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| 8-K - 8-K - Forestar Group Inc. | form8-kxinvestorpresentati.htm |
Forestar Investor Presentation November 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 Businesses
Execution of Initiatives and Strategic Acquisitions Positions Forestar with Stronger Portfolio of Assets 4 Real Estate • Land - 120,000 acres, principally low basis land • Projects - 95 (10 states and 13 markets) • Significant Commercial Properties - 5 Oil and Gas • Fee and Leasehold Interests - 948,000 net acres* • Producing Gross Wells - 961** Natural Resources •108,000 acres with timber *** •Water Interests - 1.5 million acres**** Assets and Resources – Q3 2014 Note: includes ventures * Includes approximately 358,000 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 2,000 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 in the appendix of this presentation 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
Improving Financial Strength and Liquidity While Executing Growth Strategy Execution of Strategic Initiatives Positions Forestar with Strong Balance Sheet, Ample Liquidity and Assets Well Positioned to Generate Earnings and Cash Flow Going Forward 1 Fair value of convertible notes as of Q3 2014 is $102 million and YE 2013 is $100 million; principal amount of notes is $125 million which is due and payable at maturity in 2020 2 Represents amortizing note portion of $150 million tangible equity unit offering 3 Consolidated debt principally non-recourse to Forestar 4 Includes unrestricted cash plus available revolver 7 1 ($ in Millions) Q3 2014 Actual YE 2013 Actual Credit Facility Borrowings --- $200 8.50% Senior Secured Notes $250 --- Convertible Debt 1 102 100 Amortizing Notes 2 19 26 Other Consolidated Debt 3 58 31 Total Debt $429 $357 Shareholder’s Equity $745 $715 Total Debt / Total Capital 37% 33% Available Liquidity 4 >$458 $353 Q3 2014 Debt Maturity Schedule $2 $50 $24 $1 $125 $250 2014 2015 2016 2017 2018 2019 2020 2021 2022
Real Estate Building Momentum By Accelerating Real Estate Sales and Building a Solid Multifamily Pipeline 8
9 Delivering The Greatest Value From Every Acre of Our Real Estate Pipeline (Acres) 1 Activity – Uses Financials 2 2,000 763 residential acres - 2,349 lots 646 commercial acres $58K per lot $197K per acre (avg sales price) 10,000 Approved uses, ready for Development - 15,400 lots High Value Creation 24,000 11 projects Planned Lifestyle Communities (1st and 2nd move-up focus) Low Basis Low Cost 84,000 Timberland Sales Fiber Sales Recreational Leases $3K per acre (avg sales price) 120,000 Total Real Estate Acres - 95 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 Q3 2014; Includes ventures. 2 Based on FY 2013 sales activity.
Denver 6 - $34 Salt Lake City 1 - $- Los Angeles 2 - $22 Kansas City 1 - $3 Atlanta 29- $89 TEXAS 49 - $435 Nashville 4 - $24 Charlotte 2 - $19 Austin 14 - $160 Dallas/Ft. Worth 16 - $109 Gulf Coast 4 - $35 Houston 11 - $49 San Antonio 4 - $82 Note: MSA performance based on Employment, Gross Metropolitan Product (GMP) and House Price Index Projects and investment as of Q3 2014; includes ventures Note: $ in millions Oakland 1 - $9 Real Estate Assets Located in Stronger Residential Markets; ~68% of Investment in Texas 10 Forestar markets
* 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 11 Real Estate Capitalizing on Well Located Communities, Low Inventories and Solid Job Growth $0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 0 500 1,000 1,500 2,000 2,500 2008 2009 2010 2011 2012 2013 2014E* Lot Sales Average Lot Margin 1,365 804 642 A ve ra ge Lo t M ar gi n 1,883 1,060 1,117 Note: Includes ventures YTD Q3 1,834 Planned Lot Sales ** Texas Markets represent Dallas, Houston, San Antonio and Austin Source: Metrostudy Texas Lot Supply – 4 Major Markets** Rank MSA Annual Job Gains Percent Change (YOY) 2 Houston-The Woodlands-Sugar Land, TX 120,700 4.3% 16 Austin-Round Rock, TX 32,300 3.7% 3 Dallas-Fort Worth-Arlington, TX 107,000 3.4% 24 San Antonio-New Braunfels, TX 20,200 2.2% Texas Major Markets 280,200 3.6% US Average 2,635,000 1.9% Top Job Growth MSAs - September 2014 0 10 20 30 40 50 60 0 50,000 100,000 150,000 200,000 250,000 4 Q 0 0 3 Q 0 1 2 Q 0 2 1 Q 0 3 4 Q 0 3 3 Q 0 4 2 Q 0 5 1 Q 0 6 4 Q 0 6 3 Q 0 7 2 Q 0 8 1 Q 0 9 4 Q 0 9 3 Q 1 0 2 Q 1 1 1 Q 1 2 4 Q 1 2 3 Q 1 3 2 Q 1 4 M o S TEXAS Lots TEXAS MoS Equilibrium Va ca n t D ev el o p ed L o ts
Texas Markets Driving Lot Sales and Margins FOR Well Positioned With Lot Inventory in Texas Markets 12 Active Residential Projects Q3 14 Lot Sales Vacant Dev. Lots Lots Under Dev. Remaining Lots to be Developed 42 285 1,046 895 9,216 Forestar Texas Lot Sales & Inventory – Q3 2014 • 2013 total lot gross profit up over 77% vs. 2012 • YTD 2014 total lot gross profit up nearly 30% vs YTD 2013 • Texas – 87% of YTD 2014 lot profit • Atlanta recovering – 99 lot sales in FY 2013; 94 lot sales in YTD 2014 excluding 367 bulk sales Dallas 36% Houston 36% San Antonio 11% Nashville 3% Atlanta 7% Austin 4% Other 3% Forestar Lot Sales Profit by Market (YTD 2014) Texas Markets Represent Over 68% of our Investment in Real Estate
Cibolo Canyons - Accelerating Value Realization 13 CCSID Annual Hotel Occupancy Tax & Sales Tax Collections Cibolo Canyons Special Improvement District (CCSID) Payments to Forestar ($ in millions) Investment Received Future 2014 – 2034 Infrastructure Reimbursement $66 $25 $41* HOT & Sales and Use Tax** 43 66 >35 Total $109 $91 >$76 ($ in m il lio n s) *Excludes interest **Assumes no growth in HOT and Sales and Use tax collections through 2034 ***Represents annualized nine month actuals $1.0 $3.0 $5.0 $7.0 2010 2011 2012 2013 2014 Est. Hotel Occupancy Tax Sales & Use Tax Forestar received $46.5 million from Cibolo Canyons Special Improvement District (CCSID) on October 24, 2014 Forestar entitled to receive additional Hotel Occupancy (HOT) and Sales and Use taxes above CCSID debt service requirements through 2034 ***
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 Cash Contribution FOR Cash Distribution* Cash Multiple** Eleven Austin 100% 257 100% $40 $2.8 - 3.4 $25 $36 - 38 1.4 - 1.5x Midtown Dallas 85% 354 100% 35 - 40 2.8 - 3.2 10 20 - 28 2.0 - 2.8x 360° Denver 80% 304 20% 50 - 55 3.8 - 4.4 4 11 - 12 2.8 - 3.0x Acklen Nashville 35% 320 30% 55 - 60 4.1 - 4.2 6 14 - 17 2.3 - 2.8x HiLine Denver 5% 385 25% 70 - 75 5.1 - 5.3 6 16 - 20 2.6 - 3.3x 1,620 55% $250 - 270 $18.6 - 20.4 $51 $97 - 115 2.2 - 2.7x * Return projections are based on exit cap rates ranging from 4.75% - 6.5%, depending on property type and location. Ranges presented to reflect variations due to timing of exit and changes in market conditions. ** Cash multiples include fees *** FOR will be limited partner and not developer of this project 14 Site Pipeline Expected Ownership Proforma Units Houston, TX – Cinco Ranch *** 90% 360 Charlotte, NC – Dilworth 25 - 100% 379 Nashville, TN – Music Row Venture 230 Austin, TX – Downtown Edge Venture 275 Austin, TX – West Austin Venture 200 ($ in millions) Note: Eleven 75% partner interest in venture was purchased for $21.5 million in 3rd quarter 2014. Expected cash distribution and multiples reflect post acquisition ownership.
Note: Includes consolidated ventures Forestar Real Estate Revenues (Excluding Timberland, Mitigation & Multifamily Revenues) Capitalizing on Well Located Communities, Low Inventories and Forestar’s Ability to Deliver 15 • Driving residential lot and tract sales in good locations and healthy markets • Opportunistically monetizing undeveloped land and stabilized multifamily communities • Acquiring community development and multifamily sites in “A” locations • Real Estate segment EBITDA: FY 2013 = $71.5 million YTD 2014 = $68.9 million Accelerating Value Realization $0 $10 $20 $30 $0 $20 $40 $60 $80 $100 $120 YTD 2010 YTD2011 YTD 2012 YTD 2013 YTD 2014 A ve ra ge Lo t M ar gi n ($ in t h o u sa n d s) To tal R e ve n u e s ($ in m ill io n s) Residential Lots Residential Tracts Commercial Tracts Income Producing Average Lot Margin Average Lot Margin (Excluding Bulk Sales)
Oil and Gas Building Momentum By Driving Leasing and Exploration to Increase Production and Reserves 16
Recognizing and Responsibly Delivering the Greatest Value From Our Oil and Gas Resources 1. Acres as of Q3 2014. Includes approximately 590,000 owned net mineral acres and 358,000 net acres of leasehold mineral interests 17 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 82,000 • Working and Royalty Interests • Production • 3,754 BOE/Day Production Q3 2014 • 1.1 MMBOE Production FY 2013 • Reserves • 8.5 MMBOE Proved Reserves YE 2013 347,000 • Geological and Geophysical Evaluations • Drilling Operations 519,000 • Develop Prospects 948,000 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 18 Mineral Interests Located In Prolific Oil & Gas Basins Leasehold Interests Fee Ownership Basins / Formations Net Mineral Acres Georgia / Alabama Owned 192,000 Leasehold 9,000 Total 201,000 Louisiana Owned 144,000 Leasehold 5,000 Total 149,000 Texas Owned 252,000 Leasehold 13,000 Total 265,000 Nebraska / Kansas Leasehold 274,000 North Dakota Leasehold 8,000 Other Owned 2,000 Leasehold 9,000 Total 11,000 Total Owned 590,000 Leasehold 358,000 Total 948,000 Oklahoma Leasehold 40,000 Note: Acres as of third quarter 2014.
19 Drilling and Completion Investments Driving Production Growth and Improved EBITDAX 50,000 100,000 150,000 200,000 250,000 300,000 Q4 2012 Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 B O E Working Interest Legacy Minerals Quarterly Oil & Gas Production Quarterly Oil & Gas EBITDAX $0 $5,000 $10,000 $15,000 $20,000 $25,000 Q4 2012 Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 $ in thou sand s Working Interest Legacy Minerals * Includes gain on sale of oil and gas properties of $1.3 million in Q4 2013, $5.7 million in Q2 2014 and $3.3 million in Q3 2014 * * *
0 500 1,000 1,500 2,000 2,500 3,000 2011 2012 2013 Q3 2014 B o e / D a y North Dakota Kansas/Nebraska Texas/Louisiana/Other Production Growth Driven by Bakken / Three Forks 20 20 Average Daily Production Working Interests 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 2011 2012 2013 Q3 2014 Boe / D ay Working Interests Royalty Average Daily Production 57% of Q3 2014 Daily Production from Working Interests Driven by Bakken/Three Forks
Core Bakken Locations Provide Significant Value Creation Potential 7,800 net mineral acres - Bakken / Three Forks *Major operators in Core Acreage Position 21 Bakken Operators* *Wells and acreage are approximate Bakken / Three Forks Percentile Ranked Production (60-90 Days) Bakken / Three Forks Leasehold* Net mineral acres leased ~7,800 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% 10% 20% 30% 40% 50% $70 Strip $90 IR R WTI Oil Price 22 2 Bakken / Three Forks Drilling Activity Investment and Value Realization Note: Based on current plans from operators, subject to change 0 20 40 60 80 100 120 140 2010 2011 2012 2013 2014E P ro d u ci n g W e lls Bakken/Three Forks Producing Wells** Actual Wells Planned Wells ** Gross wells Bakken/Three Forks PV10 and Pricing Sensitivity * $70 WTI Oil WTI Strip $90 WTI Oil EUR (MBOE) PV10 ($MM) PV10 ($MM) PV10 ($MM) 700 $0.3 $0.5 $0.8 600 $0.1 $0.3 $0.5 500 ($0.1) $0.1 $0.3 * Estimated Ultimate Recoveries (EUR’s)assuming $90, 10/30/14 strip (approximately $80), and $70 WTI oil and applying $6.42 well head differentials, and assuming $3 natural gas average price over life of well. Total costs includes land, drilling and completion, LOE and production severance taxes. Note: Actual results may vary from illustrations Bakken/Three Forks EUR and Oil Pricing Sensitivity * 700 MBOE EUR 600 MBOE EUR 500 MBOE EUR Target Return
Kansas / Nebraska Working Interest Investment Return Sensitivity 23 23 0 20 40 60 80 100 120 140 2012 2013 2014E P ro d u ci n g W e lls Kansas/Nebraska Producing Wells** **Represents gross wells; and assumes 40% drilling success rate in 2014 * 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, 10/30/14 strip (approximately $80), and $70 WTI oil price, applying net $7 differentials over life of the well 0% 10% 20% 30% 40% 50% 60% 70% 80% $70 Strip $90 IR R WTI Oil Price Kansas/Nebraska EUR and Oil Pricing Sensitivity * Target Return Kansas/Nebraska PV10 and Pricing Sensitivity * $70 WTI Oil WTI Strip $90 WTI Oil EUR (MBOE) PV10 ($MM) PV10 ($MM) PV10 ($MM) 40 $0.2 $0.4 $0.6 35 $0.0 $0.2 $0.3 40 MBO EUR 35 MBO EUR
Increased Cash Flow through Proved Reserve Growth in Bakken / Three Forks 24 Proved Reserves (MMBoe): Average Annual Growth of 54% Reserves Growth Production Replaced Net Reserves Increase % Oil2 Investment 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)
Accelerating Value Realization and Growing Net Asset Value 25 0 200 400 600 800 1,000 $0 $5 $10 $15 $20 $25 $30 $35 $40 YTD 2011 YTD 2012 YTD 2013 YTD 2014 To tal P ro d u ctio n ( M b o e ) EB IT D A Forestar Oil and Gas EBITDA ($ in millions) Lease Bonus / Delay Rentals Royalties Working Interests Production (Mboe) *BOE = Barrels of oil equivalent (converting natural gas to oil at 6 Mcfe / Bbl) 1st Half 2014 2nd Half 2014E Working Interest Oil Production (MBO) 346 MBO Note: Actual results may vary Forestar Focused on Developing Best of Class Oil and Gas Business
Strategic Initiatives Update Growing Forward Through Strategic and Disciplined Investments and Increasing Returns
Growing FORward Initiatives Growing Long-Term Shareholder Value Growing Through Strategic and Disciplined Investment Increasing Returns 27 • 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 Delivering Value Through Execution of Strategic Initiatives YTD Q3 2014 Results • Total segment EBITDA of $108.5 million up nearly 39% vs. YTD Q3 2013 • Sold $31 million in non-core assets • Invested $178 million in “A” locations and resource play • Available liquidity > $450 million • Cash flows and liquidity expected to adequately fund Growing FORward initiatives • Plans to repurchase up to $55 million in stock under existing share repurchase program
Forestar Investor Presentation 28
29 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 www.ForestarGroup.com 2008-Q 2 2014 2008-Q 2 2014 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% 744 $ 23,967,178 643 53 1,098 $ 40,000 101 $ 29,000 Texas Austin 100% 1,886 $ 51,823,584 1,727 103 1,173 $ 46,000 159 $ 222,000 Dallas/Fort Worth 100% 1,284 70,568,281 1,208 683 2,997 63,000 76 99,000 Houston 100% 223 16,587,043 157 81 628 53,000 66 157,000 San Antonio 100% 759 55,459,749 739 239 1,057 69,000 20 215,000 Texas 100% 4,152 $ 194,438,657 3,831 1,106 5,855 $ 60,000 321 $ 178,000 Georgia Atlanta 100% 4,439 $ 18,483,231 3,564 312 4,594 $ 25,000 875 Tennessee Nashville 100% 126 $ 8,686,743 126 11 139 $ 185,000 - South Carolina Charlotte 100% 47 $ 4,331,074 47 - 189 $ - - $ - Florida Tampa 100% - $ - - - - $ 22,000 - Missouri & Utah 100% 97 $ 3,003,382 97 16 226 $ 39,000 - Ventures Texas Austin 50% 241 $ 1,154,032 241 - 821 - Dallas/Fort Worth 25%-88% 410 9,012,940 356 - 638 $ 55,000 54 $ 411,000 Houston 37%-90% 999 31,051,804 713 252 2,492 45,000 286 212,000 Gulf Coast 50%-75% 77 34,675,724 44 151 48 124,000 33 San Antonio 50% 36 1,963,381 36 50 - 91,000 - 25%-90% 1,763 $ 77,857,881 1,390 453 3,999 $ 50,000 373 227,000 Georgia Atlanta 75% - $ - - - - $ 53,000 - Total 11,656 $ 339,683,503 9,698 1,951 16,100 $ 53,000 1,958 $ 192,000 * Includes lots that we plan to sell as residential tracts. Date: August 8, 2014 FORESTAR GROUP INC. RESIDENTIAL & COMMERCIAL - ENTITLED, DEVELOPED AND UNDER DEVELOPMENT Residential Commercial AT SECOND QUARTER-END 2014
30 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 YTD ($ in millions) Q3 2014 Q3 2013 YTD Q3 2014 YTD Q3 2013 Real Estate Segment Earnings in accordance with GAAP $16.0 $13.2 $66.9 $40.7 Depreciation, Depletion & Amortization 0.7 0.7 2.1 2.5 EBITDA $16.7 $13.9 $68.9 $43.2 Oil & Gas Segment Earnings in accordance with GAAP $6.0 $8.5 $16.3 $17.9 Depreciation, Depletion & Amortization 8.4 5.4 20.7 13.8 EBITDA $14.4 $13.9 $37.0 $31.7 Other Natural Resources Segment Earnings in accordance with GAAP $0.7 $0.5 $2.2 $2.8 Depreciation, Depletion & Amortization 0.1 0.2 0.4 0.5 EBITDA $0.8 $0.7 $2.6 $3.3 Total Segment Total Segment Earnings in accordance with GAAP $22.7 $22.2 $85.4 $61.4 Depreciation, Depletion & Amortization 9.2 6.3 23.1 16.8 EBITDA $31.9 $28.5 $108.5 $78.2
31 Forestar’s Oil and Gas Segment EBITDAX is a non-GAAP financial measure within the meaning of Regulation G of the Securities and Exchange Commission. Non-GAAP financial measures are not in accordance with, or an alternative to, U.S. Generally Accepted Accounting Principles (GAAP). The company believes presenting non-GAAP Oil and Gas Segment EBITDAX is helpful to analyze financial performance without the impact of items that may obscure trends in the company’s underlying performance. A detailed reconciliation is provided below outlining the differences between these non-GAAP measures and the directly related GAAP measures. Quarter YTD ($ in millions) Q3 2014 Q3 2013 YTD Q3 2014 YTD Q3 2013 Oil and Gas Segment Earnings, in accordance with GAAP $6.0 $8.5 $16.3 $17.9 EBITDAX adjustments, pre-tax Depreciation, Depletion & Amortization 8.4 5.4 20.7 13.8 Geological, Geophysical, Seismic and Dry Hole Costs 4.7 1.7 14.1 5.1 Total Oil and Gas Segment EBITDAX $19.1 $15.6 $51.1 $36.8 Reconciliation of Non-GAAP Financial Measures (Unaudited)
($ in 000’s) Actual 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) Actual 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 32
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 33