Forestar Investor Presentation June 2014 Growing Forward Through Strategic and Disciplined Investments and Increasing Returns

Notice To Investors This presentation contains “forward-looking statements” within the meaning of the federal securities laws. Forward-looking statements are typically identified by words or phrases such as “will,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “target,” “forecast,” and other words and terms of similar meaning. These statements reflect management’s current views with respect to future events and are subject to risk and uncertainties. We note that a variety of factors and uncertainties could cause our actual results to differ significantly from the results discussed in the forward-looking statements, including but not limited to: general economic, market, or business conditions; changes in commodity prices; opportunities (or lack thereof) that may be presented to us and that we may pursue; fluctuations in costs and expenses including development costs; demand for new housing, including impacts from mortgage credit rates or availability; lengthy and uncertain entitlement processes; cyclicality of our businesses; accuracy of accounting assumptions; competitive actions by other companies; changes in laws or regulations; and other factors, many of which are beyond our control. Except as required by law, we expressly disclaim any obligation to publicly revise any forward-looking statements contained in this presentation to reflect the occurrence of events after the date of this presentation. This presentation includes Non-GAAP financial measures. The required reconciliation to GAAP financial measures can be found as an exhibit to this presentation and on our website at www.forestargroup.com. 2

Maximizing Long-Term Shareholder Value 3 Maximizing Long-Term Shareholder Value Through the Development of Best of Class Real Estate and Oil and Gas and Businesses

Execution of Initiatives and Strategic Acquisitions Positions Forestar with Stronger Portfolio of Assets 4 Real Estate • Land - 119,000 acres, principally low basis land • Projects - 92 (10 states and 13 markets) • Significant Commercial Properties – 5 Oil and Gas • Fee and Leasehold Interests - 863,000 net acres* • Producing Gross Wells – 1,014** Natural Resources •108,000 acres with timber *** •Water Interests - 1.5 million acres**** Assets and Resources – Q1 2014 Note: includes ventures * Includes approximately 273,000 net acres of leasehold interests **Includes 547 royalty interest wells on owned mineral acreage; excludes 1,181 wells with overriding royalty interest ***Included in real estate. Excludes 14,000 leased acres ****Includes a 45% non-participating royalty interest in approximately 1.4 million acres

Triple in FOR Initiatives Focus on Accelerating Value Realization Optimize Transparency & Disclosure Raise NAV Through Strategic and Disciplined Investments 5 Triple Residential Lot Sales Triple Oil and Gas Production 0 500 1,000 1,500 2,000 2,500 2008-2011 Average 2012 2013 Lo ts S o ld Triple in FOR 2015 Goal 2,200 lots 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2008-2011 Average 2012 2013 Triple in FOR Goal 1,100 MBOE 0 20 40 60 80 100 120 140 160 2008-2011 Average 2012 2013 Triple in FOR Goal Total Segment EBITDA Average = $120 million Triple Total Segment EBITDA Note: EBITDA = Total segment earnings (loss) + depreciation + depletion and amortization Total Segment EBITDA is a Non-GAAP financial measure. The reconciliation between GAAP and Non-GAAP financial measures is included in the appendix to this presentation and provided on the company’s investor relations website. Execution of Triple in FOR Initiatives Putting EBITDA Points on the Board To ta l S eg m en t EB IT D A ( $mi lli o n s) MB O E Pr o d u ct io n 1,057 $117 1,883

Growing FORward Through Disciplined Investments Focused on Increasing Returns 1) Real Estate Acquisition and Development 2) Oil and Gas Exploration and Development 3) Strategic Investments 6 Increasing Return on Assets Growing Real Estate Segment EBITDA ($ in millions) Growing Oil and Gas Segment EBITDA ($ in millions) Forestar’s Segment EBITDA is a non-GAAP financial measure within the meaning of Regulation G of the Securities and Exchange Commission. Non-GAAP financial measures are not in accordance with, or an alternative to, U.S. Generally Accepted Accounting Principles (GAAP). The Company believes presenting non-GAAP Segment EBITDA is helpful to analyze financial performance without the impact of items that may obscure trends in the Company’s underlying performance. A detailed reconciliation is provided on page 46 outlining the differences between these non-GAAP measures and the directly related GAAP measures. No assurance can be provided that targets will be achieved. Forestar New Initiatives in Response to Accelerated Completion of Triple in FOR Grow Total Segment EBITDA Increase Target Return on Assets Reposition $100 million of Non-Core Assets $29 $38 2008-2011 Average 2013 2016 Target $72 2008-2011 Average 2013 2016 Target ($1) (0.1%) 6.1% 2008-2011 Average 2013 2016 Target

Real Estate Building Momentum By Accelerating Real Estate Sales and Building a Solid Multifamily Pipeline 7

8 Delivering The Greatest Value From Every Acre of Our Real Estate Pipeline (Acres) 1 Activity – Uses Financials 2 2,000 819 residential acres - 2,512 lots 682 commercial acres $55K per lot $170K per acre (avg sales price) 10,000 Approved uses, ready for Development - 16,280 lots High Value Creation 25,000 12 projects Planned Lifestyle Communities (1st and 2nd move-up focus) Low Basis Low Cost 82,000 Timberland Sales Fiber Sales Recreational Leases $3K per acre (avg sales price) 119,000 Total Real Estate Acres - 92 Projects Development Entitled Entitle Timberland C R E A T I O N R E A L I Z A T I O N Real Estate Greatest Value 1 Net acres as of Q1 2014; Includes ventures. 2 Based on FY 2013 sales activity.

Note: MSA performance based on Employment, Gross Metropolitan Product (GMP) and House Price Index Source: Brookings Institute Salt Lake City 1 - $1 Oakland 1 - $9 Strongest Quartile Weakest Quartile Los Angeles 2 - $21 Kansas City 1 - $3 Atlanta 29 - $81 San Antonio 4 - $88 Projects and investment as of Q1 2014; includes ventures TEXAS 48 - $378 Denver 6 - $39 Austin 13 - $98 Dallas/Ft. Worth 16 - $97 Gulf Coast 4 - $35 Houston 11 - $60 Nashville 2 - $15 Note: $ in millions Charlotte 2 - $18 9 Real Estate Assets Located in Stronger Residential Markets; ~65% of Investment in Texas

10 * Actual results may vary A n n u al Lo t Sal e s 2006 Peak Sales = 3,600 lots Annual Lot Sales & Avg. Lot Margin 10 Real Estate Capitalizing on Housing Recovery 1,365 804 642 A ve ra ge Lo t M ar gi n 1,883 1,060 1,117 Note: Includes consolidated ventures 2010 2011 2012 2013 Lot Sales Gross Profit ($ in millions) Over 1,400 Lots Under Option Contracts With Homebuilders as of First Quarter 2014

Texas Markets Driving Lot Sales and Margins FOR Well Positioned With Lot Inventory in Texas Markets 11 Active Residential Projects Q1 14 Lot Sales Vacant Dev. Lots Lots Under Dev. Remaining Lots to be Developed 42 517 1,389 662 10,051 Forestar Texas Lot Sales & Inventory – Q1 2014 • 2013 total lot gross profit up over 100% vs. 2012 • Texas – 90% of FY 2013 lot profit • Atlanta recovering – 99 lot sales in FY 2013; 33 lot sales in Q1 2014 excluding bulk sales Dallas 37% Houston 34% San Antonio 16% Nashville 3% Atlanta 5% Austin 3% Other 2% Forestar Lot Sales Profit by Market (FY 2013) Texas Markets Represent Almost 65% of our Investment in Real Estate

Building Solid Pipeline of Multifamily Development Opportunities (Proforma) Proforma Project Cash Flows Expected Forestar Cash Flows Project Market % Complete Units FOR Ownership Total Development Cost Expected Project NOI FOR Equity FOR Total Cash Cash Multiple* Eleven Austin 98% 257 25% $40 – 45 $3.4 $4 $12 3.0x 360° Denver 57% 304 20% 50 – 55 3.8 4 11 2.8x Midtown Dallas 30% 354 100% 35 – 40 2.8 10 20 2.0x Acklen Nashville 4% 320 30% 55 – 60 4.1 6 14 2.3x Littleton Denver -- 385 25% 70 – 75 5.1 6 16 2.6x 1,620 40% $250 – 275 $19.2 $30 $73 2.4x * Cash multiples include fees 12 Site Pipeline Expected Ownership Proforma Units Charlotte, NC Venture 375 Austin, TX – Pressler Venture 280 Austin, TX – Westlake Venture 218 ($ in millions)

Note: Includes consolidated ventures. Core Real Estate Business Strengthening 13 Capitalizing on housing recovery by driving residential lot and tract sales Selling commercial tracts - reflects broadening real estate recovery Acquiring attractive community development and multifamily sites Real Estate segment EBITDA: Q1 2014 = $24.2 million FY 2013 = $71.5 million Accelerating Value Realization $0 $25 $50 $75 2010 2011 2012 2013 Income Producing Residential Lots Residential Tracts Multifamily Commercial Tracts Real Estate Segment Earnings Contribution (Excluding Timberland Sales & Asset Impairments)

Oil and Gas Building Momentum By Driving Leasing and Exploration to Increase Production and Reserves 14

Recognizing and Responsibly Delivering the Greatest Value From Our Oil and Gas Resources 1. Acres as of Q1 2014. Includes approximately 590,000 owned net mineral acres and 273,000 net acres of leasehold mineral interests 15 V A L U E C R E A T I O N & R E A L I Z A T I O N Minerals Greatest Value Acres 1 Activity 73,000 • Working and Royalty Interests • Production • 1,919 BOE/Day Production Q1 2014 • 1.1 MMBOE Production YE 2013 • Reserves • 8.5 MMBOE Proved Reserves YE 2013 255,000 • Geological and Geophysical Evaluations • Drilling Operations 535,000 • Develop Prospects 863,000 Total Net Mineral Acres Production - Reserves Exploration and Development Subsurface Evaluation

Williston (Bakken / Three Forks) Denver – Julesburg Basin Central Uplift Appalachian Basin Black Warrior Anadarko Basin Fort Worth Basin East Texas Basin Gulf Coast Basin Texas, Louisiana, Mississippi Salt Basin South Extension Appalachian Basin 16 Mineral Interests Located In Prolific Oil & Gas Basins Leasehold Interests Fee Ownership Basins / Formations Net Mineral Acres Georgia / Alabama Owned 192,000 Leased 8,000 Total 200,000 Louisiana Owned 144,000 Leased 4,000 Total 148,000 Texas Owned 252,000 Leased 12,000 Total 264,000 Nebraska / Kansas Leasehold 195,000 North Dakota Leasehold 8,000 Other Owned 2,000 Leased 11,000 Total 13,000 Total Owned 590,000 Leased 273,000 Total 863,000 Oklahoma Leasehold 35,000 Note: Acres as of first quarter 2014.

Located In Prolific Oil & Gas Basins 17 Net Mineral Interests* State Owned Leasehold Total Texas 252,000 12,000 264,000 Louisiana 144,000 5,000 149,000 Nebraska / Kansas - 195,000 195,000 North Dakota - 8,000 8,000 Georgia / Alabama 192,000 9,000 201,000 Other** 2,000 44,000 46,000 Total 590,000 273,000 863,000 * Note: As of Q1 2014; includes both fee and leasehold interests ** Excludes approximately 8,000 net mineral acres located in various states related to overriding royalty interests • Over 860,000 net mineral acres located in prolific oil and gas basins • 73,000 net mineral acres held by production • 37,000 net mineral acres working interests • 36,000 net mineral acres royalty interests • Acquired additional 61,000 net leasehold mineral acres in Kansas in Q2 2014 • Recurring cash flows from royalty interests • 255,000 net mineral acres in geological and geophysical evaluation • Focused on developing prospects from 290,000 owned net mineral acres • Limited carrying costs *Wells Awaiting Completion **Represent gross wells Q1 2014 Working Interest Well Status** Bakken/ Three Forks Lansing- Kansas City TX, LA & Other Total Q1 Production (BOE / Day) 810 539 570 1,919 Q1 2014 Wells WAC* 18 0 1 19 Q1 2014 Wells Drilling 3 3 4 10 Drilling Plan FY2014** 63 90 8 161

0 500 1,000 1,500 2,000 2011 2012 2013 B o e / D a y North Dakota Kansas/Nebraska Texas/Louisiana/Other Production Growth Driven by Bakken / Three Forks 18 18 Average Daily Production Working Interests 0 500 1,000 1,500 2,000 2,500 3,000 2011 2012 2013 Boe / D ay Working Interests Royalty Average Daily Production 44% of 2013 Daily Production from Working Interests Driven by Bakken/Three Forks

Core Bakken Locations Provide Significant Value Creation Potential 7,600 net mineral acres - Bakken / Three Forks *Major operators in Core Acreage Position 19 Bakken Operators* *Wells and acreage are approximate Bakken / Three Forks Percentile Ranked Production (60-90 Days) Bakken / Three Forks Leasehold* Net mineral acres leased ~7,600 Average working interest 8.8% Potential units ~60 Potential gross wells ~450 Area of Forestar Leases Regions shown in shades of yellow and orange represent areas in which production is in the upper 50th percentile whereas areas shown in shades of blue and gray represent areas in which production is in the lower 50th percentile. Production Percentile Source: North Dakota Geological Survey; S.H. Nordeng 2013; Edward C. Murphy Site Geologist 100% 0% Dunn McKenzie Mclean Mountrail

0 200 400 600 800 1,000 1,200 Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014E Bakken/Three Forks Production (Boe/Day) 20 20 Bakken / Three Forks Leasehold Interests 2013 Gross Wells Producers Added During 2013 44 Producers at YE 2013 * 80 Q1 2014 Producers Added During Q1 2014 3 Average WI Q1 2014 3.13% Drilling & Awaiting Frac at End Q1 2014 21 Total Wells Planned 2014** 63 Expected Average WI 2014 10.0% Bakken / Three Forks Drilling Activity Accelerating Investment and Value Realization * Producing or capable of producing at YE 2013 ** Based on current plans from operators, subject to change *** Assuming $90 oil and $3 natural gas average price over life of well. Total costs includes land, drilling and completion, LOE and production severance taxes. 0 20 40 60 80 100 120 140 160 2010 2011 2012 2013 2014E P ro d u ci n g W e lls Bakken/Three Forks Producing Wells**** Actual Wells Planned Wells +44 +25 +7 +4 +57 **** Represent gross wells Weather impacts * EUR (MBOE) IRR Based on existing wells 600 41% As underwritten 500 28% Bakken/Three Forks EUR Sensitivity *** Note: Actual results may vary from illustrations

Kansas/Nebraska: Central Kansas Uplift & Western Kansas Plays Shallow Conventional Statistical Play 21 *Wells and acreage are approximate Kansas/Nebraska Acreage Position Kansas / Nebraska Leasehold Interests Key Metrics Net Mineral Acres Leased as of Q1 2014 195,000 Net Mineral Acres Leased in April 2014 61,000 Total Wells Planned for Drilling 2014 90 Expected Avg. Historical Success Rate 40% Expected Avg. Working Interest 2014 70% Source: B. Jackson, 2012 Using Seismic to Identify Structures Forestar Leases Gas Fields Oil Fields Forestar Q2 Leases Nebraska Kansas

Kansas / Nebraska Drilling Activity Achieves 40% Success Rates 22 22 Kansas / Nebraska Leasehold Interests Activity Gross Wells Producers Added During 2013 36 Producers at YE 2013**** 97 Producers Added Q1 2014 *** 12 Total Wells Planned for Drilling in 2014 90 Key Metrics Success Rate FY 2013 47% Success Rate Q1 2014 40% Expected Avg. Working Interest 2014 70% *** Includes two well re-completions for new pay zones **** Producing or capable of producing at YE 2013 0 20 40 60 80 100 120 140 2012 2013 2014E P ro d u ci n g W e lls +36 +36* Kansas / Nebraska Producing Wells** *Assumes 40% success rate for wells drilled in 2014 **Represents gross wells 0 100 200 300 400 500 600 Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014 B O E/D a y Kansas / Nebraska Production (Boe/Day) Single-Well Economics Risked (Illustrative)* Estimated EUR’s (Boe) 35 - 40K PV-10 $0.5 Returns (IRR) * (Based on 40% success rate) > 60% *Includes 1.5 dry hole costs @ $230,000 + 1.0 completed well cost at $550,000 for a 40% success rate. Includes land, drilling and completion, LOE, production severance taxes and seismic costs. Assumes $90 average oil price over life of the well Note: Actual results may vary from illustrations

Increased Cash Flow through Proved Reserve Growth in Bakken / Three Forks 23 Proved Reserves (MMBoe): Average Annual Growth of 54% Reserves Growth Production Replaced Net Reserves Increase % Oil2 Investment3 2013 8.5 4.0 1.1 2.9 69% $99 2012 5.6 3.3 0.7 2.6 57% $1733 2011 3.0 1.0 0.4 0.6 36% $4 2010 2.4 0.7 0.4 0.3 25% - Texas & Louisiana North Dakota Other Kansas & Nebraska = = = = 1 Represents present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual discount rate of 10%. Future Net Cash flows represents an undiscounted value based upon estimate of future net cash flows from proved developed reserves after deducting estimated severance and ad valorem taxes, but before deducting estimates of future income taxes. 2 Includes natural gas liquids. 3 Includes $152 million associated with acquisition of Credo. $56 $77 $133 $222 $317 $0 $100 $200 $300 $400 2009 2010 2011 2012 2013 $34 $45 $82 $138 $183 $0 $50 $100 $150 $200 2009 2010 2011 2012 2013 Present Value of Estimated O&G Revenue1 ($ in millions) Future Net Cash Flows From Proved Reserves1 ($ in millions)

2014 Capital Investment Plan Generating Production and Reserve Growth By Accelerating Investment 24 Total Oil & Gas 2014 Capital Investment: ~ $125 - $135 million Capital Allocation by Activity and Region Drilling & Completion Proforma Returns *** * Based on March, 2014 strip prices ** Includes differentials by region ***Total Weighted Average weighted by 2014 planned drilling and completion capital investment Note: Actual results may vary. 0% 20% 40% 60% 80% $60 $80 Strip* $100 We ig h te d A ve ra ge R e tu rn Oil Price ($/bbl)** Activity Percent Drilling & Completion ~ 75% - North Dakota - Kansas/Nebraska - Texas/Oklahoma/Other Land Extensions ~ 22% Seismic ~ 3%

Accelerating Value Realization and Growing Net Asset Value Building Momentum By Accelerating Value Realization and Growing Net Asset Value Capitalizing on investments to accelerate earnings and cash flow Increasing oil production and proven reserves Expected investment returns above cost of capital 25 0 200 400 600 800 1,000 1,200 $0 $20 $40 $60 2010 2011 2012 2013 P ro d u ctio n ( M b o e ) To tal EB IT D A X Forestar Oil and Gas EBITDAX ($ in millions) Working Interests Royalties Lease Bonus / Delay Rentals Production (MBoe) BOE = Barrels of oil equivalent (converting natural gas to oil at 6 Mcfe / Bbl) FY 2013 * Revenue $68/BOE Cost $50/BOE Margin $18/BOE * Fully loaded costs including all segment operating expenses

Strategic Initiatives Update Growing Forward Through Strategic and Disciplined Investments and Increasing Returns

Strategic Initiative: Growing FORward Growing Long-Term Shareholder Value Growing Through Strategic and Disciplined Investment Increasing Returns 27 * Excludes gains from strategic timberland sales • Development of Existing Locations • Acquisitions and Extensions 2016 Targets: • Total Segment EBITDA of $200 million • Return on Assets of 10.0% • Reposition $100 Million of Non-Core Assets $36 $117 2008-2011 Average 2013 2016 Target $200 Accelerating Total Segment EBITDA ($ in millions) (0.1%) 6.1% 2008-2011 Average 2013 2016 Target 10.0% Increasing Return on Assets *

Delivering Shareholder Value Through Execution of Strategic Initiatives 2009 Strategic Initiatives • Monetize 175,000 acres of timberland and reduce debt $150 million 2012 Triple in FOR • Triple total segment EBITDA, oil and gas production and lot sales 2014 Growing Forward • Growing segment earnings through strategic and disciplined investments • Focused on increasing return on assets • Repositioning non-core assets • Sold $20 million of non-core assets in Q1 2014 28 Cash flows and Liquidity Position Forestar to Adequately Fund Growing FORward Initiatives

Forestar Investor Presentation 29

30 Financial Tools and Additional Disclosures Available on our Website • Historical Financials • Segment Disclosures • At-A-Glance • Corporate • Oil and Gas • Real Estate • Multifamily • Water • Videos • 101 Learning Tools 2008-Q 2 2013 2008-Q 2 2013 Assets State Market Ownership Total Remaining Acres Investment Basis Remaining Acres Vacant Developed Lots & Lots Under Development Remaining Lots To Be Developed * Average Lot Sales Remaining Acres Average Commercial Sales (Price/Lot) (Price/Acre) Residential & Commercial Real Estate Projects - Entitled, Developed & Under Development Wholly-Owned California Oakland 100% 288 $ 8,915,357 - - - 288 Colorado Denver 100% 780 $ 21,150,219 682 111 1,092 $ 22,000 98 $ 29,000 Texas Austin 100% 2,046 $ 61,858,640 1,849 210 1,395 $ 45,000 197 $ 280,000 Dallas/Fort Worth 100% 1,184 $ 53,079,612 1,111 781 2,445 $ 51,000 73 $ 78,000 Houston 100% 284 $ 13,486,407 218 123 819 $ 46,000 66 $ 157,000 San Antonio 100% 839 $ 54,233,170 785 322 921 $ 68,000 54 $ 193,000 Texas 100% 4,353 $ 182,657,829 3,963 1,436 5,580 $ 52,000 390 $ 159,000 Georgia Atlanta 100% 5,443 $ 21,216,445 4,447 427 7,387 $ 43,000 996 Tennessee Nashville 100% 120 $ 7,288,043 120 - 173 $ - - Florida Tampa 100% - $ (60,000) - - - $ 22,000 - Missouri & Utah 100% 102 $ 3,050,641 102 13 41 $ 38,000 - Ventures Texas Austin 50% 241 $ 1,199,401 241 - 821 - Dallas/Fort Worth 25%-88% 576 $ 25,201,719 519 334 1,680 $ 74,000 57 $ 294,000 Houston 37%-90% 1,088 $ 30,824,908 736 449 2,311 $ 42,000 352 $ 210,000 Gulf Coast 50%-75% 189 $ 34,247,843 45 153 47 $ 243,000 144 San Antonio 50% 62 $ 2,146,024 62 23 46 $ 85,000 - 25%-90% 2,156 93,619,895 1,603 959 4,905 $ 57,000 553 $ 227,000 Georgia Atlanta 75% 631 $ 2,327,546 631 258 794 $ 53,000 - Total 13,873 $ 340,165,975 11,548 3,204 19,972 $ 53,000 2,325 $ 180,000 * Includes Lots that we plan to sell as residential tracts. Date: August 7, 2013 Residential Commercial FORESTAR GROUP INC. RESIDENTIAL & COMMERCIAL - ENTITLED, DEVELOPED AND UNDER DEVELOPMENT AT SECOND QUARTER-END 2013 www.ForestarGroup.com

31 Forestar’s Total Segment EBITDA is a non-GAAP financial measure within the meaning of Regulation G of the Securities and Exchange Commission. Non-GAAP financial measures are not in accordance with, or an alternative to, U.S. Generally Accepted Accounting Principles (GAAP). The company believes presenting non-GAAP Total Segment EBITDA is helpful to analyze financial performance without the impact of items that may obscure trends in the company’s underlying performance. A detailed reconciliation is provided below outlining the differences between these non-GAAP measures and the directly related GAAP measures. Quarter Full Year ($ in millions, except per share amounts) Q1 2014 Q1 2013 2013 2012 2011 Total Segment Earnings (loss), in accordance with GAAP $23.9 $25.8 $93.8 $80.2 ($7.8) Non-cash items, pre-tax Depreciation, Depletion & Amortization 5.5 $5.0 23.3 10.6 7.1 Total Segment EBITDA $29.4 $30.8 $117.1 $90.8 ($0.7) Reconciliation of Non-GAAP Financial Measures (Unaudited)

32 Forestar’s Segment EBITDA is a non-GAAP financial measure within the meaning of Regulation G of the Securities and Exchange Commission. Non-GAAP financial measures are not in accordance with, or an alternative to, U.S. Generally Accepted Accounting Principles (GAAP). The company believes presenting non-GAAP Segment EBITDA is helpful to analyze financial performance without the impact of items that may obscure trends in the company’s underlying performance. A detailed reconciliation is provided below outlining the differences between these non-GAAP measures and the directly related GAAP measures. Reconciliation of Non-GAAP Financial Measures (Unaudited) Quarter Full Year ($ in millions, except per share amounts) Q1 2014 Q1 2013 2013 2012 Real Estate Segment Earnings in accordance with GAAP $23.6 $19.4 $68.4 $53.6 Depreciation, Depletion & Amortization 0.6 $1.1 3.1 4.3 EBITDA $24.2 $20.5 $71.5 $57.9 Oil & Gas Segment Earnings in accordance with GAAP $0.8 $5.1 $18.9 $26.6 Depreciation, Depletion & Amortization 4.8 $3.7 19.5 5.0 EBITDA $5.6 $3.8 $38.4 $31.6 Other Natural Resources Segment Earnings in accordance with GAAP ($0.5) $1.3 $6.5 $0.0 Depreciation, Depletion & Amortization 0.1 $0.2 0.7 1.3 EBITDA ($0.4) $1.5 $7.2 $1.3

33 Forestar’s Oil and Gas Segment EBITDAX is a non-GAAP financial measure within the meaning of Regulation G of the Securities and Exchange Commission. Non-GAAP financial measures are not in accordance with, or an alternative to, U.S. Generally Accepted Accounting Principles (GAAP). The company believes presenting non-GAAP Oil and Gas Segment EBITDAX is helpful to analyze financial performance without the impact of items that may obscure trends in the company’s underlying performance. A detailed reconciliation is provided below outlining the differences between these non-GAAP measures and the directly related GAAP measures. Quarter Full Year ($ in millions, except per share amounts) Q1 2014 Q1 2013 2013 2012 Oil and Gas Segment Earnings, in accordance with GAAP $0.8 $5.1 $18.9 $26.6 EBITDAX adjustments, pre-tax Depreciation, Depletion & Amortization 4.9 3.7 19.5 5.0 Geological, Geophysical, Seismic and Dry Hole Costs 4.1 1.3 11.0 1.7 Total Oil and Gas Segment EBITDAX $9.8 $10.1 $49.4 $33.3 Reconciliation of Non-GAAP Financial Measures (Unaudited)

($ in 000’s) Est. YE 2013* Actual YE 2012* Actual YE 2011* Undiscounted future net cash flows before income taxes $316,550 $222,231 $133,729 Less: undiscounted future income taxes (78,977) (52,088) (41,835) Undiscounted future net cash flows after income taxes $237,573 $170,143 $91,894 Reconciliation of Non-GAAP Financial Measures (Unaudited) In our full year and fourth quarter 2013 earnings release and conference call presentation materials furnished to the Securities and Exchange Commission on Form 8-K on February 13, 2014, we used certain non-GAAP financial measures. The non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures. These non-GAAP financial measures reflect an additional way of viewing aspects of our operations that, when viewed with our GAAP financial statements and the accompanying reconciliations to corresponding GAAP financial measures, may provide a more complete understanding of our business. We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety. Reconciliation of Non-GAAP Financial Measures (Unaudited) The following table shows a reconciliation of PV-10 (discounted future net cash flows before income taxes) to the standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with generally accepted accounting principles, or GAAP). PV-10 is an estimate of the present value of future net cash flows from proved developed reserves after deducting estimated severance and ad valorem taxes, but before deducting any estimates of future income taxes. The estimated future net cash flows are discounted at an annual rate of 10%. A reconciliation of PV-10 to the standardized measure of discounted future net cash flows as computed under GAAP is illustrated below: ($ in 000’s) Est. YE 2013* Actual YE 2012* Actual YE 2011* PV – 10 (discounted future net cash flows before income taxes) $182,776 $137,675 $81,919 Less: discounted future income taxes (45,923) (29,719) (25,712) Standardized measure of discounted future net cash flows $136,853 $107,956 $56,207 The undiscounted value represents an estimate of future net cash flows from proved developed reserves after deducting estimated severance and ad valorem taxes, but before deducting estimates of future income taxes. A reconciliation of undiscounted future net cash flows before income taxes to the undiscounted future net cash flows after income taxes is illustrated below: We believe both PV-10 and undiscounted values are important for evaluating the relative significance of our oil and gas interests and that the presentation of the non-GAAP financial measures provides useful information to investors because they are widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our mineral assets. * Includes our share of proved developed reserves in equity-method ventures 34

Forestar Investor Presentation For questions, please contact: Anna Torma SVP Corporate Affairs Forestar Group Inc. 6300 Bee Cave Road Building Two, Suite 500 Austin, TX 78746 512-433-5312 annatorma@forestargroup.com 35