs | (20) | (0.01) | (2,901) | (0.19) | |||||||||||
Adjusted G&A | $ | 13,686 | $ | 3.88 | $ | 55,459 | $ | 3.72 | |||||||
Combined Year Ended | Successor | Predecessor | |||||||||||||||||||||
Period from October 2, 2016 | Period from January 1, 2016 | ||||||||||||||||||||||
$ | $/Boe | $ | $/Boe | $ | $/Boe | ||||||||||||||||||
(In thousands, except per Boe amounts) | |||||||||||||||||||||||
General and administrative | $ | 125,928 | $ | 6.50 | $ | 9,837 | $ | 2.27 | $ | 116,091 | $ | 7.73 | |||||||||||
Stock-based compensation (1) | (5,963) | (0.31) | (1,965) | (0.45) | (3,998) | (0.27) | |||||||||||||||||
Employee incentive and retention | (22,984) | (1.19) | (2,843) | (0.65) | (20,141) | (1.34) | |||||||||||||||||
Restructuring costs | (23,669) | (1.22) | (4,804) | (1.11) | (18,865) | (1.26) | |||||||||||||||||
Doubtful receivable (write-off) recovery | (3,556) | (0.18) | 13,166 | 3.02 | (16,722) | (1.11) | |||||||||||||||||
Shareholder litigation costs | (963) | (0.05) | — | — | (963) | (0.06) | |||||||||||||||||
Adjusted G&A | $ | 68,793 | $ | 3.55 | $ | 13,391 | $ | 3.08 | $ | 55,402 | $ | 3.69 | |||||||||||
(1) | Year ended December 31, 2017, Successor 2016 Period and Predecessor 2016 Period exclude $1.8 million, $4.3 million and $5.1 million, respectively, for the acceleration of certain stock awards. |
Reconciliation of PV-10 to Standardized Measure
PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using 12-month average prices for the year ended December 31, 2017. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities. It is useful because its calculation is not dependent on the taxpaying status of the entity. Because of the present value of future income tax discounted at 10% is insignificant, these measures are equivalent.
The PV-10 of strip-based proved reserves is a non-GAAP financial measure and differs from standardized measure because it reflects the estimated proved reserves economically recoverable based on forward NYMEX strip prices rather than SEC pricing and does not include the effects of income taxes on future net revenues. PV-10 of strip-based proved reserves is useful to investors to illustrate the potential value of proved reserves that are economically recoverable in the current commodity price environment rather than SEC prices. Neither the PV-10 of the Company's SEC reserves, the PV-10 of strip-based proved reserves nor the Standardized Measure represents an estimate of fair market value of the Company's oil and natural gas properties.
Net Debt
The Company also uses the term net debt to determine the extent to which the Company's outstanding debt obligations would be satisfied by its cash and cash equivalents on hand. Management believes this metric is useful to investors in determining the Company's current leverage position following recent significant events subsequent to the period.
For further information, please contact:
Johna M. Robinson
Investor Relations
SandRidge Energy, Inc.
123 Robert S. Kerr Avenue
Oklahoma City, OK 73102-6406
(405) 429-5515
Cautionary Note to Investors - This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, but not limited to, the information appearing under the heading "2018 Operational and Capital Expenditure Guidance." These statements express a belief, expectation or intention and are generally accompanied by words that convey projected future events or outcomes. The forward-looking statements include projections and estimates of the Company's corporate strategies, future operations, and development plans and appraisal programs, projected acreage position, drilling inventory and locations, estimated oil, and natural gas and natural gas liquids production, rates of return, reserves, price realizations and differentials, hedging program, projected operating, general and administrative and other costs, projected capital expenditures, tax rates, efficiency and cost reduction initiative outcomes, liquidity and capital structure and infrastructure assessment and investment. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the volatility of oil and natural gas prices, our success in discovering, estimating, developing and replacing oil and natural gas reserves, actual decline curves and the actual effect of adding compression to natural gas wells, the availability and terms of capital, the ability of counterparties to transactions with us to meet their obligations, our timely execution of hedge transactions, credit conditions of global capital markets, changes in economic conditions, the amount and timing of future development costs, the availability and demand for alternative energy sources, regulatory changes, including those related to carbon dioxide and greenhouse gas emissions, and other factors, many of which are beyond our control. We refer you to the discussion of risk factors in Part I, Item 1A - "Risk Factors" of our Annual Report on Form 10-K and in comparable "Risk Factor" sections of our Quarterly Reports on Form 10-Q filed after such form 10-K. All of the forward-looking statements made in this press release are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our Company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to update or revise any forward-looking statements.
SandRidge Energy, Inc. (NYSE: SD) is an oil and natural gas exploration and production company headquartered in Oklahoma City, Oklahoma with its principal focus on developing high-return, growth-oriented projects in the U.S. Mid-Continent and Niobrara Shale.
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SOURCE SandRidge Energy, Inc.
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