Rosetta Resources Inc.Investor Presentation  November 2014  PERMIAN BASIN + EAGLE FORD 

 Cautionary Statements  2  This presentation includes forward-looking statements. Forward-looking statements related to future events, such as expectations regarding our capital program, development plans, production rates, resource potential, transportation capacity, net present value and projected liquidity. These statements are not guarantees of future performance and actual outcomes may differ materially. Factors that could affect the Company's business include, but are not limited to: oil and gas prices, operating hazards, drilling risks, unsuccessful exploratory activities; unexpected cost increases; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or future litigation; limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets; as well as changes in tax, environmental and other laws applicable to our business. Other factors that could cause actual results to differ materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting our business generally as set forth in our filings with the Securities and Exchange Commission. Unless legally required, the Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. For filings reporting year-end 2013 reserves, the SEC permits the optional disclosure of probable and possible reserves.  The Company has elected not to report probable and possible reserves in its filings with the SEC.  We use the term “net risked resources” or “inventory” to describe the Company’s internal estimates of volumes of natural gas and oil that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques.  Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the Company.  Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.  

 Test Future Growth Opportunities to Expand Inventory  Advancing delineation of Delaware Basin multi-stacked lateral potentialRefining and expanding testing of Upper Eagle Ford pilotsAssessing Gaines County acreage in Midland BasinPursuing new growth targets through bolt-on acquisitions in core areas          Successfully ExecuteBusiness Plan  Grow total production and liquids volumes while applying cross-basin knowledgeContinue to improve performance of drilling and completion operationsMaintain competitive overall cost structure and marginsCapture firm transportation and processing capacity          MaintainFinancial Strength & Flexibility  Actively manage strong balance sheet for optimum financial flexibilityMaintain adequate liquidity throughout cyclesManage exposure to commodity price risk through prudent hedging program      Company Strategy – Key Elements   3 

                           Rosetta Resources Overview  4    Permian   Gaines Co. ~13,000 net acresMidland Basin – Exploratory    Reeves Co. ~47,000 net acresDelaware Basin – Delineating  Permian    Eagle Ford~60,000 net acres (100% operated)                  Central Dimmit Co. Area~8,500 net acres, Dimmit Co.   Tom Hanks~3,500 net acres, LaSalle Co.  Lopez ~500 net acres, Live Oak Co.  Karnes Trough ~1,900 net acres in oil windowDewitt & Gonzales Co.  Briscoe Ranch~3,600 net acres, Dimmit Co.    Encinal~12,700 net acres, Webb & LaSalle Co.  Steiren Area~2,500 net acres in oil windowAtascosa Co.    Gates Ranch~26,200 net acres, Webb Co.  0  10  20  Miles  Market Summary(November 7, 2014 Close)  Ticker:  ROSE    Market capitalization:  $2.4 billion    Share price:  $38.48    Enterprise value:  $4.3 billion  Note: Acreage numbers are rounded   

 Strong Growth Track Record  5  Net Production(MBoe/d)    72  74  Total CompanyEstimate Range  Permian ~288 MMBoe  Net Risked Resource Potential (MMBoe)    *Post-Divestiture 

 Capital Programs1  6  Permian 45%  Eagle Ford55%  ~32% production growth in 2014 and more than 20% in 2015  $1.2 billion 2014 capital program; 86 percent spent through Sept 30th Eagle Ford – Three rigs in Q4 2014Expect to complete ~4-7 wellsDrill first Briscoe Ranch Upper Eagle Ford testPermian Basin – Four rigs in Q4 2014Expect to complete 3 hz wells and spud ~9 hz wellsComplete longest lateral drilled to date; 7,000 ft and 27 frac stages  Other7%  Permian Op24%  Eagle Ford66%  PermianNon-Op3%  2015E by Division  2014 by Region   2015 capital and production preliminary outlookEstimated $950 million capital budget, down 20% from 2014; second highest capital budget in company historyAnnual production guidance range of 77-83 MBoe/d or more than 20% increase over 2014, at the midpoint  Capital includes capitalized interest and other corporate costs; Excludes acquisition capital. 

 Total Company Inventory+/- 1,500 net wells -- remaining as of 9/30/2014 (excluding Upper Eagle Ford, Encinal & Gaines Co.)  7  Asset Name  Net acres  Wellscompletedby Rosetta  Wells awaiting completion  Well Spacing  Remainingnet locations1   Avg Cost / Well$M (5000’ lateral)  Gates Ranch (100% WI / 75% NRI)  26,200  184  24  55  247  $5.5 - $6.0      8 UEF          Briscoe Ranch (100% WI / 81.3% NRI)  3,600  29  11  50  39    Central Dimmit2 (100% WI / 75 – 77% NRI)  8,500  23  10  60  91        1 UEF          Tom Hanks(100% WI / 77% NRI)  3,500  15  6  50   40    Lopez(100% WI / 75% NRI)  500  3  -  50   5  $7.5 - $8.0  Steiren (Undelineated)(100% WI / 75 - 77% NRI)  2,500  -  -  50  21  $5.5 - $6.0  Total Eagle Ford3 Inventory  44,800  263  51  50 - 60  443  $5.5 - $8.0  Permian 3rd Bone Spring Hz4  47,000(Reeves Co)  1  1  80  296  $8.0 - $9.0  Permian WC ‘A’ Hz4    14  5  80  450    Permian WC ‘B’ Hz4    -  -  80  158    Permian WC ’C’ Hz4    1  -  80  105    Total Permian Inventory  47,000  16  7  80  1,009  $8.0 - $9.0  Total Company Inventory  91,800  279  57   50 - 80  1,452   $5.5 - $9.0  Remaining net locations may vary based on changes in well lateral lengthsCentral Dimmit includes L&E, Vivion and Light Ranch Excludes producing areas in Karnes Trough that are fully developed (26 completions). Excludes 6 producing wells completed in Encinal area.Horizontal operated and non-operated project count includes potential in multiple horizons (Wolfcamp A, B, C, and 3rd Bone Spring); assuming 660’ between laterals or 80-acre spacing 

 Permian Basin Division 

 Permian Division – Reeves County~47,000 net acres  9  2014 Activity Summary – 1st Nine Mos.        Reeves County (Op)  Vertical  Horizontal  TOTAL  Wells Drilledby Rosetta  15  22  37  Wells Completedby Rosetta  19  14  33  Wells Placedon Production  18  15  33  Wells Drilled Awaiting Completion  5  6  11    Successfully completed seven horizontal wells, six WC ‘A and one 3rd Bone Spring; total average gross 7-day IP ~1,300 Boe/dProduced 8.2 MBoe/d, an increase of 82 percent versus second quarter Flowing back Intrepid 27-38 #2H WC ‘A’ well, longest lateral to date; completed with 27 stages across an effective 7,000-foot lateral  HIGHLIGHTS  3rd Quarter 20149 completions:7 horizontal2 vertical  Intrepid Flowing Back  Operating Interest  Non-operating Interest 

 Regional structure map of the Permian Basin  Modified by Beaubouef at al. (1999) from Wright. 1962 and Fitchen 1997  Permian Asset PotentialStacked Zones Provide Collection of Horizontal Development Opportunities  10    Primary Completion Targets    In comparison, the lower Eagle Ford reservoir thickness is ~100 feet at Gates Ranch  1,300’    Rosetta’s Reeves Co. acreage position    Rosetta’s Gaines Co. acreage position(Exploratory) 

 Permian – Horizontal Development Plan 9/30/2014  11  Horizontal project count is operated and non operated and includes multiple horizons (Wolfcamp A, B, C, and 3rd Bone Spring).  OperatedNon-Operated      1,348 Gross (Avg. 75% WI)Horizontal Well Locations1  Deacon Jim 6 #1H7-IP 69330-IP 273   Johnny Ringo St 9 2H7-IP 1,39330-IP 1,068  Sam Bass 15 1H7-IP 63830-IP 625  Sheriff Woody 10 #1H7-IP 1,66930-IP 1,399  Calamity Jane 22 1H 7-IP 1,96630-IP 1,687  Black Jack 16 3H7-IP 1,15430-IP 1,039  Gaucho 15 1H7-IP 104930-IP 809  Gaucho 15 2H7-IP 82930-IP 526  Intrepid 27-38 #2HFlowing Back  A  BS  A  A  A  A  A  A  A  City of Pecos 13 #3H7-IP 1,05330-IP 769  Balmorhea Ranch 32-157-IP 96930-IP 739  Dynamite Dan 37 #1H7-IP 1,30230-IP 1,116  Black Jack 16 1H7-IP 1,39530-IP 1,216  Tall Texan 36 #4H7-IP 1,60830-IP 1,271  Roy Bean 42 1H7-IP 36130-IP 298  Black Jack 16 2H7-IP 1,33830-IP 1,088  Monroe 39 #4H7-IP 1,47430-IP 1,238  Balmorhea Ranch 41 3H7-IP 98730-IP 863  A  A  A  A  A  C  A  A  A  DRILLED AWAITING COMPLETION  COMPLETION ACTIVITY SINCE 6/30/14  COMPLETED BEFORE 6/30/2014 

 Completion Design ImprovementsRate Comparisons  12  3rd Bone SpringWolfcamp AWolfcamp C  309  Denotes old completion design;excludes Wolfcamp ‘C’ well    Denotes new completion design;excludes 3rd Bone Spring well and Deacon Jim (NE step-out)  4Q 2013 – 1Q 2014  2Q 2014  3Q 2014  1. Source: Tudor, Pickering, Holt & Co. 

 Permian Asset Potential Multiple Benches in Delineation Phase Across Rosetta’s Acreage  13  OperatedNon-Operated      3rd Bone Spring  Wolfcamp A  Wolfcamp B  Wolfcamp C  Completed Prior 3Q2014 Proposed 2014 Activity Offset Operations 

 Permian – Reeves CountyUpper Wolfcamp Horizontal Type Curve (1/30/2014)  14  Months on Production  3-Stream BOEPD*  P50 Type Curve    Average Well Costs($MM)  $8.5 ($8-$9 range)  30-Day IP RateBoe/d (gross)  1,090  Composite EURMBoe (gross)   550 (500-600 range)  % Oil  74%  % NGL  10%  *All production data normalized to 5,000' lateral length; well production data updated as of 10/30/2014.Note: Rosetta reports reserves and production in 3-stream. Rosetta assumptions for gas shrink and NGL yield applied to offset operators’ 2-stream public data.   3Q 2014 WC ‘A’ Completions30-Day Avg (BOEPD)Normalized to 5000’    City of Pecos 13 #3H  893  Tall Texan St 36 #4H  1,785  Sheriff Woody 10 #1H  1,960  Monroe 39 A #4H  1,342  Dynamite Dan 37 #1H  1,364  Deacon Jim 6 #1H  326 

 South Texas Division 

 South Texas Division – Eagle Ford  16  2014 Activity Summary – 1st Nine Mos.                GatesRanch  BriscoeRanch  CentralDimmit  TomHanks  Encinal  TOTAL  Wells Drilledby Rosetta  48  8  15  7  2  80  WellsCompleted  52  13  12  11  2  90  Wells Placedon Production  54  13  9  11  2  89  Wells Drilled Awaiting Completion  24  11  10  6  0  51  HIGHLIGHTSProduced 65 MBoe/d, an increase of 34 percent from 2013 and 15 percent versus second quarterTesting potential of Upper Eagle Ford across multiple areasPlan to drill first Upper Eagle Ford well at Briscoe Ranch in Q4 2014   

 Gates Ranch~26,200 net acres in Webb County  17    Sep 30, 2014 Summary     Completions to date:  192 gross completions  Locations remaining:  247 LEF net well locations1      Average2 Lower EF Well Characteristics    Well Costs:  $5.5 - $6.0 MM  Spacing:  55 acres (475 feet apart)  P50 Composite EUR:  1.67 MMBoe (0.7 – 2.7 range)  Condensate Yield:  55 Bbls/MMcf (30 – 80 range)  NGL Yield:  110-115 Bbls/MMcf  Shrinkage:  23%  Under current Lower Eagle Ford (LEF) 55-acre spacing assumptionsBased on 5,000’ lateral length and 15-stage completion  9 miles  10 miles          1st Pilot  2nd Pilot  4th Pilot    Upper EF Pilot 

   Central Dimmit County Area~8,500 net acres located in Dimmit County  18  Sep 30, 2014 Summary     Completions to date:  24 gross completions  Locations remaining:  91 LEF net well locations  Average Well Costs:  $5.5 – $6.0 MM        Lasseter & Eppright  Light Ranch  2 completions  Vivion      3rd Upper EF Pilot  3 completions 

 Upper Eagle Ford Pilot Program  19  3  4      New UEFTest Areas 

 Marketing and Financial Overview 

 Gas Transportation CapacityFirm gross wellhead transportation and processingCurrent capacity of 345 MMcf/d Six processing options – Gathering (Plant)Regency (Enterprise Plants)Energy Transfer “ETC” Dos Hermanas (Exxon King Ranch)Eagle Ford Gathering (Kinder Morgan Houston Central)ETC Rich Eagle Ford Mainline (LaGrange / Jackson / Kennedy)  Oil Transportation CapacityGates Ranch, Briscoe Ranch & Central Dimmit CountyPlains Crude Gathering – Firm gathering capacity of 25,000 Bbls/d to Gardendale hub with up to 60,000 Bbls storage; operating since April 2012All condensate is stabilized with distillation tower methodology Access to truck and rail loading and pipeline connections to the Gulf Coast  Eagle Ford Multiple Takeaway Options  21  Gates Ranch NGLBreakdown July 2014  Gates RanchCondensate Stabilization 

 Permian Basin Marketing  OilCurrently trucked from leasesGathering options under evaluationOil gravity averages 43 degrees and receives no gravity deductsNew Permian takeaway pipelines on the way (Bridge Tex, PE2, Cactus)Midland–Cushing differentials improving; currently trading below $5 in Q4 2014, down from the ~$10 differential seen in Q3 2014Natural GasGas is rich and is processed at two plants Most leases under long-term gathering agreementResidue gas sales tied to Waha and Permian indicesNGLsNGLs extracted under firm, multi-year gathering/processing agreementsCombination of net proceeds and Mont Belvieu pricing  22 

 Commodity Derivatives Position – Nov 4, 2014  23  $37.10  $83.33X$109.63  $93.13  $89.81  $90.28  $31.90            Liquid Derivatives(Bbls/d)    Natural Gas Derivatives(MMBtu/d x 1,000)   

 Debt and Capital Structure  24  ($MM)  ($MM)  Capital Structure    Debt Structure   

 Liquidity  25  Adequate liquidity to fund 2014 and estimated 2015 capital program$950 million borrowing base$800 million committed amount$140 million outstanding on October 31st   Total Liquidity(Millions)   

 Investment Summary  Drill-bit focused producer with core acreage positions in Eagle Ford and Permian Basin playsAttractive core Delaware Basin position gaining momentumSuccessful operator in the high-return Eagle Ford area, reducing well costs adding significant net asset valueLarge inventory of future growth opportunities with multiple stacked lateral potentialSolid reputation of financial strength and business flexibility to support growth throughout industry cycles  26  Rosetta Resources – Growing Value in a Rock Solid CombinationPERMIAN BASIN + EAGLE FORD 

 Appendix 

 Attractive Well Economics (Typical Well)  Metrics  Gates Ranch        BriscoeRanch  Tom Hanks  L&E  Horizontal Upper Wolfcamp    Far South  Southeast  NorthCentral  Far North          Average WI NRI  100%   100%   100%   100%   100%   100%  100%   100%    75%  75%  75%  75%  81%  77%  75%  75%  Average Cost / Well, gross ($MM)  $5.75  $5.75  $5.75  $5.75  $5.75  $6.0  $5.75  $8.5  Gross 30-day IP (Boe/d)  1,500  1,500  1,400  1,400  1,180  720  685  1,090  Gross EUR (MBoe)P50, Unrisked  2,35016% Oil39% NGL  2,15016% Oil39% NGL  1,12220% Oil37% NGL  1,01120% Oil37% NGL  73425% Oil40% NGL  34682% Oil8% NGL  52450% Oil26% NGL  55074% Oil10% NGL  Rate of Return BFIT (%)  97%  87%  49%  52%  48%  43%  30%  23%  PV10 BFIT ($MM)  $17.1  $14.8  $6.3  $5.8  $4.9  $4.0  $2.9  $2.9  Payout BFIT (yrs)  1.0  1.1  1.6  1.4  1.5  1.6  2.3  2.9  Net Developed F&D ($/Boe)  3.24  3.54  6.74  7.48  9.61  22.54  14.64  20.58  28  Note: EURs and economic metrics are “Unrisked”. Horizontal wells based on 5,000’ lateral length, unless noted. Capital costs utilize sand proppant for completions.Type curves are available on the ‘Investors’ page on the company website, www.rosettaresources.com.Oil price assumptions, $/Bbl - $78.51 in 2015, $79.62 in 2016, $80.39 thereafter.NGL price assumptions, $/Bbl - $28.32 in 2015, $28.72 in 2016, $29.62 thereafter.Gas price assumptions, $/MMBtu - $3.89 in 2015, $3.97 in 2016, $4.08 thereafter. 

 Reeves County Horizontal Delineation ProgramRecent Well Performance Reflecting Enhanced Completion Design    Early Design  New Design  Average Lateral Length  5,000’  5,000’  # of Stages  17  19  Spacing between stages  290’  260’  Proppant Type  Sand  Sand  Proppant per Stage, Mlbs  240  310  Proppant per Lateral Ft, lbs  830  1,200  Addition of slickwater fluid component to activate natural features and increase fracture complexityShorter stage spacing to create larger stimulated rock volume (SRV)Increased proppant volume to focus on creating larger SRV  29  Boe/d  Q3 2014Completions1  Pre-2Q 2014 Completions  1Excludes 3rd Bone Spring well and Deacon Jim (NE step-out) 

 Eagle Ford Horizontal ProgramWell Cost Guidance Reduced by $500M Reflecting Change in Completion Design    Past Design  New Design  Average Lateral Length  5,000’  5,000’  # of Stages  15  15-21  Spacing between stages  300’  240-330’  Proppant Type  Ceramic  Sand  Proppant per Stage, Mlbs  275  360-500  Proppant per Lateral Ft, lbs  825  1,500+  Shifting focus of completion design with change in proppantPast Focus: Maximize conductivityNew Focus: Maximize stimulated rock volume while obtaining necessary conductivity for optimum flowReplacing ceramic proppant with sand pumped in much larger volumesAnalyzed performance of 12 Gates Ranch sand wells vs offsetting ceramic wellsChange applies to Gates Ranch, Briscoe Ranch, L&E, Vivion and Tom Hanks  30 

 Upper Eagle Ford Pilot ProgramFuture Plans are to pilot test the Upper Eagle Ford at North Gates & Briscoe Ranch ...  31  Lower Eagle Ford Landing Zones  A’  A          4-22  5-22  BVP 25  BVP 50 51 52  BVP 53  BVP 54  L&E B31                  A  A’  Pilot #1(East Gates)  Pilot #4(East Gates)  Pilot #2(South Gates)  Pilot #3(L&E)  Future Pilot(North Gates)  Future Pilot(Briscoe)      Target 

 ($ in millions)                  FY 2011    FY 2012    FY 2013    2014 First Nine Months   Net Income  $100.5    $159.3    $199.4    $128.1  Income tax expense  55.7    95.9    110.6    72.6  Interest expense, net of interest capitalized   21.3    24.3    36.0    53.6  Other income (expense), net  0.9    0.1    0.3    12.5  Depreciation, depletion and amortization  123.2    154.2    218.6    293.7  EBITDA  $301.6    $433.8    $564.9    $560.5  Unrealized derivative loss (gain)  (1.2)    (19.7)    16.3     (17.2)  Stock-based compensation expense  29.0    18.5    11.0    9.8  Adjusted EBITDA*  $329.4    $432.6    $592.2    $553.1                          Adjusted EBITDA Reconciliation  EBITDA is calculated as net income, excluding income tax expense, interest expense, net of interest capitalized, other income (expense), net, and depreciation, depletion and amortization. Adjusted EBITDA is calculated as EBITDA excluding unrealized gains or losses on derivative instruments and stock-based compensation expense.   *2013 Adjusted EBITDA of $592MM has not been adjusted to add back non-recurring items of Reserve for Commercial Dispute $20.4MM and Acquisition Costs $2.3MM.2014 Adjust EBITDA of $574.3 has not been adjusted to add back non-recurring items of Reserve for Commercial Dispute $5.8MM , Acquisition Costs $0.6MM, and Loss on Debt Extinguishment of $12.6MM  32