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| 8-K - 8-K - ABRAXAS PETROLEUM CORP | march2016update8-k.htm |
Abraxas Petroleum Corporate Update March 2016 Raven Rig #1; McKenzie County, ND Exhibit 99.1
2 The information presented herein may contain predictions, estimates and other forward- looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those included in the forward-looking statements include the timing and extent of changes in commodity prices for oil and gas, availability of capital, the need to develop and replace reserves, environmental risks, competition, government regulation and the ability of the Company to meet its stated business goals. Forward-Looking Statements
3 I. Abraxas Petroleum Overview
4 Headquarters.......................... San Antonio Employees(1)............................ 90 Shares outstanding(2)……......... 106.3 mm Market cap(4) …………………….... $114.8 mm Net debt(3)………………………….. $137.2 mm 2016E CAPEX………………………. $17.5-40 mm (1) As of February 20, 2016. Does not include nine employees associated with the Company’s wholly owned subsidiary, Raven Drill ing. (2) Shares outstanding for the quarter ended December 31, 2015. (3) Total debt including RBL facility, rig loan and building mortgage less cash as of December 31, 2015. (4) Share price as of December 31, 2015. (5) Enterprise value includes working capital deficit (excluding current hedging assets and liabilities) as of December 31, 2015, but does not include building mortgage or rig loan. Includes RBL facility, rig loan and building mortgage less cash as of December 31, 2014. (6) Average production for the quarter ended December 31, 2015. (7) Calculation using average production for the quarter ended December 31, 2015 annualized and net proved reserves as of December 31, 2015. (8) Proved reserves as of December 31, 2015. Uses SEC YE2014 average pricing of $50.12/bbl and $2.63/mcf. See appendix for reconciliation of PV-10 to standardized measure. (9) Hedge value as of December 31, 2015. (10) Net book value of other assets as of December 31, 2015. EV/BOE(3,4,5)………………………... $6.21 Proved Reserves(8).…………..... 43.2 mmboe PV-10(8)……………………………….. $197.3 mm Hedge Value(9)……………………... $27.4 mm NBV Non-Oil & Gas Assets(10).. $27.6 mm Production(6).……………………… 5,841 boepd R/P Ratio(7)…………………………. 20.3x NASDAQ: AXAS Corporate Profile
5 Proved Reserves(1) – 43.2 mmboe Production(2) – 5,841 boepd Reserve Mix(1) Revenue By Production Stream(2) Reserve / Production Summary High-quality, Long-Lived, Oil Weighted Assets (1) Net proved reserves as of December 31, 2015. (2) For the quarter ended December 31, 2015. Oil 56% Gas 29% NGL 15% Gulf Coast/ Eagle Ford 19% Rockies 66% Permian 15% Oil Sales 90% Gas Sales 8% NGL Sales 2% Gulf Coast/ Eagle Ford 8% Rockies 68% Permian 24%
6 (Boep d ) (1) Yearly CAPEX for each year ending December 31, 2011, 2012, 2013, 2014 and 2015. 2016 represents the midpoint of guidance. (2) 2016 estimate assumes the midpoint of 2016 guidance of 5,900 – 6,300 boepd. Efficient Production Base Maintaining Volumes on Limited CAPEX Daily Production vs Yearly CAPEX(1) $0 $50,000 $100,000 $150,000 $200,000 $250,000 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 2011A 2012A 2013A 2014A 2015A 2016E (2) Ye ar ly C ap ex ($ M )
7 Williston: Bakken / Three Forks Powder River Basin: Turner Eastern Shelf: Conventional & Emerging Hz Oil Eagle Ford Shale Delaware Basin: Montoya/Devonian/Miss Gas, Shallow Oil, Bone Spring Wolfcamp Potential Rocky Mountain Gulf Coast Permian Basin Legend Proved Reserves (mmboe)(1): 43.2 Proved Developed(1): 32% Oil(1): 56% Abraxas Petroleum Corporation Core Regions (1) Net proved reserves as of December 31, 2015.
8 II. Strategic Plan
9 Operating Plan for Current Environment: ENHANCE FINANCIAL PROFILE 2016 CAPEX projected to be within cash flow Stable production - limit “growth” capital expenditures 5,227 net acre Ward/Reeves County, Texas sale 12,178 net acres surface in Pecos County, Texas sale LOWER OPERATING EXPENSES Shut in marginal production and optimize portfolio Allocate budget to investments that lower production costs Curtail and optimize G&A where necessary ECONOMICIALLY GROW AND PRESERVE INVENTORY Preserve future growth outlook by running Bakken drilling rig when economics dictate Continue to allocate capital to projects that generate strong risk adjusted returns WAIT FOR THE RIGHT DEAL Lots of distress on the market – wait for the right deal in the right area Any deal must 1. Not stress the balance sheet and 2. Be accretive Operating Plan for Current Environment
10 III. Financial Overview
11 Abraxas’ Reserve Conservatism Example: Seaport Global recently conducted a study titled “Perception versus Reality.” In this report Seaport Global compared actual results to projected well results. Abraxas scored in the top three of actual results versus projections…for the industry. (1) Seaport Global June 18, 2015.
12 2016 Operating and Financial Guidance 2016E Production Low High Total (Boepd) 5,800 6,300 % Oil 64% % NGL 11% % Natural Gas 25% Operating Costs Low High LOE ($/BOE) $9.50 $11.50 Production Tax (% Rev) 9.5% 10.0% Cash G&A ($mm) $7.0 $9.0 CAPEX (midpoint, $mm) $28.8
13 IV. Asset Base Overview
14 North Fork/Lillibridge 30 operated completed wells 6 operated wells waiting on completion 1 non-operated well waiting on completion Nine planned multi-well pads at 660 foot spacing 46 additional operated wells at 660 foot spacing 2nd Bench TF test Recent participation in successful offsetting well ~20 additional potential operated locations Additional 3rd Bench Three Forks potential Bakken / Three Forks North Fork/Lillibridge Potential
15 Well Objective Lat. Length (1) Stages (1) 30-day IP (boepd) (1,2) Status Ravin 1H Three Forks 10,000 23 391 Producing Stenehjem 1H Middle Bakken 6,000 17 688 Producing Jore Federal 3H Three Forks 10,000 35 510 Producing Ravin 26-35 2H , 3H Middle Bakken 10,000 16 524 Producing Lillibridge 2H, 4H Three Forks 9,000 28 940 Producing Lillibridge 1H, 3H Middle Bakken 10,000 33 1,283 Producing Lillibridge 6H, 8H Three Forks 10,000 33 971 Producing Lillibridge 5H, 7H Middle Bakken 10,000 34 1,027 Producing Jore 1H Three Forks 10,000 33 1,037 Producing Jore 2H, 4H Middle Bakken 10,000 33 904 Producing Ravin 4H, 5H, 6H, 7H Middle Bakken 10,000 33 1,254 Producing, first MB downspacing test Stenehjem 2H, 4H Three Forks 10,000 33 863 Producing, first TF downspacing test Stenehjem 3H Middle Bakken 10,000 33 1,057 Producing Jore 5H, 6H, 7H, 8H Middle Bakken 10,000 33 819 Producing Stenehjem 5H Middle Bakken 10,000 33 809 Producing Sten-Ravin 1H, Ravin 8H Three Forks 10,000 33 900 Producing Stenehjem 10H Three Forks 10,000 NA NA Lateral cased Stenehjem 11H Middle Bakken 10,000 NA NA Lateral cased Stenehjem 12H Three Forks 10,000 NA NA Lateral cased Stenehjem 13H Middle Bakken 10,000 NA NA Lateral cased Stenehjem 14H Three Forks 10,000 NA NA Lateral cased Stenehjem 15H Middle Bakken 10,000 NA NA Lateral cased Bakken / Three Forks Focused on Execution (1) Represents the approximate, average lateral length, number of stages and 30-day IP for each group of wells. (2) The production rates for each well do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas.
16 Austin Chalk Jourdanton Jourdanton 7,352 net acre lease block, 100% WI 90+ well Austin Chalk potential North Fault Block ▫ Held by production ▫ 44+ potential well locations South Fault Block ▫ One unit held by production ▫ 42+ potential well locations Austin Chalk ▫ Oil generated in Eagle Ford may have migrated up to Austin Chalk in graben settings, like Jourdanton ▫ Erratic production from vertical wells in grabens ▫ Good log and mud log shows in Abraxas wells ▫ Recent completions by third parties in Karnes Trough (Graben) very promising
17 Abraxas Reeves/Ward County Assets Potential Wolfcamp & Bone Spring Divestiture 5,227 net HBP acres located on eastern edge of Delaware basin and western edge of central basin platform (CBP) Bone Spring through Wolfcamp interval contains best potential for exploitation using horizontal wells and multi-stage frac treatments ▫ Bone Spring through Wolfcamp interval is thinner than in basin, but it has a similar sequence of shale, limestone and sandstone ▫ Interval is also overpressured in the area; vertical wells require a drilling liner and 12-15#/gal mud to get through the 3rd Bone Spring, Wolfcamp and Penn interval ▫ Several vertical wells, including ones in the offering, have production or excellent oil shows from the interval Structural complexity is great in the deeper gas zones with numerous faults, steep dip, and gas accumulation controlled by structural closure. However, virtually all the faults lose throw upward in the Pennsylvanian and Wolfcamp interval. Top Wolfcamp structure is much simpler than deeper zones
18 Concept Residual oil resides as strands or stringers Indigenous microbes activated by nutrients Surface tension between oil and water is altered Oil “freed” in injection area adds to stringer, which pushes oil into producer Vendor: Glori Energy Total residual oil in 3 main reservoirs: 50 MMBO (approx.), 42% of OOIP Potential recovery: 5-10% of OOIP = 6-12 MMBO CAPEX for 8 month pilot: ~$670 K Postponed until market conditions improve Injection Well Production Well Portilla Field Potential MEOR
19 Why Abraxas? Low Risk Bakken Development Substantial Unbooked Potential Upside Significant Operational and Financial Flexibility Strong Rate of Return Driven Production Growth Prudent Financial Management
20 Appendix
21 Additional Assets Opportunity Overview Abraxas Assets 2016 Development Powder River Basin Stacked pay, liquids-rich horizontal opportunities in Campbell, Converse and Niobrara Counties, Wyoming Primarily in Converse and Campbell counties Appx 2,088 net acres at Porcupine and 14,245 net acres at Brooks Draw Hedgehog State 16-2H: Cum prod. (34 mos): 350 mboe, 23% Oil No capital budgeted for 2016 Permian Basin Large inventory conventional and unconventional targets Emerging, oil-focused horizontal drilling opportunities 28,370 total net acres Average production 856 boepd, ~23% oil (1) No capital budgeted for 2016 Raven Drilling Abraxas 100% wholly owned subsidiary $16.3 million in NBV secured against $2.7 million in rig debt (2) One 2,000 horsepower, SCR walking rig currently pad drilling in the Bakken Subsidiary includes man camp and additional related rig equipment No capital budgeted for 2016 Surface / Yards / Field Offices / Building Surface ownership in numerous legacy areas Net book value of $11.2 million (2) Surface : 610 acres Scurry, TX; 1,769 acres in San Patricio, TX; 12,178 acres Pecos, TX; 590 acres McKenzie, ND; 50 acres DeWitt, TX; 15 acres Atascosa, TX Yards/Offices/Structures: Sinton, TX; Scurry, Texas; McKenzie, ND; 24,924 square foot office building No capital budgeted for 2016 (1) Average for month of December 31, 2015 (2) As of December 31, 2015
22 Abraxas’ Eagle Ford Properties ~10,819 Net Acres Jourdanton Area Atascosa County Black oil 7,352 net acres Cave Area McMullen County Black oil 411 net acres Dilworth East Area McMullen County Oil/condensate 1,148 net acres Yoakum Area (not shown) Dewitt and Lavaca County Dry gas 1,908 net acres Jourdanton Area Cave Area Dilworth East Area
23 Eagle Ford Jourdanton Jourdanton 7,352 net acre lease block, 100% WI 90+ well Eagle Ford potential Austin Chalk and Buda also prospective North Fault Block ▫ Held by production ▫ Eight wells drilled ▫ 36+ additional potential well locations South Fault Block ▫ One well drilled ▫ 42+ additional potential well locations
24 Eagle Ford Dilworth East Dilworth East 1,148 acre lease block, 100% WI 11 additional locations (red) ▫ Eight, 5,000-5,500’ lateral locations ▫ Three, 8,500’ lateral locations R. Henry 2H ▫ 30 day IP: 780 boepd (1) ▫ On production R. Henry 1H ▫ 30 day IP: 703 boepd (1) ▫ On production (1) The production rates for each well do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas.
25 Eagle Ford Cave Cave 411 net acre lease block, 100% WI Lower Eagle Ford fully developed ▫ Four 9,000’ lateral locations Best month cumulative oil shown in green ▫ Offset operators : 8-10 mbo ▫ Abraxas Dutch 2H: 29 mbo Dutch 1H ▫ 30 day IP: 786 boepd (1) Dutch 2H ▫ 30 day IP: 1,093 boepd (1) Dutch 3H ▫ 30 day IP: 888 boepd (1) Dutch 4H ▫ 30 day IP: 926 boepd (1) (1) The production rates for each well do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas.
26 Well Area Lat. Length (1) Stages (1) 30-day IP (boepd) Status T-Bird 1H Nordheim 5,102 15 1,202 (2) Sold 13 WyCross Wells WyCross 5,000 – 7,500 18 – 29 466 – 1,184 (2,3) Sold Blue Eyes 1H Jourdanton 5,000 22 527 (2,4) Producing Snake Eyes 1H Jourdanton 5,000 18 759 (2,4) Producing Spanish Eyes 1H Jourdanton 5,000 19 213 (2,4) Producing Eagle Eyes 1H Jourdanton 3,800 18 249 (2,4) Producing Ribeye 1H Jourdanton 7,000 21 240 (2,4) Producing Ribeye 2H Jourdanton 7,000 28 389 (2,4) Producing Cat Eye 1H Jourdanton 7,000 26 491 (2,4) Producing Grass Farm 2H Jourdanton 5,000 29 193 (2,4) Producing Dutch 2H Cave 9,000 36 1,093 (2) Producing Dutch 1H Cave 9,000 37 786 (2) Producing Dutch 3H Cave 9,000 37 888 (2) Producing Dutch 4H Cave 9,000 37 926 (2) Producing R Henry 2H Dilworth East 5,000 19 780 (2) Producing R. Henry 1H Dilworth East 5,000 34 703 (2) Producing Eagle Ford Focused on Execution (1) Represents the approximate, average lateral length and number of stages for each well. (2) The production rates for each well do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas. (3) Represents the range for WyCross wells. (4) 30 day IP equivalent to highest 30 days of production after the well was placed on sub-pump.
27 Powder River Basin Turner Sandstone Horizontal Play Powder River Basin: Turner Sandstone Isopach of Turner thickness Multiple producing vertical wells, tight sandstone Horizontal exploitation with multi-stage fracs recently Porcupine Area ▫ Approximately 2,088 net acres Brooks Draw Area ▫ Approximately 14,245 net acres
28 Edwards (South Texas) PDP: 6.9 bcfe (net)(3) Previous risked offsetting PUD locations: 27.9 bcfe (net) (4) ▫ 11 gross / 7 net locations dropped to PRUD (SEC 5 year rule) 7 gross / 5 net locations drilled / completed, yet to be frac’d: unbooked Edwards economics ▫ New drill: $7.0 million well / 4.0 bcfe EUR / F&D $1.73/mcfe (4) ▫ 20% ROR at $4.30/mcfe realized price (4) ▫ Refrac: $0.7 million well / 0.5 bcfe EUR / F&D $1.40/mcfe (4) ▫ 20% ROR at $1.98/mcfe realized price (4) Montoya / Devonian (Delaware Basin, West Texas) PDP 17.1 bcfe (net) (3) PUD locations: 22.5 bcfe (net) (4) ▫ 12 gross/ 6 net locations ▫ $22.1 million PV-10 value at $2.36 realized gas(3) Other Eagle Ford Shale, Yoakum: 1,908 net acres / ~24 net locations, unbooked Permian, Hudgins Ranch: 3 gross / 2.6 net PSUD locations, 9.1 bcfe (net) (4) Williston Basin, Red River: 1 gross / .8 net PRUD location, 2.1 bcfe (net) (4) (1) Net of purchase price adjustments (2) PV10 calculated using strip pricing and internal reserve report as of 5/1/12; production and reserves as of 5/1/12. (3) Based on December 31, 2015 reserves. (4) Management estimate 2012 Ward County Acquisition Acquisition of Partners’ Interests in West Texas Purchase Price $6.7mm(1) PDP PV -15 $6.7mm(2) Production 1,440 mcfepd(2) Reserves 7.613 bcfe(2) Production $4,650/mcfe/day Reserves: $.88/mcfe Abraxas’ “Hidden” Gas Portfolio
29 Sharon Ridge/Westbrook: Clearfork Trend 89 active wells ▫ San Andres, Glorietta, Clearfork ▫ Cooperative water flood on some leases 110 potential (1) new-drills, recompletes or workovers Abraxas New Drill Type Curve ▫ 31 Mbo (100% oil) ▫ Gross/Net CWC: $0.75/$0.6 million Permian Basin Sharon Ridge - Westbrook: Clearfork Trend (1) Potential locations and prospective acres based on an internal geologic and technical evaluation of the area and offset activity. These locations have yet to be audited by our third party engineer Degolyer & Macnaughton.
30 Howe Deep: One active Montoya well Five active Devonian wells Horizontal Wolfcamp Potential Cum production (1) ▫ ~62 bcf Gross Current production (2) ▫ 1,365 mcfepd Net Permian Basin Howe Deep (1) Cum production estimated through December 31, 2015. (2) Monthly average for the month of December 2015
31 R.O.C. Deep: Six active Montoya wells Four active Devonian wells One active Ellenburger well Cum production (1) ▫ ~138 bcf Gross Current production (2) ▫ 715 mcfepd Net Permian Basin R.O.C. Deep (1) Cum production estimated through December 31, 2015. (2) Monthly average for the month of December 2015.
32 Abraxas Hedging Profile (1) Straight line average price. (2) 2000 bbls/day Jun 2015 – Dec 2015 WTI Collars 2016 2017 Oil Swaps (bbls/day) 948 608 NYMEX WTI (1) $84.10 $78.55 Oil Collars (bbls/day) 1000 Average WTI Ceiling $71.00 Average WTI Floor $60.00 Average WTI Sub-Floor $45.00 Natural Gas (mmbtu/day) NYMEX Henry Hub (1)
33 EBITDA Reconciliation EBITDA is defined as net income plus interest expense, depreciation, depletion and amortization expenses, deferred income taxes and other non-cash items. The following table provides a reconciliation of EBITDA and Adjusted EBITDA to net income for the periods presented. (In thousands) 2013 2014 2015 Net income $38,647 $63,268.73 ($119,055) Net interest expense 4,577 2,009 3,340 Income tax expense 700 (287) (37) Depreciation, depletion and amortization 26,632 43,139 38,548 Amortization of deferred financing fees 1,367 934 1,130 Stock-based compensation 2,114 2,703 3,912 Impairment 6,025 0 128,573 Unrealized (gain) loss on derivative contracts (2,561) (24,876) (18,417) Realized (Gain) loss on interest derivative contract 0 0 0 Realized (Gain) loss on monetized derivative contracts 0 0 5,061 Earnings from equity method investment 0 0 0 (Gain) loss on discontinued operations (33,377) (1,318) 20 Other non-cash items 539 0 883 EBITDA $44,663 $85,572 $43,957 Credit facility borrowings $33,000 $70,000 $134,000 Debt/EBITDA 0.74x 0.82x 3.05x
34 TTM EBITDA Reconciliation EBITDA is defined as net income plus interest expense, depreciation, depletion and amortization expenses, deferred income taxes and other non-cash items. The following table provides a reconciliation of EBITDA and Adjusted EBITDA to net income for the periods presented. (In thousands) Three Months End 31-Mar-15 30-Jun-15 30-Sep-15 31-Dec-15 TTM Net income $7,407 ($6,429) ($52,372) ($67,661) ($119,055) Net interest expense 694 816 847 983 3,340 Income tax expense 0 0 0 (37) (37) Depreciation, depletion and amortization 12,069 8,637 10,165 7,677 38,548 Amortization of deferred financing fees 644 162 162 162 1,130 Stock-based compensation 810 1,440 835 826 3,912 Impairment 0 0 59,891 68,682 128,573 Unrealized (gain) loss on derivative contracts (9,806) 5,470 (10,474) (3,608) (18,417) Realized (Gain) loss on interest derivative contract 0 0 0 0 0 Realized (Gain) loss on monetized derivative contracts 0 5,061 0 0 5,061 Earnings fro equity method investment 0 0 0 0 0 (Gain) loss on discontinued operations 20 0 0 0 20 Other non-cash items 139 143 144 457 883 EBITDA $11,977 $15,301 $9,199 $7,480 $43,957 Credit facility borrowings $134,000 Debt/EBITDA 3.05x
35 Standardized Measure Reconciliation PV-10 is the estimated present value of the future net revenues from our proved oil and gas reserves before income taxes discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2014: Total Proved 31-Dec-14 Future Gross Revenue $2,946,483 Production and Ad Valorem Taxes (278,791) Operating Expenses (613,162) Capital Costs (551,591) Abandonment Costs (5,654) Future Net Revenue 1,497,285 Present Worth at 10 Percent 637,443 Present value of future income taxes discounted at 10% (147,907) Standardized measure of discounted future net cash flows $489,536
36 NASDAQ: AXAS