Current Report Filing (8-k)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

January 19, 2016

Date of Report (Date of earliest event reported)

ABRAXAS PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)



Nevada	1-16071	74-2584033
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification Number)

18803 Meisner Drive

San Antonio, Texas 78258

(210) 490-4788

(Address of principal executive offices and Registrant’s telephone number, including area code)

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):


o	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)


o	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)


o	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))


o	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e- 4(c))

Item 7.01 Regulation FD Disclosure

Abraxas meets with analysts and investors on a regular basis. The January 2016 Corporate Update, attached as Exhibit 99.1 will be used in these discussions.

The information in this Report (including Exhibit 99.1) is furnished pursuant to Item 7.01 and shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of the Section. The information in this Report will not be deemed an admission as to the materiality of any information required to be disclosed solely to satisfy the requirements of Regulation FD.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.


99.1	Presentation

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 hereunto duly authorized.

ABRAXAS PETROLEUM CORPORATION

By: /s/ Geoffrey R. King

Geoffrey R. King

Vice President, Chief Financial Officer

Dated: January 19, 2016

Abraxas Petroleum Corporate Update January 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)............................ 91 Shares outstanding(2)……......... 106.3 mm Market cap(4) …………………….... $112.7 mm Net debt(3)………………………….. $127.8 mm PV-10(8)……………………………….. $637.4 mm (1) As of January 8, 2016. Does not include nine employees associated with the Company’s wholly owned subsidiary, Raven Drilling. (2) Shares outstanding for the quarter ended September 30, 2015. (3) Total debt including RBL facility, rig loan and building mortgage less cash as of September 30, 2015. (4) Share price as of December 31, 2015. (5) Enterprise value includes working capital deficit (excluding current hedging assets and liabilities) as of September 30, 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 September 30, 2015. (7) Calculation using average production for the quarter ended September 30, 2015 annualized and net proved reserves as of December 31, 2014. (8) Proved reserves as of December 31, 2014. Uses SEC YE2014 average pricing of $95.28/bbl and $4.35/mcf. See appendix for reconciliation of PV-10 to standardized measure. EV/BOE(3,4,5)………………………... $6.06 Proved Reserves(8).…………..... 42.4 mmboe % Oil………………………….. ~69% % Proved developed….. ~41% Production(6).……………………… 6,004 boepd R/P Ratio(7)…………………………. 19.4x 2016E CAPEX……………………. $25-40 mm NASDAQ: AXAS Corporate Profile

5 Proved Reserves(1) – 42.4 mmboe Production(2) – 6,004 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, 2014. (2) For the quarter ended September 30, 2015. Oil 69% Gas 22% NGL 9% Gulf Coast/ Eagle Ford 34% Rockies 55% Permian 11% Gulf Coast/ Eagle Ford 24% Rockies 62% Permian 14% Oil Sales 90% Gas Sales 8% NGL Sales 2%

6 (Bo p d ) (1) Total Debt includes RBL facility, Rig Loan and Building Loan. TTM recurring EBITDA. Equivalent to Revenue – Realized Hedge Settlements – LOE – Production Taxes – Cash G&A – Other Expenses. Does not include EBITDA contribution from Raven Drilling or contributions from liquidated hedge settlements. Please see appendix for EBITDA reconciliation. (2) 2015 estimate assumes the midpoint of 2015 guidance of 5,800 – 6,500 boepd and 2015 guidance for an average 69% crude oil production percentage. Prudent Growth Growing Oil Volumes while Prudently Managing the Balance Sheet (D eb t/ T TM R ec u rr in g EB IT D A ) Daily Oil Production vs. Debt/TTM Recurring EBITDA (1) 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 2010A 2011A 2012A 2013A 2014A 2015E (2) Oil Production Debt/TTM Recurring EBITDA (1)

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, Emerging Hz Oil Rocky Mountain Gulf Coast Permian Basin Legend Proved Reserves (mmboe)(1): 42.4  Proved Developed(1): 41%  Oil(1): 69% Abraxas Petroleum Corporation Core Regions (1) Net proved reserves as of December 31, 2014.

8 II. Strategic Plan

9 Operating Plan for Current Environment: PRESERVE FAVORABLE FINANCIAL PROFILE  September re-affirmation of $165 million fully conforming Borrowing Base  2016 CAPEX projected to be within cash flow  Stable production - limit “growth” capital expenditures 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 continuing to run the Bakken drilling rig  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) 5,900 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) $8.0 $9.0 CAPEX (midpoint, $mm) $32.5

13 IV. Asset Base Overview

14 Bakken / Three Forks Positioned in Core Areas North Fork 5,209 Net Acres North Fork Area  McKenzie County, ND Lillibridge Area  McKenzie County, ND South Elm Coulee Area  Richland County, MT Lillibridge South Elm Coulee

15 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  Assumes downspacing approval by NDIC  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

16 Bakken / Three Forks North Fork/Lillibridge Performance/Economics Middle Bakken: ROR vs CAPEX (1) (1) Uses strip pricing as of September 28, 2015. Uses Abraxas type curve. Uses average 12 month differentials for oil/gas/NGLs as of June 30, 2015. D&M/Booked Assumptions  533 MBOE gross type curve ▫ 78% Oil ▫ Initial rate: 17,950 bopm ▫ di: 99.3% ▫ dm: 7.0% ▫ b-factor: 1.5  Booked CWC: $8.5 million  Recent CWC $6.3 million (before pump) Middle Bakken: Type Curve Assumptions 0 20 40 60 80 100 0 200 400 600 800 1000 1200 1 31 61 91 121 151 181 211 241 271 301 331 361 W ELL COUN T B O E DAYS Abraxas Bakken Wells, McKenzie ND All Well Average vs Type 0 5 10 15 20 25 30 $5,000 $6,000 $7,000 $8,000 $9,000 R OR ( % ) CAPEX (M$)

17 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.

18 Portilla Field San Patricio County, TX Portilla Field  Annual CAPEX of ~$1 million to maintain flat decline rate  Infill and work over opportunities  100% WI ownership  Abraxas owns 1,769 surface acres  Cum Production (1) ▫ ~80 mmbo + ~92 bcf Gross from Frio sands  Current Production (2) ▫ 231 boepd Net 100% Surface Ownership (1) Cum production estimated through December 31, 2014. (2) Monthly average for the month of December 2014.

19 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 Commencing March 2016 Injection Well Production Well Portilla Field Potential MEOR

20 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

21 Appendix

22 Additional Assets Opportunity Overview Abraxas Assets 2015 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 2015 Permian Basin  Large inventory conventional and unconventional targets  Emerging, oil-focused horizontal drilling opportunities  30,891 total net acres  Average production 913 boepd, ~50% liquids (1)  Reworks Raven Drilling  Abraxas 100% wholly owned subsidiary  $17.8 million in NBV secured against $3.1 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 2015 Surface / Yards / Field Offices / Building  Surface ownership in numerous legacy areas  Surface/Yards Field Offices: $8.9 million of Book / Appraised / Tax Value (3)  Building: appraised value ~$6.1 million secured against $4.2 million mortgage (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 2015 (1) Average for month of December 31, 2014 (2) As of September 30, 2015 (3) As of December 31, 2015

23 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

24 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  Abraxas Type Curve ▫ 267 Mboe (Gross, 5,000’ lateral) ▫ 95% oil ▫ Booked CWC: $7.0 million

25 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  Abraxas Type Curve ▫ 219 Mboe (Gross, 5,000’ lateral) ▫ 57% oil ▫ Booked CWC: $7.5 million (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 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.

27 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.

28 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

29 Powder River Basin Campbell & Converse Co., WY Powder River Basin: Turner Sandstone  Porcupine Field ▫ 26/9 gross/net wells ▫ Approximately 2,300 net acres  Permitting two additional locations  Hedgehog State 16-2H ▫ Cum Production (1): 350 mboe (1) Cum production estimated through January 15, 2016. Hedgehog 16-2H Production

30 Edwards (South Texas)  PDP: 8.3 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 (5) ▫ 20% ROR at $4.30/mcfe realized price (5) ▫ Refrac: $0.7 million well / 0.5 bcfe EUR / F&D $1.40/mcfe ▫ 20% ROR at $1.98/mcfe realized price (5) Montoya / Devonian (Delaware Basin, West Texas)  PDP 17.1 bcfe (net) (3)  Previous risked offsetting PUD locations: 29.7 bcfe (net) (4) ▫ 12 gross/ 6 net locations dropped to PRUD (SEC 5 year rule)  Montoya economics ▫ $5.0 million well / 6.6 bcfe EUR / F&D $.75/mcfe (5) ▫ 20% ROR at $3.16/mcfe realized price (5)  Devonian economics ▫ $5.8 million well / 7.6 bcfe EUR / F&D $0.76/mcfe (5) ▫ 20% ROR at $2.51/mcfe realized price (5) 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) (5)  Williston Basin, Red River: 1 gross / .8 net PRUD location, 2.1 bcfe (net) (5) (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, 2013 reserves. (4) Management estimate based on previously booked PUD reserves. (5) 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

31 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.

32 Ward County  2,592/2,196 gross/net prospective (1) acres  28 potential (1) gross Wolfcamp locations ▫ Potential (1) Wolfcamp locations shown in green ▫ Wolfcamp production shown in red ▫ Wolfcamp permits show in in blue ▫ Wells shown > 7,600’ Permian Basin Reeves/Ward County Bone Spring/Wolfcamp Potential Ward County  413/340 gross/net prospective (1) acres  3 potential (1) gross 2nd Bone Spring locations ▫ Potential (1) Bone Spring locations shown in green ▫ Bone Spring production shown in red ▫ Wells shown > 7,600’ (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.

33 Abraxas Cherry Canyon Field:  30 Active Wells, three zones  Waterflood potential ▫ 27 active wells ▫ Eight Proposed Injection Wells  Horizontal potential  Cum production (1) ▫ ~5 mmboe Gross  Current production (2) ▫ 149 boepd Net Permian Basin Bell, Cherry and Brushy Canyon Production (1) Cum production estimated through December 31, 2014. (2) Monthly average for the month of December 2014.

34 Howe Deep:  One active Montoya well  Five active Devonian wells  Horizontal Wolfcamp Potential  Cum production (1) ▫ ~62 bcf Gross  Current production (2) ▫ 952 mcfepd Net Permian Basin Howe Deep (1) Cum production estimated through December 31, 2014. (2) Monthly average for the month of December 2014.

35 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) ▫ 1,351 mcfepd Net Permian Basin R.O.C. Deep (1) Cum production estimated through December 31, 2014. (2) Monthly average for the month of December 2014.

36 Abraxas Hedging Profile (1) Straight line average price. (2) 2000 bbls/day Jun 2015 – Dec 2015 WTI Collars Remainder 2015 2016 2017 Oil Swaps (bbls/day) 948 608 NYMEX WTI (1) $84.10 $78.55 Oil Collars (bbls/day) 2000 (2) 1000 Average WTI Ceiling $70.00 $71.00 Average WTI Floor $55.00 $60.00 Average WTI Sub-Floor $45.00 Natural Gas (mmbtu/day) 1450 NYMEX Henry Hub (1) $4.04

37 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) Year End Three Months End 2010 2011 2012 2013 2014 Net income $1,766 $13,743 ($18,791) $38,647 $62,994 Net interest expense 9,098 4,891 5,516 4,577 2,009 Income tax expense (79) (77) 310 700 (12) Depreciation, depletion and amortization 16,212 16,194 23,016 26,632 43,139 Amortization of deferred financing fees 2,479 1,762 937 1,367 934 Stock-based compensation 1,560 1,987 2,091 2,114 2,703 Impairment 4,787 0 19,774 6,025 0 Unre lized (gain) loss on derivative contracts (10,285) (7,476) (2,669) (2,561) (24,876) Realized (Gain) loss on interest derivative contract 0 0 214 0 0 E ings fro equity method investment 473 (2,187) (2,207) 0 0 (Gain) on sale of properties 0 0 0 (33,377) (1,318) Other non-cash items (119) 316 97 539 0 EBITDA $25,892 $29,153 $28,288 $44,663 $85,572 Credit facility borrowings $136,000 $115,000 $113,000 $33,000 $70,000 Debt/EBITDA 5.3x 3.9x 4.0x 0.7x 0.8x

38 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-Dec-14 31-Mar-15 30-Jun-15 30-Sep-15 TTM Net income $30,132 $3,961 ($6,601) ($52,372) ($24,879) Net interest expense 503 694 816 847 2,860 Income tax expense (287) 0 0 0 (287) Depreciation, depletion and amortization 12,698 12,069 8,810 10,165 43,742 Amortization of deferred financing fees 155 481 162 162 960 Stock-based compensation 653 810 1,440 835 3,738 Impairment 0 0 0 59,891 59,891 Unrealized (gain) loss on derivative contracts (22,977) (6,198) 5,470 (10,474) (34,179) Realized (Gain) loss on interest derivative contract 0 0 0 0 0 Realized (Gain) loss on monetized derivative contracts 0 0 5,057 0 5,057 Ea nings fro equity method investment 0 0 0 0 0 (Gain) loss on discontinued operations (1,840) 20 0 0 (1,821) Other non-cash items 140 139 143 144 566 EBITDA $19,177 $11,977 $15,296 $9,199 $55,649 Credit facility borrowings $120,000 Debt/EBITDA 2.16x

39 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