SANDRIDGE ENERGY, INC. (Exact name of registrant as specified in its charter)

Transcription

1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported): September 29, 2016 SANDRIDGE ENERGY, INC. (Exact name of registrant as specified in its charter) Delaware (State or Other Jurisdiction of (Commission (I.R.S. Employer Incorporation or Organization) File Number) Identification No.) 123 Robert S. Kerr Avenue Oklahoma City, Oklahoma (Address of Principal Executive Offices) (Zip Code) Registrant s Telephone Number, including Area Code: (405) Not Applicable. (Former name or former address, if changed since last report) Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below): Written communications pursuant to Rule 425 under the Securities Act (17 CFR ) Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR a-12) Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR d-2(b)) Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR e-4(c))

2 Item 8.01 Other Events On September 29, 2016, SRidge Energy, Inc. (the Company ) posted to its website, a presentation regarding the Company. The presentation is attached as Exhibit Item Financial Statements Exhibits (d) Exhibits 99.1 Presentation

3 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SANDRIDGE ENERGY, INC. (Registrant) Date: September 30, 2016 By: /s/ Philip T. Warman Philip T. Warman Senior Vice President, General Counsel Corporate Secretary

4 EXHIBIT INDEX Exhibit Number Name of Exhibit 99.1 Presentation

5 Exhibit 99.1 SANDRIDGE INVESTOR PRESENTATION ENERGY September Sridge the 2016 power of us

6 CAUTIONARY Forward Looking STATEMENTS This presentation includes Statement statements express a belief, forward-looking expectation or intention statements are within generally the meaning accompanied of Section by words 27A of that the convey Securities projected Act of future 1933, events as amended, or outcomes. Section The forward-looking 21E of the Securities statements Exchange include Act statements of 1934, as about amended. the company s These corporate EBITDA, strategies, projected capital future operations, expenditures, development projected operating, plans general appraisal programs, administrative our drilling other inventory costs, anticipated locations, efficiency estimated production, cost reduction rates initiative of return, outcomes, reserves, projections the acquisition of estimates seismic of data, net infrastructure income utilization assumptions investment, analyses made liquidity, by us capital in light structure, of our experience hedging position our perception strategies, of historical price trends, realizations current conditions differentials. We expected have based future these developments, forward-looking as well statements as other factors on our we current believe expectations are appropriate circumstances. However, whether actual results developments will conform with our expectations predictions is subject to a number of risks uncertainties, including the volatility of oil natural under gas prices, the our economic success conditions, in discovering, regulatory estimating, changes developing other factors, oil many natural of which gas reserves, are beyond the our availability control. We refer terms you of capital, to the discussion our timely of execution risk factors of hedge in Part transactions, I, Item 1A credit Risk conditions Factors of of our global Annual capital Report markets, on Form changes 10-K in for presentation the year ended are qualified December by these 31, 2015 cautionary in comparable statements. The Risk actual Factors results sections or developments of our Quarterly anticipated Reports may on not Form be 10-Q realized filed or, after even the if substantially date of this presentation. realized, they All may of the not forward-looking have the expected statements consequences made to in or this on our company or our business or operations. Such statements are not guarantees of future performance actual results or developments may differ materially from those projected in the forward-looking statements. effects We The undertake SEC permits no obligation oil natural to update gas companies, or revise any in their forward-looking filings with the statements. recovery) recoverable reserves that the SEC s guidelines prohibit us SEC, from to including disclose only in filings proved, with probable the SEC. These possible estimates reserves, are as by each their is nature defined more by speculative the SEC. At than times estimates we use the of proved, terms EUR probable (estimated or possible ultimate reserves company s, amended accordingly, Annual are Report subject on to Form substantially 10-K referenced greater risk above, of being which actually is available realized on our by the website company. at For a discussion of the company s at the proved SEC s reserves, website at as calculated under current SEC rules, we refer you to the 1

7 SANDRIDGE With a strong balance ENERGY project with capacity sheet, to do we more. have competitive project IRRs from the high-graded harvest of our Mid-Continent position, plus we re adding portfolio diversification long term growth from our North Park Niobrara balance MID-continent sheet ~$525 high-graded MM of harvest Liquidity competitive protect the project Balance IRRs sheet Adjacent Long Runway Niobrara oil dominant North park position log term oil growth exps Zone drilling Appraisal Potential Additional Zones Extended & Multilaterals New Ares Ploneering Technologies inventory 2

8 SANDRIDGE De-levered Oil ENERGY Producer Focused OVERVIEW KEY INFORMATION on Value Creation PRIMARY 462K ASSETS Mid-Continent Locations Net Acres Focus Area ~300 2P2 129K North Locations Park Basin Net Acres Niobrara Oil ~1,300 2P2 PRODUCTION 54.7 MBoepd3 Q2 16 & RESERVES (28% oil) Production 281 (25% MMBoe1 oil) Proved Reserves (1) Probable SRidge (3) Excludes reserves production PV-10 related pro forma to noncontrolling for WTO divestiture interests net of noncontrolling interests as of , based on SEC pricing at that time ($46.79 / $2.59) (2) 2P locations: Undeveloped Proved 3

9 MID-CONTINENT $225MM $255MM EXPERTISE Capital Budget EXPANDING in 2016 in Two INTO Major THE Project NIOBRARA MID-CONTINENT: HIGH-GRADED HARVEST Areas One High-graded rig active harvest most of of 2016 ~$2MM per lateral costs Mid-Continent position to manage decline rates Appraise Generate flow adjacent stability plays NIOBRARA: INITIATE competitive OIL PROGRAM while advancing returns innovations at the strip cash One Initiate rig Niobrara active through oil development August 2016 Line of sight to sub-$4mm per lateral program + Room to improve costs optimize costs Deploy extended laterals assess multilateral completions Our combined programs diversify reduce risk potential by drilling a additional higher percentage Niobrara of benches efficiency. proved locations plus sharing expertise best practices between the two areas. Continue improving both capital expense 4

10 THE Emerging REORGANIZED with Strong Pro SANDRIDGE Forma Balance ENERGY Sheet, Minimal (NYSE:SD) COMMON 19.4 MM new common shares to be issued at emergence Leverage 15.0 ~$525MM MM issuable of Liquidity 2.1 MM warrants at $42.03 strike price upon conversion of matory convert EQUITY 4.9 MM warrants at $41.34 strike price MANDATORILY CONVERTIBLE Unsecured $282MM face matorily value REVOLVING No financial covenants or borrowing convertible base redeterminations into 15.0 MM shares for two DEBT years No Liquidity interest1 CREDIT $425MM FACILITY Undrawn2 payments, expect to emerge with LIBOR (100 bps floor) bps rate 525MM $100MM CASH Pro forma for emergence ~$100MM $ in unrestricted cash (1) Make whole applicable if note accelerated following an event of default (2) Pro forma for debt pay down following emergence excludes approximately $10.2MM of LOCs Note: In addition to the items 5 above there will be a $35MM note secured by the Company s downtown office building

11 OPERATIONAL Q2 16 production HIGHLIGHTS 5.0 mmboe 28% AND oil FULL YEAR CAPEX PLAN Nibrara 1st well: (90% 30-day oil) Well costs IP1 of 550 Boepd (89% oil) four additional wells: 30-day IP avg of 460 Boepd (91% oil) three additional wells in various stages of evaluation $1.9MM Mid-continent per lateral 1st dual 1H 16 extended D&C laterla2: in Miss $1.7MM 30-day IP per of lateral 1,099 Boepd D&C on (60% first oil) Miss chester dual extended extended lateral lateral: Line 30-day of sight ip of to 560 sub-$4.0mm boepd (62% per oil) lateral D&C in Niobrara % plan muli $225MM-$255MM extended laterals CAPEX in mississippian 37 lateral spud -26 in mid-continent 11 in Niobrara (1) Calculated as the highest consecutive 6 30-Day average production rate during the early life of a well (2) A lateral is defined as a single one-mile section lateral

12 MID-CONTINENT Diverse Asset with Focus OVERVIEW Stacked reservoirs combined Exping with large Beyond acreage Mississippian base Interval in Oklahoma Appraising Miss Lime has adjacent been plays primary target additional zones? Focus +/- 300 area thick concentrated carbonate within at ~6, K TVD Over 1,600 horizontal wells drilled in net OK acres & KS in since OK Salt water disposal infrastructure 2010? Electrical 1,095 miles infrastructure of pipeline, connected to 136 active disposal wells, injecting ~670 MBwpd? Field 1,250 office miles is of located power in lines, Alva, six OK substations two micro grids KS OK R WOODS WOODWARD 7 ALFALFA MAJOR GARFIELD GRANT KAY NOBLE

13 DURABLE Multi Extended IMPROVEMENT Laterals are IN a Breakthrough MISSISSIPPIAN ECONOMICS D&C Lower CAPEX, costs per $MM lateral PER LATERAL -37% D&C vs CAPEX, 2014 Lower costs per SMM lateral PER LATERAL $ % $2.0 80% $1.0 60% E40% 20% 0% $3.0-37% $2.2 vs 2014 $1.9 D&C % Multi Capex or Extended per Lateral Laterals 8

14 CONSISTENT Similar Recoveries RESULTS for Much FROM Lower MISSISSIPPIAN Costs per Lateral DRILLING 90-DAY Lower costs CUMULATIVE for similar production MBOE PER LATERAL AND D&C CAPEX, $MM PER LATERAL 35.0 MBoe Group Group 1 Group 2 Group 3 NOV 14-JAN 4 JAN 15-AP APR JUN 15-AUG 15-MAY 15 $3.5 $3.0 $2.5 $ Lower costs for similar $1.5 production $1.0 $0.5 $0.0 Results shown by groups of 50 9 wells

15 MULTILATERAL Multiple Laterals from AND a Single EXTENDED Vertical LATERAL Wellbore TOOLKIT MORE Less capital EFFICIENT per lateral: THAN shared SINGLE facilities, LATERALS Lower LOE: shared artificial lift fixed pads, costs infrastructure Increases RECENT full ADVANCES cycle value First Extended dual laterals extended expected lateral completed to commercialize in Q1 16, Chester the Dettle oil development H Technology transfer to Niobrara 10 play in Colorado

16 MULTI Lower CAPEX, AND EXTENDED Lower LOE LATERAL Higher DRILLING NPV ENHANCES VALUE CREATION Three KEY DRIVERS years of accumulated OF MORE learnings VALUE PER have LATERAL established a competitive advantage CAPEX: LOE: Shared Lower tanks, D&C pads, per etc. lateral Ability Confidence to tailor in approach completions in new to acreage areas situation development history (1) Includes : Midstream 11 Electrical ($55K), SWD ($120K), Workovers ($320K) (2) Strip Pricing

17 MID-CONTINENT: ACHIEVEMENTS ACHIEVEMENTS AND PRIORITIES Multi Multi extended extended lateral lateral development development yields provide best strong 2016 results well returns in Mississippian Lime, driven by a significant improvement in drilled completed lateral cost per foot Dettle Chester (Dual-XL) drilling with produced most recent a 30-Day 7 laterals IP of averaging 1,099 Boepd a 30-Day (60% oil) IP of for 487 $1.7MM Boepd per (60% lateral Q2 16 Chester extended lateral, the Earl H14H, produced a 30-Day IP of 560 oil), Boepd exping (62 % oil) drilling at $2.16MM inventory per on lateral existing leasehold footprint Continued Effectively focus managing on operating SWD limitations cost improvement from regulatory through agencies, contract with renegotiations minimal production operating deferment efficiencies PRIORITIES Test Continue delineate to drive down adjacent individual emerging well plays Reduce production downtime costs through innovative operating practices including multilateral, extended lateral dual extended lateral utilization Exp alternate zone water injection 12 plan; successful Penn Ss pilot injection test initiated in Q3 16

18 NORTH Dominant PARK Acreage NIOBRARA Position with ASSET Highest OVERVIEW Targeting sub-$4mm per lateral for ~250 Niobrara MBo recovery Oil Rates Stacked Ten wells pay drilled potential in 2016; with five over wells 1,300 with locations Successfully drilled first extended lateral (two over mile 90 days lateral) of production; three wells in early evaluation phase two currently being completed 28 September MMBoe 2016 of proved production: reserves1 ~1,600 (81% Net oil); Bopd 108 from PUDs Large contiguous acreage position; federal units largely 23 horizontal eliminate near wells; term 42 drilling HBP drilling permits requirements approved SUMMARY HBP 22K Held OF by ACREAGE Federal Unit HELD (HBU) NET 53K ACRES Total Additional Acreage HBU Currently by YE 17 Held 33K 75K (58%) Total (1) Expected SRidge Acreage reserves Held as by of YE , 108K based (84%) on SEC pricing at that time ($46.79 / $2.59) 81% 1,300 OIL LOCATIONS IN NORTH PARK VS ~35% FOR DJ BASIN 129K FEDERAL NET ACRES UNIT IN JACKSON COUNTY 75K NET ACRES (OR 58%) HBP OR BY SRidge Acreage 13

19 INITIALLY Similar Geologic TARGETING Characteristics LOWER to the NIOBRARA NORTH PARK DJ Basin Niobrara but Higher Oil Cut DJ Oil BASIN EUR % BASIN Depth 5,500 81% 9,000 35% 40% Reservoir Storage Capacity ft. 6,000 Gross 8,000 Thickness ft. Porosity 6 9% 6 10% ft ft. OOIP Reservoir per Section Production 63.8 Potential MMBo 41.3 Reservoir MMBo Pressure Thermal > 0.55 Maturity psi/ft (Ro) % psi/ft 0.5 Gas-oil 1.4+% Total Organic Content 3% 3% Ratio (GOR) scf/stb Up to 10,000+ scf/stb 14

20 SANDRIDGE 467 Boepd Average RESULTS 30-day SUPPORT IP of Last MODELED Ten Wells Drilled EXPECTATIONS 478 BOEPD AVERAGE 30-DAY IP BROUGHT ONLINE by Previous 2H 16; IN Operators DESIGNED TO TEST AND EVALUATE VARIOUS ON FIRST FIVE SANDRIDGE WELLS STAGES OF EVALUATION Spacing Artificial Stimulation lift concepts, methods including 15 pumping slickwater fracs

21 ACHIEVABLE Lower Costs, Optimized UPSIDE Completions, IN NORTH PARK Extended BASIN, Laterals, COLORADO UPSIDE INCLUDES Stacked Pay Location Count Exping Proving up structural additional benches geologic (first reservoir SRidge characterization well, the Gregory model 1-9H, beyond producing existing from 54 square Upper miles Lower of 3D Niobrara) seismic by acquiring additional 65 square miles of 3D seismic starting in 2017 Drilling Optimizing extended completions laterals to (one enhance planned production in 2H 16) Reducing drilling completion costs through rate applied ultimate learnings recovery, observing while DJ reducing Basin operators costs HBP AND FEDERAL UNITS 16HOLD 58% OF ACREAGE

22 NIOBRARA WTI Oil Differential ASSET Reduced MIDSTREAM from $11+/Bbl STATUS CURRENT OIL AND GAS DISPOSITION to $3.15/Bbl Building Oil trucked out to field market gathering (centralized infrastructure; oil loading centralized bay could tank hle battery 40 MBopd) concept used for processing, storage export Gas MIDSTREAM combusted STRATEGY under appropriate permits Reduce Gas reinjection air emissions being by considered removing to liquids reduce from combustion gas stream volumes with Methane Recovery Units (MRUs) Oil Currently gas proceeding pipelines under with engineering, evaluation NORTH PARK BASIN POTENTIAL PIPELINE permitting ROUTES right-of-way acquisition for oil natural gas pipelines 17

23 NORTH ACHIEVEMENTS PARK BASIN: ACHIEVEMENTS AND PRIORITIES First Tracer production testing on achieved the Gregory on the 1-9H Gregory confirmed 1-9H with oil production a 30-Day IP from of 550 Upper Boepd (89% Lower oil) An average 30-Day IP of 478 Boepd (91% oil) from first five wells Niobrara Drilled Reduced the spud field s to rig first release two mile time lateral Reduced WTI oil differential from from $11+/Bbl 31 days to to $3.15/Bbl ~11 days Completed Zero recordable construction safety incidents of the field s since first taking central over tank operations battery PRIORITIES in December 2015 Lower Exp D&C extended Cost: lateral Line of program sight to sub-$4mm per lateral Determine Delineate additional additional proved bench reserves potential Form two additional Federal Units in 2017 increase (~33K recoverable net acres Held reserves Additional 3D seismic surveys to enhance delineation area by 65 by square Unit) Consolidate acreage in primary development area miles 18

24 INVESTMENT HARVEST & APPRAISE THESIS POST RESTRUCTURING MISSISSIPPIAN High-graded harvest EXPERTISE of our ~462K PLUS acre ADJACENT Oklahoma focus PLAYS ~1,300 producing horizontal wells, 3D seismic improved area One rig active most of 2016 reservoir characterization Production Infrastructure decline in place moderating Industry towards our leading position well costs innovative multilateral development Mid-Continent position supports other zones opportunities Appraising adjacent plays additional zones Industry activity moving north west DIVERSIFY GROW Growth OIL in oil AND reserves VALUE value VIA per NIOBRARA Drilling completing with encouraging barrel via results North Park Niobrara development Exp 1,300 locations extended lateral significant program PUD potential Upside DE-LEVERED through more Niobrara benches, completion spacing optimization lower well costs STRONG Net unlevered FINANCIAL balance sheet1 POSITION ~$525MM Liquidity strong liquidity provides financial flexibility at emergence ~$100MM Undrawn $425MM of unrestricted revolver2 cash at emergence No (1) financial Excluding covenants matorily or borrowing convertible base redeterminations note for two years (2) Pro forma for debt pay down following emergence excludes approximately $10.2MM of LOCs www. SRidgeEnergy.com 19

25 APPENDIX Sridge the power us

26 2016 TOTAL OPERATIONAL COMPANY PRODUCTION GUIDANCE Oil Total (MMBbls) Liquids (MMBbls) Natural Gas Liquids (MMBbls) Natural PRICING Gas REALIZATIONS (Bcf) Total (MMBoe) Oil COSTS (differential PER BOE below WTI) $3.75 NGLs (realized % of WTI) 27% Gas (differential below Henry Hub) $0.50 LOE % OF $9.00 $9.20 NET REVENUE DD&A oil & gas DD&A other Total DD&A $6.50 $6.95 G&A cash1 $4.25 $4.50 Severance Corporate Tax Taxes Rate 2.00% 2.25% (1) Adjusted G&A Cash 0% Deferral is a non-gaap Rate 0% items. Incentive compensation plan normalized financial to be measure consistent as it with excludes prior year from compensation G&A non-cash plans. compensation, The most directly severance, comparable bad debt GAAP allowance, measure shareholder for Adjusted litigation G&A cash costs, restructuring is General costs, Administrative other non-recurring 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 Expense. periods. future 21

27 2016 CAPEX CAPITAL GUIDANCE EXPENDITURES $MM GUIDANCE D&C Total Exploration $125 $140 Other Production E&P $95 $110 General Corporate $5 $220 $250 Total LATERAL Capital SPUDS Expenditures GROSS $225 $255 Mid-Continent North Park NET Total Laterals CAPEX Mid-Continent GUIDANCE D&C $45 $50 DETAIL $MM Total Drilling & Completing $125 $140 North Park D&C Other D&C OTHER L, G&G E&P Total Other E&P Seismic $95 $110 $10 $15 Infrastructure Workovers Capitalized G&A Interest 25 NON General E&P Total Capital Corporate Expenditures $5 (1) 2015 Carryover, JV (excl. Penalty, A&D Rig Penalty, P&A) Non-Op, $225 $255 SWD (2) Facilities Electrical, SWD, Gathering, Pipelines 22

28 2015 RESERVES YEAR END PV-10 RESERVES OIL % $MM NGLS % GAS EQUIVALENT (MMBBLS) Reservoir Category (MMBBLS) (BCF) (MMBOE) PDP Total 71 Producing $ 47 1, % $ % PNP Non Producing PBP Behind Pipe 2 1 (3) PUD Undeveloped % 83 8% Development Total Developed Status Total $ 1, % $ % Total Undeveloped % 83 8% Note: SRidge reserves 23 PV-10 pro forma for WTO divestiture net of noncontrolling interests as of , based on SEC pricing at that time ($46.79 / $2.59) Note: Numbers may not add due to rounding

29 ACREAGE Significant HBP SUMMARY ACREAGE SUMMARY Acreage, with Expiring Acreage Mostly in Kansas (IN HBP THOUSANDS) NON-HBP TOTAL TOTAL OK % % KS % % CO % % TX % % TOTAL 49% 545 Expiring 51% 23 Expiring Acreage Acreage 100% 100% Extendable Extendable Acreage Acreage 572 Expiring Acreage 100% Extendable Acreage 129 Expiring Acreage 100% Extendable Acreage 1, % Expiring Extendable Acreage Acreage Note: Data as of