Exhibit 99.2

Investor Presentation August 2015

Disclaimers This presentation has been prepared by Sundance Energy Australia Limited (ABN 76 112 202 883). Summary information The following disclaimer applies to this document and any information contained in it (the “Information”). The Information in this presentation is of general background and does not purport to be complete. It should be read in conjunction with Sundance’s other periodic and continuous disclosure announcements lodged with ASX Limited, which are available at www.asx.com.au. You are advised to read this disclaimer carefully before reading or making any other use of this document or any information contained in this document. In accepting this document, you agree to be bound by the following terms and conditions including any modifications to them. Not financial or product advice This presentation is for information purposes only and is not a prospectus, product disclosure statement or other offer document under Australian law or the law of any other jurisdiction. This presentation is not financial product or investment advice or a recommendation to acquire Sundance shares, legal or tax advice. This presentation has been prepared by Sundance without taking into account the objectives, financial situation or needs of individuals. You are solely responsible for forming your own opinions and conclusions on such matters and the market and for making your own independent assessment of the Information. You are solely responsible for seeking independent professional advice in relation to the Information and any action taken on the basis of the Information. Before making an investment decision prospective investors should consider the appropriateness of the information having regard to their own objectives, financial and tax situation and needs and seek legal and taxation advice appropriate to their jurisdiction. Sundance is not licensed to provide financial product advice in respect of Sundance shares. Cooling off rights do not apply to the acquisition of Sundance shares. Financial data All share price information is in Australian dollars (A$) and all other dollar values are in United States dollars (US$) unless stated otherwise. Sundance’s results are reported under Australian International Financial Reporting Standards. Past performance Past performance information given in this presentation is given for illustrative purposes only and should not be relied upon as (and is not) an indication of the Company’s views on its future financial performance or condition. Investors should note that past performance, including past share price performance, of Sundance cannot be relied upon as an indicator of (and provides no guidance as to) future Sundance performance including future share price performance. Investment risk An investment in Sundance shares is subject to investment and other known and unknown risks, some of which are beyond the control of Sundance. Sundance does not guarantee any particular rate of return or the performance of Sundance, nor does it guarantee the repayment of capital from Sundance or any particular tax treatment. Persons should have regard to the risks outlined in the Information.

Disclaimers (cont’d) Disclaimer Except as required by law, no representation or warranty (express or implied) is made as the fairness, accuracy, completeness, reliability or correctness of the Information, opinions and conclusions, or as to the reasonableness of any assumption contained in this document. By receiving this document and to the extent permitted by law, you release Sundance and its officers, employees, agents and associates from any liability (including, without limitation, in respect of direct, indirect or consequential loss or damage or loss or damage arising by negligence) arising as a result of the reliance by you or any other person on anything contained in or omitted from this document. Forward Looking Statements This presentation includes forward-looking statements. These statements relate to Sundance’s expectations, beliefs, intentions or strategies regarding the future. These statements can be identified by the use of words like “anticipate”, “believe”, “intend”, “estimate”, “expect”, “may”, “plan”, “project”, “will”, “should”, “seek” and similar words or expressions containing same. The forward-looking statements reflect the Company’s views and assumptions with respect to future events as of the date of this presentation and are subject to a variety of unpredictable risks, uncertainties, and other unknowns. Actual and future results and trends could differ materially from those set forth in such statements due to various factors, many of which are beyond our ability to control or predict. Given these uncertainties, no one should place undue reliance on any forward-looking statements attributable to Sundance, or any of its affiliates or persons acting on its behalf. Although every effort has been made to ensure this presentation sets forth a fair and accurate view, we do not undertake any obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Reserves This presentation contains information on Sundance Energy’s reserves and resources which has been reviewed by Sarah Fenton, Professional Engineer, who is licensed in the state of Colorado, USA and is qualified in accordance with ASX Listing Rule 5.11. Mrs. Fenton, Director of Reservoir Engineering, has consented to the inclusion of this information in the form and context in which it appears. Reserve Estimates The Company’s Reserve estimates are calculated by Netherland, Sewell & Associates, Inc. as at 1 January 2015 in accordance with SEC guidelines. Although current market prices have fallen significantly, under SEC guidelines, the commodity prices used in the December 31, 2014 and December 31, 2013 reserve estimates were based on the 12-month unweighted arithmetic average of the first day of the month prices for the period January 1, 2014 through December 1, 2014, and for the period January 1, 2013 through December 1, 2013, respectively, adjusted by lease for transportation fees and regional price differentials. For crude oil volumes, the average West Texas Intermediate posted price of $91.48 per barrel used to calculate PV-10 at December 31, 2014 was down $1.94 per barrel from the average price of $93.42 per barrel used to calculate PV-10 at December 31, 2013. For natural gas volumes, the average Henry Hub spot price of $4.35 per million British thermal units ("MMBTU") used to calculate PV-10 at December 31, 2014 was up $0.68 per MMBTU from the average price of $3.67 per MMBTU used to calculate PV-10 at December 31, 2013. All prices were held constant throughout the estimated economic life of the properties.

Company Overview Superior Performance through Commodity Cycles Note: Above based on Company filings, press releases and 1 January 2015 NSAI reserve report. Market capitalization and enterprise value shown as of 29 Jul 2015, based on 30 June 2015 debt of $155mm and cash of $3.5mm; Production numbers represent 2Q15 average daily production (1) Based on analysts’ consensus estimates (2) Excludes evaluation of the majority of the Company’s potential Woodford locations 2015 Company guidance Includes New Standard Energy acquisition which close on 7 August 2015 Net acres: ~33,775 1P reserves: 7.8 mmboe(2) Production: 1,329 boed % operated: 60.6% % WI: 43.2% Counties: Logan, Noble and Garfield Greater Anadarko Mississippian / Woodford Net acres: ~38,000(4) 1P reserves: 20.9 mmboe(4) Production: 7,235 boed % operated: 99.6% % WI: 70.5% Counties: McMullen, Dimmit, Atascosa, and Live Oak South Texas Eagle Ford Ticker: SEA (ASX Listed) Share count: 553.1 million Market capitalization: A$263 million Enterprise value: US$344 million 2015 Consensus EBITDAX: $89 million(1) Proved reserves: 26.0 mmboe (65% oil) SEC Pre-tax 1P PV-10: $532 million 1H15 daily production: 8,556 boed (66% oil) 2015 Full year production: 7,850 – 8,500 boed(3) 2015 Capital expenditures: $90MM(3) Eagle Ford focused asset base

Management Team Eric McCrady, Managing Director & CEO Eric was appointed CEO in April 2011 and Managing Director of the Board in November 2011. He served as CFO from June 2010 until becoming CEO. Eric has over 15 years of entrepreneurial experience with an extensive track record in investment evaluation and management, acquisitions and divestitures, strategic planning, general management, risk management, and capital formation with companies including The Broe Group, a private investment firm, GE Capital and American Coin Merchandising. Cathy Anderson, Chief Financial Officer Cathy was appointed CFO in December 2011. Cathy is a Certified Public Accountant with over 30 years experience, primarily in the oil and gas industry, in budgeting and forecasting, regulatory reporting, corporate controls, financial analysis and management reporting with various public and private companies including Key Production (predecessor of Cimarex), OptiGas and Arthur Andersen. Grace Ford, Chief Operating Officer Grace was appointed Chief Operating Officer in July 2015 and VP of Exploration and Development in March 2013. She served as VP of Geology from September 2011. Grace has over 17 years of technical experience focused on geology resource play evaluation and development, exploration, well and completion design, and reservoir characterization with companies including EOG Resources, Baytex Energy USA and Marathon. Mike Wolfe, Vice President, Land Mike was appointed VP of Land in March 2013. He served as Senior Land Manager from December 2010. Mike has over 30 years of senior land management experience including field leasing, acquisitions and divestitures, title, lease records, and management of a multi-rig drilling program with companies such as Cimarex and Texaco. John Whittington, Vice President, Operations John was appointed VP of Operations in May 2014. He has over 20 years experience focused on the development and optimization of onshore US resource plays with a particular focus on completion optimization and production operations with companies including Triangle Petroleum, EOG, Schlumberger, and Apex Petroleum Engineering.

Investment Thesis Premier Eagle Ford Production Base and Drilling Inventory ~38,000 net acres targeting the volatile oil and black oil window of the Eagle Ford 2015E production of 8,150 boepd generates cash flow to fund growth through the drill bit High quality technical team has driven ~100% improvement in 2P EURs over past 2 years Low cost operator with cash operating costs under $14/boe and total cash costs including debt service in the $15-$17/boe range High Quality Balance Sheet and Financial Flexibility ~$100 million in liquidity at 30 June 2015 Low leverage profile with debt to trailing twelve month EBITDA of 1.3x Maintain leases and grow production/net asset value within cash flow 1 net well remaining in 2015(1); and 12 net wells in 2016 No long-term service contracts Invest in healthy growth during distressed environment Sustainable Competitive Advantage Convert the 35% reduction in spot well costs into long-term discounted service contracts Capture expiring leases from distressed competitors who cannot meet obligations Target small bolt-on acquisitions with existing production in low-price environment As of 30 June 2015

Track Record of Growth Average daily production (Boe/d 6:1) and revenue EBITDAX and EBITDAX margin Source: Company filings, press releases, and 1 January 2015 reserve report Based on 1 January 2014 NSAI reserve report Based on 1 January 2015 NSAI reserve report NSAI PV10 less debt plus net working capital; 2014 PV10 at NYMEX strip instead of SEC pricing Reserves Net Reserve Value (AUD) per Share(3) - 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 1-Jan-14 (1) 1-Jan-15 (2) mmboe Proved Reserves Probable Reserves Possible Reserves - 0.50 1.00 1.50 2.00 2.50 2012 SY12 2013 2014 2015E 2016E 2017E 0 2,000 4,000 6,000 8,000 10,000 12,000 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 $0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 $40,000 $45,000 $50,000 Revenue Boe/d 0% 20% 40% 60% 80% 100% $- $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 $40,000 $45,000 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Adjusted EBITDAX (US$000s) Adjusted EBITDAX Margin (%)

Track Record of Value Creation Cash proceeds of $167MM from 3 asset sales in 9 months prior to price decline Prospect Basin Date Transaction Value (US$) IRR Comments DJ Basin assets (Codell/Niobrara) DJ July 2014 $116MM 104% Acquired Wattenberg in 2011/2012 Acquired non-Wattenberg in 2008/2009 Divested to private buyer in 2014 Phoenix/Goliath (Bakken/Three Forks) Willison Late 2013/Early 2014 $51MM 45% Acquired in 2008/2009 Divested to 3 separate buyers in 2013/2014 South Antelope field (Bakken/Three Forks) Williston Aug 2012 $172MM 75% Acquired in 2007/2008 Divested to QEP Ashland Prospect (Woodford Shale) Arkoma Late 2007 $46.4MM 78% Entire interest sold following re-adjusted focus to oil acreage

Track Record of Operational and Financial Execution Top 25% in FY14 Field Costs per boe Top 15% in FY14 Total Cash Costs per boe Top 15% in FY14 EBITDA Margin Top 15% Balance Sheet FY14 Note: Gas is converted to boe on an economic basis 21:1 based on the ratio of oil to gas price during 2014. Field costs include lease operating expenses and production taxes. Total cash costs include Field Costs, cash general and administrative expenses and cash interest expense. EBITDAX margin is EBITDAX divided by revenue See Appendix for details on Industry Peer Group. $9.84 - 5.00 10.00 15.00 20.00 25.00 30.00 35.00 40.00 Cost per boe $18.46 - 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00 Cost per boe 77% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% EBITDA % 1.1x - 1.0 2.0 3.0 4.0 5.0 6.0 7.0 Debt to EBITDA

Maintain focus on liquids while increasing control over quality and pace of development Operated production has increased from ~66% to over 90% over the two year period Liquid production has remained consistently in the high 70% to low 80% 2 year CAGR of 139% as of March 2015 Sold and replaced ~1,750 boepd of production ~Eagle Ford 2Q13 to 1Q15 2 year CAGR ~161% 2015E production of 8,150 boepd represents a 23% increase vs. 2014 70% decrease in planned capital expenditures during 2015E/2016E compared to 2014 proactively reacting to lower commodity prices 2015E/2016E production growth substantially funded through cash flow from existing asset base Capital Efficient Production Growth Production per 1,000 debt adjusted shares Drilling and completions funded by cash flow - 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 2012 SY12 2013 2014 2015E 2016E 2017E $- $50,000 $100,000 $150,000 $200,000 $250,000 $300,000 $350,000 2013 2014 2015E 2016E 2017E D&C CapEx Op Cash Flow

Liquidity and Hedging * Includes NSE hedges acquired which include puts covering ~23,000 bbls at an average price of $87.33 on approximately 1,500 bbls per month, August 2015 through December 2016 ** Ave ceiling price does not apply to ~23,000 bbls hedged with NSE puts, as these apply only to the average floor calculation. 2015E Oil Derivative Contracts Gas Derivative Contracts millions Weighted Average Weighted Average Consensus EBITDAX $ 90.0 Bbls* Floor* Ceiling** Mcf Floor Ceiling Cash interest (10.0) 2H 2015 323,611 $ 67.30 $ 77.46 540,000 $ 3.14 $ 3.36 Operating cash flow $ 80.0 2016 425,023 59.68 77.42 720,000 2.90 3.58 2017 264,000 50.00 81.59 540,000 3.04 3.90 Development cap ex $ (90.0) 2018 204,000 55.00 81.53 420,000 3.15 4.31 New leases (15.0) 2019 168,000 55.00 87.71 360,000 3.27 4.65 Investing cash flow $ (105.0) Total 1,384,634 $ 58.36 $ 80.12 2,580,000 $ 3.07 $ 3.87 Q1 debt draw $ 13.9 Q2 debt draw 11.1 Financing cash flow $ 25.0 2015 net cash flow - Cash $ 3.5 Undrawn borrowing capacity 95.0 Liquidity at 30 June 2015 $ 98.5

Top 20% Development Economics at January 2015 strip Source: Credit Suisse Equity Research Exploration & Production Sector Review – 23 January 2015. Year: WTI Oil: NYMEX Gas: 31% 26% 26% 23% 21% 21% 20% 20% 20% 17% 17% 17% 16% 16% 15% 15% 15% 14% 13% 13% 13% 12% 12% 12% 12% 10% 10% 10% 10% 9% 8% 8% 8% 7% 7% 7% 6% 6% 6% 4% 2% 46% 39% 38% 34% 33% 32% 32% 29% 30% 27% 27% 26% 26% 23% 23% 22% 22% 21% 20% 22% 20% 19% 19% 18% 18% 15% 16% 15% 15% 16% 15% 14% 14% 12% 12% 12% 11% 11% 12% 8% 5% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% IRR at the Strip IRR -20% Cost Deflation 2015 2016 2017 2018 2019 2020 2021 2022+ $56.28 $62.63 $66.55 $68.50 $69.75 $69.75 $69.75 $69.75 $69.75 $3.03 $3.46 $3.76 $3.96 $4.12 $4.12 $4.12 $4.12

Core Eagle Ford Assets Drive Growth Through Commodity Cycles ~38,000(1) Net Mineral Acres Targeting the Eagle Ford ~38,000(1) acre position targeting the Eagle Ford ~14,000 net acres in McMullen county area ~19,000 net acres in Dimmit county ~5,300(1) net acres in Atascosa county 1H 2015 production of 7,235 Boe/d in EGFD 20.9 mmboe of proved reserves(1&2) Offset operators include: Anadarko, EOG, Chesapeake, Murphy, Pioneer, Swift and Talisman ~1 remaining net lease obligation wells in 2015 (currently drilling) Drilled 4x 10,000’ laterals in Dimmit County 2 wells currently flowing back 2 wells scheduled for completion in 3rd quarters of 2015 Eagle Ford operator with substantial, high-quality drilling inventory and significant production growth profile Includes acquisition of New Standard Energy Eagle Ford assets Based on 1 January 2015 NSAI reserve report Drilling year inventory based on two rig program drilling 36 net wells per year assuming 40-80 acre spacing EOG EOG EOG Newfield Chesapeake Murphy Anadarko SM-Energy Pioneer Pioneer Pioneer Conoco Conoco Cabot Chesapeake Chesapeake Talisman Talisman Marathon BHP -Petrohawk BHP -Petrohawk Chesapeake Marathon N Murphy Swift 50 miles Oil Window GOR < 750 Volatile Oil & Condensate Window Dry Gas Window McMullen Area Eagle Ford Acreage: ~19,000 net acres Dimmit Acreage: ~19,000 net acres Producing Eagle Ford wells color coded by Operator (as of April 2015)

Capital Expenditure Reductions Reduced base case Eagle Ford AFE by ~34% in less than 9 months Drilling Drilling Completions Completions Assumptions: 6,250' lateral length, 18,100' TD $8,344 $485 $72 $18 $1,240 $897 $128 $5,504 $- $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 2014 Q4 AFE Market Conditions (day rate & casing) Efficiencies (change in BHA design) Design Changes (casing) Market Conditions Design Changes (prop, stages, fluid) Design & Efficiencies (equip selection, commingle) 2015 Q3 AFE $’000s

19,245 net acres, including NSE 82 wells drilled to date including 9 on the NSE acquisition acreage 39.0 gross / 24.0 net wells drilled in 2014 Includes 11 gross / 3.5 net Chesapeake operated wells 66 wells completed to date including NSE 32.0 gross / 24.4 net wells completed in 2014 5.0 gross / 4.0 net wells completed H1 2015 16.0 gross / 8.5 net wells waiting on completion including NSE Asset Overview McMullen - Atascosa Area (~19,000 net acres) McMullen Area Eagle Ford Operators N 10 miles LEGEND SEA Acreage SEA Acreage Pro forma of NSE acquisition Chesapeake Conoco EOG Marathon Murphy Newfield PetroHawk / BHP Pioneer Sundance Energy Talisman Swift EGFD Producers

McMullen Area Economics Economics include $500M in facilities costs 30.9% NGL of oil and $3.50 NYMEX Gas; 29% shrinkage and 92 bbl/MMcf LOE $9,000 per month and $2.13/BO variable B factor of 1.1, terminal decline 6%, first month oil rate of 13,500 BO, flat GOR NOTE: With the demonstrated capability to drill longer laterals, inventory numbers may vary from previously disclosed amounts. Outperformance vs type curve drives better than forecast economics Inventory 80 : (65-80) Total Well Cost $6.0 MM: ($5.5 - $7.0 ) Frac Stages 29 # : ( 20-36 ) Average Lateral Length 6,550 ft : ( 4,500 - 7,500 ) Spacing 550 ft : (550' - 660') 5800 EUR Gross 512 Mboe Oil Only 328 Mbo Oil EUR/ft 50 bo/ft GOR 2,700 scf/bbl Net 384 Mboe F&D $ 15.63 /boe IRR & NPV (1) $75 Nymex IRR 60% NPV10 $5,026 $65 Nymex IRR 42% NPV10 $3,490 $55 Nymex IRR 27% NPV10 $1,958 $45 Nymex IRR 13% NPV10 $450 PV10 Breakeven Price: $42.25 0 20000 40000 60000 80000 100000 120000 140000 160000 180000 200000 - 100 200 300 400 500 600 700 800 0 4 8 12 16 20 24 Cumulative Oil Equiv. Production Daily Average, Oil Equiv., BOEPD Producing Months Type Curve Oil Equiv Rate Type Curve Cumulative Oil Equiv. Central Area BOE South Area BOE North Area BOE

Atascosa County Economics Economics include $500M in facilities costs 30.9% NGL of oil and $3.50 NYMEX Gas; 29% shrinkage and 92 bbl/MMcf LOE $9,000 per month and $2.13/BO variable; B factor of 1.1, terminal decline 6%, first month oil rate of 8,700 BO, flat GOR Pro Forma including 44 locations acquired in NSE transaction NOTE: With the demonstrated capability to drill longer laterals, inventory numbers may vary from previously disclosed amounts. Option to rising oil prices Inventory 83 (45 - 83) Total Well Cost $6.30 MM: ($5.5 - $7.0 ) Frac Stages 35 # : ( 30 - 40 ) Lateral Length 7800 ft : ( 6,500 - 8,000 ) Spacing 330 ft : (330' - 660') EUR Gross 323 Mboe Oil Only 312 Mbo Oil EUR/ft 40 BO/ft GOR 300 scf/bbl Net 242 Mboe F&D $ 26.00 /BOE IRR & NPV (1) $75 Nymex IRR 25% NPV10 $2,233 $65 Nymex IRR 16% NPV10 $923 $55 Nymex IRR 8% NPV10 ($384) $45 Nymex IRR 1% NPV10 ($1,686) PV10 Breakeven Price: $58.00 - 20,000 40,000 60,000 80,000 100,000 120,000 0 50 100 150 200 250 300 350 0 4 8 12 16 20 24 Cumulative Oil Production Daily Average, Oil, BOPD Producing Months

18,771 net acres 8 wells drilled to date 4.0 gross / 2.4 net wells drilled in 2014 4.0 gross / 4.0 net wells drilled H1 2015 with average lateral length of ~9,200’ 1.0 gross / 1.0 net well remaining to be drilled in 2015 6 wells completed to date 4.0 gross / 2.4 net wells completed in 2014 2.0 gross / 2.0 net wells completed H1 2015 ~10,000' laterals for total estimated cost of $8MM/well Successfully completed with production results expected in Q3 2.0 gross / 2.0 net well WOC in H2 2015 Asset Overview Dimmit County (~19,000 net acres) Dimmit Area Eagle Ford Operators N 10 miles LEGEND SEA Acreage Anadarko Eagle Ford Wells Chesapeake Eagle Ford Wells Newfield Eagle Ford Wells Talisman Eagle Ford Wells Murphy Eagle Ford Wells SEA Eagle Ford Wells Swift Eagle Ford Wells St. Mary Eagle Ford Wells

Dimmit County Economics Economics include $500M in facilities costs 30.9% NGL of oil and $3.50 NYMEX Gas; 29% shrinkage and 92 bbl/MMcf LOE $9,000 per month and $2.13/BO variable B factor of 1.1, terminal decline 6%, first month oil rate of 12,500 BO, flat GOR NOTE: With the demonstrated capability to drill longer laterals, inventory numbers may vary from previously disclosed amounts. Substantial potential economic improvement through longer laterals Inventory 259 (130 - 259) Total Well Cost $7.50 MM: ($6.5 - $8.0 ) Frac Stages 35 - 50 ' # : (35 -50 ) Lateral Length 9,200 ft : ( 7,500 - 10,000 ) Spacing 330 ft : (330' - 660') EUR Gross 826 Mboe Oil Only 405 Mbo Oil EUR/ft 44 bo/ft GOR 5,000 scf/bbl Net 620 Mboe F&D $ 12.10 /boe IRR & NPV (1) $75 Nymex IRR 59% NPV10 $7,178 $65 Nymex IRR 43% NPV10 $5,291 $55 Nymex IRR 30% NPV10 $3,405 $45 Nymex IRR 18% NPV10 $1,520 PV10 Breakeven Price: $36.95 0 20000 40000 60000 80000 100000 120000 140000 0 50 100 150 200 250 300 350 400 450 0 4 8 12 16 20 24 Cumulative Oil Production Daily Average, Oil, BOPD Producing Months Type Curve Oil Rate Type Curve Cumulative Oil 3 Well Actual Average

Oil focused Eagle Ford drilling inventory generates strong returns Proven low-cost operator with track record of optimizing recoveries Solid financial position provides liquidity to capitalize on downturn Ability to grow production and cash flow with existing assets and cash flow Takeaways

Appendix

SEC Case Reserve Report Prepared by Netherland Sewell and Associates (1) (1) Based on 1 January 2015 NSAI reserve report Sundance Total Oil (mbbls) NGL (mbbls) Gas (mmcf) Mboe PV10 (US$MM) PV10 (A$MM) Proved Developed Producing 6,124 1,801 12,364 9,986 337.9 414.2 Proved Undeveloped 10,903 2,365 16,369 15,996 193.7 237.4 Total Proved 17,026 4,166 28,733 25,981 531.6 651.6 Probable Developed 1,344 260 2,008 1,939 48.3 59.2 Probable Undeveloped 10,988 5,795 56,424 26,187 185.5 227.4 Total 2P 29,358 10,221 87,165 54,107 765.4 938.2 Possible Developed 978 173 1,338 1,375 35.6 43.6 Possible Undeveloped 26,616 21,999 264,376 92,677 689.5 845.2 Total 3P 56,953 32,393 352,880 148,159 1,490.5 1,827.1 Eagle Ford Stand Alone Oil (mbbls) NGL (mbbls) Gas (mmcf) Mboe PV10 (US$MM) PV10 (A$MM) Proved Developed Producing 4,919 955 7,373 7,103 270.8 331.9 Proved Undeveloped 7,984 1,332 10,275 11,029 178.5 218.8 Total Proved 12,903 2,287 17,648 18,132 449.3 550.7 Probable Developed 1,344 260 2,008 1,939 48.3 59.2 Probable Undeveloped 4,833 2,819 38,866 14,130 139.9 171.5 Total 2P 19,081 5,367 58,523 34,201 637.5 781.4 Possible Developed 978 173 1,338 1,375 35.6 43.6 Possible Undeveloped 13,019 14,813 221,981 64,828 529.3 648.8 Total 3P 33,078 20,353 281,843 100,404 1,202.3 1,473.8

Eagle Ford Portfolio Return Sensitivities Average Netherland Sewell & Associates 2P type curve(1) McMullen County Eagle Ford NSAI 2P Type Curve 347.5 mbo, 57.5 mbngl, 624.5 mcf 6,902’ average lateral length Dimmit County Eagle Ford NSAI 2P Type Curve 268.7 mbo, 76.6 mbngl, 827.3 mcf 6,059’ average lateral length Based on 1 January 2015 NSAI reserve report 17% 33% 12% 25% 9% 20% 5% 15% - 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 450,000 1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96 101 106 111 Cumulative production (boe/6:1) Production month Oil Gas NGLs - 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96 101 106 111 Cumulative production (boe/6:1) Production month Oil Gas NGLs $40/BBL $50/BBL $60/BBL $70/BBL $80/BBL $5.0MM 23% 42% 66% 94% 100% $5.5MM 17% 33% 52% 75% 100% $6.0MM 12% 25% 41% 60% 83% $6.5MM 8% 20% 34% 49% 68% $7.0MM 6% 15% 27% 41% 57% $7.5MM 4% 12% 22% 34% 48% $8.0MM 1% 9% 18% 28% 40% $40/BBL $50/BBL $60/BBL $70/BBL $80/BBL $5.0MM 9% 20% 34% 48% 65% $5.5MM 5% 15% 25% 38% 52% $6.0MM 2% 10% 20% 30% 42% $6.5MM 0% 7% 15% 24% 34% $7.0MM 0% 5% 11% 19% 28% $7.5MM 0% 2% 8% 15% 23% $8.0MM 0% 0% 6% 12% 19%

Share Price Performance vs Australian Peer Group Note: YTD period covers 1/1/15 – 7/20/15. One year period covers 6/30/14-7/20/15. Three year period covers 6/30/12-7/20/15. Five year period covers 6/30/10-7/20/15. See Appendix for peer data set. See Appendix for details on Focused Peer Groups. YTD Change vs ASX Peers 1 Year Change vs ASX Peers 5 Year Change vs ASX Peers 3 Year Change vs ASX Peers - 16% -50% -40% -30% -20% -10% 0% 10% 20% Co. 1 Sundance Co. 3 Co. 4 Co. 5 Co. 6 Co. 7 - 45% -80% -70% -60% -50% -40% -30% -20% -10% 0% Sundance Co. 2 Co. 3 Co. 4 Co. 5 Co. 6 Co. 7 - 37% -100% -90% -80% -70% -60% -50% -40% -30% -20% -10% 0% Co. 1 Co. 2 Co. 3 Sundance Co. 5 Co. 6 Co. 7 148% -50% 0% 50% 100% 150% 200% Sundance Co. 2 Co. 3 Co. 4 Co. 5 Co. 6

Share Price Performance vs Eagle Ford Peer Group Note: YTD period covers 1/1/15 – 7/20/15. One year period covers 6/30/14-7/20/15. Three year period covers 6/30/12-7/20/15. Five year period covers 6/30/10-7/20/15. See Appendix for peer data set. See Appendix for details on Focused Peer Groups. YTD Change vs EGFD Peers 1 Year Change vs EGFD Peers 5 Year Change vs EGFD Peers 3 Year Change vs EGFD Peers - 16% -50% -40% -30% -20% -10% 0% 10% Co. 1 Co. 2 Co. 3 Sundance Co. 5 Co. 6 Co. 7 - 45% -100% -90% -80% -70% -60% -50% -40% -30% -20% -10% 0% Co. 1 Sundance Co. 3 Co. 4 Co. 5 Co. 6 Co. 7 - 37% -100% -80% -60% -40% -20% 0% 20% 40% 60% 80% 100% Co. 1 Co. 2 Co. 3 Sundance Co. 5 Co. 6 148% -50% 0% 50% 100% 150% 200% Sundance Co. 2 Co. 3 Co. 4

Share Price Performance vs Small Cap (<$1B EV) Peer Group Note: YTD period covers 1/1/15 – 7/20/15. One year period covers 6/30/14-7/20/15. Three year period covers 6/30/12-7/20/15. Five year period covers 6/30/10-7/20/15. See Appendix for peer data set. See Appendix for details on Focused Peer Groups. YTD Change vs Small Cap Peers 1 Year Change vs Small Cap Peers 5 Year Change vs Small Cap Peers 3 Year Change vs Small Cap Peers - 16% -100% -80% -60% -40% -20% 0% 20% 40% - 45% -100% -80% -60% -40% -20% 0% - 37% -100% -50% 0% 50% 100% 150% 200% 250% 148% -100% -50% 0% 50% 100% 150% 200% 250%

Share Price Performance vs All Peers Note: YTD period covers 1/1/15 – 7/20/15. One year period covers 6/30/14-7/20/15. Three year period covers 6/30/12-7/20/15. Five year period covers 6/30/10-7/20/15. See Appendix for peer data set. See Appendix for details on Focused Peer Groups. YTD Change vs All Peers 1 Year Change vs All Peers 5 Year Change vs All Peers 3 Year Change vs All Peers - 16% -100% -80% -60% -40% -20% 0% 20% 40% Co. 1 Co. 2 Co. 3 Co. 4 Co. 5 Co. 6 Sundance Co. 8 Co. 9 Co. 10 Co. 11 Co. 12 Co. 13 Co. 14 Co. 15 Co. 16 Co. 17 Co. 18 Co. 19 Co. 20 Co. 21 Co. 22 Co. 23 Co. 24 - 45% -100% -90% -80% -70% -60% -50% -40% -30% -20% -10% 0% Co. 1 Co. 2 Co. 3 Co. 4 Co. 5 Co. 6 Sundance Co. 8 Co. 9 Co. 10 Co. 11 Co. 12 Co. 13 Co. 14 Co. 15 Co. 16 Co. 17 Co. 18 Co. 19 Co. 20 Co. 21 Co. 22 Co. 23 Co. 24 - 37% -100% -50% 0% 50% 100% 150% 200% 250% Co. 1 Co. 2 Co. 3 Co. 4 Co. 5 Co. 6 Co. 7 Co. 8 Co. 9 Co. 10 Sundance Co. 12 Co. 13 Co. 14 Co. 15 Co. 16 Co. 17 Co. 18 Co. 19 Co. 20 Co. 21 Co. 22 148% -100% -50% 0% 50% 100% 150% 200% 250% 300%

Focused Peer Groups re Share Price Performance Q1 2015 results unless otherwise noted Q1 2015 BOEPD % Liquids 1P MMBOE Ticker Q1 2015 BOEPD % Liquids 1P MMBOE Ticker EGFD Peers: Other Small Cap Peers: Abraxas Petroleum 6,590 78% 42 AXAS Approach Resources 14,300 67% 146 AREX Carrizo Oil & Gas 34,595 72% 151 CRZO Callon Petroleum 8,567 83% 33 CPE EP Energy 102,400 70% 622 EPE Contango Oil & Gas 16,044 32% 46 MCF Lonestar Resources 5,547 83% 31 ASX:LNR Emerald Oil 4,715 96% 26 EOX Matador Resources 23,513 48% 69 MTDR Evolution Petroleum2 1,640 100% 13 EPM Sanchez Energy 45,222 71% 135 SN Goodrich Petroleum 8,671 56% 46 GDP Sundance Energy 9,581 87% 26 ASX:SEA Miller Energy2 3,476 71% 6 MILL Panhandle Oil & Gas 6,399 28% 34 PHX ASX Peers: Parsley Energy 18,919 77% 91 PE Austex Oil Ltd 1,201 52% 9 ASX:AOK Penn Virginia 24,721 78% 115 PVA Beach Energy Ltd3 23,582 22% 33 ASX:BPT Rex Energy2 32,697 35% 223 REXX Drillsearch Energy Ltd1 7,446 90% 8 ASX:DLS Sundance Energy 9,581 87% 26 ASX:SEA Lonestar Resources 5,547 83% 31 ASX:LNR Synergy Resources 7,745 59% 16 SYRG Maverick Drilling and Exploration 2 1,013 4 ASX:MAD Senex Energy Limited 3,667 94% 6 ASX:SXY Sundance Energy 9,581 87% 26 ASX:SEA 1 Drillsearch only released 2P reserves. 2 Maverick only released gross production. Net production was unavailable. % Liquids was unavailable. 3 Beach Energy did not release liquids production or reserves information. Therefore % Liquids shown is strictly % Oil.

Industry Peer Group re Operational Performance FY14 results unless otherwise noted Enterprise Enterprise MBOEPD % Liquids 1P MMBOE PV-10 Value Ticker MBOEPD % Liquids 1P MMBOE PV-10 Value Ticker Abraxas Petroleum 6.6 78% 42 513 359 AXAS Midstates Petroleum 34.2 59% 151 1,820 2,150 MPO Antero Resources 247.5 17% 2,114 7,635 13,508 AR Newfield Exploration 126.1 58% 645 6,212 7,945 NFX Approach Resources 14.3 66% 146 1,056 662 AREX Northern Oil and Gas 17.0 88% 101 1,405 1,188 NOG Bill Barrett 17.6 79% 122 1,170 1,125 BBG Oasis Petroleum 50.4 87% 272 3,982 3,985 OAS Bonanza Creek 27.5 65% 90 1,107 1,333 BCEI Panhandle Oil and Gas 6.4 31% 34 205 385 PHX Cabot Oil & Gas 317.3 4% 1,233 6,493 13,918 COG Parsley Energy 18.9 77% 91 956 3,112 PE Callon Petroleum 8.6 78% 33 582 873 CPE PDC Energy 32.2 64% 250 2,306 2,398 PDCE Carrizo Oil & Gas 34.6 76% 151 3,382 CRZO Penn Virginia 24.7 77% 115 1,182 1,800 PVA Cimarex Energy 157.8 47% 522 4,353 10,452 XEC PetroQuest Energy 11.5 25% 28 235 387 PQ Clayton Williams 17.2 83% 75 933 1,258 CWEI Pioneer 193.8 65% 799 7,785 20,467 PXD Comstock Resources 26.7 20% 103 - 1,258 CRK QEP Resources 139.2 41% 655 5,340 4,373 QEP Concho Resources 132.2 58% 637 8,023 15,987 CXO Range Resources 221.3 33% 1,718 7,593 10,552 RRC Contango Oil & Gas 16.0 35% 46 648 309 MCF Resolute Energy 13.5 92% 74 833 827 REN Continental Resources 206.8 64% 1,351 18,433 20,481 CLR Rex Energy 32.7 37% 223 1,025 1,065 REXX Denbury Resources 74.4 83% 438 5,908 5,258 DNR Rice Energy 73.4 0% 218 1,308 4,100 RICE Diamondback Energy 33.1 84% 117 2,045 5,143 FANG Ring Energy 2.8 92% 15 299 344 REI Earthstone Energy 3.8 71% 22 256 197 ESTE Rosetta Resources 65.7 61% 282 2,617 3,402 ROSE Eclipse Resources 26.6 28% 59 331 1,262 ECR RSP Permian 15.9 86% 106 876 2,490 RSPP Emerald Oil 4.7 87% 26 444 279 EOX Sanchez Energy 45.2 74% 130 1,781 2,152 SN Energen 70.1 60% 442 4,220 5,348 EGN SandRidge Energy 87.7 42% 516 4,088 5,334 SD Energy XXI 60.0 75% 246 5,948 4,173 EXXI SM Energy 186.4 55% 548 5,699 4,909 SM EP Energy 102.4 67% 622 6,898 7,064 EPE Southwestern Energy 431.2 9% 1,791 7,543 14,971 SWN EQT Corporation 268.9 9% 1,790 4,810 14,981 EQT Stone Energy 46.3 46% 153 1,419 1,420 SGY EXCO Resources 56.4 9% 211 1,543 1,677 XCO Sundance Energy 8.4 82% 26 1,485 368 SEA-AU Gastar Exploration 12.6 53% 102 817 650 GST Swift Energy 34.0 41% 194 1,652 1,172 SFY Goodrich Petroleum 8.7 62% 46 645 761 GDP Synergy Resources 8.0 52% 50 497 1,058 SYRG Gulfport Energy 72.7 23% 156 1,573 4,598 GPOR Triangle Petroleum 13.8 89% 59 821 1,076 TPLM Halcon Resources 43.1 91% 189 3,256 4,921 HK Ultra Petroleum 130.4 10% 895 5,233 4,896 UPL Jones Energy 26.4 58% 115 1,388 1,302 JONE W&T Offshore 48.8 65% 120 1,703 1,754 WTI Laredo Petroleum 47.5 75% 297 3,247 3,628 LPI Warren Resources 13.0 24% 58 555 424 WRES Lonestar Resources 5.5 83% 36 370 LNR-AU Whiting Petroleum 167.0 89% 780 10,843 10,592 WLL Magnum Hunter 44.7 30% 84 909 1,561 MHR WPX Energy 187.6 32% 828 3,883 6,196 WPX Matador Resources 23.5 41% 79 949 2,175 MTDR

Operating costs used in this report are based on operating expense records of Sundance. Capital costs used in this report were provided by Sundance and are based on authorizations for expenditure and actual costs from recent activity. Future net revenue is after deductions for Sundance's share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. “PV10” is defined as the discounted Net Revenues of the Company’s reserves using a 10% discount factor. Reserves are estimated in US dollars. US dollars are converted at 1.2258 USD/AUD. “1P Reserves” or “Proved Reserves” are defined as Reserves which have a 90% probability that the quantities actually recovered will equal or exceed the estimate. “Probable Reserves” are defined as Reserves that should have at least a 50% probability that the actual quantities recovered will equal or exceed the estimate. “2P Reserves” are defined as Proved Reserves plus Probable Reserves. “Possible Reserves” are defined as Reserves that should have at least a 10% probability that the actual quantities recovered will equal or exceed the estimate. “3P Reserves” are defined as Proved Reserves plus Probable Reserves plus Possible Reserves. “boe” is defined as barrel of oil equivalent, using the ratio of 6 mcf of Natural Gas to 1 bbl of Crude Oil. This is based on energy conversion and does not reflect the current economic difference between the value of 1 MCF of Natural Gas and 1 bbl of Crude Oil. “m” is defined as a thousand. “mmboe” is defined as a million barrels of oil equivalent. Reserve Report Footnotes and Definitions